UOP Fluid Catalytic

Cracking Process Process Technology Manual

ORPIC Sohar, Oman September 2012

– LIMITED DISTRIBUTION –

This material is UOP LLC technical information of a confidential nature for use only by personnel within your organization requiring the information. The material shall not be reproduced in any manner or distributed for any purpose whatsoever except by written permission of UOP LLC and except as authorized under agreements with UOP LLC.

157048 Table of Contents

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FCC PROCESS TECHNOLOGY

TABLE OF CONTENTS

I. INTRODUCTION

II. PROCESS FLOW Reactor Regenerator Main Column Gas Concentration and Recovery III. PROCESS CONTROL Reactor Regenerator Main Column Gas Concentration IV. EQUIPMENT Process Equipment and Its Use Metallurgical Corrosion V. FLUIDIZED SOLIDS Theory Applications to Fluid Catalytic Cracking VI. CATALYST History Modern FCC Catalysts Time and Temperature Effects Poisons Catalyst Management Catalyst Properties and Testing VII. PROCESS VARIABLES Reactor and Regenerator Process Variables Feedstock VIII. PROCESS CALCULATIONS FCC Flow Corrections and Mass Balance Liquid Product Cutpoint Corrections Reactor and Regenerator Heat Balance FCC Unit Mechanical Summaries Additional FCC Unit Calculations

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IX. FEED AND PRODUCT TREATING Feed Treating Product Treating – Reasons and Methods X. ANALYTICAL METHODS Minimum Sample Size Typical Sampling Schedule Outline of FCCU Laboratory Methods XI. PROCEDURES Refractory Dryout Startup Shutdown Emergencies Catalyst Handling FCC Unit Evaluation XII. SAFETY General Additional Safety Precautions for Entering Vessels High Temperature Problems Chemical Hazards XIII. ENVIRONMENTAL Emissions Sources and Solutions

157048 Introduction

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Introduction

UOP Company History For more than 80 years, UOP has been one of the world’s leading licensors of new

and innovative technology. Today, UOP continues in this role with 30 offices on 4

continents and 9 manufacturing facilities worldwide. UOP currently licenses and

designs more than 60 different processes and has a total of 5,500 units licensed

worldwide. For the last 50 years, the fluid catalytic cracking (FCC) process has

been an important and successful part of UOP's licensing activities.

The Early Years UOP was founded in 1914 as the National Hydrocarbon Company on the strength

of patent rights developed from the pioneering work of Jesse A. Dubbs, a California

inventor. The company was financed by a noted Chicagoan, J. Ogden Armour. In

1915, the company name was changed to Universal Oil Products Company.

From the beginning, the goal of the company was to develop and commercialize

technology for license to the petroleum refining industry. Under the direction of C. P.

(Carbon Petroleum) Dubbs, son of Jesse Dubbs, research and development work

continued at the company's small site near Independence, Kansas, where the

famous Dubbs Thermal Cracking process was successfully demonstrated in 1919.

The then-revolutionary process became the foundation of UOP's rapid growth and

its early worldwide recognition by the industry. The early period of growth was ably

directed by its president, Hiram J. Halle, and by Dr. Gustav Egloff, one of the

world’s leading petroleum chemists.

In 1931, UOP established its headquarters in Chicago and its research laboratories

in nearby Riverside, Illinois. That same year the ownership of UOP passed to a

consortium of its major licensees, led by Shell and Standard Oil of California.

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During this stage, the company benefited immensely by the addition to its research

staff of Prof. Vladimir Ipatieff, a famous Russian scientist known internationally for

his work in high-pressure catalysis. His contributions in catalytic chemistry gave

UOP a position of leadership in the development of catalysis as applied to petro-

leum processing. The first project of Ipatieff and his research team was catalytic

polymerization. Other eminent scientists were also attracted to UOP’s research

center in Riverside during this period.

With the outbreak of World War II, UOP scientists and engineers focused their

knowledge and talents on developing new catalytic processes, notably alkylation

that helped meet wartime energy requirements, especially for aviation fuel. UOP

also cooperated with other companies to develop the FCC process.

In 1944, the owners of UOP divested themselves of their holdings in the company,

and UOP’s stock was placed in trust. The American Chemical Society was named

as the beneficiary. Thus, the Petroleum Research Fund was created with the

understanding that income from the trust was to be used for advanced scientific

education and fundamental research in the petroleum field.

In spite of some financial and legal setbacks suffered by UOP during this period,

strong management succeeded in steering the company back to its original course:

taking creative research from concept to commercial reality. UOP was recognized

as a company employing the world’s most knowledgeable scientific and technical

personnel, who understood petroleum refining and the need for improved process-

ing methods and techniques.

In 1949, UOP's research staff developed a radically different refining process that

used a catalyst containing platinum. Called the Platforming™ process, it revolu-

tionized the art of reforming to produce gasoline with substantially improved octane

number. The process was also instrumental in making benzene available in a

quality and quantity never before realized on a commercial scale. With the

Platforming™ process and other innovative processes, UOP became a vital

contributor to the emergence and growth of the petrochemical industry.

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In the early 1950s, UOP also began to manufacture its own proprietary catalysts

and a variety of refining chemicals at a newly constructed plant in Shreveport,

Louisiana. Later UOP built manufacturing plants at McCook, Illinois; Brimsdown,

U.K.; and other locations. In 1952, UOP moved its headquarters and engineering

activities to Des Plaines, a suburb of Chicago. Soon after, the construction of a new

research center at the same location was begun.

The Recent Era In 1959, UOP assumed its fourth different corporate form when it was sold to the

public for the first time in its history. As a publicly owned company, UOP entered a

new era marked by growth and diversification. The 1960s saw UOP grow from

essentially a process-licensing company to a diversified corporation through many

acquisitions and mergers with other companies. By 1975, UOP Inc. included more

than 20 different divisions involved in such areas as aerospace and automotive

technology.

During the 1960s and 1970s, UOP's tradition of innovative process development

and commercialization continued with the licensing of the first Sorbex™ simulated

moving-bed countercurrent adsorption process in 1961 and the introduction of

UOP's CCR Platforming™ process early in the 1970s.

In 1975, Signal Companies Inc. acquired 50.5% of UOP and in 1978 acquired the

remaining 49.5%, making UOP a wholly owned subsidiary of the company. When

the Signal Companies merged with Allied Corporation in 1985, UOP Inc. became a

subsidiary of Allied-Signal Inc. As the result of reorganizations and restructuring by

its parent companies during the 1980s, UOP’s business scope was refocused on

the development and licensing of process technology and the marketing of products

associated with its licensing activities. Of the 20 different divisions, only the Process

Division and UOP Management Services remain in the present UOP.

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In 1988, Allied-Signal entered into an agreement with Union Carbide Corporation

that resulted in the creation of a unique joint venture company called simply UOP.

The new UOP combined the resources of Allied-Signal’s UOP Inc. with the

Catalysts, Adsorbents and Process Systems (CAPS) Division of Union Carbide. The

joint venture brought together in synergistic union the strong R&D traditions of both

companies. The joint venture now contains the new materials R&D of the CAPS

Union Carbide researchers and the scale-up and commercialization skills of UOP

research. In addition, the joint venture brings together the commercial experience

and worldwide marketing presence of both partners. The result is unprecedented

growth for UOP and the development of valuable new technologies, products, and

services for its customers. Table 1 summarizes some of the historical highlights of

UOP as a process technology company.

Table 1 UOP's History

1914 National Hydrocarbon Company formed to hold Jesse Dubbs

patents for a process to recover heavy oil from water

1915 Name changed to Universal Oil Products Company --

patents for Dubbs cracking process issued

1921 Dubbs continuous cracking process commercialized

1930 Ipatieff joins UOP beginning a wave of new process develop-

ments: alkylation, catalytic polymerization, C4 isomerization

1941 FCC technology developed

1949 Platforming™ introduced, many aromatics processes followed

Late 1950s Hydrocracking introduced

1961 First Sorbex™ unit licensed

Early 1970s CCR Platforming™ introduced

1988 UOP merged with the EP&P and CAPS groups of Union Carbide

1995 UOP acquires the Unocal hydroprocessing business

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In the last 20 years, UOP has developed and commercialized a variety of new and

innovative processes for the refining and petrochemical industry including the

Penex™, Molex™, BenSat™, Oleflex™, Ethermax™, Merox™, Styro-Plus™,

Alkylene™, Isal™, Isomar™ and Detal™processes.

UOP transfers this technology to its clients through its licensing activity. In the

technology transfer process, UOP licenses technology; assists in the planning,

design, engineering and commissioning of new installations; provides management

services and advises on the efficient performance of processing facilities throughout

the world.

Behind the successful performance record of UOP is a highly qualified and strong

team continuously at work on ideas and projects. The scientific disciplines are

strongly represented in UOP's team of personnel. UOP has about 4,000 employees

worldwide. With a wide array of highly specialized talents, UOP offers its clients the

complete capability necessary in meeting the demands of today, and the challenges

of the future.

UOP licenses or maintains a position of technical expertise for more than 60 differ-

ent processes in the petroleum and petrochemical industry. Approximately 175

process units are licensed yearly, and to date UOP has licensed more than 5,500

individual process units and provided technical know-how in designs for more than

1,000 additional non-licensed units. UOP presently holds in excess of 9,000

unexpired patents.

UOP's worldwide licensing activities are supported by a network of offices and

representatives. UOP is centered in Des Plaines, Illinois, and has a district office in

Houston. UOP Limited, a 100% UOP owned subsidiary for operations in Europe,

Africa and the Middle East, has its main European office in Guildford (near London)

and district offices in New Delhi, Jakarta, Jeddah, Beijing and Moscow. UOP Asia

Pacific, located in Tokyo, is an affiliate company of UOP for the licensing of UOP

processes in Japan and certain other areas in the Far East and Southeast Asia.

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UOP has catalyst manufacturing facilities in the United States and in Europe. UOP

Asia Pacific operates a catalyst plant in Japan.

The international scope of UOP activities is evidenced by the fact that process units

have been designed for installation in more than 80 countries around the world.

UOP activities related to these installations have ranged from preparation of

engineering designs for single process units to extensive planning studies involving

market analyses, feasibility and optimization studies, designs for entire grassroots

refineries (both process units and offsites), and complete plant commissioning

services.

The services provided by UOP for these units includes plant design, inspection,

commissioning, performance testing, and training of refinery operating personnel.

Since 1955, UOP has provided, or is providing, engineering designs for more than

125 grassroots refineries and petrochemical complexes. UOP also provided design

specifications for all offsite equipment for many of these installations.

Historical Origins of FCC Technology The advent of the petroleum refining industry can be traced to the rapidly increasing

demand for kerosene to fuel kerosene lamps for lighting in the latter half of the

1800s. With the invention of electric lighting and the automobile in the early 1900s,

the high value product of petroleum refining shifted from kerosene to gasoline. The

increasing demand for gasoline soon outstripped the availability of straight-run

gasoline from crude oil distillation. This shortage of gasoline provided the impetus

for the development of technologies to increase the gasoline yield from a barrel of

crude oil. Table 2 shows a summary of the progression of cracking technology

which has led to the FCC process as we know it today.

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Table 2 Historical Origins of Fluid Catalytic Cracking

1913 - 1936 Thermal cracking

Burton thermal cracking process (1913)

Dubbs thermal cracking process (1915)

Current use – visbreaking, coking

1936 - 1941 Fixed-bed catalytic cracking

Houdry Process Company (1931)

- Multiple reactors -- cyclic process (1937)

- Silica-alumina catalyst (acid-activated clay)

1941 - 1955 Moving-bed catalytic cracking

Thermofor catalytic cracking (TCC) developed by

Socony-Vacuum (Mobil)

Houdryform catalytic cracking

- Continuous process

- Macro-catalyst, moving bed

1942 - Present Fluid catalytic cracking (FCC)

Joint development (1938)

- Continuous process

- Micro-catalyst, fluidized bed

Thermal Cracking The first thermal conversion process was the Burton process first practiced

commercially in 1913 by Standard Oil of Indiana. In the original Burton process, oil

was exposed batch-wise to high temperature at elevated pressure to achieve

thermal conversion to lighter products. Because of the batch nature of the Burton

process, commercial units contained a large number of individual cracking stills in

order to achieve acceptable daily throughputs.

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Following the commercialization of the Burton process, the Dubbs thermal cracking

process was developed and patented in 1915 (UOP). The Dubbs process was a

continuous process for the thermal conversion of oil to lighter products at elevated

temperature and pressure. The Dubbs process was widely used in refineries

through the 1920s and into the 1930s.

Thermal cracking processes continue to be used in refining today. Examples of

currently used thermal processes are visbreaking and various forms of coking.

Fixed-Bed Catalytic Cracking In the mid 1920s, a French mechanical engineer and racecar enthusiast named

Eugene Houdry became interested in gasoline quality. After the trial and error

screening of hundreds of catalyst formulations, Houdry found that acid-activated

clay (silica and alumina) was an effective catalyst for cracking heavy oil to lighter

products, particularly high octane gasoline.

In 1931, Houdry, in partnership with Socony-Vacuum (now Mobil), founded the

Houdry Process Company to develop Houdry's fixed-bed catalytic cracking process.

The Houdry catalytic cracking was a cyclic process which typically used four time-

phased reactors, each of which cycled through a sequence of steps outlined below:

1. Hot heavy oil is cracked by contact with a fixed bed of catalyst.

2. The reactor is purged to remove hydrocarbon.

3. Coke deposited on the catalyst is burned off with air.

4. The combustion gases are purged from the reactor and the reactor

is ready to begin the next cracking cycle.

A number of technical innovations were required to make the Houdry cracking

process successful. Among these were the development of automatic valves and

the use of control algorithms to control the reaction-regeneration cycles. Many of

the innovations associated with the commercialization of the Houdry cracking

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process were considered revolutionary in the field of process engineering at the

time they were first introduced.

The Houdry catalytic cracking process was first commercialized at the Sun-Marcus

Hook refinery in 1937. The Houdry process was technically attractive to refiners and

by 1940, 14 commercial Houdry units were in operation. Interest in the Houdry

process declined after 1941 because of further advances in catalytic cracking

technology.

Moving-Bed Catalytic Cracking The next advance in catalytic cracking was the development of a continuous

moving-bed cracking process. The Thermofor Catalytic Cracking (TCC) and

Houdryform Catalytic Cracking (HCC) processes were developed in parallel in the

1940s and early 1950s. Both processes used a similar concept and had

approximately equal success.

In the TCC process, the catalyst pellets continuously move through the reactor to

the regeneration vessel and are then returned to the reactor. The key to the TCC

process was the Thermofor kiln used to regenerate the spent catalyst (the kiln had

been originally developed to burn coke off of Fuller’s earth used to filter lube oils).

In the TCC process, regenerated catalyst flows by gravity from a surge vessel

elevated above the reactor, into the reactor vessel where the catalyst contacts hot

oil and the cracking reactions take place. The air environment of the catalyst surge

vessel is buffered from the hydrocarbon environment of the reactor by steam

injected into the catalyst transfer line. Both the hydrocarbon vapors and catalyst

flow down through the reactor to a lower section where the cracked products exit

the reactor through separation pipes. The spent catalyst continues to flow by gravity

down through a steam stripping zone into the regeneration kiln where coke is

burned off the spent catalyst with air. The steam stripping zone also serves to

provide a barrier between air in the regenerator and hydrocarbon in the reactor. In

early TCC units, the hot regenerated catalyst pellets were mechanically conveyed

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back up to the catalyst surge vessel by bucket elevators. Later units employed

pneumatic air lift systems to transfer the regenerated catalyst back up to the surge

vessel.

Socony-Vacuum was the principle developer of the TCC process and the first semi

commercial unit started up at the Paulsboro refinery in 1941. The TCC units were

licensed and operated by Socony-Vacuum and others from 1941 to about 1955

when the TCC gave way to the more versatile FCC process developed in the during

the late 1930s and early 1940s. A few TCC units still continue to operate today.

The FCC Process Early development of the FCC process took place late in the 1930s. A number of

motivations were behind the development of the FCC process. Among these were

the high fees required to license the Houdry cracking process, the diffusion and

heat transfer limitations associated with both the Houdry fixed-bed process and the

TCC process (both used large size catalyst pellets), and the increasing demand for

high octane aviation gasoline brought on by World War II.

Initial FCC process development efforts were led by Standard Oil of New Jersey

(now Exxon) in association with two researchers from the Massachusetts Institute of

Technology, Warren Lewis and Edwin Gilliland (consultants to Standard-NJ). Lewis

and Gilliland had found that under the proper aeration conditions, finely divided solid

particles (powders) could flow through pipes and in many respects act similarly to

liquids. This was the advent of fluidization. The use of finely divided cracking

catalyst offered a means of overcoming the diffusion and heat transfer limitations

encountered with the large size catalyst pellets used in the earlier catalytic cracking

processes.

In 1938, Standard-NJ and some of the other major oil companies, as well as M. W.

Kellogg Co. and Universal Oil Products (UOP), formed Catalytic Research Associ-

ates (CRA) to jointly develop a fluidized catalytic cracking technology. The first

commercial-scale (13,000 BPD) FCC unit, designated the Model I, started up at

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Standard-NJ's Baton Rogue refinery in May 1942. Two other Model I FCC’s were

designed but were not built as the improved Model II FCC design came very

quickly. When Standard-NJ announced the construction and imminent startup of the

first FCC Model I, they also announced that Universal Oil Products (UOP) and M.

W. Kellogg would be designing and licensing the new FCC technology. In the three-

year period between 1942 and 1945, 34 new FCC units came on stream in the

refineries of 20 different oil companies. The installed capacity of these new FCC

units was over 500,000 BPD. Thirteen of these units were licensed from UOP.

Following the commercialization of the Model I and Model II FCC units within the

CRA partnership, the FCC unit design and development diverged with the partner

companies largely going their separate ways with regard to future FCC technology

development and commercialization.

UOP and Fluid Catalytic Cracking During the 1940s, military requirements resulted in widespread commercialization

when UOP designed about 40% of the 34 units that were built and operated.

Following this period, UOP was in the forefront with commercialization of the

"stacked" FCC unit design which featured a low-pressure reactor stacked directly

above a higher pressure regenerator. The stacked design not only met the

economic needs of smaller refiners, it was a major step toward shifting the cracking

reaction from the dense phase of the catalyst bed to the dilute phase of the riser. In

the mid-1950s, UOP introduced the "straight-riser" or side-by-side design. In this

unit, the regenerator was located near ground level with the reactor to the side in an

elevated position. Regenerated catalyst, fresh feed and recycle were directed to the

reactor by means of a long, straight riser located directly below the reactor.

Compared to earlier designs, product yields and selectivity were substantially

improved.

A major breakthrough in catalyst technology occurred in the mid-1960s with the

development of the zeolitic catalysts. These catalysts demonstrated vastly superior

activity, gasoline selectivity and stability characteristics compared to the amorphous

157048 Introduction

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silica-alumina catalysts then in use. The availability of the zeolitic catalysts served

as the basis for most of the process innovations that have developed in recent

years.

The continuing sequence of advances in both catalyst activity and process design

culminated in the most significant concept to date in the field of the FCC process –

the achievement of transport-phase cracking entirely in the riser, or all-riser crack-

ing. The key to all-riser cracking is the design of a system that initiates a plug-flow

reaction and then stops the cracking reaction at the optimum yield of desired

products. UOP commercialized a new design based on this concept in 1971. This

design was also applied to existing unit revamps. Commercial results confirmed the

expected advantages of the system compared to the older designs. The quick

quench design provided the desired high selectivity to gasoline, reduced coke yield,

and a reduction of secondary cracking of desired products to lighter, less valuable

material.

The next major improvement in the FCC technology was the development of

catalysts and regenerator systems for the complete internal combustion of carbon

monoxide (CO) to carbon dioxide (CO2). In 1973, an existing UOP unit was

revamped to include a new combustor concept in regeneration technology to

achieve direct conversion of CO within the unit. This was followed by the start-up in

1974 of a new FCC unit specifically designed to incorporate the combustor

regenerator technology.

This development in regenerator design and operating technique resulted in

reduced coke yields, lower CO emissions which satisfy environmental standards

and higher circulating catalyst activity that improved product distribution and quality.

Table 3 summarizes some of the major achievements in UOP's FCC process

technology development and commercialization.

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Table 3 Milestones in FCC Technology

1942 UOP begins licensing the FCC Process

1945 13 Units licensed by UOP

1947 UOP commercializes stacked unit design

Economical for small refiners

50 Stacked designs over 10-year period

1950s UOP commercializes side-by-side design

Straight riser

Better suited for larger units

Riser extension and termination

(more reaction in riser)

1973 First complete combustion regenerator

1983 First two-stage regenerator with external dense-phase

cooling for highly contaminated resid feed commissioned

1983 First elevated distributors commissioned

1991 - 1995 Newest generations of highly contained riser termination

devices commercialized (VDS™ and VSS™)

1994 First Optimix™ feed distributor commissioned

1994 First MSCC™ unit commissioned

2006 First AF™ Packing commissioned

Recent Developments Advances in riser termination devices occurred at a rapid rate in the 1980s to the

mid 1990s. Early riser termination devices such as the open Tee resulted in very

long residence times for the hydrocarbon products in the reactor vessel. This

extended residence time resulted in nonselective thermal cracking and secondary

catalytic cracking reactions. Recent improvements have resulted in better contain-

ment of the hydrocarbon vapor to the riser and therefore lower post riser residence

time. This reduced delta coke and dry gas and improved gasoline selectivity. Early

versions of these high containment riser terminations included the vented riser and

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SCSS (suspended catalyst solids separation) devices. In 1991, the first VDS™

(vortex disengager stripper) was commissioned. This technology further minimized

the post-riser residence time resulting in further improvements in product yields. In

1995, the first VSS™ (vortex separation system) was commissioned.

Improvements in feed distribution systems also occurred rapidly in the late 1980s

and 1990s. Elevated, radially oriented feed distributors minimize nonselective

thermal cracking reactions by providing more uniform feed/catalyst contacting with

less back mixing than the earlier wye feed distributors. Acceleration zone

technology which pre-accelerates the catalyst into a uniform, moderate density flow

pattern for optimum oil penetration and uniform catalyst/oil contacting further

improved the performance of the elevated feed distributors. The first UOP elevated

feed distributors were commissioned in 1983. Developments in spray nozzle

technology resulted in the Optimix™ feed distributor which has a smaller, more

uniform oil droplet size and a spray pattern that distributes the oil uniformly over the

entire riser area for superior catalyst/oil contacting and performance. The first

Optimix™ feed distributor was commissioned in 1994. Since then, the number of

refiners using Optimix™ feed distributors has grown to over 80.

Resid processing in FCC units began in the mid-1970s. During this same period,

reactor temperatures were being increased to maximize gasoline octane. The need

for higher conversion, combined with the desire to process residue feeds signifi-

cantly increased coke yields and ultimately limited the FCC regenerator capacity.

The RCC®, or Reduced Crude Conversion, process was developed jointly by UOP

and Ashland Oil in the late 1970s to address residue processing. It is an extension

of UOP's FCC design experience that incorporates many innovations and modifica-

tions from the UOP-Ashland Oil development program. In addition to cold-flow

modeling work, a large-scale pilot plant was constructed at Ashland's Catlettsburg,

Kentucky refinery. Testing in this 200 BPSD plant examined processing variables

and new mechanical designs on a wide range of residual feedstocks. In 1983,

Ashland commissioned a 40,000 BPSD RCC unit at the Catlettsburg refinery.

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Several major innovations from the pilot plant testing and first commercial design at

Ashland have become the foundation of UOP's technical offering for catalytic

cracking of residue feedstocks, including the following.

• Acceleration zone and feed distribution system

• Higher containment riser termination devices for quick disengagement

• Two-stage catalyst regeneration

• Catalyst cooler

Since 1983, eight grass-root RCC units licensed by UOP have been commissioned.

In addition, resid feedstocks are being processed in more than 30 existing UOP

FCC units. In present times, the distinction between a gasoil FCC unit and a resid

FCC unit has blurred to the point where most modern FCC units are capable of

processing some level of resid. The term RFCC is used by UOP today to designate

a new unit utilizing a 2 stage regenerator designed for the specific intent of

processing resid feeds. Table 4 shows a brief summary of resid processing and

UOP's activity in the area of resid processing.

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Table 4 Resid Processing Milestones

1940s Resid component added to feed

1950s Resid processing diminishes

1975 Resid processing regains attractiveness

Market conditions favor increased efficiency in

gasoline production

Technology and catalyst advances increase resid

processing potential

UOP units begin processing resid/gasoil blends

1976 UOP and Ashland Oil Cooperation

Research and development for reduced crude

conversion

Semi-commercial demonstration

1983 First RCC unit commissioned

1984 - 2006 8 New RCC units operating --

>30 Units processing resid

Commercial Experience

Since commercialization of the FCC process, UOP has licensed more than 210

units, or over 50% of all non-captive installations. More than 140 of these units

continue to operate throughout the world. The superior technology and operational

reliability built into UOP FCC units are some of the reasons why 58 refineries

worldwide have licensed new UOP FCC units since 1980, which is more than all

other licensors combined during this period. UOP's commercial activity in the

FCC/RCC/MSCC™ processes since 1980 is as follows:

63 New units licensed

40 New units commissioned

330 Revamps

180 Major revamps

30+ Units processing resid with UOP technology

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Revamp activity is of equal importance in demonstrating technical expertise. In the

period 1980-1998, UOP performed more than 330 unit revamps that encompassed

virtually every major section of the FCC unit. This activity is vital to UOP's continu-

ing advances in both process and design engineering. The depth of both grass-root

and revamp experience gives UOP great capability to respond to the changing

needs of the industry.

FCC Process Description The FCC process converts heavy crude oil fractions into lighter, more valuable

hydrocarbon products at high temperature and moderate pressure in the presence

of a finely divided silica/alumina based catalyst. In the course of cracking large

hydrocarbon molecules into smaller molecules, a non-volatile carbonaceous

material, commonly referred to as coke, is deposited on the catalyst. The coke laid

down on the catalyst acts to deactivate the catalytic cracking activity of the catalyst

by blocking access to the active catalytic sites. In order to regenerate the catalytic

activity of the catalyst, the coke deposited on the catalyst is burned off with air in the

regenerator vessel.

One of important advantages of the FCC process is the ability of the catalyst to flow

easily between the reactor and the regenerator when fluidized with an appropriate

vapor phase. In FCC units, the vapor phase on the reactor side is vaporized hydro-

carbon and steam, while on the regenerator side the fluidization media is air and

combustion gasses. In this way, fluidization permits hot regenerated catalyst to

contact fresh feed; the hot catalyst vaporizes the liquid feed and catalytically cracks

the vaporized feed to form lighter hydrocarbon products. After the gaseous hydro-

carbons are separated from the spent catalyst, the hydrocarbon vapor is cooled and

then fractionated into the desired product streams. The separated spent catalyst

flows via steam fluidization from the reactor to the regenerator vessel where the

coke is burned off the catalyst to restore its activity. In the course of burning the

coke a large amount of heat is liberated. Most of this heat of combustion is

absorbed by the regenerated catalyst and is carried back to reactor by the fluidized

regenerated catalyst to supply the heat required to drive the reaction side of the

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process. The ability to continuously circulate fluidized catalyst between the reactor

and the regenerator allows the FCC unit to operate efficiently as a continuous

process.

The FCC units are large-scale processes and unit throughputs are typically in the

range of about 10,000 to 130,000 barrels per day. This corresponds to catalyst

circulation rates of around 7 to 130 tons per minute. The largest commercial FCC

unit in operation was designed at 130,000 BPSD, pushed to ~184,000 BPSD, and

in 2005 was revamped to a nominal 200,000 BPSD with a catalyst circulation rate in

excess of 170 metric tons per minute. These large circulation rates of hot, abrasive

catalyst constitute a very significant challenge to the mechanical integrity of the

reactor, the regenerator and their associated internal equipment. Thus, mechanical

design considerations are critical to the ultimate success of an FCC unit as a

prominent refinery process unit. The main features of an FCC unit are:

Catalytic process

Mechanical process

Cracks heavy molecules to lighter ones

Pressure: 15-45 psig (1-3 kg/cm2g)

Temperature:

Reactor: 915-1050F (490-565C)

Regenerator: 1200-1450F (650-790C)

Reaction and regeneration sections intimately

linked by heat balance and catalyst circulation

FCC Process Feedstocks FCC units process heavy oil from a variety of variety of refinery flow schemes.

Generally, the feed comes from either the refinery crude unit or vacuum unit and

constitutes the fraction of the crude boiling in the range of 650 to 1000+°F (350 to

550+°C). There may be additional feed preparation units upstream of the FCC unit

such as a hydrotreater or deasphalter. Figure 1 shows a schematic diagram of the

possible refinery flows providing feed to an FCC unit.

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In addition, the FCC units commonly process heavy fractions from other conversion

units as part of the combined FCC feed blend. Examples of these types of streams

are coker gasoil and hydrocracker fractionator bottoms. The types of heavy hydro-

carbon streams that are commonly charged to an FCC unit are:

Atmospheric gasoil

Vacuum gasoil

Atmospheric resid

Coker gasoil

Demetallized oil

Hydroprocessed gasoil

Hydroprocessed resid

Lube oil extracts

157048 Introduction

Page 20

FCC Products The products obtained from the FCC unit are light hydrocarbon gases (C2-) which

are normally used within the refinery as fuel gas, light olefins and paraffins (C3’s

and C4’s) also referred to as LPG, gasoline, LCO and clarified oil commonly

referred to as main column bottoms. In addition, flue gas is generated from the

burning of coke in the regenerator. Heat is recovered from the flue gas and is used

to make steam and in some cases power is also recovered from the flue gas in the

form of electricity via a power recovery expander coupled to a motor/generator.

Products produced from an FCC unit are:

Light gas

Light olefins

Light paraffins

Gasoline

Light cycle oil

Main Column Bottoms

Coke (burned in unit as fuel)

Most of the FCC product streams undergo further processing before leaving the

refinery as marketable products. Figure 2 shows typical routes for the FCC product

steams going to further processing and ultimately to blending into the refinery

product pools.

LPG

157048 Introduction

Page 21

Reactor&

Regen.

MainColumn

&Gas Con

LPG Pool

GasolinePool

DieselPool

Heavy FuelOil Pool

LPGMerox

GasolineMerox

Flue Gas

Fuel Gas

C3/C4

Splitter

Alkylation Alkylate

C3/C4

Paraffins

MTBE

DistillateHydrotreaterLCO

CLO

Gasoline

Figure 2Typical Use of FCC Products

The light liquid products from the FCC process are LPG and gasoline. The LPG

from an FCC unit is highly olefinic and has become an increasingly valuable stream

for further processing in the present movement toward reformulated gasoline and

as petrochemical unit feedstocks. The FCC olefins are an important feedstock for

the production of MTBE and alkylate as gasoline blending components and for the

production of polypropylene. The FCC gasoline generally has good octane proper-

ties (90-95 RON and 80-83 MON) and may make up 30 vol-% or more of the

refinery gasoline pool. Some typical characteristics of light FCC products from high-

conversion operations (VGO Feed, 1.0 wt% sulfur) are:

157048 Introduction

Page 22

LPG:

500 - 1500 wppm total sulfur

30 - 40 vol-% C3 olefins

34 - 45 vol-% total C4 olefins

Gasoline: C5 - 380F 90% point (193C 90% point)

92 - 94 RONC

0.1 - 0.2 wt-% sulfur

30 - 40 vol-% olefins

25 - 35 vol-% aromatics

0.5 - 1.0 vol-% benzene

The heavy liquid products from an FCC unit are normally LCO and clarified oil. The

LCO product is normally used as a blending component in the diesel pool and/or in

the heavy fuel oil pool. It is becoming increasingly common for LCO destined for

diesel blending to be hydrotreated first for sulfur reduction. Clarified oil is usually

blended off to the heavy fuel oil pool. In some cases, the FCC unit clarified oil is

used in coker feed, for asphalt production or sold as feed for carbon black produc-

tion. Some characteristics of heavy FCC products from high conversion operations

(VGO Feed, 1.0 wt% sulfur) are:

Light cycle oil: 600F 90% point (316C 90% point)

20 - 26 cetane index

1 – 1.5 wt-% sulfur

75 - 80 vol-% aromatics

3 - 3.5 cSt @ 122F (50C)

Clarified slurry oil:

2 - 3 wt-% sulfur

9 - 13 cSt @ 210F (100C)

Source: Middle Eastern light gasoil

157048 Introduction

Page 23

157048 Introduction

Page 24

Abbreviations and Definitions

ABD average bulk density

ACFM actual cubic feet per minute

activity conversion of oil by test catalyst compared to standard

reference feed often referred to as MAT activity

adjusted conversion or yields reported as corrected to standard

product cutpoints

afterburning burning of CO above the dense bed in the dilute phase or

flue gas, characterized by temperature increase

AGO atmospheric gasoil

Al aluminum

Al2O3 alumina

APS average particle size

AR atmospheric column resid

ash non-combustible particles remaining after burning of a

main column bottoms sample

as produced conversion or yields reported as percent of fresh feed at

the actual product rates not adjusted to standard product

cut points

ASTM American Society for Testing and Materials

ßo Coefficient of thermal expansion at 60°F, (1/°F)

behind in burning insufficient coke combustion in regenerator,

characterized by increased coke production in reactor

and dark grey regenerated catalyst (high carbon on

regenerated catalyst)

BPD barrels per day

157048 Introduction

Page 25

BS & W bottoms sediment and water, normally reported in vol-%

C1, C2 methane, ethane, ...

C3= olefin (propylene)

caustic sodium hydroxide

CCR catalyst circulation rate

CFR combined feed ratio (volume of fresh feed plus recycle,

divided by volume of fresh feed)

CN- cyanide ion

CO2/CO mole ratio of carbon dioxide to carbon monoxide,

indicates degree of partial combustion

cold regenerator operation in conventional controlled regenerator

afterburning mode of regeneration

conversion measure of the rate of gasoil disappearance (or

conversion) from feed to products defined as

COS carbonyl sulfide

CRC carbon on regenerated catalyst

CSO clarified slurry oil

Cu copper

DA, DS, DG reactor or regenerator purges using air, steam or gas,

respectively

P, DP pressure drop or pressure difference between two points

dry gas gas from sponge absorber (usually refers to C2-)

EP end point of distillation

F-1 research octane number (RON)

F-2 motor octane number (MON)

157048 Introduction

Page 26

Fe iron

Fines catalyst particles less than 20 microns diameter

Fm feed metals factor

Gasoline efficiency ratio of liquid vol-% gasoline to vol-% conversion,

indicates selectivity to produce gasoline

GC, GLC gas chromatography, gas/liquid chromatography

Gb Fluid gravity at base temperature (60°F)

Gf fluid gravity at flowing temperature

gpm gallons per minute

H2/C1 ratio of moles hydrogen to moles of methane

H2S hydrogen sulfide

HC hydrocarbon

HCN heavy cat naphtha product drawn from the side of the

main column

HCO heavy cycle oil

HPS high pressure separator

H enthalpy (heat) difference

IBP initial boiling point of distillation

K (UOP K) measure of paraffinicity or aromaticity of hydrocarbon

lb/Bbl (#/Bbl) pounds per barrel

LCO light cycle oil

LV-% liquid volume percent

M prefix for thousand

MC main column

157048 Introduction

Page 27

MCB main column bottoms product

MON motor octane number

MW molecular weight

N (or N2) nitrogen

Na sodium

NH3 ammonia

Ni nickel

NOx nitrogen oxides

O (or O2) oxygen

ppm parts per million

Pf Pressure at flowing conditions (absolute)

recycle normally refers to heavy oil from main column which has

already passed through the reactor that is returned with

the fresh feed to the reactor, this could also refer to light

material such as LCO or gasoline; a stream which returns

to its source.

RE (or Re2O3) rare earth (or rare earth oxide)

Rg regenerator

RON research octane number

RSH mercaptan sulfur

RVP Reid vapor pressure

Rx reactor

SA surface area

SCF/Bbl (SCFB) standard cubic feet per barrel of fresh feed

157048 Introduction

Page 28

SCFD standard cubic feet per day

selectivity preferential towards specified goal or species

severity combines different factors to give an overall qualitative

measurement of extent or difficulty in cracking and

regeneration

Si silicon

Si2O3 silica

sintering closure of catalyst pores

SOX sulfur oxides

spillback gas recycle, may also refer to liquid recycle

SS stainless steel, also second stage

Tf temperature at flowing conditions (absolute)

V vanadium

VGO vacuum gasoil

vol-% volume percent

wt-% weight percent

157048 Introduction

Page 29

UOP P&I Diagram Abbreviations

AR Analysis Recorder

ARC Analysis Recording Controller

DR Specific Gravity Recorder

FA Flow Alarm

FE Orifice Flange Assembly

FFRC Flow (ratio) Recording Controller

Fl Flow Indicator

FIC Flow Indicator Controller

FIF Flow Indicator Flow Type

FQI Flow Meter Displacement Type

FR Flow Recorder

FRA Flow Recording Alarm

FRC Flow Recording Controller

FRCF Flow Recording Controller Float Type

FRCQI Flow Recording Controller Integrator

FRQI Flow Recorder Integrator

FRQIA Flow Recorder Integrator Alarm

HC Hand Control

II Current Indicator

LA Level Alarm

LC Level Controller

LG-B Gage Glass Boiler Type—Visible Length Shown

157048 Introduction

Page 30

LG-R Gage Glass Reflex Type—Visible Length Shown

LG-RLT Gage Glass Reflex Type

Visible Length Shown—Low Temperature

LG-T Gage Glass Through View Type

Visible Length Shown

LG-TK Gage Glass Through View Type

Visible Length Shown—KEL-F

LG-TLT Gage Glass Through View Type

Visible Length Shown—Low Temperature

Ll Level Indicator

LIA Level Indicating Alarm

LIC Level Indicating Controller

LR Level Recorder

LRA Level Recording Alarm

LRC Level Recording Controller

PA Pressure Alarm

PC Pressure Controller

PDC Pressure Differential Controller

PDI Pressure Differential Indicator

PDIC Pressure Differential Indicating Controller

PDR Pressure Differential Recorder

PDRA Pressure Differential Recording Alarm

PDRC Pressure Differential Recording Controller

PDRCA Pressure Differential Recording Controller Alarm

157048 Introduction

Page 31

PI Pressure Indicator

PIA Pressure Indicating Alarm

PIC Pressure Indicating Controller

PR Pressure Recorder

PRA Pressure Recording Alarm

PRC Pressure Recording Controller

SI Speed Indicator

SR Speed Recorder

TA Temperature Alarm

TC Temperature Controller

TDR Temperature Differential Recorder

TDRA Temperature Differential Recording Alarm

TDRC Temperature Differential Recording Controller

TI Temperature Indicator

TIC Temperature Indicating Controller

TIX Temperature Indicator Skin

TR Temperature Recorder

TRA Temperature Recording Alarm

TRC Temperature Recording Controller

TRX Temperature Recorder Skin

TW Thermowell

Zl Valve Position Indicator

157048 Introduction

Page 32

When Instruments Are Designated with an Alarm

H Indicates High

HH Indicates High-High, typically in association with an Emergency

Shutdown (ESD) system trip point

L Indicates Low

LL Indicates Low-Low, typically in association with an Emergency

Shutdown (ESD) system trip point

157048 Process Flow

Page 1

PROCESS FLOW

INTRODUCTION

The modern Fluid Catalytic Cracking unit is a large and complex process for

cracking heavy gas oil to lighter hydrocarbons. FCC has largely replaced the old

thermal crackers because it is a more efficient process, i.e. more production of

valuable products at a lower overall cost by using catalyst and heat instead of

simply heat.

In its simplest form, the process consists of a reactor, a catalyst regenerator, and

product separation. This is shown in Figure 1. Catalyst circulation is continuous, at

very large mass flow rates. For this reason, the reactor and regenerator are usually

discussed as one section. The product separation is usually divided into its low and

high pressure components, i.e. the main column section, and the gas concentration

and recovery section.

Figure 1:

Fluid Catalytic Cracking Process

Regenerator Reactor

CatalystTransfer

LinesProduct

Separation

Raw OilAir

Flue Gas

Products

157048 Process Flow

Page 2

Reactor-Regenerator

This is the heart of the process, where the heavy feed is cracked. The reaction

products range from oil which is heavier than the charge to a light fuel gas. The

catalyst is continuously regenerated by burning off the coke deposited during the

cracking reaction. This provides a large measure of the heat required for the

process.

Main Column

The main column cools the reactor vapors and begins the separation process. A

heavy naphtha fraction and light and heavy fuel oils (LCO and CLO) come off the

tower as products; gasoline and lighter materials leave the top of the tower together

and are cooled and separated further into product streams in the gas concentration

section.

Gas Concentration and Recovery

This section separates the main column overhead into gasoline, liquefied petroleum

gas, and fuel gas streams. The composition of each stream is controlled for

maximum product value. Figure 2 shows a slightly more detailed schematic of an

FCC unit.

157048 Process Flow

Page 3

Fig

ure

2F

CC

Blo

ck F

low

Dia

gram

FC

C-P

F0

02

Ste

am

Raw Oil

Cat

alys

tS

ecti

on

Po

wer

Rec

ove

ryS

ecti

on

Flu

e G

asC

oo

ler

Flu

eG

as

Mai

n C

olu

mn

Sec

tio

nG

as C

on

Sec

tio

nF

uel

Gas

MC

BL

CO

HC

OH

eavy

Nap

hth

a

Lig

ht

Nap

hth

aL

PG

BF

W

157048 Process Flow

Page 4

PROCESS FLOW DESCRIPTION Reactor-Regenerator

The FCC process was developed in the early 1940's. A number of companies

participated in the early stages of the work, so most of the early units were virtually

identical. The first design, the Model I, was installed at only three refineries and

quickly replaced by a more successful Model ll. Thirty-one of these were built,

thirteen designed by UOP. Figures 3 and 4 show the configurations of the Model I

and the Model II FCC’s, respectively.

The Model II units had double slide valves and long standpipes, which were a prime

source of operating problems due to loss of catalyst fluidization in the standpipes.

The raw oil charge passed through a dense bed of fluidized catalyst in the reactor

vessel; however, evidence indicated that a large part of the desired cracking was

occurring in the transfer line where the hydrocarbon first contacted the catalyst.

The early units used low activity catalysts by today's standards, starting with natural

clay and later progressing to amorphous synthetic silica/alumina catalysts. Large

amounts of heavy oil were recycled back to the reactor in order to obtain the

desired conversion levels of 40-60 vol-%.

UOP introduced a major departure from the Model ll design in 1947. The

regenerator riser was eliminated and the regeneration air was injected directly into

the regenerator dense bed. Single slide valves and the more compact design cut

construction costs. An important feature of the design was a long reactor riser,

which was a major advantage as FCC technology advanced toward entirely riser

cracking. The UOP Stacked FCC design proved to be quite popular and UOP

designed about 50 Stacked FCC units. Figure 5 shows the typical arrangement of

the UOP Stacked FCC unit.

157048 Process Flow

Page 5

Figure 3: Model I FCC

Steam

WaterCatalystRecycleCooler

FiredHeaterRaw Oil

Charge

Regenerator

Reactor

CottrellPrecipitator

Flue Gas

CatalystFines

Products toMain Column

Cyclones

Hoppers

SteamAir orSteam

Standpipes

ReactorRiser

RegeneratorRiser

FCC-PF003

157048 Process Flow

Page 6

Figure 4

Down-flow Model II Catalytic Cracking Unit

Raw OilCharge

MCBRecycle

Air

Steam toStrippingSection

Reactor

Products toMain Column

MulticyclonesWasteHeat

Boiler

FlueGas

CottrellPrecipitator

Regenerator

FCC-PF004

157048 Process Flow

Page 7

Figure 5

UOP Stacked Fluid Catalytic Cracking Unit

To Main Column

Cyclone

Reactor

Spent CatalystStripper

StrippingSteam

Air

Slurry Recycle

HCO RecycleRaw OilCharge

Flue Gas

OrificChamber

Regenerator

Spent CatalystSlide Valve

Flue GasSlide Valve

Regenerated CatalystSlide Valve

FCC-PF005

157048 Process Flow

Page 8

The next advance in reactor-regenerator design was the Side-by-Side unit, shown

in Figure 6. This design was better for larger units, where stacking the reactor on

top of the regenerator became more expensive. The Side-by-Side layout has also

been used for many of the new small units. The straight riser showed less erosion

than the curved riser of the Stacked unit. Some of the Side-by-Side units were

designed with a reactor dense bed. This bed was eliminated with the advent of

zeolite cracking catalysts, and the riser was extended within the reactor to minimize

thermal and catalytic cracking by reducing vapor residence time in the vessel.

Initially, cyclones were installed on the riser to separate the oil and catalyst, but this

was not particularly successful due to poor cyclone performance. The riser cyclones

were replaced by a "Tee" shaped termination at the top of the riser. The riser

cyclone could then be moved over to allow room for the addition of another cyclone

at the reactor outlet, providing two stages of cyclone separation. Later advances in

riser termination devices concentrated on maximizing hydrocarbon containment or

minimizing the post-riser residence time in the reactor shell where non-selective,

thermal and secondary cracking reactions occur. Side-by-Side units have won

good acceptance by the industry and over 75 UOP designed Side-by-Side FCC

units have been built.

Zeolite cracking catalysts were developed in 1963 and gradually accepted by the

industry over the next ten years. These catalysts proved to be much more active

than amorphous catalysts and were ideally suited for the short contact time riser

cracker. Conversion levels rose as high as 80% without requiring excessive reactor

temperature.

Another significant improvement in FCC reactor technology was the use of elevated

feed distributors. The older wye feed distributors injected the raw oil charge into a

highly back-mixed catalyst flow that resulted in non-uniform oil/catalyst mixing and

excessive light gas and coke formation. In newer systems, multiple, radially oriented

feed distributors elevated in the riser inject raw oil more uniformly to maximize

selectivity to desired products.

157048 Process Flow

Page 9

New regenerator designs were also developed over the years. The old perforated

plate air distributor was changed to a pipe grid for better air distribution. Two stage

cyclones replaced single stage cyclones and reduced catalyst losses.

The burning of coke in the old regenerators was not complete, i.e., not all the carbon went to CO2, and the flue gas normally contained 6-10 vol-% CO. The unit

ran with no excess oxygen. This prevented afterburning in the cyclones and the

resultant heat damage to the cyclones. An extra furnace to generate steam, the CO

boiler, was added to utilize heat that would otherwise be lost. All of the excess CO

in the flue gas could be burned in the CO boiler, but capital costs were high. The obvious solution to this problem was to burn all of the CO to CO2 in the regenerator,

where the catalyst can absorb the heat.

Although this could be done in a standard “bubbling bed” regenerator, a new, “high

efficiency” type regenerator design proved more efficient. In the high efficiency or

combustor style regenerator, shown in Figure 7, the air and catalyst is mixed in a

fast fluidized environment in the lower part of the regenerator or combustor. The

fluidized catalyst is then carried up the combustor riser to the upper regenerator.

The fluidization in the combustor provides excellent air/catalyst mixing and heat

transfer to maximize coke burning kinetics. The high efficiency regenerators on

stream average less than 100 ppm CO, and less than 40 ppm NOx in the flue gas.

This design enables refineries to get greater thermal efficiency from the unit while

simultaneously meeting more stringent air quality standards.

157048 Process Flow

Page 10

Figure 6 UOP Side by Side Fluid Catalytic Cracking Unit

Raw

Oil Feed

Air

FlueGas

Rxn Products toMain Column

RegeneratedCatalys

Slide Valve

Bubbling BedRegenerator

Reactor

StrippingSteam

SpentCatalys

Slide Valve

Down-TurnedArm

Flue GasSlide Valve

WySection

Main Distributo

157048 Process Flow

Page 11

Figure 7 Modern UOP Side by Side Fluid Catalytic Cracking Unit

With High Efficiency Regenerator, Elevated Feed Distributors and Vortex Separation System Riser Termination

157048 Process Flow

Page 12

The process flow of the reactor and regenerator section of a typical, modern FCC

unit with a high efficiency regenerator can be described as follows:

Lift steam and/or light hydrocarbon is injected at the base of the riser or Wye to

accelerate the catalyst from towards the elevated feed distributors, which are

located about 1/3 the way up the riser. The preheated raw oil charge is pumped

through the feed distributors and atomized with the addition of steam then injected

into the regenerated catalyst stream. The heat from the catalyst and reduced

hydrocarbon partial pressure in the riser both act to help vaporizes the oil. The

catalyst, oil and steam travel up the riser to a region of lower pressure in the reactor

where the cracked hydrocarbon products are separated from the catalyst in the riser

termination device and cyclones before going to the main column for initial product

separation.

During the cracking reaction, a carbonaceous by-product called coke is deposited

on the circulating catalyst. This catalyst (referred to as spent catalyst) drops from

the reactor disengager and cyclones into the stripping section where a

countercurrent flow of steam is used to remove both interstitial and some adsorbed

hydrocarbon vapors. The stripped catalyst flows from the reactor stripper through

the spent catalyst standpipe to the regenerator, where the coke is continuously

burned off. The catalyst flow through the spent catalyst standpipe is controlled to

balance the circulating catalyst flow by maintaining a constant catalyst level in the

reactor.

In the regenerator, the spent catalyst mixes with air and hot regenerated catalyst

from the recirculation catalyst standpipe at the base of the combustor. Here the

coke deposited during in the reactor is burned off to reactivate the catalyst and

provide heat for the net endothermic cracking reactions. The heat of combustion

raises the catalyst temperature in the regenerator to a range of 1200°F-1375°F

(648°C-746°C). The catalyst and air flow up the combustor riser and separate at a

"Tee" shaped head. The flue gas is further "cleaned" of catalyst in the cyclones in

the upper regenerator. The recirculation catalyst standpipe returns some of the hot

regenerated catalyst to the combustor either on temperature or density control to

provide heat for initiation of the carbon burn. The remainder or the regenerated

157048 Process Flow

Page 13

catalyst flows down the regenerated catalyst standpipe on reactor temperature

control to the riser Wye to complete the cycle.

The flue gas exits the regenerator through the flue gas slide valves on pressure

control to the regenerator. An orifice chamber located downstream of the slide

valves acts to reduce the pressure drop and velocity across valves to minimize

mechanical deflection of the body and erosion to the internals. Many units have a

power recovery unit in place of the slide valve and orifice chamber to recover

electrical energy by letting down the high volume, moderate pressure flue gas

across a turbo-expander connected to a motor/generator. Finally the sensible heat

energy in the flue gas is recovered through steam generation in either a CO boiler

or flue gas cooler depending on the mode of operation in the regenerator. Many

units also have an electrostatic precipitator or wet gas scrubber to remove catalyst

fines from the flue gas before it is discharged to the atmosphere.

The reasons and methods for varying the high efficiency regenerator operation will

be discussed in more detail later in the PROCESS VARIABLES section.

RFCC Regenerator

As a result of the crude oil embargoes and oil price rises of the 1970’s, interest in

processing heavier feeds in FCC units grew. However, FCC technology at that time

could not handle highly contaminated heavy feeds while maintaining a reasonable

degree of conversion. In the mid 1970’s, UOP and Ashland Oil Company embarked

on a joint development project to develop catalytic cracking technology capable of

processing very heavy, highly contaminated feeds, i.e. feeds with high metals and

Conradson carbon contents. The result of this development program was the

commercialization of the RCCSM (Reduced Crude Conversion) process at Ashland’s

Catlettsburg refinery in 1983.

The main feature of the RCC unit is a two stage regenerator equipped with a

catalyst cooler to remove heat from the regenerator. The upper or first stage

regenerator burns approximately 2/3 of the coke from the catalyst in partial

combustion mode to limit the heat of combustion and therefore the temperature of

157048 Process Flow

Page 14

the catalyst. A portion of the partially regenerated catalyst entering the lower or

second stage regenerator flows through the catalyst cooler(s) where heat is

removed from the catalyst to generate steam. The cooled catalyst and the

remainder of the hot catalyst from the first stage regenerator mix in the second

stage regenerator where the coke burning is completed under conditions of complete CO combustion in the presence of excess O2. Carbon is burned off the

catalyst to low levels in the second stage regenerator at moderate temperature to

maximize catalyst activity. The combustion gases from the second stage regenerator pass into the first stage regenerator where the pre-heated excess O2

improves coke burn kinetics, and is completely consumed. The combined flue gas

exits through two stages of cyclones in the first stage regenerator and out through a

single common flue gas line. The overall mode of combustion for the two stage

regenerator is partial burn with the additional benefit that all of the catalyst returning

to the reactor is fully regenerated due to the full burn environment of the second

stage regenerator.

Figure 8 shows the arrangement of the regenerator of an RFCC unit. The reactor is

the same as the modern Side by Side unit shown in Figure 7.

Figure 9 shows the process flow for a catalyst cooler. Although catalyst coolers are

not a new idea for FCC service, past attempts to employ catalyst coolers on FCC’s

have been largely unsuccessful from both mechanical and process points of view.

UOP’s catalyst cooler represents an improved design developed and refined to

provide both mechanical reliability and a wide range of heat removal flexibility. Heat

removal varies with the rate of fluidization air injected to the cooler and the catalyst

slide valve opening.

The operation of the catalyst cooler is as follows; catalyst enters the cooler shell

where the tube bundle is immersed in hot fluidized catalyst. Fluidization air is

injected at the bottom of the cooler shell to control the fluidization and heat transfer.

Annular bayonet type water tubes are used in the tube bundle. Water entering the

bundle flows up through the inner tube, flows out the top of the inner tube and down

through the annular space between the inner and outer tubes where heat transfer

occurs and water is vaporized to steam. In flow-through style coolers cooled

catalyst exits the cooler shell through a standpipe and slide valve and is returned to

157048 Process Flow

Page 15

the regenerator to allow hot catalyst to enter the top of the cooler to maximize the

cooler duty. Back-mix type coolers rely only on fluidization and back-mixing to

transfer hot catalyst from the regenerator rather than using catalyst flow through a

standpipe. Back-mix coolers have a simpler mechanical configuration but can only

remove approximately 70% of the heat transfer capable through a flow-through

cooler.

A large excess of water is circulated through the tubes where heat transfer

generates steam to ensure that the tube walls are always wet and cooled. The

steam and water mixture returns from the cooler bundle to a steam drum where the

steam and water are separated. Water from the drum is circulated back to the

cooler and the saturated steam from the steam drum is routed to the refinery steam

system.

157048 Process Flow

Page 16

Figure 8 UOP RFCC Regenerator Process Flow

Second StageAir

FirstStage Air

Spent Catalystfrom Reactor

RegeneratedCatalyst to

Reactor

Vent Tubes

RecirculationCatalyst

Standpipe

Flue Gas

2nd StageRegenerator

1st StageRegenerator

CatalystCooler

Water/Steam

Water

157048 Process Flow

Page 17

Figure 9 UOP FCC Catalyst Cooler Process Flow

MakeupBFW

Saturated

Steam to

Superheater

Fluffing

Air

Blowdown

CirculatingWater

Water andSteam

FCC-PF009

Cooled CatalystSlide Vlave

157048 Process Flow

Page 18

Main Column

The main column is the first step in the separation and recovery of the cracked

hydrocarbon vapors from the FCC reactor. The reaction products enter the column

at high temperatures, 900-1022°F (480-550°C). The main column is similar to a

crude tower, with two important differences: 1) The vapors must be cooled before

fractionation can begin, and 2) a large quantity of lighter gas passes overhead with

the gasoline. Figure 10 shows the general process flow for an FCC main column.

Large quantities of heavy oil are circulated over a series of disc and doughnut trays

to cool the vapors and wash down entrained catalyst. The heat removed by the

main column bottoms and the heavy cycle oil is used for feed preheat, steam

generation, reboiler heat in the rest of the unit, or some combination of the three.

The catalyst washed out of the reactor is concentrated in the main column bottoms

stream.

Most of the bottoms flow is directed through exchangers for heat removal and

returned to the disc and doughnut trays. The return line must be free draining to

avoid plugging problems with catalyst fines settling in low points. Some of the

cooled bottoms material from the steam generators may be returned directly to the

bottom of the tower as quench to reduce the temperature of the liquid and minimize

coking and fouling in the bottoms system. Figure 11 shows a typical process flow

for the main column bottoms pumparound and product circuit.

Many older units used a slurry settler to separate and return catalyst fines to the

reactor with a slurry stream off the bottom of the settler. The main column bottoms

product comes off the top of the settler and is normally called clarified slurry oil. In

reactors with two stages of cyclones and in units with modern riser termination

devices, the use of slurry settlers has normally been discontinued. Heavy bottoms

product comes directly from the main column bottoms circulating stream, as does

any slurry recycle to the reactor.

157048 Process Flow

Page 19

Figure 10 UOP FCC Main Column

1

6

7

38

37

36

35

34

33

32

30

29

26

22

21

19

27

FI

FI

To Wet GasCompressor

To SourWater

Steam

Steam

HeavyNaphthaProduct

Light CycleOil Product

Flushing Oil

5

GasConcentration

Unit

GasConcentration

Unit

GasConcentration

Unit

EqualizingLine to/fromFeed Drum

Flushing Oil

Torch Oil

BFW

Steam

ReactorVapors

CW

CW

Main ColumnBottoms Product

Raw Oil toReactor

Raw Oil fromSurge Drum

To PrimaryAbsorber

157048 Process Flow

Page 20

Figure 11 UOP FCC Main Column Bottoms Process Flow

1

3

6

Mai

n C

olum

n

Water

Steam

Water

Steam

E

E E

Quench

MCBSteam

Generators

RawOil

CirculatingBottoms/Raw Oil

Exchanger

MinimumSpillback

RxOverhead

EFRC

RawOil

NetBottoms/Raw Oil

Exchanger

TemperedWater

MCBProduct

MCBProductPumps

Main ColumnBottoms Circulation

Pumps

MCB Product CircuitMinimum Flow Valve

157048 Process Flow

Page 21

As previously mentioned, most FCC units with modern riser terminations and

reactor cyclones do not require the use of a slurry settler and new units currently

being designed do not include settlers. If a refiner has strict specifications on the

ash content of the main column bottoms product, then more advanced alternate

fines removal equipment is usually employed to reduce the catalyst fines to very low

levels. The two most common types of catalyst removal equipment used today are

the micromesh filter and the electrostatic separator. Cyclonic separation devices

have also been used, but are typically limited to smaller capacity installations.

A typical micromesh filter system will have 2 or 3 vessels with up to 100 filter

elements in each. When multiple filtration vessels are used, each filtration vessel is

sized for 100% of the design flow rate. One vessel is typically in filtration mode

while another is in backflush mode to remove the filter cake from the elements.

When enough catalyst fines have deposited on the filter elements to increase the

pressure drop across the filter to a pre set limit, the vessel is taken off line for back

flushing. Once the filter vessel is off line and drained the vessel is filled with

backflush liquid, either HCO or LCO, and allowed to soak to help dissolve any

heavy aromatic compounds on the elements. The top of the vessel is then

pressured up with either fuel gas or nitrogen to provide the driving force for a high

velocity back flush. The back flush material is collected in a receiver vessel and

pumped back to the reactor riser. A typical process flow for the micromesh filtration

system is shown in Figure 12.

A typical electrostatic slurry oil filtration unit consists of 4-16 skid mounted

cylindrical shells (modules) depending on the volume of filtrate to be process. Each

module contains a high voltage cylindrical electrode surrounded by conductive glass

beads, with a ground rod located in the center of the module assembly. During the

separation cycle, the glass beads are ionized in an electrostatic field. As catalyst

particles flow between the beads, they are electrostatically collected on the surface

of the beads. Each module is sequentially back-flushed while the remaining

modules in the system continue the separation. In the backflush cycle, the electrode

is de-energized and the beads are fluidized, resulting in a circulating motion up

through the center of a 9-inch annular electrode and down the outside. The

circulation up the center annulus and down the walls of the module creates a

scrubbing action, to mechanically scrub the beads clean. Mechanically scrubbing

157048 Process Flow

Page 22

the beads as opposed to solvent soaking as with the micro-mesh filters, raw oil

feed, or any compatible oil can be used as the backflush medium to an electrostatic

filter. The back flush material is directed back to the reactor riser.

Figure 12

Main Column Bottoms Product Filtration System

Filter#1

Filter#2

Filter#3

ReceiverVessel

Back FlushLiquid

(LCO/HCO)

Backwash Gas(N2 or Fuel Gas)

N2 or Fuel Gas

Vent

MCBProduct

Clean MCBProduct to

Storage

CatalystBackwashto Reactor

157048 Process Flow

Page 23

There are typically three side-cuts withdrawn from the main column, heavy cycle oil

(HCO), light cycle oil (LCO), and heavy naphtha (HCN). The refiner may withdraw

all three, only two or one, depending on product needs and tower design. On

relatively rare occasions, the main column is designed with a fourth side-cut to

discretely fractionate a heavy LCO cut and a light LCO cut. The side-cut streams

that go out as product are usually stripped to meet flash-point specifications.

Pumparound loops from these side-draws are used to heat balance the main

column by exchanging heat with the gas concentration unit reboilers, the raw oil

charge or boiler feed water. The heat removed in the bottom and side pump-

arounds determines the amount of reflux in each section of the tower and must be

properly balanced for proper column operation. Gasoline and light gases pass up

through the main column and leave as vapors. After being cooled and condensed,

unstabilized gasoline is pumped back to the top of the column as reflux to control

the top temperature in the column. Figures 13, 14, 15 and 16 show typical process

flows for the HCO pumparound, the LCO pumparound, the Heavy Naphtha

pumparound and the Main Column Overhead system, respectively.

157048 Process Flow

Page 24

Figure 13 Main Column HCO Pumparound

Main Column

HCO InternalReflux

(Pumped)

Heavy Cycle OilCirculation

Pumps

E

E

LIC

To PumpFlushing OilSupply Header

ETo FeedSurge Drum(normally no flow)

To MCB/FeedExchanger Outlet(for startup)

Filling Line(from feed pump)

Gas Con UnitDebutanizerReboiler

157048 Process Flow

Page 25

Figure 14 Main Column LCO Pumparound and Product

LCOProduct

LCO toFlushing Oil

Steam

LIC

FI

CWBFWPreheater

Lean Oil toSponge Absorber

Rich Oil fromSponge Absorber

FIC

FIC

FIC

FIC

Debutanizer FeedExchanger

StripperReboiler

FCC-PC403

157048 Process Flow

Page 26

Figure 15 Main Column Heavy Naphtha Pumparound and Product

Main Column

HydrotreatedHeavy NaphthaProduct

Reflux(Gravity Flow)

Heavy NaphthaCirculation

Pumps

Heavy NaphthaProduct Pumps

Heavy NaphthaProduct Cooler

LICE

FRC

Steam

LCO

Stri

pper

Hea

vyN

apht

haSt

ripp

er

HeavyNaphthato and fromNHT Unit

CW

E E

Circulating Naphtha/Debutanizer Feed

Exchanger

C3/C4 SplitterReboiler

E

FRC

Signal from HCNHydrotreater

157048 Process Flow

Page 27

Figure 16

Main Column Overhead System

FCC/DS-R00-37

157048 Process Flow

Page 28

The raw oil feed system is included in the main column section for better process

efficiency, i.e. to take advantage of the heat from the main column. Feed enters the

unit from storage or directly from upstream processes, such as a vacuum tower or a

hydrotreater. The latter scheme is more efficient because the feed will not have to

be cooled before storage and then reheated flowing into the FCC. The number and

type of exchangers used will depend on cost and process factors that will vary with

each refinery.

Most newer units do not use fired charge heaters. Fired charge heaters have

become unpopular due to the increases in fuel costs, operational safety and impact

on overall refinery stack emissions. The feed goes directly to the riser after the raw

oil/main column bottoms exchanger. Figures 17 and 18 show typical process flow

schemes for the FCC feed preheat system without a fired charge heater and with a

fired charge heater, respectively.

Figure 17 Feed Preheat

MCBRecycle

HCORecycle

Raw Oil fromCrude Unit/

Hydrotreating

LCOProduct

MCBProduct

Circ.MCB

ToReactor

EqualizingLine To/FromMain Column

Raw Oil SurgeDrum

FCC-PF401

157048 Process Flow

Page 29

Figure 18

Feed Preheat with Fired Heater

Raw Oil fromStorage/

Upstream Unit MCBProduct

Circ.MCB

ToReactor

FuelGas

Equalizing LineTo/From Main

Column

FiredHeater

Raw Oil SurgeDrum

FCC-PF401

157048 Process Flow

Page 30

Gas Concentration and Recovery

This section further separates the main column overhead products into stabilized

gasoline, LPG and fuel gas. The normal configuration is shown in Figure 18.

Unstabilized gasoline from the main column overhead receiver is pumped to the

primary absorber, where it is used to adsorb C3’s and C4’s in the gas stream at

much higher pressure than the main column. From here the liquid stream goes to the high pressure receiver (separator), then the stripper column, where H2S and

C2- are removed. The gasoline off the bottom of the stripper is pressured to the

debutanizer for separation of LPG and gasoline and vapor pressure adjustment of

the gasoline. The overhead of the debutanizer is olefins rich LPG which is often further processed, for C3 and C4 separation and propylene recovery.

The gas from the main column overhead receiver goes first to the wet gas

compressor. From here it is pressured to the HPS, the primary absorber, and finally

the sponge absorber. Valuable light products such as LPG are removed in the first

of two vessels by absorption into the gasoline. The second vessel is the sponge

absorber which uses a LCO pumparound from the main column as a final

absorption stage before the gas goes out as fuel.

Wash water, typically clean condensate, is injected into the inlet to the wet gas

compressor interstage condenser. From the interstage receiver it is pumped to the

high pressure receiver then to the main column overhead condensers. This water

washes out salt forming and corrosive and species such as H2S, NH3, cyanides and

phenols. The wash water flow is shown in Figure 19.

157048 Process Flow

Page 31

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157048 Process Flow

Page 32

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157048 Process Control

Page 1

PROCESS CONTROL

Reactor-Regenerator Control Systems

Most of the control systems in a Fluid Catalytic Cracking unit are similar to those used

elsewhere in the refinery.

Good control of the catalyst circulation through the reactor and regenerator is critical for

stable operation. The catalyst circulation control scheme is shown in Figure 1. This

figure shows a side by side unit with a bubbling bed regenerator but the catalyst

circulation control between the reactor and regenerator is the same on all FCC and

RFCC units.

The circulation of hot regenerated catalyst from the regenerator to the reactor is

controlled to maintain a constant reactor temperature with the regenerated catalyst slide

valve. The circulation of spent catalyst from the reactor to the regenerator is controlled

to maintain a constant catalyst level in the reactor with the spent catalyst slide valve.

The controls on both the spent catalyst and regenerated catalyst slide valves also

include a low differential pressure override. If the differential pressure across either slide

valve drops to a very low or negative value the override will close the slide valve. This

minimizes the possibility of reverse flow in the standpipes, either air entering the reactor

or hydrocarbon entering the regenerator, which are hazardous situations.

Figure 1 shows signals from the reactor temperature controller and level controllers

going to low level selectors (LSS). The low signal selectors also receive signals from the

differential pressure controllers on the corresponding slide valve. If the differential

pressure across the slide valve is greater than the override setpoint, typically 2 psi (0.14

kg/cm2) the LSS will select the process variable (level or temperature) to control the

slide valve. If the slide valve pressure drop falls below the override setpoint the LSS will

send that output to the slide valve which will start closing. The low differential pressure

override controllers should always be in automatic.

157048 Process Control

Page 2

Figure 1 Catalyst Circulation Controls

<

<

PDIC

LSS

PDIC

LSS

LIC

TIC

PDIC

RawOil

Air

FlueGas

Products toMain

Column

>

PIC

HSS

SpentCatalyst

Slide Valve

RegeneratedCatalyst Slide

Valve

LI

XI(Density)

Regenerator

Reactor

Lift Gas/Steam

RiserTermination

Device

FCC-PC001

157048 Process Control

Page 3

For steady control of the catalyst circulation between the reactor and regenerator the

differential pressure across the slide valves must be constant. To ensure steady slidy

valve DP’s the differential pressure between the reactor and regenerator is controlled

with the double disc flue gas slide valves on the outlet of the regenerator. In addition to

the slide valves an orifice chamber is also used to take approximately 2/3 of the total

flue gas system pressure drop to minimize erosion in the flue gas slide valves.

A typical flue gas system without power recovery is shown in Figure 2. The reactor

pressure is not controlled directly and floats on the main column overhead pressure.

The reactor-regenerator differential pressure controller allows the regenerator pressure

to change along with the reactor pressure. Pressure control for units with power

recovery is discussed later.

Figure 2 Regenerator Pressure Control/

Flue Gas System

Flue GasSlide Valves

OrificeChamber

CO Boiler ElectrostaticPrecipitator

Flue Gas

Air

Steam

Water

PIC PDIC

>HSS

Air

Signal fromReactor

Pressure Tap

FCC-PC002

157048 Process Control

Page 4

Reactor Control (Figure 3)

Reactor temperature is controlled by the flow of hot regenerated catalyst as described

above. The temperature controller may be located in the reactor vapor line or in the

upper vapor space of the reactor vessel depending on the type of riser termination

device.

The reactor pressure is not directly controlled. Reactor pressure floats on the main

column overhead pressure. Thus, the reactor pressure is the sum of the main column

overhead receiver pressure plus the pressure drop through the main column and MC

overhead condensers plus the pressure drop through the reactor cyclones and reactor

vapor line.

The reactor catalyst level is controlled by the flow of spent catalyst to the regenerator as

described above. Modern reactor designs include a wide range level indicator and a

more accurate, narrow range level controller. Also, the density in the spent catalyst

stripper is measured to allow compensation of the level indication for actual catalyst

density. The level is typically controlled off of the wide range LIC because the signal has

less noise but a switch is included in newer unit designs to allow use of the more

accurate narrow range LIC if desired.

Steam is used to atomize the feed in the elevated Optimix feed distributors (Figure 4).

The amount of steam used determines the both the pressure drop and extent of

atomization as well as the velocity out of the distributor tip and penetration into the

catalyst. During normal operation the steam and oil enter the nozzle separately and are

mixed internally near the tip. The steam flow is normally set at design rates, typically1-2

wt% of the design charge rate. During operation at turndown additional steam may be

used to maintain the optimal pressure drop across the nozzles (typically 50-75 psig) to

ensure adequate atomization is maintained. An alternative that allows maintaining near

design pressure drop and atomization at turndown with minimal additional steam is to

mix a small amount of steam directly with the oil before it enters the nozzle. This results

in a large increase in pressure drop with minimal increase in velocity out of the tip. The

oil and steam flows to each nozzle have restriction orifices with pressure drop indicators

and globe valves to ensure that the flows to each nozzle are equal.

157048 Process Control

Page 5

Figure 3 Reactor Control and Instrumentation

XI(Density)

X

LI (DensityCompensated)

LIC LIC

SWITCH

MPS

PrestrippingSteam

StrippingSteam

FluffingSteam

XI(Density)

PDICLSS<

PDIC

LSS<

TIC

Lift Gas

MPS

FIC

FIC

FIC

Lift Steam

Start-up/EmergencySteam

AtomizingSteam

Raw Oil

For Feed/Steamcontrols see Figure 4

PDI

RegeneratedCatalyst

SpentCatalyst

FCC-PC003

157048 Process Control

Page 6

The feed bypass system is also shown in Figure 4. When a situation requiring a quick

shutdown is encountered, a control board mounted switch is activated which trips a

solenoid valve controlling the pneumatic signals to the feed bypass valves, causing

these valves to move to their failure positions, i.e. the valve in the line to the riser closes

and the valve in the bypass line to the main column opens. Normally, the next course of

action is to open the emergency steam to the riser to either maintain catalyst circulation

if the regenerated catalyst slide valve remains open or to clear the riser of catalyst if the

regenerated catalyst slide valve is closed.

On units with elevated feed distributors, another important operating variable affecting

the yield pattern is the lift zone velocity. The lift zone velocity is a function of the lift

steam and/or lift gas flow rates which are controlled on straight flow control. As the lift

zone velocity is increased the catalyst density at the point of the feed injection

decreases allowing better penetration of the atomized oil droplets into the catalyst. The

optimum lift zone velocity is typically in the range of 10 – 15 ft/sec (3 – 4.5 m/sec).

Either lift gas, lift steam or a combination of both may be used to achieve the optimum

lift zone velocity.

Stripping steam flows are also controlled on straight flow control. The optimal total

stripping steam rate is typically 1.7 – 2.5 lb/M-lb catalyst circulation but this can vary

significantly with depending on the unit design. The stripping steam rate should be

changed when any process conditions are changed that result in a significant change in

the catalyst circulation rate. The stripping steam rate should also be tested occasionally

to ensure that the optimum steam rate is used.

157048 Process Control

Page 7

Figure 4 Feed/Atomizing Steam Control

NORMALLY

NO FLOW

HEADER

PURGE

Local FI mustbe readablefrom valve

To othernozzles

Steam

Local FI mustbe readablefrom valve

Local PI must bereadable from valve

FIPI

FI

PI

FI

FI

FI

To othernozzles

Raw Oil fromPreheat

Raw Oil to MainColumn

Vent

SInstrument

Air

Feed BypassSwitch

To othernozzles

HS

FO

FO

FC

FCC-PC004

157048 Process Control

Page 8

Bubbling Bed Regenerator Control

In full combustion units without a catalyst cooler the regenerator temperature is not

directly controlled and is a function of a number of process variables. In simple terms,

the regenerator temperature is a function of delta coke, i.e. the wt% coke on spent

catalyst entering the regenerator minus the wt% coke on regenerated catalyst leaving

the regenerator. The concept of delta coke is discussed in more detail later in the

section of this book covering Process Variables.

The regenerator may be operated to burn the coke on catalyst completely to CO2

(complete combustion mode) or may be operated so that some of the coke is burned to

CO (partial combustion mode).

In units that operate in partial combustion mode the CO2/CO ratio of the flue gas may

be controlled to adjust the heat of combustion and therefore adjust the regenerator

temperature. The CO2/CO ratio is controlled primarily with the amount of combustion air

entering the regenerator. Partial combustion operation is discussed in more detail in the

Process Variables Section.

In units with a catalyst cooler, the regenerator temperature may be controlled by

controlling the amount of steam generated in the cooler. The controls of the catalyst

cooler are discussed in more detail later in this chapter.

The regenerator catalyst inventory serves as the surge capacity for catalyst in the

system and there is no control instrumentation on the regenerator catalyst level. A level

indicator is provided to monitor the regenerator catalyst level. The regenerator catalyst

level changes with catalyst additions, withdrawals and losses. In most units the level is

controlled by intermittent withdrawals of equilibrium catalyst. It is important that the level

be maintained above the terminations of the cyclone diplegs and below the level that

would cause the catalyst in the cyclone diplegs to back up into the cyclone dustbowl.

157048 Process Control

Page 9

The air rate to the regenerator is controlled either to maintain a minimum of excess

oxygen in the flue gas (typically 2%) for full combustion operation or to control the

CO2/CO ratio and therefore the heat of combustion and regenerator temperatures in

partial combustion operation.

High Efficiency Regenerator

The instrumentation and controls for a FCC unit with a high efficiency, combustor style

regenerator is shown in Figure 5.

The pressure, regenerated catalyst temperature and combustion air rate for the high

efficiency regenerator are the same as the bubbling bed regenerator described above.

The difference between the high efficiency regenerator and a conventional "bubbling

bed " regenerator is that the regenerator is divided into two sections. The lower section

is called the combustor and is where the spent catalyst and air mix and coke

combustion occurs. The combustor operates in the fast fluidized regime of fluidization.

All the catalyst entering the combustor is transported up the combustor riser into the

upper regenerator where the regenerated catalyst disengages from the flue gas. The

upper regenerator holds the cyclones, provides volume for the regenerated catalyst to

disengage from the flue gas and provides the surge capacity for catalyst in the system.

An important feature of the high efficiency regenerator is the recirculating catalyst

standpipe and slide valve. The recirculation of hot regenerated catalyst from the upper

regenerator to the combustor is important in controlling the coke combustion rate. By

controlling the amount of catalyst recirculated, the following parameters are controlled in

the combustor: the pre-combustion mixing temperature, the catalyst density, catalyst

flux and catalyst residence time. This, in turn, allows the coke combustion rate and

catalyst regeneration to be optimized. The recirculating catalyst slide valve is controlled

through a low signal selector and a slide valve PDIC, similarly to the other slide valves.

On early designs, this slide valve position was set on hand control. In current designs,

the recirculation slide valve position is controlled by a temperature or density controller

located in the upper section of the combustor. A switch is used to select the input signal

to the recirculation slide valve low signal selector.

157048 Process Control

Page 10

Figure 5 High Efficiency Regenerator Controls and

Instrumentation

<

TIC

SWITCH

XIC(Density)

LSS

XI(Density)

LI

RegeneratedCatalyst to Reactor

Spent Catalystfrom Reactor

TI's(1 Each Cyclone)

Signal fromReactor Pressure

Tap

PDIC

>

Fluffing Air

FIC

RecirculatingCatalyst Slide

Valve

PDIC

PIC

FCC-PC005

157048 Process Control

Page 11

In a high efficiency regenerator the dense bed catalyst level in the upper regenerator

provides the surge volume for the unit and is not controlled directly except by catalyst

additions and withdrawals.

A small flow of fluffing air to the upper regenerator on straight flow control is required to

ensure proper fluidization and flow into the regenerated and recirculation catalyst

standpipes.

RFCC Two Stage Regenerator Control

The regenerator control systems for the RFCC unit with a 2 stage regenerator are

shown in Figure 6. The reactor control systems are identical to those described above

for the conventional reactor-regenerator.

The principal difference is that the coke combustion is completed in 2 stages. The upper

regenerator, or 1st stage, is a bubbling bed regenerator operating in partial combustion

mode without excess oxygen. The catalyst exiting this stage still contains a significant

amount of coke which is burned off in the 2nd stage operating in full combustion mode

with excess oxygen. This allows the benefits of both partial combustion (lower

regenerated catalyst temperature) and full combustion (very low carbon on regenerated

catalyst for maximum activity).

In the RFCC the catalyst level in the second stage is controlled by the flow of catalyst

from the first stage to the second stage through the recirculation catalyst standpipe and

slide valve. This slide valve has a differential pressure override which closes the slide

valve if the pressure drop across the valve drops to low as described above for the

other slide valves. The level in the first stage regenerator is the surge volume for the

unit and is typically controlled by periodic withdrawals of equilibrium catalyst.

Since RFCC units are designed for heavily contaminated feed stocks one or more

catalyst coolers are included in the design and are used to control the temperature of

the regenerated catalyst circulated back to the reactor. The total air rate which controls

157048 Process Control

Page 12

the CO2/CO ratio in the flue gas and therefore the heat of combustion is also used to

adjust the temperature of the regenerated catalyst.

Figure 6

RFCC Regenerator Controls and Instrumentation

<LSS

PDIC

LIC

XI

LI

<

PDIC

LSS

TIC

SecondStage Air

SecondStage Air

FirstStage Air

RecirculationCatalyst

StandpipeCooledCatalyst

Standpipe

Spent Catalystfrom Reactor

RegeneratedCatalyst to

Reactor

Side View

FCC-PF006

Vent Tubes

157048 Process Control

Page 13

Air Blower Control

The control system for the main air blower depends on whether the blower is an axial or

centrifugal machine and whether it is turbine or motor driven. The most common

configuration built today is a turbine driven axial blower because these are generally

more efficient, but the choice is unit specific.

Figure 7 shows a conventional control scheme for a turbine driven axial blower. Flow is

measured by the venturi in the discharge line and is controlled by varying the speed of

the turbine. Alternatively, the air rate may be controlled by varying the stator vane

position for a fixed speed, axial blower.

A variable vent line, called a snort, is located on the air blower discharge and is used to

prevent air blower surge. An anti-surge system control system constantly monitors the

flow through the blower and the discharge pressure and compares the operating

condition to the surge line on the blower curve. If conditions close to the surge line are

detected the anti surge-controller opens the snort valve to increase the flow to

atmosphere and reduce the discharge pressure of the blower. Modern anti-surge control

systems available from specialized vendors continuously monitor a number of process

variables and calculate deviation from surge to allow operation closer to the surge line

while providing better protection for the equipment. The process variables monitored by

the modern anti-surge controllers are shown in Figure 7.

Occasionally, on older partial combustion units, an additional, smaller vent is used to

fine tune the air flow to the regenerator. This may be tied into a differential temperature

controller (DTC) which controls the temperature difference between the regenerator

dense and dilute phases to limit or control afterburn in partial combustion units.

On RFCC units control valves are used on the air lines to the first and second stages of

the regenerator (Figure 8). Typically the air to the second stage is set at ~25-30% of

the total air flow. In some units an additional control loop is included to minimize the

discharge pressure and thereby minimize the energy consumed by controlling the axial

air blower stator vane position. This control loop minimizes the blower discharge

pressure until one of the 2 flow control valves on the discharge is nearly wide open.

157048 Process Control

Page 14

Figure 7 Main Air Blower Control

Figure 8

RFCC Main Air Blower Control (Anti Surge and Special Check Valve Details Not Shown)

T

FO

FT TT PT

SIC

Steam

FIC(Temp, Pressure Corrected)XIC

(Anti-Surge)

TT PTTT PT

FT

ST

Vent toAtmosphere

Silencer

Special CheckValve

AirCylinder

Vent

InstrumentAir

S

Low FlowShutdown

Air toRegenerator

SuctionFilter

Housing

SnortValve

FCC-PC007

T

FO

TT PT

FIC (Press, TempCorrected)

TT PT

FIC (Press, TempCorrected)

ZT

ZT

Steam

ZIC

Special CheckValves

To First StageRegenerator

To Second StageRegenerator

XIC(Anti-Surge)

Vent toAtmosphere

Silencer

Stator Vanes

SuctionFilter

Housing

FCC-PC008

157048 Process Control

Page 15

The check valve in the air blower discharge line isolates the blower from the regenerator

if the blower trips. This minimizes the possibility of hot catalyst backing up into the

blower and minimizes the volume of air in the piping if surging occurs. The closing

action is assisted by a spring loaded air cylinder, which operates when the air flow falls

below a certain limit. When the flow drops below the low limit a solenoid valve de-

energizers and vents the air from the cylinder allowing the spring to move a cam which

bumps the check valve to assist it in closing. An air line from the catalyst hoppers or

plant air is used to provide plant air to clear catalyst from the discharge line if the blower

is down. It can also be used to supply warm blower air to the catalyst hoppers.

Power Recovery Controls

A typical process flow and control scheme for the flue gas system on an FCC with a

power recovery unit is shown in Figure 9. On units with a power recovery turbine,

butterfly valves are used in the flue gas line instead of slide valves for pressure control.

The butterfly valves operate on a single, split range controller which first opens the

valve on the line to the expander inlet then opens the butterfly valve on the bypass

around the expander if the capacity of the expander is exceeded. The bypass valve may

also be controlled to limit the speed of the expander or the pressure in the expander.

In the past, flue gas power recovery systems were designed with regenerator pressure

held steady to minimize fluctuations to the power recovery expander-motor/generator-

air blower train. With this control strategy, a regenerator pressure controller output

signal was used to control the power recovery butterfly valve positions. In this control

scheme, the regenerator pressure is fixed and the reactor-regenerator differential

pressure is allowed to float within reasonable limits.

Recently, the control system for flue gas power recovery pressure control has been

modified so that the reactor-regenerator differential pressure is controlled with a

differential pressure controller as in conventional flue gas systems. The objective of this

change in pressure control strategy is to insure that the reactor-regenerator pressure

balance and catalyst circulation are maintained at steady conditions. Now the output

signals of the reactor-regenerator PDIC and the regenerator PIC are fed to a high signal

157048 Process Control

Page 16

selector (HSS). The high signal selector directs the appropriate control signal (normally

the PDIC) to set the positions of the expander inlet and bypass butterfly valves via a

split range signal. The expander turbine is discussed further in the section covering

Equipment.

Modern power recovery controls, while controlling in the same manner, are more

complicated than discussed here. Power recovery controls and anti-surge controllers

are provided by specialized vendors. The additional functions performed by these

controllers are beyond the scope of this manual.

On units with power recovery, a steam turbine may be used for startup of the air blower.

The turbine can also provide auxiliary power if necessary. The motor/generator imports

or exports power to maintain a constant speed on the power recovery train. If more

energy is being supplied to the expander and the turbine than is required by the blower

there will be surplus electricity generated and exported. If the blower needs more power

than the expander is providing then electricity will be consumed to hold the train at

normal speed.

The flue gas leaving the regenerator flows through a series of small cyclonic devices in

the third stage separator for catalyst fines removal to minimize erosion in the expander.

The underflow catalyst stream from the third stage separator, carried by a small gas

flow, bypasses the expander and typically leaves the system with the main flue gas

stream downstream of the expander turbine. The underflow from the bottom of the

separator is controlled by a restriction orifice called the critical flow nozzle.

A flue gas quench system is also included on units with power recovery. If the flue gas

temperature exceeds the design temperature of the expander a flow of cooling steam is

started to the regenerator plenum through a split range controller. If the steam fails to

cool the flue gas sufficiently a flow of cooling water, typically BFW, is started to the

plenum. Most power recovery vendors also include an emergency steam quench at the

inlet of the expander for additional protection.

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Figure 9 Power Recovery Controls

OrificeChamberPIC

HSS

Flue GasCooler

ElectrostaticPrecipitator

FlueGas

M

Expander

Motor/Generator

Steam

T SteamTurbine

Air Blower

Air

SplitRange

ThirdStage

Separator

ButterflyValves

CriticalFlow

Orifice

RO

Signal FromRegeneratorTemperatureTransmitter

FC

AtomizingSteam

SplitRange

HighTemperatureSignal Opens ThisControl Valve First

TIC

PurgeSteam

FC

FI

ConcentricSleeve Purge

StuffingBox

PlenumShell

Retractable Tip

To OtherNozzles

BFW

LPS

TIC

Quench Connection -See Detail Below

Regenerator Plenum Chamber Quench Detail

FCC-PC009

PDIC

>

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Page 18

Catalyst Cooler Controls

Catalyst coolers provide FCC operating flexibility, permitting direct control over the

regenerated catalyst temperature. The regenerated catalyst temperature is a major

variable impacting cracking reactions since it sets both the catalyst to oil ratio and

determines the temperature of the catalyst surface at its first contact with the oil feed.

Both of these variables are important in determining the overall conversion and yield

pattern in the FCC.

Figure 10 shows a schematic of a flow-through catalyst cooler installed on a high

efficiency regenerator with the associated cooler fluidization air, water circulation, steam

drum and control instrumentation. As already discussed, hot catalyst from the upper

regenerator flows through the cooler shell, around the water tubes of the inserted tube

bundle and out of the cooler through a cooled catalyst standpipe and slide valve into the

combustor. The fluidization air lance system delivers fluidization air to the cooler shell to

maintain catalyst fluidization and mixing in the shell and to ensure that catalyst flows

smoothly through the cooler and out through the standpipe. The combination of mixing

and net catalyst flux through the cooler provide the driving force for heat transfer by

maintaining contact of hot catalyst with the tube wall.

The cooler duty is therefore controlled by controlling the amount of fluidizing air and the

flow through the cooled catalyst standpipe. Minimum and maximum fluidizing air rates

are typically specified to ensure that the air lances do not plug with catalyst and that

high velocities in the cooler do not cause erosion on the tube surface. In back mix type

coolers without a standpipe and slide valve the cooler duty is controlled only with the

fluidizing air.

To protect the tubes from thermal damage and oxidation, a large excess of water is

circulated through the tubes to ensure that the tube walls remain wetted. The ratio of

water circulated to steam generated is typically in the range of 20:1 to 25:1 lbs water

circulation per pound of steam generated. In the most recent designs the water

circulation rate is determined by the pump curve and no control valve is provided. In

earlier designs water circulation is controlled by a control valve. A low flow signal from

the flow indicator or controller activates a spare water circulation pump autostart. A low

low flow signal from the water circulation flow indicator or a low low steam drum level

157048 Process Control

Page 19

effectively causes the cooler to shutdown by closing the cooled catalyst slide valve and

closing the fluidization air control valve.

The mixture of steam and water exiting the cooler tube bundle flows to the steam drum

where the steam and water are separated. The saturated steam flow from the drum is

metered and flows out to the refinery steam system. Normally the saturated steam

leaving the steam drum is superheated in some type of downstream steam superheater.

The water returned to the steam drum is recirculated back to the cooler tube bundle. A

small continuous blowdown flow of water is removed from the drum to control

accumulation of impurities in the circulating water. The outputs of the steam product

flow meter and the steam drum level indicator are summed and control the flow of boiler

feed water (BFW) makeup entering the steam drum.

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Page 20

Figure 10 Catalyst Cooler Controls

M

To MotorControlCircuit

STEAMSEPARATOR

ContinuousBlowdown

IntermittentBlowdown

LG LT LT LT

PI

PG

FIC

Low Flow

Pump AutoStart

LI

MakeupBFW

Steam To MotorControlCircuit

MT

LIC

FI

FIC

FI

FI

I

I

I

I

Low Low Flow orLow Low LevelSlide Valve Trip

I

Low Low Flow orLow Low LevelFluffing Air Trip

Steam andWater

Steam

Air

IInterlock System

Low/Low

Low Flow(2/3 Voting)

Low Low

Level (2/3Voting)

TI

TI

FCC-PC010

FO

FT

DE

SVENT

DE

SVENT

157048 Process Control

Page 21

Emergency Interlock Systems

For many years automated interlock systems that removed feed from the FCC were not

used because it was assumed that a well trained operator would make a better decision

regarding stopping feed to the unit than any logic system looking at only a limited

number of inputs. Also, since many of the inputs into the interlock system relied on

pressure taps around the reactor and regenerator which were prone to plugging, the

threat of spurious trips was too great.

Recently, however, many refiners understand the value of a properly designed interlock

decision to automatically remove feed from the FCC and place it in a safe condition.

Also, in many refineries the turnover of operations personnel has increased so that

many FCC operators have limited experience. There have been a number of incidents

where operators tried to keep the unit running during upset conditions warranting

shutting down the unit only to greatly increase the mechanical damage done to the unit.

Instead of a shutdown lasting only a few hours an extended shutdown resulted.

UOP now includes an emergency interlock system on all new units and major revamps.

The purpose of this system is to move the unit to a safe condition during an abnormal

event while permitting a safe, fast restart of the unit once the problem is resolved. This

system automatically performs the steps necessary to accomplish these goals that were

once left to the operator. The system is also designed to minimize the risk of spurious

trips or shutdowns resulting from false indications when no abnormal condition existed.

The emergency interlock system monitors the air flow rate, regenerated and spent

catalyst slide valve pressure drops and valve positions, feed flow rate, reactor

temperature, and reactor stripper level to determine and verify the existence of an

abnormal event warranting a shutdown of the FCC. Once the abnormal event is

detected and verified by 2 out of 3 voting systems or a by a combination of abnormal

process readings the following actions are automatically initiated:

157048 Process Control

Page 22

The feed is bypassed to the main column

Raw oil flow rate is reduced (now going to the main column)

The spent and regenerated catalyst slide valves are closed

Steam is increased to the riser

All related controllers are placed in manual as required

Torch Oil Nozzle Control

Figure 11 below shows a typical torch oil arrangement for an FCC regenerator. The

torch oil nozzles provide a means of injecting heavy oil, usually raw oil feed or HCO,

into the regenerator when extra heat is needed, e.g. during startup. Details of the nozzle

will be described in the section covering equipment. Control of the torch oil flow and the

torch oil atomization steam is often by hand control on older units. New unit designs

usually use a flow controller with a split range output to the torch oil flow and the torch

oil atomization steam to ensure that the atomizing steam is commissioned before the

oil. The torch oil assembly is provided with a continuous steam purge to the annular

space around the torch oil nozzle to keep it clear of catalyst. This purge steam flow is

regulated to less than 50 lb/hr (25 kg/hr) steam with a restriction orifice. In addition, a

small flow of steam is sent to the nozzle tip through a restriction orifice when torch oil is

not in use to help cool the nozzle and keep it from plugging with catalyst.

157048 Process Control

Page 23

Figure 11 Torch Oil Control

STRAINERS

FI

FI MUST BEREADABLEFROM CONTROLVALVE

S

VENT

FC

RO

DE

PI MUST BEREADABLE FROMCONTROL VALVE

From RawOil Pumps

From HCOOil Pumps

FC

PI

FC

PI

FIC

Split Range(Steam ValveOpens First)

RegeneratorShell and

Lining

Stuffing Box

ManifoldPurge Steam

Annular SleevePurge Steam

AtomizingSteam

InstrumentAir

Emergency InterlockUnit Shutdown Logic

Steam

I

FCC-PC011

157048 Process Control

Page 24

Direct Fired Air Heater (DFAH)

Figure 12 shows the control system of a modern direct fired air heater, present on all

FCC units between the main air blower and the combustion air inlet to the regenerator.

The air heater is used for refractory curing and dry-out following repair or renewal of

regenerator linings as well as during normal startup to heat the regenerator catalyst

inventory. The DFAH outlet temperature is controlled by the fuel gas rate. A high

temperature shutdown trips the fuel gas to the heater to prevent damage to the air grid

in the regenerator. Modern air heater controls trip the fuel gas on a flame out signal

from a flame sensor or on low air flow rate. Separate shutoff valves are provided so that

the tight shut off of only the fuel gas control valve is not relied upon for emergency trip

conditions.

Figure 12 Direct Fired Air Heater Control

Burner

Damper

FC

INSTRUMENTAIR

SightPort

PDI Must BeReadableFrom Damper

Ignitor

VENTDE

PI

Pilot/Ignitor

FuelGas

PI

PI

PressureControlValve

PIC

PI

Air

TIC

I

High TemperatureShutdown

IgnitorStart

FlameSensor

I

I

Pilot Gas

SightPort

ToRegenerator

Interlock Shuts Down the Air Heater on:

Low Air Flow High Outlet Temperature Loss of Flame Detection

FCC-PC012

PI

S

S

S

Sight Port(sightingflame)

Sight Port(sightingopp. wall

157048 Process Control

Page 25

Catalyst Addition Controls

Continuous additions of fresh catalyst are required to maintain the activity of the catalyst

in the reactor and regenerator and to replace catalyst fines lost from the unit through the

cyclones. Regular additions of small batches of catalyst results in more stable operating

conditions and yields than larger batches added less frequently. The typical UOP

catalyst addition system uses a volume pot and automated valve sequence to add a

constant volume of catalyst at timed intervals. This system is shown in Figure 13.

Specialized valves, designed to close on the catalyst transfer lines when they are full of

catalyst, are required to ensure reliable service. Other systems are available including

weight addition systems which include a load cell to add weighed batches of catalyst on

a regular interval.

157048 Process Control

Page 26

Figure 13 Catalyst Addition Control

S

Vent

InstrumentAir

S

Vent

InstrumentAir

SVENT

FC

RO

FC

Plant Air

INSTRUMENTAIR

Plant AirRO

To Regenerator

VolumePot

I

I

I

Plant Air

FC

FI

Plant Air

FI

Fresh CatalsytHopper

Sight Flow Indicator

FCC-PC013

157048 Process Control

Page 27

Main Column Control

The main column is the first step in the product separation sequence. The superheated

reactor vapors need to be cooled so that fractionation can be conducted. In large

measure, operation of the main column becomes an exercise in controlled heat removal

coupled with sufficient liquid-vapor contacting to effect the desired degree of

fractionation into desired product streams, typically main column bottoms (MCB), light

cycle oil (LCO), heavy naphtha (HCN), unstabilized gasoline and wet gas. MCB, LCO

and HCN are drawn as products directly from the main column, although on many FCC

units HCN is not removed from the unit as a product stream. On some units, Heavy

Cycle Oil (HCO) is drawn as a product from the main column between the MCB and

LCO products. Main column sidecut products are often steam stripped in sidecut

strippers for flash point adjustment. The unstabilized gasoline and wet gas are further

separated in the gas concentration section. The arrangement and integration of heat

exchange from an FCC main column varies from refinery to refinery based on the

specific requirements and economics of a given installation. The following discussion

describes typical heat exchange circuits used on an FCC unit. Figure 14 shows a

simplified FCC main column schematic.

157048 Process Control

Page 28

Figure 14 Main Column Overview

Raw Oil toReactor

MCB Product

BFW

Steam

LCO fromGas Con

LCO to

Gas Con

LCOProduct

HCN Product

LCO toFlushing Oil

HCO toGas Con

HCO fromGas Con

HCN toGas Con

HCN fromGas Con

CW

Net OVHD Liquidto Gas Con

Wash Water

WGC Spillback

Sour Water

ReactorProductVapor

Steam

Steam

OVHD Vaporto WGC

FCC-PC400

157048 Process Control

Page 29

Main Column Bottoms Pumparound Circuit

The main column bottoms circulation system (Figure 15) is designed to desuperheat

the reactor vapors, condense the bottoms product and scrub entrained catalyst fines

from the reactor product vapor. Main column bottoms (MCB), also commonly called

slurry oil, is removed from the bottom of the main column and typically pumped to a

circulating bottoms/raw oil exchanger and one or more steam generators. MCB may

also be used to provide heat to reboilers. The reactor vapors are desuperheated by

contact with a large stream of cooled slurry oil on the disk and donut trays. The bottoms

flow over the disc and donut trays also washes catalyst fines out of the reactor vapors.

The total bottoms circulation rate over the disc and donut trays is normally set at 150%

to 200% of the feed rate or 6 gpm per ft2 of column area (15 m3/hr per m2 of column

area), whichever is greater. A minimum spillback valve is provided to maintain this

minimum flow during turndown operation. This ensures enough circulating MCB is

returned to the main column to adequately wet the disc and donut trays, thereby

cleansing the reactor vapors of catalyst fines and preventing coke formation on the disk

and donut trays due to insufficient liquid flow over the trays.

Typically the bottoms temperature is maintained at 670-700°F (354-370°C) to minimize

coking and fouling in the slurry circuit. The bottoms temperature is controlled by the

LCO product draw rate (or HCO product draw rate if HCO is withdrawn as a product).

This flow is adjusted manually by the operators. If the bottoms temperature is too high

the LCO product rate is reduced to drop more LCO to the bottom of the column which

lowers the bubble point of the MCB product. Alternatively, if a higher LCO endpoint is

desired than can be achieved while controlling the bottoms temperature in this manner,

a stream of cooled bottoms from the steam generator (quench) may be returned directly

to the bottom of the column to sub cool the liquid there. In this manner the temperature

in the bottom of the column is no longer composition dependent and the LCO/MCB

cutpoint may be varied independently of the bottoms temperature.

157048 Process Control

Page 30

Figure 15 Main Column Bottoms and HCO Flow and Control

Raw

MCBProduct

BFW

SteamReactorProductVapor

LIC

FI

FIC

CW

MCBQuench

Disc and DonutMinimum Flow

Raw

LIC

DebutanizerReboiler

HCN StripperReboiler

FIC FIC

FIC

FIC

FIC

Torch Oil

Pump Flushing Oil

FCC-PC401

FIC

157048 Process Control

Page 31

During normal operations the heat input from the circulating main column bottoms to

reboilers and preheat exchangers will be set by product and process considerations.

This is true of the heat removed in the other pump around loops as well. Heat input to

the steam generators is generally the only variable available to the operator for

adjustment of the column heat balance and reflux rates. Increasing the bottoms flow

through the steam generators will cause more heat to be removed. This will reduce the

amount of hot vapor traffic up the column and eventually will reduce the overhead reflux

rate and the heat removed in the overhead system.

Each exchanger in the main column bottoms pumparound circuit is designed for oil

containing catalyst particles. Main column bottoms flows through the exchanger on the

tube side and the velocity should be kept between 3.75 ft/s and 7.0 ft/s (1.14 m/s and

2.13 m/s) for straight tubes and between 3.75 ft/s and 5.75 ft/s (1.14 m/s and 1.75 m/s)

for U-tubes. Below the minimum velocity, catalyst can accumulate on the tube walls

and slowly plug the tube while greatly reducing heat transfer. If the velocity is above 7

ft/s (2.13 m/s), there is a risk of erosion on the tube walls. If the circulating MCB is very

low in ash content (<0.15 wt-%) the risk of erosion is greatly reduced. The rates

required to meet these velocities must be calculated for each exchanger before startup.

Bottoms product is withdrawn on straight flow control adjusted manually by the operator

to maintain a steady bottoms level in the main column. The product is cooled, typically

in cooling water exchangers before being sent to tank. In many cases the bottoms

product is also exchanged with the raw oil.

Removal of catalyst fines from the bottoms product by filtration, settlers or hydroclones

is an option which may be included depending on the end use of the bottoms product. If

a slurry settler is used to reduce catalyst fines in the bottoms product, the settler inlet

flow is drawn upstream of any bottoms product coolers. Hot main column bottoms

enters the settler tangentially and the swirling motion imparted distributes the heavy oil

evenly as it moves up to the outlet. Settler superficial velocity is limited to 30 BPD/ft2

(50 m3/d/m2) or less in the settler so that the fines can settle to the bottom of the

vessel. Clarified oil product (CLO) leaves from the top of the settler. Diluent (cooled

main column bottoms, raw oil or HCO) is added at the bottom of the settler to carry the

157048 Process Control

Page 32

fines back to the riser. The diluent addition rate is always equal to or slightly less than

the slurry flow to the riser and the settler feed rate is normally equal to or greater than

the clarified product from the from the top of the settler so that net flow is downward

carrying the settled fines out of the settler. Figure 16 shows the slurry settler flow and

control. Slurry settlers are not as common today because of the improvement in reactor

riser terminations and cyclones.

Filtration of the slurry product is becoming more common either to produce carbon black feed stock (which typically requires less than 100 wppm solids), to minimize downstream problems in fired heaters or to minimize tank cleaning cost. Figure 17 shows a typical flow and control for a bottoms filtration unit.

Figure 16 Slurry Settler Flow and Control

ClarifiedSlurry OilProduct

SlurrySettler

PSV

FI FIC

Return toMain Column

Diluent(HCO orRaw Oil)

Sewer

Slurryto Riser

Main ColumnBottoms

FIC

FIC

FIC

FCC-PC402

157048 Process Control

Page 33

Figure 17 Main Column Bottoms Filter Flow and Control

Filter#1

Filter#2

Filter#3

ReceiverVessel

Solvent Fluid(LCO/HCO)

Backwash Gas(N2 or Fuel Gas)

N2 or Fuel Gas

Vent

MCBProduct

CleanMCB

Product toStorage

CatalystBackwash

toReactor

FIC

PIC

PDIPDIPDILS LS LS

FI

LIC

FIC

SplitRange

PIC

FIC

Bypass(normallyclosed)

Valve sequencing controlled by programmable logic controller(PLC)Signals to/from PLC not shown for clarity

FCC-PC412

157048 Process Control

Page 34

HCO Pumparound Circuit

HCO is withdrawn from the column and commonly used to provide heat to the raw oil

preheat exchanger and the debutanizer reboiler as shown in Figure 15. Occasionally,

HCO is also used to generate steam and reboil side cut strippers such as a heavy

naphtha stripper. HCO flow to each of these exchangers is regulated by a flow

controller. Each controller is set by the operator to achieve desired product or process

specifications. If a steam generator is used, then the HCO pumparound heat removal

may be varied to some extent independently of process or product requirements. The

HCO reflux to the column is typically pumped back to the column on flow control reset

by the HCO draw tray level.

A decrease in heat removal from the HCO circuit will require an increase in heat

removal elsewhere in the column. For example, if less heat is removed in the

debutanizer reboiler then fewer vapors will be condensed in this part of the column

increasing the amount of vapor rising up the column. If the excess heat is not removed

in another pumparound circuit the overhead duty and reflux to the top of the main

column will increase to remove this heat.

HCO product (if any) can be removed through a stripper for flash point adjustment. The

amount of HCO product produced will depend on reactor operating conditions, feed

quality and catalyst type. The plant operator will make adjustments in HCO, LCO and

naphtha draw off rates to maintain target cut points or end points for these products. If

HCO is taken as a product it would typically be cooled against raw oil in a charge

preheat exchanger and then sent through a water cooled product cooler on flow control.

The HCO circuit also provides torch oil to the regeneration section for start-up and

emergencies and flush oil to the main column bottoms pumps.

157048 Process Control

Page 35

LCO Pumparound and Product Circuit Circulating LCO normally provides heat to the gas concentration unit stripper reboiler

and the debutanizer feed exchanger as shown in Figure 18. Flow to each exchanger is

regulated by a flow controller which is set according to process requirements. A stream

of LCO, after heat exchange at the stripper reboiler, is sent to the sponge absorber as

“lean” oil to adsorb light gasoline range components from the light gas in the gas

concentration section. The “rich” oil from the sponge absorber is returned to the main

column with the cooled LCO circulation stream, providing internal reflux for the main

column LCO section. On many units this reflux steam is circulated from a total trap tray

by gravity through a flow meter to provide additional column process information.

Most units contain an LCO stripper for LCO product flash point adjustment. Depending

upon the plant arrangement, light ends in the LCO can be removed either by steam

stripping or by refluxing the liquid using heat from the circulating HCO. The LCO product

may exchange heat with the raw oil feed stream before being cooled with water in a

product cooler and being sent to storage. Flow to storage is set by a flow controller. The

amount of LCO sent to storage is typically varied to control the temperature in the

bottoms of the main column as described previously. Alternatively the LCO product rate

may be adjusted to maintain a constant temperature at the draw tray and therefore

maintain a constant endpoint. Stripped LCO is available for use as emergency quench

to the riser, instrument flush and pump gland seal oil.

157048 Process Control

Page 36

Figure 18 LCO Flow and Control

LCOProduct

LCO toFlushing Oil

Steam

LIC

FI

CWBFWPreheater

Lean Oil to SpongeAbsorber

Rich Oil fromSpongeAbsorber

FIC

FIC

FIC

FIC

Debutanizer FeedExchanger

StripperReboiler

FCC-PC403

157048 Process Control

Page 37

Heavy Naphtha Pumparound and Product Circuit

A heavy naphtha (HCN) product is typically withdrawn through a side cut stripper

column in order to remove light ends for vapor pressure adjustment. The product may

be either steam stripped or reboiled with HCO. The naphtha stripper bottoms product is

cooled with water in a product cooler and then sent to storage or treating on flow

control. The HCN product flow rate is adjusted by the operator to maintain a constant

draw temperature and therefore endpoint at the draw tray. The portion of the naphtha

draw from the main column which is not stripped as product is pumped and used for

heat exchange with raw oil feed, the C3/C4 splitter reboiler, water or other low

temperature streams and returned to the main column as internal reflux for the main

column naphtha section. Figure 19 shows the flow and control for the naphtha

pumparound circuit.

Figure 19 HCN Flow and Control

FCC-PC404

HCNProduct

HCO

FIC

CW

FIC

FIC C3/C4 SplitterReboiler

FI

LIC

157048 Process Control

Page 38

Main Column Overhead System

Reactor product vapors contain large quantities of light gas and gasoline vapors which

pass through the entire main column as gases. A portion of these products are

condensed in the overhead condenser, the trim condenser and separated in the main

column overhead receiver. A quantity of the condensed hydrocarbon liquid (unstabilized

gasoline) is pumped to the main column as reflux (Figure 20).

Reflux to the main column controls the overhead vapor temperature. This temperature

determines the endpoint of the debutanized gasoline product from the gas concentration

unit. The reflux also heat balances the column. If heat removal from one section is

changed the overhead reflux rate will respond in the opposite direction to maintain a

constant top temperature. For example, if more heat is required in the feed to the

debutanizer, LCO circulation will be increased to provide the heat. The increased heat

removal from the LCO circulation will condense more vapors rising up the column. Less

heat will reach the top of the column. The top temperature controller will then reduce the

reflux flow to maintain the column top temperature, thus heat balancing the column.

The unstabilized gasoline liquid in the receiver not used as reflux is pumped to the

primary absorber in the gas concentration unit on receiver level control. Gas flows to the

suction drum of the wet gas compressor in the gas concentration unit. Water from the

overhead receiver water boot is pumped to the waste water treating unit.

The main column pressure, and therefore the reactor pressure, is controlled at the

overhead receiver by the amount of gas removed through the wet gas compressor. This

control must be very steady because swings in this pressure will affect the pressure

balance between the reactor and regenerator and therefore will affect the catalyst

circulation. The wet gas compressor control system depends on the type of driver and

the compressor design.

Regardless of the primary pressure control system, a backup control system is present

in case the wet gas compressor trips or can not handle all of the gas produced in the

reactor. This is shown in Figure 20. In this case an overpressure control valve, typically

157048 Process Control

Page 39

set at 0.3-0.5 psi (0.02-0.035 kg/cm2) above the setpoint for the primary pressure

controller will open venting some of the gas to flare or a low pressure fuel gas system.

This control system allows the unit to continue operating during a short duration

compressor failure and is useful during startup before sufficient gas is produced in the

reactor to run the compressor.

Figure 20 Main Column Overhead Flow and Control

PSV

CoolingWater

Wet GasCompressor FirstStage Spillback

To Wet GasCompressor

Suction Drum

To FlareHeaderFC

Signal to WetGas Compressor

Controls

PICPRC

Net OverheadLiquid to High

PressureReceiver

SourWater

LIC

TIC

FIC FIC

LIC

FI

WashWater

FCC-PC405

157048 Process Control

Page 40

Wet Gas Compressor Control

Steam Turbine Driven Wet Gas Compressor Control

The compression of the wet gas from the main column overhead receiver to the gas

concentration section is done in two stages, with external cooling and liquid knockout

between the stages. A variable speed steam driven centrifugal compressor is shown in

Figure 21. The control system is set up to hold pressures steady and to prevent the gas

compressor from surging, which can cause serious damage to the wet gas compressor.

The pressure control signal from the main column overhead receiver has a split range,

to the low signal selector controlling the spillback, and to the governor on the steam

turbine. The second stage spillback to the first stage compressor discharge is controlled

by a low signal selector which is fed by the interstage suction drum pressure signal and

the second stage flow signal. The low signal selector will ignore one of the two inputs,

whichever is higher, and transmit the lower output signal intact.

The system works as follows:

1. Normal flow - at lower charge rates, the main column overhead receiver signal

will control the first stage spillback to hold receiver pressure constant. The

second stage spillback will be controlled by the anti-surge controller to satisfy the

minimum flow requirements of the surge curve. The turbine will be running at

minimum governor speed. As the charge rate is increased, there is a greater net

flow of gas, so the two spillbacks are gradually closed by the controllers. When

the spillbacks reach the fully closed position, the output signal from the overhead

receiver pressure controller will be high enough to begin increasing the

compressor speed. The speed will then be continuously varied to remove the gas

from the main column and hold the pressure constant. Throughout this, the flow

controllers will have no effect as long as there is sufficient gas flow to keep the

machine out of surge.

157048 Process Control

Page 41

2. Abnormally low flow - there would be two main reasons for low gas flow. The first

would be insufficient gas from the main column, such as when the feed was

suddenly cut out. The second reason would be an abnormally high second stage

discharge pressure, caused by problems in the gas concentration unit. Whatever

the cause, when the flow falls below the point set by the operator on the FRC,

the output signal falls, which would then be transmitted by the low signal selector.

This opens the spillback valves to recycle gas back to the suction, allowing the

gas to be moved through the machine in sufficient quantities to keep it out of a

surge condition. When normal conditions are restored, the flow controller output

will rise, and the low signal selector will return the spillbacks to pressure control.

If the low flow is caused by high pressure in the gas concentration unit, opening

the first stage spillback will overpressure the main column. This condition will

open the overpressure control valve to flare, holding the receiver pressure at the

overpressure set point.

3. Abnormally high flow - the main cause for very high flow rates would be operating

the FCC unit in such a fashion that the compressor could not handle the gas

flow. The machine would be at maximum governor speed with both spillbacks

closed. Pressure in the main column would rise, opening the overpressure

control valve to flare.

Modern anti-surge and pressure control systems take advantage of faster transmitters

and computer technology to allow monitoring of multiple variables and rapid calculation

of corrected flow rates to allow more efficient operation closer to the surge line with less

spillback. These inputs to the anti-surge controllers are shown in Figure 21.

157048 Process Control

Page 42

Figure 21 Wet Gas Compressor Control

Steam Turbine, Variable Speed

FCC-PC407

NirogenPurge

NirogenPurge

AntisurgeController

FI

FO

TI

Steam

T

SpeedSensor

SI

To SurfaceCondenser

TT

PT PT

TT

PT PT

AntisurgeSignal OpensControl Valve

FO

FI

SC

Signalfrom MainColumn

OverheadPRC

To HighPressureReceiver

AntisurgeSignal Opens

ControlValve

First StageSpillback to

Main CoulumnOverhead

FromMain

ColumnOverheadReceiver

FirstStage

SecondStage

TT

TT

AntisurgeController

157048 Process Control

Page 43

Motor Driven Wet Gas Compressor Control

This case would be for a constant speed centrifugal compressor. The instruments,

controls, and actions are essentially the same as discussed above, except that the

governor speed control is replaced by a suction butterfly valve to throttle the gas flow to

the compressor. This valve normally stays partially closed, against a limiting stop. As

more flow is required, after the spillbacks have closed, the butterfly valve will open

allowing more gas to move through the compressor. The action on low gas flow is to

move gas through the compressor spillback valves in the same manner as described

above for the variable speed machine.

Reciprocating Wet Gas Compressor Control

Older FCC units occasionally used reciprocating wet gas compressors. These are rarely

used today because of the better efficiency of the centrifugal compressors.

Reciprocating compressors are normally constant speed machines. At normal flows and

pressures, the spillbacks open or close to hold the overhead receiver and interstage

suction drum pressures at the point set by the operator. Abnormally low flow rates, such

as when the charge is cut, will cause a drop in pressure, opening the spillbacks. High

second stage discharge pressure will have the same effect. Reciprocating machines

may also have clearance pockets and suction valve unloaders which can be varied to

control flow, but this will depend on the individual machine.

Variations

There are other control schemes which are in use today, depending on the individual

refiner's needs. Some plants have been designed with only one spillback, from second

stage discharge to the main column overhead receiver. This does not allow the same

freedom of action as that offered by two spillback valves. Excess pressure drop through

one part of the system caused by such things as exchanger fouling, is one reason why it

is better to have the extra freedom of two spillbacks.

157048 Process Control

Page 44

Main Column and Gas Concentration Section Water Wash

The overhead stream from the main column contains a number of contaminants which

can cause corrosion, plugging and fouling. These contaminants include ammonia,

sulfides, cyanides, chlorides and phenols. A wash water stream is used to remove the

contaminants. The wash water should be clean, preferably steam condensate, to

prevent adding more problems such as salts or dissolved oxygen to the system. Wash

water is effective in removing most of these impurities because most of them are ionic

or polar species which tend to be readily soluble in water.

Figure 22 shows the preferred arrangement of the water wash system for an FCC

fractionation and gas concentration section. Clean water is pumped into the first stage

discharge of the wet gas compressor at the inlet to the interstage cooler. The water from

the interstage receiver is pumped out on level control to the wet gas compressor

discharge at the inlet of the high pressure cooler. Water collected in the high pressure

receiver water boot is pressured on water boot level control to the inlets of the main

column overhead condenser and trim condenser. Sour water is then pumped to

disposal from the main column receiver water boot on receiver water boot level control.

The recommended water wash rate is 6.5 to 7.0 vol% of feed or about 2 gpm per 1000

BPD feed (approximately 1.15 liters/min of water per 1 m3/hr of fresh feed rate). The

drain water from both the overhead receiver and the high pressure receiver should be

checked regularly for pH. The main column overhead receiver water should be in the

range of pH 8.0 to 8.5. The high pressure receiver drain water should also be slightly

alkaline, pH 7.5 – 8.0.

157048 Process Control

Page 45

Figure 22 Wash Water Control

M

FI

Main ColumnOVHD Vapors

FirstStage

SecondStage

Condensate

Water BreakDrum

LICFIC

LIC

High PressureReceiver

Main ColumnOVHD Rec.

Wet Gas Compressor

SourWater

Liquid fromPrimary Absorber

Vapor fromStripper

CW

CW

To PrimaryAbsorber

Water Flow Indicated by Bold Lines

To PrimaryAbsorber

To Stripper

FCC-PC409

157048 Process Control

Page 46

Feed Preheat Train

There are two basic raw oil preheat schemes used in FCC units. One uses a fired

heater to supply some or all of the feed preheat duty. Fired feed preheaters are

expensive to build and operate by today's standards so fired preheaters are mainly in

use on older FCC units. The other feed preheat scheme uses extensive heat integration

to provide feed preheat duty. Most new FCC units use this heat exchange scheme and

do not employ fired feed preheaters. Figures 23 and 24 show FCC feed preheat

schemes with and without fired heaters, respectively.

In both preheat trains, the raw oil flows to a feed surge drum directly from the crude unit,

vacuum unit, hydrotreating or from storage. The surge drum pressure rides on main

column pressure through a vent line connected to the lower section of the main column

just above the HCO draw. The surge drum level is normally controlled by controlling the

flow of one of the feed sources into the unit.

The charge is pumped from the surge drum on flow control through heat exchangers

before reaching the feed distributor at the reactor riser. The only significant difference

between the two schemes is the presence of the fired heater. Both schemes use a TRC

to control the raw oil outlet temperature from the circulating main column bottom/raw oil

exchanger by bypassing some of the raw oil around the exchanger. The flow of main

column bottoms through the exchanger is varied to keep the temperature controller in a

good operating range. With the fired heater, each heater pass is also controlled by a

TRC.

157048 Process Control

Page 47

Figure 23 Feed Preheat System

MCBRecycle

HCORecycle

TICSplitRange

High TemperatureCloses Control

Valve

Low TemperatureCloses Control

ValveRaw Oil fromCrude Unit/

Hydrotreating

Raw Oil fromStorage

LCOProduct

MCBProduct

Circ.MCBSplit

Range

High Level Closesthis Valve First

LIC

FIC

FIC

FIC

Level ControlSignal fromUpstream

Unit

<LSS

ToReactor

EqualizingLine To/FromMain Column

FIC

Raw Oil SurgeDrum

FCC-PC411

157048 Process Control

Page 48

Figure 24 Feed Preheat with Fired Heater

TIC

Raw Oil fromStorage/

Upstream Unit MCBProduct

Circ.MCB

LIC

FIC

ToReactor

TIC

FuelGas

Equalizing LineTo/From Main

Column

FiredHeater

Raw Oil SurgeDrum

FCC-PC410

157048 Process Control

Page 49

Gas Concentration Unit Control

A typical flow scheme for the overall gas concentration unit is shown in Figure 25. It is

convenient to discuss the controls in 2 sections - the absorber section and the

fractionation section. The absorber section removes LPG and light material from the

gases and recycles them back to the high pressure receiver. The fractionation section

strips C2 and lighter material as well as H2S from the LPG and gasoline and recycles

them back to the high pressure receiver. The fractionation section also separates the

LPG and gasoline.

Because the absorbed and stripped material are recycled back to the high pressure

receiver good control of the gas concentration unit requires a good balance of stripping

and absorption. If excessive stripping is occurring then excessive absorption will also be

required to achieve reasonable C3 and C4 recoveries from the fuel gas. This is at a

minimum a waste of utilities and in severe cases can result in increasing recycle flows,

or “snowballing”, until one or more of the columns flood.

157048 Process Control

Page 50

Figure 25 Gas Concentration Unit Flow

Stabilized Gasoline toTreating

Stripper

Debutanizer

CW

Lift Gas toReactor

SpongeGas to

Treating

UnstabilizedGasoline fromMain Column

OVHD

CW

Wet GasCompressorDischarge

Wash Water toMain Column

OVHD Receiver

Wash Waterfrom Interstage

Receiver

LCO fromMain

Column

Rich Oilto MainColumn

LPG toTreating

PrimaryAbsorber

SpongeAbsorber

CW

Circ.HCO

CW

High PressureReceiver

Lean GasKO Drum

FCC-PC703

157048 Process Control

Page 51

Absorber Section - Primary Absorber

LPG and heavier hydrocarbons are recovered from the light gas (also called sponge

gas or fuel gas) in this section of the gas concentration unit shown in Figure 26. Gas

from the high pressure receiver enters the primary absorber below the bottom tray and

is contacted by counter current flow with unstabilized gasoline on level control from the

FCC main column overhead receiver.

Many units also recycle stabilized gasoline (debutanizer bottoms) on flow control to the top tray to increase recovery of the C3 and C4 hydrocarbons. Unstabilized gasoline is

typically fed to the 6th tray from the top when recycle gasoline is used. Heat is removed

from the column to maximize adsorption efficiency with two pumparound inter-coolers,

one about one third the way down the column and another about two thirds of the way

down from the top. The rich oil flows from the bottom of the column to the high pressure

condenser on level control cascaded to a flow controller. The overhead gas stream

flows into the sponge absorber.

Absorber Section - Sponge Absorber

The sponge absorber is typically a packed column which serves to recover nearly all the

remaining C5 and C6 material and some C3 and C4 hydrocarbons. Circulating light cycle

oil on flow control from the stripper reboiler is heat exchanged with the rich oil and then

cooled before being pumped to the top of the absorber as “lean” oil. The gas from the

primary absorber flows upward from the bottom of the column. Rich oil leaves the

bottom of the column on level control. The rich oil is heated in the rich oil/lean oil

exchanger before returning to the main column with the circulating LCO stream. Lean

sponge gas leaving the top of the sponge absorber is cooled and any condensed liquid

drops out in the lean gas knockout drum. The liquid is periodically drained to the LCO

return line.

Gas from the lean gas knockout drum is normally sent on pressure control to a fuel gas

amine treater before being sent to the refinery fuel gas system. In FCC or RCC units

using lift gas technology, a portion of the lean sponge gas (before amine treating) is

recycled to the reactor riser on flow control for use as lift gas. The sponge gas pressure

157048 Process Control

Page 52

controller sets the pressure for the knockout drum, the sponge absorber, the primary

absorber, the high pressure receiver and the stripper column. The pressure of each

vessel depends upon the pressure drop between the vessel and the lean gas knockout

drum.

Figure 26

Gas Concentration Unit – Absorber Section

Stabilized Gasoline toTreating

Stripper

Debutanizer

CW

Lift Gas toReactor

SpongeGas to

Treating

UnstabilizedGasoline fromMain Column

OVHD

CW

Wet GasCompressorDischarge

Wash Water toMain Column

OVHD Receiver

Wash Waterfrom Interstage

Receiver

LCO fromMain

Column

Rich Oilto MainColumn

LPG toTreating

PrimaryAbsorber

SpongeAbsorber

CW

Circ.HCO

CW

High PressureReceiver

Lean GasKO Drum

FCC-PC703

157048 Process Control

Page 53

Fractionation Section - Stripper Column

Removal of light hydrocarbons from the LPG and gasoline is accomplished in the

stripper column (see Figure 27). Liquid from the high pressure receiver is heated with

debutanized gasoline before entering the top of the stripper. Heat to the stripper is

provided from the debutanized gasoline reboiler and the LCO reboiler. The LCO flow to

the reboiler is controlled on a cascade loop to maintain a constant vapor rate from the

top of the column. A bypass around the debutanizer bottoms to the lower reboiler is

provided in case the demand for LCO to the upper reboiler is less than the required flow to the sponge absorber. The stripping rate is varied to reject all of the C2 and lighter

material and in some cases to control the amount of H2S going to the debutanizer and

therefore into the LPG product. Stripper overhead vapors return to the high pressure

condenser. Liquid leaves the bottom of the stripper on level control and is pressured to

the debutanizer column feed exchanger.

Fractionation Section - Debutanizer Column

Gasoline vapor pressure adjustment and separation of the C5 and heavier components

from the LPG is achieved in the debutanizer column. Circulating LCO provides heat to

the debutanizer feed before the feed enters the column at tray 20. LPG leaves the top of

the column as a gas and is cooled in the condenser before collecting in the overhead

receiver. The pressure in the column is controlled by controlling the amount of vapor

entering the condenser. A hot vapor bypass around the condenser is used to control the

pressure drop between the column and the receiver to ensure that the opening of the

pressure control valve stays in a good operating range. If the hot vapor bypass valve is

fully open then the temperature, and therefore the pressure, in the receiver is too low

indicating that less cooling is required at the condenser and that either the fan speed

should be reduced or one or more fans should be shut off. Likewise, if the hot vapor

bypass valve is fully closed then the fan speed needs to be increased or additional fans

turned on.

Liquid from the overhead receiver is returned to the column top as reflux to control the

column temperature at tray 6. Net overhead liquid is pumped to the LPG treating unit to

control the level in the receiver.

157048 Process Control

Page 54

Heat to the debutanizer reboiler is typically supplied by circulating HCO. The flow of

HCO is adjusted by the operator to adjust the reflux rate in the column and the quality of

fractionation. The temperature controller is adjusted to control the RVP (Reid Vapor

Pressure) of the gasoline. Stabilized gasoline flows from the column bottom to supply

heat to the stripper reboiler and then to the stripper feed exchanger. Gasoline from the

stripper feed exchanger can be split into two streams. Recycle gasoline is cooled and

pumped to the primary absorber on flow control. Net debutanizer bottoms (i.e., gasoline)

is cooled and pumped to the treating unit. The net gasoline flow controller is reset by the

debutanizer bottoms level controller to maintain the column bottom level.

157048 Process Control

Page 55

Figure 27 Gas Concentration Unit – Fractionation Section

1

7

19

20

35

36

40

1

18

19

36

FIC

CirculatingHCO To/FromMain Column

Stabilized Gasolineto PrimaryAbsorber

FIC

FIC

StabilizedGasoline to

Treating

LiquidfromHPR

SplitRange

TIC

LIC

FI

TIC

PIC

PDIC

Vaporto HPR

Stripper

Debutanizer

CirculatingLCO To/

From MainColumn

FIC

FIC

CW

LIC

LPG toTreating

FCC-PC700

157048-1 Equipment

Page 1

EQUIPMENT

INTRODUCTION

The Fluid Catalytic Cracking unit is exposed to severe temperature, erosion and

corrosion effects. The equipment has been designed to withstand these conditions

for an acceptable mechanical life, but the life can be drastically shortened by abuse

or poor operations. Proper control and operation will avoid the unnecessary

problems which lead to premature failure.

The FCC unit should be inspected every turnaround. The inspection can be done by

a UOP inspector, the refinery inspection department, or both. Adequate record

keeping of these inspections is necessary to develop the unit history which will aid

the refiner to judge equipment life, determine potential problems and evaluate the

effect of different metallurgy and process conditions related to the equipment.

A good inspection will include the following:

1) An evaluation of the equipment which has experienced erosion and/or

corrosion

2) A list recommending minor repair work

3) An assessment of mechanical problems caused by the operating

conditions of the previous run

4) A list of spare parts required for the next turnaround

Erosion and corrosion are not always obvious. A thorough inspection of the

equipment will reveal the extent of any damage and help determine the cause and

effect relationship. Also, because no equipment lasts forever, the inspection will

help the refiner determine when equipment must be replaced so advance orders

can be made.

157048-1 Equipment

Page 2

Minor repair work can prevent small problems from expanding to larger problems. It

is difficult to predict the amount of minor work which will be required. The desired

length of the next run will determine the extent of the repairs.

PREPARATION for INSPECTION

Preparation for inspection should begin well before the shutdown. Proper

scheduling of inspection and maintenance will avoid delays and wasted time. As

soon as an inspector finds a problem, parts can be ordered and work can be

scheduled so the completion of the turnaround will not be delayed.

The normal shutdown procedure will remove most of the catalyst from the unit and

cool the vessels to 200-250°F (90°-120°C). The manways should be opened on

both the reactor and regenerator to air cool the vessels. Vacuum connections are

provided to remove any remaining catalyst. The vacuuming operation can begin

while the manways are being opened, if there is sufficient manpower. When the

vacuuming is complete, water washing can be started. This will remove the dust

and fines which would hinder a complete inspection. A simple water spray is usually

sufficient, with the water draining out of the reactor and regenerator at the bottom of

each vessel. The water will not cause any problems with the vessel internals, even

stainless steel. A high-pressure blast could obviously damage the refractory;

common sense is required. Clean, potable water with less than 50 ppm chlorides

should be used. Excess water should not be allowed to stand on the equipment for

long periods of time. An air hose can be used to blow away these puddles. There

are a few areas that are difficult to drain, such as the regenerator plenum chamber.

These can be cleaned with a heavy-duty vacuum cleaner. Because there are

different reactor and regenerator designs, the exact cleaning method should be

determined by the refiner.

The main column and gas concentration section should also be cleaned for

inspection after the normal shutdown procedures have been completed.

Hydrocarbon and sour water should be pumped or pressured out of the unit. Gas

and vapors are removed by steaming out the vessels. Any remaining material can

157048-1 Equipment

Page 3

be removed as necessary by water washing the equipment. Do not allow any water

in the wet gas compressor. Normal refinery safety practices should be followed for

toxic vapors, explosivity, oxygen content of vessels, etc. The refinery safety

engineer should follow the turnaround carefully.

AIR BLOWER

The main blower of an FCC unit supplies large quantities of air to the regenerator.

Advances in rotating machinery technology have led to the replacement of the old

positive displacement reciprocating air compressor with centrifugal and axial

machines. Blowers can be driven by steam or gas turbines, electric motors, or flue

gas turbines, usually referred to as power recovery expanders. Depending on the

mode of operation and other factors such as feed quality, the FCC unit needs 10-

14.5 pounds of air per pound of coke, which is approximately 2000-3000 SCF/bbl

(330-500 Nm3air/m3FF). Air is filtered through a screened suction housing that

should be designed for noise abatement. Compressed air leaves the blower at

about 300-450°F (150-230°C) and 30-60 psia (2.1-4.2 kg/cm2(a)).

CENTRIFUGAL MACHINE

Air flow rates on a centrifugal machine are controlled by varying the speed of

rotation, throttling the suction, or venting off excess air. Four to six stages are

common, with labyrinth seals used to prevent leakage between stages. These

machines normally use forced lubrication systems for the bearings and may be

equipped with temperature and vibration probes for early detection of mechanical

problems.

157048-1 Equipment

Page 4

AXIAL MACHINE

An axial blower, shown in Figure 1, uses rotating blades to move the air. The air

flows through the machine in a straight line, each successive stage adding pressure

energy much like a propeller blade. The air flow rate is most often controlled by

varying the shaft speed. This can be accomplished either through a turbine driver,

or by including a Variable Speed Drive (VSD) unit on a motor. If the machine is

designed for constant speed, other means of flow control must be provided. One

option is to snort (vent) excess air to atmosphere. However, for normal control this

would require power to compress air that is vented back to atmosphere, and is

simply not energy efficient. Practical options include the use of small variable pitch

blades known as “stators” on the blower housing. The variable pitch stators redirect

the air flow into the path of the rotating elements. When this redirection is at a

steeper angle, more air is transferred. These machines use forced lubrication

systems and are normally equipped with temperature and vibration probes.

Another option to control air flow from a fixed speed blower is to include a suction

throttle valve. This mode of operation is very common in older machines, but as

with a snort valve, it is not an energy efficient system. The suction throttle valves

on motor driven air blowers can be eliminated through the installation of a VSD unit

onto the motor.

Axial compressors are generally more efficient at larger capacities than centrifugal

machines. They are smaller and lighter than an equivalent size centrifugal unit.

Choice of machine depends on the individual refiner, but axial blowers are more

common for larger units.

Specific operation of these large machines is too complex to describe in this

manual. Individual manufacturer's instructions should be followed for each unit.

157048-1 Equipment

Page 5

Figure 1Axial Compressor

BLOWER PROBLEMS

The problems encountered with an FCC blower can be divided into two groups;

operational and mechanical. Examples of mechanical problems are vibration, shaft

displacement and noise. These may result from manufacturing defects, construction

mistakes such as misalignment of the driver and blower, and routine wear of the

bearings. In most cases, however, mechanical problems are caused by operational

difficulties. An example is surge, which occurs when the air blower is not able to

produce enough head to overcome downstream resistance. A centrifugal

compressor curve, shown in Figure 2, gives a typical head-flow relationship, while

Figure 3 shows a curve for an axial machine.

At a fixed speed the compressor will follow the curve. Flow decreases with

increasing head, similar to a pump. Unlike a pump, however, the characteristic

curve begins to turn down toward the zero capacity region after reaching a peak in

157048-1 Equipment

Page 6

pressure. This peak is called the stability limit or surge point. The machine will thus

produce less head at the decreased capacity. The pressure downstream of the

machine is higher and the flow reverses through the blower. When the downstream

pressure is relieved, normal flow is restored. Resistance quickly builds again and

the machine surges. The condition can be recognized by a characteristic cycling

sound and a rapid rising and falling of the flow between normal and zero. When the

gas moves back into the machine, the rotor tends to stall, which can cause serious

damage as the machine is subjected to large unusual forces and increased gas

temperature across each surge cycle. Surge cycles can result in damage to the

thrust or axial bearings and labyrinth seals. In severe cases the rotor itself may

crack or rub against the casing. On an axial blower the blades may break.

To prevent this backflow condition, many blowers are fitted with an anti-surge

controller. The controller essentially compares pressure rise and flow against a

programmed operating map of the blower. The operating map includes a calibrated

surge line. As the machine approaches the surge line a blow-off valve, commonly

referred to as a “snort valve”, is opened slowly. Opening the snort increases flow

through the machine and prevents surging. Surge is generally considered more

dangerous to axial blowers than to centrifugal, but should be avoided for either.

Choke, or stonewalling, is a low pressure, high flow condition where the gas velocity

approaches the speed of sound. Dangerous vibrations result and can cause the

rotor to crack. This condition may also be seen on the characteristic curve at low

head. The line becomes almost vertical as the capacity increases and air velocity

approaches the sonic value. This condition is infrequent but care must be taken to

avoid it. Choke is more of a problem for axial than centrifugal machines. Rotating

stall is a somewhat rare phenomenon, indicated by an inability to build pressure

while the flow is more or less normal. It results when air moves around the axial

rotor, rather than through it. The best cure is to back down to starting conditions and

restart increasing the flow again.

The air blower suction line should be inspected for cleanliness. The suction hood or

housing should be cleaned. Except for vibration from the blower, this section of the

plant is not subject to any unusual stresses, and normally lasts for many years.

157048-1 Equipment

Page 7

Inspection and maintenance on the blower and associated systems should follow

the manufacturer's recommendations. Replacement of the bearings, seals,

lubricating oil, etc. is required at certain intervals. The air filters on the suction

housing should be inspected during normal turnarounds and replaced or repaired

as required.

Performance (capacity) of the blower can diminish over time due to fouling of the

blades. Foulants may include dust and chemical contaminants drawn into the

machine through the filter housing. Episodes of blade fouling have been associated

with sudden and heavy rains, washing contaminants off of the suction filters and

into the blower. Performance decline of up to 10% of rated flow have been

associated with blade fouling. Most vendors offer a surfactant or solvent injection

system that can be added to the suction line of the machine to help remove blade

foulants from the blower.

The air blower discharge line is not subject to corrosion or metal loss. All air snort

valves should be checked by the instrument department; few problems are ever

encountered with the air snort valves.

In the event of an emergency trip, many modern machines require that they be

rotated while cooling down. If this procedure is not followed when required, serious

rotor deflection can result. Excessive rotor deflection can result in serious

mechanical damage to the compressor, requiring a major overhaul of the machine.

157048-1 Equipment

Page 8

Figure 2Centrifugal Air Blower Performance Curve

Figure 3Axial Air Blower Performance Curve

157048-1 Equipment

Page 9

POWER RECOVERY

The power consumed by the air blower is a significant part of an FCC unit's

operating expense. Utility costs continue to rise, only partially offset by more

efficient motors and turbines. Recovery of the energy in the hot flue gas from the

regenerator can increase the overall efficiency of the unit. This was first done with

steam generation systems. The flue gas exchanges heat with a circulating water

stream. A 30,000 BPD (195 m3/hr) FCCU without a CO boiler can produce 40-70 M-

lb/hr (18-32 t/hr) of 600 psig (42 kg/cm2) steam. Heat recovery in this scheme is

somewhat limited by a minimum allowable flue gas temperature. Sulfur oxides and

water vapor in the stack gas can cause corrosion of the equipment if they condense

in the flue gas duct. The temperature at which the condensation occurs is known

as the acid gas condensation point, which shifts depending on the concentration

and distribution between the different oxides. The acid gas condensation point is

typically in the range of 400-600°F (200-315°C), although it may be higher for some

units. The maximum temperature limit of the flue gas is typically a function of

metallurgical design limits for downstream equipment, which may include an

electro-static precipitator, flue gas scrubber, and/or stack.

The major disadvantage of a straight steam generation energy recovery scheme is

that no power is recovered from gas pressure, normally 10-40 psi (0.7-2.81 kg/cm2)

above atmospheric pressure at the regenerator outlet. Another approach to

recovering energy from the flue gas was tried in 1950. This was a turbo expander,

driven directly by hot flue gas. Initial results were unsatisfactory; after only 750

hours of operation catalyst fines in the flue gas had substantially eroded away the

turbine blades and casing. The fines problem was solved by placing an additional

catalyst separator, known as a Third Stage Separator (TSS) outside of the

regenerator.

In the TSS, flue gas moves through a large number of small cyclone assemblies in

which the catalyst is centrifugally separated from the flowing gas stream. To

remove the separated catalyst fines from the TSS, a small amount of gas, typically

3% of the regenerator flue gas, is used to pneumatically sweep the catalyst fines

157048-1 Equipment

Page 10

out the bottom of the vessel. The clean flue gas is then directed to the inlet of the

power recovery expander.

UOP has been designing power recovery systems since 1973. Between 1973 and

2004, UOP licensed 33 TSS’s with 22 placed into operation. The original units were

designed by UOP under license from Shell. Over the years, UOP improved upon

the original design by implementing several modifications. Even with these

modifications incorporated into the base design, very little had actually changed in

the overall design of the TSS in 25 years. These TSS designs still suffered from the

limitations imposed by radial flow gas distribution and reverse flow in the cyclone

elements.

In 1996, UOP launched a development program to design and offer a smaller, more

economic, high efficiency TSS that could not only be utilized in power recovery

installations, but also be a viable alternative to electrostatic precipitators and wet

gas scrubbers for environmental applications.

The cold flow modeling (CFM) test program extended over 2 years, during which

both dimensional variables and process flow variables were studied. Based on a

thorough understanding of cyclone theory, and drawing on other sources of cyclone

expertise, the UOP program investigated the contribution of many variables on

catalyst separation efficiency. These variables included:

Cyclone diameter and geometry

Inlet velocity

Length to diameter ratio

Outlet velocity

Catalyst loading

Gas distribution

Over 200 individual tests were conducted on single and multiple cyclone models to

determine the highest efficiency and highest capacity design cyclone. The tests

were conducted with commercial FCC catalyst fines. Computational fluid dynamic

(CFD) computer modeling was used to validate and benchmark the CFM work, and

to quickly investigate potential improvements and guide the physical modeling

program.

157048-1 Equipment

Page 11

The development work culminated in the new UOP TSS design (see Figure 9). The

most significant improvement in the design is that the UOP TSS utilizes axial flow

for catalyst/gas separation. The flue gas flow is maintained essentially in one

direction - in the top and out the bottom of the unit. Axial flow distribution minimizes

the potential for solids re-entrainment resulting from gas flow direction change and

resultant eddy current formation. The older style TSS utilizes radial flow distribution

in which the flue gas is distributed from the centerline of the TSS, radially outward

between the two tube-sheets. As such, the inner tubes see a higher gas and dust

loading than the outer tubes. The mal-distribution of flue gas and fines inherent in

this design results in varying efficiency across the older style TSS.

The new UOP TSS is about 40% smaller than other TSS offerings for the same

capacity; making it less expensive to fabricate, easier to install, and better suited

where plot space is a premium.

The first UOP TSS was commercialized in April 2002. Performance testing on the

unit was performed twice in 2002, following the unit startup in April and again in

December. The initial test showed that the UOP TSS discharged between 36-50

mg/Nm3 of particulates, depending on flue gas rate. The NSPS compliance testing

resulted in a particulate matter emission of 0.6 lbs/1000 lbs of coke burn, only 67%

of that allowed by NSPS standards. This performance showed that the UOP TSS

could not only provide power recovery expander erosion, but could also be used as

in the refiners particulate emission control strategy, by replacing more traditional,

costly, and hazardous means (electrostatic precipitators and wet gas scrubbers) of

controlling particulates exiting the flue gas stack.

A comparison of the older style TSS and newer style TSS is shown in Figure 4.

Both vessels are carbon steel vessel with 4" (100 mm) of refractory lining and

stainless steel internals. The cold-wall construction is more effective on both

erosion and cost basis than the early hot-wall stainless steel separators. A coarse

screen, or grate, covers the flue gas outlet entrance to trap large chunks of

refractory or other debris.

The overall efficiency of the separator depends on the efficiency of the regenerator

cyclones and the quantity of catalyst fines being generated in the reactor-

regenerator system. The separator should remove >70-90% of the particles for high

157048-1 Equipment

Page 12

and low regenerator cyclone efficiency, respectively. Most of the fines which pass

through the separator are smaller than ten (10) microns. These small particles do

not cause much erosion to the expander blades but the smallest particles can

deposit on the expander blades and casing, causing vibration problems.

The pressure drop across the expander is on the order of 10-30 psi (0.7-2.1

kg/cm2), with a temperature drop of 200°-250°F (110°-140°C). After driving the

turbine, the flue gas goes to a steam generator for further energy recovery.

The majority of the catalyst is removed from the flue gas with the underflow from

the third stage separator which is typically routed back into the flue gas downstream

of the expander. If required, an electrostatic precipitator or flue gas scrubber may

be placed downstream of the steam generator to remove any remaining catalyst

fines before the flue gas is exhausted to atmosphere. Alternatively the underflow

may be filtered to achieve ~99.99% removal of the catalyst fines, or routed to a 4th

stage cyclone separator to achieve ~60-90% removal of the catalyst fines from the

underflow stream, depending on local environmental restrictions.

The power recovery train usually consists of five parts; the expander turbine,

motor/generator, air blower, and a steam turbine, and is commonly referred to as a

“5-Body Train”, see Figure 5. In this arrangement the expander turbine is coupled

to the main air blower shaft to directly supplement the power requirement of the

blower. The 5-body train requires a steam turbine or motor to get it started; in some

cases only one of them is provided.

The expander, shown in Figures 6 and 7, is a single stage machine because of the

low pressures involved. The gas to the expander is accelerated over a parabolic

nose cone. Pressure energy is converted to velocity energy, and the high velocity

gas drives the turbine.

Expander turbines designed in the past were generally limited to an inlet

temperature of 1200-1250°F (650-675°C) to prevent heat damage. This generation

of expanders however, still required quench injection systems in the regenerator

plenum chamber to protect the expanders in the event of a regenerator temperature

157048-1 Equipment

Page 13

excursion. Quench systems essentially dumped steam and water into the

regenerator plenum to cool the flue gas. While this provided for thermal protection

of the expander, the increased steam and water in the flue gas often resulted in

“sticky” catalyst that agglomerated in cement-like deposits that increased blade

fouling on the expander. Newer expander turbines normally have a design

temperature in excess of 1375°F (750°C) and do not require a quench control

system.

For units with a power recovery system, butterfly valves in the flue gas line control

the differential pressure between the reactor and regenerator. The PDIC sends a

signal to the large butterfly valve which is located at the inlet to the expander. A

smaller butterfly valve will allow flue gas to bypass the expander when the large

butterfly valve is fully open because of an excessive flue gas rate or when the

expander is off line. This prevents over pressuring the regenerator.

In the traditional five piece power recovery train, the motor/generator is usually a

constant speed induction type machine that provides extra power to the blower

shaft when needed. If the expander produces more energy than is required by the

blower, the machine will act as a generator and feed power into the electrical grid.

This acts as a braking mechanism and provides some over-speed protection for the

machine.

157048-1 Equipment

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Figure 4 Third Stage Separator

Figure 5

5-Body Power Recovery Train

Expander

Main AirBlower

InletGuideVanes

FlueGas

Exhaust

FlueGasInlet

AirIn

Air toRegenerator

SteamTurbine

SteamInlet

ExhaustSteamOutlet

GearBox

Motor /Generator

ElectricalConnection to

Power Grid

11' 6" OD48 Tubes

23'

70 Tubes 19' 3" OD

29'

New Style TSSOld Style TSS

157048-1 Equipment

Page 15

Figure 6Flue Gas Expander

Because power recovery trains are generally fitted on larger units, the blowers used

are of the higher efficiency axial type. The blower is a constant speed machine in

most cases, especially if used with an induction type motor/generator. Varying the

angle of the stator blades in the blower is the most economical control scheme.

Because the motor/generator has a large startup electrical power requirement, a

steam turbine may be used to bring the train up to speed. The turbine will normally

provide 50-75% of the power needed for the blower. Once the train is close to

design speed, the motor can be started without using excessive amounts of

electricity. This in turn decreases the size of the transformers and switch-gears

needed. When the expander is running the turbine is allowed to freewheel, or may

157048-1 Equipment

Page 16

be used to provide extra power. If there is no steam turbine, the expander turbine

may be used to "bootstrap" the train up to speed.

In unit revamp situations where the main air blower is not to be replaced, the power

recovery train can be reduced to 3 parts; the expander, gear reducer and generator.

This configuration is known as a “Gen Set” power recovery installation. In this

configuration, the power recovery system is completely isolatable from the

remainder of the FCC unit. The electrical power generation from the system is

routed directly into the refinery power grid. The net power recovery capable through

a Gen Set system is lower than a 5-body train due to efficiency losses in the switch

gear, and motor. However, the capital expenditure of Gen Set systems is lower,

and they can be completely isolated from the remainder of the FCC unit should

there be any equipment problems with the power recovery system.

157048-1 Equipment

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Figure 7 Flue Gas Expander

Inlet

Rotor

Blades

Shaft

Coupling

Bearing

Outlet

FCC-E001

157048-1 Equipment

Page 18

A typical power recovery expander performance map is illustrated in Figure 8. The

power recovery system achieved commercial success in 1963. More than 30 units

are in operation or under construction. It has proven to be a valuable tool in

increasing efficiency and decreasing costs for Fluid Catalytic Cracking units.

Figure 8 FCC Power Recovery

1600 ºF(871 ºC)

1300 ºF (704 ºC)

1200 ºF (649 ºC)

1100 ºF (593 ºC)

1000 ºF (538 ºC)

44.7 psia(3.14 kg/cm2a)

40 psia (2.81 kg/cm2a)

36 psia (2.53 kg/cm2a)

32 psia (2.25 kg/cm2a)

28 psia (1.97 kg/cm2a)26 psia (1.83 kg/cm2a)

Percent Flue Gas Mass Flow Rate

Per

cen

t E

xpan

der

Hor

sep

ower

157048-1 Equipment

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CHECK VALVE

The check valve is installed on the discharge of the air blower. It prevents backflow

of air or catalyst, which could cause serious damage to the blower. Fluidized

catalyst will easily flow back through the air heater if pressure is lost. If the blower

starts to surge, the large volume of the regenerator must be isolated from the

blower. Figures 9-11 show the check valve and its associated equipment.

Figure 9Blower Discharge Check Valve

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Figure 10Blower Discharge Check Valve - Side View

The special check valve is a swing style check valve with a spring loaded air

cylinder that provides spring force assisted closing. An oil filled dash pot provides a

damping action on opening. Construction is of heavy wall steel to resist temperature

and pressure stresses, with 11-13% Cr or stainless trim. The stainless steel shaft is

supported by hardened stainless steel bushings, with graphoil packing used to

prevent leakage. Older designs have incorporated asbestos packing that may need

to be addressed with the appropriate abatement procedures. The shaft is connected

to the dashpot and to a lever arm that has counterweights that support 75% of the

disc weight. These weights minimize the pressure drop through the valve, but

should never hold the disc open when there is no air flow. The lever arm is usually

cut to the proper length in the factory, and the weights set in the field.

157048-1 Equipment

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The air cylinder consists of a small piston opposed by a spring. Under normal

conditions, air is supplied to the piston, which moves up to compress the spring.

The piston rod moves freely between two small lever arms attached to the check

valve shaft. As the piston rod rises, the valve is free to open. Air flow from the

blower forces the valve open. The air to the piston is supplied through a three-way

valve that will vent off cylinder pressure when actuated. For older units, a shutdown

of the blower would signal the valve to cut off the air supply. For the new units that

have venturi meters on the blower discharge line, a low flow signal will signal the

valve to cut off the air supply. A shutdown on the blower itself, low blower-

regenerator differential pressure, or low air flow can all be configured to cut off the

air supply to the piston and activate the special check valve. Instrument air failure

will also vent off pressure from the cylinder. Upon initial venting, the spring provides

a sharp thump to the valve shaft to help free the disc in the event that it has become

slightly stuck in the open position. The force of the spring is not enough to close

against the normal operating air flow from the main air blower. As such, a spurious

activation of the special check valve, i.e., a loss of instrument signal to the solenoid

valve, would result in a higher pressure drop through the check, but would not force

a unit shutdown.

After initial actuation, with no air pressure to oppose it, the spring provides a

constant load on the valve shaft. As the piston rod comes down, it pulls on the lever

arms, which exert a closing force on the shaft. This provides a starting boost to

close the check valve and will bring the valve closer to the seat before the air flow to

the regenerator actually stops.

Following a solenoid trip, the three-way valve must be manually reset in the field.

This functionality is included in the system design to help ensure that movement of

the check valve disc is controlled and stable, rather than a sporadic situation that

would result if the air cylinder was pressured and depressured in a random fashion

during an upset.

Typical turnaround maintenance on the special check valve includes maintenance

of the air cylinder, refilling the dashpot oil, repacking of the stuffing box hinge

157048-1 Equipment

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assembly, replacement of the accordion type protective piston rod cover. After the

check has been reassembled, the flapper should move freely and close normally

under its own weight. Proper seating of the check disc should be confirmed

internally with visual inspection. If the main air line is too small to facilitate internal

visual inspection, the approximate position of the disc can be verified by the position

of the counter-weight arm.

DASHPOT

The dashpot provides a resistance to a sudden opening of the check valve. It has a

loose fitting piston that rides in an oil filled cylinder. The valve in the bypass line

restricts oil flow from the top of the dashpot to the bottom as the piston moves up.

This restriction prevents the check valve from opening too quickly. As the piston

moves down on the check valve closure, the valve in the bypass on the dashpot

opens wide to allow rapid closing of the check valve. Some snubbing action remains

to prevent excessive slamming. The dashpot should be filled with a light lubricating

oil such as SAE 10W. It is also important to provide a "volume leg" in the oil piping

to account for the volume of the piston shaft in the closed position. The setting on

the oil dash pot needs to be verified on initial installation and subsequent

turnarounds by opening the disc and allowing it to fall closed. Proper setpoint of the

oil valve should result in a smooth controlled closure of the disc with no substantial

impact on the valve seat.

If the check valve is thrust open under low air flow conditions, it may fly up too far,

and then slam back onto the seat. This can cause damage to the valve seating

surfaces. As a result, the check valve should be examined for any unusual wear,

such as impact erosion on the seat during the turnaround.

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DIRECT FIRED AIR HEATER

The direct fired air heater (Figure 12) is a carbon steel, internally insulated vessel

that heats the air to the regenerator primarily during startup. A pilot burner, as well

as one main burner (two - on rare occasion), are used to fire fuel gas, LPG, or oil on

heater discharge temperature control. The pilot for the burner is lit by a high energy

electrical electrode igniter. Air is directed to the burner by a large damper, controlled

externally with a hand crank. Sight ports are provided for flame observation. Air

purges to the sight ports keep the glass cool and can be used to blow catalyst out of

the ports if it backs up from the regenerator. A block valve is provided to shut off

and isolate the ports when the burner is either being ignited, or not being used. On

heaters that are mounted vertically, directly beneath the regenerator, there are

several stainless steel baffles spaced approximately three inches apart at the outlet.

The baffles prevent flame impingement on the air grid in the regenerator, which

could cause extensive damage to the grid. The baffles should be routinely

inspected during each turnaround.

The extent of the direct fired air heater repair work required during a turnaround will

depend on the hours and type of use. Over-firing and burner misalignment are the

two main causes of refractory spalling and reduced equipment life.

On low �Coke operating units, the regenerator temperature can be cool enough to

adversely affect regenerator performance. On occasion, some refiners supplement

the regenerator temperature by Auxiliary firing of the air heater during normal

operation. While this has proven effective for some refiners, care must be taken not

to exceed maximum recommended exit velocities on the main air distributor.

Operating with distributor jet velocities too high can result in excessive erosion to

the main air distributor as well as excessive catalyst fines generation in the unit.

The fuel source to the DFAH needs to be maintained within the fuel specifications

outlined by the vendor. Improper fuel/air/burner combinations can result in severe

mechanical damage to both the DFAH and the regenerator internals; i.e., accidental

injection of liquefied LPG through a fuel gas burner.

157048-1 Equipment

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Figure 12 Direct Fired Air Heater

Air Splitting Damperwith Limit Stops

Pilot/IgnitorAssembly

MainGas

AirPurge

Sight Port(2 Required -

Must Sight Pilotand Main Burner)

Air Purge andBlast Connection

AirInlet Air

OutletTI's

(2 Required)

AirPurge

AirPurge

Sight PortSighting

Opposite Wall

Sight PortSightingBurner

Baffle 4" (100 mm)Vibrocast Insulating

Refractory

4" VacuumCleanout

Connection

Manway

FCC-E002

157048-1 Equipment

Page 25

AIR GRID

The original design for a conventional regenerator air distribution system was a

perforated plate. Air entered the base of the regenerator and then passed through a

large number of small holes in a large metal plate. In the late 1970's and early

1980's, the processing of more contaminated feedstocks increased air demand and

regenerator temperatures. Increased incidents of erosion, full CO combustion, and

the introduction of new regenerator designs lead to significant changes in the

design of the air grid.

The bubbling-bed regenerators feature a high catalyst entry point into the dense

bed relative to the air grid. Two basic types of air grid designs are used by UOP in

this style of regenerator: pipe grid and mushroom grid. The high-efficiency

regenerators have a low catalyst entry point relative to the air grid. On this design,

UOP uses a pipe grid.

The mushroom grid with extension arms is used in situations where a standpipe

inlet is below the air grid. A dome grid was used previously, but an exit in the grid

was needed to transfer catalyst to the regenerator standpipe. The mushroom air

grid with extension arms distributes air through jets located in the dome and arms.

A side view of the grid is shown in Figure 13. Figure 14 shows a plan of the

mushroom grid with arms.

The mushroom grid is constructed with 1" (25mm) lining on the dome and ¾" (19

mm) lining on the extension arms. The lining minimizes the thermal stresses on the

grid wall resulting from the temperature differential between the inlet air and

regenerator.

157048-1 Equipment

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Figure 13 Mushroom Air Grid with Extension Arms

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Figure 14 Plan View of Mushroom Air Grid with Arms

Plugged NozzleOpen Nozzle

157048-1 Equipment

Page 28

The dome air grid distributes air through jets located on its dome. A side view of the

grid is shown in Figure 15.

Figure 15 Dome Air Distributor

157048-1 Equipment

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Some dome-type air distributors have experienced jet erosion. UOP believes that

the erosion on this type of air grid is due to catalyst from the spent and recirculating

catalyst standpipes impacting directly onto the surface of the distributor. When the

catalyst impacts the air grid in this fashion, the catalyst can be forced into the jets

resulting in erosion as the catalyst is blown out of the jets. Erosion can also occur

on the external portion of the jet from the catalyst impact.

Several methods of combating this type of erosion have been developed. One

method is to install extended catalyst deflectors, which distribute the catalyst over a

wide cross-sectional area of the regenerator to minimize the localized impact of

catalyst onto the grid. Another modification is to cover the surface of the air grid with

an abrasion-resistant lining so that the outlet of the jets is flush with the abrasion-

resistant lining. The dual-diameter jets have also been replaced with single-

diameter, higher velocity jets.

Because of mechanical reliability the pipe grid is the most commonly designed type

of air grid today. The pipe grid distributes the air through two to four large laterals

into a number of small branches. A side view of the grid is shown in Figure 16.

Figure 17 shows a plan of the pipe air grid. Modern air grids use a dual diameter jet

(Figure 18) with a restriction orifice at the inlet. This allows a higher pressure drop

for better air distribution while minimizing the velocity out of the jet for minimum

catalyst attrition.

Air grids are designed for a total pressure drop between 0.8 and 1.2 psi (0.06-0.085

kg/cm2). The pressure drop must be maintained above 0.5 psi (0.035 kg/cm2) to

achieve even distribution and should be below 1.5 psi (1.05 kg/cm2) to minimize

main air blower discharge pressure.

Many of the pipe grid and supports designed for partial combustion units were low

alloy, such as 5% chrome. The higher temperatures encountered in a most modern

full CO burning units require 304 SS.

157048-1 Equipment

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Pipe-grids designed by UOP in the early 1970's had experienced cracking at certain

butt welded joints, but otherwise worked well. UOP has modified the pipe-grid

design and the advantages of this style of air grid are as follows:

1) by using a 90° elbow (instead of a 45° lateral arm), thermal stress in the air

grid is greatly reduced because the elbow has greater flexibility

2) the 90° elbow is attached to the header arms and main hub with extruded

connections which moves the welds away from the highly stressed junction

3) the branch arms pass through the header arms which increases the strength

of these joints

4) external abrasion resistant lining protects against erosion and also provides a

smooth thermal gradient

Figure 16 Pipe Air Grid

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Figure 17Plan of Pipe Air Grid

Figure 18 Dual Diameter Jet Detail

157048-1 Equipment

Page 32

A pipe grid is subject to severe catalyst erosion on the upper surface of the

branches. For this reason, older units had stainless steel retaining dams, Figure 19,

welded on top of each lateral. These dams held an insulating layer of catalyst which

alleviated both erosion and possible heat damage problems. Currently, UOP

designs the air distributor so the entire surface of the branches have abrasion

resistant lining. The lining provides both the erosion resistance and the thermal

barrier required.

Figure 19 Coffer Dam

Branch

Stiffener

157048-1 Equipment

Page 33

The jets on the pipe air grid and on the arms of the mushroom grid point down to

avoid channeling the catalyst bed, as seen in Figure 18. It should be noted that

some of the jets are normally plugged. This is done for three reasons:

1. To prevent a blast of air from impinging directly on an air pipe or the

regenerator wall.

2. To increase the pressure drop to the proper level if the grid has too many

holes (future design case).

3. To properly distribute air across the full regenerator cross section to

compensate for spent catalyst maldistribution.

The pressure drop across the air grid can be calculated with the equation:

P = P * V

2200 * T =

2.238 * W

C * A *

2 2

d2

h2

where:

P = Grid pressure drop, psi

P = Air pressure to grid, psia

T = Air temperature to grid, ° R

V = Velocity of air through jets: flow rate of air/total cross sectional area

of all open jets, ft/sec

W = Air Flow, lb/sec

Cd = Orifice Coefficient

Ah = Orifice Cross Sectional Flow Area, in2

= Flowing Air Density, lb/ft3

157048-1 Equipment

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REGENERATOR

The regenerator is an internally lined carbon steel vessel. The lining, called

refractory, is a concrete type material which is gunned onto reinforcing support

anchors. This lining is necessary to protect the metal wall of the vessel from the

high temperatures at which the regenerator operates and should keep the outer

shell of the regenerator below 650°F (343°C) at all times. The refractory is applied

over stainless steel hexmesh or steerhorn anchors. Different grades and depths are

applied depending on the service. In general, four - five inches (100 - 125mm) is

used in the regenerator when insulation is of primary importance.

Abrasion resistant refractory lining are used on all internal surfaces in the

regenerator to protect the base metal from the erosive environment. ¾ - 1 inch (19 -

25mm) of lining is typically used and is anchored by stainless steel hex mesh

anchors. This refractory is much harder and denser than the insulating refractory so

that it is provides more erosion protection but does not offer the same insulating

properties.

Instrument connections are inserted through the refractory. Thermowells, which are

used to measure catalyst or gas temperatures, are hard surfaced with a cobalt-

chrome stellite hard surfacing to protect them from the erosive conditions. Pressure

taps (and pressure taps used as level indicators) are protected by steam, gas, or air

purges. These are discussed later in this section. The purges provide a buffer

between the catalyst bearing gas in the regenerator and the small instrument taps

which can easily plug.

Figure 20 shows a conventional (bubbling bed) regenerator in detail. The air flows

from the grid up through a dense bed of catalyst where the carbon is burned off.

The catalyst enters the vessel from the spent catalyst standpipe, at the end of which

is a deflector baffle to distribute the catalyst evenly over the bed, not straight down

to the outlet. The design shown does not have an internal catalyst hopper, which is

a large diameter cone above the regenerated catalyst standpipe. The higher density

catalyst in the cone provides extra head pressure in the standpipe if needed by a

particular unit.

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Combustion gases, excess air, and catalyst particles traveling from the dense

phase to the dilute phase are separated using two-stage cyclones. Flue gas leaving

the cyclones enters a plenum chamber at the top of the regenerator. The hot gases

travel through the double-disc slide valves, which are set to regulate the reactor-

regenerator differential pressure. The flue gas then travels through the orifice

chamber, where its pressure is dropped through a series of perforated plates.

Finally, the energy of the flue gas is recovered in a CO boiler (or steam generator

for a full combustion unit) where the CO is burned along with auxiliary fuel gas and

air to generate steam (or simply cooled to generate steam in a full combustion unit).

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Figure 20 Conventional Regenerator

T

REGENERATOR PLENUMCYCLONE SUPPORTS

REFRACTORYLINING

REFRACTORYLINING

EXTERNALLINING

SPENT CATALYSTDEFLECTOR

AIR DISTRIBUTOR

SECOND STAGECYCLONES

FIRST STAGECYCLONES

THERMOCOUPLES(1each cyclone)

TRICKLEVALVES

SPENT CATALYSTSTANDPIPE

TI’s

LEVEL ANDPRESSURE TAPS

MANWAYS

CATALYSTWITHDRAWAL

OPEN PRIMARYCYCLONE DIPLEG

TERMINATIONSLEVEL AND DENSITYPRESSURE TAPS

MANWAY

TORCH OIL

REGENERATEDCATALYSTSTANDPIPE

FCC-E003

157048-1 Equipment

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TWO STAGE REGENERATOR

The two-stage regenerator (RFCC) is used for units with heavily contaminated resid

feed stocks. The coke deposited on the catalyst is burned off by air distributed

through a grid mounted at the bottom of each stage. The spent catalyst enters the

upper, first stage regenerator which operates in partial combustion mode to

minimize the heat of combustion. Approximately 70% of the coke on the spent

catalyst is burned off in this stage. The catalyst is then transferred to the lower,

second stage regenerator through the recirculation catalyst standpipe. The second

stage operates in full combustion mode with excess oxygen to completely remove

the remaining carbon from the catalyst. This combination provides the heat balance

advantages of partial combustion operation with the advantage of low carbon, high

activity regenerated catalyst.

In the second stage regenerator, air is typically distributed through pipe grid

distributors although dome air distributors can also be used. In the upper

regenerator, the air distributor is typically the mushroom-and-arm type. Arms are

radially arranged around a central dome. The skirt which holds the upper air

distributor in place physically separates the two stages. Vent tubes in the skirt allow

the transport of combustion gasses and excess oxygen (with some catalyst) from

the second stage to the first stage. A two-stage regenerator is shown in detail in

Figure 21.

The recent RFCC design uses multiple pipe air grids in the first stage regenerator

entering through the cone rather than a single dome grid entering through the

second stage. This is a mechanically simpler design which eliminates the need for a

complex expansion joint on the air line. This also allows individual control to the air

grids in each section of the first stage. This configuration is shown in Figure 22.

157048-1 Equipment

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Figure 21 Two Stage Regenerator

SpentCatalyst

Spent CatalystDistributor“Ski-Jump”

First StageRegenerator

Second StageRegenerator

Vent Tubes

First Stage Air Inlet

RegenStandpipe

Hopper

Flue Gas

RegeneratedCatalyst

2nd Stage Air

RecirculationCatalyst

StandpipeCatalystCooler

CooledCatalyst

Standpipe

Second StageRegenerator(Side View)

Pipe Air GridDistributor

MushroomGrid

Distributor

PrimaryCyclone

SecondaryCyclone

157048-1 Equipment

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Figure 22 Updated RFCC First Stage Air Grid Design

2nd Stage Regenerator

1st Stage Regenerator

First StageAir In

FCC-E004

157048-1 Equipment

Page 40

RFCC units will also have one or more catalyst coolers. The catalyst cooler slide

valve position is set by the signal from the second stage regenerator temperature

controller or the slide valve differential pressure controller over-ride via a low signal

selector. The recirculating catalyst slide valve position is set in a similar manner, by

signals from the lower regenerator level controller or the slide valve differential

pressure controller through a low signal selector. Each slide valve packing is steam

purged like the regenerated catalyst slide valve.

In the first stage the flue gas and catalyst are separated by two-stage cyclones. The

catalyst falls down the cyclone diplegs which are submerged in the catalyst bed to

provide a seal against gas passing up the diplegs. The primary cyclone diplegs are

typically open ended pipes with a splash plate and the secondary cyclones have

trickle valves. The catalyst flows into the annular zone around the mushroom air

distributor and into the recirculation catalyst standpipe and catalyst cooler(s). Air is

directed through nozzles on the underside of each arm of the upper air distributor to

help maintain proper fluidization of catalyst in this area.

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HIGH EFFICIENCY REGENERATOR

The high efficiency regenerator approximates a plug flow burning profile for the

catalyst as opposed to the back-mix regime of the standard bubbling bed design.

Because the high efficiency design burns essentially all of the CO in the

regenerator, there is no need for a CO Boiler and there is typically very little

afterburning. The plug flow burning profile also results in much lower NOx

emissions than a bubbling bed.

The spent catalyst from the reactor mixes with the blower air and roughly an equal

amount of recirculating regenerated catalyst at the bottom of the regenerator

(combustor). The recirculating flow of catalyst is necessary because the spent

catalyst at 925°-1025°F (495°-550°C) is not hot enough to initiate and complete

burning in a reasonably sized vessel. The mixing takes place in the lower part of the

regenerator, called the combustor or in a mixing riser, depending on the design.

Figures 23 and 24 show the two designs. These were developed to obtain the best

regeneration, with vessel cost and maintenance considered. The coke burns off the

catalyst as it travels up the combustor riser with the air. There is a rough separation

at the top of the riser through a "tee" shaped outlet. The flue gas goes up to a two-

stage cyclone system and out to energy recovery. The catalyst is returned to a

dense phase. From here the flow splits, part of the catalyst going to the base of the

reactor riser, and the rest back to the combustor.

The high efficiency regenerator has most of the same fittings as the conventional

bubbling bed design. The torch oil nozzles, instrument connections, and catalyst

loading lines are positioned differently because of the different regenerator

configuration, but function in the same manner as those in a conventional unit. If the

unit is equipped with a flue gas power recovery system, there will be spray nozzles

in the plenum chamber for emergency cooling if the temperature at the inlet to the

expander exceeds the safe limit of the machine.

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Figure 23 UOP Fluid Catalytic Cracking Process

High Efficiency Regenerator System

Mixing Zone

SpentCatalyst

RegeneratedCatalyst

Combustor

CombustorRiser

Cyclones

Spent Catalyst Distributor(Ski Jump)Air Grid

UpperRegenerator

Fluffing Air Ring

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Figure 24 High Efficiency Regenerator with External Mixing

SpentCatalyst

RegeneratedCatalyst

Air

RecirculationCatalyst

Standpipe Catalyst/AirDistributor

Combustor

CombustorRiser

UpperRegenerator

Lift Riser

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COMBUSTOR CONE

Figure 25 illustrates the changes in regenerator cone design that have taken place

since the mid-1980s. UOP has developed a new cone detail (see Figure 26) that

eliminates the radial and axial constraint imposed by the hard refractory lining and

cold regenerator shell. The resulting stress is dissipated by incorporating a flexible

soft pack ceramic lining that permits both radial and circumferential expansion.

Additionally, the new cone detail minimizes thermal stresses due to radial

expansion by providing a flexible skirt section that connects to the regenerator wall.

The key feature of the new internal combustor cone design is the air space

incorporated between the cone skirt and the regenerator shell. The air space is

required to provide the optimal heat transfer medium between the cone and the

regenerator shell. By using this air space, it has been proven that the thermal

stresses in the cone are less than the stresses compared to other internal cone

designs that have experienced deformation.

In order to maintain this air space, it is mandatory to keep the air gap free of

catalyst. The catalyst seal device achieves this objective (see Figure 27). Some

characteristics of the catalyst seal are as follows:

1) the seal is not tight; the gap operates at regenerator pressure

2) the seal design supports the weight of the catalyst within the regenerator

3) the seals allows thermal expansion of the cone

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Figure 25 Combustor Cone Modifications

UOP 3110-4UOP 1906H-7

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Figure 26 Detail of Combustor Cone Design

FiberfraxMoist Pak-D

Ceramic FiberBlanket Insulation

Catalyst Seal Device(Figure 26)Refractory

Lining

AbrasionResistant Lining

Retaining Ring

Air Space

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Figure 27 Detail of Catalyst Seal Device

Ceramic Fiber(2 layers)

3.5” Sch. 10S Pips

4”(Cold Position)

2”(Hot Position)

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COMBUSTOR RISER ARMS

Several old-style high-efficiency regenerators have experienced excessive

deformation of the regenerator riser arms. The rectangular openings in the bottom

of the arms have "ovaled" and sagged. The arms have rotated at the leading edge

of the opening and have sagged 1 ft. to 2 ft. (300-600 mm) below the guides on the

regenerator wall.

The primary cause of the deformation is attributed to high-temperature creep

relaxation. During the late 1970's, the original circular openings in the arms were

enlarged to rectangular openings to improve catalyst separation efficiency. This

larger opening significantly decreases the inherent bending strength of the arm.

Several modifications to existing units have been implemented. The first method is

to install stiffeners to the arm to reinforce the opening. The second method is to

install a tension member from the riser to prevent excessive deformation.

The new-style riser arms have a modified geometry. The arms have been designed

as oblong members to improve strength. Additionally, a greater number of shorter,

smaller diameter arms are used (Figure 28). The shorter arm reduces the bending

stress resulting from weight. The increase in the number of arms improves the flow

characteristics in the regenerator by more uniformly discharging the catalyst across

the regenerator's cross-sectional area.

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Figure 28 New Style Combustor Riser Arms

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FLUFFING AIR DISTRIBUTOR

To improve fluidization in the upper regenerator and flow into the standpipes a

fluffing air ring (Figure 29) is installed in the cone. An alternate source of fluffing air

other than the main air blower is now specified for the upper air distributor. On

designs where the fluffing air was provided by the main air blower, circumstances

could arise where insufficient P was available for good fluidization of the catalyst.

Figure 29 Fluffing Air Distributor

ABRASION RESISTANTLINING

ABRASION RESISTANT

LINING

PIPE

3/4 " XX-STRONG PIPE

DISTRIBUTOR JET

STANDPIPES

RESTRICTIONORIFICE

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TORCH OIL NOZZLES

The torch oil nozzles shown in Figure 30 provide a means of injecting heavy oil into

the regenerator when extra heat is needed (e.g. during the startup). The oil is

sprayed into the regenerator with atomizing steam through a special nozzle made of

tungsten alloy to withstand the high temperature. These nozzles may be retracted

through a packing gland if they need to be cleaned. Steam is continuously injected

through a 1/8" (3mm) restriction orifice to the annular space around the nozzle to

keep the area clear of catalyst, which could pack up and prevent retraction of the

nozzle. Steam is also continuously injected through the nozzle tip to keep it cool

and prevent plugging with catalyst. Excess steam may contribute to erosion and

catalyst breakup.

The nozzle should be marked so that after cleaning it can be returned to its proper

position - recessed ¼" (6 mm) back from the refractory face. This position allows

the oil spray to miss the regenerator wall, yet protects the nozzle.

During a turnaround, the various steam and torch oil nozzles should be inspected. If

there has been too much purge steam around the barrel there may be erosion

problems in the refractory surrounding it. The nozzles should be checked for wear

and cleanliness. If the nozzle was not recessed the proper ¼" (6mm), there will

probably be severe metal loss. Refractory damage may indicate the nozzle was

recessed too much. Nozzle positions should be checked when they are replaced.

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Figure 30 Torch Oil Nozzle

SPRAY NOZZLES

Spray nozzles are used to inject water through an atomizing nozzle to cool off the

flue gas in the plenum chamber if the unit has power recovery. The spray water

should be clean, such as steam condensate. Contaminants such as sodium will

cause problems by deactivating the catalyst or contributing to its breakup.

Mechanically, the spray nozzles are similar to the torch oil nozzles.

CATALYST COOLER

The ability to control and vary the amount of heat removed from the regenerator

creates an additional degree of freedom by moderating the regenerator temperature

as a limiting constraint. The catalyst cooler provides a variable heat sink, which

157048-1 Equipment

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allows the refiner to vary the catalyst/oil ratio, reactor temperature, and feed

temperature independently of one another.

The catalyst cooler tube bundle is inserted into a refractory lined shell off the side or

bottom head of the regenerator. The tubes of this exchanger are the bayonet type.

The boiler feed water enters the cooler through the inner tubes and the mixture of

water and steam exits the cooler through the annulus between the inner and outer

tubes. The outer tubes are 3 inch (75mm) O.D. made from 1¼ Cr, ½ Mo seamless

tube material. The inner tubes are 1-3/8 inch (35mm) O.D. made from carbon steel

seamless tubing.

The stainless steel fluidizing air lances distribute air into the cooler near the bottom

of the tubes. The air creates turbulence and increases heat transfer coefficient as

the bubbles travel upward. The backmixing created by the bubbles also brings hot

catalyst into the cooler from the regenerator. The air is delivered to a common

manifold supplying all the lances through a flow controller. The lances contain a

restriction orifice, located near the piping header at the top of each lance, to help

distribute the air uniformly over the cross sectional area of the cooler. The

countercurrent fluidizing air improves heat transfer by creating turbulence and

mixing in the region of contact between the hot catalyst and the tubes. A differential

pressure transmitter, with taps located above and below the cooler, gives a direct

indication of the density of the fluidized catalyst at various conditions of catalyst flow

and air injection.

Mechanical reliability is achieved by locating the cooler in the dense phase of the

regenerator. In the dense phase, the heat transfer coefficient is higher which

permits lower catalyst and fluidization air velocities. Lower velocities minimize

erosion within the cooler. In addition, the cooler tubes are located in the vertical

plane. This feature generates a uniform heat transfer coefficient over the entire tube

surface thereby preventing uneven surface temperatures which cause localized

stress.

Catalyst coolers have been designed and built to fit virtually every regenerator

configuration, including single-stage bubbling beds, high-efficiency combustors, and

two-stage regenerators. Three basic styles of UOP catalyst coolers are currently

available:

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Flow-through catalyst cooler – The catalyst flows downward into the cooler shell

and exits into the cooled catalyst standpipe near the bottom of the tube bundle. The

standpipe transports the cooled catalyst through a slide valve and expansion joint

into the combustor on a high efficiency regenerator or to the second stage

regenerator on an RFCC. In a single stage bubbling bed regenerator the catalyst

can be lifted back into the regenerator with air through a lift riser. Both the catalyst

flow through the cooler and the fluffing air rate are used to control the cooler duty.

Backmix catalyst cooler – This style contains no catalyst exit standpipe. Hot

catalyst enters the cooler by backmixing as a result of fluidization air injected near

the bottom of the tube bundle. The major advantage of this cooler design is that no

slide valve, expansion joint, or standpipe is required. This configuration also permits

the cooler to be lower to the ground if elevation is a limiting constraint. The duty of

a back mix cooler is ~60% of an equal sized flow through cooler and is controlled

only with the fluffing air.

Hybrid catalyst cooler – The combination of flow-through and backmix operation

constitutes the hybrid catalyst cooler. In a hybrid, the catalyst exits into a standpipe

located at the midsection of the tube bundle (instead of at the bottom as in flow-

through coolers). In the hybrid cooler, the upper portion of the bundle operates in

the flow-through mode, and the bundle length below the catalyst outlet operates in

the backmix mode. This configuration achieves somewhat less heat-removal

capacity than a full flow-through cooler but still transfers cooled catalyst down to the

lower portion of the regenerator.

The catalyst cooler steam generation circuit includes the cooler, steam drum, and

circulation pumps. Boiler feedwater is pumped to the bottom head, enters the inner

tubes, then flows down through the annulus between the inner and outer tubes

where it absorbs heat to generate steam. The steam-water mixture leaves the

catalyst cooler to be separated in the steam drum. Makeup boiler feed water is

delivered to the steam drum through a flow controller which is cascaded to signals

from the drum level and steam generation flow transmitters. Steam flows from the

drum through a stop check non-return valve and a superheater (either part of the

flue gas cooler or a fired heater) before entering the refinery steam header.

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Figures 31-35 show some examples of catalyst coolers and catalyst cooler-

regenerator configurations that have been constructed.

Figure 31

Flow Through Catalyst Cooler UOP Catalyst Cooler General Arrangement

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Figure 32 UOP Backmix Catalyst Cooler

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Figure 33 Examples of Bubbling Bed Regenerators

with Catalyst Coolers

Water

Water andSteam

CooledCatalyst

Standpipe

Lift Riser

Lift AirDistributorAir

AerationAir

Water

AerationAir

Water andSteam

Backmixed Flow Through

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Figure 34 Examples of High Efficiency Regenerators

with Catalyst Coolers

Side Mounted HybridCone Mounted Flow Through Cone Mounted Backmix

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Figure 35 RCC Regenerator with Catalyst Coolers

Example of an RCC Regenerator with Multiple Catalyst Coolers

UOP 2119-27 Air

Fluffing Air

Air

BackmixCatalyst CoolerFlow-Through

Catalyst Cooler

Fluffing Air

157048-1 Equipment

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Operating the catalyst cooler with sufficient water circulation to ensure that the tube

walls are always wet so that they can not overheat and limiting the fluffing air so that

the tubes are not subjected to erosion are critical in ensuring mechanical integrity

and long life of the cooler. In new units the flow controller regulating the water flow

to the cooler has been eliminated so the water flow is set by the pump curve. The

spare pumps are instrumented to start automatically on low water flow. If the water

flow is not recovered by the auto start the cooler is shutdown by closing the cooled

catalyst slide valve and the fluffing air control valve. The fluffing air rate should

never exceed a flow that will result in a superficial velocity in the shell of more than

1 ft/sec (0.3 m/sec).

In recent years, as catalyst cooler reliability has improved, UOP has shifted from a

reactive to a proactive approach to catalyst cooler design. Several design

modifications have been developed recently.

Tie Rod Support

Previous designs had the tie rods, which support the eggcrate bracing, protrude

through a hole in the upper tubesheet. The tie rod was welded to the tubesheet on

the steam (bottom) side. While this method was acceptable under normal operating

circumstances, the tie rod could potentially push through the tubesheet if tie rod

growth was restricted due to an obstruction or thermal binding. This would create a

path for the steam to enter into the catalyst side of the cooler, having the same

effect as a tube leak. The current design eliminates the hole through the tubesheet,

using instead a cup into which the tie rod is inserted (see Figure 36). This cup is

countersunk and welded into the catalyst (top) side of the tubesheet. The tie rod is

welded around the rim of the cup above the refractory face providing easy access

for bundle maintenance or refurbishment. This design eliminates the possibility of

the tie rod creating a steam leak.

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Figure 36 Modifications to Tie Rod Supports

Refractory Lining

Upper TubesheetOld Method New Method

Egg-CrateSupport Bracing

Bracing Bars

Tie Rods

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Tie Rod / Eggcrate Connection

Several recent catalyst cooler inspections have revealed tie rod deformation,

usually more severe in the upper section between the eggcrate supports. While this

by itself had not caused any operational problems, it suggests that the fit between

the eggcrates and the outer tubes is extremely tight. Thermal expansion of the

eggcrates causes binding on the outer carbon steel tubes which are water cooled.

The hot stainless steel tie rods expand a greater amount and do not have adequate

strength to move the eggcrates as they are intended. Their thermal growth being

restricted, the tie rods buckle. As a result, the eggcrates are no longer welded

directly to the tie rods which allow them to expand independently of each other (see

Figure 36). The eggcrates are supported by minimal friction on the tubes

themselves. The hot tie rods are free to expand within the eggcrates. As a

precaution, large washers are welded to the tie rods a few inches above and below

the eggcrates to limit any unexpected movement of the eggcrates either during

operation or bundle handling.

Flat Tube Caps

The fluffing air headers and lances are supported by arms that are welded near the

top of the air lances (see Figure 37). Originally, each arm was welded to a stainless

steel pipe support stool that was welded to the outer tube hemispherical tube cap.

Later, the arm to support stool weld was removed in order to allow for a greater

degree of flexibility for the fluffing air headers and lances. In the current design, the

support stools have been replaced with flat tube caps (see Figures 37 and 38).

These new tube caps are machined bar stock that are rounded on the inside and

flat on the top. The removal of the pipe support stools has several advantages :

• A weld to a pressurized tube cap is no longer necessary.

• A postweld heat treatment step has been eliminated.

• Tube alignment is easier.

• A more uniform surface on which the air lances can rest has been created.

The small additional cost of the flat tube caps is recovered in assembly time.

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Figure 37 Modifications to Outer Tube Caps

Aeration Pipe Header

Outer Tubes

Lance SupportArms

Pipe SupportPlate

Pipe SupportStool

Aeration Lance

Flat Tube Cap

Old Method New Method

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Figure 38 Flat Tube Cap

Inner Tube Wall Thickness

The wall thickness of the inner tube has been increased on most recent catalyst

cooler designs. The resulting smaller diameter increases the inlet water pressure

drop which ensures a uniform distribution of water to all of the tubes and guarantees

the tube cap and inside wall of the outer tube are fully wet.

Eight-Foot Cooler

As FCC and RFCC units become larger and are required to process very heavier

resid, the heat removal demand increases. In anticipation of this, UOP now offers

an eight foot diameter cooler (96" ID of shell). This cooler can provide about 40%

more duty than the typical seven-foot design. This is particularly beneficial when the

157048-1 Equipment

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required duty is slightly higher than the duty of a seven foot catalyst cooler, making

a single eight foot cooler a less expensive alternative to two smaller coolers.

Update: Debris Screens

Since 1991, debris screens have been installed in all existing units. Debris screens,

which are installed at the entrance to the cooler, have become standard supply for

all coolers mounted on the lower regenerator cone or head. The screens prevent

large refractory pieces or other loose debris from accumulating at the bottom of the

tube bundle where the debris can restrict or divert the flow of air from the air lance,

potentially causing catalyst impingement on a tube and an eventual tube leak. Aside

from some minor improvements in the anchoring method, the screens have held up

well in operation and have performed their function. There have not been any tube

leaks caused by accumulated debris in coolers with debris screens.

Update: Air Lance Pressure Testing

Because the internal air piping and lances are not subject to code requirements,

UOP implemented a required shop pressure test of the completed aeration

assembly in 1991. Since that time, there have been no reported air leaks or weld

failures in any operating coolers that have received this testing. Prior to the shop

testing, air leaks had occurred in at least five units, three of which lead to tube

leaks.

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CYCLONES

The flue gas leaving the dense bed will entrain some of the catalyst particles with it.

Some of these settle back to the bed; others are carried higher. Measurements of

the entrained particles taken at increasing heights above the bed show a gradual

decrease in the amount of fines entrained. At some point above the bed, the

concentration of particles entrained levels out. This is called the Transport

Disengaging Height, or TDH.

Early FCC units used a number of small tubes, called multi-clones to remove

particles. These were not particularly effective and were difficult to maintain. The

cyclone design shown in Figure 39 was the next step. The shaveoff was intended

to increase efficiency, but also proved difficult to maintain. The cyclones used in the

modern FCC unit use a fairly simple principle to remove most of the particles. See

Figure 40. The catalyst bearing gas enters a cylinder through a tangential opening.

The catalyst is 500-1000 times as heavy as the gas, and is subjected to forces

several hundred times that of gravity as the gas swirls around the cylinder. The

larger particles are removed through centrifugal forces which force the particle

outward to collide with the wall. The collisions slow down the particle so that they

fall by gravity into the dust hopper and are returned to the vessel through the

diplegs. The viscous drag forces of the gas tend to carry some of the catalyst

particles with it. Generally only the smaller particles are light enough to stay with the

gas, because the inertial and centrifugal forces acting on them are small.

The catalyst separated from the gas stream swirls downward due to the force of

gravity. The chamber below the entrance of the cyclone tapers downward and tends

to keep the catalyst against the wall which is away from the cleaner area at the

center core (where the gas disengages and moves up). There is more disengaging

area in the hopper, which feeds catalyst to the dipleg; this disengaging area also

decreases the amount of erosion which could be created by the vortex of the

catalyst particles.

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Figure 39 Cyclone-Catalyst Fines Collector with Shaveoff

UOP 2119-28

Catalyst-FreeGas Outlet

Gas Out

Stream Pattern-Lower Portion

Catalyst-LadenGas Inlet

Stream Pattern-Upper Portion(Principally Finer Particles)Note:

Because of the High MaintenanceRequired on the Catalyst Shave-Off(Caused by Erosion) many Refiners areChoosing to remove this Device

“Catalyst Shave-Off”

Bypass

Dip Pipe

Re-EntryOpening

DisengagingHopper

CatalystOutlet

Catalyst-LadenGas Inlet

Bypass

CatalystShave-Off

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Figure 40 Cyclone-Catalyst Fines Collector

There is a pressure drop between the cyclone inlet and dipleg outlet. If the catalyst

is to be returned to the bed, the dipleg must hold a head of catalyst sufficient to

overcome this differential. If the catalyst in the dipleg stops flowing, the gas will

simply carry the catalyst out the top. If the dipleg is submerged in the bed, then the

pressure at the bottom will increase and catalyst will be forced out as the level in

the leg rises. The required head will determine the dipleg length.

There are two general types of dipleg termination devices – the trickle valve and

counterweighted flapper valve. The trickle valve in Figure 41 is generally used on

submerged diplegs. The valve is simply a flat plate held closed by gravity and

external pressure until the catalyst head in the dipleg is sufficient to open it. The leg

dumps, and the trickle valve swings shut. The counterweighted flapper valve in

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Figure 42 is another method, with a better seal than the trickle valve. The

counterweight holds the flapper closed until the catalyst head is sufficient to open

the flapper.

UOP has updated the design of the counterweighted flapper valve to improve its

mechanical reliability and maximize the unit onstream efficiency.

The major revisions to the design are:

1. Addition of a stop bar to prevent the valve from opening more than 45° (see

Figure 42).

2. Addition of a stiffener bar on the fixed portion of the pivot mechanism to

minimize warpage or movement over the course of repeated thermal cycles.

3. Minimizing the tolerance between the concentric bushings to 3 mm plus 1.6

mm minus 0 mm (1/8" plus 0.0625" minus 0") to allow for thermal growth

(see Figure 43).

4. Requirement that the hard surfacing used on the pin and bushings be crack

free. There is some concern that surface cracking may contribute to

roughness and thus restrict smooth motion of the hinge mechanism.

Alternative hard surfacing such as Waspalloy, Wallex 50 and Triten should

be considered as options for hard surfacing of the pin and bushings.

5. Increasing the amount of counter weight used (Table 1).

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Figure 41 Trickle Valve

Hinge

Flapper Plate

Stop

3-5º From Vertical

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Figure 42 Counterweighted Flapper Valve

Closed Position Open Position

STIFFENER

LUG

DETAIL

1

1

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Figure 43 Bushing Detail

LUG ON DIPLEG

OF BUSHING

ECCENTRIC BUSHING

CONCENTRIC BUSHING

OF BUSHING

AND HOLE

OF BUSHING

OF BUSHING

OF HOLE

CONCENTRIC

BUSHING

(BOTH SIDES)

ECCENTRIC

BUSHING

1/8 " (BOTH SIDES)+0.0625"-0.000"

C

C

C

C

C3"

(75m

m)

DIA

7/8 "

(22mm)

2 9/

32 "

(58m

m)

DIA

2 9/

32 "

(58m

m)

DIA

3mm+1.6mm-000mm

3/8 "(10mm)

(INCLUDES 1/8 "(3mm)

HARD SURFACING)

3/8 "(10mm)

(INCLUDES 1/8 "(3mm)

HARD SURFACING)

1/8

"

(3m

m)

1/8

"(3

mm

)

HA

RD

SU

RF

AC

ING

3"(7

5mm

) D

IA

1/8

"(3

mm

)

HA

RD

SU

RF

AC

ING

7/8 "

(22mm)

1 1/

2 "

PLU

S/M

IN 1

/32

"ID

38m

m P

LU

S/M

IN.8

mm

ID

1 1/

2 "

PL

US/

MIN

1/32

"ID

38m

m P

LU

S/M

IN.8

mm

ID

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TABLE 1 FLAPPER VALVE COUNTERWEIGHT

Dipleg Counterweight Diameter Lbs / Kg 6” (150 mm) 1.9 0.9 8" (200mm) 3.3 1.5 10" (250mm) 5.4 2.4 12" (300mm) 7.8 3.6 14" (350mm) 9.6 4.4 16" (400mm) 12.8 5.8 18" (450mm) 16.4 7.4 20" (500mm) 20.5 9.3 22" (550mm) 25.0 11.4 24" (600mm) 30.0 13.6

Two important factors in cyclone efficiency are the velocity of the gas and the size

distribution of the particles. In general, the higher the velocity, the higher the

efficiency. It should be remembered, however, that higher cyclone velocities may

mean higher vessel velocities, with more catalyst carried up to the cyclones. If these

are larger particles, most of them will be collected, but in extreme cases, the

cyclones could be overloaded and the larger particles lost. Higher velocities also

means higher rates of erosion and catalyst attrition. The solids distribution is not

under immediate control, except by minimizing attrition of the catalyst by avoiding

areas of high velocity. In general, the small fines, less than 20 microns, will be lost,

with most of the larger size particles collected. The reactor cyclones generally do a

better job because here the coke on the catalyst fines makes them larger and

easier to collect.

The design of the cyclone is the important factor in its efficiency as well as the

resistance to erosion; it is normally handled by the cyclone manufacturers.

However, in the early 1980's, erosion in the cyclones and cyclone diplegs increased

noticeably. Units were beginning to process larger quantities of heavier and more

contaminated feeds. These feeds produce more coke, which increases air demand

and regenerator temperatures. The net result is increased erosion as a result of an

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increase in catalyst loading and cyclone velocities. Competition among vendors was

another factor leading to an increase in instances of erosion. In some cases,

vendors supplied cyclones with key geometric ratios, such as L/D, minimized for

cost reasons.

To address these problems, UOP began to specify cyclone geometric relationships

and velocity criteria. The purpose was to ensure that all cyclone vendors bid on the

same basis and that the cyclones supplied met the process and mechanical

requirements set by UOP.

The requirements set forth in the "Mechanical Considerations In FCC Design" paper

presented at the 1996 UOP FCC Symposium have significantly reduced erosion

problems. These requirements are as follows:

Single-Stage Reactor Cyclone Criteria Inlet velocity shall not exceed 65 ft/sec (19.8 m/sec). Outlet velocity shall not exceed 100 ft/sec (30.5 m/sec). Ratio of barrel area to inlet area shall be 5.5 minimum. Ratio of the main cone outlet diameter to the barrel diameter shall be 0.4

minimum. Ratio of cyclone height, measured from the roof of the cyclone to the outlet of

the dust hopper cone, to its barrel diameter shall be 5.0. Projected apex point of the main cone shall terminate at a minimum distance of

0.3 x barrel diameter above the outlet of the dust hopper cone (0.5 x barrel diameter for eccentric diplegs).

Ratio of the dust hopper diameter to the main cone outlet diameter shall be 1.5 minimum.

Ratio of the dust hopper cone height to the barrel diameter shall be 0.45 minimum.

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Regenerator Cyclone Criteria

First Stage

Inlet velocity shall not exceed 65 ft/sec (19.8 m/sec).

Outlet velocity shall not exceed 80 ft/sec (24.4 m/sec).

Ratio of barrel area to inlet area shall be 3.7 minimum.

Second Stage

Inlet velocity shall not exceed 75 ft/sec (22.9 m/sec).

Outlet velocity shall not exceed 120 ft/sec (39.6 m/sec).

Ratio of barrel area to inlet area shall be 4.3 minimum.

Both Stages

Ratio of the main cone outlet diameter to the barrel diameter shall be 0.4

minimum.

Ratio of cyclone height, measured from the roof of the cyclone to the outlet of

the dust hopper cone, to its barrel diameter shall be 5.0.

Projected apex point of the main cone shall terminate at a minimum distance of

0.3 x barrel diameter above the outlet of the dust hopper cone.

Ratio of the dust hopper diameter to the main cone outlet diameter shall be 1.5

minimum.

Ratio of the dust hopper cone height to the barrel diameter shall be 0.45

minimum.

The reactor cyclones are normally a low alloy steel, such as 1¼ Cr, ½ Mo. Some

older partial CO combustion regenerator cyclones used 5 Cr or 12 Cr, with 1¼ Cr

diplegs sometimes. For the higher temperatures of modern, complete CO

combustion, Type 304 stainless steel (18 Cr, 8 Ni) is used. Abrasion resistant lining

is used on all cyclones to protect them from catalyst erosion. The inlet horn, the gas

outlet pipe, barrel, disengaging hopper, and part of the dipleg will be lined. The

157048-1 Equipment

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extent of the dipleg lining will depend on accessibility and prior experience; erosion

in one area usually leads to a lining at the next turnaround. The exterior of the

diplegs must be protected with an abrasion lining where they are subject to catalyst

impingement, such as from the spent catalyst inlet or from another dipleg discharge.

ORIFICE CHAMBER

Orifice chambers (Figure 44) are used on FCC units when the regenerator pressure

is controlled by flue gas slide valves. The chamber is a cylindrical vessel with a

series of perforated grid plates (Figure 45). These plates hold a backpressure

downstream of the slide valves. By reducing the pressure drop across the valves,

their operating life is greatly extended because there is no sudden acceleration of

the catalyst bearing gas stream. The flow through the orifice chamber may be

upflow or downflow depending on downstream equipment. There are no moving

parts, so no adjustments can be made on stream. UOP designs the orifice chamber

as follows:

the flue gas slide valve is designed for approximately one-third of the pressure

drop and the orifice chamber is designed for the remaining two-thirds of the

pressure drop.

enough grids are installed to limit the pressure drop across each individual grid

while maintaining a specified velocity across each hole.

the distance between the top grid and the flue gas slide valve is kept at a

maximum. In revamp situations, this distance may be short and lining will be

required for the first grid only. Additionally, the installation of a shroud at the

inlet has proven to be beneficial in reducing erosion.

Given the UOP design philosophy of using cold wall construction whenever

possible, UOP has developed a cold wall orifice chamber. As a result, the chamber

walls are no longer prone to buckling, cracking, bulging and other phenomena

associated with high temperature stainless steel design.

Because of the high inlet temperature of the orifice chamber, the grids must be

designed for stainless steel metallurgy (if a waste heat boiler is installed upstream,

then carbon steel or low chrome can be used). The grids are supported by a

157048-1 Equipment

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cylindrical skirt section; typically two grids are supported from one skirt section. The

cylindrical skirt is supported by a tapered skirt section which is then welded to the

chamber wall. The tapered skirt requires a certain length to accommodate the

thermal expansion of the stainless steel grid relative to the cold wall shell. A gap is

also provided between the skirt and the refractory lining to allow for this expansion.

Blanket insulation is provided behind the tapered skirt to allow for the thermal

deflection.

The cold wall orifice chamber significantly reduces the amount of thermal growth of

the flue gas line (as compared to the hot wall design). This reduction will reduce or

eliminate the amount of expansion joints required. Given the change in thermal

movements, as well as the additional weight (due to the refractory), the entire flue

gas system should be reviewed for both support and flexibility for revamps.

Inspection

UOP has developed two types of orifice chambers to accommodate various revamp

inspection requirements. The first option allows external manway access to each

pair of top skirt grids (due to the skirt support scheme, external access to all grids is

not possible). To accommodate the external manways, extra tangent length for the

orifice chamber is required.

In the event there are space limitations, a shorter version has been developed.

Inspection access for this design requires the use of internal manways on each grid.

157048-1 Equipment

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Figure 44 Cold Wall Orifice Chamber

FLOW

InternalManways

Inlet Shrould

157048-1 Equipment

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Figure 45 Orifice Chamber Details

CERAMIC FIBERBLANKETINSULATION

HIGH DENSITYREFRACTORYLINING

+-

AIR

SP

AC

E

HIGH DENSITYREFRACTORY LINING

ABRASIONRESISTANT LINING

AIR GAP

LINING TRANSITION

RIN

G N

O 1

RIN

G N

O 2

RIN

G N

O 4

RIN

G N

O 5

INTERNAL MANWAY

GRIDC

RIN

G N

O 3

GRIDC

RING NO 4

RING NO 3

RING NO 2

STAGGER HOLESWHERE POSSIBLE

RADIUS RING NO 1

RING NO 5

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ELECTROSTATIC PRECIPITATORS

Electrostatic precipitators (Figure 46) are used to remove catalyst fines from the

flue gas. The equipment consists of a large rectangular steel shell which contains a

number of wires called discharge electrodes, and a number of flat collecting plates.

The wires and plates are hung vertically, in alternating rows. A high electrical

potential is put on the discharge electrode wires, and the plates are electrically

grounded. A corona discharge surrounds the discharge electrode because of the

high potential. Gas ions formed by this corona move rapidly towards the collecting

electrode. When an ion strikes a catalyst fine, it becomes charged. The electrical

field between the electrodes causes the particle to deposit on the collecting

electrode. As more particles collect, a layer of fines builds up on the plate. A

mechanical rapper periodically strikes the frame of the collecting plate, and the

particles are knocked off. The fines tend to agglomerate into larger particles which

fall into dust hoppers under the electrodes. There is no physical change in the

particles, simply an agglomeration which makes them large enough for gravitational

forces to exceed the carrying force exerted by the gas.

Precipitators usually operate at pressures slightly above atmospheric. Inlet

temperatures range from 400-800°F (205-425°C). The temperature is especially

important if the flue gas has acidic components such as SOx or NOx. These may

condense and combine with water to form corrosive agents. The precipitator shell

may be insulated to hold the metal temperature high enough to prevent

condensation.

157048-1 Equipment

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Figure 46

Electrostatic Precipitator

UOP 2119-34

DischargeElectrodeRapper

Insulator

Collecting Surface Rapper

Transformer Rectifier

Gas Out

Hopper

Catalyst Fines OutDischargeElectrode

Gas Flow In

CollectingSurface

157048-1 Equipment

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Collection efficiencies range from 70-99%, with 90-95% more common. The factors

affecting the efficiency are:

1. Effective voltage and other electrical factors

2. Resistivity of fines

3. Size distribution

4. Gas flow rate

5. Collector plate area

6. Rapping cycles

As the effective voltage increases, the efficiency increases. Too high of a voltage

can lead to arcing, which will damage the electrodes. Arcing can also occur if the

weights holding the discharge electrode wires fall off and allow the wires to swing

over towards the collecting plate. The precipitator should be designed with the

proper number of power supplies and control equipment to prevent excess

sparking.

The resistivity of the fines is approximately constant. It may be decreased for better

collection efficiency by adding small (<20 ppm) amounts of ammonia, but this is

usually not required. Spray water is also used in some cases.

The size distribution will be determined by cyclone performance in the regenerator.

Large solids rates to the precipitator, even with high efficiencies, may still lead to

emission problems, so it is better to have lower loadings to the unit. Larger particles

are easier to collect, because the smaller ones are more easily carried with the gas.

Typical gas flow rates are 5-6 ft/sec (1.5-1.8 M/s). Lower flow rates will give greater

efficiency. A higher collecting area will also increase efficiency.

The final factor, the rapping cycle, is normally designed for one strike from each

rapper every 1-3 minutes. Greater power and frequency of rapping will increase

efficiency, but must be balanced against cost. Both collecting and discharge

electrodes are fitted with rappers, most of them positioned on the collectors.

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CATALYST STORAGE HOPPER

The FCC unit is normally built with two or three catalyst hoppers (Figure 47). One is

for fresh catalyst, the other is for equilibrium catalyst. RFCC units or FCC units with

high metals feed stocks may have a third hopper for storing low metals equilibrium

catalyst. The vessels are normally carbon steel, constructed to withstand a full

vacuum, although this should be checked before the first use. Many units are built

with automatic gauging devices, but these are not always accurate because the

float tends to sink in the catalyst. For accurate measurement of the catalyst level,

the hopper should be fluffed with air from the bottom and the catalyst allowed to

settle. A hand gauge can then be used to read the tons of catalyst from a chart of

inventory as a function of hopper ullage. Exact settled densities for a given type of

catalyst may be determined by measuring level change after a weighed amount of

catalyst has been loaded or unloaded by truck or cartons. A discussion of catalyst

loading and hopper operation is provided in the procedure section.

CATALYST LOADING AND UNLOADING LINES

The catalyst transfer line at the bottom of the regenerator is normally used to

remove catalyst from the regenerator when the unit is shut down. Most of the

catalyst will be loaded and unloaded through a connection (4-6 inch or 100-150

mm) in the dense bed area. For rapid transfer, a large line is used. For gradual

fresh catalyst addition, a smaller line is used which connects into the large line just

before the regenerator at an angle to minimize erosion. The catalyst lines are

usually carbon steel. The catalyst withdrawal lines from the regenerator should be

1¼ Cr, ½ Mo (up to the second block valve). It may be cased in places for

personnel protection, but should be allowed to cool off to the atmosphere so that

the temperature limits of the metal are not exceeded when hot catalyst is unloaded.

Some units have finned pipe to help in cooling off the unloaded catalyst.

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Figure 47 Catalyst Storage Hopper

VacuumNozzle

Auto GaugeInstrument

ManualGauge Hatch

Relief Valve

Inlet

Grate withWire Mesh

Outlet

Manway

Catalyst Makeup(Fresh Catalyst Only)

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CATALYST STANDPIPES AND EXPANSION JOINTS

Catalyst flows through refractory-lined standpipes from the regenerator to the base

of the riser, from reactor to the regenerator, and from the upper regenerator to the

combustor. Expansion joints (Figure 48) are placed in these large catalyst-transfer

lines to absorb thermal movement within the system and thereby minimize stresses

imposed on vessel nozzles. The expansion joint is lined to protect the bellows from

catalyst erosion. Pantographic linkages are used on the expansion joints to assure

equal movement of both expansion bellows during temperature changes.

Parameters affecting expansion joint design are movement to be absorbed, process

environment, mechanical construction, and specified cycle life. During the last 10

years, advances have been made in the engineering and metallurgy of expansion

joints. For a hot wall regenerator standpipe using 304H SS, the expansion joint had

Inconel 625 bellows that were annealed after forming [for combined resistance to

polythionic attack (PTA) and stress corrosion cracking (SCC), Inconel 625 is one of

the recommended alloys]. The maximum allowable bellows temperature for this

design was 1200°F. Today we use cold wall design for the standpipe and expansion

joint. The expansion joint bellows use Inconel 625 LCF (low cycle fatigue) with a

maximum allowable temperature of 1000°F and it is not annealed after forming.

Annealing reduces the strength of the bellows as well as the fatigue properties.

It is important that the bellows material not get too hot so age hardening does not

occur. It is also important to stay above the dew point of the process so the bellows

stay dry and corrosion is avoided. For example, the regenerator expansion joint

bellows temperature would be close to the dew point so UOP specifies external

insulation of 25 mm which is enough to raise the bellows metal temperature to 600-

800°F and to stabilize it from external changes caused by the weather.

157048-1 Equipment

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Figure 48

Expansion Joint Location

Spent CatalystExpansion Joint

Regenerated CatalystExpansion Joint

Recirculation CatalystExpansion Joint

Spring Hangers

Structural Bumper

Top of Support

Top of Support

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The typical components of a UOP specified expansion joint are shown in Figure 49.

Figure 49 Expansion Joint Components

Flow

Bellows

Convolution Cover

Liner

RootRing

PurgeConnection

Bellows Design – UOP presently specifies single ply bellows. Dual Ply bellows are

acceptable provided each ply is designed for full temperatures and pressure. Dual

Ply bellows should include a method for pressure leak detection (preferably a

positive pressure gage) as shown in Figure 50. When adding a dual ply

replacement to an existing expansion joint, the piping system should be reviewed

for the additional loads induced by the higher spring rates of the dual ply.

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Figure 50 Two-Ply Bellows

WEEP HOLE

FOR LEAK

DETECTION

PROCESS PIPE

SEAL BAND TO ISOLATE

BELLOWS ATTACHMENT

WELD

TWO-PLY TESTABLE

BELLOWS

ATTACHMENT

WELD

Control Rod Design – The control rods are intended for control and stability of the

expansion joint and are not intended to take the full bellows pressure thrust force.

The control rods should be used for reference when determining the installed

position of the expansion joint as well as a reference during operation and shutdown

(for future trouble shooting information).

Equalizing Rings – UOP presently specifies a self equalizing expansion joint. Root

rings are an acceptable alternative to equalizing rings. (UOP specifies a minimum

area requirement for root rings). Equalizing rings and root rings are intended for

added protection in the event of over pressure.

Bellows Packing Details – Several methods of packing the bellows are shown in

Figure 51. External insulation is required on packed bellows to minimize the

potential of condensation during operation. UOP currently uses packed bellows for

all expansion joints except for the spent catalyst expansion joint which is

continuously steam purged to remove hydrocarbon and minimize coking. Several

refiners have successfully used packed bellows for the spent catalyst expansion

joint. UOP is currently evaluating several FCC units before packed bellows for this

service is incorporated in the project specifications.

157048-1 Equipment

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Figure 49 illustrates a typical expansion joint with an aeration connection. The

purge prevents an accumulation of catalyst between the bellows and inner wall

which would restrict the movement of the expansion joint. The purge should be 5-10

psi (0.35-0.70 kg/cm2) above standpipe pressure; the purge is normally controlled

with a restriction orifice.

Figure 51 Packing Details of Expansion Joints

The expansion joint of the spent catalyst standpipe is of hot-wall construction to

match the spent-catalyst stripper. Based on the location of vessel supports, this

157048-1 Equipment

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expansion joint absorbs both axial compression and lateral offset. These forces are

due to the regenerator expanding upward, the spent catalyst stripper downward,

and the standpipe compressing during operation. This standpipe is relatively short

and therefore not subjected to out-of-plane movement that occurs on inlet and

outlet nozzles connected to large-diameter vessels. Early units used carbon steel

standpipes and slide valves for the spent catalyst to the regenerator. Most of the

newer units use 1¼ Cr, ½ Mo; although a few have stayed with insulation lined

carbon steel.

On new units, the regenerated catalyst standpipe and the lower portion of the

reactor riser are of cold-wall construction. On this type of unit, the expansion joint

needs to absorb axial extension and lateral offset, mainly as a result of the large

thermal growth from the hot-wall stripper and upper reactor riser. On older units

having a hot-wall wye section and regenerated catalyst standpipe, the primary

movement during operation is still axial extension and lateral offset. However, on

shutdown of the unit, the expansion joint may need to absorb axial compression,

which occurs when the raw oil is cut from the unit, steam is added at the bottom of

the riser, and the regenerated catalyst slide valve is closed. The steam cools the

reactor riser while the regenerator standpipe remains at operating temperature

because of hot catalyst filling the standpipe above the closed slide valve. The

regenerated catalyst standpipe can also be subjected to additional movements

because of the long length of reactor riser and standpipe. Any bowing of the riser or

the stripper or sagging of the standpipe affects the amount of axial movement and

lateral offset the expansion joint has to absorb. The regenerated catalyst standpipes

and slide valves range from 5% Cr on conventional units to stainless steel (Type

304) in older higher temperature units and cold wall design in modern high

temperature units.

Thermal movement is absorbed within the expansion joints by means of a flexible

item referred to as bellows. The bellows are formed into a corrugated shape from

thin-gauge material of a metallurgy selected to perform in the process environment

encountered; the expansion joint bellows are normally Alloy 625. The geometry and

number of corrugations used relate to the total movement capacity of a bellows.

The bellows design is based on equations outlined in the Standards of the

157048-1 Equipment

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Expansion Joint Manufacturers Association (EJMA). These equations were

developed from engineering efforts with expansion joint manufacturers, extensive

testing programs, and operating history. See Figure 52. The expansion joint must

also conform to the ASME Code for Pressure Piping, B31.3.

The expansion joint bellows absorb movement by means of axial compression or

extension, angular rotation, and lateral deflection. See Figure 53. The expansion

joints used in the FCC unit standpipe are subjected to both axial movement and

lateral deflection. For this reason, two separate sets of bellows, called a dual

element expansion joint, are incorporated in the design. The lateral deflection

occurs in the vertical plane, parallel to the expansion joint pantographic linkage, and

is absorbed by means of angular rotation of the bellows.

157048-1 Equipment

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Figure 52 Bellows Movement

▀

TAN =hL

2

▀2

= +

If Ends are Parallel: = ▀ =

h

L

E

D

C

AB

F

Ratios:C A FD B E

= =

Tan ( ) = ( )( )or

( )( )

2

C - AF

2

D - BE

2

157048-1 Equipment

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Figure 53 How Motion is Absorbed by Bellows

157048-1 Equipment

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SLIDE VALVES

Slide valves are used to control catalyst flow. These are gate-type valves driven by

a hydraulic actuator. The primary problems encountered with slide valves were

associated with erosion and corrosion. The elimination of guide steam purges have

alleviated many of the corrosion problems. However, if guide steam purges are

present, then the steam purge can be used once or twice a shift to keep the guides

free of catalyst. In some cases, a continuous purge is used, but its flow should be

restricted to prevent erosion of the guides. To prevent erosion, the valve disc is

covered with an abrasion-resistant refractory anchored by stainless steel hexmesh.

Hard metal surfacing is used on other parts of the valve exposed to catalyst flow

(see Figures 54 and 55). The clearances between the support guides on the sides

of the valve and the disc are set by the manufacturer. The entire system will expand

when it gets hot, so these clearances should be checked to avoid binding or

sticking. The new slide valves are designed such that no guide purge is required.

Cold wall design which uses carbon steel (see Figure 54) has also eliminated some

corrosion problems as well as many of the cracking problems generally associated

with hot wall design (specifically polythionic attack on the stainless steel). By

working closely with many slide valve suppliers, UOP has also incorporated design

and geometry guidelines which minimize erosion during normal operation. These

changes include locating the orifice plate upstream of the valve and sloping the

bottom of the bonnet a minimum of 30° from the horizontal. The sloped bottom

prevents catalyst accumulation in the bonnet. The support guides for the disc are

recessed a minimum of 3" (75mm) from the sides of the inlet port. Other design

improvements recently developed are as follows:

1. Five second stroke time for normal operation.

2. Two second stroke time for emergency shutdown.

3. Emergency shutdown features are testable on stream.

4. Offset port to center flow during normal operation.

5. Development of cold wall valves for spent catalyst standpipe service.

6. In shop hot stroke test required to guarantee trouble free operation in the field.

157048-1 Equipment

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Figure 54 Cold Wall Slide Valve

Port Opening

Guide Bolting

Drain SlotsGuide

Bonnet

C PortL

C ValveL C PortL

C ValveL

Flow

Bonnet

Stuffing Box

Stem DiscOrificePlate

CarbonSteelShell

157048-1 Equipment

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Figure 55 Hot Wall Slide Valve

HYDRAULIC OIL SYSTEM

A hydraulic oil cylinder is used to drive the slide valve because of its size and the

required fast response. A low capacity, high head pump supplies the oil through the

controlling pilot valve. A manual control valve, the joystick, is also provided in case

the pilot valve plugs. Most slide valves are equipped with a handwheel for use

during total hydraulic oil failure. When the bypass valve between the two ends of

the hydraulic oil cylinder is opened to equalize pressures, the handwheel is

engaged. It is somewhat risky to attempt control on handwheel during normal

operation, because the handwheel is usually very slow. A typical response time for

a slide valve on a conventional hydraulic oil operation would be fully open to fully

closed in 30 seconds maximum. Many older systems unfortunately are slower than

this. Startup should never be attempted with handwheel control as valve closings

will be slower than required. The handwheel should never be engaged until the

hydraulic cylinder is bypassed. The equipment may be damaged if the hydraulic

cylinder exerts force against the hand wheel.

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A typical FCC slide valve hydraulic oil system, used in earlier designs, is shown in

Figure 56. The hydraulic oil is pumped out of the low pressure tank through a filter

to the slide valve. It circulates back from the valve or from two flow by-passes. One

of these is a hand controlled valve at the end of the hydraulic header; the other is a

minimum flow bypass on automatic control. These keep the oil circulating and

prevent pump damage that might occur if the pump were to run against a closed

system, such as when the pilot valve is holding the valve in one position. A spare

pump with auto start is used to maintain flow if the first pump fails. The high

pressure oil tank will supply sufficient hydraulic oil to close the slide valves if both

pumps go down. This tank is not large enough to hold oil pressure for more than

one to two minutes. If both pumps are lost, the unit should be brought down until at

least one is running again. Modern plants are designed with a separate oil system

for each valve, but it is more common to have one hydraulic oil system for all slide

valves. Small multi-stage centrifugal pumps are gradually replacing the

reciprocating pumps on older plants.

157048-1 Equipment

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Figure 56 FCC Slide Valve Hydraulic Oil System

UOP 2119-44

Legend

DF

FHFIC

F & WHC

HPRHVIA

LPRPVROSV

= Drain= Filter= Flexible Hose= Flow Indicating Controller= Filling & Withdrawal= Hydraulic Cylinder= High Pressure Receiver= Hand Valve= Instrument Air= Low Pressure Receiver= Piolet Valve= Restriction Orifice= Safety Valve

N2 IA

Must Drain

RO

D

LPRHPR

PISV

FIC

M P P T

F & W

HV

FH

FVHC

From ControlInstrument

F

F

F

157048-1 Equipment

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UOP currently specifies electrohydraulic actuator assemblies with an individual

hydraulic power source for each slide valve (see Figure 57). The individual

hydraulic power source has several advantages in that the valves act independently

and eliminate all interconnecting piping.

A continuous running variable displacement pump maintains the system's hydraulic

pressure. When no valve movement is required, the pump operates near its no-load

current level and reduces heat generated in the reservoir. Hydraulic oil flows from

the pump through a set of filters into the accumulators and actuator. The actuator is

electronically controlled and directs hydraulic oil pressure to either end of the

cylinder, positioning the slide valve in response to the process demand.

An accumulator makes the fast response of the valve possible. When necessary,

this accumulator will drive the valve two complete cylinder strokes at an

approximate speed of 5 seconds per stroke. If the accumulator becomes depleted,

the pump motor itself can supply power to move the slide valve 10% of its stroke

every 10 seconds.

There is an emergency accumulator, which normally is isolated from the hydraulic

system and can be used only if directed from the control room. This accumulator

will also generate two actuator cylinder strokes.

If the pump and spare motors are lost and the emergency accumulator is not used,

there are two means of manually positioning the actuator. One mode of manual

operation uses a hand pump to move the cylinder. During normal operations, the

hand pump is isolated from the system. The other mode uses a mechanical jack or

manual handwheel to move the cylinder. When the handwheel is put into operation,

the hydraulic cylinder is automatically bypassed to prevent damage should hydraulic

power be restored.

The hydraulic pilots are very sensitive mechanisms and it is imperative that the oil

supplied to them is absolutely clean. It is important that the hydraulic oil used has

the proper viscosity and meets all the specifications given by the valve

manufacturer.

157048-1 Equipment Page 100

Figure 57 Slide Valve Actuator

Component Arrangement and Hydraulic Circuitry

REACTOR RISER DISENGAGER DESIGNS

The heart of any catalytic process is the reaction site. In the case of the modern

FCC unit, this is the riser. With the introduction of riser cracking, the reaction site

has changed from the reactor vessel to the riser. Today's reactor could be more

properly called a disengaging vessel. A historical progression of riser termination

devices (from the 70's to early 90's) is illustrated in Figure 58. These include: the

traditional T-type disengager, downturned arms, vented riser, and direct-connected

cyclones or suspended catalyst separation.

157048-1 Equipment Page 101

Downturned arms had essentially replaced T-type disengagers in revamp situations

where the scope did not extend to a change in reactor cyclone design. The

downturned-arm separation device began to replace the traditional T-type

disengager in 1984. Currently, UOP has nine of these designs in operation.

The downturned-arm design offers an increase in separation efficiency compared to

the traditional T-type disengager. The T-type disengager has a separation efficiency

in the range of 70%. Modeling work performed by UOP indicates that the separation

efficiency of the downturned-arm separation device is about 80%. As a result of the

improvement in separation efficiency, a reduction in catalyst loss from the reactor is

observed if the existing cyclones are heavily loaded with catalyst. The reduction in

abrupt changes of catalyst direction has reduced erosion compared to the T-type

disengager.

Figure 58 Reactor Riser Disengaging Devices

157048-1 Equipment Page 102

Vented-riser systems, which use the momentum of the catalyst exiting the riser for

ballistic separation, have been successfully operating for more than 10 years and

are well proven in commercial applications. UOP has 11 vented-riser designs in

operation. On later vented riser designs, no mechanical or erosion problems have

been observed. However, limited erosion has been noticed on units revamped to a

vented-riser when the catalyst flux is high. As a preventative measure, UOP now

recommends additional ¾" (19 mm) abrasion-resistant refractory lining to be

installed in the following areas on vented-riser reactor systems (Figure 59):

The reactor head extending approximately 3 ft beyond the tangent line. The

refractory lining is used to cover a target area on the head of the reactor

where the catalyst impacts directly. The lining is a precaution since erosion

has not been observed in this area.

DA points. Half-pipe shields coated with refractory lining are installed over

the DA points to protect them against erosion.

Manways. Refractory lining is installed in the lower half of the manways in

active areas. The most important site for installation of the refractory is on

the large manway.

TI points. Half-pipe shields coated with refractory lining are installed over the

TI points to protect them against erosion. The thermowells are to be the hard

surfaced type. The control point is moved to the reactor plenum chamber.

The reactor shell above the cone section. A stainless steel taper bar should

be used to terminate the abrasion resistant lining being added. The angle of

this taper bar should be as small as possible. The abrasion resistant lining is

usually extended a minimum distance of 3' (0.9 M) above the reactor cone.

157048-1 Equipment Page 103

Figure 59 Extent of Reactor Cladding and Hex Lining

For Vented Riser Terminations

Direct-connected cyclones are now a well-proven technology. They represented a

continuing evolution toward minimizing counterproductive post-riser residence time

and maximizing separation efficiency.

157048-1 Equipment Page 104

In this design, the combined catalyst and product vapor mixture exits the riser and

passes directly into the riser cyclones for separation. The product vapors exit the

riser cyclone gas tube and pass through a second stage of cyclones before exiting

the reactor. The catalyst flows down the cyclone diplegs into the catalyst stripper.

The vapors carried down the diplegs and the vapors from the catalyst stripper are

swept from the reactor system back into the cyclone system with steam into a vent

tube entering the cross over duct between the cyclone stages.

Because all of the catalyst flows into the cyclones, erosion was concern in the

design of a direct-connected cyclone system. Reports from the operating UOP

direct-connected cyclone systems that have undergone scheduled mechanical

turnarounds indicated only negligible erosion in the riser and cyclone areas.

Because of the transfer piping now incorporated between the primary and

secondary cyclones, the hydrocarbon vapor product and hot catalyst are no longer

in contact with the reactor shell. Consequently, a large thermal differential is

introduced between the reactor internals and the adjacent reactor shell at startup, at

shutdown, and during emergency situations. The mechanical design of the reactor

must accommodate this thermal gradient. UOP's standard design practice is to use

a thermal differential, which is based on the difference between the reactor design

temperature and the steam condensation temperature.

The thermal gradient is not limited to the reactor internals. The reactor riser, reactor

vapor manifold, and reactor vapor line are also subjected to the same thermal

differential. As a result, all guides, supports, and other attachments to the reactor

shell must be designed to accommodate this condition. UOP's experience has been

that all support guides, and sometimes the actual vapor line, require some type of

modification when the direct-connected cyclone system is incorporated into the

design. In summary, the addition of direct-connected cyclones affects the entire

reactor system and is not just limited to the internals.

During the 90's, UOP developed and put into commercial operation the suspended

catalyst separation system which combines the features of the vented riser

(allowing pressure upsets) and direct connect (high containment) systems (see

Figure 60). This system is a two cyclone vented riser which operates with a similar

flow pattern to the direct connect system, but the riser above the first stage is open.

157048-1 Equipment Page 105

The riser fills with a dense zone of catalyst above the inlet to the first stage cyclone

during normal operation, but during a pressure upset the catalyst is free to

discharge harmlessly into the reactor. It was also proven that the suspended

catalyst separation system had the same advantage as the direct connect system;

post riser cracking is minimized because all of the vapor goes to the first stage

cyclone.

Figure 60 Suspended Solids Separation Riser Design

157048-1 Equipment Page 106

The most recent commercially proven riser termination technology developed by

UOP is the Vortex Separation Technology. This includes the Vortex Separation

system (VSS) for internal risers and the Vortex Disengager Stripper (VDS) for

external risers. (see Figures 60 and 61).

The operating principle of the VSS riser termination system is quite simple. Catalyst

is discharged centrifugally in the horizontal plane, swirls downward along the wall of

the chamber, and contacts the prestripping vapors before entering the stripper

vessel. The vapor outlet from the VSS chamber is directly connected to a single

stage of conventional cyclones.

The base of the VSS is submerged in a fluidized dense phase of catalyst in the

reactor cone. The catalyst discharging from the cyclone diplegs easily

communicates with the catalyst level within the VSS chamber to maintain a

controlled catalyst level. Tray and baffle arrangements at the bottom of the VSS

chamber and top of the stripper direct stripped hydrocarbon vapors and stripping

steam rising from the stripper up through the VSS chamber for use as prestripping

media. Any vapors entrained down the cyclone diplegs, along with fluidization

steam, and purge steam flow out of the reactor vessel on pressure balance through

vent nozzles in the VSS outlet duct.

The top of the vessel, the lower section above the stripper and the reactor riser

above the stripper are lined with abrasion resistant lining for erosion protection.

Material of construction is normally 1¼ Cr ½ Mo. The vessel normally operates at

510-530°C (950-990°F). External insulation is required not only for personnel

protection but to prevent excess coke formation. Formation of coke in the reactor

prevents the use of air for heat up during normal startup procedures.

157048-1 Equipment Page 107

Figure 60 Vortex Separation System (VSS)

Dipleg

VortexChamber

Section A-A

InternalRiser

CatalystLevel

VortexChamber

PrestrippingSteam

Spent CatalystStripper

A A

PrestrippingSection

Gas

Catalyst

157048-1 Equipment Page 108

Figure 61 Vortex Disengager Stripper (VDS)

To MainColumn

Riser

Cyclones

VortexDisengager

PrestrippingSection

SpentCatalystStripper

Counter WeightedFlapper Valves

FluffingSteam Ring

FluffingSteam Ring

StrippingSteam Ring

Spent Catalyst ToRegenerator

Plenum

Catalyst ReturnSlots

Gas Flow ToCyclones

Catalyst Flow toStripper

Reactor Shell

SupportBrackets

157048-1 Equipment Page 109

REACTOR RISER

The reactor riser is a vertical pipe in which the desirable cracking reactions take

place. Hot catalyst enters the “wye” section at the bottom of the riser and is lifted up

to the feed injection point by the lift gas/steam mixture. Two wye designs, a hot wall

and a cold wall, have been used. The two wye sections differ in wall temperature

and resulting stresses. The modern cold wall wye with 5" (125 mm) of refractory

lining has a lower wall temperature and reduced stress, permitting the metallurgy to

be changed from 304H stainless steel to carbon steel. The cold wall wye and the

hot wall wye are illustrated in Figures 62 and 63. A mixture of lift gas and steam is

injected through the lift nozzle at the bottom of the wye section. Catalyst and lift

media travel up the riser to the feed distributors where the riser diameter increases.

This increase allows for the increased volume of hydrocarbon vapors as the oil is

injected and vaporized when it meets the catalyst. Because the riser volume is

small it limits the contact time between the catalyst and hydrocarbon. This prevents

overcracking of the products. Below the point where the riser enters the reactor

stripper, the riser is carbon steel with castable refractory lining. This lining is

abrasion resistant and insulates the carbon steel from the high catalyst

temperatures. Above the point at which the riser enters the reactor stripper, the riser

becomes hot wall so the metallurgy is upgraded to typically 1¼ Cr ½ Mo.

157048-1 Equipment Page 110

Figure 62 Cold Wall Wye

Reinforcing Rings

Bumper

Lift Gas Distributor

5” High Density Refractory

Carbon Steel

157048-1 Equipment Page 111

Figure 63 Hot Wall Wye

157048-1 Equipment Page 112

REACTOR RISER FEED DISTRIBUTION

The earliest feed distributors were simple open pipe bayonets located in the base of

the wye section. Figure 64 shows an example of this type. Efforts were then made

to generate some feed dispersion by using multiple nozzles at the exit point of the

distributor. This led to the design of the "showerhead" distributor shown in Figure

65. This change generated a substantial improvement in overall process

performance. Figure 66 shows the effect on cross-sectional temperature profiles in

the riser when changing from a single nozzle bayonet to the multi-nozzle

showerhead design.

In the late 1970's and throughout the 1980's, much emphasis was placed on

atomizing the oil into very fine droplets and evenly dispersing these droplets into the

flowing catalyst. UOP's efforts led to the development of the WYE premix distributor

shown in Figure 67. Steam is injected into the feed upstream of the distributor. The

combined stream is then "pre-mixed" inside the distributor to obtain a pseudo

emulsion phase before it exits the nozzles at the distributor tip. The expanding

steam at exit conditions helps to break up the oil into fine droplets to achieve rapid

vaporization and even mixing with the catalyst.

Further refinements to the wye feed distributor were made by utilizing an annular lift

around the base of the distributor. Either steam or gas can be used as the lift

media. The intent is to provide some pre-acceleration of catalyst around the

distributor before the catalyst is contacted with feed. This serves to reduce the

degree of backmixing in the wye and lower riser. Figure 68 shows a wye premix

distributor with annular lift.

157048-1 Equipment Page 113

Figure 64 Reactor Riser Feed Distributor

Bayonet Type

157048-1 Equipment Page 114

Figure 65 Reactor Riser Feed Distributor

Jet Nozzle Type

157048-1 Equipment Page 115

Figure 66 Effect of Feed Distributor

UOP 3110-9

157048-1 Equipment Page 116

Figure 67 Premix Feed Distributor (Wye)

157048-1 Equipment Page 117

Figure 68 Premix Feed Distributor with Annular Lift (Wye)

157048-1 Equipment Page 118

ELEVATED FEED SYSTEM

During the 1990's, the industry widely accepted that elevated radial injection system

on the riser is the preferred feed injection location. A typical elevated feed injection

system is shown in Figure 69. The wye section, acceleration zone, and mix zone

are the main elements. The term system must be emphasized because the best

result will not be realized without all the parts functioning in the proper manner. The

UOP system has evolved over many years from a combination of strong process

understanding, commercial testing, cold flow modeling, and mathematical modeling.

Acceleration Zone

The base of the wye section is quite turbulent because the huge mass of catalyst

changes direction here. Significant backmixing occurs as the catalyst begins to

move up the riser. Clearly, injecting the feed at this location cannot be desirable.

Restoring an even flow of catalyst is important before injecting the feed. Restoring

an even flow is the function of the acceleration zone.

A carrying gas, either steam, dry gas, or a combination of both, is injected at the

base of the wye. Proper acceleration of the catalyst results in a more even catalyst

flow distribution and a lower slip factor. The slip factor is the ratio of the gas-phase

velocity to the catalyst-particle velocity. The catalyst is always moving at a lower

velocity and “slips” relative to the gas phase. At higher gas-phase velocity, the slip

factor decreases. A riser flow with a high slip factor is a less uniform and more

unstable system. The goal is to minimize backmixing when the feed is injected.

Uneven catalyst flow and high slip in the riser can lead to localized areas of high

temperature and feed overcracking, which result in greater amounts of coke and dry

gas and reduce selectivity to desired products. In addition, lift gas has proven to

passivate metals which further reduces the dry gas yields.

157048-1 Equipment Page 119

Figure 69 Elevated Feed Injection System

UOP 2569B-1

Mix Zone

AccelerationZone

Feed &Steam

Steam or Gas

Catalyst

157048-1 Equipment Page 120

Catalyst Velocity and Density

Computational fluid-solid dynamic modeling work has indicated that the catalyst flow

in the riser can be subject to undesirable slugging phenomena at low velocities.

Increasing the catalyst velocity helps to reduce such slugging and improves the

initial contact with feed. All evidence, both commercial testing and theoretical

principles, confirms that an accelerated, moderate-density catalyst phase is the

ideal environment for feed injection in a flowing riser.

Mix Zone

The last part of the feed distribution system is the mix zone, the point of contact

between the flowing catalyst and injected feed. At this location, the feed is

vaporized rapidly, and cracking reactions begin. This zone is a complex three-phase

system: flowing solids, liquid feed spray, and vaporized gas phase. Rapid and

intimate mixing at this point is critical to achieving the best yield performance. The

number of feed nozzles, location and angle of injection, spray pattern and riser

coverage, and droplet size and velocity are all important parameters that are

optimized to generate the best performance.

A final objective of the mix zone is to achieve a plug-flow environment as quickly as

possible once the catalyst and feed have been mixed. An even distribution of

catalyst and hydrocarbon vapor helps promote and complete the desired reactions

as the mixture flows up the riser. Backmixing of catalyst at the point of contact must

be minimized. Riser gamma scans at this location have helped identify and optimize

the desired flow patterns.

The first generation of elevated feed system used the elevated premix feed

distributor shown in Figure 70.

157048-1 Equipment Page 121

Figure 70 Elevated Riser Premix Feed Distributor

157048-1 Equipment Page 122

Optimix Feed Nozzle

After the elevated premix feed distributors were proven successful, UOP instituted a

program to further improve the atomization and dispersion characteristics of its feed

nozzles. The result of these efforts is the new Optimix feed nozzle (see Figure 71).

The important features of the Optimix nozzle are:

• Small average droplet size • Narrow droplet size distribution • Flat fan spray pattern • Even liquid flux across spray • Moderate pressure drop • Three stages of atomization • Short residence time after internal droplet generation • High turndown efficiency

The Optmix nozzles have been commercially proven in more than twenty units and

major performance benefits with the Optimix nozzle system have been achieved in

dry gas reduction and gasoline yield improvement.

The feature most recently added to the Optimix distributor is the DUR O LOK

coupling. This coupling provides a means for replacing the tips for maximum

flexibility in both maintenance and modification for changes in design charge rate.

157048-1 Equipment Page 123

Figure 71 UOP Optimix Feed Nozzle

Steam

Oil

DUR O LOCTM

Coupling

REACTOR PLENUM

The direct-connected cyclone reactor systems prompted the development of new

reactor plenum designs. In a direct-connected system, the area surrounding the

cyclones is relatively inactive. The traffic in this area is limited primarily to the

vapors being carried out of the reactor stripper. During startups and shutdowns, the

temperatures observed at the reactor shell and cyclones can therefore be

substantially different. To accommodate the large differences in thermal expansion,

new plenum designs were required. Different approaches to this problem are shown

in Figure 72. UOP typically uses an internal plenum design to minimize overall

vessel height and cost.

157048-1 Equipment Page 124

Figure 72 UOP Plenum Chamber Designs

External Plenum Internal Plenum External Manifold

SPENT CATALYST STRIPPER

The spent catalyst stripper (Figure 73) surrounds the upper portion of the reactor

riser. Catalyst descending from the reactor passes into the stripper where it flows

over stripper baffles. The steam to the stripping section is distributed through a

number of small holes in two opposing semi-circular steam rings. A rate of 1.5-2

lb/1000 lb catalyst is typical. The stripping steam displaces oil vapors from the voids

between the catalyst particles and in the catalyst pores and returns this vapor to the

reactor. The catalyst flows out the spent catalyst standpipe with some entrained

steam. A small quantity of steam is injected into the base of the stripper cone

through an additional semi-circular steam ring which maintains catalyst fluidization

and assures an even temperature distribution at this section.

Improved stripping of hydrocarbon from the spent catalyst provides significant

advantages: catalytic coke from higher conversion replaces entrained hydrocarbon

due to the increased catalyst-to-oil ratio resulting from lower regenerator dense bed

157048-1 Equipment Page 125

temperatures. Alternatively, a lower coke yield for the same conversion can be used

to increase throughput on main air blower limited units.

In 1998 and 1999 UOP conducted an extensive research program to evaluate the

existing commercial stripper tray designs and develop a more efficient design. A

commercial scale Plexiglas model was built to allow visual observations of the

catalyst and gas flow patterns. Catalyst circulation rates greater than commercial

flux rates were possible in this model. Helium tracer gas injected to the catalyst

entering the top of the model was used to quantify the stripping efficiency for each

tray type.

The three stripper tray designs which were used commercially in the past by UOP

and tested in the model are shown in Figure 74.

The classic UOP tray, which had 2 rows or large holes on the top of the tray was

used up to the mid 1980’s. The stripper tray style with three rows of holes in the

skirt was used from the mid 1908’s to early 1990’s. In the early 1990’s the jets were

returned to the top of the trays with longer skirts which allowed more pressure drop

across the tray for better steam distribution. Each of these designs perform well at

low to moderate catalyst flux rates, up to ~60,000 lb/hr/ft2 (290 kg/hr/m2). Above

these rates the efficiency falls quickly and fluidization problems can occur which

limit the capacity of the stripper.

The modern tray design developed from the cold flow modeling is shown in Figure

75. This tray uses a larger number of smaller jets on the top of the tray spread out

over a larger percentage of the tray than in previous designs. This provides for

better steam/catalyst contacting resulting in improved stripping efficiency. Another

advantage resulting from this is that all areas of the bed are uniformly fluidized

resulting in smoother catalyst flows and uniform catalyst flux. This improved

fluidization has allowed the upper limits on catalyst flux to be pushed above 100,000

lb/hr/ft2 ( 490,000 kg/hr/m2) while maintaining very high stripping efficiency. The

catalyst flux is based on the annular area between the riser and stripper shell.

157048-1 Equipment Page 126

The modern stripper is also designed for higher catalyst residence times than the

early models. This residence time is important to allow completion of bed cracking

reactions of the absorbed hydrocarbons which continue to generate strippable

vapors that can be removed before the catalyst enters the regenerator. The uniform

catalyst flux in the modern stripper also increases the effective catalyst residence

time by eliminating areas of stagnant catalyst and areas of high catalyst flux.

Figure 73

High Efficiency Spent Catalyst Stripper

StrippingSteam

StrippingSteam

Fluffing Steam

Abrasion ResistantLining

Riser

Stripper Shell

Insulation

FCC-E005

157048-1 Equipment Page 127

Figure 74 Historical Stripper Tray Designs

Classic UOP TrayUp to Mid 1980'sShort skirtHoles on top near the edge

Mid 1980's to Early 1990'sLonger skirtHoles on vertical skirt

Modified Classic UOP TrayEarly 1990's to 1999Long SkirtJets on top near the edge

FCC-E006

157048-1 Equipment Page 128

Figure 75 Modern Stripper Tray Design

C Spent CatalystStripper

L

Detail

12-14 GageTubing

AbrasionResistant Lining

StripperShell

Riser

FCC-E007

157048-1 Equipment Page 129

REFRACTORY LlNING

Refractory lining is used extensively in the reactor and regenerator. The types of

refractories generally fall into three categories: abrasion resistant, insulating, and

castable. Castable refractory lining exhibits both abrasion resistant and insulating

properties. In recent years, abrasion resistant plastic linings have entered the

market. Plastics have become popular for small repair jobs because of their ease of

application. The material is putty-like and comes ready for installation without

addition of water. A listing of the various applications is given in Table 2.

TABLE 2

REFRACTORY LlNING

Abrasion Application Resistant Castable Insulating

Reactor X

Reactor Stripper X

Upper Regenerator X X

Lower Regenerator X X

Standpipes X X

Upper Reactor Riser X

Lower Reactor Riser X X

Cold Wall Wye X

Hot Wall Wye X

Feed Distributor X

Expansion Joint X

Slide Valve X X

Cyclones X

External Mixer X

Flue Gas Line X X

Catalyst Cooler X

157048-1 Equipment Page 130

UOP has made several modifications to the refractory specifications to ensure the

proper use of materials, installation procedures, and inspection and testing

methods. Some of the major revisions to the UOP Standard Specifications include

the following:

The anchor spacing has been reduced from 12” (300) for high density

vibrocast refractory and gunned refractory:

Anchor Location Anchor Spacing

Top head of Vertical Vessels

Plenum Areas

Overhead Areas

1.0 x Lining Thickness

Horizontal Shells

Catalyst Transfer Lines

Overhead Vapor Lines

1.5 x Lining Thickness

Vertical Shells

Bottom Head of Vertical Vessels

Downhand Areas

2.0 x Lining Thickness

The straight-leg anchor design has been replaced with a "steerhorn"-style

anchor. The steerhorn-style anchor provides more positive anchorage and

minimizes slippage.

The coating on the anchor has been reduced to the tip of the leg. Coating on

just the top ½" (13mm) of the anchor leg allows a greater bond and allows

thermal expansion of the tips without spalling the lining on the surface.

Metal reinforcing fibers are incorporated in the refractory. The use of

stainless-steel metal fibers are required to improve the strength of the

refractory lining for cold crushing, modulus of rupture, and thermal shock and

to minimize cracking. The quantity of fibers is minimized (2 lb/ft3 or 32 kg/M3)

to ensure uniform mixing and to reduce handling problems.

157048-1 Equipment Page 131

The heat drying procedure has been modified. The modified procedure is

required to ensure refractory quality by incorporating a controlled, slow heat-

drying rate.

The installation temperatures are controlled to ensure that the lining is not

freezing or being subjected to incomplete hydration.

Mandatory testing of materials is now required to ensure the quality of the

materials and skill of the installers. Materials and installers must pass all

testing requirements prior to installation.

Figure 76

Steerhorn Anchors for Gunned and Vibrocast Refractory Lining

60º

Cap1-1/2” (38 mm)

1”(25 mm)

5/16” (8mm)Diameter Anchor

1/2”(13mm)Radius

Shell Weld

3/8”(9 mm)Radius

157048-1 Equipment Page 132

THERMOWELLS

Reactor thermowells are protected with a hard metal surfacing. The number will

depend upon the size of the unit. The most important temperatures are the riser

outlets for a modern unit, or the dense bed for an older unit. These can be checked

with the reactor over head and stripper bottom outlet thermowells. The catalyst in

the stripper usually is 5-10°F (3-6°C) hotter than the cyclone outlets, because heat

transfer from the catalyst to the oil is not perfect. Thermowells may inadvertently be

placed in a dead area, where false, usually low, readings are obtained. False

readings can be detected by comparing the different readings obtained around the

reactor.

The thermowells used in the regenerator are protected by a stellite hard surface

coating. Wear will vary, depending on location. During the inspection, each

thermowell should be carefully checked and replaced if necessary.

DRY STEAM, DRY AIR and DRY GAS SURGE POINTS

The instrument connections on the reactor and regenerator must be protected from

catalyst damage. The fluidized catalyst will behave like a liquid and "flow" into any

instrument opening. Once the catalyst is out of the fluidized area, it tends to settle

and pack. The instrument tap is blocked off and a false reading given. To avoid this

problem, a stream of dry air, gas or steam is injected into the line between the

vessel and the instrument to provide a buffer seal. This system is shown in Figure

76. It is important to point out that if air is used as the purge gas, its flow should be

minimal to prevent localized burning or harmful oxidation reactions. The amount of

steam injected is controlled by restriction orifices, 1/8" (3mm) for steam and 1/16"

(1.6mm) for air or gas. The pressure to the orifice should be 5 psi (0.35kg/cm2)

higher than the vessel pressure. For differential instruments, there is no error in

measurement because the isolating medium injected is the same for each tap. For

single instruments, any error introduced is negligible.

157048-1 Equipment Page 133

Figure 76 “DA”, “DG” and “DS” Piping

Nozzle on VessleOr Standpipe

3/4 '' Instrument Air for "DA" Points 3/4 '' Purge Gas for "DG" Points

P

Strainer

1/16" RestrictionOrifice

1/2" Pipe to Instrument Provide 6' (1800) or MoreClearance to Enable Use of

Reamer

3/4" SCH 160 PipingMinimum Run StraightPiping Between Fittings

3/4 '' Purge Steam for "DS" Points

FCC-E008

157048-1 Equipment Page 134

During inspection, the pressure taps (and pressure taps used for level indication)

should be cleaned and the surrounding refractory should be checked. The reamer,

shown in Figure 77, can be used to clean out the taps when the unit is on stream,

or when it is down.

Figure 77 Pressure Tap Reamer

FLEXIBLE GRAPHITEPACKING

ROUND HEADSTEEL PLUG

STEEL GLAND

STEEL STUFFING BOX

6'' (150) DIAMETER HANDWHEEL

1/4 '' (6) STEEL ROD

5'-0

'' (1

52

5) 3/4 '' FORGED STEELSCREWED TEE

3/4 '' SCHEDULE 80SEAMLESS STEEL PIPENIPPLE 9'' (230) LONG

1/4 '' (6) DRILL(WELD TO ROD)

3/4 '' NPT (NATIONALSTANDARD PIPETAPER THREAD)(NOTE 2)

FCC-E009

157048-1 Equipment Page 135

MAIN COLUMN

The FCC main column is shown in Figure 78. The column may be divided into two

sections: the regular fractionator and the lower disc and doughnut trays. The bottom

six trays are designed for high vapor and liquid flow rates. The trays are shown

schematically in Figure 79. A coke trap, shown in Figure 80, prevents large pieces

of coke or other debris from entering the bottom line.

The steam ring may be used on some units to steam strip the bottoms material of

any lighter hydrocarbons. The column is fitted with three sample lines which are

normally called try lines; the bottom try line is also used as a sample line. These are

used to check the bottoms level because the level glass and indicator are subject to

occasional plugging by fines or coke particles. Both level instruments are protected

with an LCO flush which flows into the level instrument from the top.

The FCC main column is mounted on a table top instead of the skirt mounting seen

on most columns. Table top mounting simplifies maintenance work on the bottoms

lines, which are subject to plugging from coke or catalyst fines. A separate suction

line to each pump allows operation to continue through one line while the other is

cleaned. As an additional note, every valve in the bottoms circuit should be installed

with the stem up to keep catalyst fines out of the bonnet. If plant layout does not

allow a stem to be straight up, it should be as close to the vertical position as

possible.

The upper part of the tower is similar to any other fractionator. Sidecut streams

must be stripped to remove absorbed light material. Stacked heavy cat naphtha and

light cycle oil strippers are shown in Figure 81. Steam is the most common

stripping method, although reboiler strippers are sometimes used. Reboiler

strippers decrease the amount of sour water that must be treated. The overhead

vent from each stripper returns to the main column in a vapor space.

157048-1 Equipment Page 136

The overhead from the column is condensed by air or water coolers, normally a

combination of the two. Water from the gas concentration section washes the

ammonia and some other salts from the last bank of condensers. If it were injected

before this, much of the water could vaporize, decreasing its effect. The sour water

is separated in the overhead receiver (see Figure 82) and sent to a sour water

stripper. Gasoline and gas go to the gas concentration section, with some gasoline

returned to the tower for reflux.

The main column is made of regular or killed carbon steel, with a 1/8 inch (3 mm)

thick Type 405 or 410 (12 Cr) cladding from below the naphtha or LCO draw tray to

the bottom outlet. Any nozzles or manways in this clad section should also be alloy

lined. All the trays and caps in the column are Type 410 stainless. The inspector

should look for any evidence of pitting, cracks or bulging in the alloy lining. Metal

thickness should be checked and recorded for future reference. A general

inspection should be made for loose caps, clips and bolts, and for general metal

loss or tray distortion. The upper part of the column is usually not subject to severe

corrosion. The bottom of the column should be checked for integrity of the lining

and for any signs of coke buildup. Excess amounts of coke may indicate that the

bottoms temperature was too high during operation. The coke trap and steam ring

should be cleaned and checked for corrosion. The steam ring should have the

nozzles pointing upward, to avoid erosion to the bottom head lining.

157048-1 Equipment Page 137

Figure 78 Main Column

26

27

30

32

37

34

35

38

36

33

17

21

19

18

7

6

4

3

1

31

29

28

5

20

Reflux

Manway andVentVapor Out

HCN LiquidReturn

HCN StripperVapor Return

HCN RefluxDraw

HCN Pumparoundand Product Draw

HCN RefluxReturn

LCO PumparoundReturn

LCO RefluxDraw

LCO Pumparoundand Product Draw

LCO StripperVapor Return

LCO RefluxReturn

HCO PumparoundReturn

Feed Surge DrumEqualizing Line

HCO Pumparoundand Reflux Draw

HCO Reflux Return

MCB PumparoundReturn

Reactor Vapor Inlet

Try Lines

Coke Trap

Steam OutQuench

Bottoms Pumaparoundand Product Draw

410S or 405cladding

FCC-E400

157048-1 Equipment Page 138

Figure 79 Typical Disc and Donut Pans

VESSEL

VESSEL

OPEN AREA

PLAN OF DISCNO HOLES AT FEED POINTS

C

VESSEL

VESSEL

OPEN AREA

C

C

*

*

SECTION A-A

SUPPORT

RING

VESSELC

SYMMETRICAL

ABOUT CENTERLINE

AA

OMIT HOLES FOR

TOP DONUT ONLY

DOWNCOMER

OF TRAY

SUPPORT

RING

1-3/8" DIAMETER HOLES

ON 5" EQUILATERAL

TRIANGULAR PITCH1-3/8" DIAMETER HOLES

ON 2-1/2" EQUILATERAL

TRIANGULAR PITCH

4" HIGH WEIR FOR

TOP DONUT ONLY

TRAY

1-3/8" DIAMETER HOLES

ON 5" EQUILATERAL

TRIANGULAR PITCH

1-3/8" DIAMETER HOLES

ON 2-1/2" EQUILATERAL

TRIANGULAR PITCH

C

PLAN OF DONUT

DONUT TRAY

DISC TRAY

FCC-E401

157048-1 Equipment Page 139

Figure 80 Typical Coke Trap

12015

0

50 (TYPICAL)

SUPPORTS

150

100

25 R

(BOTTOMS OUT)

OPENINGS

40

PROVIDE 2 DRAIN

OPENINGS, LOCATED

180 DEG APART. OD OUTLET NOZZLE

FCC-E402

157048-1 Equipment Page 140

Figure 81 Heavy Cat Naphtha Stripper (Top) Light Cycle Oil Stripper (Bottom)

BAFFLE

1

6

Vortex Breaker

1

6

Manway and Vent

Vapor to Main Column

HCN from Main Column

Stripping Steam

LC-LG

Vapor to Main Column

Vent

Stripped HCN Product

LCO from Main Column

Stripping Steam

Vortex Breaker

LC-LG

Stripped LCO Product

FCC-E403

157048-1 Equipment Page 141

Figure 82

Main Column Overhead Receiver

Inlet Distributor(Detail)

PC LC & LG

LC & LGWater

Vent and Ventilation

Vapor Outlet

Water Boot

Water Outlet

HydrocarbonOutlet

Vortex Breakers

Manway

Steam Out

Slots Must FaceNearest Head

1/2" Drain HoleFCC-E404

157048-1 Equipment Page 142

MAIN COLUMN BOTTOMS

The main column bottoms pumps are detailed in Figure 83. The minimum

distances shown are important to prevent catalyst fines from settling in a line that is

not in service and plugging it. The draw stream for heavy oil out of the unit (i.e. to

the slurry settler or storage) always comes off the bottom of the main column

bottoms header. Any catalyst or coke which has a tendency to settle will be drawn

off and removed from the circulating loop. Steam and LCO lines are provided for

flushing on shutdown and for cleaning. If the unit is shut down without flushing,

catalyst fines may settle, or the heavy oil may set up causing problems with

cleaning.

The suction and discharge lines of the main column bottoms pumps range from 5

Cr, ½ Mo to 9 Cr, 1 Moly. The exchanger metallurgy ranges from carbon steel to 5

Cr, ½ Mo. Carbon steel does not last long if it is exposed to hot main column

bottoms so the slurry service side of the tubes, tube sheets, and heads should be

clad with a chrome alloy, such as Type 410. After the first exchanger, most of the

piping is carbon steel. All piping and exchangers should be inspected for corrosion

and fouling at each turnaround, and the appropriate records kept.

The recommended main column bottoms velocities through the tubes are 3.75 to

7.0 ft/sec for straight tubes and 3.75 to 5.75 ft/sec for U-tubes. Deviations outside of

these ranges will show up as excessive amounts of settled catalyst fines or erosion

to the tubes.

The main column bottoms pumps normally have steam turbine drivers. Speed is

limited to 2000 rpm to minimize erosion. The shaft is tungsten carbide or stellite

coated, with a light cycle oil flush to the throat bushing and wear rings and HCO to

the mechanical seal. UOP recommends aluminum foil packing with light cycle oil

flush for cooling and lubrication. Graphite or asbestos have occasionally been used

in this service. Many refiners have installed mechanical seals with good success.

157048-1 Equipment Page 143

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405

157048-1 Equipment Page 144

Besides the turnaround, the bottoms pumps usually require some repair work

during the course of the run. The seal flush system should be checked for

cleanliness, and the packing replaced if necessary. The packing is especially

vulnerable to the hot, erosive conditions. There may also be wear to the pump case

and rotor. If this is severe, a hard surfacing material may be applied to the rotor.

The inspector should also check the pump suction strainer for corrosion and holes.

SEAL AND GLAND FLUSH

The main column bottoms pump is protected by gland and seal flushes to keep

catalyst fines out of the throat and to lubricate and cool the packing. HCO is used

as the flushing medium. LCO is not used as a flush to the main column bottoms

pumps because suction will be lost when vapors are formed in the pump casing.

For earlier units, all main column bottoms and slurry flow instruments and control

valves are flushed with LCO to keep out fines that could plug up or erode the

equipment. The total amount of LCO required will depend on the number of flushing

points. The flush to each instrument will not be exactly the same because of the

pressure drops through the system, although this can be partially balanced by the

globe valve provided at such point. The primary control is a 1/16 inch (1.6 mm)

restriction orifice after the globe valve. These orifices must be kept clean. A rough

number for total LCO required is 1000-2000 BPD (6.5-13 M3/hr). Smaller units

usually have fewer exchangers and, therefore, require fewer control valves and less

oil. The LCO which enters the main column bottoms stream will flash off when it is

returned to the column. Excessive flush will cause cooling problems in the bottoms,

and should be avoided.

Currently, UOP designs slurry flow instruments which do not use flushing as shown

in Figure 84.

157048-1 Equipment Page 145

Figure 84 Slurry Service Orifice Meter Piping Assembly Closed Coupled Above Orifice for ANSI Class 300/600

¼" Globe

½" Gate(Install on Vertical Tap)

Screwed Cap(do not seal

weld)

¼"

Pipeminimum

Transmitter MountingBracket

SingleValve

EqualizingManifold

2" Field FabricatedInstrument Pipe

Support

½" Pipe

½" Solid Plug

min

imu

m

Pipe Strap

Flow

Flange Adapters

PCapsule

HL

FCC-E406

157048-1 Equipment Page 146

SLURRY SETTLER

In earlier units when the cyclone efficiency was not as high, the main column

bottoms stream contained catalyst fines which had to be removed to meet certain

product specifications. Part of the bottoms stream was sent to the carbon steel

settler (sometimes called a clarifier) where the fines would settle out and were

returned to the reactor with a slurry recycle. Clarified oil came off the top of the

vessel. The settler operated liquid full, with a cross-sectional area designed for an

upward oil velocity of 30 BPD/ft2 (2.1 M3/hr/M2) or less at normal charge rates.

Heavy cycle oil or raw oil diluent could be used to flush the fines back to the reactor.

Figure 85 FCC Slurry Settler

UOP 2119-67

VentRelief Valve

Manway

Dilute OilInlet and

Distributor

Main ColumnBottoms InletNozzle andWear Plate

Clarified Oil Outlet

Steamout

Slurry Outlet

FlushingNozzle

157048-1 Equipment Page 147

SLURRY FILTRATION

Filtration of the slurry product to achieve product specifications of 100 wppm total

solids or lower is becoming increasingly common. Sales of the slurry product as

carbon black feedstock and desire to minimize the increasing cost of tank cleaning

are driving this trend.

The most common type of filters use pourous, sintered metal filter elements. A

typical filter system will have 2 or 3 vessels with a number of filter elements in each.

One vessel is typically in filtration mode while another is in backflush mode to

remove the filter cake from the elements. When enough catalyst fines have

deposited on the filter elements to increase the pressure drop across the filter to a

pre set limit the vessel is taken off line for back flushing. Once the filter vessel is off

line and drained the vessel is filled with backflush liquid, either HCO or LCO, and

allowed to soak to help dissolve any heavy aromatic compounds on the elements.

The top of the vessel is then pressured up with either fuel gas or nitrogen to provide

the driving force for a high velocity back flush. The back flush material is collected in

receiver vessel and pumped back to the reactor riser or to the spent catalyst

stripper. A typical arrangement for the filtration equipment is shown in Figure 86.

157048-1 Equipment Page 148

Figure 86 FCC Slurry Filter

FILTERVESSEL

#1

FILTERVESSEL

#2

FILTERVESSEL

#3

BACKFLUSHRECEIVER

VENT

BACKFLUSHTO

REACTOR

BACKFLUSHGAS

BACKFLUSH GASACCUMULATOR

SLURRYIN

HCO orLCO

SOAK IN

CLEANPRODUCT

OUT

FCC-E407

157048-1 Equipment Page 149

GAS CONCENTRATION SECTION

The gas concentration unit is relatively easy to operate and usually trouble free. It

may be forgotten in the planning for the turnaround. This can prove to be a serious

mistake because the vessels and lines are sometimes subject to severe corrosion.

The amount and type of corrosion will depend on the feedstock, vessel metallurgy,

and the methods used to combat this corrosion

Corrosion in this unit can be broken down into three classifications:

1. Hydrogen blistering and/or embrittlement.

2. Corrosion of steel by hydrogen sulfide, cyanides, and other acids.

3. Ammonia attack on Admiralty tubes.

The first of these, hydrogen blistering, is the most common problem with general

metal attack by the various acids a close second. Hydrogen blistering occurs in

steel where surface corrosion is active. Blisters are formed by the diffusion of

atomic hydrogen into steel and then accumulate at slag or inclusions within dirty

steel. The atomic hydrogen then converts into molecular hydrogen, and the

resultant pressure forms the blister. Blisters may rupture to the thin side of the

defect. The presence of cyanides (Prussian blue) greatly increases susceptibility of

H2 blistering in steel. The inspector should look for a bluish color when the plant is

first opened, because this is a good indication of areas where corrosion and/or H2

blistering may be found. Hydrogen sulfide (H2S) also contributes to blistering and

corrosion; it is present in most gas concentration units. The inspector should look

for H2S pitting, blisters, and general metal loss. Inspection of the equipment should

be thorough, and when corrosion is found, the type and extent of the corroded

areas should be determined. It is not unusual to find one head or one particular

plate in a vessel full of blisters, with the remaining portion of the vessel in good

condition. Repairs can be made by replacing the damaged areas and still maintain

the equipment in service.

157048-1 Equipment Page 150

Ammonia attack on Admiralty tubes in the condensers or coolers is not severe if

there is sufficient wash water during operation. Stress corrosion of brass tubes may

be seen in exchangers where the pH is high. Galvanic corrosion and dezincification

of brass tubes may be found where dissimilar metals are used in the condensers or

coolers. Water side erosion or corrosion of the tubes may occur if dirty or

contaminated water is used. This could be caused by suspended solids, or if there

were salts or other chemical species, for which the exchanger was not designed.

The type and amount of problems will vary between refineries. It may even change

over a period of time for one unit, as feed or cooling water quality changes. Every

turnaround a good inspection should be made with precise records on each piece of

equipment. Previous records should be available, and corrosion rates determined

each time. Changes of materials in bundles or shells, should be considered if

exchanger life is too short.

Gas plants are usually easy to gas free and open for inspection. Some units that

have been coated with an epoxy type paint cannot be subjected to steam for gas

purging. These items must use water or inert gas to clean for entry, which makes

the job more difficult. Knowledge of protective coatings and locations is a must for

the refinery safety and inspection departments. Operations supervisors should have

written orders for each piece of equipment which detail the correct procedures to

follow in flushing and opening these items.

Admiralty tube bundles should be handled in special slings to eliminate over-

stressing and potential stress cracking of the tubes at the lifting areas. Good

supervision of opening and removing of equipment is critical in this unit.

The inspector should follow the flow from the low and high pressure receivers to the

final condensers. Corrosion found in any item should be followed to the next item in

the flow pattern to determine the extent and area the corrosion has covered.

Because there is a certain amount of crossover flow, such as wash water from the

HPS to the MC overhead, there may be some backtracking. The corrosion

products, such as iron sulfide scale, will not necessarily be in the same area as the

most severe corrosion. Should hydrogen blistering be found, the blisters should be

measured, drilled if necessary with air drills, and the ruptured metal should be

measured to determine if the corrosion allowance has been exceeded. If blisters are

small, ½" (13mm) or less, they can be covered with a protective lining to eliminate

157048-1 Equipment Page 151

future growth. Corrosion allowance in the blistered areas should be maintained if

possible. General corrosion, such as H2S pitting, may require replacement of all or

part of a vessel or line. Scabbing is usually not effective, but can be used if time is

short and if the scabbing is done well.

If repairs are not made, the item should be programmed for the next turnaround as

necessary work. Various metal corrosion test samples can be installed in the

corroded area to determine the best material to be used to resist the corrosion.

Hydrogen probes, electrical resistance corrosion probes, and corrosion coupons

can be used to indicate the rate and severity of corrosion activity during the run. On-

stream inspection of piping can also be used to monitor present problems and to

find areas that should be checked carefully or shutdown.

If corrosion or blistering is found, there is usually a question concerning

replacement with a higher quality material. All equipment eventually wears out; it is

a matter of comparing cost with possible benefits. Replacement of trays and other

tower internals is easier than replacing the vessel shell. If the refiner feels that the

equipment is wearing out too quickly, then a higher alloy may be justified. Before

the decision is made, a careful investigation should be conducted to determine

other ways of resisting corrosion. For the FCC gas concentration section, the best

method to resist corrosion is to maintain the wash water injection at a rate of 6.5-7.0

vol.% of the feed. This has greatly limited or eliminated corrosion in most cases.

Inhibitors have been used in some cases, but they are usually not necessary.

Most of the material used in the gas concentration section is carbon steel. Killed

steel is common for towers and the upper trays in the absorbers. The debutanizer

reboiler is very often 5% chrome, ½% moly steel. A lower alloy steel, such as

1¼% chrome, ½% moly, may be used in areas that have had corrosion problems.

In severe cases, the affected area may be lined with a 12% chrome, such as Type

405 or 410. The compressor rotor is usually a specially tempered 1¼% chrome,

½% moly steel.

157048-1 Equipment Page 152

WET GAS COMPRESSOR

The compressor of an FCC unit separates the relatively low pressure of the main

column from the higher pressure gas concentration and recovery section. Positive

displacement reciprocating or centrifugal machines can be used; the latter have

become more common because of better performance at lower cost.

During the turnaround, thickness measurements of piping headers and manifolds

should be made each down period and compared to previous readings. Severe

corrosion may be found in the discharge manifolds and piping to the receivers. The

manufacturer's instructions should be followed for the gas compressor inspection.

This machine normally requires maintenance work on the seals or packing.

CENTRIFUGAL MACHINES

Centrifugal compressors (Figure 87) are multi-stage machines, contained within the

two external stages. Each of the two stages is protected by an anti-surge device

which will over-ride normal controls to protect the machine. Gas leakage out of the

casing is prevented by suction and discharge end labyrinth seals. These seals are

backed by either buffer gas or seal oil, normally oil. The seal oil system runs 5 psi

above suction gas pressure, using a seal oil head tank or differential pressure

controller to hold this differential pressure even if suction pressure varies

somewhat. A balancing drum is used to offset axial thrust, so suction pressure is

maintained at both ends of the compressor. The seal oil system must be kept in

operation while the casing is under pressure or gas will leak out.

157048-1 Equipment Page 153

Figure 87 Centrifugal Compressor

FCC/DS-R00-45

157048-1 Equipment Page 154

RECIPROCATING MACHINES

Reciprocating compressors can be driven by gas engines, turbines, or electric

motors. They are usually constant speed machines. Suction valve unloaders and

clearance pockets are provided on some machines for greater operating flexibility.

A reciprocating machine should never be run with discharge valves blocked in.

Liquid slugging is also very dangerous, as the liquid is incompressible and will lead

to broken piston rods or a cracked head. Suction knockout drums should be

checked frequently for any liquid.

The reciprocating machine uses packing to prevent gas leakage from the

compressor. This simple system should work quite well as long as the packing is

tightened correctly. Over tightening will lead to excess wear and then leakage.

157048-1 Equipment Page 155

FIRST AND INTERSTAGE SUCTION DRUMS

These vessels are designed to remove any liquid from the gas streams to the

compressor. They are normally carbon or killed steel, with a stainless steel mesh

blanket to remove any entrained droplets. The first stage liquid is drained to a

blowcase, and pressured back to the overhead receiver. The liquid from the

interstage drum is pumped to the HPS. A typical drum is shown in Figure 88. Pitting

corrosion has been found in the lower portion of the shell and bottom head.

Hydrogen blistering and embrittlement has also been found.

Figure 88 Compressor Suction Drum

Mesh Blanket(Demister Pad)

Ventilation andVent Nozzles

Gas Out

Gas Inlet withDistributor

LC-LG

Steamout

Liquid Out

Vortex breaker

Manway

FCC-E700

157048-1 Equipment Page 156

WASH WATER

The overhead stream from the main column contains various contaminants which

may cause corrosion, plugging, or fouling. These would include ammonia, sulfides,

cyanides, chlorides, and phenols. A wash water stream is used to remove them,

because most of them are ionic or polar species, readily soluble in water. Flow rates

are usually maintained at 6-7 vol% of the fresh feed rate.

The water should be clean, preferably steam condensate, to prevent adding more

problems such as salts or dissolved oxygen to the system. The water is injected

after the compressor first stage and is pumped out of the interstage suction drum to

the HPS. Here it collects in a water boot and is pressured back to the main column

overhead condensers. It collects in the overhead receiver water boot and is pumped

out to the sour water stripper for disposal.

There is always water present in the main column and gas concentration section

from stripping steam and other sources. If the wash water is not used to flush out

the sulfides, ammonia, cyanides, and other species, the water present can become

highly corrosive from absorption of these contaminants. Sulfide levels of greater

than 20,000 ppm have been reported in the overhead receiver water. Hydrogen

blistering and general corrosive attack may become quite severe, especially if feed

sulfur is greater than 1%, or nitrogen greater than 1000 ppm. Also, while the

overhead receiver water may be basic, pH >7, most of the ammonia that is

responsible for this will drop out in the main column receiver.

The water in the gas concentration section may become acidic from H2S and CN-. If

there is any oxygen present, elemental sulfur may be formed from oxidation of the

sulfides. This will cause problems in meeting gasoline product specifications. Wash

water will solve many of these problems by diluting the corrosives, and keeping the

water pH at 8-9, where sulfide oxidation is greatly reduced.

157048-1 Equipment Page 157

HIGH PRESSURE SEPARATOR

The HPS Figure 89 receives the liquid streams from the interstage suction drum

and primary absorber bottoms, and the gas streams from the second stage

compressor discharge and the stripper overhead. The vessel is carbon or killed

steel; it looks very similar to the main column overhead receiver shown in Figure

82, with a slotted pipe distributor instead of a baffled inlet. Sour water is pressured

from the boot to the main column overhead, while gasoline is pumped to the

stripper. The gas goes to the primary absorber. Pitting corrosion has been found in

the lower section. Hydrogen blistering and embrittlement has also been found.

Figure 89 High Pressure Separator

Slotted PipeDistributor

Inlet Pressure Relief

Manway

Steam Out

PI & PC LI & LCVentilationand Vent

Vapor Out

Liquid Out

VortexBreaker

LI & LC

Water Boot

Water Out

FCC-E701

157048-1 Equipment Page 158

PRIMARY ABSORBER

The primary absorber (Figure 90)is a killed steel column with about 30-40 trays.

The trays are normally carbon steel with Type 410 stainless steel fittings. Valuable

light products such as LPG are absorbed from the gas as it travels from the bottom

to the top outlet. The most common tower design uses two intercoolers to remove

the heat of gas absorption from the gasoline as it fails down the tower. This

temperature rise is roughly 20-25°F (11-14°C). These intercoolers are located

roughly one-third and two-thirds of the way down the tower. The gasoline circulation

through the water coolers may be pumped or gravity driven. Water drain pots are

required on the gravity circulation systems to prevent accumulation of water as the

gasoline cools; a water head would stop gasoline circulation. Pumped systems are

better from a velocity, and thus heat transfer, viewpoint.

Another design that has become popular recently uses debutanized FCC gasoline

as a final wash before the gas leaves the tower. A cooled slipstream from the

bottom of the debutanizer is introduced at the top of the column, with the gasoline

from the main column overhead receiver entering the tower 5 to 7 trays lower. This

system allows the use of only one intercooler with the same or better C3 recovery

efficiency, i.e., the amount of C3 recovered in the debutanizer overhead compared

to the total amount produced. The gasoline from the bottom of the primary absorber

is pumped to the HPS; the gas flows to the sponge absorber.

Serious corrosion can occur in this column from H2 attack. Hydrogen blistering can

be severe in the upper section and top head, and is also seen occasionally in the

middle of the tower and in the intercoolers. The shell and heads should be

inspected at each turnaround. The inspection of the internals should pay particular

attention to stagnant areas around weirs, downcomers, and nozzle extensions.

Bolts and trays should be inspected for tightness and embrittlement of materials.

157048-1 Equipment Page 159

Figure 90 Primary Absorber

1

Distributor8

9

12

13

14

26

27

28

40

DistributorRecycle Gasoline Inlet

Vent and VentilationVapor Outlet

Manway

Upper Inter Cooler Return

Lower Inter Cooler Return

Upper Inter Cooler Draw

Lower Inter Cooler Draw

Vapor InletLC & LG

Liquid Outlet

FCC-E702

UnstabilizedGasoline Inlet

157048-1 Equipment Page 160

SPONGE ABSORBER

The sponge absorber (Figure 91) is a "guard" tower which uses LCO to absorb any

remaining liquid from the gas. If any significant quantities of C5 or C6 remain in the

gas stream, these will cause problems with treating. If the gas is sent directly to the

fuel system, condensation of heavy material is dangerous.

The sponge absorber is fabricated with killed steel. It used to be designed with 25

carbon steel trays; the tray fittings were Type 410 stainless. Currently, UOP designs

all sponge absorbers with packing towers which minimizes the risk of foaming. A

mesh blanket, Type 304 stainless, is installed at the top of the absorber to trap any

entrained liquid.

The gas leaves the tower on pressure control. Absorption LCO is flow controlled,

with a lean oil/rich oil exchanger to heat the rich sponge oil as it leaves the

absorber. This decreases the temperature effects when the LCO is returned to the

main column. The lean oil is water cooled after it leaves the rich oil exchanger, to

100°F (38°C) maximum.

The inspector of the tower should follow the same pattern of inspection as the

primary absorber. The sponge absorber is subject to corrosion and hydrogen

blistering, but usually somewhat less than the primary.

157048-1 Equipment Page 161

Figure 91 Sponge Absorber

Pre-Distributor

Manway

Vapor Inlet

Steam Out

Liquid Out

Re-Distributor

Hold Down Grid

Mesh Blanket

Vapor OutletVent and Ventilation

Bed Support

LC-LG

FCC-E703

157048-1 Equipment Page 162

STRIPPER

The stripper (Figure 92) removes light hydrocarbons and H2S from the gasoline. A

LCO reboiler is used to heat the tower and to preheat the gasoline feed. The off-gas

goes to the HPS; an FRC in the gas line controls the LCO to the reboiler.

The stripper is made of killed carbon steel with about 30-40 carbon steel trays. Tray

fittings are Type 410 stainless. Some units have experienced high corrosion rates in

the stripper. The reboiler is usually carbon steel, but may be 5% Cr ½% Mo in

cases where severe corrosion has occurred. This corrosion is not common and can

usually be corrected without the additional expense of a chrome reboiler. Inhibitor

has been used in some cases, but this protection can be lost with unstable

operating conditions. The inspector should check metal thickness and the reboiler

should be checked for unusual wear during the turnaround.

157048-1 Equipment Page 163

Figure 92 Stripper

1

18

19

36

Vent and Ventilation

Vapor Outlet

Liquid Inlet

Distributor

Manway

LC & LG

Reboiler Return

Reboiler Draw Off Well

Liquid Out to Reboiler

Steam Out

Liquid Out

Vortex Breaker

FCC-E704

157048-1 Equipment Page 164

DEBUTANIZER

The stripped gasoline is pressured to the debutanizer for vapor pressure

adjustment. The LPG product after treating can be used for fuel or further

processed for petrochemicals. The gasoline product usually requires treatment for

sulfur, and the addition of inhibitors for better stability.

The most common method of pressure control is a hot vapor bypass around the

overhead condenser. The reflux back to the tower is temperature controlled by a

TRC device located on the fourth tray from the top. This scheme gives a better split

than overhead temperature control. Heat is supplied by a HCO reboiler,

occasionally supplemented by a main column bottoms reboiler. Hot fluid to the

reboiler tubes is FRC controlled. Insufficient heat will not give good fractionation,

too much heat will flood the tower.

The debutanizer (Figure 93) is killed steel with 35-40 carbon steel trays. Tray

fittings are Type 410 stainless. The overhead system is usually carbon steel, with

inhibited Admiralty tubes in the water condenser. The shell of the reboiler is carbon

steel; the tubes, tube sheet and floating head cover are 5% Cr ½% Mo. Carbon

steel clad with Type 410 stainless may be used instead of 5% Cr. Hot fluid flow is

through the tubes. This vessel and associated piping are occasionally subject to

severe corrosion and hydrogen blistering. The best solution to this and to the

corrosion problems of the other vessels is water injection at the interstage receiver.

As mentioned above, some refiners have also used alloy steel or monel instead of

carbon steel for severe cases of corrosion in the debutanizer.

157048-1 Equipment Page 165

Figure 93 Debutanizer

1

7

8

19

20

35

36

40

Vent andVentilation

Vapor Outlet

Reflux

TIC

StripperBottoms

Inlet

Manway

ReboilerReturn

Manway

Steam Out

Liquid Out toReboiler and

Product

LC & LG

Vortex Breaker

FCC-E705

157048-1 Equipment Page 166

CORROSION

Steel Corrosion

It has been established that steel corrosion, hydrogen blistering, and weld cracking

problems come from a water, hydrogen sulfide, ammonia, and/or cyanide

environment. The overall corrosion reaction for steel is:

Fe° + 2HS- = FeS + S-2 + 2H° (1)

The amount of bisulfide ion (HS-) formed depends on the pH, temperature, and

hydrogen sulfide (H2S) partial pressure and comes from the H2S dissociation:

H2S = H+ + HS- (2)

The iron sulfide (FeS) scale provides some protection against corrosion if the

system pH is about 8. However, dissolved hydrogen cyanide (HCN) accelerates

corrosion by destroying the protective FeS film and converting it into soluble

ferrocyanide complexes:

FeS + 6CN- = Fe(CN)6-2 + S-2 (3)

The ferrocyanide (Fe(CN)6-4) is easily recognized by its blue color (Prussian blue)

when water samples are allowed to dry.

Hydrogen Blistering

Some portion of the hydrogen atoms formed in the corrosion process (Equation 1)

gradually penetrates the steel through surface imperfections and diffuse into the

steel as atomic hydrogen. This diffusing hydrogen reacts to form molecular

hydrogen:

2H° = H2

157048-1 Equipment Page 167

The hydrogen molecules are larger in size and are trapped in the steel cavities

causing local pressure to build up. The result is blistering and fissures in the metal.

High quality killed carbon steel usually has less inclusions today than in earlier

times, and blistering is usually less of a problem than before.

Water Wash

Most refiners feel that wash water is adequate for cyanide control. Hydrogen

blistering has not been a problem in most of the FCC Gas Concentration units.

Cyanide is effectively kept out of the Gas Concentration Unit through the use of an

adequate wash to the Main Column overhead receiver and to the wet gas

compressor Interstage suction drum. An effective water wash dilutes and scrubs the

corrosive species such as hydrogen sulfide, ammonia, chlorides, and cyanides from

the FCC light hydrocarbon streams.

As stated previously, the water wash rate should be at least 6-7 Vol% on fresh feed

to the FCC Unit. There should be no entrainment of water from the overhead

receiver to the primary absorber column. Recommended water wash sources

include oxygen free water, steam condensate, and boiler feed water before

alkalinity adjustment. If the wash water contains oxygen, gum formation will

increase and wet gas compressor fouling may occur. If the wash water contains

magnesium or calcium salts, these components will precipitate increasing the

fouling problems. Also, if oxygen is present, elemental sulfur may be formed

causing copper strip corrosion in the gasoline.

Condensate pH

Overhead streams in the fractionator and gas concentration section consist mainly

of hydrocarbon vapors, steam, and relatively small amounts of contaminants.

During condensation, the water phase absorbs some of the contaminants and can

become highly corrosive. The FCC Process condensate develops a pH of 7 to 9

because of the higher concentration of ammonia relative to the acid contaminants

and because ammonia is more soluble in water than hydrogen sulfide or hydrogen

cyanide.

157048-1 Equipment Page 168

It is recommended to maintain the pH of the condensate in the range of 8.0 - 8.5 to

prevent elemental sulfur formation and reduce the corrosion rate. Polysulfide can

decompose at a pH below 7.8 forming H2S and free S. This will cause the gasoline

to be corrosive. The pH measurement of the high pressure separator and main

column overhead receiver water must be made at site with portable pH meters. The

pH of a water sample can change as much as 2 pH units if the sample is taken to

the laboratory.

Polysulfide Injection

Some Refiners who are processing feed with high nitrogen content and have high

cyanide concentrations in the Unit are using ammonium polysulfide to reduce the

overall corrosion rate. The ammonium polysulfide is an additive that converts

cyanides to thiocyanates by the reaction:

(NH4) 2S3 + HCN = NH4SCN + S2-2

The refiner should monitor the Gas Concentration Unit carefully when injecting

polysulfide, since these compounds could sometimes cause more problems than

benefits. The following are some disadvantages of the ammonium polysulfide:

1) The pH of the system should be higher than 8.0. At lower pH values the

polysulfide decomposes into ammonia (NH3), hydrogen sulfide (H2S), and

elemental sulfur (S°). The H2S will increase the corrosion rate and the

elemental sulfur (S°) will give corrosive gasoline and equipment plugging

problems.

2) The polysulfide will commence salting out at temperatures below 38°F and

plug pump suction and discharge lines.

3) The polysulfide will decompose at temperatures close to 250°F producing H2S,

NH3, and S°. As stated previously, the H2S will increase the corrosion rate and

the S° will give corrosive gasoline and equipment plugging problems.

157048-1 Equipment Page 169

4) An excess of 10 to 15 ppm of polysulfide over the stoichiometric amount of

cyanide is desired. If over 30 ppm is present, there will be enough found in the

sour water stripper bottoms to give problems in the effluent treating. Upon

neutralization the (NH4)2S3 decomposes into NH3, H2S, and S°. This can result

in bacterial kill in biotreating and equipment plugging.

5) Wash water requirements are generally higher to assure that the polysulfide

stays in solution. If the polysulfide does not stay in solution equipment plugging

will increase. Also, processing the additional sour water can be costly.

157048 Fluidized Solids

Page 1

FLUIDIZED SOLIDS

Introduction

A fluidized bed is formed by passing a gas upwards through a bed of solid particles. If the gas velocity (U) is above a minimum gas velocity, Umf, the solids become

fluidized and the mixture behaves like a liquid.

Figure 1 Fluidized Beds Behave Like a Liquid

No Flow Flow

U Umf U Umf

157048 Fluidized Solids

Page 2

A fluidized catalyst bed provides a number of key processing advantages.

Fluidization facilitates the transfer of catalyst, which permits the continuous

reaction/regeneration cycle of the FCC unit. Catalyst addition and removal is easy,

simplifying catalyst management. High mass and heat transfer in a fluidized bed

allow for efficient operation. For a given material and gas velocity, pressure drop is

lower in fluidized beds than in fixed catalyst beds. These characteristics make the

fluidized bed an attractive choice as a chemical or physical processing tool.

Fluidized Bed Theory

An unfluidized bed of catalyst is referred to as a fixed bed. The catalyst particles are

in close contact with each other and contain void spaces. The voids are due to the

spherical shape of the catalyst and the efficiency with which spheres can be

packed. By introducing a fluidization medium – air, hydrocarbon vapor, or steam –

the catalyst can be made to behave like a liquid. Once fluidized, the catalyst will

assume a level surface and exert a pressure profile similar to that of a liquid. In this

state, the catalyst can be made to flow through a pipe as in the case of the

standpipes and reactor riser. In essence, it is a liquid stream. It is this principle

which permits circulation of catalyst between the reactor and regenerator.

When a fluidization gas is initially introduced to a fixed bed of catalyst, there is no

change in the bed; the gas simply flows through the void spaces. As the velocity of

the gas increases, it begins to exert a force on the bed to lift the catalyst. The void

volume begins to increase as the bed expands. With a further increase in gas

velocity, there is a point at which the drag (friction) force exerted on the particle is

just equal to the force exerted by gravity on the catalyst. This gas velocity is referred to as the incipient fluidization velocity or minimum fluidization velocity (Umf). Any

further increase in gas velocity allows the catalyst to freely move in the flowing gas,

constantly colliding with other catalyst particles. At this point the catalyst bed is

fluidized and behaves like a liquid.

157048 Fluidized Solids

Page 3

This behavior will change as more gas is pressured through the bed. Bubbles of gas

begin to appear in the bed. The point at which this occurs is defined as the minimum bubbling velocity (Umb). The bubbles may be small ones which disappear

after a short rise, or larger ones that grow as they pass through the bed. As the

velocity is increased further, the bubbles begin to occupy more of the bed. The

bubbles bursting through the surface throw catalyst into the area above the bed.

The surface of the bed is violently disturbed by the slugs, yet remains fairly distinct.

As gas velocity is further increased, the bed enters a turbulent state, where the

upper surface of the bed is not well defined. Slugging by large gas bubbles

decreases. Bubbling bed regenerators typically operate in this region. Advantages

of this regime are high solids mixing and therefore high heat and mass transfer

rates, contributing to the combustion of coke off the catalyst. The mixing is primarily

in the vertical direction and is driven by catalyst particles being pushed upwards on

top of the bubbles then falling off and dropping down behind the bubbles as shown

in Figure 2.

Eventually, the gas velocity exceeds the terminal velocity of some of the particles in

the bed. This regime is known as fast fluidization. Combustors typically operate in

this regime. At this point, a fluidized bed is not maintained unless catalyst is

recycled to the bed. Further gas rate increase moves into the pneumatic conveying

regime. Without recirculation of catalyst, all catalyst will be ‘blown’ out of the vessel.

157048 Fluidized Solids

Page 4

Figure 2 Bubble Driven Catalyst Mixing

Bubble

Wake

Drift

CatalystFlow

Gas

FCC-F001

157048 Fluidized Solids

Page 5

Figure 3 illustrates the pressure drop across a bed as a function of fluidization gas

superficial velocity. Initially, the pressure drop increases with velocity to the point of initial fluidization, Umf. For typical FCC catalyst this value is around 0.01 ft/sec.

Once fluidized, the catalyst exerts a pressure profile similar to that of a liquid. The

pressure head exerted by the bed will be about equal the weight of catalyst and the

gas contained in it. As a result of frictional losses, the pressure drop across the bed

is slightly greater than its weight. Between the point of initial fluidization and the

point at which entrainment begins, the behavior of the catalyst may be described by

the following equation:

P = (cat + gas) * h where gas 0

P = Pressure Drop, psi

= Density, lbs/ft3

h = Bed Height, ft/144

At higher velocities, we approach the pneumatic conveying regime in which the

entire bed is eventually entrained; hence a sharp pressure drop.

157048 Fluidized Solids

Page 6

Figure 3 Pressure Drop Across a Fluidized Bed

P = (cat +gas) * h gas 0P = Pressure Drop, psi

U = Gas VelocityUmf = Minimum fluidization Velocity

Umb = Minimum bubbling velocity

BubblingBed

Regenerator

Initiation ofFluidization Entrainment

Begins

PneumaticConveying

Gas

Combustor

ReactorRiser

U-Umf < Umb

FixedBed

BubblingRegime

Slug FlowRegime

U>Umb

FastFluidization

TurbulentRegime

Increasing Gas Velocity

U<Umf

ParticulateRegime

Incr

easi

ng P

ress

ure

Dro

p A

cros

s th

e B

ed

Density, lbs/ft3

hBed Height, ft/144

157048 Fluidized Solids

Page 7

FCC Catalyst Fluidization

FCC catalyst is a fine powder, generally smaller than most refinery catalysts. The

physical properties of the catalyst effecting the fluidization characteristics are

density, particle shape, and size distribution. In the Geldart powder classification

system, FCC catalyst is considered a Group A material. The “A” representing

‘aeratable’. The classes of particles under the Geldhart classification system are

shown in Figure 4.

FCC catalyst bulk density (non-fluidized) is about 50-55 lb/ft3 (800-880 kg/m3) and is

a result of catalyst composition and the manufacturing process. FCC catalyst is

roughly spherical in shape. This shape is advantageous to fluidization as it tends to

pack less tightly when defluidized. Spheres also lack the sharp edges which can

contribute to plant erosion problems. FCC catalyst is a mixture of particle sizes

ranging from 10-130 microns. The presence of fines (particles < 40 microns) is

helpful for fluidization. Fines are introduced with the fresh catalyst and are produced

during operation of the unit by attrition. These smaller particles move more easily in

the gas and act as a lubricant between the larger particles to lower the minimum

velocity required for fluidization. Generally, the more fines in the catalyst inventory,

the easier the catalyst is to fluidize and the longer it takes to defluidize once the

aeration medium is stopped. The physical properties of the gas also have a strong

influence on fluidization. The primary factors are the gas viscosity and density.

FCC unit design takes into consideration all the fluidization parameters. Changing

temperatures, pressures, bed heights, and gas velocities are considered when

sizing and orienting process equipment.

157048 Fluidized Solids

Page 8

Figure 4 Geldart’s Particle Classification

10,000

5,000

3,000

1,000

200

2,000

500

100

300

10 20 50 100 200 500 1,000 2,000dp, Microns

Pp,

Pg,

Kg/

m3

C

A

B

D

A: Aeratable (Umb> Umf) Have Significant Deaeration TimeB: Bubbles Above Umf (Umb= Umf)

C: CohesiveD: Spoutable

157048 Fluidized Solids

Page 9

Fluidization in Regenerator

Superficial velocities in the FCC regenerator are considerably higher than minimum

fluidization. This is because the air rate is set by the coke make in the unit, not the

fluidization requirements. Less air would leave the unit behind in burning, with most

of the coke still on the catalyst. The regenerator diameter could be increased to

drop the superficial velocity but this would add considerable cost in construction.

Additionally, uniform distribution of air is more difficult in very large vessels. The

FCC design takes into account the need to regenerate catalyst, maintain

fluidization, retain catalyst inventory, and minimize capital expenditures.

The conventional or “Bubbling Bed” regenerator, shown in Figure 5, generally

operates with superficial air velocities of 2-3.5 ft/sec. This velocity is in the turbulent

fluidization regime. This regime exhibits violent bubbling and gas slugging which

causes catalyst to be thrown upward into the freeboard area above the bed. Most of

the catalyst settles back to the bed by gravity. However, some of the catalyst,

especially fines, is carried up above the freeboard area. The regenerator vessel can

thus be divided into two sections, the dense bed and the dilute phase.

The dense bed is all the catalyst contained below the established bed level. The

dilute phase is where larger catalyst particles separate from the gas and fall back to

the bed. Any catalyst particles that do not separate in the dilute phase, enter into

the regenerator cyclones. Catalyst entering the cyclones is separated by centrifugal

force with the larger particles being returned to the bed via the cyclone diplegs.

Catalyst fines too small to be separated by the cyclones are carried out of the

regenerator with the flue gas.

In a bubbling bed regenerator it is important that the coke and air are evenly

distributed. The air bubbles rising through the bed result in thorough mixing in the

vertical direction but little mixing horizontally. Therefore if the spent catalyst, and

therefore the coke, is not uniformly distributed the areas with more coke may be

short of air allowing CO to breakthrough the bed. The other areas with less coke

operate with excess oxygen. This combination results in afterburning and high

157048 Fluidized Solids

Page 10

temperatures in the dilute phase. For this reason a spent catalyst distributor or “ski

jump” is used on all spent catalyst standpipe outlets. In many cases the air grid jet

plugging pattern will be shifted to areas expected to have less coke present to

reduce the air in that area.

The design distance between the cyclone inlet and the surface of the dense bed is

determined by the Transport Disengaging Height, or TDH. The TDH is a function of

the superficial gas velocity, vessel diameter, and the particle size distribution. The

amount of catalyst entrained in the gas above a fluidized bed decreases with the

height above it. A given particle reaches a distance above the bed where

gravitational forces overcome the upward drag forces of the gas, and the particle

falls back to the bed. The smaller the particle, the greater the distance. A height is

reached where the amount of entrained solids becomes constant, no more particles

are overcome by gravitational forces. The particles here are to small to settle. This

height, the TDH, determines what minimum distance above the bed the cyclones

inlets must be placed. Other considerations for setting the cyclone design inlet level

include dense bed level variations and minimum required dipleg length. To account

for these considerations, the cyclone inlet height will be greater than the actual

TDH.

As illustrated in Figure 6, if a regenerator is operated in such a manner that the

distance between the catalyst bed and the cyclone inlet is less than the TDH, the

catalyst density at the cyclone inlet will be higher. This will increase the catalyst

loading to the cyclone and potentially increase catalyst losses from the cyclone.

In a bubbling bed regenerator the discharge of the primary cyclone diplegs which

are returning hot catalyst to the bed can be directed to heat colder areas of the bed,

typically near the spent catalyst inlet.

157048 Fluidized Solids

Page 11

Figure 5 Conventional FCC Regenerator

Air

Tra

nsp

ort

Dis

eng

agin

gH

eig

ht

Fre

eb

oar

d

CatalystMovement

GasBubbles

DenseBed

FlueGas

157048 Fluidized Solids

Page 12

Figure 6 Schematic Depiction of TDH

TDH

Hei

gh

t

Density of Solids

U

157048 Fluidized Solids

Page 13

The combustor section of aHigh Efficiency regenerator operates at much higher

velocities than the conventional regenerator. The lower part of the regenerator, the

combustor, operates at the low end of the fast fluidization regime at a velocity on

the order of 5-6 ft/sec. At this velocity catalyst is carried upward. The catalyst

travels up the combustor riser in pseudo plug flow. Much of the catalyst slips behind

and backmixes as it moves upward. At the top of the combustor riser the

regeneration gas and catalyst undergo a primary separation. The upper regenerator

vessel is designed to operate with superficial gas velocities on the order of 2-3

ft/sec. Since the regeneration gas does not pass through the catalyst bed in the

upper regenerator, a small stream of fluffing air is directed into the dense bed to

keep it aerated. Since the combustor velocity is so high and the net catalyst flow is

up, external catalyst recycle is necessary to maintain density in the combustor. The

density in a high efficiency combustor is controlled with a slide valve on a recycle

standpipe. The amount of catalyst circulated from the dense bed in the upper

regenerator controls the density and temperature in the combustor.

Figure 7 represents fluidization data for a commercial combustor operation at

various catalyst loadings and superficial air velocities. The figure shows the

pressure gradient, or fluidized density in lb/ft3, measured across the combustor

section. The catalyst loading, W (lb/ft2/sec), is referred to as the flux and is the

summation of both the reactor-regenerator catalyst circulation and the combustor’s

external recirculation. Lines A through D represent lines of constant gas velocity.

The gas superficial velocity A lies well below the catalyst transport velocity;

however, at low solids flux (region X-Y) dilute phase flow exists. At condition Y, the

solids flux is sufficient to choke the system and any further increase in solids

loading (region Y-Z) results in a substantial density (inventory) increase. At the

higher gas velocities B & C, choking takes place at much higher solids flux and

results in a less abrupt change in combustor density with further increases in flux.

Such a region can be referred to as fast-fluidized. Eventually, at higher velocities

like D, true transport flow will be generated under which conditions no solid flux can

choke the system.

157048 Fluidized Solids

Page 14

This operating data demonstrates how flexible the system is in adjusting combustor

inventory/coke burning capacity for various operating conditions. Consider the

operating condition E at gas velocity B. If the superficial velocity is now increased to

C either by a change in regenerator pressure or air rate, the combustor density will

decrease to condition F at constant solids loading. However, if necessary, the

combustor density may be reestablished at condition G by means of increasing the

solids flux (opening the external recirculation slide valve). Note that an adjustment

in combustor density also changes the combustor inventory and a change in the

upper regenerator level (surge inventory).

The catalyst bed density in a regenerator is primarily a function of superficial

velocity. For typical bubbling bed regenerator velocities, bed densities would range

from 30 to 40 lb/ft3. By contrast, typical combustor densities range from 10 to 15

lb/ft3. Figure 8 gives a correlation between bed density and superficial velocity.

Figures 9, 10, & 11 show normal catalyst densities in various unit configurations.

157048 Fluidized Solids

Page 15

Figure 7 Combustor Operation

D

GE

F

(Z)

Gas Velocity, ft/secCombustor CatalystInventory, I =

Density x Volume

Com

bu

stor

Den

sity

, lb

/ft3

3

(X)

(Y)(Y)

Catalyst Loading (W) lb / sec/ft2

BC

A

157048 Fluidized Solids

Page 16

Figure 8 Catalyst Bed Density

60

50

40

30

20

10

0

Bed

Den

sity

, lb

/ft

3

0 3.01.00.1 10.0

Superficial Velocity, ft/sec*Adapted from a paper "Fluidization and the FCC Process" by W.S. Letzch of Katalistiks

157048 Fluidized Solids

Page 17

Figure 9 Catalyst Densities

Side by Side FCC with Bubbling Bed Regenerator/ Tee Disengager Riser Termination

35(560)

3(50)

35(560)

5(80)

40-45(640-720)

2(30)

Densities in lb/ft3 (kg/m3)

157048 Fluidized Solids

Page 18

Figure 10 Catalyst Densities

High Efficiency Regenerator/ Highly Contained Riser Termination/ Elevated Feed

8-12(130-200)

40(640)

3(50)

1(20)

<1(<15)

40-45(640-720)

5(80)

35(560)

15-20(240-320)

157048 Fluidized Solids

Page 19

Figure 11 Catalyst Densities

RFCC 2 Stage Regenerator

<1(<15)

40-45(640-720)

5(80)

15-20(240-320)

35(560)

35(560)

35(560)

3(50)

3(50)

157048 Fluidized Solids

Page 20

Fluidization in Standpipes

Fluidized catalyst can be made to flow through pipe in the same manner as a liquid.

Standpipes generate static head which allows transport of catalyst between the

reactor and regenerator. The static head generated must be enough to overcome

any pressure differences between the reactor and regenerator. As catalyst travels

down the standpipe it carries gas with it which keeps the catalyst fluidized and

flowing smoothly. The pressure will increase as the catalyst progresses down the

standpipe because of the additional head. This increase in pressure causes the

entrained gas to compress and the void volume to decrease. If the gas is

compressed too much the catalyst in the standpipe becomes dearated, it will no

longer flow smoothly and can cause circulation problems. A condition know as ‘slip-

stick’ flow can ensue where the catalyst ‘breaks’ away from the dearated mass and

passes down the standpipe. Reactor temperature and reactor level swings can be a

symptom of this phenomenon. Standpipe design criteria are set to ensure that

pressure head build up, flux rate and velocity, and aeration levels are adequate to

ensure stable operation.

Figure 12 illustrates the pressure profile in a standpipe. Troubleshooting of low or

erratic standpipe flow should start with a single gauge pressure survey to ensure

that the right amount of head is generated in the standpipe. The head generation

should be the density in the standpipe, typically 35 lb/ft3 (560 kg/m3) times the

elevation change. Another useful troubleshooting exercise is to check the flow

through the slide valve versus the expected flow predicted by the slide valve

equation:

W =A x Cd x (DP x )1/2

1.5

Where: W = Catalyst Mass Flow (lb/sec)A = Total Slide Valve Open Area, in2Cd = Valve Coefficient (0.9 Typical)DP = Slide Valve Pressure Drop (psi) = Standpipe Density (35 lb/ft3 Typical)

157048 Fluidized Solids

Page 21

Flow problems in standpipes can have several causes including:

Too much gas entrained into the standpipe

Insufficient gas to keep the standpipe fluidized

Shallow standpipe angle

Elbows in standpipes

Poor catalyst fluidization properties (typically lack of fines <40 )

Figure 12 Standpipe Pressure Profile

Height

Pressure

Slide Valve Entrance Effects

Slide Valve DP

Standpipe EntranceEffects

Head Generation

157048 Fluidized Solids

Page 22

Fluidization in Reactor Riser

Elevated feed systems use steam and/or lift gas to accelerate catalyst up the riser.

Typical velocities in the ‘lift zone’ are 12-18 ft/sec (3.6-5.5 m/sec). This velocity is in

the conveying regime and transports the catalyst up the riser with minimum

slippage. This velocity region results in a moderate and uniform catalyst density

profile at the point of feed injection. The moderate density allows the feed droplets

to penetrate the catalyst more easily resulting in more uniform catalyst/oil

contacting. Feed is radially injected roughly 1/3 the distance up the riser where

rapid vaporization and reaction take place. The vapor expansion results in a

dramatic increase in velocity up the riser. Riser exit velocities of 60 ft/sec are

typical. Feed riser residence times are on the order of two to four seconds. This

would be considered dilute phase pneumatic conveying. During startup, shutdown,

or emergency situations, it is important to maintain lift media in the riser to ensure

that catalyst does not ‘slump’ and plug the riser. Typically, lift steam is added to the

wye to ensure adequate velocity in the riser in such situations.

Because fluidized solids flow like a liquid they will flow into any stagnant area.

Therefore it is important to keep the feed nozzles purged with steam any time there

is catalyst in the riser without feed.

Fluidization in Reactor

Depending on the reactor riser termination, catalyst and oil exiting the riser are

separated in a ballistic manner or by centrifugal force in a vortex chamber or

cyclone system. The catalyst, once separated from the reaction products, falls down

into the reactor stripper. With modern, highly contained riser terminations, the

reactor is essentially a large disengaging device as the majority of the reaction

takes place in the riser.

As in standpipes, the catalyst flowing down the diplegs is kept fluidized by the

reactor vapors which are entrained with the catalyst. In direct connected cyclone

systems with almost all of the catalyst circulation flowing down the primary cyclone

157048 Fluidized Solids

Page 23

diplegs this gas volume can be very large, as much as 6 wt% of the total product.

Once the catalyst exits the dipleg the entrained gas is exposed to high temperatures

for an extended period of time in the large reactor shell volume resulting in higher

light ends and coke make. This is one of the reasons for development of the vortex

separation technology which provides a highly contained riser termination without

the entrainment of hydrocarbons back into the reactor through the diplegs.

Fluidization in Reactor Stripper

The reactor stripper is similar in principle to a dense bed in the regenerator. The key

difference is that the fluidization, or stripping, medium is steam and not air. Steam is

introduced through pipe distributors and flows up through the bed displacing

hydrocarbons from the interstitial and void spaces of the catalyst. Roughly 1.5 to 2.5

pounds of steam per thousand pounds of catalyst is required for a well designed

stripper. The stripping action helps to recover valuable reaction products and

maintains proper fluidization of the catalyst as it moves back to the regenerator.

Typical superficial velocities are in the range of one to three feet per second.

Poor stripper design can result in uneven distribution of the vapor flow. As a result

of this, some of the catalyst may become defluidized while the catalyst flux in other

areas of the stripper increases. This can reduce stripping efficiency due to poor

catalyst/steam contacting, excessive gas entrainment down the stripper and lower

residence times in the active portion of the stripper. As the catalyst flux in the active

area of the stripper increases more gas can be entrained down the stripper and into

the standpipe resulting in lower densities, less standpipe head generation and lower

slide valve pressure drop.

157048 Fluidized Solids

Page 24

Fluidization in Catalyst Coolers

As stated earlier, bubbles rising through a catalyst bed result in thorough mixing in

the vertical direction. In a catalyst cooler this phenomena is used to continually

replace cooled catalyst with hot catalyst from the regenerator vessel by bubbling air

injected near the bottom of the tubes. As the fluffing air rate is increased the rate of

hot catalyst entering the catalyst cooler increases. The heat transfer coefficient

between the catalyst particles and the tubes also increase with increasing fluffing air

as the bed becomes more turbulent.

Flow through type catalyst coolers also use a standpipe and slide valve to

continually circulate hot catalyst from the regenerator through the cooler. This

increases the temperature of the catalyst in the cooler further so that ~50% more

duty can be obtained from a flow through cooler than a back mixed cooler.

157048 Catalyst Page 1

CATALYST

INTRODUCTION

The FCC catalysts in use today are a complex blend of technologies. The

workhorse catalyst in this complex system is, itself, a complex blend of

technologies. The main component in the workhorse catalyst is a crystalline silica-

alumina material known as a zeolite, or alternatively known as a molecular sieve.

The quantity and the properties of the zeolite in the catalyst can be altered to fit the

individual activity and product yield requirements of the refinery. A second active

component in the workhorse catalyst is typically an active alumina, included in the

workhorse catalyst to provide conversion of the very large and heavy molecules in

the feed, which are difficult for the molecular sieve to process. This second

component also can protect the molecular sieve from contaminants in the FCCU

feed, which can damage the performance of the molecular sieve. A third component

is added to this catalyst cocktail to make the catalyst hard enough to meet the

stringent particulate emissions requirements of the FCCU.

In today’s world, other catalytic components are frequently combined with the

workhorse catalyst, as catalyst additives. These additives can be included to

provide increased gasoline octane, increased yields of light olefins, principally

propylene, enhanced coke burning characteristics in the regenerator, and

decreased SOx and NOx emissions from the regenerator.

HISTORY

The first FCC catalysts were finely ground, naturally occurring clays. By today's

standards, these catalysts were inexpensive, but they suffered from poor stability,

activity, and integrity. Activity was less than half what it is today, and erosion caused

157048 Catalyst Page 2

by the jagged edges of natural catalyst created maintenance problems which

required high makeup rates to keep up unit inventory.

The first major improvement in FCC catalysts was the introduction of the all-

synthetic catalysts in 1946. These new catalysts were amorphous silica-alumina

materials containing approximately 12% alumina and 88% silica. They were spray

dried as the final step in their manufacture, which resulted in a roughly spheroidal

particle. This improved particle shape provided improved fluidization characteristics

and decreased equipment erosion problems. These low alumina catalysts were

more active than the ground clays and produced higher octane gasoline.

The early 1950's saw the next major improvement in these amorphous FCC

catalysts. The catalyst alumina content was increased to 25%. Catalyst activity

increased with increased surface area.

Shortly after the development of the higher alumina catalyst, a silica-magnesia

catalyst was introduced. Though advertised to be selective for middle distillate (light

cycle oil) production, these catalysts did not regenerate sufficiently to be

commercially acceptable.

A breakthrough in FCC catalyst technology for maximizing gasoline selectivity

occurred during the early 1960's, when it was discovered that molecular sieves

could be excellent cracking catalysts. The silica - alumina chemical composition of

the catalyst remained basically the same, but the structure was radically different.

The crystalline zeolite has a well ordered, repeatable framework structure in

contrast to the amorphous, sponge-like structure of the previous low and high

alumina catalysts. The zeolite, when first synthesized, contains ion exchangeable

Na+ cations. In that form the zeolite is a poor cracking catalyst. The break through

discovery occurred when it was found that the replacement of Na+ with either H+ or

rare earth (principally lanthanum and/or cerium) cations by ion exchange converted

the zeolite into an outstanding cracking catalyst.

157048 Catalyst Page 3

There are over 30 different naturally occurring zeolites, but only 8 exist in sufficient

quantities to permit commercial exploitation. Over 100 have been synthesized in the

laboratory. The zeolite used in today’s FCC catalyst is called a Type Y sieve and is

close to a rare natural mineral called faujasite. Large quantities of this material are

synthesized by the catalyst industry; roughly 50 million pounds per year are used for

FCC catalyst.

When zeolites were first tested as FCC catalysts, a pure zeolite was used. In the

pilot plants in operation at that time, this zeolite proved far too active, more than 100

times as active as amorphous catalysts. But when the zeolites were incorporated

into an amorphous base, the catalyst showed great promise. The first commercial

catalysts were made with 8-10% zeolites, and showed an activity 1.5 to 2 times that

of the amorphous types. To utilize this higher activity, UOP introduced the short

contact time, all riser cracking concept. The short contact time minimized

undesirable over cracking, while the high activity maintained good conversion.

Since virtually all the cracking could be done in one pass, it was no longer

necessary to recycle large quantities of heavy oil from the main column. Obviously,

the fresh feed rate was increased. However, for distillate operations, the low reactor

severity desired still required a high recycle rate.

The Y-zeolite is made up of regularly reoccurring cage-like structures. The cage has

openings into the cage of approximately 7Ǻ in diameter. The zeolite is, thus,

sometimes referred to as a molecular sieve, since the constrained entrance into the

zeolite cage acts as a sieve. Molecules up to a certain size can enter the cage while

larger molecules are kept out. Cracking occurs inside the cage at the locations of

the active sites, which are associated with the aluminum atoms inside the cage. The

cracked products must then exit the catalyst. At this time, the accepted theory is

that the reaction is not diffusion-controlled or limited, although the effect is present.

When exposed to the severe hydrothermal conditions that exist in the regenerator,

the crystalline structure of the zeolite is susceptible to significant destruction of its

structure, resulting in loss of catalytic activity. A major advancement in catalyst

technology occurred in the late 1960s, when it was discovered that a controlled

157048 Catalyst Page 4

hydrothermal pretreatment could improve the stability of the zeolite. The resulting

product was designated as “ultra-stable Y-zeolite”, commonly referred to as US-Y.

The 1970s ushered in the age of Environmental Sensitivity. Air pollution concerns

impacted the operations of the FCCU. This in turn ushered in the age of Catalyst

Additives. The first environmental concerns that effected FCC operations were in

the areas of CO pollution from the FCC regenerator and lead pollution from car

exhausts.

Prior to 1970, burning coke in the regenerator resulted in equal volumes of CO and

CO2 in the flue gas. It was impossible to convert the CO to CO2 in the FCCU without

creating unacceptable temperatures in the upper part of the regenerator.. A

modestly sized FCCU (20,000 BPD) without a CO boiler typically emitted over

20,000 lbs/hr of CO into the atmosphere. In the early 1970s it was discovered that a

small amount of platinum (~ 1ppm) in the FCC catalyst inventory allowed the CO to

be completely converted to CO2 without causing excessive temperatures in the

regenerator. In addition to eliminating CO, “complete combustion” had economic

advantages as well. Today, the 1 ppm of platinum is typically added as a catalyst

additive, which contains a high concentration of Pt (500 – 1000 ppm).

Prior to the 1970s, tetra ethyl lead (TEL) was used to increase gasoline octane but

concerns were raised that it also resulted in toxic lead emissions in automobile

exhaust. In the 1970s, legislation in the U.S. was passed that reduced, and

eventually eliminated, the amount of TEL that could be used in gasoline. Refiners

had to take steps to regain the lost octane. The use of US-Y zeolites in the FCCU

was found to help increase FCC gasoline octane. At the same time, a new zeolite

with a smaller pore than Y-zeolite, designated as ZSM-5, was developed which,

when added to the FCC catalyst inventory, was found to increase gasoline octane.

An additive containing ZSM-5 was frequently used for this purpose in the 1980s.

Sulfur oxide emissions (SOX) from the regenerator flue gas became an

environmental concern in the 1980s. This led to another catalyst additive which

refiners could blend with their FCC catalyst. The additive captured the SOX

157048 Catalyst Page 5

produced in the regenerator and carried it back to the reactor, where the sulfur was

released as H2S and left the FCCU with the product gases. The sulfur could then be

recovered as elemental sulfur in a Klaus plant.

In the late 1990s, concerns about nitric oxide (NOX) emissions from the regenerator

began to be raised. Catalyst suppliers began to provide additives that could be used

to reduce NOX. With the aid of the NOX additive NOX was converted to N2 and left

with the regenerator flue gas.

Also in the late 1990s, demand for propylene increased to the point where

propylene became an FCC product of considerably greater value than FCC

gasoline. Refiners who could produce a high quality propylene product began to run

their cat crackers to maximize propylene. The use of a ZSM-5 containing additive

became the variable that had the biggest impact upon increasing FCC propylene

yields. Whereas, in the 1980s, a ZSM-5 additive was used to increase gasoline

octane, at the start of the 21st century, ZSM-5 additives were primarily being used to

increase FCC propylene yields. The trend towards increasing value of propylene

continued during the period 2000 – 2005, during which time the price of propylene

increased from ~$500 / metric ton to ~$900/ metric ton. Refiners have increased

their use of ZSM-5 additives during this period and catalyst suppliers have

responded by increasing the content of ZSM-5 zeolite in their additives. In the

1980s, ZSM-5 additives typically contained 10% ZSM-5 zeolite. By 2005, additives

containing 40% ZSM-5 were common. Catalyst suppliers were also beginning to

supply a multi-functional catalyst which contained, within one catalyst particle, both

a Y-zeolite component and a ZSM-5 zeolite component.

157048 Catalyst Page 6

MODERN FCC CATALYSTS

PURPOSE OF THE CATALYST

Understanding some basic principles regarding fluid catalytic cracking (FCC)

catalyst performance is important to understanding catalyst technology. The modern

FCC catalyst carries out a variety of functions.

One important function is to provide all the process heat requirements This is

achieved by the burning of coke on the catalyst in the regenerator, which:

• Heats the hydrocarbon feed up to the reaction temperature

• Provides for the endothermic heat of cracking

• Compensates for all the unit's heat losses

• Heats the air from the air blower up to the temperature of the

regenerator

On the reactor side, the catalyst must have sufficient activity to carry out catalytic

conversion of the hydrocarbon feed before any significant amount of thermal

cracking occurs and must have the selectivity characteristics that provides the type

of products required by the refinery.

Thus, the catalyst must have the thermal stability to maintain particle and catalytic

integrity under severe regenerator conditions. It must have the physical strength to

maintain particle morphology under the severe impact and erosion forces so that it

remains in the unit, and it must have the proper flow characteristics to allow it to

readily flow between the regenerator and the reactor.

Thermal (free radical) cracking is the predominant cause for the removal of

hydrocarbon groups from the ends of a hydrocarbon chain, producing most of the

methane, and a large portion of the ethane and ethylene produced. Significant

quantities of the larger fragments (C3 and greater) are generally not produced by

157048 Catalyst Page 7

thermal cracking. Small amounts of C4 to C16 -olefins are produced. A high

percentage of the olefins that are formed condense directly to coke.

Catalytic cracking, by comparison, produces fewer C2 fragments and relatively few C1 fragments. With catalytic cracking, cracking occurs at the strong acid sites in the

zeolite cage where the Brønsted acid sites occur. Cracking is by beta scission. The fragments that are cracked off the large gas-oil molecule are mainly in the C3 to C6

range. A large number of olefins are produced. Because of the ability of the catalyst

to achieve rapid double-bond shifts, the linear olefins are generally in thermal

equilibrium with each other. However, since hydrogen transfer (H-transfer) is a

principal reaction and is selective for tertiary olefins, the isomeric olefins are present

in less than thermal equilibrium, since some of the isomeric olefins are converted to

the saturated isomer before desorbing from the catalyst surface.

Basically, the catalyst carries out two classes of reactions:

• Primary reactions, which involve only a single molecule.

• Secondary reactions, in which bimolecular reactions take place. These

reactions involve molecules formed from the primary reactions.

Cracking of the original large gas-oil molecule is a primary reaction. Such reactions

can be:

• Paraffin smaller paraffin + olefin

• Alkyl naphthene naphthene + olefin

• Alkyl aromatic aromatic + olefin

• Multiring naphthene alkylated lesser-ring naphthene

The secondary reactions are mainly associated with H-transfer reactions of one kind

or another and generally result in the saturation of an olefin:

• Olefin + paraffin paraffin + olefin

• Olefin + naphthene paraffin + aromatic

• Olefin + olefin paraffin + diolefin (or coke)

157048 Catalyst Page 8

• Olefin + olefin paraffin + aromatic

The isomerization of a straight-chain olefin, after the initial formation of the olefin, is

another important secondary reaction.

CATALYST COMPONENTS

To carry out its functions, the modern FCC catalyst is typically made up of four

separate but important components:

• Zeolite (molecular sieve)

• Active matrix component

• Inactive matrix component

• Binder

The inactive matrix component and the binder control the overall activity of the

catalyst by diluting the highly active components down to the proper activity level

and provide the proper particle strength and morphology. In the area of particle

strength, all catalyst suppliers have made major advances in catalyst attrition

resistance. In the 1990s, achieving good catalyst attrition resistance is generally not

a problem.

From a catalytic point of view, the zeolite and the active matrix components are the

items of principal interest.

The Zeolite

The zeolite provides controlled Brønsted (proton donor) acidity from its crystalline

structure and both Brønsted and Lewis (electron acceptor) acidity from the

nonframework alumina. Non-framework alumina exists as a result of the hydro-

thermal removal of alumina from the silica - alumina zeolite framework. Some basic

zeolite concepts help to understand how the zeolite functions.

157048 Catalyst Page 9

Zeolite Reaction Pathways

Zeolitic cracking is believed to begin with the transfer of a proton from the catalyst

surface to an olefinic double bond in the hydrocarbon molecule, thus forming a

carbenium ion. The double bond was initially created through a free radical thermal

cracking step or by a Lewis acid reaction initiated by an active alumina surface.

These steps are illustrated below.

• Initiation: nC10H22 CH3–(CH2)6–CH=CH–CH3+H2

• Carbenium ion formation (Brønsted Acidity)

The carbenium ion migrates freely through the hydrocarbon molecule to

increasingly stable locations, and arrives at a position where the flexing of the C–C

in the β position sufficiently weakens the bond, cracking the bond to a smaller,

stable carbenium ion and an olefin. This mechanism is known as Beta scission.

(Hydrocarbon)

(Protonated Catalyst Surface)

C7H15 – CH = CH – CH3

+

O|

Si|

O

– – O – AL – O

H+ |

|O

O

Hydrocarbon Adsorbed on CatalystSurface in Carbenium Ion Form

O|

Si|

O

– – O – AL – O |O

O

C7H15 – C – C – CH3

-

+

H

H

H

C6H13 – C – C – CH2 – CH3

O|

Si|

O

– – O – AL – O |O

O

+

-

C6H13 + CH2 = CH – CH2 – CH3

O – AL – O |O

O

+

-

H H

H

157048 Catalyst Page 10

In this illustration, the -CH3 fragment at the other β C-C position can not generate

enough vibration to crack the bond.

The carbenium ion also promotes rapid skeletal isomerization to the tertiary carbon

location, which is the most stable configuration, as:

C2 H5 – CH 2 – CH 2 – CH 2

O – AL – O | O

O-

+C2 H5 – C – CH 3

O – AL – O | O

O-

+

CH 3 |

It also promotes the bimolecular H-transfer reaction:

In this illustration, the hydrocarbon molecule receiving the H atom is no longer

attached to the zeolite particle and desorbs into the product stream. The molecule

which donated the H atom is now doubly attached to the zeolite particle, making it

more difficult to desorb. As the molecule continues to donate H atoms, it becomes

more and more strongly attached to the catalyst particle, to the point where it may

be impossible to desorb. It is then classified as coke.

CH3

C2H5 C CH3 + C10H21

O AL O O AL O

O O

+ +

- -O O

CH3

C2H5 C CH3 + C10H21

O AL O O AL O

O O

++ ++

-- --O O

CH3

C2H5 CH CH3 + C10H20

O AL O O AL O

O O

++

- -O O

CH3

C2H5 CH CH3 + C10H20

O AL O O AL O

O O

++++

-- --O OO

157048 Catalyst Page 11

Zeolite Structure

The zeolite used in today's FCC catalyst is the Y-type faujasite. The tetrahedral

structure is the basis for the entire geometry of the Y-type faujasite. The tetrahedron

is present at the beginning when silicon and aluminum atoms are combined with

four oxygen atoms (Figure 1) in a tetrahedral arrangement. The silica and alumina

tetrahedra are then arranged at the vertices of a truncated octahedron known as the

sodalite cage. This cage has 8 hexagonal faces, 6 square faces (Figure 1), and 24

silica and alumina vertices.

Figure 1 Zeolite Molecular Structure

The sodalite cages also combine tetrahedrally, through the hexagonal faces, with

other sodalite cages (Figure 2) to form the supercage, also known as the unit cell.

Eight sodalite cages make a unit cell. Some important dimensions of these

structures in a Y-type faujasite crystal are:

• Sodalite cage

– Entrance diameter 2.2 Å

Tetrahedron

Oxygen

Siliconor

Aluminum

Sodalite

157048 Catalyst Page 12

• Supercage

– Entrance diameter 7.4 Å

– Internal diameter 13 Å

• Unit cell (as synthesized)

– External diameter 24.67 Å

Figure 2 Zeolite Molecular Structure

Zeolites are frequently referred to as either a large pore zeolite, with a 12 member

ring pore entrance; as a medium pore zeolite, with a 10 member ring opening; or as

a small pore zeolite, with an 8 member ring pore opening. The Y-zeolite is a large

pore zeolite with a 12 member ring.

SodaliteCages

HexagonalPrisms

Supercage

157048 Catalyst Page 13

The key to the performance characteristics of this crystal is that aluminum is

trivalent and thus does not fit comfortably into a tetrahedral arrangement with four

oxygen atoms, whereas silicon, being tetravalent, does. In such an arrangement,

the silicon atom is electrically neutral, but each aluminum atom takes on a negative-one charge. This charge is counterbalanced by a cation, such as Na+, NH4+, Ce+2

or La+3. The presence of these charged particles directly or indirectly produces the

protons on the catalyst surface that create the catalytic properties of the zeolite.

Zeolite Ion Exchange

When the catalyst is first manufactured, the charged particle on the catalyst surface

is not a proton. Rather it is a sodium cation that comes from the sodium aluminate

and sodium silicate used to produce the zeolite. Each supercage thus initially has

the formula:

Na54 (AlO2)54 (SiO2)138 • (H2O)250

Each aluminum atom has a corresponding sodium atom. Also, when manufactured,

approximately seven aluminum atoms are in each of the eight sodalite cages, for a

total of 54 aluminum atoms per super cage.

In the sodium form, the crystal has poor hydrothermal stability because sodium

promotes dealumination of the crystal lattice. The sodium cation is therefore

removed by ion exchange during catalyst manufacturing and is replaced with either

ammonium cations, which form the Brønsted acidity protons directly upon heating in

the FCC unit, or with rare earth cations (principally lanthanum or cerium). The rare

earth cations hydrolyze water molecules on the catalyst surface and thereby create

the necessary protons. The rare earth cations are the most successful in preventing

crystal dealumination. Consequently, the early zeolitic catalysts used in the 1960s

and 1970s were fully rare earth exchanged.

157048 Catalyst Page 14

Zeolite Dealumination

Under the conditions of steam and high temperature that exist in an FCC

regenerator, all Y-type faujasite zeolites dealuminate to some degree, even if fully

rare earth exchanged. The crystal structure is attacked by water molecules, which extract the aluminum and deposit it within the supercage as Al(OH)3:

The non-framework alumina (NFA) that is deposited has catalytic activity (Lewis acidity). It tends to catalyze the formation of C2 and lighter gases, olefins, and coke.

The hydroxyl nest, which is formed when aluminum is removed from the framework,

represents a point of framework weakness that can lead to crystal collapse. In some

cases, silicon atoms migrate from the crystal surface into the crystal lattice in an

annealing type of operation and fill the vacancies left by the departing aluminum

atoms. Also, in other cases, silicon atoms from a collapsed framework react with the

NFA to form silica-alumina compounds.

A further effect of dealumination is that the crystalline structure shrinks in size, the

O-Si-O bond being smaller than the O-Al-O bond. The greater the degree of

dealumination, the smaller the crystalline unit cell size. Also, as aluminum is removed from the crystal structure, the ratio of SiO2 to Al2O3 in the remaining

framework increases. The measurement of unit cell size by X-ray diffraction techniques then becomes a convenient way to determine the SiO2/Al2O3 ratio of

the zeolite in a catalyst. Such a relationship is shown in Figure 3.

O |O — Al- — O + 4 H+OH-

| O

OH

OH OH + Al(OH)3 + Cation • OHOH

157048 Catalyst Page 15

Figure 3 Effect of Dealumination on Unit Cell Size

Because rare earth exchange prevents dealumination, the degree of dealumination

can be controlled by controlling the amount of rare earth exchange. Thus,

decreasing the degree of rare earth exchange decreases the number of aluminum

atoms in the unit cell and results in a smaller unit cell size (Figure 4).

24.70

24.60

24.50

24.40

24.30

24.205 8

10 20 30 40 50 60SiO2/Al2O3 mol Ratio in Unit Cell

0 30 50 60 70 80 85% Dealumination (Starting with 5.0 SiO2/Al2O3)

Un

it C

ell S

ize

(ao)

of N

A-Y

Zeo

lite

, Å

90

24.66

24.52 (US-Y)

157048 Catalyst Page 16

Figure 4 Effect of Rare Earth Exchange on

Equilibrated Unit Cell Size

One of the important catalyst developments in recent years was the realization that

important selectivity benefits can be achieved by reducing the amount of alumina in

the crystal structure. Because only the presence of aluminum atoms causes the

protons to exist on the catalyst surface, decreasing the aluminum atoms causes the

catalyst activity to decrease. Reducing the number of aluminum atoms also spreads

the active sites further and further apart, making bimolecular secondary reactions

(H-transfer) more difficult. This site reduction results in less olefin saturation (more

olefin production) and less coke formation and also increases the strength of the

individual acid sites by decreasing the interaction between sites. The net result is an increase in C3 and C4 production and an increase in aromatic hydrocarbons in the

gasoline fraction. An important benefit is an increase in gasoline octane. These

trends are seen in Figures 5 to 9.

24.45

0

% RE2O3 on 100% Y-Zeolite

24.40

24.35

24.30

24.25

24.202 4 6 8 10 12 14 16

Zeo

lite

Un

it C

ell S

ize,

Å(A

fter

5 h

r 81

5o C S

team

ing)

157048 Catalyst Page 17

Figure 5 Delta Coke at 65 wt% Conversion

157048 Catalyst Page 18

Figure 6 Gasoline Olefin Content at 65 wt% Conversion

157048 Catalyst Page 19

Figure 7 C6-C8 Aromatics at 65 wt% Conversion

157048 Catalyst Page 20

Figure 8 Gasoline RONC at 65 wt% Conversion

157048 Catalyst Page 21

Figure 9 Gasoline MONC at 65 wt% Conversion

157048 Catalyst Page 22

Changing the degree of zeolite dealumination has some other subtle effects on the

cracking reaction and on FCC operating conditions. Increased dealumination (lower

unit cell size) increases the endothermic heat of cracking and also increases

cracking activation energy. The multiple effects of changing unit cell size are

illustrated in Figure 10. Although the higher heat of reaction and lower delta coke

resulting from lower unit cell size increases the catalyst circulation rate and lowers

regenerator temperature, it also increases coke yield because of the effect of

increased heat of reaction on the FCC heat balance.

Figure 10 Effect of Equilibrium Zeolite Unit Cell Size

24.25 24.30 24.35 24.40 24.45

Specific Catalyst Activity

Coke

Heat of Reaction

Octane

Activation Energy

Equilibrium Zeolite Unit Cell Size , Å

157048 Catalyst Page 23

The ZSM-5 Zeolite for Octane and Olefin Production

The ZSM-5 zeolite cage, with a 10 member ring pore entrance, has a smaller pore

mouth (~ 5.5 Ǻ) than the Y zeolite, with a 12 member ring and a 7.4Ǻ pore mouth.

ZSM-5 is designated as a shape selective zeolite, meaning that the hydrocarbons

that can enter the Zeolite cage are limited to the smaller molecules, such as the

linear and singly branched molecules in the gasoline boiling range. Large

molecules, such as found in VGOs, can not enter the ZSM-5 cage. ZSM-5 is

considered to be a medium pore zeolite, compared to the Y-zeolite, which is known

as a large pore zeolite.

ZSM-5 also has significantly fewer aluminum atoms in the cage structure than the

Y-zeolite, hence it has higher SiO2/ Al2O3 ratios. Depending on the zeolite synthesis

procedure, ZSM-5 type zeolites, as produced, can have SiO2/ Al2O3 ratios in the 30

-50 range (the most common range) up to a 300 – 500 ratio. The latter are

commonly designated as Silicalites, since they are nearly 100% silica. Despite the

fact that these zeolites have very few aluminum atoms in the cage structure, and

hence, very few active sites, they still have surprisingly good activity.

ZSM-5 mainly cracks the larger olefinic molecules (C7= to C12=) in the gasoline

range, reducing them to smaller olefins, mainly C3= and C4=, with C3=/ C4= ratios

typically > 1. Some ethylene is also produced from the cracking of the large

gasoline molecules. At typical FCC riser temperatures, ZSM-5 does not crack the

saturated paraffins nor the aromatics in the gasoline boiling range.

Since the high molecular weight , paraffinic molecules in gasoline are low octane

components, removing them via ZSM-5 cracking, with the corresponding

concentration of aromatics, results in an increase in gasoline octane, both RON and

MON. Consequently, in the 1980s, ZSM-5 containing additives were used to

enhance gasoline octane. They did, however, have the disadvantage of reducing

the yield of gasoline.

157048 Catalyst Page 24

As the demand for propylene increased in the 1990s, ZSM-5 additives began to be

used to increase the yield of FCC derived C3=. That trend has continued to

accelerate in the 21st century. Placing a high concentration of ZSM-5 crystalline

zeolite into the FCC catalyst blend can produce high C3= yields. Yields of up to 20

wt% C3= can be achieved with the proper feed and operating conditions, compared

to a C3= yield of 3-4% at conventional FCC conditions.

Catalyst suppliers are actively working to produce more effective ZSM-5 additives.

The additives produced in the 1980s typically contained 10% ZSM-5 crystalline

zeolite. As the demand for C3= increased, the need arose for FCC catalyst blends

containing higher amounts of ZSM-5. However, using large quantities of the 10%

additive resulted in a dilution of the base Y-zeolite catalyst. Since only the Y-zeolite

could crack VGO, the dilution resulted in an unacceptable loss of VGO cracking

activity. Additives containing higher contents of ZSM-5 were developed. A second

generation of additives containing 25% ZSM-5 was provided to the industry. Going

higher in sieve content and maintaining adequate attrition resistance proved to be

difficult, but eventually that problem was resolved. Additives containing 40% ZSM-5

with good attrition resistance are now available. Catalyst suppliers are now working

on developing a single particle catalyst which contains both a Y-zeolite and a

ZSM-5 zeolite.

Today’s ZSM-5 additives are modified by the addition of phosphorous to the zeolite.

Phosphorous combines with aluminum atoms in the zeolite crystal structure,

through an oxygen bond, and enhances the stability and acidity of that alumina site.

Catalyst suppliers now routinely include the equilibrium catalyst phosphorous

content on their equilibrium catalyst report. Knowing the phosphorous content of the

fresh additive allows the refiner to tract the amount of ZSM-5 additive in their

equilibrium catalyst blend.

A typical set of results for increasing amounts of ZSM-5 additive is shown in

Figures 11 and 12.

157048 Catalyst Page 25

Figure 11

Effect of ZSM-5 on Product Yields

0

2

4

6

8

10

12

14

16

18

20

0 0.5 1 1.5 2 2.5 3 3.5

ZSM-5 Crystal Content in FCC Catalyst - wt%

C2=

, C

3=,

& C

4= Y

ield

s -

wt%

30

32

34

36

38

40

42

44

46

48

50

Gas

oli

ne

Yie

ld -

wt%Gasoline →

Butylenes

Propylene

Ethylene

157048 Catalyst Page 26

Figure 12

Effect of ZSM-5 On Gasoline Octane

157048 Catalyst Page 27

The Matrix

The matrix is defined as the entire catalyst particle except the zeolite. Its function is

to provide catalyst hardness, as well as to adjust the catalyst activity to the proper

level by diluting the zeolite, and to provide some special properties, such as

bottoms cracking activity and metals traps.

Zeolites have one major drawback: their porosity. The pore opening is too small

(7 to 8 Å) to allow the large molecules with high molecular weight to enter the

zeolite cage. For this reason, some precracking must occur before the zeolite can

play a major role.

To some extent, the zeolite itself can provide this precracking function. The zeolite

has some external, active surface area that can be reached through the large inert

pores provided by the kaolin-silica binder matrix. Some mesopores in the 20 to 50 Å

region are also created within the zeolite as a result of sieve collapse. These

mesopores can then provide some access to the zeolite interior. Consequently, the

zeolite itself can precrack a large percentage of the paraffinic molecules in the feed.

The large, multi-ring aromatic molecules create a more-difficult problem.

Active Alumina Matrix

The active alumina matrix component provides the catalyst with the ability to crack

these large molecules. As seen in Figure 13, the active alumina matrix provides

significant surface area and hence active sites in the 50 to 200 Å region. These

pores are sufficiently large to provide easy access to the large molecules and thus

allow precracking to occur.

157048 Catalyst Page 28

Figure 13 Effect of Matrix on Pore Size Distribution

When precracking is insufficient, as it usually is when no active alumina matrix is

present, too few intermediate products are fed to the zeolite, and the zeolite tends

to overcrack these intermediates. The net result is a loss in LCO yield (poor LCO

selectivity). Thus, the addition of an active alumina matrix benefits LCO selectivity,

and the benefit is greater for an aromatic feed than for a paraffinic feed (Figure 14).

Figure 14

157048 Catalyst Page 29

Effect of Matrix on LCO Yield

The typical active alumina matrix achieves its activity to a large degree through Lewis acid sites. These sites are well known to cause coke and H2 formation. Thus,

the selectivity achieved via active alumina cracking is expected to be substantially

poorer than with zeolitic cracking. This reaction occurs for both paraffinic feeds and

aromatic feeds (Figures 15 and 16).

Figure 15

27

20

Aromatic Feed@ 60% Conversion

Matrix Area, m2/g

25

23

21

19

17

1540 60 20 100 120 140 160

LC

O, w

t-%

Paraffinic Feed@ 75% Conversion

157048 Catalyst Page 30

Effect of Matrix on Coke Yields

5.2

20

Aromatic Feed

Matrix Area, m2/g

4.4

3.6

2.8

2.0

1.240 60 20 100 120 140

Cok

e, w

t-%

FF

Paraffinic Feed

157048 Catalyst Page 31

Figure 16 Effect of Matrix on Dry Gas Yields

157048 Catalyst Page 32

Catalyst Contaminants and Poisons

Contaminant Metals (Coke and H2 Production)

A number of metals typically found in FCC feed are deposited on the catalyst.

These metals, including nickel, vanadium, copper and iron can catalyze unwanted dehydrogenation reactions to produce large quantities of coke and H2. Nickel is

typically the strongest dehydrogenation catalyst of these metals. Vanadium

generally considered to be ¼ as strong. Iron, which originates as organically bound

iron in the hydrocarbon molecules of the feed, deposits on the catalyst and is an

active dehydrogenation agent. However, most of the iron deposited on the catalyst

originates from equipment scale and is inactive. The combined iron content, which

is thus relatively inactive, is typically considered to be approximately 1/10 as strong

a dehydrogenation agent as nickel. Copper has as much dehydrogenation activity

as nickel but is usually present in much smaller amounts.

A frequent method for expressing the combined contaminant potential of these metals is through the use of an equivalent nickel value, where: EqNi = Ni + Cu + V/4

+ Fe/10. Since Copper is usually present in very low quantities and iron is such a

weak dehydrogenation catalyst the equivalent nickel is often expressed simply as Ni

+ V/4.

The ratio of hydrogen to methane is an indication of metals catalyzed dehydrogenation reactions. A sponge absorber off gas H2/C1 ratio for

uncontaminated catalyst should be 0.1 to 0.3. A figure of 1.0 or greater would

indicate metals contamination.

One method of evaluating the effect of contaminant metals on catalyst selectivity is

to monitor the equilibrium catalyst performance in a standardized laboratory test (see page 61) as the metals content changes. Some typical catalyst coke and H2

responses to increasing equilibrium catalyst (E-cat) metal contamination are shown

in Figures 17 and 18. As seen in these figures, the response varies significantly

from catalyst to catalyst.

157048 Catalyst Page 33

Figure 17 Effect of Metals on Coke Factor

Figure 18

Effect of Metals on H2 Factor

3.0

1,000

2.5

2.0

1.5

1.0

0.52,000 3,000 4,000 5,000

C atalystFAB

Equivalent N ickel (N i + V /4), w t-ppm

Cok

e F

acto

r of

Eq

uil

. Cat

alys

t V /N i3.32.40.5

C atalyst F

C atalyst A & B

8 .0

7 .0

6 .0

5 .0

4 .0

3 .0

2 .0

E q u iva len t N ick el (N i + V /4 ), w t-p p m

H2

Fac

tor

of E

qu

il. C

atal

yst

C a ta lyst F

C ata lyst B

C ata lyst A

C ata lystFAB

V /N i3 .32 .40 .5

1 ,000 2 ,000 3 ,000 4 ,000 5 ,000

157048 Catalyst Page 34

Extrapolation of Figures 17 & 18 would indicate that nickel levels above 10,000

ppmw would result in totally unacceptable H2 and Coke Factors. Recent experience

has shown that these factors do not continue to increase linearly with increasing

nickel content. Rather, as seen in Figure 19, they reach an upper limit, which

depends upon catalyst design. It is believed that there is a limiting catalyst surface

area for supporting the deposited nickel. Once the metal has covered the available

area, additional metal deposits on top of already deposited metal and does not

generate any additional catalytic metal surface area.

Figure 19

Effect of Nickel Upon E-Cat H2 & Coke

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

0 5000 10000 15000 20000 25000

Nickel on E-Cat - ppmw

E-C

at H

2 Y

ield

- w

t%

0

0.5

1

1.5

2

2.5

3

3.5

4

4.5

E-C

at

Co

ke

Yie

ld -

wt%

Coke

Hydrogen

Metals Passivation

The FCC feed additives that form chemical complexes with nickel have been

successful in reducing the dehydrogenation activity of nickel. Antimony compounds,

which have been in use for more than 30 years, are effective chemical additives.

157048 Catalyst Page 35

Data showing the reduction in H2 yield as a result of using antimony are shown in

Table 1.

Bismuth-containing additives have also been found to reduce the dehydrogenation

activity of nickel. Although somewhat less effective than antimony, the bismuth

additives have the advantage of being less of a concern from an environmental

point of view.

TABLE 1

HYDROGEN YIELD DECREASE EXPERIENCED BY PHILLIPS LICENSES USING METALS PASSIVATION

Hydrogen Yield, SCFB FF

License

Catalyst 4 Ni + V,

Ppm

Unpassivated

Passivated

% Charge

1 3,600 92 58 37

2 16,200 202 104 49

3 6,540 64 21 67

4 10,820 126 62 51

5 8,800 87 55 37

6 6,140 161 103 36

7 8,300 105 85 19

8 10,800 71 19 73

9 9,300 159 109 31

Average 44

Reference: W.C. McCarthy, et al. Paper No. 13, Katalistiks 3rd FCC Symposium, 1982.

157048 Catalyst Page 36

Perhaps the most-active area in catalyst development in recent years has been the

development of active matrices that minimize the adverse effect of metals. One

advancement has been achieved through pore-structure adjustments and alteration

of the surface chemistry of the aluminas, using a large-pore boehmite alumina.

Such a matrix alumina is believed to encapsulate the nickel, so that the nickel

surface is no longer exposed and cannot make contact with the hydrocarbons to

catalyze dehydrogenation. With this technology, antimony additives provide only a

small additional benefit. Equilibrium catalyst material data illustrating the

performance of such a nickel trap are seen in Figure 20.

Figure 20 Catalyst Performance with Nickel Trap and

Antimony

0.25

0

Without Nickel Trap & with Sb

Nickel, ppm (thousands)

1 2 3 4 5 6 7

H2

Yie

ld, w

t-%

V=1,000-2,000wt-ppm

With Nickel TrapWith Sb

Without Sb

{

0.20

0.15

0.10

0.05

157048 Catalyst Page 37

Contaminant Metals (Catalyst Deactivation)

Vanadium destroys the zeolite. In the presence of steam and high temperature

(regenerator conditions), vanadium forms vanadic acid, a highly mobile compound

that moves freely across the catalyst surface. It reacts with the aluminum in the

zeolite structure to form a low melting point eutectic compound that causes the

crystal structure to collapse. This collapse destroys activity. A typical example of the

effect of vanadium on equilibrium catalyst activity is shown in Figure 21.

Figure 21 Effect of Vanadium on Catalyst Activity

Vanadium traps have also been an area of considerable R&D activity. One family of

vanadium traps that appeared to have great promise was the titanate family,

particularly barium titanate. Laboratory testing in 1984-1985 indicated that catalysts

containing a barium titanate metals trap could sustain high levels of vanadium with

70

3,000

Vanadium Content of Equilibrium Catalyst, wt-ppm

3,500 4,000 4,500 5,000 5,500 6,000 6,500 7,000

Eq

uil

ibri

um

Cat

alys

t M

AT

Act

ivit

y

68

66

64

62

60

58

56

54

52

Catalyst Addition Rate~ Constant at 1.7%of Inventory/Day

157048 Catalyst Page 38

little loss in activity and with little increase in H2 and coke production. Unfortunately,

when placed in actual commercial use, the titanates appeared to be sensitive to

sulfur poisoning and have not lived up to their laboratory performance. As yet, they

have shown little trapping capability in refinery use.

Rare-earth-based vanadium traps, which are much less susceptible to permanent

sulfur poisoning, have been considerably more successful in commercial refinery

use. This technology, which was originally commercialized by Katalistiks in the late

1980s, is now being used by Grace, designated as their RV technology. Grace

catalysts that incorporate the RV trap are called “Residcats.” The RV trap can be

used either as a separate additive or incorporated into the cracking catalyst particle.

Because of its high mobility, vanadium readily jumps from particle to particle,

seeking those particle locations where it has a high affinity. Separate particle

vanadium traps thus work nearly as well as in-catalyst traps. An illustration of the

effectiveness of the rare earth vanadium trap is given in Figure 22.

Figure 22 Effect of Vanadium Trap

1,000 2,000 3,000 4,000

Vanadium on Equilibrium Catalyst, wt-ppm

Base Case

VanadiumTrap

70

72

68

66

64

62

60

58Eq

uil

ibri

um

Cat

alys

t M

AT

Act

ivit

y

157048 Catalyst Page 39

Sodium and other alkalis or alkaline earths such as calcium, potassium and lithium

are strong catalyst poisons which can have an immediate and significant impact on

catalyst activity. Sodium is usually present in the feed as salt resulting from

operational problems in the crude unit desalter or from purchased feeds from

tankers. Poor steam quality can also be a source of these contaminants. An

increase in sodium of just 0.1 wt% can cause a drop of up to 3 numbers in catalyst

activity.

Iron is another potential catalyst poison in high concentrations. If enough iron

accumulates on the surface of the catalyst the access to the active catalyst sites

may be blocked resulting in lower effective catalyst activity. Several units have

reported significant loss in catalyst activity when the iron on the equilibrium catalyst

exceeds ~3000 – 5000 wt ppm above the fresh catalyst iron level.

Basic nitrogen compounds in the FCC feed are temporary poisons that bond with

the active acid sites making them inaccessible for cracking reactions. The nitrogen

is oxidized off the catalyst during regeneration and leaves as NOx compounds in

the regenerator flue gas. The deactivation effect, thus, lasts only as long as the

basic nitrogen compounds are present in the feed. Typically, basic nitrogen

compounds make up about 1/3 of the total nitrogen compounds in the feed.

Coke can also be considered as a temporary catalyst poison, which sits on the

catalyst active sites and is removed during regeneration. If coke is not completely

removed during regeneration, a loss in actual catalyst activity will result. Typically a

loss of 1.0 – 1.5 activity numbers occurs for every 0.1wt% coke left on the catalyst.

Note that the activity numbers reported on a catalyst vendor’s equilibrium catalyst

report are determined after any remaining carbon is burned off. If the catalyst

leaving the regenerator does have a significant amount of unremoved coke, the

reported activity on the equilibrium catalyst sheet will thus not reflect the actual

lower, working activity in the reactor.

157048 Catalyst Page 40

CATALYST ADDITIVES CO Combustion Promoters

In the early 1970s, researchers discovered that certain Group VIII metals,

particularly platinum, can be incorporated into an FCC catalyst system at low

concentrations (13 wt ppm) to catalyze the combustion of CO to CO 2 effectively.

Of even greater importance was their discovery that at this low incorporation, the

Group VIII metals did not catalyze undesirable dehydrogenation reactions during

the cracking reaction. The cracking-selectivity characteristics achieved by the

cracking catalyst in use in the FCCU are thus not altered when such a CO

combustion promoter is added to the catalyst inventory.

The use of 12 ppm platinum in FCCU circulating catalyst inventories is now widely

practiced throughout the world to catalyze the combustion of CO to CO2 in the

FCCU regenerator. The promoter is added to the FCC catalyst inventory either as

an integral part of the fresh FCC catalyst, where it is included in the fresh catalyst at

12 wt ppm, or as a separate additive. The additive, which typically contains

5001000 wt ppm of platinum, is added to the FCCU by a small metering system

that is independent of the fresh cracking-catalyst addition system. In the United

States, the separate additive approach is generally used; in Europe, the additive is

most commonly incorporated with the fresh cracking catalyst.

Through the use of a combustion promoter, CO combustion occurs readily in the

dense phase at temperatures well below 700C (1292˚F). It has been reported that

promoted CO combustion occurred as low as 650C (1202˚F) in a commercial

FCCU operation.

Promoted combustion has a number of important benefits. First, the afterburn

problem, i.e., burning in the dilute phase, is greatly reduced. By consuming CO in

the dense phase, the potential heat release from burning in the dilute phase is

significantly decreased. A commercial example of a 90F reduction in regenerator

afterburn by using a CO combustion promoter is as follows:

157048 Catalyst Page 41

Without promoter With promoter

Typical flue gas temperature, ºF 1290 1220

Typical dense phase temperature, ºF 1225 1245

Afterburn ΔT, ºF + 65 - 25

The increased flexibility of FCCU operations resulting from using a CO combustion

promoter is an even greater advantage. When using a promoter, the air rate to the

regenerator can be varied to achieve any degree of CO combustion that is desired.

By this mechanism, heat can readily be added to or removed from the regenerator

to produce changes in regenerator temperature, catalyst circulation rate, coke yield,

and reactor feed conversion.

In actual practice, the regenerator temperature is normally controlled at the

maximum temperature allowed by the regenerator metallurgy. Variations in feed

quality in the FCCU can result in significant regenerator temperature excursions if

the degree of CO combustion is unchanged (constant heat of combustion). With a

CO combustion promoter present, the degree of CO combustion can be varied to

hold the regenerator temperature constant at the desired maximum value even

though significant changes in feed quality have occurred. This flexibility is achieved

mainly through regenerator air rate control. To a lesser degree, additional flexibility

is achieved by controlling the addition rate of fresh CO combustion catalyst to the

catalytic cracker. When a CO combustion promoter is used, changes in the air rate

affect the amount of CO converted to CO 2 both in the dilute and in the dense

phase. Changing the amount of CO burned in turn affects both the dense- and

dilute-phase temperatures. Increasing the amount of excess O2 in the regenerator

causes an increase in CO burning in the regenerator dense phase as indicated by

an increase in dense-phase temperature. Additional burning in the dilute phase also

occurs, causing an increase in T (afterburning) between dense and dilute phases.

As a typical example, a decrease in CO content in the regenerator flue gas from 5

to 3 vol % would result in a dilute-phase temperature increase of 55˚F, a dense-

phase temperature increase of 29˚F, and an increase in dilute-dense T of 26˚F.

157048 Catalyst Page 42

The amount of promoter used can also be a variable in influencing the degree of

CO combustion. A promoted catalyst system can be classified as fully or partially

promoted. A partially promoted system is one in which an increase in promoter

content results in a decrease in the dilute-dense T. Conversely, a fully promoted

system sees no effect on afterburn T when the promoter level is changed. An

increase in the promoter content increases the proportion of CO that is burned in

the regenerator dense phase, and decreases the dilute-dense T, as seen in

Figure 23 . The change in dilute-dense T is mainly because of changes in the

dilute-phase temperature. Changes in promoter concentration have only a small

effect on dense-phase temperature but greatly affect dilute-phase temperatures.

Figure 23

Additives to Reduce Sox in Regenerator Flue Gas

Recently, governmental regulations, particularly in the United States, have

significantly reduced the allowable FCCU emissions for sulfur oxides. A new 50

MBPD unit or an existing 50 MBPD unit being significantly revamped in 2002 would

be required to meet <0.7 t/d of sulfur oxides in the regenerator flue gas.

157048 Catalyst Page 43

Currently, many refiners find that the use of a SOx adsorbing additive is the most

effective way to comply with the EPA regulations.. With such an additive, the

following steps occur:

SO 2 is oxidized to SO3 in the regenerator:

2 SO2 + O2 → 2 SO3

SO3 is adsorbed in the regenerator by the SOx additive

SO3 + MO → MSO4

MO = metal oxide and M is most commonly magnesium:

The metal sulfate is reduced in the reactor

MSO4 + CH4 → MS + CO2 + 2 H2O

Release of H2S is released in the stripper

The metal oxide adsorbent is regenerated

MS + H2O → MO + H2S

The H2S is carried out with the reactor products, goes through the product-recovery

system of the FCCU, and eventually to further processing for sulfur recovery. The

metal oxide adsorbent recirculates with the spent cracking catalyst back to the

regenerator for the next SOx adsorption cycle.

The first commercially effective metal oxide adsorbent consisted of a solid solution

of a pure magnesium aluminate spinel (MgAl2O4) with MgO. Such a solid solution (

Mg2AlO5) does not destroy the spinel framework. The adsorption activity of the

dispersed MgO in the spinel is much greater than that of pure MgO itself.

Cerium is effective in oxidizing SO2 to SO 3. Consequently, a cerium-impregnated

Mg2Al2O 5 actively converts the SO 2 to SO3, which is then strongly adsorbed by the

dispersed MgO as MgSO4. A completely cyclic SOx removal catalyst contains, in

addition to the above component, a fourth metal component such as vanadium to

catalyze the conversion of MgSO4 to MgO.

Multifunctional SOx removal catalyst systems have been in commercial use since

1985 in the United States. Such systems have successfully reduced SOx

157048 Catalyst Page 44

emissions in the FCCU regenerator by typically 20-60%, with reductions up to 90%

reported. Additive levels in the circulating catalyst inventory range from 1-10%. The

additive level and the amount of SOx reduction depend on conditions, such as feed

quality, the presence or absence of a CO combustion promoter, regenerator

temperature, regenerator mixing efficency, and excess O2 content.

Hydrotalcite, a MgO/Al2O3 containing compound, has also been found to have SOX

adsorbent capability and is now being used in some SOX adsorbent additives.

Recently, both spinel and hydrotalcite types of SOx reduction technology have been

upgraded to higher performance standards, frequently by the addition of more

magnesium oxide component.

Because O2 is necessary to convert SO2 to SO3, decreasing O2 in the regenerator

has been found to reduce the effectiveness of the SOx removal additive. The SOx

additives used in regenerators operating in a partial CO combustion mode, where

excess O2 is frequently limited to 0.2vol in the flue gas, are less successful in

reducing SOx. In such cases, SOx removal is typically 2030% less than for a full

CO combustion ( 1+ excess O2) case. Additives to Reduce NOx in Regenerator Flue Gas

NOx (nitrous oxides ) emissions are now recognized as a significant contributor to

photochemical smog and acid rain, and therefore have come under greater

regulatory scrutiny than in the past. In terms of tons emitted per year, the FCCU

regenerator is one of the largest point source of NOx emissions. Only a small

portion of the NOx present in the flue gas is produced through the oxidation of N2 in

the regenerator air stream. The main source of the NOx comes from the

combustion of organic nitrogen, originating in the FCC feed of which approximately

50% ultimately reaches the regenerator section in the coke. However, only 5% to

20% of the organic nitrogen compounds entering the regenerator end up as NOx,

predominantly NO. The remainder is converted to N2. Since most of the organic

nitrogen ends up as N2, there is likely a secondary reaction with CO or coke to

reduce NO to N2. Although feed nitrogen is the source of NOx, researchers have

found that final NOx concentrations are due more to the type of N in the feed and to

157048 Catalyst Page 45

the regenerator conditions, than they are to the absolute content of N in the feed.

The amount of excess oxygen may have a more direct correlation with the final NOx

concentration leaving the regenerator. Increasing the O2 in the regenerator flue gas

from 0.1 to 1.6% has been reported to double NOx emissions when no CO

combustion promoter is present. Adding a platinum-based combustion promoter,

which increases the available atomic oxygen, can increase the NOx content much

more.

An emerging picture of the complex NOx chemistry in the FCCU regenerator

includes the following reaction networks:

Pyrolysis Oxidation

N (Coke) HCN N2, NO, N2O

N (Coke) NH3 N2, NO, N2O

NO Reduction

2NO + 2 CO coke N2 + 2 CO2

NO + CFAS* 1/2N2 + CO * FAS = Free Active Surface

The use of platinum based CO combustion promoters, which decrease the CO

concentration in the regenerator, have been found to result in increased NOx

emissions. It is also believed that platinum promotes the combustion of HCN, further

increasing NOx.

Catalyst additives have had mixed results in reducing flue gas NOx emissions.

Recent research in NOx additives has taken two approaches: the development of

CO combustion promoters that do not catalyze NOx formation and additives that

directly reduce NOx emissions. Non-platinum combustion promoters such as

palladium and cerium on alumina have had some success. Copper on alumina has

had some success in converting NOx to N2.

Additives to Reduce Sulfur in Gasoline

157048 Catalyst Page 46

The latest additive development has been directed at reducing the sulfur content in

gasoline, which is believed to be largely due to the presence of thiophene and

alkylated thiophenes in the FCC gasoline. The additives are intended to

dehydrogenate the thiophenes which then can crack, releasing H2S. Zinc based

catalysts on an alumina support have had mixed results.

CATALYST SELECTION

An enormous amount of flexibility is available in the design of FCC catalysts. The

catalyst designer can choose from a large variety of zeolites. Depending on the

zeolite chosen, the designer can vary the amount of zeolite, the type of ion

exchange, and the type of active matrix and can include metals traps or additives.

This complexity is illustrated in Figure 24. Each unique combination of these factors

provides a uniquely different result, and each has some specific positive and some

negative benefits. Catalyst suppliers are continuously working to improve the

catalyst to provide more flexibility to meet the specific needs of each individual

refiner.

The catalyst advancements are mainly related to improved coke and gas selectivity

in the presence of contaminant metals and in the presence of increased matrix

activity for better bottoms cracking and LCO selectivity.

Because of the wide variability in catalyst options and the individuality of each

refinery's situation, generalizing as to which catalyst is best should be avoided. The

choice is best arrived at when the refiner and catalyst supplier work closely together

to take advantage of the catalyst flexibility available. UOP can also assist in this

selection process by providing an assessment of the various catalyst options based

on commercial experience in other UOP units and on standardized testing in UOP

pilot plants.

157048 Catalyst Page 47

Figure 24

Catalyst Formulation

Plus Rare Earth Variations Variations in Total Sieve Content Combustion Promoter Bottoms Cracking Additives Environmental Additives

Low-Activity Matrix

Active AluminaMatrix

Nickel Trap

Vanadium Traps

ReHY

USY

Other ZeoliteTreatments

ZSM-5

157048 Catalyst Page 48

TIME AND TEMPERATURE EFFECTS

High temperatures in the presence of steam will result in loss in catalyst activity.

This condition exists in the regenerator where steam is formed as a result of

burning the hydrogen in the coke and in the lift zone of the reactor. The rate of

hydrothermal deactivation is relatively slow at temperatures below 1300 ºF (700 ºC)

and increases rapidly at temperatures greater than ~1350 – 1400 ºF (730 – 760 ºC)

although thermal stability varies from catalyst type to catalyst type. Generally,

hydrothermal deactivation in the FCC unit is minimal because the temperatures are

typically lower than 1350 ºF (730 ºC). Steam used in the reactor for feed

atomization and spent catalyst stripping does not contribute significantly to

hydrothermal deactivation because of the relatively low temperatures in the riser

and stripper. For a given catalyst over a set period of time (say one hour), a

graphical representation of the resultant catalyst activities at various temperature

levels is shown in Figure 25.

Figure 25 Catalyst Hydrothermal Deactivation

60

65

70

75

80

1350 1400 1450 1500 1550Deactivation Temperature, ºF

5 hours - 100% Steam

M.A

.T. Conve

rsio

n, w

t%

Catalyst A

Catalyst B

Catalyst C

157048 Catalyst Page 49

Use of torch oil can also result in thermal deactivation if the oil is not properly

atomized.

CATALYST MANAGEMENT

The type of catalyst used in a particular FCC unit depends on feedstock properties,

the desired product make, and unit bottlenecks. The choice of catalyst should be

made after careful study of all factors, including cost. Any catalyst changeover will

take significant time to be effective. Varying feedstocks and operating conditions

may also change yields and cloud the results of catalyst changes.

Fresh catalyst is typically added to the unit for two reasons:

1. To maintain catalyst quality. 2. To replace physical losses.

If the unit holds catalyst well, it may be necessary to withdraw equilibrium catalyst

and add fresh to maintain a desired activity. If the catalyst has been damaged by

excessive use of steam or torch oil, or contaminated by metals, it may be necessary

to increase the catalyst makeup rate.

The desired catalyst activity is based on several factors, the first of which is

economics. The refiner should examine.

1. Relationship between yield and activity. 2. Value of any extra conversion. 3. Rate of catalyst degradation at higher yields. 4. Ability of downstream units to handle extra conversion. 5. Cost of catalyst.

The addition of fresh catalyst should be done as evenly as possible. There are a

variety of continuous loaders on the market which make this quite easy.

157048 Catalyst Page 50

If a large batch of fresh catalyst is added too quickly, the relative activity increase

may cause overcracking with lower gasoline and higher dry gas yields.

The unit should be monitored with plots to follow:

1. Catalyst activity. This is normally done weekly by the catalyst supplier.

2. Makeup and withdrawal rates.

3. Reactor and regenerator temperature.

4. Conversion levels and product yields. 5. H2/C1 ratio – This will indicate possible metals poisoning.

These procedures are required for routine monitoring of the unit. Moreover, without

them, it is impossible to make intelligent decisions on catalyst management.

It may be necessary to add catalyst to make up physical losses. These can be due

to excessive or improper steam usage, equipment damage – such as a bypassed

cyclone If catalyst losses are severe, or fresh catalyst addition is not desirable,

equilibrium catalyst can be added, either from a newly purchased stock or from on-

hand stock.

In some units, low metals equilibrium catalyst is added to replace higher metals

catalyst from the inventory. This is an effective way to reduce the levels metals and

therefore minimize the negative effects of the metals without the high cost of adding

large amounts of fresh catalyst. This is especially true in units with resid feed stocks

which are typically higher in metals than VGO.

Catalyst loading and use should be reviewed periodically to ensure proper unit

operation. This review should normally be done about every two months. If there

are special problems such as metals, the policy will have to be reviewed more

often. Care should be taken, however, that other factors such as different

feedstocks do not lead to hasty, inappropriate decisions.

157048 Catalyst Page 51

CALCULATION OF FRESH CATALYST ADDITION RATE

The fresh catalyst addition rate is a critical factor in the operation of an FCC unit

and in maintaining a desired catalyst activity. The following sample calculation

illustrates a method of approximating the addition rate to achieve a desired activity.

Basis of calculation:

1. Fresh catalyst activity is 79.

2. Equilibrium catalyst activity is 69.

3. Desired catalyst activity is 73.

4. Present addition rate is 2.5 short tons/day.

5. Unit inventory is 200 short tons.

6. Catalyst retention factor is 0.80.

The retention factor is an index attrition number which accounts for the weight

fraction of fresh catalyst that is not lost from the regenerator during loading.

Generally, the retention factor will vary from 0.70 to 0.80 depending on the specific

catalyst.

1. Calculate average catalyst age

ACA = INV/CAR

where: ACA = Average catalyst age in days

INV = Unit inventory in short tons

CAR = Present catalyst addition rate in short tons per day

157048 Catalyst Page 52

In our sample calculation:

ACA = 200 tons/2.5 tons per day = 80 days

2. Calculate the deactivation constant

DC = [LN ( FCA ) - LN (ECA)] /ACA

where: DC = Deactivation Constant

FCA = Fresh Catalyst Activity

ECA = Equilibrium Catalyst Activity

ACA = Average Catalyst Age in Days

In our sample calculation:

DC = [LN (79) - LN (69)]/80

DC = 0.00169

3. Calculate the new catalyst addition rate

NAR = [INV x DC x RF]/[LN (FCA) - LN (DCA)]

where: NAR = New Catalyst Addition Rate in short tons per day

INV = Unit Inventory in Short Tons

DC = Deactivation Constant

RF = Retention Factor

FCA = Fresh Catalyst Activity

DCA = Desired Catalyst Activity

In our sample calculation:

NAR = 1200 x 0.00169 x 0.80]/lLN (79) - LN (73)

NAR = 3.43 short tons per day

157048 Catalyst Page 53

4. Calculate the time required for 75% turnover at the new addition rate.

Inventory Turnover = - LN 1 - PCT

100

INV / NAR RF

where: PCT = Percent Turnover desired

NAR = New Catalyst Addition Rate in short tons per day

RF = Retention Factor

In our sample calculation:

Time Required for 75% Inventory Turnover

= - LN 1 - 75

100

200 / 3.43 0.80

= 101 days

157048 Catalyst Page 54

CALCULATION OF METALS ON EQUILIBRIUM CATALYST

Excessive metals concentration on equilibrium catalyst results in undesirable

dehydrogenation reactions and loss of catalyst activity. The following sample

calculation outlines a method of predicting the current metals concentration on

catalyst.

BASIS:

Feed Rate 20,000 BPD

Feed Specific Gravity 0.9042

Metals in Feed 3 ppm

Catalyst Addition Rate 2.5 Short Tons/day

Metals on Catalyst Addition ppm

Initial Metals on Equilibrium Catalyst 1,000 ppm

Equilibrium Catalyst Inventory 200 Short Tons

Find metals concentration after 100 days of operation at the above conditions.

EMF = EMI - FCM - 0.175 SG FFR FFM

CAR

EXP -

CAR TS

INV

+ 0.175 SG FFR FFM

CAR

+ FCM

where:

EMF = Final Equilibrium Catalyst Metals Concentration in ppm

EMI = Initial Equilibrium Catalyst Metals Concentration in ppm

FCM = Catalyst Addition Metals Concentration in ppm.

SG = Feed Specific Gravity

FFR = Feed Rate in BPD

157048 Catalyst Page 55

FFM = Metals Concentration on Feed in ppm

CAR = Catalyst Addition Rate in Short Tons per Day

INV = Reactor/Regenerator Catalyst Inventory in short tons

TS = Time Period in Days

EMF = 1000 - 0 - 0.175 0.9042 20000 3

2.5

EXP -

2.5 100

200

+ 0.175 0.9042 20000 3

2.5

+ 0

EMF = 2996 ppm

CATALYST PROPERTIES AND TESTING

Catalyst manufacturers routinely test for their customers catalyst samples taken

from the FCCU circulating catalyst inventory. These are referred to as equilibrium

catalyst samples, or E-cat samples. Samples are taken generally on a weekly or bi-

weekly basis, but, in special situations, can be taken more frequently. Samples are

also sometimes taken of the fines leaving the FCCU, when the FCCU appears to

have a catalyst loss problem. The evaluation report which a catalyst manufacturer

prepares contains valuable information that provides the refinery with a better

understanding of the unit operation and enables him to improve the operation of the

FCC unit. If the FCCU is having problems, the E-cat data can tell the refiner if the

problems are related to deteriorating catalyst performance or whether he should

look to mechanical problems in the unit.

At present, there are no standard catalyst testing procedures used by the various

catalyst manufacturers. Results for the same sample will most likely differ from one

laboratory to another. Catalyst reports are more useful as trend indicators than as

reliable guides based on their absolute values.

157048 Catalyst Page 56

A catalyst test report will include information on the physical, chemical, and catalytic

properties of the equilibrium catalyst.

Under the category of physical properties, information will frequently be found on:

Catalyst surface area – total area, zeolite area, and matrix area

Zeolite unit cell size

Catalyst bulk density

Catalyst pore volume

Catalyst particle size distribution

Catalyst fluidization properties

Following is a description of the various tests performed by laboratories:

PHYSICAL PROPERTIES

Surface Area

The body of catalyst particles is made up of pores which contain the active sites

where the cracking reactions occur. Nearly all (90 – 95%) of the catalyst's surface

area is internal. The total surface area, measured in square meters per gram of

catalyst, is made up of two components, the zeolite surface area and the area of the

material around the zeolite, known as the matrix surface area.

The zeolite surface area is the larger of the two and is a good indicator of the

catalyst activity. The zeolite surface area measures the area within the pores of

about 50Ǻ or less. The matrix surface area measures the surface area in the pores

> 50Ǻ, which provide the channels through which the hydrocarbons can reach the

zeolite. The active alumina incorporated for bottoms cracking is found in this higher

pore range.

Surface area is measured by nitrogen adsorption at very low pressure. Total

surface area is typically determined by the BET method which measures adsorption

at a single pressure. Matrix surface area is determined by the t-plot method, which

157048 Catalyst Page 57

measures adsorption over a wide range of pressures. Zeolite surface area is

typically obtained by difference.

Typical surface area values for Y-zeolite based catalysts range from 70-200 m2/gm

for equilibrium catalyst and up to 400 m2/gm for fresh catalyst. ZSM-5 has a much

lower surface area than does Y-zeolite. Unlike Y-zeolites, ZSM-5 loses little, if any,

surface area upon exposure to regenerator conditions. A ZSM-5 additive containing

25% crystalline ZSM-5 zeolite would be expected to have a surface area in the 70 -

90 m2/gm range, both in the fresh condition and in the “deactivated” condition.

Apparent Bulk Density (ABD)

The apparent bulk density of the catalyst is its density measured in grams / cc.

Fresh catalysts have ABD's ranging from 0.7-1.0 grams/cc, while equilibrium

catalysts vary from 0.75-1.0. The ABD depends upon the chemical composition,

pore volume, and particle size distribution.

Hydrothermal deactivation causes the fresh catalyst to both lose moisture content

and to shrink somewhat in size. With regard to bulk density, these are counteracting

influences. Bulk density, thus, does not change greatly due to hydrothermal

deactivation. Thermal deactivation, which can occur with an extreme regenerator

temperature excursion, does cause significant collapse of both the sieve and matrix

and hence causes a significant increase in bulk density. Monitoring the equilibrium

catalyst bulk density can provide an indication of such an event.

FLUIDIZATION CHARACTERISTICS

Some catalyst suppliers routinely test the catalyst in a fluidization test stand and

report the ratio of minimum bubbling velocity / minimum fluidization velocity

UMB /UMF. This ratio is a measure of the range of catalyst densities within which a

smooth standpipe operation is obtained. The larger the value, the better.

Particle Density

157048 Catalyst Page 58

Particle density is the weight per unit volume of catalyst. Particle density is defined

as:

Skeletal Density

(Skeletal Density Pore Volume) + 1

Particle density is always less than skeletal density. A comparison of density would

be:

Particle Density ≈ 2 ABD ≈ 1.7 CPD

Compacted Particle Density (CPD) is similar to ABD, but the catalyst is tapped until

it settles to a minimum volume.

Skeletal Density

Skeletal density is the density of the solid portion of the catalyst, exclusive of the

volume of pores or voids. The values are obtained with a pycnometer after

determining pore volume. Typical skeletal density for low alumina catalyst is 2.35

g/ml; for high alumina the density is 2.5 g/ml. The zeolites fall somewhere in

between these two.

Pore Volume

Pore volume is another indicator of the zeolite content of the catalyst. Higher pore

volume would usually indicate higher zeolite content for two catalysts of the same

type, but would not necessarily indicate higher activity. Pore volume can be determined by N2 adsorption, or by water titration. The values reported on the

equilibrium catalyst sheet are obtained from a water titration.

157048 Catalyst Page 59

The pore volume of equilibrium catalyst generally ranges from 0.2-0.5 cc/gm. The

variation here is because of the many different types of catalyst, and because of

different manufacturing techniques. Hydrothermal deactivation causes a slight

decrease in pore volume, while thermal deactivation causes a greater decrease.

Pore Diameter

This is a convention used to describe the average pore size. The assumption is

made that the pores are in the form of minute cylinders of diameter, PD, and length,

L. By definition then, the following equations apply:

SA = (PD)L

Pore Volume (PV) = (PD)2L

4

Therefore: PV

SA = L

(PD)2

4

1

(PD) L

=

PD

4

Therefore:

PD = 4 PV

SA

Using:

SA in m2/g

PV in cc/g

PD in Angstroms

The equation then becomes:

PORE DIAMETER (PD) = 4 PV 104

SA

157048 Catalyst Page 60

Attrition Resistance

The attrition resistance of catalyst is an indication of its strength and hardness. A

more attrition-resistant catalyst will erode at a lower rate as it circulates through the

unit. Each catalyst supplier has their own technique for measuring attrition

resistance. Comparing one supplier’s attrition value with another supplier’s value is

not recommended.

Typical FCCU catalyst loss due to attrition is approximately 1 wt% of the catalyst

inventory per day.

Particle Size Distribution

The fluid properties of the catalyst are largely a function of the range of particle size.

Typical particle size distributions are:

% under 20 microns 1

% under 40 microns 10

% under 60 microns 33

% under 80 microns 55

% under 100 microns 73

Average Particle Size (APS) 75 microns

The average size, in microns, of the particles contained in a catalyst sample is

determined by the 50% point on a weight distribution plot. Equilibrium catalyst

usually has an APS of 65-85 microns.

The desirable particle size distribution is the coarsest one that still gives good

fluidization. This coarse distribution will also result in minimum catalyst entrainment

with the exiting gases. The catalyst will erode with time and provide its own supply

of fines, leading to a gradual catalyst loss.

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Satisfactory fluidization demands a range of particle sizes. The percentages of

particles under 40 microns and over 100 microns are good indicators of the

performance to be expected from the catalyst. UOP FCC units are designed for

relatively coarse catalyst and normally operate quite satisfactorily with 5% or less of

particles smaller than 40 microns.

LOSS ON IGNITION

This is the amount of material which the catalyst loses after heating for a specified

period at temperatures in the range of 1000° to 1100˚F. Catalyst is usually sold on a

dry basis but shipped with some moisture present. Typical values are 10-15% by

weight. If the moisture content is too high, there may be problems with catalyst

packing in the hopper. If the value is too low, less than 5%, the catalyst has been

over dried. This could adversely affect activity and make smooth addition of fresh

catalyst difficult, due to static electricity.

CATALYTIC PROPERTIES

The catalyst's conversion ability is determined by testing in a small micro reactor

system at standard conditions. The test measures the equilibrium catalyst's activity

and selectivity. A decoked catalyst sample is used to crack a typical FCC feedstock

in a laboratory reactor. The resulting liquid and vapor products and the catalyst

coke content are analyzed and the results compared to a laboratory standard.

A catalyst activity number is reported, which is related to the conversion achieved in

the lab test, while the selectivity values relate to the catalyst's undesirable

characteristics of producing coke, light hydrocarbon gases, and hydrogen. These

data are found on each catalyst supplier’s equilibrium catalyst sheet. Each

laboratory has its own unique feed and operating conditions for this test. Although

each catalyst supplier’s reported values on the same sample will be different, their

values will not be greatly different, and changes reported from one sample to

another should be relatively the same.

157048 Catalyst Page 62

The test method does not duplicate commercial performance so the results are only

relative. By comparing the results to a standard, however, the performance of the

sample in a commercial unit can be predicted. It is important to remember that the

sample is tested after any remaining coke is burned off so in units with high carbon

on regenerated catalyst the reported activity will not correlate with the activity in the

commercial reactor.

SELECTIVITY

The selectivity values reported for an equilibrium catalyst relate its tendencies to form coke, C1-C4 gases, and hydrogen to those of a standard reference catalyst

when corrected to the same conversion. Selectivity is affected by the catalyst type

as well as varying degrees of metals contamination.

The catalyst's coking characteristic is measured by the coke factor, CF, which is

dependent on the accumulated Ni + V level. This coke factor can be used to

separate the effect the catalyst type and its accumulated metals level has on coking

from the effects due to processing conditions such as the actual FCCU feedstock's

coking tendency and the FCCU reactor temperature.

Hydrogen (H2) production is also very sensitive to the catalyst metals

contamination. The H2 producing tendency is measured by the H2/CH4 factor which

usually varies from less than one up to two for metals levels up to 1500 ppm. Some

catalyst suppliers provide a H2 yield value from their standard test.

The other selectivity value which relates to the catalyst's gas yield is the gas factor,

GF. This, like the coke factor, varies with the fresh catalyst type, but it is not as

metals sensitive as is the coke factor or the H2 value . Generally, the gas factor will

not give an increasing trend until the metals accumulation exceeds 2000 ppm. This

factor is used to separate the effect the catalyst type and its contamination has on

light gas production from FCCU processing conditions such as reactor temperature,

regenerator temperature, or the feedstock quality.

157048 Catalyst Page 63

CO COMBUSTION TEST

Some catalyst suppliers test the equilibrium catalyst for its ability to combust CO to

CO2. The reported value is given as the performance of the catalyst relative to a

catalyst that is considered to be fully loaded with a CO combustion promoter.

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PROCESS VARIABLES

INTRODUCTION

Proper control of an FCC unit requires careful balancing of many variables. Within

certain limits, the system can be controlled to provide optimum performance. The

limits, or restrictions, include feedstock quality, equipment limitations, and environ-

mental constraints.

Of primary interest is the unit enthalpy balance which results from the many unit

operating conditions. The amount of coke produced in the reactor is a direct result

of the operating conditions imposed on the unit by the operator and is relatively

independent of the feed quality. The unit yields are directly related to the quality of

the feed and the operating severity set by the enthalpy balance. As these topics are

developed in this chapter, it will become clear that many of the assumptions made

by FCC operators are incorrect and a better understanding of the relationships of

the process variables is necessary to properly predict unit operation.

REACTOR-REGENERATOR HEAT BALANCE

The most fundamental principle in the operation of the FCC unit is that in steady

state operation the reactor will produce just the amount of coke necessary for the

regenerator to burn to satisfy the reactor energy demand. This is called the heat

balance. The calculation of the heat balance is shown in the calculation section of

this book. In this section, the relationship of coke burning to coke production will be

discussed.

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The amount of energy flowing in the unit operation can be summarized as:

Energy In + Energy Produced = Energy Out + Energy Consumed

Energy In = Energy in the air to the Regenerator, raw oil, steam, and lift

gas

Energy Produced = Heat of Combustion from Coke

Energy Out = Energy in the Flue Gas, Reactor Vapor, Steam from the

Cat Cooler, Radiation Loss

Energy Consumed = Heat of Reaction, Sensible Heat of the Feed, and the Feed

Latent Heat of Vaporization

At steady state the net heat of combustion must equal the heat consumed by the

reactor. Stated mathematically:

NET HEAT OF COMBUSTION

[∆Hcomb - ∆Hair - ∆Hloss] BTU

LB COKE

MUST EQUAL

TOTAL REACTOR HEAT LOAD

[∆Hfeed + ∆Hdiluent + ∆Hrecycle + ∆HRx] FEEDLB

BTU

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The coke yield from the unit can then be written as:

WT% COKE YIELD ON FEED = 100 Hfeed + Hdiluent

+ Hrecycle + HRx BTU

LB FEED

Hcomb - Hair - Hloss BTU

LB COKE

Note that the coke yield depends on the energy balance of the unit and the only

term that represents feed quality is the heat of reaction. Thus as feed quality

changes and the heat of reaction changes, there will be a change in coke yield.

Otherwise, the coke yield is set by the operating conditions imposed by the

operator.

THE ENTHALPY OPERATING WINDOW

Let us take as an example a unit operating in full CO combustion with a heavy gas

oil feed in once-through (no recycle) operation. As shown in the calculation section,

the enthalpy changes for diluents and normal vessel heat losses are negligible, so

the coke yield equation can be simplified to:

WT% COKE = 100 H feed + H Rx

H Comb Net

The unit control variables then become the feed temperature and the reactor

temperature. The usual range of feed temperature is 350-520°F and 970-990°F for

the reactor so a table showing the enthalpy changes for these ranges is:

CONTROL VARIABLE DEPENDENT VARIABLE REACTOR TEMP. 970 - 990°F ∆H REACTION FEED TEMP. 350 - 520°F REGEN CAT. TEMP. ∆H FEED 409 - 530 BTU/LB FEED

157048 Process Variables

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Thus, the maximum range in coke yield variability for these operating ranges is

4.8-5.8 wt%. The potential change in coke yield due to any variation in dependent

variable such as heat of reaction, flue gas temperature, feed enthalpy and heat of

reaction is extremely limited. The following table shows the range of coke yields for

various variable changes.

DEPENDENT VARIABLE RANGE ENTHALPY COKE YIELD HEAT REACTION LOW/HIGH CONV. 100 - 200 4.6 - 5.5 BTU/Lb Fd REGEN TEMP. 1250 - 1400°F 3407 - 4010 5.14 - 5.39 BTU/Lb Coke H2 IN COKE 6.0 - 7.0 16547 - 17000 5.5 - 5.3 BTU/Lb Coke

The net coke yield is thus essentially independent of feed quality. The conversion

and the cat/oil ratio are the variables that change with varying feed quality. In

essence, conversion coke from the quality feed is replaced by contaminant coke

from the poor feed at a correspondingly lower conversion.

Another way to look at this balance is to look only at the components of the reactor

side heat balance.

BTU/Lb Feed %

Feed Enthalpy Requirement 530 72.6

Stripping Steam Enthalpy 5 0.68

Feed Steam Enthalpy Requirement 13 1.78

Heat of Reaction 180 24.67

Heat Loss 2 0.27

TOTAL 730 100

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Over 70% of the coke produced in the unit is used just to heat up and vaporize the

feed. Only about one fourth of the coke is used to provide the heat of reaction. As

we saw above, the heat of reaction does not vary very much from feed to feed, so

the range of coke production can be seen clearly to be limited to less than half of

25% or about 10% of its typical value. In most units this corresponds to 5.5 wt%

plus or minus 10% (5.0 to 6.05) even for wide swings in feed quality and conversion

level.

THE DELTA COKE OPERATING WINDOW

Now that the coke yield on feed is known to be set by the operating conditions in the

unit, the next important term in the heat balance is the 'delta coke'. Delta coke is the

difference in coke content between the regenerated catalyst and spent catalyst.

Another way to express this is the coke yield on feed divided by the catalyst/oil ratio.

DELTA COKE = ENTHALPY COKE

CAT/OIL (or COKE YIELD)

Since the coke yield is set by the operating conditions, the cat/oil and the delta coke

must vary proportionally opposite to each other. The delta coke term is strongly

related to the regenerator temperature and thus the product selectivities.

TRegen = TRx + C

Cp Hcomb - Hair - Hloss

where: Cp = catalyst heat capacity

∆C = delta coke

Rearranging the equation, the cat/oil ratio can be calculated knowing the

regenerator and reactor temperatures, and the coke yield from the heat balance

calculation.

Cat /Oil = Coke Yield wt%

100 Cp

H Comb Net TRegen - TReactor

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At constant operating conditions if the delta coke is changed the regenerator

temperature and cat/oil ratio will vary as follows:

DELTA COKE 0.5 0.775 0.928 1.137

REGEN TEMP °F 1250 1330 1390 1470

CAT/OIL 11.4 7.6 6.5 5.4

COKE YIELD WT% 5.7 5.91 6.03 6.18

BASIS: 980°F Rx, 350°F Feed, 190 BTU/Lb Feed ∆HRx, FULL CO

COMBUSTION, 1.0 CFR

The delta coke function therefore impacts conversion and selectivity enormously

due to its influence on regenerator temperature and corresponding cat/oil. At the

same time, since the regenerator temperature has little influence on the enthalpy

coke, the coke yield changes very little for large variations in delta coke at constant

heat of reaction.

HEAT REMOVAL FROM THE REGENERATOR BY CATALYST COOLING

Since we have just seen that the coke yield is set by the operating conditions and

not the feed quality, what can be done when a poor quality feed must be processed

and the conversion is not sufficient at the current operating conditions? At the same

time, this poor quality feed usually will result in a higher regenerator temperature as

well, causing a decline in liquid product yield. If a constant coke yield is required

due to an air blower limitation, any heat input to the reactor side must be offset by a

similar heat removal on the regenerator side. With the installation of a catalyst

cooler, the feed preheat can be increased to reduce the coke make, and a

corresponding heat removal via catalyst cooling can be done in the regenerator to

increase the cat/oil ratio and increase conversion to maintain constant coke

157048 Process Variables

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production. The overall yields can be greatly improved through the increase in

catalyst circulation. The higher E-cat activity resulting from the lower temperature

also improves the yields.

COKE YIELD FLEXIBILITY FOR OPTIMUM PERFORMANCE

The prime objective of most FCC operations is the conversion of feedstock to

gasoline and other valuable products, while minimizing the production of less

valuable products such as clarified oil and coke. The unique feature of an FCC unit

is that it supplies its own fuel, not only for the conversion to the products it

produces, but also for the fractionation of the products as well. This fuel is the by-

product of the cracking reactions left on the catalyst, commonly referred to as coke.

It has been the quest of designers not only to minimize coke on catalyst from the

cracking reactions, but to minimize coke on catalyst from other sources as well. It

has been documented that coke on catalyst can come from feed contamination

such as metals, coke added by the high boiling fraction of the feed, and by

entrainment from the catalyst circulation through the reactor stripper. The objective

is to produce the most desirable yield pattern for a given feedstock with the least

amount of coke possible. Once a unit is designed, it has a certain coke burning

capability which the operator can utilize to increase cracking severity as much as

desired for each feedstock. With heavier feeds that contain less hydrogen and

inherently produce less liquid yield volume, high coke burning capabilities are

needed and a way to increase the coke yield to improve yields is needed. The key

is to produce enough coke to increase the conversion of the feed until the optimum

yield pattern is achieved.

QUALITY AND CONDITION OF CHARGESTOCK

The typical feed to an FCC unit is a heavy gas oil, such as heavy atmospheric, light

vacuum, and heavy vacuum gas oil. The unit can accommodate a range of different

rates and types of feed within its design limitations. Typically a unit may run at

design conditions, at a higher charge rate with moderate conversion, or at low

charge rates with very high conversion levels.

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Some FCC units recycle heavy oil from the main column back to the riser. The

amount is defined by the combined feed ratio:

CFR = BPD raw oil + BPD total recycle

BPD raw oil

Typical combined feed ratios for riser cracking units operating with a higher activity

catalyst would be 1.0-1.10. Older units running on low activity catalyst could range

from 1.2 to 1.8. If the oil can be cracked on one pass and not recycled, more fresh

feed can be processed. The recycle is generally heavy material which tends to be

more difficult to crack, and when it does crack, it makes more coke and light gas

than does the fresh feed. Many refiners run only enough recycle to return catalyst

fines to the reactor from the main column. This generally means a CFR of 1.05 or

less.

Proper control of upstream units, such as the vacuum column, is essential to good

feed quality. This control is mentioned only briefly in the following discussion

because it is beyond the scope of this work, but will affect all the variables listed

below.

There are several important characteristics which are used to describe the raw oil

charge. These relate to its ease of cracking and to most potential problems. The

major elements are:

RAW OIL CHARGE CHARACTERISTICS

1. °API GRAVITY AND UOP K (HYDROGEN CONTENT)

2. BOILING RANGE

3. AVERAGE BOILING POINT

4. CARBON RESIDUE

5. METALS

6. SULFUR, NITROGEN, AND OXYGEN

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°API GRAVITY

API gravity is a specific gravity relating the density of oil to the density of water.

Feed to an FCC can range from 15° to 45° API, with 20-25° API the most common.

Any change in this number is due to a change in boiling range, crude type, or both.

If the API gravity increases because the feedstock is more saturated (paraffinic and

less aromatic), the following changes can be expected:

1. The charge will crack more readily for the same reactor temperature and there

will be greater conversion.

2. At a constant conversion level, there will be a greater gasoline yield, with a

slightly lower octane.

3. Products will be less olefinic.

A rough indication of the quantities of paraffins present is a characterization factor

which relates boiling point to specific gravity. This is the UOP K factor, which is

given by:

UOP K = (CABP)

SG60

1/3

where:

CABP = Cubic average boiling point, °R SG60 = Specific Gravity at 60°F

A detailed example of this calculation is given earlier. A UOP K factor of 11.2 would

show a more aromatic stock, while a K factor of 12.5 would indicate a more highly

paraffinic stock. One key feature of the FCC unit is that the hydrogen in the product

streams must come from the hydrogen in the feed. There is no added hydrogen in

this process. One good way to check the quality of FCC data and yield estimates is

157048 Process Variables

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to do a hydrogen balance across the unit as shown in the calculation section. Gasoline yield is a very strong function of the H2 in feed as shown:

GASOLINE YIELD vs. HYDROGEN CONTENT

BOILING RANGE

The boiling point range of FCC feed usually varies from an initial point of 500°F

(260°C) to an endpoint of about 1050°F (565°C). The distillation must be conducted

under vacuum and corrected to atmospheric pressure, because thermal cracking

will occur above 700°F (371°C).

There are two boiling point ranges which are used to describe the lighter material in

the feed. These are "percent over 430°F" (221°C), and "percent at 650°F" (343°C).

The first quantifies the amount of gasoline in the feed. This material may be

cracked, but only at a very slow rate. Most of it merely passes through the unit, with

perhaps some small octane improvement. The octane improvement is somewhat

Gas

olin

e Y

ield

, Vol

-%

Hydrogen in FCC Feed, Wt-%

11 12 13

50

60

70

157048 Process Variables

Page 11

higher for cracked gasoline, as compared to straight run material. Gasoline in the

FCC feed is not considered desirable because it occupies space which could be

used to process gas oil, and because it usually has a low octane number. It would

be better to remove this material in the crude unit and send it to a reformer.

The "percent at 650°F" (343°C) is a measure of the light fuel oil in the charge. The

boiling point of 650°F is chosen because it corresponds to the normal LCO

endpoint. This material will crack, but not to the same extent as the heavier

molecules. It will produce more coke than will the gasoline, but again, less than the

heavier material.

The endpoint of FCC charge stock may vary, depending to some extent on the

suitability of the material for cracking operation. The presence of coke precursors,

such as polynuclear aromatics, organometallic compounds, and high sulfur material,

are, in many cases, good reasons for avoiding the inclusion of high boiling point

compounds in FCC feed. This depends very much on the individual stock.

AVERAGE BOILING POINT

The average boiling point of the FCC feed depends on the average molecular

weight. An increase in API and the molecular weight will typically cause the

following:

1. The charge will crack more readily, so at constant reactor temperature

the conversion will increase.

2. At constant conversion, the gasoline yield will increase about 1% for an

increase in the molecular weight of 20. This would correspond to an

increase of 2° API. 3. At constant conversion, the yield of C4 and lighter will decrease.

4. The olefinic content of the products will decrease.

5. The regenerator temperature will tend to rise.

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There are upper limits to these increases. An exceptionally heavy feed might prove

to be undesirable because of high Carbon Residue, Sulfur, and similar factors. The

exact changes will depend on the individual feedstock.

CARBON RESIDUE

The carbon residue of a feedstock is an indirect measure of its coke producing

nature. The value may be determined by either the Conradson or Ramsbottom

methods. An increase in residue of a feed from one crude source will generally

result in an increase in regenerator temperature. The exact nature of coke laydown

is somewhat complicated so this characteristic is not always reliable for comparing

feeds from different crudes.

The carbon residue can be a useful number for determining possible contamination

in storage, or of problems in the upstream feed preparation units. Because

entrainment in the vacuum tower is a common cause of increased carbon residue, a

higher metals level may be observed at the same time. Gas oil having a carbon

residue over 0.5% should be considered suspect.

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COLOR

Color may be used as a possible indication of problems. Darker stocks tend to have

higher carbon residues, sulfur, and metal problems. This method is especially

valuable because it is a relatively quick and easy test.

METALS

Organometallic compounds in the FCC feed can cause serious overcracking if the

metals deposit on the catalyst. The cleanliness of a chargestock is given by a

metals factor:

Fm = V + 10 (Ni + Cu)

where:

Fm = Metals factor

V = Vanadium concentration, wppm

Ni = Nickel concentration, wppm

Cu = Copper concentration, wppm

All metal concentrations are ppm by weight in the feed. A factor of 1.0 is considered

safe, over 3.0 indicates a danger of poisoning.

Normal dry gas make at 60-70% conversion is 50-100 SCF/bbl. A heavily contaminated stock would produce 200 SCF/bbl or more. The ratio H2/C1 will

increase as dehydrogenation reactions are catalyzed by the metals, especially Ni. An H2/C1 ratio of 1.0, as compared to the normal 0.3-0.5, would again indicate

metals poisoning. A third indication of metals would be an increase of 10-15% in the olefin content of the C3 stream, to as high as 85%.

Sodium and vanadium pose a different threat to the catalyst than nickel. These

metals are mobile at high temperatures and can destroy the zeolite in the catalyst

causing low activity and conversion. Even with metal traps in the catalyst, high

157048 Process Variables

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catalyst usage will be required to flush these metals from the unit to maintain

reasonable activity, conversion and selectivity.

Proper control of the feed preparation units is necessary to prevent these metals

from contaminating the feed. Most of the metals are concentrated in the heavier

fractions, although a few may be volatile at lower temperatures. Keeping

entrainment in the feed towers to a minimum will keep metals level down to a safe

value.

SULFUR

Sulfur is as undesirable in cat cracker charge as it is in the feed to most refining

units, causing corrosion of the equipment and increased difficulty in treating products. At 50% conversion, about 35% of the sulfur charged is converted to H2S,

and at 70%, this figure will rise to about 50%. The sulfur content of a 400°F

endpoint cat gasoline will be about 10% of that of the raw oil charge, but this

fraction increases rapidly as the endpoint is raised above 400°F. As would be

expected, the higher the sulfur content of the gasoline, the lower will be its lead

response, although lead response is no longer important in many parts of the world.

Hydrotreating will significantly improve FCC feedstock. The effect is twofold: the

removal of impurities and the hydrogen addition to saturate molecules. The first of

these is important when the charge is contaminated with sulfur, nitrogen or metals.

These poisons may cause both process and environmental problems. Hydrogen

addition to the feed, especially to the large polynuclear aromatics, will give higher

conversion and a decreased coke yield by making these heavy compounds easier

to crack.

The FCC product sulfur distribution is not even; it tends to concentrate in the heavy products and as H2S. Table 1 is a typical product sulfur distribution for a non-

hydrotreated feed.

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TABLE 1

COMMERCIAL SULFUR BALANCE

(80.7 LV-% CONVERSION)

STREAM PERCENTAGE COMPOSITION OF FEED WT-% SULFUR SULFUR

FEED: VIRGIN GAS OILS 1.04 100.0

PRODUCTS: SPONGE ABS. OH — —

DEBUT. OH — — H2S 44.4

RSH 3.8

GASOLINE 0.15 6.5

LIGHT CYCLE OIL 1.35 16.7

CLARIFIED OIL 2.08 17.1

FLUE GAS 9.1

SOUR WATER 1.9

99.5

Much of the feed sulfur comes off as H2S because H2S, once formed, is fairly stable

under the conditions encountered in the reactor. This desulfurization is beneficial

because concentrating the feed sulfur in one product stream decreases the

difficulties in treating other products.

Higher sulfur feedstocks that are mildly hydrotreated will tend to produce a lesser percentage of H2S, and leave a larger portion of the feed sulfur in the heavy

products. The effects are shown in Table 2 for cycle oil sulfur content.

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The results of this sulfur concentration in heavy products will vary with the refinery's

needs. Product specifications and uses must be balanced against changes in

corrosion rates and required metallurgy, and should be examined on a case by case

basis.

TABLE 2

SULFUR DISTRIBUTION

EQUIVALENT PROCESSING CONDITIONS

TOTAL PERCENTAGE CYCLE OIL OF FEED SULFUR SULFUR SULFUR, CONTENT, IN CYCLE FEEDSTOCK TYPE WT-% WT-% OILS RAW 2.68 4.31 43.7 HYDROTREATED 0.56 1.40 55.8 HYDROTREATED 0.26 0.76 67.6

Metals

The reduction of metals by hydrotreating follows the same pattern as nitrogen and

oxygen removal. It is possible to reduce the feed metals factor, Fm, by 50-90% in a

moderate severity hydrotreater.

Hydrogen Addition

Hydrotreating an FCC feedstock to improve quality is generally more attractive if

gasoline or LPG is the desired product. Moderate severity LCO production may not

justify hydrotreating unless there is a high concentration of feed sulfur or other

contaminants. Table 3 shows the yield changes for a charge stock under equivalent

cracking conditions at three levels of hydrotreating.

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The increase in conversion in Table 3 is accompanied by an increase in gasoline efficiency, except for the severe hydrotreating case where potential alkylate (C3 and

C4) is significantly higher. The decrease in sulfur content would be accompanied by

a decrease in nitrogen and metals, while the decreasing carbon deposition will

indicate a slightly higher product yield, with less feed being converted to coke.

TABLE 3

EFFECT OF FEEDSTOCK

HYDROTREATING: EQUIVALENT CRACKING CONDITIONS

FEED RAW HYDROTREATED

GRAVITY, API 21.7 25.5 26.4 33.3

SULFUR, WT-% 2.68 0.53 0.28 0.01

CONVERSION (LV-%) 78.1 80.7 81.7 92.0 C5+ GASOLINE (LV-%) 55.5 60.1 61.0 68.2

POTENTIAL ALKYLATE (LV-%) 33.6 37.2 37.1 41.8

RELATIVE CARBON DEPOSITION 1.0 0.78 0.76 0.43

FCC GASOLINE RESEARCH CLEAR OCTANE NUMBER 93.8 93.9 94.0 92.0

RATIO ISOBUTANE/BUTYLENES IN C4 FRACTION (MOL-%) 0.68 0.72 0.79 0.81

GASOLINE EFFICIENCY VOL-%, GASOLINE/CONVERSION 0.71 0.74 0.75 0.74

A detailed analysis for two different feedstocks is given in Table 4. Two obvious

changes are the increase in API gravity and UOP K, indicating a greater degree of

hydrogen saturation. There is some small degree of hydrocracking, as shown by the

decrease in average molecular weight and boiling point.

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TABLE 4

FCC FEEDSTOCK PROPERTIES

GACH SARAN (HEAVY IRANIAN) L. A. BASIN SEVERELY HYDRO- HYDRO- HYDRO- RAW TREATED RAW TREATED TREATED

API 22.9 26.3 22.2 26.3 35.0

K 11.78 11.98 11.45 11.7 11.99

MW 385 380 316 298 266

S, WT-% 1.83 0.14 1.30 0.1 0.001

CON. CARBON, WT-% 0.34 0.06 0.1 0.1 0.0

N2, PPM 1880 1570 3380 2190 2

AROMATICS, WT-% 48.5 42.1 53 51 30.5

ASTM D 1160

IBP 504 458 382 360 360

10 661 632 548 530 440

30 760 739 653 628 518

50 822 799 724 707 594

70 877 856 795 779 682

so 958 933 880 868 810

95 983 990 965 954 920

% RECOVERED 98 98 98 98 98

FM FACTOR 2.3 1 2.9 0.0 0.0

PILOT PLANT CONVERSION VOL-% 77 83 68 76 89

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Feed hydrotreating is becoming more common as the quality of FCC feedstocks

decreases. Table 5 summarizes the advantages of hydrotreating. The economic

question of increased cost for hydrotreating versus increased yields and other

benefits must be solved for each plant.

TABLE 5

ADVANTAGES OF HYDROTREATING

1. HIGHER CONVERSION

2. HIGHER GASOLINE YIELD

3. HIGHER C3-C4 YIELD

4. LOWER SULFUR AND METALS

5. LOWER CLARIFIED OIL YIELD

6. LOWER COKE MAKE

J Cracking

A modification of feed hydrotreating is J cracking. This process treats the light cycle

oil stream, which is then recycled back to the riser with the raw feedstock. The

hydrotreated LCO can be cracked, increasing the yield of all the lighter products. J

cracking partially saturates the di-, tri-, and tetra-aromatics present in LCO. These

components then crack instead of forming coke when the stream is recycled. Table 6

compares the product yields for J cracking and normal operation for a hydrotreated

feed.

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TABLE 6

FCC YIELD COMPARISON FOR J CRACKING

FEED: HYDROTREATED 25° API MIDDLE EAST GAS OIL

OPERATION

NORMAL + J CRACKING

CONVERSION, VOL-% 85 95

YIELDS

H2S, WT-% 0.15 0.25

C2 MINUS WT-% 2.77 3.06

C3, VOL-% 12.5 13.7

C4, VOL-% 18.0 19.6

C5- 380°F 90% GASOLINE, VOL-% 67.1 74.3

LCO, VOL-% 10.0 0.0

CLARIFIED OIL, VOL-% 5.0 5.0

COKE, WT-% 5.0 6.1

POTENTIAL C3-C4 ALKYLATE, VOL-% 32.8 34.5

TOTAL 10 PSI RVP GASOLINE, VOL-% 110.2 120.1

RESEARCH OCTANE—FCC GASOLINE 92.5 92.6

RESEARCH OCTANE—TOTAL GASOLINE 93.2 93.3

MOTOR OCTANE—TOTAL GASOLINE 85.3 85.2

NOTE: RVP IS REID VAPOR PRESSURE

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OXYGEN AND NITROGEN

Oxygen and nitrogen pose different problems than sulfur. Oxygen may be present in

the feedstock chemically bonded to a hydrocarbon, or it may simply be absorbed by

the oil as it sits in storage. Dissolved oxygen, if not stripped, may cause fouling of

heat exchangers when the temperature approaches 400°F (200°C). Another source

of oxygen is the instrument purges or the entrained oxygen carried into the reactor

with the regenerated catalyst. This is more of a problem with the complete CO

combustion units than with the traditional plants, because regenerator oxygen levels

are high. Most of the oxygen in the reactor will be quickly converted to water, carbon

oxides, phenols, cresols, or acids. Other reactions, including the problems of free

oxygen, are discussed later under Product Treating.

A severely contaminated feedstock may contain 4000 ppm nitrogen, a good feed

less than 500-600 ppm. Much of the nitrogen will be converted to ammonia, which

can cause plugging problems in the main column overhead. Cyanides are also

formed, these contribute to blistering and corrosion in the gas concentration section.

Wash water to the main column overhead and gas plant is used to minimize these

problems.

Some of the nitrogen will stay with the catalyst as a constituent of coke. It burns off

in the regenerator to give nitrogen oxides and small amounts of ammonia. These

problems are discussed in Section XIII, Environmental. High nitrogen levels are

detrimental to catalyst activity, since the basic nature of the ammonia formed tends

to deactivate the acid sites on the catalyst. This deactivation is reversible and

catalyst activity will be restored with low nitrogen feed.

Difficulties with nitrogen and oxygen are normally not severe enough to justify

hydrotreating for only these poisons. But they rarely occur alone; a bad feedstock

will usually have high concentrations of sulfur or metals in addition to the oxygen and

nitrogen.

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The amount of poisons removed again depends on what species are present, and

the severity of treatment. Moderate hydrotreating will remove 10-50% of the total

nitrogen. A high severity operation may run close to 100% removal. Treatment for

oxygen gives similar results.

PROCESSING OF RESIDUAL FEEDSTOCKS

There are several problems and penalties associated with processing residual

feedstocks. There is a loss of selectivity in liquid product yield since the feed

generally contains less hydrogen than the gas oil fraction. The increased boiling

range brings more contaminants into the unit, both as coke precursors and as

metals. The coke precursors will cause a higher delta coke on catalyst and will

result in a hotter regenerator and less conversion for the coke yield generated. The

higher metals will cause more light gas production as will the higher regenerator

temperatures. Catalyst activity will be effected by the high metals and by the

additional deactivation from the high regenerator temperature. The higher coke yield

will mean thruput will have to be reduced to stay within the coke burning capacity of

the unit.

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The following table from a commercial unit illustrates what happens as the feed is

changed from VGO to Resid.

Commercial Operations Changing from Gas Oil to Residue Processing

Feed A B C D

Composition, vol Ratio

VGO / Atm. Residue 100 / 0 38 / 62 25 / 75 0 / 100

Conradson Carbon, wt-% 0.16 2.25 2.96 3.95

Metals (Ni+V), wt-ppm 1.0 9.6 9.0 6.3

Commercial Performance

Conversion, lv-% 86.2 82.2 79.7 76.5

Gasoline Yield, lv-% 62.6 60.3 59.5 57.4

Coke, wt-% 5.6 7.2 7.1 7.5

As the contamination in the feed increased as a reflection of the poorer feed quality,

the coke make required to maintain conversion increased. However, by careful

selection of the crudes purchased, the metal content of the resid was controlled so

that their effect on the operation was limited and the additional coke burning

requirement was the major change. Note that the gasoline yield was reduced by

almost 5 LV% due to the change in feed.

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This same dependency on feed quality is evident in the RCC unit as well. The following tables show the performance of the unit on three different quality feeds:

RFCC Unit Feedstock Variation

Low Intermediate High Carbon Carbon Carbon Residue Residue Residue °API 22.8 21.3 19.2 Sulfur, wt-% 0.9 1.1 1.2 Nitrogen, wt-% 0.12 0.14 0.19 Conradson Carbon, wt-% 4.8 6.0 7.9 Metals

Nickel, wt-ppm 8 13 17 Vanadium, wt-ppm 17 31 52

Commercial RFCC Performance on Different Residues

Low Carbon Residue

Intermediate Carbon Residue

High Carbon Residue

Dry Gas, wt-% 3.4 3.2 4.0C3’s + C4’s, lv-% 25.2 24.7 23.9Gasoline (430°F EP), lv-%

59.1 56.6 55.6

Light Cycle Oil (630°F EP), lv-%

15.0 14.2 15.0

Clarified Oil, lv-% 7.5 10.2 10.9Coke, wt-% 8.4 9.1 10.8Total C5+ Liquid, lv-% 106.4 105.7 105.4RON Gasoline 91.9 93.2 93.3

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Figure 1 illustrates the relative loss in conversion as a result of an increase of

contaminants in the FCC feed, as expressed in terms of the Ramsbottom carbon. It

is assumed that the proper catalyst makeup policies have been followed, so as not

to operate with heavily contaminated catalyst (for example, total metals on catalyst

of less than 5000 ppm). The loss in conversion is, in part, attributable to the

deterioration of the feed quality, but the main cause is the decrease in catalyst

circulation resulting from the higher regenerator temperature experienced by the

unit.

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Figure 2 summarizes the effect that contaminated feed has on the unit's regenerator

temperature.

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These plots also summarize the experiences of most refiners, who found that the

units designed for VGO could not accommodate more than about 3.5 to 4.0 wt-%

Conradson carbon in the feedstock due to excessively high regenerator tempera-

tures. The high temperatures also resulted in severe catalyst deactivation and poor

unit performance. This fact, i.e., that residual stocks deposit more carbonaceous

material during the cracking cycle than can be effectively used to fuel the

conversions reactions, led to the development of alternative technologies directed

at:

• Limiting the heat release during regeneration

• Seeking external removal of heat

The first approach led to the development of the two-stage regeneration system that

is currently practiced in the Ashland RCC unit and the second to the development of

the catalyst cooler, also incorporated in the design of this unit.

Table 5 summarizes the relevant properties of an atmospheric resid that will be

used to illustrate the benefits that can be obtained by varying the heat removal in a

commercial unit. Case 1 found in Table 6 represents a very low coke make

operation where the regenerator temperature has been allowed to equilibrate at a

very high level, in the order of 1480°F. The yield structure is poor and the gas make

extremely high. The subsequent cases illustrate the benefits that can be derived by

manipulating the heat balance forcing the unit to produce more coke. Even though

the unit is producing an additional amount of coke, the yield pattern improves. The

data in Table 6 is plotted graphically in Figure 3.

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TABLE 5

RCC FEEDSTOCK FOR COKE YIELD VS. CONVERSION STUDY

API 20.8

Conradson Carbon 4.8

Metals, wt-ppm 20.0

UOP K 12.1

Source Atmospheric Resid

TABLE 6

RCC ESTIMATED YIELDS VS. UNIT COKE YIELD Case 1 2 3 4

Coke Yield, wt-% 7.3 8.57 9.73 11.10

Conversion, LV-% 68.3 77.2 80.9 83.0

Dry Gas, wt-% 7.2 4.2 3.4 3.3

Gasoline, LV-% 46.0 56.3 58.5 59.1

LCO, LV-% 16.9 13.4 11.4 9.7

Slurry, LV-% 14.8 9.4 7.7 6.4

Total Liquid, LV-% 101.6 106.6 107.6 107.5

Heat Removal No No Yes Yes

Feed: Table 5

Gasoline, 380°F at 90% Pt.

LCO, 600°F at 90% Pt.

Installing a variable heat removal catalyst cooler enables the refiner to adjust the

heat removal required for a given feedstock to produce the optimum yield pattern.

Even though the coke yield has increased, the resulting yield pattern at the higher

coke make is more favorable than that which can be achieved at the lower coke

makes. These benefits are achieved at relatively low regenerator temperatures, of

less than 1350°F, for good catalyst activity maintenance.

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Commercial experience indicates that operations at regenerated catalyst

temperatures greater than 1350-1400°F offer very little advantage, and, in fact,

result in poor yields and very high gas production. Units currently processing some

resid which are forced to operate at high regenerator temperatures are ideally

suited for the installation of a UOP catalyst cooler. In addition to the conversion and

selectivity benefits obtained by operating at the lower catalyst temperatures,

considerable savings can be obtained by the reduction in catalyst makeup. This is

due to the reduction in the hydrothermal deactivation of the catalyst as a result of

the lower regenerator temperature. If it is desired to keep the unit coke make

constant, another interesting application of this technology is illustrated in the

following case.

Table 7 shows the savings possible in a unit processing resid. As can be seen in

the table, the heat balance has been adjusted to keep the coke make constant to

satisfy the unit constraints. The reduction in regenerator temperature results in a

lower catalyst addition rate, since the hydrothermal deactivation of the unit's catalyst

has been reduced. For a 20,000 BPD unit, this catalyst savings amounts to

approximately 1.6 million dollars per annum.

TABLE 7

CATALYST COOLER ADDITION FOR MORE PROFITABLE OPERATION AT CONSTANT COKE MAKE

Feed No Cat Cooler With Cat Cooler

API 27.0

Conradson Carbon, wt-% 3.0

Feed Temperature, °F Base Base + 160

Reactor Temperature, °F Base Base

Regenerator Temperature, °F 1410 1350

Conversion, LV-% 85 85

Coke Yield, wt-% Base Base

Catalyst Addition Base 0.5 Base

Heat Removal No 2500 Btu/lb coke

Catalyst/Oil Ratio Base Base

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The preceding discussions have illustrated the benefits that can be derived with the

installation of a catalyst cooler. This flexible technology permits:

• Adjustments in the unit conversion to achieve the optimal yield pattern for a

given feedstock

• Enhancement of the unit's capability to process more contaminated feedstocks

• A more profitable unit operation while keeping the unit coke production

constant.

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REGENERATION SECTION

The main purpose of the regeneration zone is to oxidize the coke on spent catalyst

and reestablish the catalyst activity of the fluidized particles prior to being returned

to the reactor riser. The heat from this combustion of coke in turn provides the

energy to satisfy the process requirements. Thus, the regeneration section has a

very fundamental significance.

Over the years this section has undergone fundamental design and mechanical

improvements. One of the first big movements occurred during the 1970's, with the

advent of total combustion. UOP moved away from the conventional bubbling or

turbulent-bed regenerator to a fast-fluidized, high-efficiency style combustor. Since

then this design has become well established as shown in Figure 8, and more than

45 units in commercial operation. Contrasting a modern high efficiency combustor

design with a typical bed style configuration of the past, as in Figure 6, the major

regenerator improvements are aimed towards:

• Enhanced and controlled coke burning kinetics • Reduced catalyst inventory • Narrow catalyst residence time distributions • Ease of start-up and routine operability • Uniform radial carbon and temperature profiles • Limited afterburn and uniform temperature distribution at cyclones • Additional heat balance flexibility from Total CO combustion Dense phase catalyst cooling

• Particulate, power and waste heat recovery

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These benefits are principally derived from the combination of a more

homogeneous gas and solids contacting regime and reduced yet controlled particle

residence time distributions.

The following sections will discuss in detail the fundamental regenerator fluidization

regimes, mixing characteristics, combustor hydraulics and coke burning kinetics,

and how they relate to commercial performance and unit optimization.

FCC REGENERATOR FLUIDIZATION REGIMES

In commercial FCC regenerator designs, various fluidization regimes exist. The

schematics shown in Figure 4 serve to illustrate these various regimes pictorially.

FIGURE 4

FLUIDIZATION REGIMES

UOP 3106-6

(D) TransportRiser Reactor

Gas Velocity

Catalyst Flux

(C) Fast Fluidized Bed

(B) TurbulentFluidized Bed

A) BubblingFluidized Bed

Bed

Den

sity

UOP 3106-6

(D) TransportRiser Reactor

Gas Velocity

Catalyst Flux

(C) Fast Fluidized Bed

(B) TurbulentFluidized Bed

A) BubblingFluidized Bed

Bed

Den

sity

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Bubbling Bed (Umb - 1.0 ft/s Superficial Velocity)

The bubbling bed regime ranges from the minimum bubble velocity Umb (which

typically for FCC type A particles is from 0.02-0.1 ft/s), up to about 1.0 ft/sec

superficial velocity. Here three distinct yet interchanging gas phases exist: the

bubble phase, the emulsion phase, and the gas phase inside the catalyst pores.

These three phases all flow at various relative velocities. Discrete bubbles of gas

flowing through the bed produce abrupt pressure fluctuations at the bed surface.

The relative fluctuations are determined by the bubble frequency or superficial gas

velocity Ug, as shown in Figure 5.

FIGURE 5 BUBBLING TO TURBULENT BED TRANSITION

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Figure 6 represents a typical bubbling bed regenerator in which there is limited

solids entrainment and transport through the freeboard region. Most of the larger

particles that are entrained are returned to the bed through the two stage cyclone

diplegs. There exists a sharp, distinct catalyst bed level. The distance between the

primary cyclone inlet horn and the surface of the bed should be greater than the

transport disengaging height (TDH).

FIGURE 6 BUBBLING BED REGENERATOR

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Turbulent Bed (1.0-3.5 ft/sec Superficial Velocity)

With higher gas velocities, the distinct bubble phase disappears and the bulk of the

gas flows as described by Yerushalmi "in voids which continually coalesce and split

tracing tortuous passages as they rise through the bed"1. The upper bed surface is

considerably more diffuse with reduced pressure fluctuations and substantially

higher entrainment of solids into the freeboard region (Figure 5 in Fluidization).

Because of the requirement for higher coke burning capacity and improved

contacting efficiency, the vast majority of commercial regenerators are operating in

the turbulent bed regime. In this regime the ultimate regeneration capacity is set by

the sharp increase in solids entrainment as velocity increases, see Figure 7, and by

the cyclone separation efficiency and dipleg hydraulics.

FIGURE 7 MAXIMUM DILUTE PHASE ENTRAINMENT

IN VERTICAL GAS-SOLIDS UPFLOW

1. “Further Studies of the Regimes of Fluidization,” Powder Technology.

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Fast Fluidized Bed (3 -10 ft/sec Superficial Velocity)

The regime now extends into a complex transport phase where there is a sharp

increase in the rate of solids carryover as the transport velocity is approached. In

the absence of any solid recycle, the bed would rapidly disappear. Beyond this

velocity, catalyst fed to the base of the regenerator traverses it in fully entrained

transport flow with the voidage or density of the resulting suspension being

dependent not only on velocity of the gas but also on the solids flow rate (flux =

lb/s/ft2). If the solids rate is low, dilute-phase flow will result. If on the other hand,

solids are fed to the regenerator at a sufficiently high rate, for example by

recirculating solids carried-over back to the combustor, then it is possible to

maintain a relatively large solids concentration referred to as the fast-fluidized bed.

The transport velocity may therefore be regarded as the boundary which divides

vertical gas-solids flow regimes into two groups. Below the boundary lies the

bubbling, turbulent fluidized bed. Above lies the transport regime which, depending

on the solids flux, encompasses a wide range of states from dilute-phase flow to the

fast fluidized bed. Due to cluster formation, for FCC catalyst the transport velocity is

approximately 20 times the terminal velocity of a single 50µ FCC particle.

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COMBUSTOR HYDRAULICS AND MIXING CHARACTERISTICS

Figure 8 shows a typical high-efficiency style regenerator. The combustor section

can be operated either above or below the fluid cracking catalyst transport velocity.

The resulting catalyst/air suspension in the combustor depends not only on the gas

velocity but also on the solids flow rate (lb/sec/ft2). Adjustment in the quantity of

catalyst being externally recirculated (via slide valve control) can therefore be used

to control the catalyst inventory in the combustor for various air rates.

FIGURE 8

HIGH EFFICIENCY REGENERATOR

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Figure 9 represents typical combustor hydraulics for various catalyst loadings and

superficial gas velocities. The combustor density is measured across the entire

combustor height and the solids loading W (lb/sec/ft2) is the summation of both the

spent catalyst circulation and the combustor external recirculation. The gas

superficial velocity (A) lies well below the catalyst transport velocity, but at a low

solids flux (region X-Y), dilute phase flow exists. At condition (Y), the solids flux is

sufficient to choke the system and any further increase in solids loading (region Y-Z)

results in a substantial density (inventory/residence time) increase.

FIGURE 9 COMBUSTOR OPERATION

At the higher gas velocities (B) and (C), choking takes place at much higher solids

flux which results in a less abrupt change in combustor density with further

DD

CCBB

GE

F

(Z)

AA Gas Velocity, ft/sCombustor CatalystInventory Is:I = Density x V

Where V IsThe CombustorVolume, ft.3

Com

bu

stor

Den

sity

, lb/

ft.3

(X)

(Y)(Y)

Catalyst Loading (W) lb / s/ft2

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increases in flux. Such a region is the fast-fluidized regime. Eventually at higher

velocities like (D), true transport flow will be achieved where there is no solids flux

that can choke the system.

This relationship shows how flexible the system is in adjusting the combustor

hydraulics (inventory/residence time) for various operating conditions such as

temperature, pressure, superficial gas velocity, catalyst circulation and carbon

concentration. Consider the operating condition 'E' at a superficial velocity (B). If the

superficial velocity is now increased to (C) either by a change in pressure or

combustor air flow rate, the combustor inventory will decrease to condition 'F' at

constant solids loading. However, if necessary, the combustor inventory may be re-

established at condition 'G' via an increased solids flux (external recirculation slide

valve). It is important to keep in mind that any adjustment in combustor inventory

results in a change to the upper regenerator level (surge inventory).

Since the externally recycled solids are at final regeneration temperature, this will

set the pre-combustion temperature of the combined spent catalyst, recirculated

catalyst and combustion air streams. Figure 10 shows a typical response of the pre-

combustion temperature for various external catalyst recirculation rates. The control

of the quantity of solids being recycled to the combustor therefore sets both the pre-

combustion temperature and inventory (residence time) required for complete

combustion with limited afterburn and low carbon on regenerated catalyst (<0.05

Wt-%).

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FIGURE 10

CATALYST PRE-COMBUSTION TEMPERATURE

Solids Mixing Characteristics

The bubble or gas induced solids mixing characteristics in the various fluidized bed

regimes have received considerable attention over the years. Although the bubble

induced vertical mixing rate of solids is extremely high, the radial mixing

characteristics are relatively poor (since bubbles flow vertically).

Since some commercial bubbling/turbulent bed regenerators exceed 50 feet in

diameter and have relatively low L/D bed ratios (<0.2), severe gas/solid

(carbon/oxygen) distribution problems can be encountered. This results in:

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1. Thermal gradients, both inter-particle and within the bed.

2. Residence time distributions and short circuiting.

3. Afterburn in the dilute phase and cyclones.

Singer investigated catalyst mixing patterns in various commercial catalytic cracking

units (reactor/regenerator/stripper sections) via the use of certain radioactive

isotopes2. The measured distributions indicate that although the dense beds in the

regenerator approach good mixing, there are substantial deviations from perfect

mixing attributable to catalyst by-passing and regions of relatively immobile catalyst.

Over the years, in order to improve the radial mixing characteristics and residence

time distributions (short circuiting) of the turbulent/bubbling bed systems,

considerable attention has been placed on:

• Dual diameter vessels • Fluidization bed length/diameter ratios • Air distribution, grid pressure drop and plugging patterns • Spent catalyst addition and withdrawal points, tangential swirls, deflector

plates, baffles and entry elevation within the fluidized bed • Cyclone dipleg discharge orientation

2. “Catalyst Mixing Patterns in Commercial Catalytic Cracking,” I&EC, 49.

Most of these intrinsic mixing problems were eliminated with the high efficiency style

combustor. Figure 11 compares the theoretical particle residence time distributions

of a modern high-efficiency style combustor with that of a conventional bubbling

bed. The basic difference in response curves is due to both the fluidization regime

(fast-fluidized) and the solids entry/exit configuration. The combustor regenerator

more closely approaches a plug flow reactor system where it is impossible for a

spent catalyst particle to leave the regenerator without passing through the dilute

phase combustion zone.

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FIGURE 11

THEORETICAL RESIDENCE TIME DISTRIBUTIONS

Regarding radial/axial mixing, it is still highly desirable for the lower (5 feet)

combustor section to be operated with a pseudo-dense phase acceleration zone.

The relatively high slip and low voidage enhances the effective fast-fluidized bed

thermal conductivity, allowing rapid heat transfer between the hot recycled and

relatively cold spent catalyst particles up to the pre-combustion temperature. This

produces uniform radial temperatures in the lower combustion zone.

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COKE BURNING KINETICS AND OPTIMIZATION

The coke deposited on the catalyst consists primarily of carbon and hydrogen along

with relatively small amounts of sulfur, nitrogen and metals. This discussion will

focus on the carbon and hydrogen species. The amount of hydrogen in coke has

typically decreased over the years to levels of 6-7 wt-% with the use of high

conversion, zeolite catalysts and modern stripper designs.

Catalyst regeneration, as a carbon removal process, is widely accepted as being

first order with respect to carbon concentration and oxygen partial pressure:

dC / dt KCPo2

Where:

K = Rate constant, hr-1 atm-1

C = Wt-% carbon on catalyst PO2 = oxygen partial pressure, atm

The reaction rate constant will be dependent on temperature and can be

represented via an Arrhenius type equation:

dC / dt Koe

E

RTCPo2

(1)

where:

∆E = Activation Energy

R = Gas Constant

T = Temperature, °R

This relationship for the rate of carbon burning from fluid catalytic cracking catalysts

was found experimentally to hold over a wide range of temperatures with diffusional

limitation not controlling. A similar expression can be used for the hydrogen content

of the coke, with the oxidation of hydrogen proceeding more rapidly than that of

carbon:

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dH / dt K oe

E

RTHPo2

(2)

Where:

K o Ko H = Wt-% hydrogen on catalyst

When discussing coke combustion rates and kinetics, it is important to differentiate

between net coke yield and coke concentration (analogous to heat and

temperature). The net coke yield is set by the unit enthalpy balance with little direct

impact on the rate of coke combustion of individual particles.

Delta Coke

This is a dependent variable, which is difficult to accurately predict due to its

dependency on feedstock quality, processing conditions and catalyst formulation.

This term also sets the final regenerator temperature via:

TRegen TRx C / Cp Hcomb H FGair Hloss

With a few simplifying assumptions, such as a plug flow combustor and total combustion of coke to CO2, the differential equations (1) and (2) can be solved

numerically in order to gain insight into the impact and optimization of such process

variables as:

• Temperature

• Catalyst recirculation

• Oxygen partial pressure

• Carbon and hydrogen concentration

on the overall coke combustion rates.

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Pre-combustion Mix Temperature and Catalyst Recirculation

As discussed in a previous section, controlled catalyst recirculation to the

combustor serves to:

• increase residence time via combustor hydraulics

• raise pre-combustion temperatures (Figure 10)

Pre-combustion temperature is the mix temperature of the cold spent catalyst, hot

recycled catalyst, and combustion air:

Tmix

0.275F CCR TRegen 0.275 CCR TRx 0.273BTB

0.273B 0.275F CCR 0.275 CCR

Where:

B = lb air/hr

F = Cat Recirculation, wt ratio of CCR

CCR = Cat Circulation Rate, lb/hr TB = Blower Temp, °F

0.275 = specific heat of catalyst, BTU/lb/°F

0.273 = specific heat of air, BTU/lb/°F

The table below shows the substantial impact of recirculated catalyst on the combustion rates via the increased initiation temperature Tmix.

Recycle Coke Concentration Mix Temperature Regen Time Zero 0.8 to 0.05 Wt-% 913 121 sec's 1.5 CCR 0.8 to 0.05 Wt-% 1161 44 sec's

For identical conditions the overall combustion time is reduced by a factor of 3. In

reality this would be reduced further by additional internal recirculation (solids slip).

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Regenerator Temperature and Coke Concentration

These two parameters are strongly interdependent since the final regenerated

catalyst temperature is set by:

TRegen = TRx + ∆C/Cp [∆HComb - ∆HAir - ∆Hlosses]

Where: ∆C = Cspent - Cregen

With Cregen --> 0 for most operations

The impact of temperature alone on the rate of carbon combustion is exponential

and quite dramatic:

Temperature 1100°F 1200°F 1300°F 1400°F Relative combustion rate 1 2.5 6 18

And slows dramatically with carbon concentration on catalyst:

Carbon Reduction 1.0 to 0.9 Wt-% 0.15 to 0.05 Wt-% Relative time required 1 10 For combustion

At constant temperature, oxygen partial pressure, and delta coke reduction.

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Oxygen Partial Pressure

This parameter is set by the combination of regenerator operating pressure, excess

air, and oxygen concentration in the supply air. The relationship between the rate of

combustion and oxygen partial pressure is linear. Figures 12 and 13 show the

relative effect of total pressure and excess oxygen on the regeneration time at

various temperatures.

FIGURE 12

RELATIVE EFFECT OF EXCESS OXYGEN CONCENTRATION ON REGENERATION TIME

AS A FUNCTION OF TEMPERATURE

1. Total pressure assumed constant at 30 psig 2. Plug flow regeneration system 3. Carbon reduced from 1.10 to 0.3 wt-% on catalyst 4. Excess O2 change made by adjusting main air rate

Reg

ener

ator

Tim

e, s

ec

Temperature, oF

10

100

1120 1140 1160 1180 1200 1220 1240 1260 1280

5% Excess O2

2% Excess O2

Reg

ener

ator

Tim

e, s

ec

Temperature, oF

10

100

1120 1140 1160 1180 1200 1220 1240 1260 1280

5% Excess O2

2% Excess O2

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FIGURE 13

Relative Effect of Total Pressure on Regeneration Time Requirement at Various Temperatures

1. Plug flow assumed. 2. Carbon level reduced from 1.10 TO 0.3 wt-%

0

102030405060708090

100110120130140150

0 10 20 30 40 50

1250F1200F1150F

Reg

ener

atio

n T

ime,

Sec

Total Pressure, psia

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COMBINED PROCESS VARIABLES

With some simplifying assumptions, all the process variables and their interactions

can be mathematically modeled via equations (1) & (2) in order to achieve

additional understanding and optimization of the combustor performance.

As an example of the model's use, Figure 14 and Table 8 show the calculated time

dependent responses of the numerous products of combustion for the following set

of typical combustor operating conditions:

Typical Process Conditions

Regenerator pressure 30.0 psig

lb air/lb coke 14.18

Hydrogen in coke 6.0 wt-%

Coke on spent catalyst 0.8 wt-%

Recycle catalyst temperature 1344°F

Blower discharge temperature 320°F

Catalyst recycle 1.5 X’s

Reactor temperature 980°F

% oxygen in air 21 mol% CO2/(CO2+CO) 1.0

Calculated Time Dependent Variables

Particle Temperature, °F

Carbon Concentration, wt-%

Hydrogen Concentration, wt-%

Flue Gas Oxygen Concentration, mol%

Assumptions:

1. Complete combustion

2. Plug flow regeneration

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FIGURE 14

COMBUSTOR COMPOSITION PROFILES

0

5

10

15

20

25

0 1 2 3 4 5 10 15 20 25 30 35 40 45 50 55 60

1100

1150

1200

1250

1300

1350

1400

1450

1500

Tem

per

atu

reTime (seconds)

Co

mp

osi

tio

n

Carbon Wt-%

Flue Gas O2 mol-%

Hydrogen W

t-%

Temp, oF

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TABLE 8

FCC COMBUSTOR MODEL

CALCULATED TIME-DEPENDENT VARIABLES

Carbon Hydrogen Flue Gas O2 Time Temp, °F wt-% wt-% mol%

0 1160 0.752 0.046 21.0

1 1177 0.708 0.036 18.3

2 1182 0.663 0.028 17.7

3 1206 0.616 0.022 16.2

4 1218 0.574 0.016 14.8

5 1230 0.532 0.012 13.7

10 1272 0.358 0.002 8.5

15 1295 0.246 0.001 7.0

20 1310 0.174 ------- 5.5

25 1319 0.126 ------- 4.6

30 1325 0.097 ------- 3.9

35 1330 0.076 ------- 3.5

40 1333 0.060 ------- 3.2

45 1335 0.046 ------- 2.9

50 1336 0.039 ------- 2.7

55 1338 0.032 ------- 2.6

60 1339 0.026 ------- 2.5

Total Combustion and CO Promoter In the absence of a CO combustor promoter, large variations in CO2/CO ratios are

observed. At the catalyst surface it is believed that the ratio of CO2/CO is an

intrinsic function of the temperature at the burning site ("Arthur's ratio"). However, the CO exiting the burning site may be further oxidized to CO2 at a rate dependent

on temperature, CO, O2, and H2O partial pressures, active metals on the catalyst,

carbon/oxygen distributions within the fluidized bed, and even the catalyst

presence.

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This burning of CO in the dilute phase known as "afterburning" can produce large

flue gas temperature increases above those in the dense phase. This is due to the

relative heats of combustion:

C CO ≈ 3,960 BTU/lb

C CO2 ≈ 14,150 BTU/lb

As the amount of CO combustion is increased to 100%, the air required for

combustion also increases. This is partially offset by the improved utilization of the

heat of combustion, but full CO combustion will require a larger blower than a partial

CO combustion operation if the catalyst is regenerated reasonably clean.

Heat of Combustion vs.CO2/CO Ratio in Flue Gas

11000

12000

13000

14000

15000

16000

17000

1 2 3 4 5 6 7Hea

t C

ombu

stio

n, B

TU

/ lb

Cok

e

Total Combustion(16,500 BTU / lbCoke)

CO2/CO mol Ratio

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In the absence of catalyst, a flue gas stream of 3/1 CO2/CO mol composition

undergoing complete combustion to CO2 could see a temperature increase

> 600°F. (Note: this temperature increase is moderated due to the sensible heat of

any entrained catalyst.)

In the 1970's, in order to exploit the higher activity, more coke selective zeolite

catalysts, operations with high temperature, once through total combustion were

utilized for the processing of conventional high quality vacuum gas oils. Table 9

shows a comparison between old and modern operations.

Combustion Air Requirementvs. CO2/CO in the Flue Gas

10

11

12

13

14

15

1 2 3 4 5 6 7

Air

/Cok

e (w

t-R

atio

)

CO2/CO mol Ratio

Complete Combustionwith No Oxygen

in Flue Gas

Complete Combustionwith 2% Oxygen

in Flue Gas

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TABLE 9

CATALYST FORMULATION AND PROCESS DESIGN MODIFICATIONS

Amorphous Catalyst RE-Y Zeolite

Components Wt-% LV-% Wt-% LV-% H2S 0.5 0.4

C2 4.5 3.75

C3 6.75 6.45

C4 11.95 11.45

C5+ Gasoline 45.4 54.4 50.2 59.8

LCO 12.8 12.4 12.55 12.0

CLO 8.7 7.6 9.4 8.0

Coke 9.4 5.8

100 100

Process Conditions Process Conditions

Bed cracking = 935°F Riser cracking = 980°F

CFR = 1.3 CFR = 1.0

Partial burn Total combustion

Capacity = Base Capacity = 1.7 x Base

RONC = 92.5 RONC = 91.8

From the unit enthalpy balance:

100 Hfeed + HRx + Hdiluents + Hrecycle

Hcomb - Hair - Hlosses

BTU/Lb feed

BTU/Lb coke = wt% coke on feed

The total combustion, no recycle operation resulted in substantially lower coke

yields (9.4 > 5.8 Wt-%), higher liquid volume yields, and capacity increases (1.7) at

equivalent conversion. These changes resulted from several major process

changes, described below:

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∆Hcomb: 9055 14,150 BTU/lb coke

∆Hrecycle: Zero BTU/lb feed

With the combustor operation, complete CO combustion (< 50 ppm CO in flue gas)

can be achieved thermally, without promoter at temperatures greater than 1270°F

and 2 mol % excess oxygen in the flue gas.

However, Mobil discovered that certain Group VIII metals, particularly platinum,

could be used at very low levels (1-3 wt ppm) to effectively catalyze the combustion of CO to CO2 either as an integral part of the fresh FCC catalyst or as a separate

additive. In the combustor operation these additives are also frequently used but at

lower concentrations than the conventional bubbling bed regenerators.

The optimization of the combustor operation is simply the optimization of coke

burning kinetics, with a slight twist over conventional bubbling bed systems because

of the fast-fluidization regime. The combustor operation is normally quite stable, and

with only a little attention from the operator, optimal conditions can be maintained

without difficulty.

The focus of where to begin lies in only two areas: carbon on regenerated catalyst

and afterburning control. If these are both within acceptable values, no further

optimization is required. To adjust these values, we need to examine the areas of

control for the combustor.

Temperature

The primary control point for optimization is the combustor temperature. Although

the other factors are important, the temperature can be considered the one truly

independent variable for the operator.

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The catalyst recirculation slide valve controls the combustor temperature by

adjusting the amount of hot catalyst recycled to the vessel. It is normally operated

on TRC control. With adequate excess oxygen, combustor density and normal

velocity, an upper combustor temperature of 1275°F should be sufficient. This

temperature may need to be increased for the following reasons:

• Dilute temperatures are too high due to afterburn • Combustor density is low due to high air rates • Flue gas oxygen is low due to blower limits • CRC is high due to above situations

The ability to increase temperature in the combustor is, however, limited. Once the

recirculation slide valve is full open, no further increase in temperature can be

gained with hot recycle catalyst. The effect of other factors, such as the use of CO

promoter or increased ∆coke operation, can lead to additional temperature

increase.

It should be noted that a flow-through catalyst cooler can limit the effectiveness of

the recirculation catalyst to raise combustor temperature. The cooled catalyst flow

will require additional hot catalyst recycle to maintain desired temperatures.

Somewhat compensating is the high ∆coke operation that calls for the catalyst

cooler in the first place. However, if it becomes necessary, the cooled catalyst slide

valve can be adjusted to help optimize the combustor temperature.

Density

Density and velocity together determine the residence time of the catalyst within the

combustor. It is desirable to maintain at least 6 lb/ft3 density in the combustor and if

possible, 9 - 10 lb/ft3 should be a normal operating target.

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The combustor density is a dependent variable, since the temperature controls the

recirculation slide valve, unit capacity determines the velocity based on air rate, and

spent catalyst flow is dependent on the catalyst/oil ratio. However, where possible

the density (residence time) should be increased for the following situations:

• CRC is high due to insufficient combustion time • Dilute temperatures are too high due to afterburn

Increased density will promote better thermal mixing and will increase residence

time to help resolve these conditions. Also keep in mind that as density increases,

the combustor catalyst inventory increases and the upper regenerator level will

decrease.

Velocity

Combustor velocity is a dependent variable determined by the amount of air needed

to complete the combustion and thus is not a variable available to the operator to

optimize other combustor conditions. However, excessive levels of flue gas oxygen

(>2.5%) provide little benefit and only serve to increase combustor velocity

unnecessarily.

A good range for combustor velocity is 4 to 5.5 ft/s. The lower end of the range is

generally better when there is a choice. When velocity exceeds 5.5 ft/s, the unit can

become combustion limited and increased afterburning may be observed. At high

combustor velocities due to capacity demands, CO promoter can be a valuable

addition. Although velocities in excess of 6 ft/s have been observed commercially,

they have been run in a promoted operation.

Combustor velocity may be too high if the following conditions are observed:

• Afterburn increases despite other efforts to minimize • CRC increases even with high combustor temperature

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Excess Oxygen

The air rate and regenerator pressure will determine the oxygen partial pressure in

the combustor. Although higher levels of excess oxygen via increased air rate are

beneficial to the combustion kinetics, they are counterproductive to the unit

economics. Velocity will increase as air rate is increased, negating some of the

advantages of higher oxygen partial pressure. Thus, flue gas oxygen should be

maintained at or below 2 mol%.

There are certain situations when an increase in oxygen beyond normal flue gas

levels may be warranted:

• Velocity is low and combustor temperature cannot be increased further • CRC is high despite other efforts to minimize

One element that can be considered to increase oxygen partial pressure in the

combustor without increasing air rate is the use of pure oxygen injection. In certain

situations this may be economically feasible.

CO Combustion Promoter

If all other conditions in the combustor are optimized, the use of promoter will not be

required. However, it is perhaps inevitable that the FCC unit will be pushed to the

limits such that the combustor conditions will generally exceed optimum values. In

this case, the use of promoter can provide an additional measure of safety for

controlling afterburn and avoiding excessive dilute phase temperatures.

Particularly when maximum unit capacity is required beyond design levels, the use

of promoter can be beneficial. The following conditions might suggest that promoter

should be considered: • Velocity is high, density is low and recirculation catalyst is maximized • Dilute temperatures are high due to the previous conditions • Afterburn is high despite high combustor temperatures

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Maximum Capacity

Since many units operate on the basis of pushing the FCC capacity to the limit, it is

appropriate to discuss what will happen in the combustor. Prior comments on the

operating variables have addressed some of the concerns of higher capacity

operation, but an overall perspective is needed.

In general, pushing capacity to the maximum will result in a combustor operating at

high velocity, low density and low catalyst residence time. Directionally, this will tend

to increase afterburn and carbon on regenerated catalyst.

From earlier data shown regarding coke burning kinetics, carbon is reduced to

levels around 0.15 wt% very quickly, but to get to 0.05 wt% requires substantial

additional time. In a maximum capacity operation, there may not be sufficient time in

the combustor to reach carbon levels of 0.05 wt% or below.

It is important to point out that this is not all bad, and in fact may be economically

advantageous. With the use of promoter to maintain control of after burning, it is

possible to allow the CRC to increase as a trade off for more feed capacity.

Although effective catalyst activity is reduced, the reduction may be small enough to

justify the higher capacity operation.

Optimization Summary

All of the above variables need to be thoroughly understood, especially how they

interact with each other. Application of this knowledge properly will result in arriving

at the best operation for each particular unit. Optimization should be considered as

a continuous effort, since what is optimal in one set of circumstances may not be in

another.

As a final note, it should be emphasized that UOP is always interested in obtaining

feedback on the operation and experiences of these units from the refiner. Our

Technical Service department is always available to provide assistance or

consultation as needed. Only through working together can we hope to continue to

improve our designs and their performance capability.

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MAIN COLUMN BOTTOMS AND SLURRY SETTLER

INTRODUCTION

The main column bottoms system on an FCC presents some unusual mechanical

and operating problems. The vapors entering the column are superheated and

contain catalyst fines which may cause erosion or plugging. Heavy oil cascading

down the disc and doughnut (side-to-side on some units) trays cool and condense

the heavy vapors so that they can be fractionated. The catalyst fines are washed

down to the bottom of the column by this cascading stream.

COKE

Many units have some coke buildup in the reactor, vapor line, and bottom of the

main column. The amount in the reactor and vapor line can be minimized by good

insulation. The coke buildup in the main column is influenced by three factors:

1. Hydrocarbon characteristics 2. Temperature 3. Residence Time

Some hydrocarbons have a greater tendency to thermally crack and produce coke

than others. The Conradson or Ramsbottom carbon residue tests may be used to

get some idea of this tendency, but it is difficult to compare one stock with another.

The amount of catalytic cracking that has taken place in the reactor will influence

the coke production of the hydrocarbons in the main column. The operation of the

FCC unit and of the upstream units that produce FCC feed are controlled by other,

more important variables than the main column bottoms coke make. Temperature

and residence time control are used to minimize the bottoms coke problem.

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The maximum allowable temperature in the bottom of the tower is usually given as

700°F (370°C). Experience with a particular feed may raise or lower this somewhat,

but it is better to run lower to prevent coke problems. Many refiners use 680-700°F

(360-370°C) as the normal operating point.

The major control on the bottoms temperature is by the composition of the material,

but the quench line may also be used to sub-cool the bottoms material. This line

returns cool oil directly to the bottoms level, instead of to the disc and doughnut

trays. It is generally used at high throughput, when there is adequate flow to the

discs and doughnuts, and the heat input to the column is high.

Residence time refers only to the time spent in the column, not in the entire slurry

system. The oil begins to cool as soon as it leaves the tower. There may be some

minor coking in the slurry settler and associated piping, but usually this is not

enough to affect plant operations. If the oil is in the tower too long, at too high a

temperature, serious coking can plug the bottom. Removal is difficult, because

chipping away with hammers usually leads to lining damage. Other methods, such

as chemical cleaning, are usually ineffective.

At low charge rates, the bottoms circulation through the exchangers must be

reduced to heat balance the tower. The oil cascading down the discs and

doughnuts decreases to a point where the trays run dry. Because the hot reactor

vapors are not cooled, they can cause warping and distortion of both the disc and

doughnut trays and those above as this large volume of vapors tries to pass up the

column. Catalyst fines will be carried up into the HCO and LCO circuits, which can

be quite serious, because these areas are not designed for fines removal. Product

specifications will be adversely affected.

The solution to this problem and that of long residence times at low circulation rates

is to use the minimum flow line which bypasses the exchangers and returns oil

directly to the column, over the disc and doughnut trays. The flow over these trays

should be at least 50 gpm/ft tower ID (37.3 m3/hr/meter tower ID). This line is

usually used on startup, when the charge rate is low and the tower is cool. As

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charge rate increases, the flow rate through the minimum line is decreased to force

oil through the heat exchange circuits. There should always be a small amount of oil

flowing through the line, so that the oil does not set up. The same is true for the

quench line to the bottom of the fractionator.

Some units have used a large impingement baffle to break up the reactor vapors as

they enter the column. Many of these baffles proved to be a good starting point for

coke, and the baffles were removed. Inevitably, there is some coke buildup; pieces

may break off with thermal shock or other stresses. If a chunk of coke could enter

the bottom line, it could cause plugging or pump damage. A coke trap made of Type

405 or 410 stainless steel is used at the bottom of the column to keep these large

chunks out of the line. Smaller pieces of coke pass through it and are caught by the

pump suction screens. These can be cleaned on stream, while the larger chunks of

coke might prove difficult to remove from the line.

CATALYST CARRYOVER

The amount of catalyst carryover from the reactor will depend on unit design,

cyclone efficiency, catalyst type, and unit throughput. Unusual problems such as

high reactor level, cyclone failure through cracks or plugged diplegs, or pressure

surges can increase the catalyst carryover to unacceptable levels. A conventional

unit of older design (single stage cyclones) should lose less than 0.4 LB/bbl charge

over to the main column, with most of this returning with the slurry recycle. A new

unit with a riser "Tee" and high efficiency cyclones should lose less than 0.05

LB/bbl.

It is not practical to actually measure the catalyst content of the main column inlet

vapors. The catalyst content of the circulating bottom stream is, however, a good

indication of the catalyst losses. A general assumption may be made that very little

catalyst is entrained up into the HCO or LCO products. If this is not the case, the

bottoms circulation over the disc and doughnut trays should be increased as much

as possible, within the limits imposed by other operating variables. The lower part of

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the tower should be inspected carefully at the next turnaround to determine if the

problem is here.

The main column bottoms pump discharge manifold is constructed to direct the

catalyst fines and coke particles out of the circulating system. The lines to the

various exchangers come off the top of the manifold. The line to the slurry settler

will come off the end of the manifold from the bottom. If there is no settler, the

reactor recycle and bottoms product lines will both come off the bottom of the

manifold. This obviously will not achieve a complete removal of catalyst fines or

coke, but it will help prevent a buildup in the main column bottoms circulating

system.

SLURRY SETTLER

The slurry settler process flow is shown in Figure 16 in Process Control section.

Main column bottoms enter the settler through a tangential nozzle; this gives it a

swirling motion that promotes a more even distribution of the heavy oil as it moves

up towards the outlet. The catalyst fines settle out and are carried back to the

reactor. The carrying medium will depend upon the operation.

1. Low activity catalyst with large amounts of recycle:

This would be typical of older units that require the high recycle rates to get desired

conversion. The recycle consists of main column bottoms and HCO, which is cooler

and has a higher flowing specific gravity than the bottoms material. The HCO is

injected into the upper diluent point and flows down with some of the bottoms and

most of the catalyst that enters the settler. A plant operating in this mode would

have a CFR of 1.2 to 2.0.

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2. Higher activity catalyst with little or no recycle:

The use of the new higher activity catalysts and better reactor design enable the

refiner to crack most of the feed on the first try. The heavy oil product make is

lower; it is also a more refractory material which tends to go to coke and dry gas

when recycled to the reactor. The carrying material used in this case may be HCO,

but for many units, raw oil is the better choice. The bottom diluent injection point is

used to minimize the amount of raw oil that will go up into the settler. If the raw oil

thermally cracks or goes out with the CSO, it may cause problems with the CSO

product specifications. To help prevent this, the flow back to the reactor should

always be higher than the diluent flow to the settler.

SETTLER OVERHEAD

The amount of CSO that comes off the top of the settler will also depend upon the

operation. The decreased heavy oil make of the newer units can lead to a buildup of

catalyst in the main column because there is less main column bottoms leaving the

tower to take it out. This refers to oil leaving the system, not to the bottoms

circulation streams. The concentration of fines in the tower may build up enough to

cause serious erosion and plugging problems. The most effective solution is to use

a return line from the top of the settler to the main column disc and doughnut trays.

The flow to the settler can then be increased by the amount of oil which is returned

to the main column relatively free of catalyst.

Typical settler flow rates are shown in Table 11. For this table, it was assumed that

catalyst is coming overhead from the reactor at a rate of 100 LB/day. The catalyst

can only leave the system through the outlet to the settler; therefore, the

concentration will be equal to the amount of catalyst (100 LB/day), divided by the

flow to the settler.

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TABLE 11

SLURRY SETTLER FLOW

CASE A CASE B CASE C Feed to FCC, BPD 10,000 10,000 10,000 Main Column Bottoms To Slurry Settler, BPD 1500 500 1500 Main Column Bottoms Catalyst Concentration, lb/bbl 0.067 0.20 0.067 Diluent, BPD 500 500 500 CSO Product, BPD 1,000 500 500 Recycle to Reactor, BPD 1,000 500 500 CSO Return to Main Column, BPD 0 0 1,000

Case A would be an operation with lower activity catalyst and a higher CSO product

make. Case B would be a conversion to higher activity operation, decreasing the

amount of recycle and the CSO product. Neither Case A or B uses a return line

from the top of the settler to the main column. Case C is similar to B in that a higher

activity catalyst is used, with a small amount of main column bottoms produced. The

use of the return line from the top of the settler back to the main column allows the

flow to the settler to be increased to 1500 BPD. A limit on flow to the settler is the

velocity of fines settling. The liquid velocity should never exceed 30 BPD/ft2 (50

m3/d/m2) of settler cross sectional area. Above this, there may be problems with

catalyst carry over into the overhead stream.

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FCC UNITS WITHOUT SLURRY SETTLER

Some of the new units have incorporated a reactor cyclone configuration which

decreases the amount of catalyst carryover to the main column. The reactor riser

ends with a pair of outlet arms, and a two stage cyclone system on the reactor

outlet eliminates most of the catalyst in the overhead vapors. With this system,

some refiners have elected not to use a slurry settler. The recycle to the reactor and

the bottoms product come directly from the main column bottoms pump discharge

manifold.

PLUGGING

There are occasional problems with plugging in the lines or exchangers of catalyst

bearing streams. If there is a plant upset which causes large amounts of catalyst to

go overhead, such as a sudden dip in column pressure, immediate action should be

taken to remove the extra catalyst from the system. Increased slurry recycle and

clarified oil product would be the two most important steps. These should be

continued until the laboratory confirms that the BS & W content of the bottoms

stream is back to normal.

In the event of a major upset that completely fills the bottoms of the column with

catalyst, care must be taken to avoid further complications. Catalyst holds heat fairly

well and conducts it poorly, so the cool-down period may be on the order of several

days. The thermocouples in the column will be well insulated by the catalyst close to

the wall, so the readings will probably be lower than the actual temperature of most

of the catalyst. Introduction of cold oil or wash water will produce severe pressure

surges that may damage the column internals. The oil soaked catalyst is both a fire

and breathing hazard. The shutdown for cleanout can be estimated at one week, a

good argument against hasty measures that could lead to excessive catalyst

carryover to the column.

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MAIN COLUMN BOTTOMS EXCHANGERS

To prevent catalyst plugging or erosion in the exchangers, UOP calls for the

following velocities in the tubes:

1. Straight tubes: maximum velocity 8.0 ft/sec, minimum 4.00 ft/s.

2. U-tubes: maximum velocity 8.00 ft/sec, minimum 4.00 ft/s.

In general, the optimum velocity is 8.00 ft/s. Straight tube construction is

recommended. It is important to think of these numbers when changing raw oil

charge or exchanger flow rates. Plugged exchangers are difficult to clean. A catalyst

bearing stream is never routed through the shell side of an exchanger because the

catalyst fines will settle to the bottom of the exchanger. There will be a progressive

loss of heat transfer area as more and more tubes are covered by the fines.

MAIN COLUMN BOTTOMS HEAT REMOVAL

The main column bottoms circulation rate is adjusted to control the column's heat

removal requirement. The bottoms stream generally exchanges heat with the raw oil

feed and is utilized in the production of superheated steam in the steam generators.

A reduction or increase in the bottoms heat removal must be compensated by an

increase or reduction in heat removal in another section. Provided no other changes

are made, the overhead reflux rate will compensate for any changes in bottoms

heat removal. As illustrated in Table 12, a decrease in the bottoms stream heat

removal results in an increase in reflux rate. The bottoms stream heat removal

should be adjusted to minimize the reflux rate and maintain good product

distillations.

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TABLE 12

Feed Rate, BPD 17550 17550 Overhead reflux rate, BPD 10488 11581 Net ovhd light gas yield, MMSCFH 13.81 13.81 Net ovhd liquid yield, BPD 7973 7993 Ovhd heat removal, MM-BTU/hr 42.81 45.24 Net heavy naphtha yield, BPD 2782 2782 Circ. heavy naphtha heat removal MM-Btu/HR 12.32 12.32 Net LCO yield, BPD 1790 1790 Circ. LCO heat removal, MM-BTU/hr 10.17 10.17 Net bottoms yield, BPD 967 967 Circ. bottoms heat removal, MM-BTU/hr 31.0 28.57

GASOLINE/DISTILLATE PRODUCTION

The main column draw temperatures are dependent on the stream's composition

and vary with changes in draw rate. As the gasoline product draw is reduced, liquid

will drop down the column to the LCO draw tray and require an increase in LCO

product draw. The reduced gasoline draw rate will result in a lighter gasoline

product having a lower ASTM distillation end point and a lower draw tray

temperature. The LCO product also becomes lighter because of light material

dropping to the LCO draw tray. The LCO initial boiling point temperature will

decrease with a slight decrease in the draw tray temperature. Table 13 illustrates

the changes which result to the main column and product streams as the LCO yield

is increased by reducing the gasoline endpoint and yield.

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TABLE 13

Gasoline:

API 57.9 57.2 56.3

Product rate, BPD 15800 16200 16600

90% BP temp., °F 372 381 392

RONC 90.7 90.6 90.4

MC overhead temp., °F 311 316 323

Light cycle oil

API 20.1 19.8 19.3

Product rate, BPD 6000 5600 5200

Flash point, F 198 204 212

10% BP temp., °F 462 471 482

90% BP temp., °F 624 624 624

End point, F 664 664 664

MC draw temp., °F 482 485 499

Slurry

°API 6.2 6.2 6.2

Product rate, BPD 2800 2800 2800

GASOLINE CUT PROPERTIES

Gasoline or any other liquid stream can be broken up into numerous cuts, each

having distinct properties. Examining the cuts which comprise a typical gasoline

sample will show how overall product quality can be improved.

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A FCCU gasoline sample from a high severity operation was broken up into nine cuts, each having a narrow TBP range as illustrated in Table 14. The properties of the individual cuts are shown in Figures 6 and 7.

TABLE 14

Cut No. Cumulative TBP Fraction, °F Vol -% 75 - 93

1 20 93 - 145 2 30 145 - 181 3 40 181 - 210 4 50 210 - 250 5 60 250 - 286 6 70 250 - 286 7 80 286 - 334 8 90 334 - 387 9 100 387+

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FIGURE 15: FCC GASOLINE CUT PROPERTIES

0

100

200

300

400

1 2 3 4 5 6 7 8 9Gasoline Cut

Avg. B

oiling P

oin

t Tem

p, °

F

20

40

60

80

100

1 2 3 4 5 6 7 8 9

Gasoline Cut

API G

ravi

ty

80

84

88

92

96

100

1 2 3 4 5 6 7 8 9

Gasoline Cut

RO

NC

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FIGURE 16: FCCU GASOLINE CUT PROPERTIES

0

0.2

0.4

0.6

0.8

1

1.2

1 2 3 4 5 6 7 8 9Gasoline Cut

Sulfur, w

t %

0

10

20

30

40

50

60

70

80

90

100

1 2 3 4 5 6 7 8 9Gasoline Cut

Bro

min

e N

um

ber

0

10

20

30

40

50

60

70

80

1 2 3 4 5 6 7 8 9

Gasoline Cut

Liq

uid

Vo

l %

Paraff in/Naptha Aromatic Olefin

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The sulfur content of gasoline increases sharply in the last 387+ TBP fraction as

indicated in the Wt-% SULFUR graph. The overall sulfur content of gasoline hence

could be reduced by lowering the gasoline end point temperature.

The RONC graph of the various cuts indicates a reduction in octane at CUT 4

(181-210 TBP) and CUT 9 (387+ TBP). A slight increase in the overall gasoline

octane can be obtained by reducing the end point temperature of the gasoline. If it

were possible to remove CUT 4, gasoline octane could be further increased.

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ROUTINE PROCESS VARIABLE CONTROL

REACTOR REGENERATOR SECTION

This tabulation of process conditions is intended to assist the operator in selecting

the optimum operating conditions for different operations. It may be noted here that

process units rarely operate at their design conditions.

Variable Operating Conditions Raw oil charge rate As desired. Raw oil temperature To balance coke yield, conversion, and RON

requirements. Slurry recycle rate Normally at minimum. HCO or raw oil to Equal to or slightly less than total flow of slurry slurry settler recycle to reactor, or until clarified oil gravity

changes. Heavy recycle rate Heavy recycle rate can be varied to adjust

conversion product yields or increase coke yield. Combined feed temperature Normally as high as possible provided neither

reactor nor regenerator temperature is excessive. Reactor temperature As necessary to obtain desired conversion and

RON. Reactor pressure Equals fractionation column receiver pressure plus fractionation pressure drop. Reactor level (Riser To cover top stripping grid. cracking operation) Reactor level (Bed cracking Minimum level needed to achieve desired operation) conversion. Emergency steam to riser Used to initiate catalyst circulation on startup and

to avoid plugging the riser on an emergency shutdown. Normally not used.

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Variable Operating Conditions LCO or gasoline to riser Used to control regenerator temperature when the

unit is "behind in burning". Stripping steam Just enough to strip catalyst. This value can be

arrived at by observing the effect of decreasing the stripping steam on regenerator temperature. 1.5-2 lb/1000 lb catalyst circulation is typical.

Steam to feed nozzle Normally adjusted to maximize feed distributor

pressure drop within feed pump hydraulic constraint. Usually 1-2 wt% of feed.

Regenerator air rate As necessary to control regenerator temperature

spread or to give good control using automatic snort. On total CO burning units to obtain 1-4% oxygen in flue gas.

Regenerator dense Normally cracking conditions are varied to phase temperature optimize regenerator dense phase temperature.

Too cold and catalyst will not be well regenerated. Too hot and reaction with oil will be thermal with resultant loss of gasoline and increase in gas.

Regenerator dilute phase The difference between regenerator dense, dilute or flue gas temperature and flue gas temperatures is an indication of the (on conventional partial amount of excess oxygen present, and is the CO burning units) criterion by which the air rate is varied. Regenerator pressure Equals the reactor pressure plus the reactor (conventional) regenerator differential pressure. Regenerator pressure (with Regenerator pressure controlled, reactor-regener- flue gas power recovery) ator differential allowed to swing within reasonable

limits. Regenerator level The catalyst level can vary from about 35" to 80"

of H2O with the unit inventory and regenerator velocity.

Reactor-regenerator Varied to obtain stable slide valve differentials and differential pressure minimum utility consumption.

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Variable Operating Conditions Slide valve differential Dependent on vessel differential and catalyst pressure condition. Over-rides are normally set at 1-2 psi. Steam to spray and Flow will be almost zero except when sprays are torch nozzles in service. Torch oil rate Used on startup and to control afterburning on

partial CO combustion units. Torch steam pressure Only used when necessary to atomize torch oil

and normally 5-10 psi higher than regenerator pressure.

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TABLE 15

MAIN COLUMN

Variable Operating Conditions Main column bottoms Adjust clarified oil yield and quench to hold long temperature enough to prevent coking. Circulating slurry rate As necessary to control fractionating column heat

removal requirements. To minimize top reflux to obtain minimum gap (25-40°F) on gasoline between 90% and E.P.

Slurry return temperature Of little interest. Dependent on cleanliness of

exchangers, number in service and circulation rate.

Clarified slurry yield, or As necessary to control fractionating column main column bottoms bottoms temperature and level. yield if no slurry settler Main column bottoms BS&W Adjust flow to slurry settler, clarified oil return to

main column, and slurry recycle. If no slurry settler, adjust bottoms recycle and bottoms product.

Heavy recycle oil circulation Rate is set as desired to transfer heat to various

reboilers. Heavy recycle deck Depends on distillation range on heavy recycle temperature and on tower pressure. Light cycle oil yield Depends on charge rate and conversion, and is

varied to maintain desired properties of light cycle oil. Also used to control bottoms level.

Flush oil As required to keep catalyst out of instruments.

Normally 1500-2000 BPD, but this will vary between different units.

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Variable Operating Conditions Light cycle oil Enough to meet flash point specifications. stripping steam Light cycle oil Depends on distillation range of light cat gas oil deck temperature and on tower pressure. Unstabilized gasoline top Is varied to control tower top temperature and reflux rate depends on amount of heat removed lower in

column. Circulating top Depends on water temperature and flow rates. reflux temperature Fractionator column top Varied to control endpoint of unstabilized temperature gasoline. Overhead receiver pressure Can be varied as discussed. Overhead receiver Should always be as cold as is economically temperature possible. Unstabilized gasoline yield Depends on charge rate and conversion. Wet gas molecular weight Minor variations in density will be due to changes

in receiver conditions, but major changes will be due to increased hydrogen production. At low densities, the compressor will have an increased tendency to surge.

Wet gas flow Dependent on compressor speed but must be

adequate to handle production plus spillback for control. Must be above minimum to keep out of surge.

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TABLE 16

GAS CONCENTRATION SECTION Variable Operating Conditions Wet gas compressor Run at minimum governor until spillbacks close. Variable speed Fixed speed centrifugal Butterfly valve opens away from limiting stop as

spillbacks close. Fixed speed reciprocating On spillback control. Wet gas spillbacks Vary as needed to hold main column overhead

receiver and interstage pressure. Used to keep centrifugal machine out of surge.

High pressure separator Temperature 80°F-100°F (27°-38°C) Pressure Rides on primary absorber backpressure. Primary absorber Top and intercoolers Less than 100°F (38°C) temperatures Intercooler flow rates As needed for good absorption efficiency. Pressure Rides on sponge absorber backpressure. Sponge absorber Top temperature As cool as economically practical. Lean oil flow rate As needed for good absorption efficiency. Do not

flood tower. Pressure Controlled to give good absorption efficiency and

hold correct backpressure on HPS.

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Variable Operating Conditions Stripper Overhead vapor flow Controlled by heat input to column to give rate sufficient C2- and H2S stripping. Heat input to column Controlled to give proper overhead vapor rates. Pressure Rides on high pressure separator backpressure. Debutanizer Top temperature Controls reflux to give desired RVP of gasoline. Top reflux temperature Should be as cold as economically possible. Reboiler heat As required to give good fractionation. Pressure Varied as needed for good fractionation, but must

be high enough to allow condensation of C3-C4 stream by air fin fans or cooling water.

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PROCESS CALCULATIONS

INTRODUCTION

Throughout the years the Fluid Catalytic Cracking process has been a very versatile

and flexible tool for the refiner, and has become the basic conversion step in the

modern refinery. This process has survived and prospered because of its ability to

handle the many changes in catalyst, operating conditions, and feedstocks that have

occurred over the years.

The FCC Unit produces large volumes of high octane gasoline, olefinic LPG, fuel oil

(LCO and MCB), fuel gas, steam, and electricity. The yields are mainly determined by

process variables (i.e. feedstock, operating conditions, mechanical features, and type of

catalyst). Process variables have varying degrees of interdependence and may change

frequently producing changes in the yield structure of the products. A performance test

conducted at least once a week is recommended to evaluate the effect of process

variables on yield. The tests can be used to chart a history of the unit and to find

conclusions at different operating conditions.

The performance test provides accurate yield structures at a particular set of operating

conditions and provides a base point for further testing. The Performance Test normally

includes a heat balance, material balance, and a pressure survey. In those cases where

more information is desired, a Mechanical Evaluation Test is recommended. The refiner

can use this test to assess the potential of the unit and determine possible bottlenecks.

This section explains how to accomplish an acceptable Heat and Material balance and

how to do some of the most important calculations in the FCC Unit. An FCC

Performance Test Procedure is available on request from the Technical Service

Department. This procedure explains in detail how to conduct a performance test in the

FCC Unit.

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MATERIAL BALANCE

A material balance on an FCC Unit is done by drawing an envelope around the unit in a

manner that flow rates are known for all streams. This envelope includes the Reactor,

Regenerator, Main Column, and Gas Concentration sections. Normally, the Gas

Concentration Unit includes the primary absorber, sponge absorber, stripper column,

and debutanizer column.

1. Data

Flow rates, flowing temperatures and laboratory analyses are required for each stream.

Pressure is also needed for the gas streams. The following table shows the information

needed to do a material balance:

INPUT DATA FOR HEAT AND MATERIAL BALANCE

Stream Flow Temp. Pressure API Distillation GC Meter Factor

Feed Yes Yes Yes D-1160 Yes

Air* Yes Yes Yes Yes

MCB Yes Yes Yes D-1160 Yes

LCO Yes Yes Yes D-86 Yes

Gasoline Yes Yes Yes D-86 Yes Yes

LPG Yes Yes Yes Yes

Sponge Gas Yes Yes Yes Yes Yes

Flue Gas Yes

Notes *Ambient temperature and relative humidity of air are needed.

Reactor, Regenerator, and combined feed temperature are needed for Heat Balance

The method for including extraneous streams is straight forward as long as flow rates

and analyses are known. These additional streams coming into the Main Column and

Gas Concentration Unit are subtracted from the product streams.

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2. Liquid Streams

Calculate corrected liquid flow rates using the following equation:

Q = K R (Gf)1/2 / Gb

Where: Q = flow rate

K = flow meter constant ("K" factor)

R = chart reading

Gb = base gravity @ 60°F

Gf = gravity at flowing temperature

The flowing gravity Gf is calculated using the following equation:

Gf = Gb x VCF

Where: VCF = Volume correction factor

VCF = EXP [ (-ßo) ∆T(1+0.8 ßo ∆T) ] 0.9545

Where:

Go = density at 60°F in kg/m3 926

T = observed temperature in °F 173

∆T= T - 60 113

ßo = coefficient of thermal expansion at 60°F, (1/°F)

The set of correlations for the coefficient of thermal expansion based on API Data

Tables are:

ßo = (Ko + K1 Go + K2 Go² )/ Go² 0.00039779

Where:

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Product °API Range Ko K1 K2

Crude Oils 0 – 100 341.0957 0 0

Gasoline 52 – 85 192.4571 0.2438 0

Gasoline/Jet 48 – 52 1489.0670 0 -0.0018684

Jet Fuels 37 – 48 330.3010 0 0

Fuel Oils 0 – 37 103.8720 0.2701 0

Lubricating Oils -10 – 45 0 0.3488 0

For FCC Raw Oil Feedstock (VGO); Ko = 341.0957, K1 = 0, K2 = 0

The following rounding is applied to the input and output of all routines.

Temperature: 0.1°F

Density: 0.1 °API or 0.5 kg/m3

VCF: five significant figures for computation

Example: Raw Oil Charge

K = 3,380 in BPSD

R = 8.9

Gb = 0.9260

VCF = 0.9545

Gf = 0.9260 x 0.9545 = 0.8839

Q = 3,380 x 8.9 x (0.8839)1/2 / 0.9260= 30,542 BPSD

Q = (BPSD) x 5.614583 ft3/bbl x (Gb x 62.3635 lb/ft3 H2O)/24 hr/day

Q = 412,615 lb/hr

Similar calculations are done for all C5+ liquid streams. LPG streams are treated as follows:

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Estimation of VCF for LPG

The following equation approximates VCFs from API Tables #33 and #34:

1.060T10VCF B*GbA

Where:

T = Flowing Temperature, °F

Gb = Specific Gravity @ 60°F, in g/ml

A = 2.64641798

B = 1.40583481

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3. Gas Streams

Calculate corrected gas and air flow rates as follows:

Q = K x R x (Pf/(Tf x SG))1/2

Where: Q = flow rate

K = flow meter constant ("K" factor)

R = flow meter reading

Pf = Pressure at flowing conditions (absolute)

Tf = Temperature at flowing conditions (absolute) SG = specific gravity of gas = MWgas/MWair (1.0 for air)

Example: Sponge Gas Q = K x R x [(Pf/(Tf x SG))]1/2 Where: K = 91,848 scfh R = 6.5 chart reading Pf = 173 psig + 14.7 = 187.7 psia Tf = 113°F + 460 = 573°R SG = 0.7054 from Sponge gas calculations MW = 18.9 from Sponge gas calculations Q = 91,848 x 6.5 x [(187.7)/(573 x 0.7054)]1/2 = 406,837 scfh M = Mass Flow = scfh x MW/379.67 = 20,261 lb/hr Where: 379.67 is the conversion factor for scf / mol Similar calculations are done for all gas, vapor, and air streams.

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4. Calculate Coke The coke make is calculated from the Heat Balance. (Refer to Heat Balance calculation section.) 5. Calculate the as Produced Yields A product yield is defined as the product rate divided by the raw oil rate. The volume percent of each product stream is:

Vol-% (A) = (A, bpsd)100/Fresh Feed, bpsd The weight percent is:

Wt-% (A) = (A, lb/hr)100/Fresh Feed, lb/hr Where: A = any product stream

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6. Weight and Liquid Volume Recoveries

Once the weight and the volume flows are known for each stream, the Weight recovery

and the Liquid volume recovery can be calculated. Proper data analysis requires that

the Weight recovery must be 100.0 2.0 wt-%. Errors outside this range are significant

and cast doubts on the validity of the test data. The Sponge Gas used to calculate the Weight recovery should not include the inert gases (N2, O2, CO, CO2). In addition, the

as-produced Liquid Volume recovery does not include the C3+ from the sponge gas.

Weight % Recovery = (Products, lb/hr x 100)/(Fresh Feed + Extraneous Feeds) lb/hr

Liquid Volume % Recovery = (Products, bpsd x 100)/(Fresh Feed + Extraneous

Feeds)bpsd

7. Conversion

Conversion is defined as the volume percentage of raw oil converted to gasoline and

lighter components. This is calculated as:

Conversion, Vol% = Feed - LCO - HCO - MCB

Feed 100

This conversion is called ‘as-produced’ or ‘apparent’ conversion because is not corrected

for cut-points. The ‘corrected’ or ‘true’ conversion is calculated using the same equation

after the gasoline and LCO yields are corrected for cut-points.

8. Gasoline and LCO Yield Adjustments

It is important to correct the gasoline and LCO yields on a constant cut-point basis. It is

inaccurate to compare gasoline yields at different 90% or EP temperatures. The gasoline yield must also be adjusted by removing the C4's and adding the C5's and C6's from the

LPG and Sponge Gas streams. The procedures to adjust the liquid yields and to calculate the C4's in the gasoline are attached in this section.

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9. Gasoline Selectivity

The gasoline selectivity is the corrected gasoline yield divided by the true conversion:

Gasoline Selectivity = (Corrected Gasoline Yield)

True Conversion 100

10. LPG and Sponge Gas Calculations

These procedures use the mol percentage from the GC analysis, the molecular weight,

and the specific gravity to calculate the flow rate of each component. Also, the stream

specific gravity and molecular weight are calculated. The procedure is attached in this

section.

11. C3 and C4 Recovery

The C3 and C4 recovery indicate how the Gas concentration is performing. The C3

recovery is calculated as:

C3 Recovery, Vol% = C3 in LPG

(C3 in LPG + C3 in Fuel Gas) 100

The C4 recovery is calculated as:

C4 Recovery, Vol% = C4 in LPG

(C4 in LPG C4 in Fuel Gas C4 in Gasoline) 100

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FCC Unit Material Balance

Refiner: _______________________________ Location: _______________________ Date: __________

TI - Tag FE - Tag Gravity Vol.Corr. Flowing Meter

Temp. °F Readings Gb@60°F Factor Gravity Gf "K" BPSD lb/Hr Vol% Wt%

1 Fresh Feed (FF) TI—10 FRC-10

173 8.90 0.9260 0.9545 0.8839 3,380 30,538 412,601

2 Main Col Bottoms (MCB)

TI-20 FRC-20

462 4.80 1.0412 0.8806 0.9169 418 1,843 28,005 6.04 6.79

3 Light Cycle Oil (LCO)

TI-30 FC-30

101 9.00 0.9200 0.9838 0.9051 700 6,515 87,450 21.33 21.19

4 Gasoline (DebBt) TI-40 FRC-40

148 7.60 0.7599 0.9489 0.7211 2,118 17,987 199,434 58.90 48.34

5 LPG TI-50 FRC-50

87 7.20 0.5612 0.9653 0.5418 632 5,964 48,833 19.53 11.84

6 LPG (ELPG) Extraneous Feed

TI- FRC-

0 0 0.00 0.00

7 Coke See attached Heat Balance calculation sheet. 25,187 6.10

PE-Tag

Press, psig SCFM

8 Sponge Gas (SGas) TI-60 FC-60 PRC-60 W/o Inerts 6,589 18,821 4.56

113 6.50 0.6519 173 1,518 6,996 20,887

8 Gas (HGas) Extraneous Feed

TI- FC- PRC- W/o Inerts 0 0 0.00

9a Air to Regenerator (Dry Back)

TI-70 FIC-70 PI-70

415 6.83 1.00 44.5 46,000 81,721 374,251

9b Air to Cat. Cooler TI-72 FIC-72 PI-72

230 5.00 1.00 56 325 520 2,382

9c Air to Distributor 2 TI-74 FIC-74 PI-74

230 6.20 1.00 56 635 1,260 5,771

9 Total Air to Regen (Wet Basis) 83,502 382,405

As produced Calculations

10 Weight Rec Inert Free = [MCB lb/hr+LCO lb/hr+DebBt lb/hr+LPG lb/hr+SGas lb/hr+Coke lb/hr]*100/ [FF lb/hr+ELPG lb/hr+EGas lb/hr] =

= 98.82 Wt%

11 Liquid Vol. Recovery = [MCB bpsd+LCO bpsd+DebBt bpsd+LPG bpsd]*100/[FF bpsd+ELPG bpsd] = 105.8 Vol%

12 Conversion = [FF bpsd-MCB bpsd-LCO bpsd]*100/[FF bpsd] = 72.6 Vol%

For Liquids : BPSD = Units K [SQRT(Gf)]/Gb

: lb/hr = [BPSD (Gb) (5.6146ft3/bbl) (62.3689lb/ft3)]/(24h/d) = (14.591) ( BPSD) (SG)

For Gases or Air : SCFM = K Units SQRT{psia/(°R*Gb)} lb/hr = (scfm MW 60min/hr)/379.5

LV% = (stream, bpsd)(100)/(FF, bpsd) Wt% = (stream, lb/hr)(100)/(FF, lb/hr) uop1292rc

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FCC Unit Material Balance Continuation Refiner: _______________________________ Location: ____________________ Date: _____________

Yields Adjustment for Gasoline @ 380°F - 90% and LCO @600°F - 90%.

IBP, °F 10%, °F 70%, °F 90%, °F EP, °F °API BPSD lb/hr

Gasoline 367 410 54.71 17,987 199,434

LCO 319 460 569 618 653 22.30 6,515 87,450

MCB 524 710 4.40 1,843 28,005

Totals 26,346 314,889

Gasoline

Gasoline Factor (F1) = [(380-T90)/(EP-T90)](1/9)+1 = [ ( 380 – 367 )/(410-367)] (1/9) + 1= 1.034 F1

LCO Factor (F2) = [(380-IBP)/(T10-IBP)](1/9) = [ ( 380 - 319 )/(460-319)] (1/9) = 0.05 F2

cGasoline, BPSD = (Gasoline, bpsd)(F1) + (LCO,bpsd)(F2) = 18,587 cBPSD 60.9 cLV%

c °API = API + 37.5(LV% - cLV%) / LV% = 52.13 c °API 0.771 cSG

cGasoline, lb/hr = cBPSD x cSG x 14.591 = 208,974 c lb/hr 50.6 cWt%

Gasoline Yield Adjustment for C4's, C5's, & C6's. lb/hr BPSD

C4's in Gasoline = 3,390 380

C5's + C6's in LPG = 423 46

C5's + C6's in SGas = 248 26

C5's + C6's in Extr Feeds = 0 0

13 Corrected Gasoline, BPSD = cGasoline-C4's+C5's+C6's Extr(C5+C6) = 18,587 corrBPSD 60.9 corrLV%

14 Corrected Gasoline, lb/hr = cGasoline-C4's+C5's+C6's-Extr(C5+C6) = 208,974 corrlb/hr 50.6 corrWt%

15 Corrected °API = ((141.5*BPSD*14.591)/(lb/h*24))-131.5 = 52.13 corr°API

LCO

LCO Factor (F3) = [(600-T70)/(T90-T70)](0.2)+0.7 = [ (600-569)/ (618-569)] (0.2) +0.7 = 0.827 F3

MCB Factor (F4) = [( 600-IBP )/( T10-IBP )]( 0.1 ) = [ ( 600 - 524

)/ (710-524)] (0.1) = 0.041 F4

Gasoline Factor (F5) = Gasoline - cGasoline = ( 17,680) - (18,587) = -907 F5

16 Corrected LCO, BPSD = [(LCO bpsd)F3 + (MCB bpsd)F4 + F5]/0.9 = 5,059 corrBPSD 16.6 corrLV%

17 Corrected LCO °API = API + 5( LV%-corrLV% )/LV% = 23.42 corr°API 0.913 corrSG

18 Corrected LCO, lb/hr = corrBPSD x corrSG x 14.591 = 67,416 corrlb/hr 16.3 corrWt%

MCB

19 Corrected MCB, BPSD = Total C5+ Liq. Yield - Corr Gasoline - Corr LCO =

= 17,689+6,515 +1,843-18,587 -5,059 = 2,392 corrBPSD 7.8 corrLV%

20 Corrected MCB, lb/hr = Total C5+ Wt. Yield - Corr Gasoline - Corr LCO =

= 196,715+ 87,450+ 28,005-208, 974-67, 416 = 35,780 corrlb/hr 8.7 corrWt%

21 Corrected °API = [( 141.5 * BPSD * 5.6146 * 62.3689 )/( lb/h * 24 )] - 131.5 = 6.5 corr°API

22 True Conversion = [FF bpsd - corrMCB bpsd - corrLCO bpsd]100/[FF bpsd] = 75.6 corrVol%

*Note that Total C5+ yield = cGasoline + LCO + MCB API = (141.5/SG) - 131.5

Note- The Factor equations are valid only if the as produce 90% temperatures are between 360-400°F for gasoline and 580-620°F for LCO.

The Factor Equations were developed from the 90% plus 10% Method. Used this method if the 90% Temp. are not in the specified range.

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Sponge Gas Calculations Example Refiner: ______________________________Location: _____________________________ Date: _______________ A B C=AxB D E F

Component MW mole% g/100mol Ib/hr sp gr bpsd (scfh)

O2 32.00 0.04 1.3 14 (168) CO 28.01 0.00 0.0 0 (0) CO2 44.01 1.47 64.7 716 (6,170) N2 28.01 4.31 120.7 1,335 (18,091) Total Inertes (t) 5.82 186.7 2065 (24,429) H2 2.02 28.29 57.0 631 (118,745) H2S 34.08 2.57 87.6 969 (10,787) C1 16.04 28.21 452.6 5,006 (118,409) C2 30.07 15.83 476.0 5,265 (66,445) C2= 28.05 15.55 436.2 4,825 (65,270) C3 44.10 0.48 21.2 234 0.5077 31.6 C3= 42.08 1.48 62.3 689 0.5220 90.4 iC4 58.12 0.59 34.3 379 0.5631 46.2 nC4 58.12 0.25 14.5 161 0.5844 18.8 1-C4= 56.11 0.24 13.5 149 0.6013 17.0 i-C4= 56.11 0.25 14.0 155 0.6004 17.7 t-C4= 56.11 0.12 6.7 74 0.6100 8.4 c-C4= 56.11 0.06 3.4 37 0.6271 4.1 1,3-C4== 54.09 0.00 0.0 0 0.6272 0.0 i-C5 72.15 0.00 0.0 0 0.6248 0.0 n-C5 72.15 0.00 0.0 0 0.6312 0.0 C5= 70.14 0.00 0.0 0 0.6496 0.0 C6+ 86.18 0.26 22.4 248 0.6640 25.6 Total Products 94.18 1,702 18,821 259.8 TOTAL (T) 100.00 1,888 20,887 (404,086) MW = TC/TB = 18.9 Pres. Psig = 173 =14.7=psia 187.7 SG = MW/28.966 = 0.6519 Temp. F = 113 + 460=R 573.0 Mole % Inerts=tB= 5.82 Meter Units = 6.5 Wt% Inerts=100tD/TD= 9.89 Meter K = 91,100 Inerts = tD = 2,065 Ib/hr Gas with Inerts: V = Vol. Flow = KxUnitsxSQRT{psia/(R*SG)} = 419,742 scfh M = Mass Flow = scfh x MW/379.5 = 20,887 Ib/hr Inert-free Gas: Mass = (M – Inerts) = M(100-wt%Inerts)/100 = 18,821 Ib/hr Vol. Flow=(V)-(tF)=V-(V x M%Inerts/Tmoles) = 395,313 scfh bpsd = [Ib/hr x24]/[ SGx5.614583ft3/bblx62.3689lb/ft3] scfh = V x Mol%/TB

D = C x M/TC = C x Total Mass Flow/(Total gr/100 mol)

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Debutanizer Overhead (LPG) Calculation Example:

Refiner: ______________________________Location: _____________________________ Date: _______________

A B C=AxE D E=C/D F=MxCftC G=VxE/tE

Component MW mole% g/100mol SG cc/lOOmol lb/hr bpsd

H2S 34.08 0.0 0.0 0.7871 0 0

C2 30.07 0.0 0.0 0.3563 0 0

C2= 28.05 0.0 0.0 0.3680 0 0

C3 44.10 12.1 533.6 0.5077 1,051 5,216 704

C3= 42.08 36.2 1523.3 0.5220 2,918 14,891 1,955

iC4 58.12 10.7 621.9 0.5631 1,104 6,080 740

nC4 58.12 3.8 220.9 0.5844 378 2,159 253

1-C4= 56.11 8.5 476.9 0.6013 793 4,662 531

i-C4= 56.11 12.4 695.7 0.6004 1,159 6,801 776

t-C4= 56.11 9.2 516.2 0.6100 846 5,046 567

c-C4= 56.17 6.2 347.9 0.6271 555 3,401 372

1,3-C4== 54.09 0.3 16.2 0.6272 26 159 17

i-C5 72.15 0.4 28.9 0.6248 46 282 31

n-C5 72.15 0.2 14.4 0.6312 23 141 15

C5= 70.14 0.0 0.0 0.6496 0 0 0

C6+ 86.18 0.0 0.0 0.6640 0 0 0

TOTAL (t) 100.0 4,996 8,899 48,838 5,962

LPG S.G. = tC/tE = 0.5614 Temperature, 0F = 87

LPG MW = tC/tB = 50.0 Vol. Corr. Factor = 0.9653

Flow Gravity, Gf = 0.5419

Meter Units = 7.2 Meter K = 631.5 V=Vol.Flow=Units x K x [SQRT(Gf)]/SG = 5,962 bpsd

M = Mass Flow = (BPSD x SG x 5.6146ft3/bb1 x 62.3689lb/ft3)/24hr/d = = 48,838 lbs/hr

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Propane and Butane Recovery Calculation Example:

( 1 ) ( 2 ) ( 3 ) ( 4 ) ( 5 ) ( 6 ) Sponge Gas Debutanizer Overhead Stabilized Gasoline

(Debut. Bottoms) Component bpsd lb/hr bpsd lb/hr bpsd lb/hr C3 32 234 704 5,215 0 0 C3= 90 689 1,956 14,888 0 0 Total C3’s (t) 122 923 2,660 20,103 0 0 iC4 46 379 740 6,078 0 0 nC4 19 161 253 2,159 47 399 1-C4= 17 149 531 4,661 34 299 i-C4= 18 155 776 6,800 34 299 t-C4= 8 74 567 5,045 112 997 c-C4= 4 37 372 3,400 44 399 1,3-C4= = 0 0 17 159 109 997 Total C4’s (T) 112 956 3,257 28,301 380 3,390 C3 Recovery = t(4) * 100 / [t(2) + t(4)] = 95.6 wt-% C4 Recovery = [T(4) + T(6)] * 100 / [T(2) + T(4) + T(6)] = 97.1 wt-%

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Yields Adjustment Composite 90% Plus 10% Method This method uses the ASTM distillation of the liquid products to create a composite curve and correct the yields to any specified 90% temperatures. Procedure 1. Using the ASTM distillation and a straight line interpolation equation, calculate

the LV% distilled every 20F for all the product streams.

%x=[(Tx-Ta)/(Tb-Ta)](%b-%a)+%a Straight line interpolation equation

%a < %x < %b Ta < Tx < Tb 2. Calculate the composite volume and percent every 20F using the following

equations:

Cumulative BPD @ Tx =

BPD = [(%Gasoline) (BPSD Gasoline) + (% LCO) (bpsd LCO) + (% MCB) (bpsd MCB)}/100

Cumulative LV% @ Tx = 100 BPD/Total BPD 3. Calculate Corrected Gasoline 90% @ 380F or Specified 90% Temperature: Corrected Gasoline (Composite Yield @ 380F)/(0.9) 4. Calculate Corrected LCO 90% @ 600F or Specified 90% Temperature:

Corrected LCO = (Composite Yield @ 600F)-(Corr Gasoline)/(0.9)

5. Calculate Corrected MCB by difference:

Corrected MCB = Total Liquid Yield – Correct Gasoline – Correct LCO

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Data:

Gasoline LCO MCB Total (%) (°F) (°F) (°F)

IBP 94 319 524 10% 124 460 710 30% 165 503 759* 50% 222 533 807* 70% 294 569 876* 90% 367 618 1100* EP 410 653 1200* BPSD 17,680 6,515 2,227 26,422

Note - *These temperatures are not needed.

%x = ((Tx-Ta)/(Tb-Ta))*(%b-%a)+%a

%a < %x < %b

Ta < Tx < Tb

i,e,

= ((100-94)/(124-94))*(10-0) +0 = 2.5 BPD = [(%Gasoline)(BPSD Gasoline) + (% LCO)(bpsd LCO)+(% MCB)(bpsd MCB)}

/ 100 % = 100 BPD / Total BPD

157048 Process Calculations

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Data:

Gasoline LCO MCB Composite Tx, °F %x %x %x BPD* Percent

80 0.0 0 0 100 2.0 354 1.34 120 8.7 1,532 5.80 140 17.8 3,148 11.91 160 27.6 4,873 18.44 180 35.3 6,235 23.60 200 42.3 7,475 28.29 220 49.3 8,716 32.99 240 55.0 9,724 36.80 260 60.6 10,706 40.52 280 66.1 11,688 44.24 300 71.6 0.0 12,667 47.94 320 77.1 0.1 13,640 51.62 340 82.6 1.5 14,701 55.64 360 88.1 2.9 15,726 59.66 367 90.0 3.4 16,134 61.06 380 93.0 4.3 16,728 63.31 400 97.7 5.7 17,643 66.77 410 100.0 6.5 18,100 68.51 420 100.0 7.2 18,147 68.68 440 100.0 8.6 18,239 69.03 460 100.0 10.0 18,332 69.38 480 100.0 19.3 18,938 71.67 500 100.0 28.6 19,544 73.97 520 100.0 37.9 0.0 20,150 76.26 540 100.0 53.9 0.9 21,210 80.27 560 100.0 65.0 1.9 21,958 83.10 580 100.0 74.5 3.0 22,600 85.54 600 100.0 82.7 4.1 23,156 87.64 618 100.0 90.0 5.1 23,656 89.53 620 100.0 90.6 5.2 23,696 89.68 640 100.0 96.3 6.2 24,092 91.18 660 100.0 100.0 7.3 24,358 92.19 680 100.0 100.0 8.4 24,382 92.28 700 100.0 100.0 9.5 24,406 92.37

Corrected Gasoline = (Composite Yield @ 380F) / (0.9) = (16,728 / 0.9) = 18,587 BPD Corrected LCO = ((Composite Yield @ 600F) - (Corrected Gasoline)) / (0.9) = (23,156 – 18,587) / 0.9 = 5,077 BPD Corrected MCB = (Total Liquid Yield – Corrected Gasoline – Corrected LCO) = (26,422 – 18,587 – 5,077) = 2,759 BPD

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REACTOR AND REGENERATOR HEAT BALANCE

Burning coke in the regenerator provides all the heat necessary for the operation of

the unit. Yet, roughly 30-40% of the heat generated by the combustion of coke exits

the regenerator in the form of hot flue gas. The remainder is absorbed by the

regenerated catalyst which carries it to the reactor riser where it is used to vaporize

and heat up the combined feed to the desired cracking temperature.

The amounts of energy associated with the unit's operation are determined from a

catalyst section heat balance. The energy balance equation at steady state may be

written as:

Energy in + Energy produced = Energy out + Energy consumed (1)

Regenerator Energy Balance

Energy in = Energy (air + spent catalyst + coke)

Energy produced = Combustion heat of coke

Energy out = Energy (flue gas + regenerated catalyst + removed +

radiation losses)

Energy consumed = 0

If the Regenerator temperature is the reference temperature then,

-∆H Air - ∆H Spent Catalyst - ∆H Coke + ∆H Combustion of coke = ∆Hremoved + ∆Hradiation losses

or: ∆H Spent Catalyst = ∆H Combustion of Coke - ∆H Coke - ∆H Air - ∆Hremoved -

∆Hlosses (2)

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Reactor Energy Balance

Energy in = Energy (feed + regenerated catalyst + diluents)

Energy produced = 0

Energy out = Energy (reactor vapors + spent catalyst + radiation losses)

Energy consumed = Heat of reaction

If the Reactor temperature is the reference base temperature, then

-∆Hfeed - ∆Hdiluents + ∆Hregenerated catalyst = ∆Hradiation losses + Heat of Reaction

or

∆Hregenerated catalyst = ∆Hfeed + ∆Hdiluents + ∆Hradiation losses +

Heat of Reaction (3)

The enthalpy change for the spent and regenerated catalyst is given by

∆Hspent catalyst = mass flow Cp (Rg Temp - Rx Temp) (4)

∆Hregenerated catalyst = mass flow Cp (Rx Temp - Rg Temp) (5)

At steady conditions,

∆Hspent catalyst + ∆Hregenerated catalyst = 0 (6)

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Regenerator Heat Balance

H C o mbustion o f Coke

R a d i a t i o n L o s s e s

H e a t R e m o v a l

Flue Gas

Air

Spent Cata l y s t

Coke

Regenerate d C a t a l y s t

Reactor Heat Balance

H Reaction Radiation Losses

Diluents

Reactor Vapors

Spent Catalyst

Coke

Feed

Regenerated Catalyst

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Combining equations (2), (3) and (6)

∆H Combustion of coke = ∆H Air + ∆H Coke + ∆Hremoved +

∆Hregen.rad. losses + ∆Hfeed + ∆Hdiluents +

∆Hrx rad. losses + Heat of Reaction (7)

The equation (7) demonstrates that all the energy in the Reactor-Regenerator

system is provided by the combustion of coke. The radiation loss term in this

equation is not a major item, but since vessel insulation is not perfect, some radiation losses do occur. The term ∆Hremoved refers to the heat duty of catalyst

cooler(s). The heat of reaction is the energy required to convert the feed to products

via the catalytic reaction mechanism.

The heat produced by the combustion of coke, equation (7), can be calculated from

the coke product rate and the mode of the regeneration operation. If all the CO were burned to CO2 in the regenerator, more heat would be available per pound of

carbon than when the unit runs in this normal partial combustion mode. The heat liberated by carbon combustion to CO2 is 14,150 BTU/lb (7,860 kcal/kg or 32,910

kj/kg) of carbon whereas heat for combustion to CO is only 3,960 BTU/lb (2,200

kcal/kg or 9,210 kj/kg).

Conversion Factors:

kcal/kg 1.8 = BTU/lb

BTU/lb 2.326 = kJ/kg

kcal/kg 4.187 = kJ/kg

The heat of reaction is endothermic. Energy is consumed by the reaction which

breaks the heavy hydrocarbon molecules into smaller, light hydrocarbon products.

The heat of reaction must be calculated from the energy balance using equation (7).

The most important value that can be calculated from the energy balance is the

catalyst/oil weight ratio. This ratio is important because it is a major factor in

hydrocarbon conversion and coke lay-down.

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The following sample outlines the energy balance calculation method:

1. Data Required

This heat balance is for a 30,565 BPSD feed case with the FCC Unit in total

combustion mode. The process conditions are:

Temperatures: Reactor 970°F

Combined Feed 375°F

Lift Gas 100°F

Lift Steam 380°F

Feed Steam 380°F

Stripping Steam 380°F

Regenerator

Regenerated Catalyst 1371°F

Flue Gas 1368°F

Average Hottest in Rg 1375°F

Air Blower Discharge 399°F

HP Boiler Feed Water 220°F

Catalyst Cooler Steam 463°F

Pressures: Catalyst Cooler Steam 452 psig

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Flow Rates: Fresh Feed 412,923 lb/hr

(No Recycle)

Lift Gas 3,250 lb/hr

Lift Steam 12,900 lb/hr

Feed Steam 1,800 lb/hr

Stripping Steam 5,000 lb/hr

Total Air to Regenerator* 382,405 lb/hr

Catalyst Cooler Steam 56,033 lb/hr

Catalyst Cooler Blowdown 6,952 lb/hr

* Total air includes: air to combustor, air to upper regenerator, and air to catalyst

cooler.

Flue Gas Composition, mol% CO = 0.0 (by GC Method) CO2 = 15.50

O2 + Ar = 3.47 N2 = 81.03

SO2 = 0.0

NO2 = 0.0

2. Flue Gas Composition Adjustment

Unlike an Orsat analysis, a GC analysis includes Argon with the Oxygen. The first

step is to adjust the flue gas O2 content for Argon (Ar). The Ar content is assumed

to be 1.2% of the nitrogen, therefore,

Ar = (0.012) (81.03) = 0.97 mol%.

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The corrected analysis is now:

CO = 0 CO2 = 15.50

O2 = 3.47 - 0.97 = 2.5

N2 + Ar = 81.03 + 0.97 = 82.0

SO2 = 0

NO2 = 0

3. Combustion Air Corrected to a Dry Basis

A psychometric chart is used to determine the moisture content of the regeneration

air. At atmospheric conditions of 62°F and a relative humidity of 97%, the moisture

content is:

Moisture Content = 0.01152 lb H2O

lb dry air

Wet Air = 380,200 lb/hr

Dry Air = 380, 200 lb/hr wet air 1 lb dry air

(1 + 0.01152) lb wet air = 375, 870 lb/hr

Water in Air = 380,200 lb/hr - 375,870 lb/hr = 4,330 lb/hr

4. Calculate Flue Gas Rate

The flue gas rate can be calculated from the regeneration air rate. These two

streams are related by the inert N2 + Ar content which remains constant through the

catalyst regeneration. From a Nitrogen balance,

Since, moles = Weight

Molecular Weight

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Then Dry Air = (375,870 lb/hr)/(28.966 MW) = 12,976 lb mol/hr mol/hr (N2 + Ar) in dry air = mol/hr (N2 + Ar) in flue gas

12,976 lb mol

hr

79 mol inerts

100 mol air =

lb mol FG

hr

82 mol inerts

100 mol FG

Flue Gas (FG) = 12,501 lb mol/hr 5. Calculate the Carbon (C) Content of Coke The carbon (C) content of the coke is calculated from the flue gas composition. One mol of C is burned for each mole of CO or CO2produced. C + O2 + H2 + S + N = CO + CO2 + H2O + SO2 + NO2 + O2

C = 12,501 lb mol

hr FG

0 mol CO + 15.503 mol CO2

100 mol FG

1 mol C

mol CO/CO2

C = 1,938 lb mol/hr of carbon 6. Calculate the Hydrogen Content of Coke

The hydrogen (H2) content of the coke must be calculated from an O2 balance:

O2 in regeneration air = excess O2 in flue gas +

+ O2 reacted to CO (0.5 mol O2/mol CO) + O2 reacted to CO2 (1 mol O2/mol CO2) + O2 reacted to H2O (0.5 mol O2/mol H2O) + O2 reacted to SO2 (1 mol O2/mol SO2) + O2 reacted to NO2 (1 mol O2/mol NO2)

157048 Process Calculations

Page 26

Where:

O2 in regen. air = 12, 976 lb mol dry air

hr

21 mol O2

100 mol air =

2,725 lb mol

hr of O2

Excess O2 in FG = 12,501 lb mol FG

hr

2.5 mol O2

100 mol FG =

312 lb mol

hr of O2

O2 reacted to CO = 12,501 lb mol FG

hr

0 mol CO

100 mol FG

0.5 mol O2

mol CO

= 0 lb mol/hr O2

O2 reacted to CO2 = 12,501 lb mol FG

hr

15.5 mol CO2

100 mol FG

1 mol O2

mol CO2

= 1,938 lb mol/hr of O2

O2 reacted to SO2 = 12,501 lb mol FG

hr

0 mol SO2

100 mol FG

1 mol O2

mol SO2

= 0 lb mol/hr of O2

O2 reacted to NO2 = 12,501 lb mol FG

hr

0 mol NO2

100 mol FG

1 mol O2

mol NO2

= 0 lb mol/hr of O2

O2 reacted to H2O (by difference) is:

O2 Reacted to H2O = 2,725 - 312 - 0 - 1,938 - 0 - 0 lb mol/hr O2 = 475 lb mol/hr of O2

The hydrogen burned by oxygen in the regenerator is:

H2 burned by O2 = 475 lb mol

hr O2

2 mol H2

mol O2 =

950 lb mol

hr H2

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Page 27

7. Calculate Coke from Carbon and Hydrogen

The mass of coke combusted to CO + CO2 + H2O is:

from carbon = 1, 938 lb mol

hr C

12.01 lb C

lb mol C =

23,275 lb

hr C

from hydrogen = 950 lb mol

hr H2

2.016 lb H

lb mol H2 =

1, 915 lb

hr H

Total = 23,275 + 1,915 = 25,190 lb/hr coke

8. Calculate Coke Yield Percent

The quantity of coke produced from the fresh feed is:

Coke Yield = Coke, lb/hr 100

FF,lb/hr

Coke Yield = 25,190 lb/hr coke

412,923 lb/hr raw oil 100 = 6.10 wt - % coke

9. Calculate Hydrogen in Coke

The H2 content of the coke is:

H2 in Coke = H2, lb/hr (100)

Coke, lb/hr

H2 in Coke 1,915 lb/hr H

25,190 lb/hr coke 100 = 7.6 wt - % hydrogen

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10. Calculate the Air/Coke Ratio

Air to Coke = (Air, lb/hr)(100)

Coke, lb/hr

Air to Coke = 375,870 lb/hr dry air

25,190 lb/hr coke = 14.92

lb of dry air

lb of coke

11. Calculate the Heat of Combustion of Coke

Combustion heats are calculated based on the average hottest temperature in the

regenerator. The dense, dilute, cyclones, and flue gas average temperatures are

calculated and the hottest is used as basis.

The average hottest temperature is 1375°F.

Hc (2C + O2 2CO) = 46,216 + 1.47 (1375°F) = 48,237 BTU

lbmole

= (0 lbmole

hr of O2 reacted to CO) (2) 48,237

BTU

lb mole

= 0 BTU/hr

Hc (C + O2 CO2) = 169,135 + 0.5 (1375°F) = 169,822 BTU

lbmole

= (1,938 lbmole

hr of O2 reacted to CO2) (1) 169, 822

BTU

lb mole

= 329.12 106 BTU/hr

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Hc (2H2 + O2 2H2O) = 104,546 + 1.585 (1375°F) = 106,725 BTU

lbmole

= (475 lbmole

hr of O2 reacted to H2O) (2) 106, 725

BTU

lb mole

= 101.389 106 BTU/hr

∆HCombustion of Coke = (0 + 329.12 + 101.39) 106 = 430.51 106 BTU/hr

Using as basis 1 lb of coke

∆H combustion of coke = 430.51 106 BTU/hr

25,190 lb/hr coke

= 17,090 BTU/lb coke

This heat of combustion must be corrected for the coke’s hydrogen content

according to the equation

Correction = 1133 - 134.6 (wt-% H)

= 1133 - 134.6 (7.6) = +110 BTU/lb coke

The net heat of combustion of coke is:

∆HCombustion = 17,090 + 110 BTU/lb coke = 17,200 BTU/lb coke

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REGENERATOR HEAT BALANCE

Basis: 1 lb of coke

12. Heat Consumed to Heat Up the Regeneration Air

Since ∆H = mass Cp ∆T

Air is heated from the main air blower discharge temperature of 399°F to the

average hottest temperature of 1375°F at an average specific heat of 0.26 BTU/lb

°F.

HAir = 375,870 lb/hr air

25,190 lb/hr coke (1375- 399F)

0.26 BTU

lb F = 3, 787 BTU/lb coke

13. Heat Consumed to Heat up the Regeneration Air Water Vapor

Water vapor is heated from 399 to 1375°F at an average specific heat of 0.5 BTU/lb

°F.

HH2O 4, 330 lb/hr H2O

25,190 lb/hr coke

0.5 BTU

lb F (1375 - 399F) = 83.9 BTU/lb coke

14. Heat Consumed to Heat Up the Coke

Coke is heated from the reactor temperature of 970°F to the average hottest

temperature of 1375°F at an average specific heat of 0.4 BTU/lb °F.

∆HCoke = (1375-970°F) 0.4 BTU/lb °F = 162 BTU/lb coke

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15. Heat Consumed to Generate Steam in the Catalyst Cooler

Enthalpies for water and steam are obtained from steam tables.

Water in at 220°F = (188 BTU/lb) (56,033 + 6,952 lb/hr) = 11.841 106 BTU/hr

Steam out at 463°F = (1,205 BTU/lb) (56,033 lb/hr) = 67.52 106 BTU/hr

Blowdown out at 463°F = (441 BTU/lb) (6,952 lb/hr) = 3.066 106 BTU/hr

Catalyst cooler duty = (67.52 + 3.066 - 11.841) 106 BTU/hr = 58.75 106 BTU/hr

Or

∆HRemoved = 58.75 106 BTU/hr

25,190 lb/hr of Coke = 2, 332 BTU/lb of coke

16. Regenerator Heat Balance

Using a typical regenerator heat loss rate of 250 BTU/lb coke, the heat consumed to

heat up the catalyst is:

RgHeat = (∆HComb Coke) - ∆HCoke - ∆HAir - ∆HH2O - ∆HLoss - ∆HRemoved

Hregen = 17,200 - 3,787 - 84 - 162 - 2,332 - 250

= 10,585 BTU/lb Coke

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17. Calculate the Catalyst Circulation Rate

The catalyst is heated from the reactor temperature of 970°F to the regenerated

catalyst temperature of 1371°F at an average specific heat of 0.275 BTU/lb °F.

Since Q = m Cp ∆T then m = Q/Cp ∆T

CCR = (Coke lb/hr)(Rg Heat BTU/lb Coke)

(0.275 BTU/lb F) (Cat T - RXT)

CCR = 25,190 lb/hr coke 10,585 BTU/lb coke

0.275 BTU/lb F (1371 - 970F) 60 min/hr 40, 299 lb/min

or

CCR = 40,299 lb/min

2,000 lb/ton = 20.15 ton/min

18. Calculate the Catalyst/Oil Ratio

C/O = CCR lb/hr

FF lb/hr

C/O = 40,299 lb/min catalyst 60 min/hr

412,923 lb/hr fresh feed = 5.86 wt/wt

19. Calculate the Regenerator Efficiency

Rg Eff = Rg Heat 100

HCombustion of Coke =

(10,585 BTU/lb of Coke) (100)

17,200 BTU/lb of Coke

= 62% (This number will be higher without catalyst cooler)

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20. Calculate the Delta Coke Wt-%:

Coke (100) (Coke, lb/hr)

Cat. Circ. lb/hr =

25,190 100

40,299 60 = 1.04 wt%

REACTOR HEAT CALCULATIONS

1 lb of fresh feed is used as basis in the following calculations.

21. Heat Consumed to Heat and Vaporize the Combined Feed

Enthalpies for the raw oil feed are obtained by using the equation as discussed after

this section. The UOP K to use for entering the enthalpy table is calculated from

UOP Method 375 as discussed in the following section. UOP K Factor is a function

of °API and Engler distillation. A high UOP K value of 12.5 indicates a more

paraffinic (saturated chain) hydrocarbon, while a lower value of 11.2 occurs for a

more aromatic (unsaturated cyclic) stock. Higher UOP K paraffinic feeds crack

easier yielding higher conversion at a given reactor temperature.

Raw Oil: UOP K = 11.8 °API Gravity = 21.3

At the 375°F riser inlet temperature, Hraw oil = 252 BTU/lb

At the 970°F reactor temperature, Hvapor = 760 BTU/lb

∆Hraw oil = 412,923 lb/hr (760-2891 BTU/lb) = 194.487 106 BTU/hr

The heat required to heat up the combined feed is the ∆Hraw oil multiplied by the

Combined Feed Ratio (CFR),

where, CFR = (raw oil + recycle) lb/hr

raw oil lb/hr = 1.0

So, ∆Hcomb feed = 194.487 106 BTU/hr

157048 Process Calculations

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Hcomb feed = 194.487 106 BTU/hr

412,923 lb/hr raw oil = 471 BTU/lb raw oil

22. Heat Consumed to Heat Up the Lift Gas:

The lift gas is heated from 110°F to 970°F at an assumed average specific heat of

0.5 BTU/lb °F.

Hlift gas = 3, 250 lb/hr lift gas (970 - 110F) 0.5 BTU/lb F

412,923 lb/hr raw oil = 3.4 BTU/lb raw oil

23. Heat Consumed to Heat Up Lift Steam, Feed Steam and Stripping Steam

Steam is heated up from the header temperature of 380°F to the reactor

temperature at 970°F at an average specific heat of 0.485 BTU/lb °F.

Hsteam = (5, 000 + 12, 900 + 1, 800) lb/hr (970 - 380F) 0.485

412, 923 lb/hr raw oil = 13.8 BTU/lb raw oil

24. Heat of Inert Gas Carried from Regenerator to Reactor by Regenerated

Catalyst

The inerts gas can be calculated from the sponge gas stream and the procedure is

at the end of this section. If this number is unknown, use 0.007% of fresh feed. Use

an average specific heat of 0.275 BTU/lb °F.

∆Hinerts = (inerts wt%) (Cp) (RxT - RgT)

= 0.007 0.275 (970 - 1371) = -0.8 BTU/lb raw oil

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25. Reactor Heat Balance

The total heat consumed in the reactor equals the sum of the heats consumed for

the combined feed, lift gas, all steam, the reactor losses, plus the heat of reaction.

Using a typical reactor heat loss rate of 2 BTU/lb raw oil, the heat balance is:

Rx Heat = ∆Hcomb feed + ∆Hlift gas + ∆Hsteam + ∆Hinerts + ∆Hloss + ∆HRxN

Hreactor = (471 + 3.4 + 13.8 - 0.8 + 2) BTU/lb raw oil + ∆Hreaction

Hreactor = 489.4 BTU/lb raw oil + ∆Hreaction

26. Overall Heat Balance

The heat consumed in the reactor is supplied by the hot catalyst circulated to the

riser. At steady state, the heat consumed in the reactor must balance the heat

produced in the regenerator. The reactor heat is based on a per lb of fresh feed

basis while that of the regenerator is on a per lb of coke basis. These two can be

equated using the raw oil to coke weight fraction to determine the heat of reaction:

Hregenerator BTU / lb coke lb coke

lb raw oil

= Hreactor [BTU/lb raw oil]

10,585 BTU

lb coke

25,190 lb/hr coke

412,923 lb/hr raw oil = 489.4 BTU/lb raw oil + ∆Hreaction

∆Hreaction = 119 BTU/lb raw oil

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FCC Unit Heat Balance Example

Refiner: Location: Date: Combustion Air Correction to a Dry Basis Flue Gas Composition Adjustment: (a) Ambient Temperature = 62 °F GC, mol-% Corrected for Ar* (b) Relative Humidity = 97 % (i) CO = 0.00 CO = 0.00 (c) Sat. Vapor Pressure = 10^[6.40375-(3165.36/(°F+392.565))] (j) CO2 = 15.50 CO2 = 15.50 = 0.275586177 psia (k) O2 = 3.47 O2 - (0.012*N2) = 2.50 (d) lb H2O/lb dry air = [0.00622*(b)*(c)]/[14.7-0.01*(b)*(c)] (L) N2 = 81.03 N2 + O2 - Cor O2 = 82.00 = 0.011520532 lb/lb (m) SO2 = 0.00 SO2 = 0.00 (e) Total Air to Regen = 380,200 lb/hr (n) NO2 = 0.00 NO2 = 0.00 (f) Total Dry Air = (e)/[1+(d)] = 375,870 lb/hr Total 100.00 100.00 (h) H2O in Air = (e) – (f) = 4,330 lb/hr *Correction required only for GC not for Orsat analysis. Temperatures: Rg=Regenerator, Rx=Reactor (o) Flue Gas Line = 1368 °F (t) Air to Rg = 399 °F (p) Rg Avg Cyclone Outlet = 1368 °F (u) Rx Temp = 970 °F (q) Rg Avg Dilute = 1375 °F (v) Hot Rg T – Air T = 976 °F (r) Rg Avg Dense (RgT) = 1371 °F (w) Rg Dense T – Rx T = 401 °F (s) Avg Hottest Rg Temp = 1375 °F Oxygen Balance: (y) (L) * (2 * 21 ) / 79 – 2(n) - 2(m) - 2(k) - 2(j) - (i) = 7.6 mol H2 / 100 mol Flue Gas (z) 2.016*(y) =12.01[ (i) + (j) ] + 32.06*(m) + 46.01*(n) = 201.5 lb coke / 100 mol Flue Gas (1a) Hydrogen = 2.016 * (y) * 100 / (z) = 7.6 wt-% Hydrogen in Coke (1b) Air = 28.966 * 100 * (L) / [ 79 * (z) ] = 14.9 Air/Coke, lb/lb (1c) Coke = Dry Air / [ Air / Coke ] = (f) / (1b) = 25,187 lb/hr of Coke (1d) Fresh Feed S.G. = 0.926 = 412,923 lb/hr Feed (1e) Coke Yield = (1c) * 100 / (1d) = 6.10 wt-% Coke (of Fresh Feed) Combustion of Coke Basis: Average Hottest Regenerator Temperature: (1f) Hc(CO) = 46,216 + 1.47 * (s) = 48,237 BTU/lb-mol (1g) Hc(CO2) = 169,135 + 0.5 * (s) = 169,823 BTU/lb-mol (1h) Hc(H2O) = 104,546 + 1.585 * (s) = 106,725 BTU/lb-mol (1i) H Comb = [ (1f) * (i) + (1g) * (j) + (1h) * (y) ] / (z) = 17,091 BTU/lb-mol (1j) Correction Factor = 1133 – 134.64 * (1a) = 109 BTU/lb-mol (1k) H Combustion Coke = (1i) + (1j) = 17,200 BTU/lb-mol Regenerator Heat Balance Basis: 1 lb of Coke (1m) H coke = 0.4 BTU/lb-mol °F * (w) = 160 BTU/lb coke (1n) H air = (1b) * 0.26 BTU/lb °F * (v) = 3,787 BTU/lb coke (1o) H H2O = (h) / (1c) * 0.485 BTU/lb °F * (v) = 81 BTU/lb coke (1p) H Radiant Losses = 250 BTU/lb coke (1q) Cat Cooler Heat Duty = 58.7 MM-BTU/hr (calculated separately) (1r) H removed = Cooler Duty / Coke = (1q) * 10^6 / (1c) = 2,331 BTU/lb coke (1s) Rg Heat = (1k) – (1m) – (1n) – (1o) – (1p) – (1r) = 10,590 BTU/lb coke (1t) Rg Eff = Rg Heat * 100 / HcombCoke = (1s) * 100 / (1k) = 61.6 % Regenerator Efficiency (1u) Cat/Oil = (1s) * (1e) / 100 * (0.275 BTU/lb °F) * (w) = 5.86 Catalyst-to-Oil Ratio (1v) Cat Circ = (Cat/Oil) * (FF) / 60 = (1u) * (1d) / 60 min/hr) = 40,313 Catalyst Circulation, lb/min (1w) Coke = 100 * Coke / (60 * Cat Circ) = 100 * (1c) / 60 * (1v) = 1.04 Coke, wt-%

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FCC Unit Heat Balance Example Continuation

Refiner: Location: Date: Reactor Heat Calculations: Basis: 1 lb of Coke (2a) Rx Temp (RxT) = 970 °F (2b) Combined Feed Temp. (CFT) = 375 °F (2c) Fresh Feed (FF) = 412,923 lb/hr (2d) FF Enthalpy @ CFT (H @ CFT)* = 289 BTU/lb (2e) FF Enthalpy @ RxT (H @ RxT)I = 760 BTU/lb (2f) Recycle (Recy) = 0 lb/hr (2g) Recy Enthalpy @ CFT (E @ CFT)* = 0 BTU/lb (2h) Recy Enthalpy @ RxT (E @ RxT)* = 0 BTU/lb *See Following Pages for Enthalpy Calculation Method (2i) Inerts from Rg with catalyst (Inerts) = 2,748 lb/hr (2j) Inerts Specific Heat (Cp) = 0.275 BTU/lb °F (2k) Lift Gas (LGas) = 3,250 lb/hr (2m) Lift Gas Temp (LGasT) = 110 °F (2n) Lift Gas Specific Heat (LGas Cp) = 0.5 BTU/lb °F (2o) Steam Temp (StmT) = 380 °F (2p) Steam Specific Heat (Stm Cp) = 0.485 BTU/lb °F (2q) Stripping Steam = 5,000 lb/hr (2r) Lift Steam = 12,900 lb/hr (2s) Feed Steam = 1,800 lb/hr (2t) Heat consumed by FF = (FF) * (H @ RxT – H @ CFT) / (FF) = 471 BTU/lb FF (2u) Heat consumed by Recycle = (Recycle) * (E @ CFT – E @ RxT) / FF = 0 BTU/lb FF (2v) Heat Consumed by Steam = (Total Stm) * (Stm Cp) * (RxT-StmT) / FF = 13.7 BTU/lb FF (2w) Heat Consumed by Lift Gas = (LGas) * (LGas Cp) * (RxT-StmT) / FF = 3.4 BTU/lb FF (2y) Heat from Inerts = (Inerts) * (Inerts Cp) * (RxT-RgT) / FF = -0.7 BTU/lb FF (2z) Reactor Heat Loss = 2 BTU/lb FF (3a) Rx Heat = (H FF) + (H Recy) + (H Stm) + (H Lgas) + (H Inrts) + (H Loss) + (H Rxn) = 489.3 BTU/lb FF + H Reaction

(Rg Heat BTU/lb Coke) * (Coke lb/hr) / (FF lb/hr) = Rx Heat = BTU/lb + H Rxn (3b) H Rxn = [(Rg Heat BTU/lb Coke) * (Coke lb/hr) / (FF lb/hr)] – BTU/lb = 157 H Rxn BTU/ lb FF

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uop K Factor from °API and Engler Distillation

Data: ASTM Distillation: Specific Gravity: 0.9258

Vol% Temperature, °F

10 660

30 781

50 887

70 1015

90 1075

1. Calculate the volumetric average boiling point as the average of the 10, 30, 50, 70

and 90 vol-% temperatures.

VABP = (T10% + T30% + T50% + T70% + T90%) / 5

VABP = (660 + 781 + 887 + 1015 + 1075) / 5 = 883.6

2. Calculate the Engler slope as °F per percent (°F/%) by subtracting the 10 vol-%

temperature from the 90 vol-% temperature, and dividing the difference by 80.

Slope = (T90% – T10%)/80 = 5.1875

3. Calculate the Cubic Average Boiling Point (CABP):

CABP = VABP * A + B

Where: A = (0.000297 * Slope + 0.001438)*Slope + 1.0

A = 1.01545

B = (-0.581 * Slope – 1.339)*Slope

B = -22.5809

4. Calculate UOP K:

SG

459.69 CABP K UOP3

= 11.89

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Enthalpy of Heavy Petroleum Fractions

The Following equations can be used to calculate the Enthalpies for the feed and recycle

streams on the FCC unit.

Liquid Enthalpy Equation: Equation source is API Procedure 4.7.B4

A1 = (-1171.26 + (23.722 + 24.907 * SG) * UOP K)

A1 = A1 + (1149.82 – 46.535 * UOP K) / SG

A1= A1 / 1,000

A2 = (1 + 0.82463 * UOP K) * (56.086 – 13.817 / SG) / 1,000,000

A3 = - (1 + 0.82463 * UOP K) * (9.6757 – 2.3653 / SG) / 1E+09

The enthalpy of liquid FCC feedstock at the riser inlet conditions is:

Hin = A1 * (TE – 259.67) + A2 * (TE² – 259.67²) + A3 * (TE³ – 259.67³)

Where: TE = Combined Feed Temperature, (°F + 459.67)

SG = Fresh Feed Specific Gravity

UOP K = Fresh Feed UOP K

Vapor Enthalpy Equation: Equation source is a curve fit from UOP PD Chart PD-189

F1 = 3.0186E-04 * SG + 3.9975E-06 * UOP K * (UOP K – 13.8584)

F2 = 0.67036000 * SG + 0.00675130 * UOP K * (UOP K – 24.7770)

F3 = 85.52390000 * SG – 4.73260000 * UOP K * (UOP K – 21.9249) – 459.6742

Enthalpy of feed in fully vaporized condition is:

Hout = F1 * (T²) – F2 * T + F3

Where: T = Reactor temperature, °F

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Heat of Combustion of Coke, BTU/lb-Mole

Table:

Temperature, °F 77 1,100 1,200 1,250 1,300 1,350 1,400

CO 47,565 47,847 47,980 48,050 48,123 48,199 48,274

CO2 169,332 169,677 169,735 169,760 169,784 169,808 169,835

H2O Vapor 104,129 106,279 106,448 106,529 106,610 106,687 106,765

Equations:

Hc(CO) = 46,216 + 1.47 * (T)

Hc(CO2) = 169,135 + 0.5 * (T)

Hc(H2O) = 104,546 + 1.585 * (T)

Where: T is in °F

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MECHANICAL EVALUATION

The Mechanical Evaluation Test should cover all facets of the FCC Unit, including the

reactor, regenerator, main column, and the gas concentration unit. All major pieces of

equipment should be part of this test, including vessels, pumps, compressors, heat

exchangers, and piping hydraulics. The procedure for this test is long and involved,

but the information can be very useful for the Refiner and for UOP. If the Refiner

wants to revamp the unit, it is important to determine maximum throughput and actual

equipment limitations. Most of the information will be collected only once, although

parts of it (such as exchanger surveys) can be repeated to follow fouling or other

potential problems.

The lists and data sheets included in this section can be used as guidelines in

collecting the required data, although the Refiner may have to modify certain parts for

his particular unit. It is important to finish collecting the data within as short a time as

possible. A single survey is generally satisfactory and it is no necessary to use long

term average data. The Unit should be operating smoothly to get realistic and good

quality data. Label the data collected and prepare a report in an orderly fashion.

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GENERAL INFORMATION LIST

This list is only a guideline. Please modify or expand as required.

1. Ambient Air Conditions

a. Temperature

b. Relative Humidity

c. Barometric Pressure

d. Wind Velocity and Direction (show on rough plot plan)

2. General Description of Unit

a. Process Flow Diagram, including flow meter and control valve locations

b. Plot Plan showing Layout of Vessel and Equipment

c. Operational Mode (partial or complete CO Combustion)

3. Units used (USA, Imperial, Metric) and Standard Conditions (0°C, 760 mm;

60°F, 14.7 psia)

4. Limiting Factors

a. Environmental Constraints (CO emissions, special product

specifications)

b. Utility Limitation (shortage of steam or electricity, etc.)

5. Performance Data

a. Accurate Flow and Weight Balance including sample analyses

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HYDRAULIC AND PROCESS SURVEY LIST

1. Single gauge pressure survey of every point in reactor-regenerator circuit,

including air into regenerator and flue gas out to point of discharge.

2. Slide valve positions and hydraulic oil pressure at each valve.

3. Air blower suction and discharge pressures, total and net (to regenerator) flow

rates, relative humidity and temperature of air, with manufacturer’s data and

performance curve for comparison.

4. Electrical or steam consumption for blower driver.

5. Power recovery units should add flue gas temperatures and pressures around

expander, butterfly valve positions, electrical power consumed or generated

and single gauge pressure survey of third stage separator.

6. For electrostatic precipitator, or other flue gas treaters, take temperatures in

and out, power consumption, and amount and size distribution of particulates

removed.

7. Complete flue gas sample before and after flue gas treater.

8. Catalyst consumption and losses.

9. Single gauge pressure survey of main column and gas concentration section

(use one low pressure and one high pressure gauge, depending on location, for

better accuracy). Include feed flow rate and temperature, reflux flow rate and

temperature, reboiler heat input, overhead temperature and pressure and

enough other data to calculate a heat and weight balance around the column.

10. Samples of main column overhead receiver gas and liquid; and gas,

hydrocarbons, and water samples from high pressure receiver for phase

equilibrium studies.

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11. Compressor suction and discharge pressures, flow rates, composition, and

temperatures, with manufacturer’s performance curve for comparison. Include

amounts and compositions of liquids drained from knockout drums.

12. Compressor driver type and power consumption.

13. All pump suction and discharge pressures, flow rates, liquid compositions or

boiling ranges, and power consumption of driver, with manufacturer’s

performance data for comparison.

14. Data on streams not usually measured, such as LCO to the sponge absorber,

including flow rates, temperatures, composition or boiling range, and single

gauge pressure survey of circuit.

15. Pressures, temperatures, and flow rates of flushing oil to instruments and pump

seals and glands.

16. Utility consumption/product data:

Steam (all pressures)

Air (plant and instrument)

Purges to instruments, packing glands, and expansion joints (specify air,

steam, nitrogen, or fuel gas), with single gauge pressure survey of utility lines at

purge points).

Cooling water

Boiler feed water

Steam condensate

Utility water

Treating chemicals for boiler feed water (type and amount)

Inhibitor and anti-corrosion chemicals used

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EXCHANGERS INFORMATION LIST

1. Flow through exchangers on both sides (gas and liquid), composition or boiling

range, and mass flow.

2. Temperatures in and out of both sides, also between shells and bundles.

3. Pressures in and out of both sides, also between shells and bundles.

4. Any material bypassed around exchangers (give rough sketch).

5. If air coolers: air temperatures in and out, air velocity out, motor amps, note any

belt slippage, variable pitch position, louver position, etc.

6. In preparing data, submit overall heat transfer coefficient and specifics on

exchangers.

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FIRED HEATERS INFORMATION LIST

1. Process flow (volume and mass, composition, molecular weight and boiling

range).

2. Single gauge pressure survey for both process and fuel system.

3. Fuel type (gas or oil) and analysis (composition, sulfur, gravity, etc.), pressure

and temperature of fuel at heater.

4. Fuel consumption.

5. Steam or air pressure for fuel oil atomization.

6. Temperatures throughout the heater, such as firebox, convection points, stack,

air preheat, and all process points.

7. Draft in firebox and stack.

8. Design information: type of furnace, materials of construction, and number,

layout and materials of tubes; including dimensions of furnace.

9. Burner data: rating, design, number. Note any unusual problems such as

plugged or inoperative burners.

10. Refiner should obtain sufficient data to calculate heat flux from both process

and fire side, heat release, heater efficiency and steam balance.

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To Main Column

ESP

Main AirBlower

AtmosphericAir

Flue Gas toStack

Feed

Orifice ChamberSteamGenerator

Flue GasSV

DFAH

1

3

4

5

67

8

9

10

11

1213

141516171819

20

2

A

B

C

D

E

F

G

H

I

J

22

Cat CoolerSlidevalve

Reactor-Regenerator Pressure Survey

Refiner:

Location:

Date:

Time:

By:

Slide Valves % Open Regenerated Recirculating Spent Flue Gas A Flue Gas B

Process Flow Feed Rate

Air Rate

Pressure Survey: _____________Units of Pressure

1 11 A2 12 B3 13 C4 14 D5 15 E6 16 F7 17 G8 18 H

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MAIN COLUMN SUMMARY – BOTTOMS page ____________________________ date ____________________________ Item No.: _____________________________ by ____________________________ Service: __________________________________________________________________ Type of Operation: _________________________________________________________ No. of Trays: _________________ Reflux Ratio: _________________________________ Type of Trays: _____________________________________________________________ Main Column Bottoms Circulating Circ. Quench CSO HCO LCO Other Mass Flow _______ _______ _______ _______ _______ ________ Temperature Out _______ _______ _______ _______ _______ ________ Return _______ _______ _______ _______ _______ ________ Pressure _______ _______ _______ _______ _______ ________ Distillation _______ _______ _______ _______ _______ ________ IBP _______ _______ _______ _______ _______ ________ 5% _______ _______ _______ _______ _______ ________ 10% _______ _______ _______ _______ _______ ________ 20% _______ _______ _______ _______ _______ ________ 30% _______ _______ _______ _______ _______ ________ 40% _______ _______ _______ _______ _______ ________ 50% _______ _______ _______ _______ _______ ________ 60% _______ _______ _______ _______ _______ ________ 70% _______ _______ _______ _______ _______ ________ 80% _______ _______ _______ _______ _______ ________ 90% _______ _______ _______ _______ _______ ________ 95% _______ _______ _______ _______ _______ ________ EP _______ _______ _______ _______ _______ ________ API or S.G. _______ _______ _______ _______ _______ ________ BS & W _______ _______ _______ _______ _______ ________ Steam to Stripper _______ _______ _______ _______ _______ ________ (Sketch system showing flows, P, T, Q on separate page) __________________________ Weight balance _______________________ Heat balance _________________________ Deviations from UOP Specifications: ___________________________________________ ________________________________________________________________________

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MAIN COLUMN SUMMARY — page _______________________________

CYCLE OIL PRODUCTS AND OVHD. date _______________________________

Item No.: ____________________________ by _______________________________

Service: _________________________________________________________________

Type of Operation: _________________________________________________________

No. of Trays: ________________ Reflux Ratio: ________________________________

Type of Trays: ____________________________________________________________ Net HCO LCO Naphtha Ovhd. Ovhd. Product Product Product Reflux Liquid Gas Mass Flow, _______ _______ ________ _______ _______ _______ Temperature _______ _______ ________ _______ _______ _______ Pressure _______ _______ ________ _______ _______ _______ Composition, ______ % _______ _______ ________ _______ _______ _______ H2 _______ _______ ________ _______ _______ _______ N2 _______ _______ ________ _______ _______ _______ H2S _______ _______ ________ _______ _______ _______ H2O _______ _______ ________ _______ _______ _______ C1 _______ _______ ________ _______ _______ _______ C2 _______ _______ ________ _______ _______ _______ C3/C3= _______ _______ ________ _______ _______ _______ iC4 _______ _______ ________ _______ _______ _______ nC4/C4= _______ _______ ________ _______ _______ _______ iC5 _______ _______ ________ _______ _______ _______ nC5 _______ _______ ________ _______ _______ _______ C6+ _______ _______ ________ _______ _______ _______ Avg. Mol. Wt. _______ _______ ________ _______ _______ _______ Gravity _______ _______ ________ _______ _______ _______ Distillation _______ _______ ________ _______ _______ _______ IBP _______ _______ ________ _______ _______ _______ 5% _______ _______ ________ _______ _______ _______ 10% _______ _______ ________ _______ _______ _______ 20% _______ _______ ________ _______ _______ _______ 30% _______ _______ ________ _______ _______ _______ 40% _______ _______ ________ _______ _______ _______ 50% _______ _______ ________ _______ _______ _______ 60% _______ _______ ________ _______ _______ _______ 70% _______ _______ ________ _______ _______ _______ 80% _______ _______ ________ _______ _______ _______ 90% _______ _______ ________ _______ _______ _______ 95% _______ _______ ________ _______ _______ _______ EP _______ _______ ________ _______ _______ _______ Steam to Stripper _______ _______ ________ _______ _______ _______ Flash Point _______ _______ ________ _______ _______ _______

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COLUMN SUMMARY page _______________________________ date _______________________________ Item No.: _____________________________ by _______________________________ Service: __________________________________________________________________ Type of Operation: _________________________________________________________ No. of Trays: _________________ Reflux Ratio: _________________________________ Type of Trays: _____________________________________________________________ Net Off Ovhd. Feed Reflux Gas Btms. Liquid Other Mass Flow _______ _______ _______ _______ _______ ________ Temperature _______ _______ _______ _______ _______ ________ Pressure _______ _______ _______ _______ _______ ________ Composition, ______ % _______ _______ _______ _______ _______ ________ H2 _______ _______ _______ _______ _______ ________ N2 _______ _______ _______ _______ _______ ________ H2S _______ _______ _______ _______ _______ ________ H2O _______ _______ _______ _______ _______ ________ C1 _______ _______ _______ _______ _______ ________ C2 _______ _______ _______ _______ _______ ________ C3 _______ _______ _______ _______ _______ ________ iC4 _______ _______ _______ _______ _______ ________ nC4 _______ _______ _______ _______ _______ ________ iC5 _______ _______ _______ _______ _______ ________ nC5 _______ _______ _______ _______ _______ ________ C6+ _______ _______ _______ _______ _______ ________ Avg. Mol. Wt. _______ _______ _______ _______ _______ ________ Gravity _______ _______ _______ _______ _______ ________ Distillation _______ _______ _______ _______ _______ ________ IBP _______ _______ _______ _______ _______ ________ 5% _______ _______ _______ _______ _______ ________ 10% _______ _______ _______ _______ _______ ________ 20% _______ _______ _______ _______ _______ ________ 30% _______ _______ _______ _______ _______ ________ 40% _______ _______ _______ _______ _______ ________ 50% _______ _______ _______ _______ _______ ________ 60% _______ _______ _______ _______ _______ ________ 70% _______ _______ _______ _______ _______ ________ 80% _______ _______ _______ _______ _______ ________ 90% _______ _______ _______ _______ _______ ________ 95% _______ _______ _______ _______ _______ ________ EP _______ _______ _______ _______ _______ ________ (Sketch system showing flows, P, T, Q on separate page) __________________________ Weight balance _______________________ Heat balance _________________________ Deviations from UOP Specifications: ___________________________________________

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ABSORBER SUMMARY page _______________________________ date _______________________________ Item No.: ____________________________ by _______________________________ Service: _________________________________________________________________ Type of Operation: _________________________________________________________ No. of Trays: ________________ Reflux Ratio: ________________________________ Type of Trays: ____________________________________________________________ Gas Liquid Gas Liquid Pumparound In In Out Out Upper Lower Mass Fl _______ _______ ________ _______ _______ _______ Temperature _______ _______ ________ _______ _______ _______ Pressure _______ _______ ________ _______ _______ _______ Composition, ______ % _______ _______ ________ _______ _______ _______ H2 _______ _______ ________ _______ _______ _______ N2 _______ _______ ________ _______ _______ _______ H2S _______ _______ ________ _______ _______ _______ H2O _______ _______ ________ _______ _______ _______ C1 _______ _______ ________ _______ _______ _______ C2 _______ _______ ________ _______ _______ _______ C3 _______ _______ ________ _______ _______ _______ iC4 _______ _______ ________ _______ _______ _______ nC4 _______ _______ ________ _______ _______ _______ iC5 _______ _______ ________ _______ _______ _______ nC5 _______ _______ ________ _______ _______ _______ C6+ _______ _______ ________ _______ _______ _______ Avg. Mol. Wt. _______ _______ ________ _______ _______ _______ Gravity _______ _______ ________ _______ _______ _______ Distillation, ° _______ _______ _______ ________ _______ _______ _______ IBP _______ _______ ________ _______ _______ _______ 5% _______ _______ ________ _______ _______ _______ 10% _______ _______ ________ _______ _______ _______ 20% _______ _______ ________ _______ _______ _______ 30% _______ _______ ________ _______ _______ _______ 40% _______ _______ ________ _______ _______ _______ 50% _______ _______ ________ _______ _______ _______ 60% _______ _______ ________ _______ _______ _______ 70% _______ _______ ________ _______ _______ _______ 80% _______ _______ ________ _______ _______ _______ 90% _______ _______ ________ _______ _______ _______ 95% _______ _______ ________ _______ _______ _______ EP _______ _______ ________ _______ _______ _______ (Sketch system showing flows, P, T, Q on separate page) __________________________

Weight balance ______________________ Heat balance ________________________

Deviations from UOP Specifications: ___________________________________________

157048 Process Calculations

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CENTRIFUGAL COMPRESSOR DATA page _______________________________ date _______________________________ Item No.: _____________________________ by _______________________________ Service: __________________________________________________________________ Manufacturer: _____________________________________________________________ Type, Model: ______________________________________________________________ No. of Stages: _____________________________________________________________ OPERATING CONDITIONS/PERFORMANCE Flow Rate: ____________ Suction Temperature: ________ °F Suction Pressure: ____________ psig Discharge Temperature: ________ °F Discharge Pressure: ____________ psig Power: ________ hp Differential Head: ____________ MW: ________ Polytropic : ____________ Operating Speed: ____________ rpm Type of Seal: _________________________________________ Lube/Seal Oil System: ________________________________________ Buffer Gas: (yes/no) Buffer Gas Rate: ______________ SCFH Automatic Surge Control: (yes/no) DRIVER Motor Manufacturer: _________________________________________ Rating: ____________________ Service Factor: ______________ Insulation Class: ____________________ Voltage/phase/cycle: Turbine Manufacturer: _________________________________________ Speed: ______________ Steam Supply: _______ psig ______ °F Steam Rate: ______________ Steam Exhaust: _______ psig ______ °F Gear Manufacturer: _________________________________________ Rating: ____________________ Service Factor: _____________ Type: ____________________ Power Loss: _____________ Deviations from UOP Specification: ____________________________________________ ________________________________________________________________________ ________________________________________________________________________ ________________________________________________________________________

157048 Process Calculations

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RECIPROCATING COMPRESSOR DATA

page ___________________________

date ___________________________

Item No.: ______________________________ by ___________________________

Service: _______________________________

Manufacturer: ___________________________ Cylinder Lubrication: ____________

Type, Model: ___________________________ Clearance Pockets: (yes/no)

No. of Stages, No. of Cylinders: ___________ Sparing Description: ____________

OPERATING CONDITIONS/PERFORMANCE

Flow Rate: ____________ Suction Temperature: _________ °F

Suction Pressure: ____________ psig Discharge Temperature: _________ °F

Discharge Pressure: ____________ psig HP/stage: _________ hp

MW: ____________

Operating Speed: ____________ rpm Cylinder Diameters: _________

Piston Speed: ____________ ft/s # of Suction/Discharge Valves: _________

Actual Rod Loadings, T/C: ________________________________________ lbf

Max Allowable Rod Loadings, T/C: ________________________________________ lbf

DRIVER

Motor Manufacturer: ________________________________________

Rating: ____________________ Service Factor: _____________

Insulation Class: ____________________ Voltage/phase/cycle:

Turbine Manufacturer: ________________________________________

Speed: _______________ Steam Supply: _______ psig ______ °F

Steam Rate: _______________ Steam Exhaust: _______ psig ______ °F

Gear Manufacturer: ________________________________________

Rating: ____________________ Service Factor: _____________

Type: ____________________ Power Loss: _____________

Deviations from UOP Specification: ___________________________________________

________________________________________________________________________

________________________________________________________________________

________________________________________________________________________

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CONTROL VALVE SUMMARY

page ___________________________

date ___________________________

Item No.: ______________________________ by ___________________________

Service: __________________________________________________________________

Description of Valve: _____________________ Design CV: ______________________

Mfgr. and Catalog No.: ______________________________________________________

Positioner? _______________________________________________________________

Actual Design

Percent open (valve position) ____________

Flow rate: ______________________ ____________ __________

Upstream pressure: ______________________ ____________ __________

Downstream pressure: ______________________ ____________ __________

Flowing temperature: ______________________ ____________ __________

Deviations from UOP Specification: ____________________________________________

________________________________________________________________________

________________________________________________________________________

________________________________________________________________________

157048 Process Calculations

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AIR FIN COOLER SURVEY page _______________________________ date _______________________________ Item No.: ____________________________ by _______________________________ Service: _________________________________________________________________ Manufacturer: _____________________________________________________________ Type, Model: _____________________________________________________________ No. of Bundles: _______________________ No. of Passes: _____________________ No. of Tubes per Pass: _________________ Fans/bundle: ______________________ Tube Size _______________ ID x _______________ Gauge x _____________ Length Piping Geometry: ______________________ Type*: ____________________________ Overall Heat Transfer Coefficient: _____________________________________________ Pressure Temperature Inlet ______________ _____________ Outlet ______________ _____________ Air In ______________ _____________ Out ______________ _____________ No. fans on __________________________ Pitch control ________________________ Louver position _______________________ Air Process Mass flow ______________ _____________ Q (calc.) ______________ _____________ Composition, ____ % H2 _____________ N2 _____________ H2S _____________ H2O _____________ C1 _____________ C2 _____________ C3 _____________ iC4 _____________ nC4 _____________ iC5 _____________ nC5 _____________ C6+ _____________ Avg. Mol. Wt. _____________ Relative Humidity ______________

157048 Process Calculations

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Gravity Distillation, ° ______ IBP _____________ 10% _____________ 30% _____________ 50% _____________ 70% _____________ 90% _____________ EP _____________ Deviations from UOP Specification: ____________________________________________ ________________________________________________________________________ ________________________________________________________________________ *Include sketch of piping geometry if different from UOP standard practice types.

157048 Process Calculations

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FLOW METER SUMMARY

page ___________________________

date ___________________________

Item No.: ______________________________ by ___________________________

Service: _________________________________________________________________

Type of Fluid: ___________________________ Normal Units of Flow: ______________

______________________________________

Type of Meter: ____________________________________________________________

Meter Reading: ___________________________________________________________

Pressure ________________

Temperature ________________

Sp. Gr.** ________________

Meter Factor ________________

Corrected Flow Rate ________________

Mass Flow Rate ________________

Avg. mol. wt. ________________

Molar Flow Rate ________________

**Sketch piping layout, showing distances in nominal pipe IDs.

157048 Process Calculations

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HEAT EXCHANGER SURVEY page _______________________________ date _______________________________ Item No.: _____________________________ by _______________________________ Service: __________________________________________________________________ Manufacturer: _____________________________________________________________ Type, Model: ______________________________________________________________ No. of Bundles: ____________________________________________________________ No. of Passes/Bundle: __________________ Tubes per Pass: ____________________ Tube Size ______________ ID x _______________ Gauge x ______________ Length Heat Exchange Surface Area/Bundle: __________________________________________ Piping Geometry (sketch if necessary): _________________________________________ Length of Service: __________________________________________________________ Design Heat Transfer Coefficient: ______________________________________________ Stream Pressure Temperature Shell Side Inlet A ______________ _____________ Outlet ______________ _____________ Tube Side Inlet B ______________ _____________ Outlet ______________ _____________ Q (calc.) Shell side ______________ Q (calc.) Tube side ______________ Composition, ______ % A B H2 ______________ ______________ N2 ______________ ______________ H2S ______________ ______________ H2O ______________ ______________ C1 ______________ ______________ C2 ______________ ______________ C3 ______________ ______________ iC4 ______________ ______________ nC4 ______________ ______________ iC5 ______________ ______________ nC5 ______________ ______________ C6+ ______________ ______________ Mass Flow ______________ ______________ Avg. Mol. Wt. ______________ ______________

157048 Process Calculations

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Gravity Distillation, ° _______ IBP ______________ ______________ 10% ______________ ______________ 30% ______________ ______________ 50% ______________ ______________ 70% ______________ ______________ 90% ______________ ______________ EP ______________ ______________ Deviations from UOP Specification: ___________________________________________ ________________________________________________________________________ ________________________________________________________________________

157048 Process Calculations

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HEATER SURVEY page _______________________________ date _______________________________ Item No.: _____________________________ by _______________________________ Service: __________________________________________________________________ Manufacturer: _____________________________________________________________ Type, Model: ______________________________________________________________ No. of Passes: _________________________ Tubes per Pass: ____________________ Tube Size ______________ ID x _______________ Wall x ________________ Length Geometry (Process): ________________________________________________________ Geometry (Flue Gas): _______________________________________________________ Stream Pressure Temperature Radiant Inlet A ______________ _____________ Outlet ______________ _____________ Convection I Inlet B ______________ _____________ Outlet ______________ _____________ Convection II Inlet C ______________ _____________ Outlet ______________ _____________ Convection III Inlet D ______________ _____________ Outlet ______________ _____________ Fuel Gas E ______________ _____________ Fuel Oil F ______________ _____________ Flue Gas Under Convection I G ______________ _____________ Flue Gas Under Convection II H ______________ _____________ Flue Gas Under Convection III I ______________ _____________ Flue Gas Under Stack Damper J ______________ _____________ Flue Gas Above Floor K ______________ _____________

157048 Process Calculations

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HEATER SURVEY page _______________________________ date _______________________________ by _______________________________ G,H, Stream A B C D E F I,J,K Mass Flow, ________ _____ _____ _____ _____ _____ _____ Composition, ______ % _____ _____ _____ _____ _____ _____ ______ H2 _____ _____ _____ _____ _____ _____ ______ N2 _____ _____ _____ _____ _____ _____ ______ O2 _____ _____ _____ _____ _____ _____ ______

CO _____ _____ _____ _____ _____ _____ ______ CO2 _____ _____ _____ _____ _____ _____ ______ H2S _____ _____ _____ _____ _____ _____ ______ SO2 _____ _____ _____ _____ _____ _____ ______ C1 _____ _____ _____ _____ _____ _____ ______ C2 _____ _____ _____ _____ _____ _____ ______ C3 _____ _____ _____ _____ _____ _____ ______ iC4 _____ _____ _____ _____ _____ _____ ______ nC4 _____ _____ _____ _____ _____ _____ ______ iC5 _____ _____ _____ _____ _____ _____ ______ nC5 _____ _____ _____ _____ _____ _____ ______ C6-205°C (400°F) _____ _____ _____ _____ _____ _____ ______

205°C (400°F)+ _____ _____ _____ _____ _____ _____ ______ Avg. Mol. Wt. _____ _____ _____ _____ _____ _____ ______ Gravity _____ _____ _____ _____ _____ _____ ______ Viscosity _____ _____ _____ _____ _____ _____ ______ Total Sulfur, _______ _____ _____ _____ _____ _____ _____ ______ Metals, ___________ _____ _____ _____ _____ _____ _____ ______ Q (calc.) Absorbed _____ _____ _____ ____ ______ Q (calc.) Released _____ _____ Heater Gross Efficiency ______ Excess Air, % ______ Tube Skin Temps:,° _____ Burner Pressure ______________________ % of Rating ____________________ Provide sketch showing piping and controls for process piping. Deviations from UOP Specification: ___________________________________________ ________________________________________________________________________ ________________________________________________________________________

157048 Process Calculations

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CENTRIFUGAL PUMP SURVEY page _______________________________ date _______________________________ Item No.: _____________________________ by _______________________________ Service: __________________________________________________________________ Manufacturer: _____________________________________________________________ Type, Model: ______________________________________________________________ No., Size and Style (Mfgrs. Designation) ________________________________________ ________________________________________________________________________ Pressure Temperature Suction ______________ _____________ Discharge ______________ Other Information Rated Flow (STP) _____________ Seal Type? Single, Tandem, Double, Bellow Sp. Gr. _____________ Spillback? Yes/No Viscosity _____________ NPSHR? _________________________ Static Suction Head _____________ Suction Specific Speed: ________________ Speed _____________ Differential Head (flowing condition) _________________________________________ Driver Type: ___________________________________________________________ Manufacturer: ___________________________________________________________ No., Size, Rating and Style (Mfgrs. designation): __________________________________ Rating: _________________ Insulation Class: _________________ Service Factor: _________________ Voltage/Phase/Cycle: _________________ Motor: Power consumption ______________ Speed ______________ Turbine: Steam consumption ______________ Pressure Temperature Steam supply ______________ ______________ Steam exhaust ______________ ______________ Speed ______________ Supply copy of Mfgrs. pump curve and plot operating point. Deviations from UOP Specification: ____________________________________________ ________________________________________________________________________ ________________________________________________________________________

157048 Process Calculations

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157048 Process Calculations

Page 67

SUPPLEMENTAL CALCULATIONS

REGENERATOR VELOCITIES

The following procedure shows how to calculate the superficial velocity in the

combustor, upper regenerator, and cyclones. This section presents two methods to

calculate the velocities in the regenerator. The first method is more precise but

requires more information and it is more laborious than the second method.

Method A

1. Required Information

The FCC Unit is in total combustion mode for this case and with no catalyst cooler.

The process conditions are:

Temperatures: Average Dense 1371°F

Average Dilute 1375°F

Average Cyclones 1375°F

Air to Regenerator 399°F

Ambient 62°F

Relative Humidity 97%

Pressures: Regenerator 32 psig

Combustor 34 psig

Cyclones 31 psig

Areas: Combustor Cross sectional 300 ft2

Regenerator Cross sectional 452 ft2

First Stage Cyclones 24.5 ft2

Second Stage Cyclones 21.3 ft2

157048 Process Calculations

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Flow Rates: Air to Regenerator 83,615 scfm

= (scfm x 28.76 lb/mol x 60 min/hr)/(379.5 scf/mol)

= 380,200 lb/hr

Flue Gas: CO = 0 CO2 = 15.50

O2 = 2.5

N2 + Ar = 82.0

SO2 = 0

NO2 = 0

2. Combustion Air Correction to a Dry Basis

A psychometric chart is used to determine the moisture content of the air. At

atmospheric conditions of 62°F and a relative humidity of 97%, the moisture content

is:

Moisture Content = 0.01152 lb H2O

lb dry air

Wet Air = 380,200 lb/hr

Dry Air = 380, 200 lb/hr wet air 1 lb dry air

(1 + 0.01152) lb wet air = 375, 870 lb/hr

Water in Air = 380,200 lb/hr - 375,870 lb/hr = 4,330 lb/hr

157048 Process Calculations

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3. Calculate Flue Gas Rate

The flue gas rate can be calculated from the regenerator air rate. These two streams are related by the inert N2 + Ar content which remains constant through the

catalyst regeneration.

Since, moles = Weight

Molecular Weight

then,

Water in Air = (4,330 lb/hr)/(18 MW) = 241 mol/hr

Dry Air = (375,870 lb/hr)/(28.966 lb/mol) = 12,976 lb mol/hr

mol/hr (N2 + Ar) in dry air = mol/hr (N2 + Ar) in flue gas

12,976 lb mol

hr

79 mol inerts

100 mol air =

lb mol FG

hr

82 mol inerts

100 mol FG

Flue Gas (FG) = 12,501 lb mol/hr

4. Calculate the Water Produced by the Hydrogen Content of Coke

The overall reaction occurring in the regenerator is:

C + H2 + S + N + O2 = CO + SO2 + NO2 + H2O + O2

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The water produced by the hydrogen (H2) content of the coke can be calculated

from an O2 balance:

O2 in regeneration air = excess O2 in flue gas +

+ O2 reacted to CO (0.5 mol O2/mol CO)

+ O2 reacted to CO2 (1 mol O2/mol CO2)

+ O2 reacted to H2O (0.5 mol O2/mol H2O)

+ O2 reacted to SO2 (1 mol O2/mol SO2)

+ O2 reacted to NO2 1 mol O2/mol NO2

where:

O2 in regen. air = 12, 976 lb mol dry air

hr

21 mol O2

100 mol air =

2,725 lb mol

hr of O2

Excess O2 in FG = 12,501 lb mol FG

hr

2.5 mol O2

100 mol FG =

312 lb mol

hr of O2

O2 reacted to CO = 12,501 lb mol FG

hr

0 mol CO

100 mol FG

0.5 mol O2

mol CO = 0 lb mol/hr O2

O2 reacted to CO2 = 12,501 lb mol FG

hr

15.5 mol CO2

100 mol FG

1 mol O2

mol CO2=1,938 lb mol/hr of O2

O2 reacted to SO2 = 12,501 lb mol FG

hr

0 mol SO2

100 mol FG

1 mol O2

mol SO2 = 0 lb mol/hr of O2

O2 reacted to NO2 = 12,501 lb mol FG

hr

0 mol NO2

100 mol FG

1 mol O2

mol NO2 = 0 lb mol/hr of O2

157048 Process Calculations

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O2 reacted to H2O (by difference) is:

O2 Reacted to H2O = 2,725 - 312 - 0 - 1,938 - 0 - 0 lb mol/hr O2 = 475 lb mol/hr of O2 Since H2 + 1/2O2 = H2O

Then

The water produced by Hydrogen and Oxygen in the regenerator is:

H2O Produced by O2 = 475 lb mol

hr O2

2 mol H2O

mol O2 =

950 lb mol

hr H2

5. Calculate the Wet Flue Gas Rate

The total moles per hour of wet flue gas are:

Wet Flue Gas = Dry Flue Gas + Water from Air + Water from H2 in Coke =

12,502 mol/hr + 241 mol/hr + 949 mol/hr = 13,692 mol/hr

The actual cubic feet per second (ACFS) of the flue gas can be calculated by using

the Ideal Gas equation of state

PV = nRT then V = nRT/P

Where

R = 10.7 (psia x ft3)/(mol x °R)

Prg = 32 psig + 14.7 = 46.7 psia

Pcomb = 34 psig + 14.7 = 48.7 psia

Pcycl = 31 psig + 14.7 = 45.7 psia

Tcomb = 1,275°F + 460 = 1,735 °R

Tdense = 1,371°F + 460 = 1,831 °R

Tdilute = 1,375°F + 460 = 1,835 °R

Tcycl = 1,368°F + 460 = 1,828 °R

157048 Process Calculations

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ACFS @Tcomb = 13,692 mol/hr x 10.73 x 1,735/(48.7x3600 sec/hr) = 1,454 ft3/sec

ACFS @Tdens = 13,692 mol/hr x 10.73 x 1,831/(46.7x3600 sec/hr) = 1,596 ft3/sec

ACFS @Tdilute = 13,692 mol/hr x 10.73 x 1,835/(46.7x3600 sec/hr) = 1,599 ft3/sec

ACFS @Tcyc = 13,692 mol/hr x 10.73 x 1,828/(45.7x3600 sec/hr) = 1,632 ft3/sec

6. Calculate Superficial Velocities

Regenerator Superficial Velocity

= (ACFS @ Tdens, ft3/sec) / (Rg Cross Sect Area, ft2) = 3.5 ft/sec

First stage Cyclones Superficial Velocity

= (ACFS @ Tdilute ft3/sec) / (Total Inlet Area, ft2) = 65.2 ft/sec

Second Stage Cyclones Superficial Velocity

= (ACFS @ Tcyc, ft3/sec) / (Total Inlet Area, ft2) = 76.6 ft/sec

Combustor Superficial Velocity

= (ACFS @ Tcomb, ft3/sec) / (Comb Cross Sec Area, ft2) = 4.8 ft/sec

157048 Process Calculations

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Method B

1. Required Information

This method does not require the flue gas analysis. The process conditions are:

Temperatures: Average Dense 1371°F

Pressures: Regenerator 32 psig

Area: Regenerator Cross sectional 452 ft2

Flow Rates: Air to Regenerator 83,615 scfm

2. Calculate the Actual Cubic Feet per Second

The volumetric flue gas rate can be calculated by using the Ideal Gas equation of

state

PV = nRT then R = PV/nT

For air we have R = P1V1/n1T1

For the Regenerator Air R = P2V2/n2T2

Combining the last two equations P1V1/n1T1 = P2V2/n2T2

Or V2 = P1V1T2 x n2 T1P2 n1

Where: P1 = 0 pisg + 14.7 = 14.7 psia

T1 = 60 °F + 460 = 520 °R

V1 = 83,615 scfm/(60 s/m) = 1,393.6 ft/s

P2 = 32 pisg + 14.7 = 46.7 psia

T2 = 1,371°F + 460 = 1,831 °R

157048 Process Calculations

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n2/n1 = 1.04 Assumed. This factor is due to the combustion of

Hydrogen to in the coke to water.

Then

V2 = (14.7 psia)(1,393.5 ft/s)(1,831°R)(1.04) = 1,606 ft3/s

(520°R)(46.7 psia)

3. Calculate Regenerator Superficial Velocity

The superficial velocity is calculated by dividing the volumetric flow rate by the cross

sectional area:

Rg Velocity = 1,606 ft3/s = 3.6 ft/s

452 ft2

The molar expansion factor n2/n1 can be approximated if the flue analysis is

available by using the following equation:

n2/n1 = 2 - (79/N2%)

Where N2% is the Nitrogen percent form the flue gas analysis.

157048 Process Calculations

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REGENERATOR AIR DISTRIBUTOR PRESSURE DROP

The pressure drop across the regenerator air distributor can be calculated by the

following formula:

P = q2

C2 A2 (2g) 144

where:

∆P = pressure drop, psi

q = air rate at flowing conditions, ft3/sec

r = density of air at flowing conditions, lb/ft3

C = orifice coefficient, 0.60-0.80

A = total cross sectional area of holes, ft2

g = acceleration due to gravity, 32.2 ft/sec2

The perforated grid air distributor is designed for a pressure differential of about 0.7-

1.2 psi. This will give good air distribution for fluidization without causing catalyst

attrition. If the pressure differential is too high, the high velocity can cause attrition.

If the pressure differential is too low, less than 0.5 psi, it can cause poor distribution

of air and distributor erosion problems.

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REACTOR STRIPPER DENSITY

The following procedure shows how to calculate the density in Reactor Stripper.

The density indicator is a differential type instrument and for this case the range is

0-145 inches of water.

1. Calculate the Distance Between Taps

Lower Instrument Tap Elevation:

59' 8 7/8" or 59.7396'

Upper Instrument Tap Elevation:

74' 4 1/8" or 74.3438'

Distance Between Taps:

74' 4 1/8" - 59' 8 7/8" = 14' 7 1/4" or 175.25"

2. Calculate the Density

Instrument Readout: 75% Instrument Span: 0-145 inches H2O

75% x 145 inches H2O = 108.75 inches H2O

32

2

2

2

2ft

lb 38.7 =

ft

in 144

OHin 27.705

lb/in

ft

in 12

in 175.25

1 OHin 108.75

157048 Process Calculations

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Notes:

i) The Spent Catalyst Stripper Density is expected to range from 30 to 45 lb/ft3.

ii) In cases when the pressure taps are under the stripper baffles the distance

between taps should be replaced by the distance between the bottom edges of

the baffles.

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REACTOR STRIPPER LEVEL

This procedure shows how to calculate the level in the reactor. The level controller

is a differential type instrument and for this case the range is 0-300 inches of water.

1. Calculate the Distance Between the Taps

Lower Instrument Tap Elevation:

62' 3 7/8" or 62.3229'

Upper Instrument Tap Location:

127' 0" - 3' 3" - 1' 6" = 122' 3" or 122.2500'

Distance Between Upper Tap and Lower Tap:

122' 6" - 62' 3 7/8" = 60' 2 1/8" or 60.1771'

2. Data Required

Instrument Readout: 50% Instrument Span: 0-300 inches H2O

Stripper Density of 36.25 lb/ft3 (From Stripper Density Calculation)

Assume Reactor Vapor Space Density of 1 lb/ft3

Distance Between Upper Tap and Lower Tap = 60.1771'

Elevation of Lower Tap = 62.3229'

Normal Reactor Catalyst Level = 84.500'

Cyclone Dipleg Outlet = 79.5417'

300 in H2O x 50% = 150 in H2O

157048 Process Calculations

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3. Method A - This is rough method.

Catalyst offt = lb 36.25

ft

ft

in 144

OHin 27.705

lb/in OHin 150

3

2

2

2

2

2 21.51

Distance Relative to Normal Catalyst Level =

(62.32 + 21.51) - 84.50 = - 0.67 (i.e. ~ 8" below normal level)

4. Method B - This method is more precise than Method A since consider the

reactor vapor density.

X + Y = 60.18 ft => Y = 60.18 - X

Where: X = Catalyst height.

y = Reactor vapor height from catalyst bed to upper pressure tap.

60.18 ft = distance between pressure taps.

332

2

2

2

2 ft

lb 1 X)-(60.18 +

ft

lb) (36.25 X

ft

in 144

OHin 27.705

lb/in OHin 150

779.64 lb/ft2 = 35.25 X lb/ft3 + 60.18 lb/ft2

Then

X = 20.41 ft above Lower Level Tap

Distance Relative to Normal Catalyst Level =

(62.32 + 20.41) - 84.50 = - 1.77 (i.e. 1' 9 1/4" below normal level)

157048 Process Calculations

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Notes:

i) The Spent Catalyst Stripper Density is expected to range from 30 to 45

Lbs/Ft3.

ii) In cases when the lower pressure tap is under the stripper baffle the distance

between taps should be replaced by the distance between the bottom edge of

the baffle and the upper tap.

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REACTOR RISER RESIDENCE TIME

Residence time, the time that hydrocarbons spend in the riser, is another design

variable utilized in controlling reaction severity. This variable is of particular

importance in operation using high activity zeolitic catalyst. Typical residence time

for current designs is two to three seconds.

Conversion is proportional to residence time in that it increases with prolonged

contact of catalyst and feedstock. Gasoline yields increase with residence time up

to a point after which over-cracking may occur. This results in a loss of gasoline

yields and a significant increase in conversion.

The method used to calculate riser residence time is as follows:

= VR/[(1/3)(VF) + (2/3) (VP)]

= Residence time in seconds

VR = Riser volume, ft3

VF = Volume of vaporized feed, steam, lift gas, water, and inerts calculated at

the average conditions at the point of feed injection, ft3/s.

VP = Volume of vaporized products, steam, lift gas, water and inerts calculated

at the average conditions at the point of feed injection, ft3/s.

It should be noted that prior to the residence time calculation, the average

temperature and pressure at the point of feed injection must be estimated to obtain VF and VP.

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The riser pressure at the point of feed injection can be approximated by assuming a

5 psig pressure drop, hence:

Riser Pressure = Reactor dome pressure + 5 psi

The average temperature at the point of feed injection is calculated as:

PLPo

OLRxWLSWLPLPoR

COLOSOWCOC

HHHOWTOSTOWTCOLToCTOCTavg

///495.0/2753.0

///495.0//2753.0

Where:

C/O = Catalyst to Oil wt. ratio, calculated in reactor-regenerator heat

balance section

S/O = Steam to Oil wt. ratio

W/O = Water to Oil wt. ratio

L/O = Lift gas to Oil wt. ratio

TR = Regenerator dense bed temperature, °F

TO = Oil feed temperature, °F

TL = Lift gas feed temperature, °F

TS = Steam feed temperature, °F

TW = Water feed temperature, °F

CPO = Specific heat of vaporized oil feed, Btu/lb/°F

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CPL = Specific heat of lift gas, Btu/lb/°F

∆HOL = Latent heat of vaporization of oil feed at inlet temperature, To,

Btu/lb

∆HWL = Latent heat of vaporization of water at inlet temperature, Tw,

Btu/lb

∆HRX = Heat of reaction, Btu/lb, calculated in reactor-regenerator heat

balance section

Tavg = Average temperature at point of feed injection, °F

157048 Process Calculations

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HYDROGEN BALANCE

This document describes a manual method for calculating the Hydrogen balance for

an FCC Unit.

Data required:

A normalized to 100% recovery product summary in wt-% A breakdown of the C4- components

The distillation and API of each C5+ product

The distillation and API of the feed

API Technical Data Book Figure 2B1.1

"Characterizing Boiling Points of Petroleum Fractions"

Figure 2 - UOP Chart 409B-12

"Hydrogen Content of Liquid Petroleum Hydrocarbons"

Description of the Calculation Method:

Step 1. Determine the molecular weight of Hydrogen per molecule for each C4-

product, e.g. H2S, H2, C1, C2, C2=, etc. See column 3 of the attached example.

Step 2. Determine the percentage Hydrogen in each C4- product component by

dividing the molecular weight of Hydrogen per molecule by the molecular weight of

each component. In the attached example this is column 3 divided by column 4

times 100. The result is given in column 5.

Step 3. Calculate the Volume Average Boiling Point (VABP) for each of the heavier products (C5+ gasoline, LCO, and MCB). See Figure 2B1.1 comments for

procedure and definitions.

Step 4. Calculate the Engler Slope for each of the heavier products (C5+ gasoline,

LCO, and MCB). See Figure 2B1.1 comments for procedure and definitions.

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Step 5. Determine the Mean Average Boiling Point from API Figure 2B1.1.

Step 6. Determine the Hydrogen content of the hydrocarbon liquid from Figure 2.

See the lower half of column 5 in the attached example.

Step 7. Multiply the wt% normalized yield pattern for each component by the

percentage Hydrogen in each product component. In the attached example this is

column 2 times column 5. The result is given in column 6.

Step 8. Calculate the percentage of Feed Hydrogen in each component by dividing the Wt% Hydrogen in each product component by the Wt% H2 in the feed. In the

attached example this is the value in column 6 divided by the Wt% H2 in the feed

(13%).

157048 Process Calculations

Page 86

Hydrogen Balance Summary

1 2 3 4 5 6 7

Mass Balance wt-% #H/Molecule MW %H2 H2 wt-% % Feed H2

Results

Feed: 100.00 Values from Figures 2B1.1 & Fig. 2 13.00 100.00

H2S 0.04 2.0158 34.08 0.06 0.0021 0.02

H2 0.23 2.0158 2.02 1.00 0.2280 1.75

C1 0.89 4.0361 16.04 0.25 0.2245 1.73

C2 0.81 6.0474 30.07 0.20 0.1622 1.25

C2= 0.91 4.0316 28.05 0.14 0.1303 1.00

C3 1.30 8.0632 44.10 0.18 0.2375 1.83

C3= 4.64 6.0474 42.08 0.14 0.6662 5.12

IC4 2.69 10.0790 58.12 0.17 0.4665 3.59

NC4 0.63 10.0790 58.12 0.17 0.1094 0.84

C4= 4.88 8.0632 56.11 0.14 0.7007 5.39

C5+ Gasoline 44.55 13.80 6.15 47.29

LCO 27.60 Values to the right 11.30 3.12 23.99

MCB 5.22 were determined from Chart 10.20 0.53 4.10

Coke 5.62 2B1.1 & Fig 2. 4.44 0.25 1.92

Total Products 100.00 See attached method. Total 39.74 12.98 99.82

Laboratory Summary for Gasoline Distillation D-86 °F °R (°R)^1/3 SpGr 0.7286

IBP 96.8 556.8 --------- API 62.02

10% 131.9 591.9 8.3962 VABP 214.7

20% 145.4 605.4 8.4596 Engler Slope 2.40

30% 163.4 623.4 8.5426 Correction Factor 6.0

40% 182.3 642.3 8.6280 CABP, °R Uncorrected 672.8

50% 203.9 663.9 8.7237 CABP, °F Corrected 206.8

60% 230.9 690.9 8.8404 CABP, °R Corrected 666.8

70% 259.7 719.7 8.9616 UOP K 11.99

80% 291.2 751.2 9.0904 Total Sulfur, wt% 0.0032

90% 323.6 786.3 9.2193 Octane (F1 C) 92

EP 371.3 831.3 --------- RVP @ 378°C, kg/cm2 39.6

Recovered Volume 99.5 %

Residue Volume 0.5 %

157048 Process Calculations

Page 87

Hydrogen Content of Liquid Petroleum Hydrocarbons

157048 Process Calculations

Page 88

157048 Process Calculations

Page 89

Comments on Figure 2B1.1

Purpose: The various average boiling points which are used to characterize petroleum fractions are correlated in Figure 2B1.1 with the ASTM D86 distillation properties of the fraction. If these boiling points are required for mixtures (or portions of a mixture) for which the composition is known, using the defining equations (2-0.3) through (2-0.7) given in the introduction. Reliability: The reliability is unknown. Notation: The volumetric average boiling point of a petroleum fraction is the weighted average of the ASTM D86 distillation temperatures after 10, 30, 50, 70 and 90 percent by volume have been distilled.

5

9070503010 TTTTT . The slope is calculated assuming a linear ASTM D86 distillation curve

between the 10 and 90 percent points

10901090 TT

in degrees Fahrenheit per percent distilled.

The relationships between the various average boiling points given in Figure 2B1.1 for petroleum fractions are analogous to those defined by equations (2-0.3) through (2-0.7) for mixtures of identifiable hydrocarbons. Special Comments: For ASTM D86 distillation temperatures above 475°F, use the following correction for cracking: TD 00473.0587.1log (2B1.1-1)

Where: D = correction to be added to T, in degrees Fahrenheit T = observed distillation temperature, in degrees Fahrenheit If the available distillation data are not from ASTM Method D86, they must be converted by the methods of Chapter 3 to calculate the volumetric average boiling point. Literature Sources: This figure was developed by Smith and Watson, Ind. Eng. Chem. 29 1408 (1937). Equation (2B1.1-1) was given by S.T.Hadden, Gulf Research and Development Company, Pittsburgh, Pa., private communication (1964). Example: Determine the molal average boiling point, weighted average boiling point, cubic average boiling point, and mean average boiling point of a petroleum fraction having the following ASTM D86 distillation properties: Distillation, percent by volume 10 30 50 70 90 Temperature, degrees Fahrenheit: 149 230 282 325 371

FVABP

2715

371325282230149 %78.2

80

149371FSlope

Using Figure 2B1.1, the average boiling points are calculated from the volumetric average boiling point:

FMABP 24130271 FCABP 2647271

FWABP 2787271 FMeABP 25219271

157048 Process Calculations

Page 90

Calculation of Flow Meter Constant “K” for Liquid Flow:

Gb

GfhFcFaDSNQ m

2max

Where: Qmax = maximum flow rate at base conditions, (@ 60°F) N = constant based on flow units D = Process pipe inside diameter d = orifice diameter S = discharge coefficient, f(d/D) Fa = thermal expansion of plate Fc = Reynolds correction factor Gf = liquid specific gravity at flowing conditions

Gb = gas specific gravity at base condition (@ 60°F) hm = maximum differential pressure (design basis)

Note: N, S, Fa, and Fc can be found in L.Spink’s “Principles and Practices of Flow Meter Engineering” Example for Sponge Gas Meter

Flow, bpsd = 34,000 N, for bpd = 194.3 D = 7.981 in d = 5.034 in B = d/D = 0.6307 S = 0.2672

Fa = 1.001 for type 304 stainless steel plate Viscosity, cS = 10 Re = 39,292; Re = 92.235*bpsd / (viscosity*D)

Fc = 1.015 hm = 100 in H2O Temp, °F = 173°F Gb = 0.9266 Gf = 0.8854 Gf = Gb*VCF = 0.9260 * 0.9562 = 0.8854

9266.0

8854.0100015.1001.1981.72672.03.194max 2Q

BPSDQ 119,34max

The “K” constant can be calculated by using the following equation:

BPSD

Gf

GbQK 360,3

10

max*

Where: 10: maximum units meter reading, MR, then:

Gb

GfMRQ 360,3 ; BPSDQ _________

157048 Process Calculations

Page 91

Calculation of Flow Meter Constant “K” for Gas Flow:

ZGbTf

PfhYFcFaDSNQ m

2max

Where: Qmax = maximum flow rate at base conditions, (@ 60°F) N = constant based on flow units D = Process pipe inside diameter d = orifice diameter S = discharge coefficient, f(d/D) Fa = thermal expansion of plate Fc = Reynolds correction factor Y = upstream orifice expansion factor hm = maximum differential pressure (design basis) Pf = absolute flowing pressure upstream of the orifice, psia Tf = absolute flowing temperature, °R Gb = gas specific gravity at base condition (@ 60°F) Z = compressibility factor of gas Note: N, S, Fa, Fc, Y and Z can be found in L.Spink’s “Principles and Practices of Flow Meter Engineering” Example for Sponge Gas Meter

Flow, scfm = 8,375 = lb/hr = 26,100 N = 128.78 for scfm and psi D = 6.065 in d = 3.5834 in B = d/D = 0.5908 S = 0.2284

Fa = 1.0003, for type 304 stainless steel plate Viscosity, cP = 0.011 Re = 2,472,487; Re = 6.32(lb/hr)/(viscosity*D)

Fc = 0.988 Y = 0.9944; Y = 1-(0.41-0.35B^4)(h/2)/(27.67Pf*(p/Cv)) hm = 200 in H2O Pf = 187.7 psia Tf = 573°R

Cp/Cv = 1.27 Gb = 0.7054 Z = 0.965 f(Tr,Pr) Tr = Tf/Tc Pr = Pf/Pc

965.07054.0573

7.1872009881.00003.1065.62284.078.128max 2

Q

scfmQ 490,10max

The “K” constant can be calculated by using the following equation:

scmPf

GbTf

QK 539,1

10

max

Where: 10: maximum units meter reading, MR, then:

GbTf

PfMRQ 1539 ; scfmQ _________

157048 Treating Page 1

FEED/PRODUCT TREATING

INTRODUCTION

FCC feeds contain a number of contaminants that affect yields, product quality,

plant emissions and corrosion in the main column and gas concentration unit.

These contaminants are handled by a combination of treating either the feed or

products as well as unit design. This subject is of increasing importance to refiners

with the ever tighter limits on emissions from the plant, especially SOx and NOx and

on limits in liquid product sulfur levels. The industry trend towards processing resid

feeds which typically have higher concentrations of sulfur, metals and carbon

residue makes this issue even more important.

In the United States new fuel specifications are will limit the sulfur concentration in

both gasoline and high speed diesel fuels to less than 50 wppm. This is an issue

critical to the FCC because in a typical refinery gasoline pool 98% of the total

gasoline pool sulfur comes from the FCC naphtha even though the FCC naphtha

makes up only 30-40% of the pool. Limits on fuel oil sulfur will also require a

reduction in the MCB product sulfur. In some areas the limits on SOx emissions will

be more restrictive requiring less than 300 ppm in the flue gas. In the coming years

these restrictions will likely become even more stringent.

FEED TREATING

Light and heavy vacuum gas oils are the most common FCC feedstock with an

increasing trend towards atmospheric resid. Also, there are economic incentives

towards processing lower priced crudes which typically contain higher levels of

contaminants.

Hydrotreating is the most common and effective method of improving the FCC feed

quality. Hydrotreating not only reduces the contaminant concentration but also

improves yields. Hydrogen addition to the feed, especially to the large polynuclear

aromatics, makes these molecules easier to crack resulting in higher conversion to

desired products with less coke and light gas make. Table 1 shows the impact of

hydrotreating on both the FCC feed properties and the FCC yields.

157048 Treating Page 2

Table 1 Feed Hydrotreating Benefits

Feed Desulfurization Untreated 90% 98% 99%

Feed Properties

Gravity, ºAPI 20.5 23.5 24.8 26.0

Sulfur, wt% 2.6 0.25 0.06 0.02

Nitrogen, wppm 880 500 450 400

Carbon Residue, wt% 0.4 0.25 0.1 0.1

Metals (Ni + V), wppm 5 2 1 <1

Yields, wt%

H2S 1.1 0.1 0.0 0.0

C2- 3.3 3.5 3.2 2.8

LPG 16.3 17.6 18.7 19.9

Naphtha 48.3 51.5 52.5 53.6

LCO 16.7 15.7 15.0 14.0

MCB 9.0 6.6 5.9 5.2

Coke 5.4 5.0 4.7 4.4

Conversion, lv% 74.3 77.7 79.1 80.8

Key Product Properties

Naphtha RONC 93.2 93.0 92.9 92.7

Naphtha MONC 80.5 80.8 81.1 81.0

LCO Cetane Index 25.7 25.7 26.4 26.5

Product Sulfur, wppm

H2S 10,100 750 190 95

Naphtha 3,600 230 55 18

LCO 29,700 3,400 900 300

MCB 57,800 11,000 3,000 1,100

SOx , vppm in flue gas 2,000 410 120 42

157048 Treating Page 3

As more sulfur is removed the sulfur balance in the FCC shifts towards higher

percentage of the total feed sulfur going to the MCB product and SOx in the flue

gas. This is because the hardest to remove sulfur is in the heavy aromatic

compounds which tend to form coke or remain uncracked. From Table 1 the

percentage of sulfur in the feed ending up in the MCB product increases from 20 to

30% and the percentage of feed sulfur ending up in the naphtha decreases from 6.7

to 4.8% as the untreated feed is desulfurized by 98%.

Table 1 illustrates a case where hydrotreating is used primarily for reduction in

sulfur. In some units, especially those treating resid feeds, the reduction of carbon

residue and metals is more important. Hydrotreating can reduce feed metals and

carbon residue by 90% or more allowing processing of extremely contaminated

resid feeds in the FCC while still achieving good yields. This can also significantly

reduce the required fresh catalyst addition rate.

Nitrogen is also removed by feed hydrotreating. Some of the nitrogen in the FCC

feed is converted to ammonia which can cause salt formation and plugging in the

main column overhead. Basic nitrogen in the feed acts a temporary poison to the

FCC catalyst. Severely contaminated FCC feeds may contain as much as 4,000

wppm nitrogen while a clean feed may contain less than 500 wppm. Cyanides are

also formed from nitrogen in the feed which can cause blistering and corrosion in

the gas concentration unit. Wash water and proper control of the main column

overhead temperature is usually sufficient to prevent these plugging and corrosion

concerns so that these are usually not a significant factor when considering

hydrotreating as an option to improve profitability.

Oxygen may be present in the feed either chemically bonded in the hydrocarbon or

absorbed from storage. Dissolved oxygen may cause fouling of heat exchangers

when the temperature approaches 400ºF (200ºC). The best method for preventing

this is to blanket the raw oil tanks with either fuel gas or nitrogen. This is most

important for cracked feed stocks such as coker gas oil or highly olefinic feeds.

Once in the reactor the oxygen will quickly be converted to water, carbon oxides,

phenols, creosols or acids.

157048 Treating Page 4

PRODUCT TREATING

FCC products contain undesirable material which must be either removed or

transformed into an inoffensive material if the product is to meet specifications for

use. The cycle oil, gasoline, LPG and fuel gas must be non-corrosive, stable in

storage and of acceptable odor. The specifications may also limit the allowable

amount of contaminants such as sulfur. Feed treating is effective in reducing nearly

all of these contaminants but it requires a very high capital investment.

The major undesirable constituents found in FCC products are:

1. Sulfur compounds. In the gasoline and lighter compounds there are

particularly hydrogen sulfide, mercaptans, elemental sulfur, and carbonyl

sulfide. While the regenerator flue gas is not considered a product of the FCC,

reduction of SOx emissions from this stream is of increasing importance to

most refiners. SOx control is covered in more detail in the Environmental

section of this manual.

2. Oil soluble or ionic metals, principally copper.

3. Nitrogen containing compounds, such as pyridine, quinoline, and pyrrole. NOx

in the regenerator flue gas is also a common concern.

4. Oxygenated compounds, including phenols and carbonic acids.

5. Diolefinic hydrocarbons.

The degree of undesirability is modified and varies between groups of substances

as well as within families of compounds, depending upon the concentrations

present and the required product specifications. Synergistic and inhibiting

relationships are known to exist, as between thiophenols and olefins which intensify

gum formation, or between elemental sulfur and hydrogen sulfide which promote

copper strip corrosion. The distribution and concentration of objectionable

157048 Treating Page 5

components in particular product are governed by FCC charge properties, catalyst

type and activity, the promotion of thermal cracking reactions, and fractionation

schemes. The following sections will discuss the impurities and what may be done

to render them harmless.

SULFUR

There are a variety of different sulfur compounds present in FCC product streams.

They vary in their potential damage, but overall rate as the most troublesome

impurity. Hydrotreating each product stream would remove them along with other

contaminants, but from both a process and cost basis this technique is rarely used

for LPG or gasoline treating. Hydrotreating is occasionally used for cycle oil treating.

Elemental Sulfur

Elemental sulfur may occur naturally, but because it is non-volatile it does not distill

to any product above the feed tray. Elemental sulfur formation can be a problem in

the gas concentration unit when oxygen in present. The most common source of

the oxygen is the wash water injected in the wet gas compressor interstage. It is

also possible that during startup catalyst circulation in the FCC oxygen will be

entrained into the reactor and enter the gas concentration unit which can cause

elemental sulfur formation for a short period after startup. The best solution to

minimize elemental sulfur formation is to eliminate all possible sources of oxygen

including using steam condensate for the wash water.

Elemental sulfur can also be found in the FCC gasoline or LPG products if there is

carry over of caustic from the Merox or other treating units.

Elemental, sometimes called free sulfur corrodes copper and consequently

produces a positive copper strip corrosion test. In the absence of H2S, as little as 5

wt. ppm free sulfur can give a failing copper strip test. If H2S is present, even in very

low concentrations, the amount of allowable sulfur is even less. When 0.3 wt. ppm

H2S is present, 0.5 wt. ppm elemental sulfur can give a filling copper strip test.

157048 Treating Page 6

Elemental sulfur has a harmful effect on alkyl lead susceptibility for gasoline octane

improvement. Free sulfur will remain as a deposit when LPG is evaporated.

Removal of elemental sulfur is very difficult; hydrotreating or redistillation are two

costly removal methods. Chemical treatments such as scrubbing with sodium or

potassium polysulfide solutions or caustic-sodium sulfide, or reverse doctor treating

may be used but may not be completely effective. Certain additives may be helpful

in masking the sulfur corrosivity test. They should be used with caution. The best

treatment method is to avoid elemental sulfur formation by preventing H2S

oxidation.

Hydrogen Sulfide

Hydrogen sulfide results from the decomposition of sulfur compounds during the

cracking reaction and concentrates in the fuel gas and LPG products. It has an

obnoxious odor at low concentration, and is very poisonous. It paralyzes the

involuntary breathing function, leading to asphyxiation, unconsciousness and death.

Hydrogen sulfide in fuel gas will burn in a heater to form SO2. This acid gas may

cause corrosion and environmental problems due to its acidity when it dissolves in

water. In the presence of oxygen, H2S may oxidize in a product stream to form

elemental sulfur. H2S has a deleterious effect on lead susceptibility of FCC

gasoline. It promotes peroxide formation and prevents oxidation inhibitors from

functioning, thus reducing gasoline stability in storage. It is undesirable in HF acid

alkylation feedstocks as one pound of sulfur consumes about five pounds of

process acid, and H2S, along with some mercaptans, is sufficiently volatile to stay

with the C3 and C4 streams.

157048 Treating Page 7

Dilute caustic soda or soda ash will remove H2S as well as CO2. The aqueous

caustic soda solution must be sufficiently dilute to prevent formation of sodium

sulfide crystals as the NaOH is converted to Na2S, and in the case of a dry feed, as

the solution dehydrates. Normal caustic concentrations are in the range of

10-15° Be to avoid Na2S crystallization.

The other principal treating method for the removal of H2S is regenerative

monoethanolamine (MEA) or diethanolamine (DEA) scrubbing. The stream to be

treated is contacted countercurrently with the amine to remove H2S, CO2, and COS.

The amine is then steam stripped to regenerate it. Although this treatment can

reduce H2S concentrations below 6 wt. ppm, it is equilibrium limited and therefore it

is normal to provide a dilute batch caustic scrubber following the amine scrubber as

a final cleanup and guard in case of an amine unit upset, e.g., when treating LPG.

Aside from pollution abatement benefits when operated in tandem with a sulfur

recovery process, amine treating usually becomes economically attractive strictly on

a chemical consumption basis when H2S levels exceed roughly 1000 ppm.

Mercaptans (RSH)

Mercaptans are found in all cracked products streams. Some of these may be

naturally occurring in the feed, but most mercaptans are formed during the cracking

reactions. Decomposition of other sulfur compounds or recombination reactions

between H2S and olefins are the major sources. There are two distinct types: alkyl,

open chain mercaptans, and aryl, aromatic mercaptans in which the •SH group is

linked to a benzene ring structure. The aryl mercaptans are also known as

thiophenols and thiocresols. They tend to predominate over alkyl mercaptans in

FCC product streams boiling over 300°F (150°C).

The lower molecular weight mercaptans have a very obnoxious odor, particularly

noticeable due to their low vapor pressure. All mercaptans, like most sulfur

compounds, have a deleterious effect on lead susceptibility of motor gasolines.

Thiophenols promote gum and sludge formation reactions and cause storage

problems. Mercaptans can react with copper, particularly if basic nitrogen is

present, to form oil soluble cuprow compounds which can be oxidized to insoluble

157048 Treating Page 8

copper oxide. The soluble copper can also then react with some oxygenated

compounds to form gelatinous copper phenolates.

Low molecular weight mercaptans may be extracted to some degree with caustic or

be sweetened, in a process which converts the mercaptans to less odiferous

disulfides. Mercaptans may be extracted from LPG to very low values, 0.5 wt. ppm

in some cases. Extraction of 50-95% of the mercaptans from gasoline is possible,

depending on boiling range. However, as mercaptans in FCC gasoline generally

represent only 10 to 35% of the total sulfur present, partial gasoline desulfurization

by extraction is usually not economical. The majority of FCC gasolines are currently

only sweetened to essentially eliminate mercaptans and produce a doctor negative,

or sweet, gasoline. Cycle oil is sometimes sweetened, but if low sulfur is desired,

the cycle oil must be hydrotreated.

Non regenerable caustic scrubbing to extract mercaptans is an old and expensive

process which may create or compound waste disposal problems. In many cases it

is not very effective. The most successful treating process for either extraction or

sweetening is the UOP Merox process. This process uses small amounts of caustic

to remove or transform mercaptans. A catalyst and oxygen supplied from

atmospheric air are used to regenerate the caustic. Further information on the

Merox process may be obtained from UOP.

Total gasoline sulfur may also be reduced by undercutting or reducing the endpoint

of the FCC gasoline. The sulfur concentration in the FCC gasoline increases rapidly

as the boiling range exceeds ~400º (200ºC). By reducing the endpoint of the

gasoline so that the heaviest 20% is included in the light cycle oil product the

gasoline sulfur content can be reduce by as much as 60%. Unfortunately, there are

significant product value losses associated with this for most refiners.

157048 Treating Page 9

Carbonyl Sulfide (COS)

Carbonyl sulfide is produced during the cracking reaction. It boils slightly below

propane at -58°F (-50°C). Upon post fractionation the COS concentrates in LPG,

propane-propylene, and finally propylene as the distilled cuts are narrowed in

boiling range. COS concentrations in the LPG stream may range from 5 to 100

ppm; the amount usually rises with increased feed sulfur, but is very unpredictable.

COS, like some other sulfur compounds, should be considered toxic.

The principle concern with COS, aside from situations where product total sulfur

must be very low or zero, is its tendency to hydrolyze, forming corrosive H2S and

CO2. This hydrolysis proceeds slowly but is catalyzed by activated alumina or

molecular sieve desiccants. COS also partially reacts with MEA in acid gas

scrabbling systems to form high boiling by-products which are not steam

regenerable. COS is also a strong poison for polypropylene producers using FCC

propylene as a feed. Some polymerization catalysts are sensitive to as little as 5

ppb COS.

Carbonyl sulfide can be partially removed from the light product streams by

scrubbing with an aqueous DEA solution. Diethanolamine, unlike monoethanol-

amine, does not chemically react with COS and therefore is steam regenerable.

Aqueous DEA scrubbing can usually reduce COS levels to less than 10 ppm. A

reduction of COS to levels of one ppm or less can be effected with a batch scrubber

using MEA, sodium hydroxide, and water to remove COS by chemical reaction.

This system is not regenerable. For units producing polymer grade propylene

additional adsorbents or reactive treaters will commonly be used to remove COS

down to undetectable levels.

Copper

Copper is a powerful oxidation catalyst. It is usually picked up from contact with

copper or copper alloy surfaces, especially when ammonia or other basic nitrogen

and mercaptans are present. Copper catalyzes gum formation by promoting olefin

oxidation reactions faster than inhibitor additives can terminate these chain

157048 Treating Page 10

reactions. Cracked distillates containing copper will form gum and gelatinous

precipitates in storage. Copper also contributes to distillate color stability problems

and catalyses oxidation of alkyl lead additives, leading to haze in some finished

gasolines.

Gross copper contamination can be removed by chemical treatment, such as dilute

acid scrubbing or clay percolation. If the copper does not exceed 1 mg/liter, it can

be rendered harmless with a copper deactivator. Dosage is roughly 10 wt. ppm

active agent for each mg/liter. The deactivator, a chelating agent, complexes with

the copper so that it cannot take part in any further reactions.

Nitrogen Compounds

There are usually two types of nitrogen found in gasoline and cycle oil. One type

would be neutral compounds such as pyrrole, and the other a basic compound such

as pyridine or quinoline. Ammonia is found in the reactor overhead vapors, but if

normal main column overhead water injection is maintained, the ammonia is

removed at this point.

Neutral nitrogen compounds are associated with sediment formation in fuel oils.

Basic compounds are typically more harmful. Pyridine has a characteristic odor

which is very unpleasant when combined with mercaptans. Both basic and neutral

nitrogen compounds are color precursors which affect distillate color stability. Their

effect on lead susceptibility and octane number varies between good and bad

depending on the particular compound in question. Both types of nitrogen

compounds may also promote oil soluble gum formation, but this has not been

firmly established at this time.

Neutral nitrogen compounds may be removed with either strong acid or strong

caustic-methanol solutions. Basic nitrogen compounds could be removed with dilute

acid in acid resistant equipment. If acid strength is too high, there may be problems

with olefin addition, sulfonation, and other acid catalyzed reactions. Hydrotreating

will decompose both types of nitrogen compounds to ammonia. This might be

157048 Treating Page 11

suitable for cycle oils, but not for gasoline, because aromatics might be saturated,

with severe loss in octane number.

Oxygen

Oxygen compounds such as phenols and cresols are formed during the cracking

reaction from oxygenated compounds in the feed and from oxygen entrained with

the catalyst. They are generally not considered harmful and may be considered

beneficial as some act as oxidation inhibitors. Some of the phenols are suspected

of being color precursors. Caustic treating can be used to remove most of the

oxygen containing compounds, including most organic acids, when deemed

necessary.

Diolefins

Diolefins, especially conjugated diolefins, are reactive hydrocarbons which quickly

enter into gum and sediment forming reactions. These compounds are normally

found in significant concentrations only in thermally cracked products. However,

when FCC conditions allow cracking to occur in the absence of catalyst, diolefins

will be formed in amounts roughly proportional to the degree of thermal cracking

present.

A good example of this type of compound is butadiene. It stays in the C4 fraction as

it is concentrated through fractionation. If this stream is then used as alkylation

feed, the butadiene will polymerize to form tar. Higher order diolefins lead easily to

gum formation in the gasoline and cycle oil streams.

Diolefins can be removed without significant olefins removal by carefully controlled

mild hydrotreating or vapor phase clay treatment. Proper dosage of oxidation will

nullify their effects. Another solution would be to minimize formation of diolefins by

decreasing thermal cracking. This could be done by reducing the reactor

temperature, reducing the regenerated catalyst temperature or by mechanical

changes minimizes post riser residence time.

157048 Treating Page 12

SUMMARY – FCC PRODUCT TREATMENT METHODS Contaminant Concentration Treatment Copper High Dilute mineral acid Clay percolation Low (<1 mg/l) Metal deactivator addition Elemental sulfur — Redistribution Hydrotreating Reverse Doctor Prevent formation by minimizing free oxygen Hydrogen sulfide, H2S High (>1000 ppm) MEA or DEA scrubbing Low Caustic soda, MEA or DEA

scrubbing Mercaptans, R-SH Any Merox (Regenerative caustic) Extractive for LPG or

Sweetening for Gasoline Total Gasoline Sulfur Undercutting of FCC gasoline Carbonyl sulfide, COS — DEA-water scrubbing Caustic-MEA-water scrubbing

(Batch operation only) Silica-Alumina Adsorbents PbO Treaters Basic nitrogen compound — Water Wash (NH3) Weak mineral acid Neutral nitrogen compound — Strong acid Strong caustic-methanol solution

157048 Treating Page 13

Contaminant Concentration Treatment Oxygen compounds, phenols or acids — Water Wash Caustic soda Diolefins — Mild hydrotreating Vapor phase clay treating Change FCC operations to minimize formation NOTE: Hydrotreating may be used to eliminate many of these contaminants. In practice, however, it is used for cycle oil treating in some cases, rarely for LPG or gasoline. Treating of the FCC feed is also effective in minimizing many of these. Regenerative caustic treating, such as the Merox process, is a very common treating method. Batch scrubbing using caustic, or regenerative MEA-DEA scrubbing are also used. This may be in conjunction with a Merox unit or without it, depending on the contaminant and on economic considerations.

157048 Analytical Methods

Page 1

ANALYTICAL METHODS

Introduction

Good analyses of the feed and product streams are essential for control and

evaluation of a Fluid Catalytic Cracker. It is extremely difficult to optimize a unit if

potential problems are not defined through the laboratory and process variables.

The following sections give a typical FCC sampling schedule and a brief outline of

some of the more common analytical methods.

There are a large number of laboratory tests which may be used. FCC products

vary widely, from clarified oil to fuel gas. This in turn leads to markedly different

analytical methods, such as six different types of distillations. The product being

tested and the type of result desired will determine which test is used.

Distillation

There are six distillation methods listed in this book. Two of them, UOP 1 and

ASTM D 86, cover the lighter fractions, from gasoline to gas oils. The UOP 1

method goes further; it continues past the typical decomposition point of 700°F

(371°C) into a thermal cracking of the sample with a dry residue (coke) remaining.

Two other methods, UOP 77 and 79, are fractionations in addition to distillations.

Either one can be used to separate certain fractions of a product for further

analysis. UOP 77 is more commonly used. UOP 79 is a high precision distillation

method which is used to determine true boiling points of petroleum fractions. The

test requires special equipment and the information obtained from this test is not

frequently needed. The two vacuum distillation methods, UOP 76 and ASTM D

1160, are used for heavy material. Reduced pressures, down to 1 mm Hg absolute

for D 1160 and 0.3 mm Hg absolute for UOP 76, permit distillation when the

temperature used for atmospheric techniques would lead to thermal cracking.

Sulfur

157048 Analytical Methods

Page 2

The six analytical methods for sulfur analysis can be initially divided into two groups,

gases and liquids. The Tutwiler method, UOP 9, gives a quantitative determination of H2S in a gas stream. A second method, UOP 212, measures H2S, mercaptans,

and COS in light gases and LPG. The Tutwiler method does not give as detailed a

test as does UOP 212, but takes less time. There are four methods given for hydro-

carbon liquid analysis. The Doctor Test, UOP 41, gives a qualitative determination of mercaptans and H2S. UOP 163 will give a breakdown of mercaptan and H2S in

liquid streams. For total sulfur of lighter oils, the Lamp method, ASTM D 1266, is

used. For oils boiling above 350°F (177°C), ASTM D 1552 may be used to

determine total sulfur.

Octane

The Motor octane method, ASTM D 2700, is more severe, i.e., gives a lower rating

than does the Research method, ASTM D 2699. The correlation between the two is

not exact, so it is generally not easy to predict one octane from another. For similar

feedstocks and plant operation, the refiner may be able to make some general

predictions from past data.

Gas Chromatography

To determine the composition of light hydrocarbon gases and LPG streams containing small amounts of C3 and C6 material, either UOP 539 or UOP 709 may

be used. Neither of these will separate argon from oxygen, or butene-1 from

isobutylene. UOP 709 is easier to run than UOP 539 and requires less elaborate

equipment, but UOP 709 does not differentiate between ethane, ethylene and

carbon dioxide. For exact determination of fuel gas from an FCC, UOP 539 would

be the better method. UOP 725 can be used to determine concentration of C5 and

lighter material in FCC gasoline.

157048 Analytical Methods

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Samples for UOP Analysis

Most refineries have laboratories for common analyses. Samples may be sent to

UOP if the refiner does not have the equipment, manpower, or wishes to check the

accuracy at his own lab. Samples which are sent to UOP for analysis sometimes go

astray, either in shipping or within UOP. In order to minimize delays caused by lost,

misplaced or unidentified samples, please observe the following rules.

1. Identify each sample with refiner, location, unit, sample, date and technical

contact person at UOP responsible for the results. Make certain the sample

tag is well secured to the sample and remains legible, even if it is wet with

water or hydrocarbon.

2. It has been found that gasoline or naphtha sample collection in clear bottles,

which are left exposed to sunlight (or ultraviolet lighting) either direct or

indirect, and whether or not the sample has been treated with oxidation

inhibitors, will result in a severe loss of octane rating within a very short time.

Every effort must therefore be made to see that only the brown or amber

sample bottles are used for daily samples and more important that all samples

shipped to UOP for analysis are taken in amber bottles, are kept in a cool dark

place until packaged for shipment, and are shipped as soon as possible after

sampling.

3. When shipping samples, mail or phone shipping information (air waybill, flight

number, bill of lading, etc.) to UOP.

4. Send a copy of the request for analysis with the samples; send the original to: UOP Technical Service Department FCC Group 25 E. Algonquin Road Des Plaines, IL 60017 USA

157048 Analytical Methods

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5. Send samples to: UOP LLC Shipping and Receiving 50 E. Algonquin Road Des Plaines, IL 60017 USA

6. For larger “Rush” samples being sent to UOP by air, indicate the shipping

instructions as: SHIP TO: UOP LLC Chicago, Illinois 60017 USA HOLD AT: O Hare Airport CALL: (847) 391-3043 ON ARRIVAL

7. All samples shipped from outside the United States require additional

paperwork to comply with the U.S. Environmental Protection Agency’s Toxic

Substances Control Act (TSCA). The following are some of the guidelines for

importing samples into the United States. Always contact your customer

service or technical service representative for assistance before

shipping any samples to ensure that all regulations are followed.

The use of a freight forwarder (e.g. Burlington Air Express or Emery

Worldwide) is preferred for all imported samples.

Overnight couriers (e.g. DHL, Federal Express or UPS) may be used

only if the written TSCA certification – authorized, signed and dated by

UOP is obtained prior to shipment and physically included with the

documentation in the shipped package.

All samples should be routed through Chicago’s O’hare International

Airport

All imports must have the following documentation: Bill of Lading (also known as a Master Airwaybill) which includes

vessel/flight information. The Bill of Lading must state: "Customs clearance by Circle International". The Bill of Lading description field must begin with the words “TSCA Certified Chemical Sample.”

Pro forma invoice (Attachment 1a and 1b: a blank form and example). TSCA Certification (Attachment 2). Analytical Requisition Form (Attachment 3) Material Safety Data Sheet (MSDS) if the sample material is regulated as

hazardous by IATA, IMO or DOT.

157048 Analytical Methods

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The documentation on the above listed items must contain the

following information: On the Proforma Invoice: Shipper’s name, address, contact name, phone number and fax number. Importer’s name, address, contact name, phone number and fax number (this

must include the UOP contact person within the U.S.). UOP has provided this information except for Contact Person

Consignee/Delivery name, address, contact name, phone number and fax number (this must include the actual delivery location). UOP has provided this information.

Approximate market value (for Customs purposes), for each item, in U.S. Dollars.

Sample descriptions in English. Packing details – the number and types of containers. Net weights and Gross weights for each item, in kilograms. Country of origin. This is the country where the sample was taken.

On the TSCA Certification Form: Sample description in English, UOP has provided this information. Date the sample is to be shipped, in English.

On the International Analytical Requisition Form: Shipper’s name, address, contact name, phone number and fax number. Sample shipping information: Carrier and flight information, phone number of

the carrier, airway bill no. Fill in all pertinent sample and analytical request information as required.

All samples must be prepared according to the hazardous materials shipping

regulations of the International Air Transportation Association (IATA), if

shipped by air, or International Maritime Organization (IMO) if shipped by

sea.

Prior to shipping, the UOP Tech Service Sample Coordinator must be

notified of all imports before their arrival in the United States. Please fax a

copy of the Pro Forma Invoice, the Bill of Lading, TSCA Certificate, and

the Analytical Requisition Form to the UOP Technical Service Sample

Coordinator at 847-391-2253. UOP will then ensure proper Customs and

TSCA clearance.

Failure to send samples with the proper documentation and information will result in

a delay of Customs clearance or refusal of the sample.

157048 Analytical Methods

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Attachment 1a Proforma Invoice International Shipper/Exporter (Name & Address) Invoice No: Invoice Date: Terms: Pro-Forma Invoice Reference No:

DESCRIPTION AMOUNT

* * * NO CHARGE INVOICE * * * QUANTITY: DESCRIPTION OF SAMPLE(S): PACKED IN BOX(ES) GROSS WEIGHT: KGS. COUNTRY OF ORIGIN (where sample was taken) __________________________ MARKS: AS ADDRESSED IMPORTER OF RECORD CONSIGNEE / DELIVERY ADDRESS: UOP LLC UOP LLC 25 EAST ALGONQUIN RD. SAMPLE RECEIVING DES PLAINES, IL 60017 50 EAST ALGONQUIN RD. DES PLAINES, ILLINOIS 60017-5016 ATTN: ATTN: UOP Tech Service Sample Coordinator UOP Contact Name

Refinery Representative Signature Refinery Representative Name: please print

I HEREBY CERTIFY THAT THIS INVOICE IS TRUE AND CORRECT.

US DOLLARS $ MARKET VALUE --DECLARED FOR CUSTOMS CLEARANCE PURPOSES ONLY

ORIGINAL INVOICE

Contact Name: Contact Phone No. Fax No.

157048 Analytical Methods

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Attachment 1b

Example Proforma Invoice International Shipper/Exporter (Name & Address) Invoice No: Invoice Date: Terms: Pro-Forma Invoice Reference No:

DESCRIPTION AMOUNT

* * NO CHARGE INVOICE * * * QUANTITY: Three 1 liter catalyst samples DESCRIPTION OF SAMPLE(S): R-134 CCR Platforming Catalyst Two regenerated samples and one spent sample PACKED IN 1 BOX(ES) GROSS WEIGHT: 3.5 KGS. COUNTRY OF ORIGIN (where sample was taken) Refining Country MARKS: AS ADDRESSED IMPORTER OF RECORD CONSIGNEE / DELIVERY ADDRESS: UOP LLC UOP LLC 25 EAST ALGONQUIN RD. SAMPLE RECEIVING DES PLAINES, IL 60017 50 EAST ALGONQUIN RD. DES PLAINES, ILLINOIS 60017-5016 ATTN: Robert S. UOP ATTN: UOP Tech Service Sample Coordinator UOP Contact Name

Joe R. Engineer Joseph R. Engineer Refinery Representative Signature Refinery Representative Name: please print

I HEREBY CERTIFY THAT THIS INVOICE IS TRUE AND CORRECT.

US DOLLARS $ MARKET VALUE --DECLARED FOR CUSTOMS CLEARANCE PURPOSES ONLY

ORIGINAL INVOICE

Mountain View Refining 1000 Mountain View Dr. Boulder City Refining Country Contact Name: Joe R. Engineer Contact Phone No. (12) 3 456 -7890 Fax No. (12) 3-098-7654

157048 Analytical Methods

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Attachment 2a

TSCA Certification Form

To: Area Director of Customs

Date:

Description of Sample: Only one of the following should be selected:

( X ) TSCA Positive Certification

I certify that all chemical substances in this shipment comply with all applicable rules or orders under TSCA and that I am not offering a chemical substance for entry in violation of TSCA or any applicable rule or order under TSCA.

OR ( ) TSCA Negative Certification I certify that all chemicals in this shipment are not subject to TSCA Signature (Authorized UOP LLC employee)

Printed Name (Authorized UOP LLC employee)

157048 Analytical Methods

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Attachment 2b

TSCA Certification Form

Example Form

To: Area Director of Customs

Date: August 23, 1999

Description of Sample: R-134 CCR Platforming Catalyst: Spent Only one of the following should be selected:

( X ) TSCA Positive Certification

I certify that all chemical substances in this shipment comply with all applicable rules or orders under TSCA and that I am not offering a chemical substance for entry in violation of TSCA or any applicable rule or order under TSCA.

OR ( ) TSCA Negative Certification I certify that all chemicals in this shipment are not subject to TSCA Signature (Authorized UOP LLC employee)

Angelo P. Furfaro

Printed Name (Authorized UOP LLC employee)

157048 Analytical Methods

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Attachment 3

International Analytical Requisition Form - UOP Technical Service

TO: UOP Technical Service Sample Coordinator Phone 847-391-2620 FAX: 847-

391-2253 UOP Technical Service Contact Phone 847-391- Fax 847-391-2253 Customer: Refinery Address Contact Name Phone Fax

Liquid & Gas Sample(s) Check if Rush MSDS is or Description Analysis Required: Included Standard

Catalyst & Adsorbent Sample(s): Process or unit: Sample Location: Check if Rush MSDS is or Catalyst Type Regenerated or Coked Analysis Required Included Standard Billing Information: Address: Attention: Sample Shipping Information: Shipped Via: Phone Number of Carrier:

Airwaybill No.:

157048 Analytical Methods

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Minimum Sample Size Analysis Minimum (cm3) Heavy Oil (Clarified Oil, Slurry, Raw Oil, Heavy and Light Cycle Oil) API 100 Distillation 250 Viscosity 150 Vacuum Distillation 300 Conradson Carbon 150 Ash (sample to be taken and shipped in a wide mouth sample container) 300 Sediment and Water 150 Sulfur 20 Nitrogen 15 Metals 100 Pour Point 200 Color 50 Gasoline, LPG API 100 Distillation 210 Hydrocarbon Types by GC 150 C5- by GLC 50 RVP 1000 Mercaptan Sulfur 100 Total Sulfur 100 Octane Research 1000 Motor for each Leaded or Clear type Catalyst 1000 NOTE: Individual samples can be taken from one large sample of each product, usually about 1-2 gallons (3.5-7.0 liters).

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TYPICAL TEST SCHEDULE

STREAM AND TEST TEST NUMBER FREQUENCY Normal Startup Raw Oil Charge Gravity D-1298 or D-5002 or D-4052 1/D 3/D Viscosity D-445 1/W 3/W Vacuum Distillation D-1160 1/D 1/D Conradson Carbon Residue D-189 or D4530 1/D 1/D BS & W D-4007 1/W 1/W Sulfur UOP 864 or D-1552 or D-2622 1/D 1/D Total Nitrogen UOP 384 or D-4629 1/W 1/W Metals Content by Wet Ash UOP 389 or D-5708 1/W 1/D (May be sent to Outside Lab) Pour Point D-97 1/W 1/W Basic Nitrogen UOP 269 Occas Occas Heptane Insolubles UOP 614 Occas Occas UOP K UOP 375 1/D 1/D Circulating Main Column Bottoms Gravity D-1298 or D-5002 or D-4052 Occas 1/D BS & W D-4007 Occas Control Ash D-482 Occas 1/D Main Column Bottoms Clarified Oil Product Gravity D-1298 or D-5002 or D-4052 3/D 3/D Viscosity D-445 1/W 1/W Vacuum Distillation D-1160 1/D 1/D BS & W D-4007 1/D Control Sulfur UOP 864 or D-1552 1/W 1/D Ash D-482 1/W 1/D

157048 Analytical Methods

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STREAM AND TEST TEST NUMBER FREQUENCY Normal Startup Heavy Cycle Oil Product Gravity D-1298 or D-5002 or D-4052 1/D 3/D Distillation D-86 1/D 3/D Pour Point D-97 1/D 1/D Flash Point D-93 1/D 1/D Viscosity D-445 1/D 1/W Sulfur UOP 864 1/D 1/D Cetane Index D-976 1/D 1/D Light Cycle Oil Product Gravity D-1298 or D-4052 1/D 3/D Distillation D-86 1/D 3/D Pour Point D-97 1/D 1/D Flash Point D-93 1/D 1/D Viscosity D-445 1/D 1/W Sulfur UOP 864 1/D 1/D Cetane Index D-976 1/D 1/D Stripped Heavy Naphtha Product Gravity D-1298 or D-4052 1/D 3/D Distillation D-86 1/D 3/D H2S and RSH UOP 163 1/W 1/W Sulfur UOP 864 1/D 1/D Composition (PONA) UOP 777 3/W 1/D Research Octane D-2699 1/D 1/D Motor Octane D-2700 1/D 1/D RVP D-323 1/D 1/D Blended Fuel Oil Product Gravity D-1298 or D-4052 1/D 3/D Distillation D-86 1/D 3/D Viscosity D-445 1/W 1/W Sulfur UOP 864 or D-1552 1/D 1/D Pour Point D-97 1/D 1/D Flash Point D-93 1/D 1/D Main Column Receiver Gas H2S UOP 212 Occas 1/D Composition UOP 539 Occas 1/D

157048 Analytical Methods

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STREAM AND TEST TEST NUMBER FREQUENCY Normal Startup Main Column Receiver Liquid Gravity D-1298 or D-4052 Occas Occas Distillation D-86 Occas Occas GC (C4 and lighter) UOP 725 Occas Occas H2S and RSH UOP 163 Occas Occas Regenerator Flue Gas Composition (Orsat or GC) UOP 172 or UOP 539 1/D 3/D SOx EPA #6 Occas Occas NOx EPA #7 Occas Occas Particulate EPA #5 Occas Occas Spent Catalyst Percent Carbon UOP 703 1/W

Regenerated Catalyst Particle Size Distribution* UOP 856 1/W 2/W Surface Area* UOP 874 1/W 2/W Pore Volume* UOP 874 1/W 2/W Activity* D-3907 1/W 2/W Metals by ICP* UOP 546 1/W 2/W Percent Carbon* UOP 703 1/D Control *Normally performed by catalyst vendor’s laboratory. Flue Gas to Electrostatic Precipitator Isokinetic Particle Determin. EPA #5 Occas Occas Flue Gas from Electrostatic Precipitator Isokinetic Particle Determin. EPA #5 Occas Occas

157048 Analytical Methods

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STREAM AND TEST TEST NUMBER FREQUENCY Normal Startup Main Column Receiver Water Iron, Copper UOP 314 Occas Occas Phenols UOP 262 Occas Occas Cyanides UOP 682 1/M Occas Sulfides UOP 683 1/M Occas Ammonia UOP 740 Occas Occas Total Oils D-3921 Occas Occas pH D-1293 1/D 3/D Total Dissolved Solids D-1126 1/W Occas Silica D-859 1/M Occas BFW and Continuous Blowdown Sodium D-4192 1/W 1/W Total Alkalinity D-1067 1/W 1/W M Alkalinity D-1067 1/W 1/W P Alkalinity D-1067 1/W 1/W Chloride (as Cl-) D-512 1/W 1/W Silica (as SiO2) D-859 1/W 1/W Total Dissolved Solids STD Method 2540C 1/W 1/W Total Suspended Solids STD Method 2540D 1/W 1/W pH D-1293 1/W 1/W Specific Conductance D-1125 1/W 1/W Phosphates D-4327 1/W 1/W Oil D-3921 1/W 1/W Hydrazine D-1385 1/W 1/W Saturated Steam from Catalyst Cooler, Flue Gas Cooler, and Main Column Bottoms Steam Generator Steam Drums Impurities D-2186-C Occas Occas Silica D-859 Occas Occas Sodium D-1428 Occas Occas Lean Gas Product H2S UOP 212 1/D 3/D Composition UOP 539 1/D 3/D Debutanizer Net Overhead Liquid H2S & Mercaptan Sulfur UOP 163 1/D 3/D Composition UOP 539 1/D 3/D Total Sulfur UOP 923 1/D 3/D

157048 Analytical Methods

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STREAM AND TEST TEST NUMBER FREQUENCY Normal Startup Debutanizer Bottoms Product Gravity D-1298 or D-4052 1/D 3/D Distillation D-86 1/D 3/D H2S & Mercaptan Sulfur UOP 163 1/D 3/D RVP D-323 1/D 3/D Research Octane D-2699 1/D 3/D Motor Octane D-2700 1/D 3/D C4 and lighter UOP 725 1/D 3/D Sulfur UOP 864 or UOP 836 1/D 3/D Naphtha Splitter Bottoms Gravity D-1298 or D-4052 1/D 3/D Distillation D-86 1/D 3/D Research Octane D-2699 1/D 3/D Motor Octane D-2700 1/D 3/D Sulfur UOP 864 or UOP 836 1/D 3/D Naphtha Splitter Side Cut Product Gravity D-1298 or D-4052 1/D 3/D Distillation D-86 1/D 3/D Research Octane D-2699 1/D 3/D Motor Octane D-2700 1/D 3/D Sulfur UOP 864 or UOP 836 1/D 3/D Naphtha Splitter Overhead Product Gravity D-1298 or D-4052 1/D 3/D Distillation D-86 1/D 3/D RVP D-323 1/D 3/D Research Octane D-2699 1/D 3/D Motor Octane D-2700 1/D 3/D C4 and lighter UOP 725 1/D 3/D Sulfur UOP 864 or UOP 836 1/D 3/D Depentanizer Overhead Product H2S & Mercaptan Sulfur UOP 163 1/D 3/D Composition UOP 539 1/D 3/D

157048 Analytical Methods

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STREAM AND TEST TEST NUMBER FREQUENCY Normal Startup Depentanizer Bottoms Product Gravity D-1298 or D-4052 1/D 3/D Distillation D-86 1/D 3/D H2S & Mercaptan Sulfur UOP 163 1/D 3/D RVP D-323 1/D 3/D Research Octane D-2699 1/D 3/D Motor Octane D-2700 1/D 3/D C4 and lighter UOP 725 1/D 3/D Sulfur UOP 864 or UOP 836 1/D 3/D High Pressure Receiver Water Iron, Copper UOP 314 Occas Occas Phenols UOP 262 Occas Occas Cyanides UOP 682 1/M Occas Sulfides UOP 683 1/M Occas Ammonia UOP 740 Occas Occas Total Oils D-3921 Occas Occas pH D-1293 1/D 3/D

LABORATORY TEST SCHEDULE FREQUENCY NOMENCLATURE

1/D One determination per day

3/D Three determinations per day

1/W One determination per week

3/W Three determinations per week

2/M Two determinations per month

N During normal operation

S During startup

Occas Determination is done only occasionally

Control Determination is done as frequently as necessary for plant control during startup

157048 Analytical Methods

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OUTLINE OF SELECTED ANALYTICAL METHODS

SUBJECT INDEX

Test Description Number

Activity Test for Catalyst D-3907

API Gravity D 1298

Apparent Bulk Density of Catalyst UOP 254

Ammonia in Refinery Water UOP 740

Ash from Petroleum Products D 482

Boilaway (weathering Test) UOP 155

Carbon on Catalyst UOP 703

Carbonyl Sulfide (COS) in Gases UOP 212

Catalyst Loading in Heavy Oil UOP 233

Color – ASTM D 1500

– Saybolt D 156

Conradson Carbon Residue D 189

Copper in Water UOP 314

Cyanide in Refinery Water UOP 682

Distillation – of Heavy Oil UOP 1

– of Petroleum D 86

– of Petroleum UOP 77

– of Petroleum UOP 79

(Fractionation)

– Vacuum UOP 76

– Vacuum D 1160

Doctor Test UOP 41

Flash Point, Closed Cup D 93

Flash Point, Open Cup D 92

Fractionation of Petroleum UOP 79

157048 Analytical Methods

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Test Description Number

Flue Gas Analysis, (GC) UOP 539

(Orsat) UOP 172

Particulates, SOx, NOx EPA #5,6,7

Gas Analysis – GC UOP 539

– GC UOP 709

- Pentenes and lighter in olefinic gasoline UOP 725

Gravity – API D 1298

Gum – Copper Dish UOP 11

– Existent (Steam Jet) UOP 277 Hydrogen Sulfide (H2S)

in Gas – Tutwiler UOP 9

– with Mercaptans UOP 212

Induction Period of Gasoline UOP 6

Iron in Water UOP 314

Isokinetic Particle Determination in Flue Gas D 3685

Kinematic Viscosity D 445

Loss of Ignition of Catalyst UOP 275

Mercaptan Sulfur – Gases UOP 212

– Liquid Hydrocarbons UOP 163

Metals – Trace, in Crackling Catalysts UOP 546

– Trace, in Oils UOP 389

– Trace, in Oils UOP 391

Nitrogen in Heavy Distillate UOP 384

Octane – Motor D 2700

– Research D 2699

Particle Size Distribution of Catalyst UOP 422

pH, Iron and Copper in Refinery Water UOP 314

157048 Analytical Methods

Page 20

Test Description Number

Phenols in Petroleum Products UOP 262

Pore Volume and Pore Diameter of Catalyst UOP 425

Pour Point of Petroleum Oils D 97

Reid Vapor Pressure D 323

Sampling of Petroleum UOP 516 or D 270

Sediment and Water in Oil D 4007

Sintering Index of Catalyst UOP 424

Sulfides in Refinery Waters UOP 683

Sulfur in Heavy Oils D 1552 Sulfur – Doctor Test (H2S and Mercaptans) UOP 41

– H2S in Gases (Tutwiler) UOP 9

– Mercaptan and H2S in Light Distillates UOP 163

– H2S, Mercaptans, and COS in Hydrocarbon Gases UOP 212

– in Heavy Distillates D 1552

– Total, in Light Distillates D 1266

Total Sulfur – Lamp D 1266

– Quartz Tube D 1552

Surface area, Pore Volume, and Pore Diameter of Catalyst UOP 425

UOP Characterization Factor – K UOP 375

Vacuum Distillation D-1160

Viscosity – Kinematic D 445

Water and Sediment in Oil D 4007

Weathering Test (Boilaway) UOP 155

157048 Analytical Methods

Page 21

OUTLINE OF SELECTED

ANALYTICAL TEST METHODS NUMERICAL INDEX

Test Number Description

UOP 1 Distillation Range of Heavy Oils

UOP 6 Induction Period of Gasoline UOP 9 H2S in Gases (Tutwiler)

UOP 11 Gum, Copper Dish UOP 41 Doctor Test (H2S and Mercaptans)

UOP 76 Vacuum Distillation

UOP 77 Distillation of Petroleum

UOP 79 Distillation of Petroleum

D 86 Distillation of Petroleum

D 92 Flash Point, Open Cup

D 93 Flash Point, Closed Cup

D 97 Pour Point of Petroleum Oil

UOP 155 Weathering Test (Boilaway)

D 156 Saybolt Color UOP 163 Mercaptans and H2S in Liquid Hydrocarbons

UOP 172 Flue Gas Analysis (Orsat)

D 189 Conradson Carbon Residue UOP 212 H2S, Mercaptans and COS in Hydrocarbon Gases

UOP 233 Catalyst Loading Test

UOP 251 Activity Test for Catalyst

UOP 254 Apparent Bulk Density of Catalyst

UOP 262 Phenols in Petroleum Products

D 270 Sampling Petroleum Products

157048 Analytical Methods

Page 22

Test Number Description

UOP 275 Loss of Ignition of Catalyst

UOP 277 Existent Gum (Steam Jet)

D 287 API Gravity

UOP 314 pH, Iron, and Copper in Refinery Water

D 323 Reid Vapor Pressure

UOP 375 UOP Characterization Factor

UOP 384 Nitrogen in Heavy Distillate

UOP 389 Trace Metals in Oils

UOP 391 Trace Metals in Oils

UOP 422 Particle Size Distribution in Catalyst

UOP 424 Sintering Index of Equilibrium Catalyst

UOP 425 Surface Area, Pore Volume, and Pore Diameter of Catalyst

D 445 Kinematic Viscosity of Oils

D 482 Ash from Petroleum Products UOP 516 Sampling of Gasoline, Distillates and C3-C4 Fractions

UOP 539 Gas Analysis (GC)

UOP 546 Metals in Cracking Catalyst

UOP 682 Cyanide in Refinery Water

UOP 683 Sulfide in Refinery Water

UOP 703 Carbon on Catalyst

UOP 709 Gas Analysis (GC)

UOP 725 Pentenes and lighter in olefinic gasoline

UOP 740 Ammonia in Water

D 1160 Vacuum Distillation

D 1266 Total Sulfur in Petroleum Products (Lamp)

D 1500 ASTM Color (formerly ASTM Union)

D 1552 Sulfur in Heavy Oils

D 2699 Octane Rating, Research

D 2700 Octane Rating, Motor

D 3685 Isokinetic Particle Determination in Flue Gases

D 4007 Water and Sediment in Oil

157048 Analytical Methods

Page 23

DISTILLATION RANGE OF HEAVY PETROLEUM OILS

UOP METHOD 1

Scope

This method is for determining the distillation range of heavy petroleum oils. It is

applicable to petroleum products whose boiling range extends above that of

kerosene; e.g., crude oils, gas oils and fuel oils. The method differs from ASTM

Method D 86 in that a 200 ml flask is used and the distillation is continued past the

thermal decomposition point to a dry or coke residue. The test is particularly useful

in estimating gasoline, kerosene and/or distillate contents and the coking

characteristics of these oils.

Outline of Method

A 100-ml sample is distilled under prescribed conditions. Systematic observations

of thermometer readings and volumes of condensate are made, and the weight of

coke or residue is determined. The results of the test are calculated and reported

from these data. No corrections are applied to the data.

Precautions

Oils containing more than traces of water are very difficult to distill. However, if the

heat is applied to the flask correctly, water can be distilled from the oil without

“bumping.” When water is present, heat the flask evenly over its top and bottom

surfaces; do not concentrate heat on the bottom of the flask. Keep the top of the

flask hot enough to prevent water vapor from condensing there and allow time for

the temperature to drop to ambient before continuing the distillation. Do not include

water in the percentages reported for the temperatures named. The IBP obtained in

this manner on samples containing water may, or may not, be a true IBP owing to

the possibility of superheating the vapors when the flame is applied to the top

surface of the flask. Note this on the distillation sheet.

157048 Analytical Methods

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Decomposition or cracking usually occurs when oils containing material boiling

above 625°F (329°C) are distilled at atmospheric pressure. When this decomposi-

tion takes place it will be impossible to maintain a uniform distillation rate without

causing a gradual drop in temperature. Therefore, disregard the 4-5 ml per minute

rate from the temperature at which cracking begins and continue the distillation at

such a rate that there is a steady rise in temperature.

Precision

See ASTM Method 86 for precision statement.

157048 Analytical Methods

Page 25

INDUCTION PERIOD OF GASOLINES BY THE UOP OXYGEN BOMB

UOP METHOD 6

Scope

This method is for determining the induction period of gasolines. It is useful in

predicting the storage stability, in lieu of the more valuable storage tests and

accelerated gum determination. It is a valuable control test and an excellent

measure of inhibitor effectiveness.

This method does not give the same numerical induction periods as ASTM Method

D 525 because of differences in construction of the bombs and bath. However, the

results are parallel and this method is preferred for its speed and convenience.

Outline of Method

The sample is placed in a bomb at 60-70°F (15-20°C) and subjected to oxygen at

100 psig. The bomb is heated rapidly to 211.6°F (99.7°C). The pressure is recorded

continuously until the break point has been passed. The induction period is then

determined from the chart record.

Precautions

The bombs and bottles must be scrupulously clean to obtain reproducible results.

Precision

Repeatability should be considered suspect it results differ from the mean by more

than 5%.

157048 Analytical Methods

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HYDROGEN SULFIDE IN GASES BY THE TUTWILER METHOD

UOP METHOD 9

Scope

This method is for the determination of hydrogen sulfide in gas mixtures. Mercaptan

sulfur, if present, is determined as hydrogen sulfide. The accuracy of this method is not sufficient to obtain reliable results below 5 grains of H2S per 100 cu. ft.

Outline of Method

The sample is admitted to a Tutwiler buret, displacing a starch solution. A known

volume of starch solution is retained in the buret and a standard iodine solution is

admitted and measured from the buret until the starch solution assumes a taint

permanent blue color. The concentration of hydrogen sulfide is calculated from the

volume of iodine used and its known normality.

Precautions

It is recommended that gases to be analyzed for hydrogen sulfide content be

sampled directly from the plant stream into the buret. If the sample is to be

transported, it should be done in a dry glass or stainless steel container.

Do not confuse the blue color of the iodine-starch complex with the opalescent

milky appearance resulting from the separation of free sulfur.

157048 Analytical Methods

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Precision

Duplicate results by the same operator should be considered suspect it they differ

by more than the following amounts, depending on the iodine solution used:

Iodine Solution A: 10 grains*

Iodine Solution B: 20 grains*

Iodine Solution C: 5 grains*

*To convert to weight ppm:

grain/100 SCF 542.1

MW gas = ppm (wt)

157048 Analytical Methods

Page 28

COPPER DISH GUM CONTENT OF GASOLINE

UOP METHOD 11

Scope

This is a method for determining the weight of the residue obtained when a gasoline

or naphtha is evaporated in a copper dish. Considered in connection with the

induction period, it is an indication of the stability of the gasoline in storage.

Outline of Method

The sample is evaporated in a clean, copper dish under controlled conditions and

the weight of the residue is determined.

Report

Report the average weight of the residue as milligrams of copper dish gum per 100

ml of gasoline.

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Page 29

DOCTOR TEST FOR PETROLEUM DISTILLATES

UOP METHOD 41

Scope

This is a qualitative test for the presence of hydrogen sulfide and mercaptans in

gasoline, jet fuel, kerosene and similar petroleum products.

Outline of Method

The sample is shaken with a sodium plumbite solution in a test tube. If hydrogen

sulfide is present the following reaction occurs:

Na2PbO2 + H2S PbS + 2NaOH

The lead sulfide is black and readily visible. If this reaction does not appear, sulfur

is added to the test tube and the mixture shaken again. If mercaptans are present,

on shaking they undergo a series of reactions, coloring the hydrocarbon layer first

orange, then red and brown, and finally a black precipitate of lead sulfide appears.

The overall reactions may be written:

Na2PbO2 + 2RSH (RS) 2Pb + 2NaOH

(RS) 2Pb + S RSSR + PbS

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Report

(a) Hydrogen sulfide present.

If hydrogen sulfide is detected, report it.

(b) Sample sour.

If a brown or black precipitate forms, the sample contains a relatively high

concentration of mercaptans and is reported sour.

(c) Sample borderline or sweet.

If the mercaptan content of the sample is low, observe the sulfur layer and

judge as follows:

Discoloration of Floating Sulfur Report

Definitely discolored “sour ”

Barely discolored borderline

Not discolored “sweet”

Precaution

Use only sufficient sulfur to form a thin film floating on the interface between the

sample and the doctor solution.

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HIGH VACUUM DISTILLATION OF

HIGH BOILING RANGE PETROLEUM PRODUCTS

UOP METHOD 76

Scope

The distillation apparatus described in this method was devised to provide a means

of determining the boiling range of heavy oils. It is intended for the determination, at

reduced pressures, of the boiling temperature ranges of petroleum products which

have an initial boiling point in excess of 460°F (238°C) and which decompose when

distilled at atmospheric pressure. The method is applicable to petroleum products

which can be partially or completely vaporized at a maximum liquid temperature of

750°F (399°C), at a pressure in the range of 0.2-0.3 mm of mercury absolute, and

which may be condensed as liquids at the pressure of the test.

Outline of Method

The sample is distilled at a pressure of 0.2-0.3 mm of mercury absolute under

conditions which provide approximately one theoretical plate fractionation. Data

obtained, converted to 760 mm mercury, allow the preparation of a distillation curve

relating volume distilled and boiling point.

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Page 32

CRUDE OIL EVALUATION BY HEMPEL DISTILLATION

UOP METHOD 77

Scope

This method is for determining the gasoline, naphtha and kerosene content of a

crude oil as a guide in operating crude oil topping facilities.

Outline of Method

The method employs a Hempel column to secure the desired precision in a manner

which simulates the results obtained from a commercial distillation. Directions are

given to obtain end point gasoline, or naphtha, and kerosene of either specified end

point or API gravity.

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Page 33

FRACTIONATION OF PETROLEUM DISTILLATES AND CRUDE OILS

UOP METHOD 79

Scope

This method describes laboratory fractionation equipment and procedures used in

obtaining true boiling point data for petroleum distillates and crude oils. Procedures

are also given for obtaining specific boiling range distillates for further analysis.

Outline of Method

A known volume of a petroleum distillate or a crude oil sample is fractionated in a

high efficiency laboratory column. The distillation may consist of: (1) the precision

fractionation of normally liquid hydrocarbons to collect fractions for further

identification: (2) the quantitative separation of normally gaseous hydrocarbons, such as C3 and/or C4 hydrocarbons from C5 and heavier gasoline or crude oil

fractions, and/or (3) the determination of true boiling point (TBP) distillation curves

at atmospheric and reduced pressures.

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DISTILLATION OF PETROLEUM PRODUCTS

ASTM D 86

Scope

This method covers the distillation of motor gasolines, aviation gasolines, aviation

turbine fuels, special boiling point spirits, naphthas, white spirit, kerosenes, gas oils,

distillate fuel oils, and similar petroleum products. A 100 ml sample is distilled under

prescribed conditions and systematic observations of thermometer readings and

volumes of condensate are made.

Definitions

1. Initial boiling point (lBP) – thermometer reading at instant first drop of

condensate falls from the lower end of the condenser tube.

2. End point (EP) – maximum thermometer reading obtained during the test.

3. Dry point – thermometer reading observed at instant last drop of liquid

evaporates from lowest point in flask. Any drops or film of liquid on side of flask

or on thermometer are disregarded.

4 Decomposition point – thermometer reading that coincides with first

indication of thermal decomposition of the liquid in the flask, as evidenced by

fumes and erratic thermometer readings which usually show a decided

decrease after any attempt to adjust the heat.

5. Percent recovery – maximum percent recovered.

6. Percent total recovery – combined percent recovery and residue in the flask.

7. Percent loss – 100 minus percent total recovery.

8. Percent residue – percent total recovery minus percent recovery.

9. Percent evaporated – sum of percent recovered and percent loss.

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FLASH AND FIRE POINTS BY CLEVELAND OPEN CUP

ASTM D 92

Scope

This method covers determination of the flash and fire points of all petroleum

products except fuel oils and those having an open cup flash below 175°F (79°C).

Summary of Method

The test cup is filled to a specified level with the sample. The temperature of the

sample is increased rapidly at first and then at a slow constant rate as the flash

point is approached. At specified intervals a small test flame is passed across the

cup. The lowest temperature at which application of the test flame causes the

vapors above the surface of the liquid to ignite is taken as the flash point. To

determine the fire point, the test is continued until the application of the test flame

causes the oil to ignite and burn for at least 5 sec.

Precision

The following data should be used in judging the acceptability of results (95 percent

confidence).

Duplicate results by the same operator should be considered suspect if they differ

by more than the following amounts:

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Repeatability

Flash point 15°F (8°C)

Fire point 15°F (8°C)

The results submitted by each of two laboratories should be considered suspect if

the results differ by more than the following amounts:

Reproducibility

Flash point 30°F (17°C)

Fire point 25°F (14°C)

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FLASH POINT BY PENSKY-MARTENS CLOSED TESTER

ASTM D 93

Scope

These methods cover the determination of the flash point by Pensky-Martens

closed-cup tester of fuel oils, lube oils, suspensions of solids, liquids that tend to

form a surface film under test conditions, and other liquids.

Summary of Method

The sample is heated at a slow, constant rate with continual stirring. A small flame

is directed into the cup at regular intervals with simultaneous interruption of stirring.

The flash point is the lowest temperature at which application of the test flame

causes the vapor above the sample to ignite.

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WATER AND SEDIMENT IN CRUDE OILS

ASTM D 4007

Scope

This standard defines a primary centrifuge method and two alternatives for

determining the amount of water and sediment in crude oil. It further specifies a

base method to be used when centrifuging is not suitable or when the accuracy of a

centrifuge method is to be confirmed.

Summary of Method

The three centrifuge methods involve selection of number of factors such as type of

solvent, type and amount of demulsifier, temperature of the sample during testing,

and the duration of centrifuging. With many types of oil, the results are not

dependent on the selected factors. Those factors which are not the most convenient

can be used with good results.

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POUR POINT OF PETROLEUM OILS

ASTM D 97

Scope

The test for pour point is intended for use on any petroleum oil.

Summary of Method

After preliminary heating, the sample is cooled at a specified rate and examined at

intervals of 5°F (or 3°C) for flow characteristics. The lowest temperature at which

movement of the oil is observed is recorded as the pour point.

Definition

Pour point – the lowest temperature, expressed as a multiple of 5°F (or 3°C) at

which the oil is observed to flow when cooled and examined under prescribed

conditions.

Calculation and Report

Add 5°F (or 3°C) to the temperature recorded and report the result as the Pour

Point, ASTM D 97.

Precision

Repeatability – Duplicate results by the same operator should be considered

suspect if they differ by more than 5°F (or 3°C).

Reproducibility – The results submitted by each of two laboratories should be

considered suspect only if the two results differ by more than 10°F (or 6°C).

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WEATHERING TEST FOR GASES

UOP METHOD 155

Scope

This is a rapid procedure for the estimation of iso- and normal butane in liquefied

butane samples. Propane does not interfere with the analysis and is determined if

present in concentrations not exceeding 25%. Pentane and olefins will interfere in

the analysis, if present. The test is sufficiently accurate for routine control of plant

operations, the apparatus is inexpensive and the technique involved requires little

experience.

Outline of Method

A 94 ml sample of liquefied butanes is drawn into a precooled centrifuge tube. It is

then weathered in air to the 90 ml mark. The centrifuge tube and contents are then

transferred to a water bath maintained at 60-70°F (15-20°C). Temperature readings

are recorded when the liquid level has dropped to the 50- and 15-ml graduation

marks of the centrifuge tube. From these temperatures and weathering test curve,

the approximate concentrations of propane, isobutane and normal butane are

determined.

157048 Analytical Methods

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Precision

Duplicate results by the same operator should be considered suspect if they differ

by more than the following amounts:

Hydrocarbons Maximum Deviation, %

Propane + 2.5

i-butane + 1.5

n-butane + 1.0

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Page 42

SAYBOLT COLOR OF PETROLEUM PRODUCTS

(SAYBOLT CHROMOMETER METHOD)

ASTM D 156

Scope

This method covers the determination of the color of refined oils such as undyed

motor and aviation gasoline, jet fuels, naphthas and kerosene. A sample of the

liquid is added to a tubular column through which a light source is seen. The color is

compared with specified glass standards. The height of the liquid sample is

decreased by levels until the color of the sample is lighter than that of the standard.

The color number above this level is reported. The range of number is +30 (lightest)

to -16 (darkest color). Color standards correspond to sample depth and color

number.

Precision

Duplicate results by the same operator should be considered suspect if they differ

by more than 1 color unit.

Results submitted by one laboratory should be considered suspect if they differ

from that of another laboratory by 2 color units.

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Page 43

HYDROGEN SULFIDE AND MERCAPTAN SULFUR IN LIQUID

HYDROCARBONS BY POTENTIOMETRIC TITRATION

UOP METHOD 163

Scope

This method is for the determination of hydrogen sulfide and mercaptan sulfur in

liquid hydrocarbons, such as gasoline, naphtha, light cycle oils and similar

distillates. It is applicable to samples containing as little as 1.0 ppm mercaptan

sulfur and 1.0 ppm hydrogen sulfide.

Attention is called to the fact that an earlier version of this method (163-62) included

determination of free sulfur. This has been deleted from the present method.

Outline of Method

The liquid hydrocarbon sample is titrated potentiometrically in ammoniacal isopropyl

alcohol using alcoholic silver nitrate as titrant. A glass reference electrode and a

silver-silver sulfide indicating electrode system are used. Estimation of the hydrogen

sulfide and mercaptan sulfur content is made from the titration curves. Either an

automatic recording titrator or a manually-operated instrument may be used.

Free sulfur is a possible interference and instructions are given for analysis of

samples containing it.

Calculations

Hydrogen sulfide, as S, wt -ppm = 16 103 A N

SV

Mercap tan, as S, wt - ppm = 32 103 (B - A) N

SV

157048 Analytical Methods

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where:

A = volume of silver nitrate solution used to reach the sulfide ion end point,

ml

B = volume of silver nitrate solution used to reach the mercaptide ion end

point, ml

N = normality of alcoholic silver nitrate solution

S = specific gravity of sample at the temperature at which the sample is

pipetted

V = volume of sample, ml

Precautions

Allow enough time for the titration cell to reach equilibrium before recording the

volume of silver nitrate solution and the emf when the manual titration is made.

When using a recording titrator, add the titrant at a rate of 3.0 ml per minute in the

vicinity of the end point, otherwise the end point will be overshot.

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VOLATILE NITROGEN BASES AND AMMONIA IN

CATALYSTS, DEPOSITS, AND WATER SOLUTIONS

UOP METHOD 169

Scope

This is a method for the determination of ammonia and steam-volatile nitrogen

bases in catalysts, deposits, and water solutions. The procedure does not

distinguish between ammonia and volatile nitrogen bases. Ammonia in the parts per

million range can be determined with this method by using 0.005 N sulfuric acid and

large samples.

Outline of Method

A known quantity of sample is introduced into a Kjeldahl flask, diluted with distilled

water, and made alkaline with 50% sodium hydroxide. The volatile nitrogen bases

are distilled in a Kjeldahl apparatus and the condensate collected in a boric acid

adsorbing solution. This solution is then titrated with standardized sulfur acid using

methyl purple indicator.

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FLUE GAS ANALYSIS (ORSAT)

UOP METHOD 172

Scope

This method is for the quantitative determination of carbon dioxide, oxygen and

carbon monoxide in flue gases.

Outline of Method

Systematically, the gas sample is admitted into a series of pipets, each containing a

reagent for the removal of an individual component. After contact with each reagent,

the gas is returned to the buret. The difference in residual volume indicates the

amount of component absorbed. In this manner, percentages of carbon dioxide,

oxygen and carbon monoxide are determined.

Precision

Duplicate results by the same operator should be considered suspect if they differ

by more than the following amounts:

Carbon dioxide + 0.2%

Oxygen + 0.3%

Carbon monoxide + 0.3%

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CONRADSON CARBON RESIDUE OF PETROLEUM PRODUCTS

ASTM D 189

Scope

This method covers the determination of the amount of carbon residue left after

evaporation and pyrolysis of an oil, and is intended to provide some indication of

relative coke-forming propensities. The method is generally applicable to relatively

nonvolatile petroleum products which partially decompose on distillation at

atmospheric pressure. Petroleum products containing ash-forming constituents as

determined by ASTM Method D 482, Test for Ash from Petroleum Products, will

have an erroneously high carbon residue, depending upon the amount of ash

formed.

Summary of Method

A weighed quantity of sample is placed in a crucible and subjected to destructive

distillation. The residue undergoes cracking and coking reactions during a fixed

period of severe heating. At the end of the specified heating period, the test crucible

containing the carbonaceous residue is cooled in a desiccator and weighed. The

residue remaining is calculated as a percentage of the original sample, and

reported as Conradson carbon residue.

Calculation

Calculate the carbon residue of the sample or of the 10 percent distillation residue

as follows:

Carbon residue = (A 100)/W

where:

A = weight of carbon residue, g

W = weight of sample, g

157048 Analytical Methods

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Report

Report the value obtained as "Conradson carbon residue, percent" or as

"Conradson carbon residue on 10 percent distillation residue, percent," ASTM

D 189.

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HYDROGEN SULFIDE, MERCAPTAN SULFUR

AND CARBONYL SULFIDE IN HYDROCARBON

GASES BY POTENTIOMETRIC TITRATION

UOP METHOD 212

Scope

This method is for determining hydrogen sulfide, mercaptan sulfur and carbonyl

sulfide in gaseous hydrocarbons and in liquefied petroleum gas (LPG) of ordinary

properties. Also covered is the determination of mercaptan in non-ordinary LPG

which may contain a wide range of hydrocarbon types from ethane to such gasoline

boiling range hydrocarbons as pentane and hexane. The hydrogen sulfide

concentration range which can be determined is from 0.3 to several thousand

wt-ppm. The method is also applicable to LPG samples containing as little as 1.0

ppm mercaptan sulfur.

Outline of Method

The sample, taken either from a sample bomb or directly from a refinery stream, is

scrubbed first through a potassium hydroxide solution and then through a

monoethanolamine solution. A potentiometric titration of the absorbed hydrogen

sulfide and mercaptan sulfur follows. The monoethanolamine solution, which

contains the absorbed carbonyl sulfide, is titrated potentiometrically with alcoholic

silver nitrate in an acidic titration solvent. The concentration of each item sought is

estimated from the titration curve.

Precision

Samples containing hydrogen sulfide mercaptan and carbonyl sulfide sulfur:

An estimated standard deviation (esd) is not reported since insufficient data are

available at present to permit this calculation with at least 4 degrees of freedom.

157048 Analytical Methods

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Samples containing mercaptan sulfur only and appreciable concentrations or

pentane and higher boiling materials:

The estimated standard deviation based on indicated replicates is shown below.

Duplicate results by the same operator should not be considered suspect unless

they differ by more than the amounts shown in the "allowable difference" column

(95% probability).

Mercaptan esd, Allowable No. of Level, wt-ppm, difference, Type of Sample Pairs wt-ppm, S S wt-ppm, S LPG containing appreciable concentrations of pentane and higher 5 6.0 0.28 1.1 boiling materials

157048 Analytical Methods

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FLUID CRACKING CATALYST LOADING TEST

UOP METHOD 233

Scope

This method is used to determine the proportion of silica-alumina type catalyst in

recycle stock from a fluid catalytic cracking plant.

Outline of Method

In this procedure the oil-catalyst mixture is washed free of oil with cold benzene,

dried and weighed.

Note: Toluene may be substituted for benzene.

Precautions

Do not conduct the analysis near an open flame. It is preferably carried out under a

hood.

Be sure the crucible is dry before placing it in the oven. It is advisable to leave the

oven door ajar for 5-10 minutes immediately after introducing the crucible.

If the catalyst persists in adhering to the Erlenmeyer flask, dry and weigh the flask

and add the increase in weight to the catalyst weight in the crucible.

Precision

Duplicate determinations by the same operator should agree within 5%.

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ACTIVITY TEST FOR FLUID CRACKING CATALYST

UOP METHOD 251

Scope

This method is for evaluating the activity of fluid catalytic cracking catalysts relative

to a reference catalyst by measuring the conversion of a Mid-continent gas oil to

gas and gasoline. The procedure is applicable to both fresh and used catalyst.

Outline of Method

A standard gas oil charge stock is cracked over the test catalyst in a fixed-bed

operation under carefully controlled standard operating conditions. The conversion

to gasoline and gas is measured. The activity, expressed as a percentage, is the

ratio of the liquid hourly space velocity used with the test catalyst to the liquid hourly

space velocity required with a primary reference catalyst to give the same

conversion as that obtained with the test catalyst. The latter value is read from an

experimentally-obtained reference catalyst calibration curve showing conversion as

a function of space velocity.

Notes

1. Fresh and equilibrium synthetic catalysts are calcined prior to activity testing

for 2 hours at 1112°F +25°F (600°C) in a muffle furnace having a vent in the

door to permit slow circulation of air. The catalyst is loaded in 150-ml tall-form

porcelain crucibles (without covers) filled about one-half full. Fresh catalyst is

first dried at about 400°F (204°C) for 2 hours to remove moisture and avoid the

spattering of catalyst which otherwise may occur if placed directly in the muffle

furnace at 1112°F. Regenerated equilibrium catalysts have substantially all of

the carbonaceous deposit (except embedded carbon) removed in calcining.

For normal carbon deposits of 0.3 to 0.5 wt-% or less, the activity rating is not

157048 Analytical Methods

Page 53

affected by the carbon removal. Abnormal carbon deposits, up to 1 and 1.5 wt-

%, usually will reduce the weight activity by 1 to 2 numbers.

In calcining fresh or used natural catalysts, the temperature employed is that

used when regenerating the catalyst in commercial practice.

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Page 54

APPARENT BULK DENSITY OF FLUID CRACKING CATALYST

UOP METHOD 254

Scope

This is a procedure for determining the apparent bulk density (ABD) of loosely

packed fluid cracking catalyst.

Outline of Method

The sample is poured into a weighed, 25 ml cylinder under carefully prescribed

conditions. Excess catalyst is scraped off and the full cylinder is weighed. The

weight of catalyst, in grams, divided by the volume of the container, in milliliters, is

reported as the ABD of the sample.

Definition

Apparent bulk density is defined as weight per unit volume. It is an empirical value

for the particular type of solid particles to which the determination applies; in this case, fluid (powered) cracking catalyst in a size range of less than 200 m effective

diameter.

Calculations

Calculate the ABD as weight per unit volume.

where:

W = weight of the catalyst, g

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Page 55

PHENOLS AND THIOPHENOLS IN PETROLEUM

PRODUCTS BY SPECTROPHOTOMETRY

UOP METHOD 262

Scope

This method is intended primarily for the quantitative determination of phenols and

thiophenols in gasoline and in refinery caustics, but it also is applicable to crude

cresylic acids derived from these refinery caustics. "Phenols" consist of a mixture of

phenol, cresols and xylenols. "Thiophenols" denotes the analogous sulfur

compounds.

Outline of Method

Phenols and thiophenols are extracted from the petroleum fraction with 10% sodium

hydroxide solution. The ultraviolet absorption spectrum of the caustic extract is then

recorded. A base-line technique is used to compensate for background absorption

of the sample. Calibration in a similar manner with known solutions and the

application of Beer's Law permits calculation of weight-percent phenols and weight-

percent thiophenols.

In the presence of excessive concentrations of mercaptans, only the sum of the

phenols and thiophenols can be determined directly. However, an accurate value

for thiophenols can be obtained from the modified procedure described, involving

adsorption of the sample on silica gel followed by selective elution of the

thiophenols.

The procedure for refinery caustics and crude cresylic acids is identical to that for

petroleum fractions except that the extraction step is omitted.

157048 Analytical Methods

Page 56

Precautions

Use clean glassware and CP reagents.

Shake vigorously in order to obtain quantitative extraction.

Since this method of sample preparation is employed chiefly to avoid the oxidation

of thiophenols during storage, the extraction must immediately follow sampling. An

inert atmosphere and the proper sample container are mandatory.

Do not use carbon dioxide as the inert gas.

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SAMPLING PETROLEUM AND PETROLEUM PRODUCTS

ASTM D 270

Scope

This method covers procedures for obtaining representative samples of stocks or

shipments of crude petroleum and petroleum products, except electrical insulating

oils, and butane, propane, and other petroleum products that are gases at

atmospheric temperature and pressure.

Summary of Method

Samples of petroleum and petroleum products are examined by various methods of

test for the determination of physical and chemical characteristics. It is accordingly

necessary that the samples be truly representative of the petroleum or petroleum

products in question. The precautions required to ensure the representative

character of the samples are numerous and depend upon the type of material being

sampled, the tank, carrier, container or line from which the sample is being

obtained, the type and cleanliness of the sample container, and the sampling

procedure that is to be used. Each procedure is suitable for sampling a number of

specific materials under definite storage, transportation, or container conditions.

The basic principle of each procedure is to obtain a sample or a composite of

several samples in such manner and from such locations in the tank or other

container that the sample or composite will be truly representative of the petroleum

or petroleum product.

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LOSS ON IGNITION OF CATALYST AT 900°C

UOP METHOD 275

Scope

This method is for determining the loss on ignition of fresh or used catalyst or

catalyst bases of the various commercial shapes and sizes, when an ignition

temperature of 900°C is specified. It is also applicable to other sample types, such

as catalyst fines.

A representative weighted sample is heated at 900°C to constant weight and the

loss in weight calculated as percent loss on ignition.

Precision

Duplicate determinations should not differ by more than 0.2% absolute for values

below 3.0%, or more than 0.3% to 10.0%.

Based on 10 pairs at the 2% loss on ignition level, the standard deviation calculated

from the mean range was 0.072%.

Time for Analysis

Elapsed time per test is about 21/4 hours (5.0 hours when fines are being

analyzed).

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EXISTENT GUM IN DIOLEFIN-CONTAINING GASOLINES

AND NAPHTHAS BY THE STEAM JET METHOD

UOP METHOD 277

Scope

Some gasolines and naphthas contain appreciable concentrations of diolefins or

other materials which are sensitive to oxidation. Examples are: (1) pyrolysis

naphtha (ethylene coproduct gasoline), (2) certain catalytically cracked gasolines,

and (3) certain thermally cracked gasolines. This method is used to determine the

existent gum in these types of materials. An inert gas, steam in this case, is used in

the evaporation step in order to prevent gum from forming in the test beaker during

the evaporation. It has been observed that the ASTM air-jet Method D 381, when

used on oxidation-sensitive samples, tends to give falsely high gum values because

of gum formation during the evaporation.

Outline of Method

The steam jet method is similar to ASTM Method D 381 for Existent Gum in Fuels

by Jet Evaporation. The sample in a tarred beaker is placed in a heated metal block

apparatus maintained at 325°F (163°C) and evaporated to dryness by a jet of steam

which has been superheated to 325°F (163°C). The residue is weighed and

reported as milligrams of gum per 100 ml of sample.

Precautions

The types of gasolines and naphthas for which this method is intended must be

sampled and handled carefully in order to prevent oxidation. For best results it is

recommended that: (1) the sample containers be purged with inert gas such as

nitrogen, carbon dioxide, or sweet refinery gas prior to taking the samples, (2) any

storage between time of sampling and analysis be in the dark (preferably

157048 Analytical Methods

Page 60

refrigerated storage), (3) the time lapse between sampling and analysis be as short

as possible.

Precision

Duplicate results by the same operator should not be considered suspect unless

they differ by more than approximately 25% of the result.

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API GRAVITY OF CRUDE PETROLEUM AND PETROLEUM PRODUCTS

(HYDROMETER METHOD)

ASTM D-287

Scope

Using a glass hydrometer the API gravity of crude petroleum and petroleum

products which have Reid Vapor Pressures under 26 lbs. can be determined.

Gravities are determined at 60°F (15°C), or converted to 60°F, by means of

standard tables. Conversion tables are not applicable to nonhydrocarbons or

essentially pure hydrocarbons such as the aromatics. Of interest: the ID of the

sample cylinder must be at least 25 mm greater than the OD of the hydrometer. The

height of the cylinder shall be such that the sample height is 25 mm more than the

submerged portion of the hydrometer.

Precision

Repeatability – Duplicates should not differ by more than 0.2 degrees API.

Reproducibility – Results should not differ by more than 0.5 degrees API when done

by different labs.

The above judgments are valid providing API gravities were obtained at a

temperature not differing from 60°F by more than 18°F (10°C).

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ANALYSIS OF REFINERY WATERS FOR pH, IRON, AND COPPER

UOP METHOD 314

Scope

This method is designed for measuring the extent of corrosion caused by refinery

waters. Copper and iron are determined at a level of 0.1 ppm and higher. The

metals may be present as simple dissolved ions, as complex ions with cyanide or

other complexing agents, or as part of the suspended solids that often are present.

Ammonia, hydrogen sulfide, hydrogen cyanide and organic matter do not interfere.

The pH of the water is determined because it usually correlates with the extent of

corrosion.

Outline of Method

The water sample, including any suspended solids, is concentrated in the presence

of sulfuric acid until sulfur trioxide fumes appear and then treated successively with

nitric acid and aqua regia.

Iron is determined colorimetrically. The lower limit of detection is 0.1 ppm iron.

Copper is determined colorimetrically. The lower limit of detection is 0.1 ppm copper

in the water sample.

The pH of the original water sample is determined with a pH meter using a glass-

calomel electrode system. Samples drawn for determination of pH at the refinery

should be taken in glass bottles, leaving little or no air space above the liquid, and

should be stoppered immediately with rubber or neoprene. The pH should be

measured as soon thereafter as possible as it is often subject to fairly rapid change

with time. Draw samples to be sent out of the refinery in polyethylene bottles to

avoid breakage.

157048 Analytical Methods

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Precision

Insufficient data available to calculate an esd with at least 3.7 degrees of freedom.

Time for Analysis

The elapsed time is about 8 hours per sample.

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VAPOR PRESSURE OF PETROLEUM PRODUCTS

(REID METHOD)

ASTM D 323

Scope

This method determines the absolute vapor pressure of volatile crude oil and

volatile nonviscous petroleum products, except LPG. The gasoline chamber of the

testing apparatus is filled with a chilled sample and connected to the air chamber

section which should be at 100°F (37.8°C). The container is then immersed in a

constant-temperature bath and shaken periodically until equilibrium is reached. A

manometer attached at the end of the cylinder like apparatus is read and corrected

if the air chamber temperature is initially at something other than 100°F.

Precision

Repeatability – Duplicate results by the same operators should be considered

suspect it they differ by more than the following:

Range Repeatability 0-5 psi 0.1 5-16 psi 0.2 16-26 psi 0.3

Reproducibility – Results by two laboratories should be considered suspect it they

differ by more than the following:

Range Repeatability 0-5 psi 0.35 5-16 psi 0.3 16-26 psi 0.4

157048 Analytical Methods

Page 65

CALCULATION OF UOP CHARACTERIZATION FACTOR AND

ESTIMATION OF MOLECULAR WEIGHT OF PETROLEUM OILS

UOP METHOD 375

Scope

This method is for determining the UOP Characterization Factor, which is indicative

of the general origin and nature of a petroleum stock. Values of 12.5 or higher

indicate a material predominantly paraffinic in nature. Highly aromatic materials

have characterization factors of 10.0 or less.

This method also may be used to estimate the molecular weight of typical

petroleum fractions. It is not intended for estimating the molecular weight of a pure

hydrocarbon compound.

Outline of Method

This method gives directions for estimating:

1. The UOP-Characterization Factor from API gravity and Engler distillation,

2. The UOP Characterization Factor from API gravity and kinematic viscosity at a

temperature of 100°, 122° or 210°F (37.8°, 50° or 98.9°C), and

3. The molecular weight from API gravity and Engler distillation.

Definitions

The UOP Characterization Factor, K, of a hydrocarbon is defined as the cube root

of its absolute boiling point, in degrees Rankine, divided by its specific gravity at

60°F.

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Molecular weight, as employed herein, is the average molecular weight of a

petroleum fraction and not that of a single, pure compound.

Cubic average boiling point is the cube of the sum of the products of the volume

fraction multiplied by the cube root of the boiling point of each component

expressed in degrees Rankine.

Mean average boiling point is the arithmetic average of the true molal boiling point

and the cubic average boiling point, expressed in degrees Fahrenheit.

True molal average boiling point is the sum of the products of the mol fraction

multiplied by the boiling point of each component.

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Page 67

NITROGEN IN PETROLEUM DISTILLATES AND HEAVY OILS

BY ACID EXTRACTION OR DIRECT KJELDAHL PROCEDURE

UOP METHOD 384

Scope

This acid extraction method is specifically intended for the determination of

combined nitrogen in petroleum distillates and heavy oils in concentrations ranging

from 0.2 to 20 ppm. Nonextractable samples, and samples containing nitrogen

concentrations ranging from 20 ppm to several percent, can be handled by a direct

Kjeldahl analysis.

The types of nitrogen compounds which can be determined are those which usually

are determined by a macro-Kjeldahl procedure and include amines, amides,

pyridines, pyroles and quinolines. The method does not apply to organic nitro-

compounds nor to those containing a -N = N- linkage.

Precision

Duplicate determinations run in the same laboratory by the same operator on the

same equipment should not differ from the mean by more than the percent relative

in the table below:

Total Percent, Nitrogen, ppm Relative

0.5 20

5 11

45 5

500 2

The estimated standard deviation was calculated to be 0.35 at the 16-ppm level,

based on 5 replicate samples; 1.38 at the 54-ppm level, based on 6 replicates.

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TRACE METALS IN OILS BY WET ASH-SPECTROGRAPHIC METHOD

UOP METHOD 389

Scope

This method is applicable to the determination of iron, nickel, vanadium, lead,

copper, sodium and molybdenum, specifically, in crude petroleum and such

fractions as gas oils, fuel oils and let fuels. Additionally, manganese, chromium,

magnesium, tin, calcium, aluminum and zinc may be determined by this method.

Each of these elements can be determined over the concentration range of 0.02 to

1000 ppm if a 50-g sample of oil is ashed. Higher or lower concentrations can be

determined by ashing appropriately-sized samples.

Outline of Method

Cobalt and potassium are added to the oil sample as internal standards and

spectroscopic buffers. The oil sample is then coked with fuming sulfuric acid, ignited

and ashed at 1000°F (538°C), treated with aqua regia and the ash dissolved in

dilute hydrochloric acid. A spark spectrum of the solution is obtained by means of a

rotating-disk electrode technique. A microphotometer is used to measure the

densities of selected metal lines. Concentrations are determined from standard

calibration curves.

Precision

The estimated standard deviations (esd) for various concentration levels of the

metals determined by this method are shown below. Duplicate results by the same

operator should not be considered suspect unless they differ by more than the

amounts shown in the "allowable difference" column (95% probability).

157048 Analytical Methods

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Metal Level, No. of esd, Allowable ppm Pairs ppm Difference, ppm

1 5 0.09 0.3

10 5 0.59 2.2

50 5 3.2 12

200 5 13 48

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TRACE METALS IN PETROLEUM AND ORGANIC

PRODUCTS BY WET-ASHING; FLAME PHOTOMETER

AND SPECTROPHOTOMETRIC METHODS

UOP METHOD 391

Scope

This method is for determining trace concentrations (parts per million) of vanadium,

nickel, iron, copper and sodium in petroleum products such as crude oils and

residues, and varied organic compounds (including nitroanilines, amines,

chlorobenzenes, phenols and other related materials) produced or used in chemical

manufacturing. Other elements commonly found in these materials do not interfere.

Outline of Method

The sample is wet-ashed with fuming sulfuric acid and the coke is burned off in a

muffle furnace. The inorganic residue remaining is dissolved in acid and diluted to a

given volume. Vanadium, nickel, iron and copper are determined

spectrophotometrically, and sodium is determined by flame photometry, using

aliquots from the acid solution.

Precaution

The sulfuric acid concentration in the standard sodium solutions must be the same

as that in the sample solutions. If a different concentration of sulfuric acid is used for

the sample solution than that specified in this method, the calibration curve must be

prepared with sodium standard solutions containing this same sulfuric acid

concentration.

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Precision

Duplicate determinations by the same operator should not be considered suspect

unless they differ by more than the following amounts:

Allowable Difference for Range, ppm Duplicates, ppm (Vanadium, Nickel, Iron, Copper) 0 to 2 — 0.1 ppm of metal >2 — 5% of the mean (Sodium) 0 to 2 — 0.2 ppm >2 — 10% of the mean

Insufficient data are available to calculate a standard deviation for the metals listed.

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PARTICLE SIZE DISTRIBUTION BY MICROMESH SIEVES

UOP METHOD 422

Scope

This method is for the determination of particle sizes of fluid cracking catalysts by

means of calibrated sieves having uniform precise square openings. It may also be

used for determining particle sizes of other powdered materials. The method

provides for the classification of particles in a range of sizes from about 20 to 149

microns.

The method is a modification of Shell Development Company, Method EMS 5Z2/61.

Outline of Method

A representative sample is appropriately humidified and then placed on the top

sieve of a calibrated set of precision sieves. The set is mounted on a specified

shaking apparatus and shaken for 20 minutes. The weight of catalyst retained on

each sieve and in the pan is determined, and the percentage of the sample retained

on each sieve and in the pan is calculated on the basis of the sum of weights of the

recovered fractions.

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SINTERING INDEX OF USED FLUID CRACKING CATALYST

UOP METHOD 424

Scope

This method provides a means of separating and measuring a fraction of used fluid

cracking catalyst having a reduced apparent density resulting from the pores having

been sealed off by localized overheating.

Precision

Duplicate results by the same operator should be considered suspect if they differ

by more than 1% absolute. Duplicate results by different operators should be

considered suspect if they differ by more than 2% absolute.

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SURFACE AREA, PORE VOLUME AND PORE DIAMETER

OF POROUS SUBSTANCES BY NITROGEN ADSORPTION

UOP METHOD 425

Scope

This method is for the determination of surface areas of porous substances by a

two-point system, using the basic Brunauer-Emmett-Teller (B.E.T.) theory of

multilayer adsorption, and pore volumes of the substances, using the capillary

condensation theory. Surface areas greater than 10 m2/g may be determined, as

well as the volume of pores up to a diameter of 600 Angstroms. Pore diameter is

calculated from surface area and pore volume.

Outline of Method

The surface area of a substance is determined by measuring the volume of nitrogen

gas adsorbed at liquid nitrogen temperature and relative pressures of 60/760 and

160/760, and applying the B.E.T. theory.

The pore volume is determined by measuring the amount of gaseous nitrogen

condensed in the pores at liquid nitrogen temperature and a relative pressure of

735/760. It can be shown by use of the Kelvin equation for capillary condensation

and the proper correction for multilayer adsorption that this volume is that required

to fill all pores of diameter less than 600 Angstroms.

157048 Analytical Methods

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Precision

Surface Area

Duplicate determinations should not differ by more than 8% from the mean.

Based on 2 sets of 5 replicate determinations, the standard deviation at the 500-600

m2/g level was 12.

Based on 2 sets of 5 replicate determinations, the standard deviation at the 100-200

m2/g level was 2.

Pore Volume

Duplicate determinations should not differ by more than 0.04 ml/g.

Based on 4 sets of 5 replicate determinations, the standard deviation in the range of

0.30 to 0.90 m2/g was 0.013.

Pore Diameter

Duplicate determinations should not differ by more than 5% from the mean.

Based on 2 sets of 5 replicate determinations, the standard deviation at the 50-60

Angstrom level was 1.

Based on 2 sets of 5 replicate determinations, the standard deviation at the 90-130

Angstrom level was 3.5.

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Time for Test

The elapsed time for 1 sample is 9 hours.

The elapsed time for 6 samples is 10.5 hours.

157048 Analytical Methods

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KINEMATIC VISCOSITY OF TRANSPARENT AND OPAQUE LIQUIDS

(AND THE CALCULATION OF DYNAMIC VISCOSITY)

ASTM D 445

Scope

This method covers the determination of the kinematic viscosity of liquid petroleum

products, both transparent and opaque, by measuring the time for a volume of liquid

to flow under gravity through a calibrated glass capillary viscometer. The dynamic

viscosity can be obtained by multiplying the measured kinematic viscosity by the

density of the liquid.

Summary of Method

The time is measured in seconds for a fixed volume of liquid to flow under gravity

through the capillary of a calibrated viscometer under a reproducible driving head

and at a closely controlled temperature. The kinematic viscosity is the product of the

measured flow time and the calibration constant of the viscometer.

Precision

The following precision applies to clean, transparent oils tested between 60° and

212°F (15° and 100°C).

Repeatability – Duplicate results by the same operator, using the same

viscometer, should be considered suspect if their difference is greater than 0.35

percent of their mean.

Reproducibility – The results submitted by each of two laboratories should not be

considered suspect unless their difference is greater than 0.7 percent of their mean.

ASH FROM PETROLEUM PRODUCTS

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ASTM D 482

Scope

This method covers the determination of ash from distillate and residual fuels, gas

turbine fuels, crude oils, lubricating oils, waxes, and other petroleum products, in

which any ash-forming materials present are normally considered to be undesirable

impurities or contaminants. The method is limited to petroleum products which are

free from added ash-forming additives, including certain phosphorus compounds.

Summary of Method

The sample contained in a suitable vessel is ignited and allowed to burn until only

ash and carbon remain. The carbonaceous residue is reduced to an ash by heating

in a muffle furnace at 1427°F (775°C), cooled and weighed.

Report

Report the result to two significant figures as the ash, ASTM D 482, stating the

weight of the sample taken.

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SAMPLING OF GASOLINES, DISTILLATE FUELS

AND C3-C4 FRACTIONS

UOP METHOD 516

Scope

This is an outline of the sampling techniques necessary for obtaining, in a stainless

steel cylinder, an air-free sample of a liquid hydrocarbon. Samples may consist of

liquefied natural gases, high vapor pressure natural gasolines, various liquefied

petroleum gases, air unstable gasolines or other liquid hydrocarbon products which

require rigorous exclusion of air.

Outline of Method

Proper sampling techniques are specified to obtain an uncontaminated, air-free

sample in a suitable container; viz., a double-valved, stainless steel cylinder. The

cylinder is mounted vertically near the sampling point and connected to the plant

sample line by steel tubing or pipe. The connecting lines are flushed with the

sample, which is then allowed to flow upward through the cylinder. Several volumes

of sample are discarded before closing the sample cylinder valves of the cylinder.

Identification and Shipment

Properly identify each sample by attaching a tag to the cylinder giving company

name and location, time and date of sampling, identity of stream sampled, sample

pressure and tests required. Crate the cylinder to protect the valves from being

opened or damaged in shipment. Affix a "Red Label" or other proper shipping label

to the crate.

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Notes and Precautions

Samples taken in containers found leaking either during or after sampling should be

discarded and new samples taken in leak-free cylinders.

Consult the current Interstate Commerce Commission or other appropriate

authorities for regulations for applicable specification for shipment. Consult ASTM

Methods D 270, D 1145 and D 1265, if necessary, for procedures for measurement

and sampling of petroleum and petroleum products.

For liquid samples taken in the above manner it is mandatory to immediately

provide a safe outage in the cylinder to prevent thermal expansion and cylinder

rupture. Follow the recommendations in this method to safely provide that outage.

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GAS ANALYSIS BY GAS CHROMATOGRAPHY

UOP METHOD 539

Scope

This method is for determining the composition of a wide variety of gaseous

hydrocarbon mixtures obtained from refining processes or from natural sources, including minor concentrations of the composite of C5 olefins and C6+

hydrocarbons. 1-Butene is not resolved from isobutylene and argon is determined

as a composite with oxygen. The lower limit of detection for a single component is

0.1 mol-%.

Outline of Method

All the constituents of a total gas sample cannot be resolved by a single

chromatographic column. Therefore in this procedure, 3 columns are connected in

series with appropriate coupling valves. Each column is used to separate a specific portion of the total sample. The first column is able to resolve gases in the C3-C5

boiling range. The second column separates the components in the intermediate

boiling range – carbon dioxide, ethylene, and ethane – while the third resolves the

light gases – hydrogen, oxygen + argon (composite), nitrogen, methane, and

carbon monoxide.

Precision

Based on 7 replicate determinations, the estimated standard deviations (esd) in

Table 1 were calculated for the components listed.

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TABLE 1

GAS ANALYSIS BY GAS CHROMATOGRAPHY

ALLOWABLE LEVEL, ESD, DIFFERENCE, COMPONENT MOL-% MOL-% MOL-%

HYDROGEN 10 0.10 0.36

NITROGEN 20 0.02 0.07

METHANE 10 0.03 0.09

CARBON MONOXIDE 10 0.14 0.49

CARBON DIOXIDE 10 0.03 0.10

ETHANE 10 0.04 0.14

PROPYLENE 10 0.02 0.05

n-BUTANE 10 0.03 0.09

ISOPENTANE 3 0.03 0.11 C5 OLEFINS/C6 PLUS 4 0.04 0.14

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METALS IN CRACKING CATALYST BY EMISSION SPECTROSCOPY

UOP METHOD 546

Scope

This method is designed for the determination of metal impurities in silica-alumina

cracking catalyst containing 0 to 30% alumina and less than 1% Na. Impurities are

determined in the following ranges: Cu and Mo, 0.001 to 1.0%; Ni, V, Mn, Cr, Pb,

Sn, and Ti, 0.005 to 1.0%; Fe and Mg, 0.01 to 2.0%; Zn and Ca, 0.05 to 2.0%; Na,

0.05 to 1.0%.

Outline of Method

Samples of the unknown diluted in graphite are burned to completion using a 6-amp

dc arc. The photographed spectra are then examined to determine the elements

sought.

Iron, nickel, and vanadium concentrations are quantitatively determined by

densitometry, using an internal standard, while the concentrations of the remaining

metals are semi-quantitatively determined by visual comparison with spectra from

known samples.

Precision

Duplicate determinations for Fe, Ni, and V should not differ from the mean by more

than 10% in the 0.01 to 1.0% range.

Based on 10 replicates, the estimated standard deviation (esd) was calculated to

be: Elemental Level esd Fe 0.6 0.047 Ni 0.02 0.0017 V 0.05 0.0075

157048 Analytical Methods

Page 84

CYANIDE AND THIOCYANATE IN REFINERY WATERS AS CYANIDE

UOP METHOD 682

Scope

This method is for determining cyanide and thiocyanate in refinery water, both of

which are then calculated as weight-ppm cyanide. The lower limit of detection is

about 0.02 wt-ppm in samples containing no sulfur and 0.8 wt-ppm in those

containing 1% sulfide.

Outline of Method

A sample of refinery water is placed in a flask and hydrogen sulfide added. The

sample is then acidified with hydrochloric acid, bromine water is added and the

mixture allowed to stand until clear.

(1) Reactions of bromine water with sample:

HCN + Br2 CNBr + HBr

KCNS + 4 Br2 + 4 H2O KBr + CNBr + H2SO4 + 6 HBr

H2S + 4 Br2 + 4 H2O 8 HBr + H2SO4

The excess bromine is destroyed with arsenious acid and a pyridine-benzidine

mixture is added. The sample is then allowed to stand for 10 minutes.

157048 Analytical Methods

Page 85

(2) Reaction of the pyridine and benzidine with sample:

N N

+ CNBr

CN

Br

(a)

NN

+

H

+ 2H 2NC 6H 4-C 6H 4-NH 2

Br

CN C 6H 4-C 6H 4NH 2

NHC 6H 4C 6H 4-NH 2 + (Br) - + H 2N-CN

(b)

After standing the sample is diluted to volume. The absorbance is read on a

spectrophotometer at 525 m and calculated as weight-ppm cyanide.

157048 Analytical Methods

Page 86

SULFIDE IN REFINERY WASTE WATER USING CADMIUM CHLORIDE

UOP METHOD 683

Scope

This method is for determining sulfide in refinery waste water. It cannot be used on

caustic solutions. Good precision can be obtained when a titrant volume of 10 ml or

more is used. The estimated standard deviation of 0.013 was obtained on a sample

containing 0.8 wt-% S. However, with titrant volumes of less than 10 ml, the results

may be high by as much as 5% of the value found.

Outline of Method

The sample is pipetted into 100 ml of water containing a small amount of

ammonium hydroxide. It is then titrated potentiometrically with standard cadmium

chloride and the result calculated as weight-percent sulfur. The titration curve may

have 2 "breaks". The possible reactions are as follows:

To the first "break":

Cd++ + (NH4)2S CdS + 2NH4+

Between the first and second "break":

either (a) Cd++ + (NH4)2S • S4 CdS + 4S + 2NH4+

(b) Cd++ + (NH4)2S • S4 CdS3 + 2NH4+

However, in this method the sulfide is calculated to the second "break" with the

equivalent weight of sulfur being 16.

157048 Analytical Methods

Page 87

Precision

The estimated standard deviation (esd) at the 0.8% sulfur level is shown below.

Duplicate results by the same operator are not considered suspect unless they

differ by more than the amount shown in the "allowable difference" column (95%

probability).

Sulfur Allowable Type of Level, No. of esd, Difference, Sample wt-% Replicates wt-% S wt -% Solution of (NH4)2S 0.8 11 0.013 0.026

157048 Analytical Methods

Page 88

CARBON ON CATALYST BY "LECO" WR-12

WIDE RANGE CARBON DETERMINATOR

UOP METHOD 703

Scope

This method gives supplementary instructions for the determination of 0.01 to 80.0

wt-% carbon on catalysts.

It is necessary that the analyst be provided with the history of the sample so that the

proper sample preparation can be applied.

Outline of Method

The sample is weighed in a ceramic crucible, mixed with accelerators and burned in

an induction furnace using oxygen carrier gas. The products of combustion pass

through a purifying train consisting of a dust trap, antimony metal for chloride

removal, manganese dioxide for sulfur removal, and a heated catalyst lube for

conversion of carbon monoxide to carbon dioxide and hydrogen to water. The

carbon dioxide is adsorbed on molecular sieves at ambient temperature. After the

adsorption period is ended, the molecular sieve column is rapidly heated to 600°F

(316°C) and the carbon dioxide eluted and carried through the measuring thermistor

by an auxiliary flow of oxygen. The output of the thermistor bridge is integrated and

read on a digital voltmeter and converted to percent carbon by calculation.

157048 Analytical Methods

Page 89

Precision

The estimated standard deviation (esd) for carbon at different concentrations is

shown below.

For the 95% probability level, duplicate results by the same operator should not be

considered suspect unless they differ by more than the amounts shown in the

"allowable difference" column.

Carbon Level, Number of Number of esd, Allowable % C Pairs Used Replicates % C Difference, % C

0.01-0.6 5 8 0.005 0.02

0.6-2 7 – 0.015 0.05

2-5 7 – 0.022 0.07

20 5 – 0.334 1.25

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GAS ANALYSIS BY GAS CHROMATOGRAPHY

USING A TWO-INJECTION TECHNIQUE

UOP METHOD 709

Scope

This method is for determining most of the components, including low concentrations of total C6+ hydrocarbons, normally found in a wide variety of

gaseous hydrocarbon mixtures obtained from refining processes or from natural

sources. Butene-1 is not resolved from isobutylene and argon is determined as a

composite with oxygen. The lower limit of detection for a single component is 0.1

mol-%.

Outline of Method

All the constituents of a total gas sample cannot be resolved by a single

chromatographic column. Therefore, in this procedure, 2 columns are connected in

series with appropriate coupling valves to a thermal conductivity detector. Each

column is used to separate a specific portion of the total sample. The first column is able to resolve gases in the C2-C5 range. The second column separates the light

gases: H2, O2 + A (composite), N2, CH4 and CO.

Precision

Based on 6 replicate determinations, the estimated standard deviation (esd) in

Table 2 was calculated for the gases listed.

Duplicate results should not differ by more than the allowable difference indicated

(95% probability).

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TABLE 2

GAS ANALYSIS BY GAS CHROMATOGRAPHY

USING A TWO-INJECTION TECHNIQUE

ALLOWABLE LEVEL, ESD, DIFFERENCE, COMPONENT MOL-% MOL-% MOL-%

HYDROGEN 21 0.186 0.68

NITROGEN 7 0.087 0.32

METHANE 12 0.180 0.66

CARBON MONOXIDE 8 0.266 0.97

PROPANE 8 0.077 0.28

PROPYLENE 6 0.203 0.74

ISOBUTANE 7 0.158 0.58

n-BUTANE 6 0.074 0.27

ISOBUTYLENE 6 0.264 0.96

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Page 92

OILY MATERIAL IN REFINERY WATERS

BY INFRARED SPECTROPHOTOMETRY

UOP METHOD 726

Scope

This method is for determining oily material in refinery waters. It is especially

suitable for routine monitoring of effluent streams known to be relatively constant as

to the nature of the oily material present. The method has an advantage over

physical test methods in that volatile hydrocarbons can be determined and are not

lost.

Outline of Method

Oily material is extracted from water with carbon tetrachloride. The infrared

absorbances of the extract are determined at 2860 cm-1 (3.50 m) and 2930 cm-1

(3.42 m), and these are used to calculate the concentration of oily matter.

Definition Oily material means any substance containing -CH, -CH2-, or -CH3 groups which

show infrared adsorption bands at 2860 cm-1 (3.50 m) and 2930 cm-1 (3.42 m)

and which is extractable from acidified water with carbon tetrachloride.

Sensitivity

The sensitivity of this method is about 1 ppm. The method can be extended to

include oil concentrations of less than 1 ppm by using cells of longer path length (5-

and 10-cm cells are common), larger samples of the water and smaller volumes of

carbon tetrachloride for the extraction.

Precision and Accuracy

Results are reported to the nearest part per million. Relative esd as reported in the

reference API method is 5%. Duplicate results should be considered suspect if they

differ by more than 20% of the average value.

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DISTILLATION OF PETROLEUM PRODUCTS AT REDUCED PRESSURES

ASTM D 1160

Scope

This method covers the determination, at reduced pressures, of the boiling

temperature ranges of petroleum products which can be partially or completely

vaporized at a maximum liquid temperature of 750°F (400°C) at pressures down to

1 mm Hg, absolute.

Summary of Method

The sample is distilled, at some predetermined and accurately controlled pressure,

between 1 mm Hg, absolute, and atmospheric, under conditions which provide

approximately one theoretical plate fractionation. Data are obtained from which a

distillation curve relating volume distilled and boiling point at the controlled pressure

can be prepared.

Significance

Some petroleum products decompose when distilled at atmospheric pressure. This

distillation method is for determination of distillation characteristics of such products.

The apparatus and conditions of test provide approximately one theoretical plate

fractionation.

Results by this method are not comparable with those of other ASTM procedures

for the determination of boiling point ranges of petroleum products, such as ASTM

Method D 86 for Distillation of Petroleum Products.

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Page 94

SULFUR IN PETROLEUM PRODUCTS

(LAMP METHOD)

ASTM D 1266

Scope

This method determines the total sulfur in liquid petroleum products in

concentrations above 0.002 weight percent. The procedure involves burning the

sample in a closed system using a suitable lamp apparatus. An artificial atmosphere composed of 70% CO, and 30% O2 is used to burn the sample to prevent formation

of nitrogen oxides. The oxides of sulfur are then oxidized to sulfuric acid. Sulfur as

sulfate is determined acidimetrically by titration or gravimetrically by precipitation as

barium sulfate.

Precision

Samples should contain in the range of 0.01% to 0.4% sulfur.

Repeatability – Duplicate results by the same operator should not differ by more

than 0.005%.

Reproducibility – Results by two laboratories should not differ by more than 0.010 +

0.025 S, where S = the total sulfur content, weight percent, of the sample.

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Page 95

ASTM COLOR OF PETROLEUM PRODUCTS

(ASTM COLOR SCALE)

ASTM D 1500

Introduction

This method has replaced the former ASTM Method D 155, Test for Color of

Lubricating Oil and Petrolatum by Means of ASTM Union Colorimeter. Method D

155 was withdrawn as an ASTM Tentative on July 1,1960. Method D 1500 is better

than the former Method D 155 in three respects: (1) the glass standards are

specified in fundamental terms; (2) the differences in chromaticity between

successive glass standards are uniform throughout the scale; and (3) the lighter

colored standards more nearly match the color of petroleum products.

Scope

This method covers the visual determination of the color of a wide variety of

petroleum products such as lubricating oils, heating oils, diesel fuel oils, and

petroleum waxes.

Report

Report as the color of the sample, the designation of the glass producing a

matching color, for example: 7.5 ASTM Color.

If the color of the sample is intermediate between those of two standard glasses

record the designation of the darker glass preceded by the letter "L", for example:

"L7.5 ASTM Color". Never report the color as being darker than a given standard

except those darker than 8, for example: ASTM Color.

If the sample has been diluted with kerosene, report the color of the mixture

followed by the abbreviation "Dil," for example: "L7.5 Dil ASTM Color".

157048 Analytical Methods

Page 96

Precision

The results obtained by different operators in the same laboratory should not vary

by more than 0.5 number, and the same variation should apply for determinations

between different laboratories at the 96 percent confidence level.

157048 Analytical Methods

Page 97

SULFUR IN PETROLEUM PRODUCTS

(HIGH-TEMPERATURE METHOD)

ASTM D 1552

Scope

This method covers two procedures for the determination of total sulfur in petroleum

products, including lubricating oils containing additives, and additive concentrates.

The method is applicable to samples boiling above 350°F (177°C) and containing

not less than 0.06 percent sulfur. Chlorine in concentrations less than 1 percent

does not interfere. Nitrogen when present in excess of 0.1 percent may interfere;

the extent of such interference may be dependent on the type of nitrogen

compound as well as the combustion conditions. The alkali and alkaline earth

metals, as well as zinc, phosphorus, and lead, do not interfere.

Summary of Method

The sample is burned in a stream of oxygen at a sufficiently high temperature to

convert about 97 percent of the sulfur to sulfur dioxide. A standardization factor is

employed to obtain accurate results. The combustion products are passed into an

absorber containing an acid solution of potassium iodide and starch indicator. A

slight blue color is developed in the absorber solution by the addition of standard

potassium iodate solution. As combustion proceeds, bleaching the blue color, more

iodate is added. The amount of standard iodate consumed during the combustion is

a measure of the sulfur content of the sample.

Report

Report the results of the test to the nearest 0.01 percent.

157048 Analytical Methods

Page 98

Precision

The following criteria should be used for judging the acceptability of results (95

percent confidence):

Repeatability – Duplicate results by the same operator should be considered

suspect if they differ by more than the following amounts:

Sulfur, weight percent (Range) Repeatability

0 to 0.5 0.05

0.5 to 1.0 0.07

1.0 to 2.0 0.10

2.0 to 3.0 0.16

3.0 to 4.0 0.22

4.0 to 5.0 0.24

Reproducibility – The result submitted by each of two laboratories should not be

considered suspect unless the two results differ by more than the following

amounts:

Sulfur, weight percent (Range) Reproducibility

0 to 0.5 0.05

0.5 to 1.0 0.11

1.0 to 2.0 0.17

2.0 to 3.0 0.26

3.0 to 4.0 0.40

4.0 to 5.0 0.54

157048 Analytical Methods

Page 99

KNOCK CHARACTERISTICS OF MOTOR FUELS

BY THE RESEARCH METHOD

ASTM D 2699

Scope

This method determines the knock characteristics of motor gasolines, intended for

use in spark-ignition engines. A Research octane number (RON) of 100 or lower is

the volume percent of iso-octane in a blend with n-heptane that matches the knock

intensity of the unknown sample. For numbers above 100, a comparison is made to

iso-octane and milliliters of tetraethyllead required to match knock intensity.

Summary of Method

The RON of a gasoline is determined by comparing its knocking tendency with

those for blends of reference fuels of known octane. Knock intensity is measured by

an electronic detonation meter on a testing unit consisting of a single cylinder

engine.

Repeatability

Data for limits on duplicate results by the same operator have not been developed.

Reproducibility

Results by different laboratories should be considered suspect if their difference is

greater than the limits shown below: Ave. Research Octane No. Level Limits

80 1.2

85 0.9

90 0.7

95 0.6

100 0.7

105 1.1

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Page 100

KNOCK CHARACTERISTICS OF MOTOR FUELS

BY THE MOTOR METHOD

ASTM D 2700

Scope

This method covers the determination of the knock characteristics of motor and

aviation-type gasolines, intended for use in spark-ignition engines, in terms of

ASTM motor octane numbers.

Summary of Method

The ASTM Motor Octane Number of a fuel is determined by comparing its

knocking tendency with those for blends of ASTM reference fuels of known octane

number under standard operating conditions. This is done by varying the

compression ratio to obtain standard knock intensity, as measured by an electronic

detonation meter.

Definitions

ASTM Motor Octane Number of motor and aviation-type gasolines of 100 and

below – The volume percent, to the nearest tenth, of iso-octane (equals 100.0) in a

blend with n-heptane (equals 0.0) that matches the knock intensity of the unknown

sample, when compared by this method.

ASTM Motor Octane Number of a motor gasoline above 100 – The value, to the

nearest tenth, that corresponds to the equivalent engine rating in terms of milliliters

of tetraethyl lead in iso-octane.

157048 Analytical Methods

Page 101

Precision

Repeatability – Data to determine acceptable limits for duplicate results obtained by

the same operator have not been developed.

Reproducibility – The difference between two, single, and independent results,

obtained by different operators working in different laboratories on identical test

material would, in the long run, and in the normal and correct operation of the test

method, exceed the following values in only one case in 20 (see table).

Average Motor Octane Number Level Limits Octane Number

80 1.2

85 1.1

90 1.0

95 1.1

99 1.5

100.1 1.1

105 1.8

157048 Analytical Methods

Page 102

SAMPLING STACKS FOR PARTICULATE MATTER

ASTM D 3685

Scope

This method covers the sampling and determination of particulate matter in stack

gases.

Significance

The following procedure describes a method of sampling in stacks and flues which

has been standardized within the limits of the many conditions which are

encountered in the normal course of sampling stacks. No one procedure or set of

apparatus will apply to all problems. The recognition of one set of apparatus which

will satisfy a number of commonly encountered conditions will often leave many

other problems unanswered. The objective has been to select apparatus that will

give a reliable answer when applied to a variety of problems.

For compliance with regulations in the United States EPA method #5 is usually

required. Check with local authorities before using any lab method required for

compliance with environmental regulations.

157048 Procedures Page 1

PROCEDURES

INTRODUCTION

The procedures given in this section are general instructions which may serve as a

guide for each unit. They cannot be specific because of the variations in the design

and construction of each Fluid Catalytic Cracking Unit. These methods should be

used by each refiner to develop a detailed set of operating instructions for his

particular unit.

Although basic procedures will be fairly consistent from unit to unit, the FCC is such

a flexible process that several different strategies exist for operating an FCC unit.

Individual refinery requirements and product markets should be carefully considered

to determine the most economic strategy to employ for the FCC unit. These

procedures will cover the basic operating steps for startup, shutdown and

emergency situations. Specific operating strategies for maximum economic benefit

will be left to the individual refiner.

This section is divided according to topic. These subsections are:

A. Refractory Dryout -- Initial Startup B. Normal Startup C. Establish Normal Operating Conditions D. Normal Shutdown E. Emergency Procedures F. Catalyst Handling G. Special Operations

Throughout these procedures, references will be made to recirculation catalyst,

combustor and upper regenerator, which implies a high efficiency style combustor

regenerator, catalyst coolers, lift gas and alternate riser termination devices. Not all

units will have these features. Where not applicable to your specific unit, certain

steps in the procedures will not be followed. The basic principles for unit operation

are the same, however, regardless of the specific features of the unit. Refer to

Figures 1 through 3 for diagrams of the unit showing the key streams used in the

following procedures.

157048 Procedures Page 2

A. REFRACTORY DRYOUT -- INITIAL STARTUP

The startup operations on the FCC Unit require careful coordination and planning.

The reactor-regenerator, main column, and Gas Concentration Unit must all be

inspected to verify proper construction and that the equipment is ready for use.

Utility systems should be commissioned and all catalyst and required chemicals on

site.

All instruments must be calibrated and control valves ready for service. Inspection

and precommissioning work is covered in depth in the UOP FCC Operations

Manual. The startup procedures that follow assume all equipment is ready for use.

The protective refractory lining in the regenerator, riser, and parts of the reactor

must be cured and dried before it is used. Failure to do this properly can result in

premature failure of this important protection. The dryout procedure is time

consuming, but once the refractory has been cured and dried, subsequent startups

will use a shorter procedure.

Minor repair work to the refractory will not necessarily require a full high

temperature dryout, but sufficient time must be allowed for curing and air drying. In

all cases the refractory manufacturer's guidelines should be consulted.

The initial dryout isolates the reactor and regenerator from the main column at the

vapor line blind. The vapor line vent opened upstream of the blind is opened to

allow air flow from the reactor to atmosphere. Any work remaining on the column,

gas compressor and Gas Concentration section can continue while the dryout is in

progress.

After application, the refractory lining contains three types of water: free, absorbed,

and chemically bonded. The curing step at ambient conditions allows time for the

chemical bonding to be completed. The free water must then be removed slowly to

prevent rapid expansion to steam that could damage the refractory. The absorbed

water is removed more slowly during a longer, high temperature step. AlI of the

157048 Procedures Page 3

refractory must be cured and dried; be sure that air is directed to every part of the

reactor-regenerator system.

The dryout may be summarized as:

1. Controlled heating of regenerator and reactor with hold steps for water

removal.

2. Reactor-regenerator assembly field test for 24 hours.

3. Controlled cooling of regenerator and reactor.

The source of heat for the dryout may be the air blower and direct fired air heater,

as in the following procedure, or it may be supplied with internal local heaters. The

choice may be dictated by the particular vendor preference and/or availability of

suitable equipment.

Procedure

The following procedure is intended to supplement the refractory vendor procedure.

During the dryout, several hold periods are maintained at a constant temperature.

The time period for the hold may vary depending on the type and thickness of the

refractory lining. Where the vendor procedure calls for more conservative steps,

those steps should be followed. Should the following steps be more conservative

than the vendor, further discussion is warranted to confirm that the dryout will be

adequate. In all cases, the procedure of the vendor responsible for the

application/performance of the refractory shall govern.

1. Refractory Curing Step

a. The curing procedure shall begin immediately after installation and shall

last a minimum of 24 hours. For the 4" low density gunned lining in the

regenerator, water or membrane curing steps may also be included.

157048 Procedures Page 4

b. During the curing procedure, the temperature of the shell and lining shall

be kept above 60°F (16°C).

2. Refractory Air Drying

a. After curing, the refractory lining shall be tested by tapping with a one

pound hammer at one foot intervals over the entire lining surface. Any

voids or dry filled spaces will emit a dull sound and these areas shall be

removed and replaced.

b. After the 24 hour curing period, the refractory lining shall be air dried for

at least another 24 hours by natural or forced ventilation.

3. Preparation Steps for Dryout

a. Isolate the structure with blinds in the feed, torch oil, fuel or gas to the CO

boiler and air heater, steam to the riser and stripper, and reactor vapor

line.

b. Double block and bleed the riser blast points, flue gas quench nozzles

and all steam purge points.

c. Remove the blankoffs on the catalyst loading lines and the drain points in

the flue gas system.

d. Remove the blankoff on the vent nozzle on top of the reactor shell and

install a gate valve. Attach a pipe stack approximately six feet (two

meters) long to the valve for personnel protection.

This valve will only be used if the reactor vapor line vent does not pass

enough hot air to adequately heat up the reactor or if the riser termination

device is highly contained so that there is little or no air flow through the

reactor shell. Open the vapor line vent valve upstream of the vapor line

blind.

157048 Procedures Page 5

e. Connect the reactor skin thermocouples to a recorder for temperature

monitoring.

f. Open air purges to all instrument DA points and slide valve packing

glands.

g. Commission the steam systems of the flue gas cooler and catalyst cooler,

if present. Steam drum boilout procedures can be combined with the

dryout as long as the dryout procedure governs. The cooler tubes must

have circulating water flow for protection during the dryout.

h. Close the spent and regenerated catalyst slide valves. Check the blast

and sample connections on the catalyst standpipes and drain any free

water.

i. Open the snort valve on the main air blower discharge.

j. Prepare the direct fired air heater for firing. Prepare alternate internal

heaters if they are to be used.

4. Start the Main Air Blower

a. Follow the manufacturer's instructions for the air blower startup.

b. Begin closing the discharge snort valve, forcing air into the regenerator.

As the pressure of the regenerator rises, the power required to drive the

blower increases. Check the air blower's performance curve and keep the

machine out of the surge condition.

5. Refractory Dryout

a. Open the blast and sample connections on the catalyst standpipes and

drain any free water.

157048 Procedures Page 6

b. Follow the vendor's instructions for dryout or the following instructions, if a

suitable alternate is not available. Values given are approximate and to

be used as guidelines. Good judgment should be used for any situations

which deviate from the described steps.

c. Raise the temperature in the regenerator at a rate of 50°F (30°C) per

hour to 250°F (120°C). Adjust the regenerator pressure to control the air

blower discharge temperature. Hold at this temperature for a minimum of

12 hours. Open the recirculation catalyst slide valve and cooled catalyst

slide valve (if present), to ensure air circulates to all parts of the

regenerator.

d. As the regenerator is heating up, open the regenerated catalyst slide

valve to circulate air up the riser into the reactor. Vent at the reactor vapor

line vent and reactor shell if required. Raise the reactor temperature at

50°F (30°C) per hour to 250°F (120°C). Open the spent catalyst slide

valve to circulate air through the standpipe into the stripper. Air flow

should be primarily through the regenerated catalyst slide valve so that

the insulating refractory in the riser is heated thoroughly.

NOTE: It is important that the air blower is used only for initial dryout in

the reactor. For later startups, only steam should be used to

heat up the reactor. During operation, coke will form on the

reactor internals and walls. There is a real danger of damaging

oxidation or fire if this material is exposed to air at high

temperature.

e. For the cold wall regenerated catalyst standpipe, wye section and riser

with 5" high density vibracast refractory lining, the minimum hold period at

250°F (120°C) is 8 hours. It may be that some of this cold wall lining has

already been installed and dried out in the shop. In that case, the

remaining reactor lining will dictate the hold period required. For the 3/4"

abrasion lining in the upper riser and reactor vessel, the minimum hold

period at 250°F (120°C) is 4 hours.

157048 Procedures Page 7

f. After the 250°F (120°C) hold period, light the direct fired air heater and

raise the temperature in the regenerator and reactor at 50°F (30°C) per

hour to 650°F (350°C) and hold for 12 hours for 4" gunned lining, 8 hours

for 5" vibracast lining, or 4 hours for 3/4" abrasion lining. An operator

should be stationed by the air heater any time it is in service.

g. When the regenerator temperature reaches 500°F (260°C), start the

purge steam flows to the torch oil guns and nozzles, and any quench

nozzles, to keep them cool. The spent catalyst standpipe expansion joint

steam purge can also be started at this time.

h. While the reactor and regenerator are heating up, the equipment should

be checked for expansion problems. Completely inspect the vessels,

standpipes and structure every hour until the regenerator plenum has

reached its maximum, generally ~1200°F (650°C), and every two hours

thereafter. Check:

(1) That the equipment is free to expand and is not contacting any

structural members.

(2) That expansion joint tie rods are loose and not binding.

(3) That catalyst lines and standpipes are free to move.

(4) That small piping, especially instrument lines and electrical cables, is

not under strain.

i. During the 650°F (350°C) hold period is a convenient time to perform the

first hot bolting step. Systematically hot bolt the entire reactor-regenerator

section.

j. All slide valves should be hot stroked at all hold temperatures. Position

indicators should be checked with board readings and the valves checked

157048 Procedures Page 8

locally for free movement. Manual and handwheel operation should be

checked and any problems corrected.

k. Raise the regenerator temperature at 100°F (55°C) per hour to 1300°F

(700°C) or the highest temperature permitted by the air heater (may be

1200°F (650°C)). Raise the reactor temperature at 100°F (55°C) per hour

to 950°F (510°C).

l. Hold the regenerator temperature at 1250°F (680°C) or the highest

achievable for 12 hours for 4" gunned lining or 8 hours for 5" vibracast

lining.

m. When the regenerator temperature reaches 1000°F (540°C), begin hot

bolting the entire reactor-regenerator section again. Check for any

expansion related problems.

6. High Temperature Field Test of Reactor-Regenerator

At the end of the final refractory dryout hold period, a high temperature test is

conducted on the reactor, regenerator and interconnecting piping under

simulated low pressure operating conditions. The integrity of field welded and

bolted joints under the strains developed by the expansion of lines and vessels

is checked before putting catalyst and oil into the system. This test is only

conducted during the initial start of the unit.

a. Follow the procedure as described in the UOP Schedule A, Project

Specification 314, Reactor-Regenerator Assembly Field Testing

Procedure. The test can only be conducted after:

(1) The refractory linings in the regenerator, reactor and associated

piping have been fully cured and dried.

(2) The direct fired air heater lining has been cured and dried.

157048 Procedures Page 9

(3) Any expansion related problems discovered in the dryout have been

resolved.

b. The reactor should be held at 950°F (510°C) and the regenerator at

1200-1250°F (650-680°C) for a 24 hour period before the system

pressure is raised.

c. Begin closing the reactor vapor line vent valve and flue gas slide valve

and raise the reactor and regenerator pressure to approximately 28 psig

(2 kg/cm2) or to the value specified in the 314 Specification.

d. Hold the reactor and regenerator at these conditions for a minimum of 30

minutes. Check all flanges and joints in the system for leaks. Check the

entire structure for any expansion related problems.

7. Cooldown and Inspection

a. After the high temperature field test is completed, reduce the reactor

regenerator pressure back to the previous level.

b. Begin reducing the air heater outlet temperature at 100°F (55°C) per

hour. When the regenerator temperature reaches 500°F (260°C), stop the

steam purges to the torch oil guns and nozzles.

c. Shutdown the DFAH when the temperature control becomes erratic due

to low fuel gas flow.

d. Continue air flow through the vessels until the temperature is within 50°F

(30°C) of the blower discharge temperature and then shut down the main

air blower.

e. Open all manways and vents. Use fans or other air moving equipment to

cool the vessel internals to ambient conditions.

157048 Procedures Page 10

f. Remove the distributor flange at the bottom of the wye section to allow

inspection of the wye section.

g. Inspect all refractory linings in the catalyst system, including the reactor,

regenerator, riser, standpipes, cyclones, air heater, flue gas line and

orifice chamber. Lock each slide valve in position to prevent accidental

movement during inspection. Small hairline cracks will be present in the

refractory and do not present a problem. Large cracks greater than 3/8"

(10 mm) that extend all the way to the shell should be repaired.

h. For the final flange assembly before startup, glue ¼” of ceramic blanket to

the refractory retaining collars on all cold wall manways or blind flanges

before they are closed (see UOP standard specification 3-24-2 Figure 4).

B. NORMAL STARTUP

The normal startup of the unit can be divided into the following steps:

1. Steam out the reactor and main column, and heat up the catalyst section.

2. Heat up the fractionation section.

3. Load catalyst to the regenerator and heat catalyst.

4. Start the wet gas compressor.

5. Circulate catalyst between the reactor and regenerator.

6. Start oil to the riser.

7. Establish normal operating conditions.

157048 Procedures Page 11

It is assumed that the unit is cold and empty, and that all precommissioning

activities and refractory dryout have been completed. General guidelines are

given in these procedures and each refiner should develop specific startup

procedures for their particular unit. Variations from the steps given here are

acceptable as long as the basic intent is followed and safety matters are not

compromised.

1. Steam Out Reactor and Main Column

a. The following procedure starts from the condition that all equipment and

vessels are full of air. Steaming of the reactor and fractionation section is

used to free the unit of oxygen. The following items should be completed

before the steam out is begun:

(1) The unit must be completely flushed, all vessels and piping closed

up, all orifice plates and instrumentation installed, and all equipment

ready for startup.

(2) The reactor vapor line blind should be removed at this time (refer to

Figure 4). Some refiners prefer to leave this blind in place until later

in the startup sequence. This is acceptable but it is generally more

convenient to remove the blind now. The procedure following is

designed to use the reactor containing steam as a protection buffer

between the regenerator with air and the main column with

hydrocarbon.

(3) If the vapor line blind is out, the vapor line vent should be blocked

and blinded.

(4) Remove the blankoff from the main column high point vent and open

the valve a couple turns.

(5) Isolate the wet gas compressor at the suction and discharge lines.

Steam should not be allowed to enter the compressor.

157048 Procedures Page 12

(6) Line up backup nitrogen to the DG purge gas header and start purge

gas to the reactor instrumentation DG points.

(7) Make sure the regenerated and spent catalyst slide valves are fully

shut. All slide valves should be operational with hydraulic systems

commissioned.

(8) Low points from various equipment and piping should be prepared to

drain condensate as the steam out progresses.

b. Start steam to the base of the riser, to the feed distributors, to the reactor

stripper, and to the spent catalyst standpipe blast point. As the reactor is

purged and heated, steam will flow through the vapor line into the main

column. Continually drain condensate at the riser, reactor, stripper, and

main column low point drains. The spent catalyst standpipe blast point will

have to be used as a drain after the initial steaming is completed.

c. Start steam into the bottom of the main column and into the sidecut

strippers. Vent at the top of the main column and at the overhead

receiver. Do not run the condenser fans or water to the trim cooler during

this procedure.

d. Steam through the overhead receiver to the wet gas compressor suction

drum. Vent at the drum and drain condensate from low points. Steam

through the spillback lines and the interstage receiver but make sure the

compressor remains isolated. Connect steam hoses as needed if there is

trouble achieving a good steam plume from vents.

e. Continually drain condensate from all low points. As the vessels and

piping heat up, less steam will condense and the low points can be

throttled to match the condensate drain rate. Condensate collecting in the

overhead receiver water boot can be pumped out with the sour water

pumps.

157048 Procedures Page 13

f. When there is a good steam plume out the top of the main column, main

column receiver, compressor suction drum and interstage receiver for at

least two hours, the system should be free of air and the steamout is

complete.

g. A quick leak check should be conducted on the system. Throttle all vent

and drain valves to raise the pressure in the system to 10-12 psig (0.7-0.8

kg/cm2). Check all flanges, valve packings, etc. for leaks. It may be that

too much steam is condensed in the main column condenser to permit

building pressure for this leak test.

h. Check all low points to ensure that all water is drained. Verify that the

spent catalyst standpipe is being drained from the blast and sample

connection.

i. Start injecting fuel gas at the LCO stripper vapor return line. Raise the

reactor and main column pressure to 10-12 psig (0.7-0.8kg/cm2) before

reducing the steam injection. This will ensure that air is not drawn into the

unit as the steam condenses.

j. Close all vents and continue draining water from all low points. Never

leave a drain point unattended with fuel gas in the system.

NOTE: Fuel gas injection to the LCO stripper should be enough that the

pressure transmitter on the main column receiver will keep the

overpressure control valve to the flare open a small amount at all

times. This will ensure that any air that might enter the system

will be purged out to the flare. On older units which used air as

the purge gas to the reactor instrument taps, air from the DA

points in the reactor is carried by the steam flows to the main

column and receiver. If this air is not purged out, the

concentration of oxygen can build up in the receiver to a high

level.

157048 Procedures Page 14

k. The main column overhead condenser can be put in service to condense

the steam and build a concentration of fuel gas in the overhead receiver.

Fuel gas pressure must be adequate to ensure that a vacuum cannot

develop in any of the vessels. This is done in preparation for starting the

wet gas compressor.

l. The Gas Concentration Unit should be air-freed by steamout in parallel

with the reactor-regenerator-main column sections. The columns and

absorbers should be pressured with fuel gas at the conclusion of the

steamout. Drain any free water from all low points.

2. Start the Main Air Blower

a. Be sure all DA and DG purges and all instrumentation in the reactor-

regenerator section are in service.

b. Start the main air blower after the fractionation section is pressured up

with fuel gas. Refer to the manufacturer's instruction manual for the

blower startup procedure.

c. The differential pressure between the reactor and regenerator should be

maintained at a negative (reactor higher) 1.5 psig (0.1 kg/cm2). This will

ensure that any leakage through the slide valves will put steam into the

regenerator rather than air into the reactor.

NOTE: The steam in the reactor acts as a buffer between the

regenerator containing air and the main column which

contains some fuel gas. As long as the reactor pressure is

maintained as the highest level in the system, no

contamination of air and fuel gas can occur.

157048 Procedures Page 15

d. Open the recirculating catalyst slide valve and catalyst cooler slide valve

(if present) to allow heated air to flow up the standpipes to the upper

regenerator.

e. If the unit is equipped with a power recovery unit, follow the

manufacturer's instructions for starting flue gas to the expander turbine

f. Begin water circulation through the catalyst cooler tubes (if present) and

flue gas cooler tubes.

3. Light the Direct Fired Air Heater

a. When the flow from the main air blower has stabilized, light the direct fired

air heater according to the manufacturer's instructions.

b. Heat up the regenerator at a maximum rate of 200°F (110°C) per hour to

a target temperature of 1000°F (540°C).

c. Start fluidizing air to the upper regenerator fluffing rings and to the

catalyst cooler fluidizing lances (if present) at minimum flow.

4. Inventory the Fractionation Section with Oil

a. As the regenerator is being heated, the fractionation section can be

inventoried with oil to begin circulation and pumparound flows. During this

process the main column overhead should be maintained above 230°F

(110°C) to minimize steam condensation in the column. Fuel gas flow

should be maintained to the LCO stripper vapor return line so that a small

purge flow is maintained through the overhead receiver overpressure line

to flare.

b. Since LCO and HCO will be unavailable for flushing oil to the instruments

and the main column bottoms pump flushes (gland seal, wear rings and

throat bushing), the flush header should be commissioned with raw oil or

157048 Procedures Page 16

a light gas oil from outside the battery limits if the raw oil is very heavy.

When the LCO and HCO products become available, the flush systems

will be changed back to the proper stream.

c. Start raw oil feed through the startup filling line to the bottom of the main

column. The addition of cold feed into the column will condense some

steam since it passes countercurrent with steam over the disk and donut

trays. Therefore, add raw oil to the column slowly until the column is hot.

Pay special care to removing free water from the low points in all vessels,

exchangers and piping because sudden water vaporization can damage

equipment.

d. Slowly warm up the main column bottoms steam generators by backing in

steam through the bypass around the non-return valves. These steam

generators will be used to heat the raw oil in the main column.

e. Start the main column bottoms pump and send oil through one of the

steam generators. This circulation must be done slowly at first to avoid

cooling the bottom of the main column. Raise the raw oil outlet

temperature as high as possible, then start flow through the second

steam generator. Try to maintain the column overhead temperature high

enough to drive water overhead.

f. When the column bottom temperature has stabilized at its highest level

from the steam heating, slowly start bottoms circulation through the other

bottoms circulation loops. Circulate through the cold sections of the

system slowly until they are heated to avoid cooling the column bottom

excessively. Watch the bottoms level and bring in more raw oil as the

total bottoms circuit is inventoried. Start flow from the net bottoms pumps

through the startup line back to the raw oil charge pumps to complete the

loop. Check for water at the low points throughout the bottoms system.

This circulation and heatup will slowly dry out the bottoms system.

157048 Procedures Page 17

g. After the bottoms circuit is hot and dry with good circulation flows, check

for free water in the LCO and HCO system low points. Check that the

sidecut strippers inlet level control valves are fully closed. Start a small

flow of hot raw oil from the main column bottoms up to the LCO circuit

return line via the startup filling line. This will put hot oil into the upper part

of the column. When the LCO draw tray is full, it will overflow to inventory

to HCO section and then overflow back to the bottom of the column. Add

raw oil as necessary to maintain the bottoms level as the LCO and HCO

sections are inventoried. Keep the bottoms temperature as hot as

possible with the steam generators.

h. Drain all free water in the LCO and HCO circuits and slowly start oil flow

through the heat exchange circuits in the Gas Concentration Unit,

bypassing the exchangers. Check that the main column overhead

temperature is high enough to avoid steam condensation in the column.

Do not place the sidecut strippers into operation at this time.

i. Circulate oil flow through the LCO and HCO circuits until the lines are hot

and all free water has been removed. Maintain a small flow from the hot

bottoms circuit up to the LCO section to keep these sections hot and

overflow the draw trays back to the bottoms.

j. Inventory the main column receiver with startup naphtha. Don't start reflux

at this time as it will cool off the top of the column and cause additional

steam condensation.

k. This method of starting oil circulation tries to minimize water accumulation

in the fractionation section. It is very important to avoid circulating free

water back to hot sections of the column as the rapid water vaporization

could cause damage to the trays. All changes in operation and flows

should be made slowly and only after first draining any free water from

low points. Spare pumps should be drained and switched occasionally to

prevent water accumulation.

157048 Procedures Page 18

5. Prepare the Regenerator for Catalyst Inventory

a. The heating of the main column and the regenerator can be taking place

at the same time. The regenerator is being heated with the direct fired air

heater and steam is flowing through the reactor. Completely inspect the

reactor-regenerator structure every hour until the maximum air heater

outlet has been reached, around 1200°F (650°C), and once every two

hours thereafter. Check:

(1) That the equipment is free to expand and is not contacting any

structural members.

(2) That expansion joint tie rods are loose and not binding.

(3) That catalyst lines and standpipes are free to move.

(4) That small piping, especially instrument lines and electrical cables, is

not under strain.

b. When the regenerator temperatures reach 500°F (260°C), start purge

steam to the torch oil guns and nozzles, and any quench nozzles in the

upper regenerator. Commission the flue gas steam generator before the

temperature exceeds 500°F (260°C). Change air purges to packing

glands and expansion joints over to steam at 500°F (260°C).

c. As soon as the regenerator temperatures are above 450°F (230°C), the

differential pressure transmitter across the spent catalyst slide valve can

be placed in service. This transmitter should read the same as the

reactor-regenerator differential pressure transmitter as it is measuring the

same two pressures. If it does not, this is an indication that there may be

condensate in the spent catalyst standpipe. The water can either be

drained from the blast and sample point, or preferably, it can be slowly

drained into the regenerator where it will vaporize and exit with the flue

gas. Manually open the spent slide valve a small amount to continually

157048 Procedures Page 19

drain the standpipe so that water does not accumulate. The desired

situation is that all of the condensate is kept drained, and if drained into

the regenerator, it is done slowly so that when the water vaporizes, it will

not cause a large pressure surge in the regenerator which could push air

into the reactor.

d. When the air heater temperature reaches 600°F (315°C), start hot bolting

flanges and manways and systematically hot bolt the entire regenerator

and flue gas system. Repeat this procedure when the air heater

temperature exceeds 1000°F (540°C).

e. When the temperature in regenerator has reached 1000°F (540°C),

catalyst can be loaded. A certain temperature is not required to load

catalyst, but since the catalyst is cold and must be heated, it is best to

have the regenerator already hot when loading is started. The main air

blower should be set at the design rate or at the maximum firing limit of

the air heater and the air heater should be adjusted to the maximum

outlet temperature, typcially around 1200 – 1350 ºF (650 - 730°C). Since

heating the catalyst inventory is very time consuming, a high rate of hot

air flow is needed to help minimize this period. Close the recirculating

catalyst slide valve and the catalyst cooler slide valve (if present) before

loading catalyst.

f. Check that all instrument purges have been started and contain the

proper RO throughout the reactor-regenerator section. Check that all

regenerator level and density transmitters are functioning. Ensure that air

flow is going to the upper regenerator fluffing rings and catalyst cooler air

lances (if present).

g. Note that as catalyst is loaded into a high efficiency, combustor style

regenerator and the combustor density increases, the pressure in the

bottom of the combustor will increase. This will reduce the spent catalyst

slide valve P and it may be possible for air to flow back into the reactor.

If this P approaches zero reduce the regenerator pressure (with the

157048 Procedures Page 20

reactor-regenerator PDIC) to ensure the spent catalyst slide valve P

remains positive.

6. Loading Catalyst to the Regenerator

The initial load of catalyst into the regenerator should ideally be enough to

provide the total unit inventory. However, due to the size of the reactor and

stripper, this is usually not the case. The regenerator should be loaded with as

much catalyst as possible to high levels, then after catalyst circulation is

started and the reactor inventoried, additional catalyst will need to be loaded

into the regenerator.

The cyclone inlet velocities in the regenerator should be maintained greater than 35

ft/sec (11 m/sec) as much as possible to ensure good catalyst separation efficiency.

Lower pressure during heatup and catalyst loading can help increase the velocity

when the regenerator is cool. For bubbling bed and RFCC regenerators the

superficial bed velocity should not exceed 3 ft/sec (0.9 m/sec) during startup to

minimize catalyst loading to the cyclones.

a. Ensure that the following items have been accomplished before loading

catalyst into the regenerator:

(1) All slide valve P transmitters should be in service and the low P

override controller operable.

(2) Check that all instrument purges, slide valve packing purges, and

expansion joint purges are commissioned.

(3) Check that steam is not being used in the regenerated catalyst

standpipe, as any condensate will make mud when the catalyst is

loaded. Check the blast and sample point to make sure no

condensate is present.

157048 Procedures Page 21

(4) Make sure the catalyst cooler, regenerated catalyst and spent

catalyst slide valves are fully closed.

(5) Ensure that fluffing air is on to the upper regenerator rings and to the

catalyst cooler (if present). Water must be circulating through the

cooler tubes to keep them cool.

(6) Raise the feed atomizing steam to 150% of design rates to ensure

that any catalyst passing through to the riser can not plug the

distributors.

b. Prepare the catalyst hoppers for transferring catalyst. Refer to the specific

procedures outlined in the Catalyst Handling section. Gauge the hoppers

before starting to establish the initial catalyst inventory.

c. Start catalyst loading to the upper regenerator. Observe the level

instruments for signs that catalyst is accumulating. For a high efficiency

regenerator, open the recirculation slide valve a small amount to begin

circulation of catalyst to the combustor when a level is established and a

differential pressure appears across the recirculation slide valve. The

regenerator will begin to cool as cold catalyst is added. Keep the air

heater firing at its maximum temperature to help heat the catalyst.

d. For a high efficiency style regenerator, open the recirculation slide valve

further to increase the density in the combustor as the level increases in

the upper regenerator. The combustor density will remain low even with

the recirculation valve full open since there is no catalyst circulating

through the spent standpipe yet. If possible, try to establish a combustor

density of 4-7 lb/ft3 (65-110 kg/m3).

e. Near the end of the catalyst loading step, when a high level exists in the

regenerator and the combustor density is as high as possible with the

recirculation slide valve open, it is advisable to reduce the main air blower

rate to around 50% of design. This will cause the combustor density to

157048 Procedures Page 22

increase, thereby increasing the combustor catalyst inventory. The upper

regenerator level will drop, which allows additional catalyst to be loaded,

increasing the total catalyst inventory. Adjust the air heater firing when the

air rate is reduced so the maximum temperature is not exceeded.

f. At the completion of the catalyst loading step, gauge the hopper again to

determine the quantity of catalyst loaded.

7. Heat Up the Catalyst Inventory

a. As the cold catalyst is being loaded, it will cool the regenerator. Keep the

air heater firing at its maximum temperature to heat the catalyst. The rate

of heating the catalyst is not critical; the size of the catalyst inventory, the

speed of catalyst loading and the duty of the air heater will affect how fast

the temperature can be raised. A rate of 200-300°F (110-170°C) per hour

is a good target.

b. For a high efficiency regenerator, adjust the catalyst recirculation rate to

obtain a density of at least 4-7 lb/ft3 (65-110 kg/m3) in the combustor

during the heatup. Torch oil should not be fired if the combustor density is

less than 4 lb/ft3 (65 kg/m3). Excessive particle temperatures or

afterburning can result if sufficient catalyst is not available to absorb the

heat from torch oil firing.

For a bubbling bed regenerator or 2 stage, RFCC regenerator the catalyst

level should be a minimum of 1 ft (0.3 m) over the torch oil guns before

starting torch oil.

c. If torch oil is to be used to heat up the catalyst, the minimum temperature

at which it should be fired is 800-850°F (425-450°C). If an increase in the

combustor temperature is observed, the torch oil has ignited. If no

temperature change is observed, the torch oil has not ignited, and its use

should be discontinued until the catalyst temperature has been raised a

further 50°F (30°C). When using torch oil, adjust the torch oil atomizing

157048 Procedures Page 23

steam pressure to a minimum of 50 psig (3.5 kg/cm2). Control the

amount of torch oil to give a smooth even rise in temperature.

d. If a catalyst cooler is present on the regenerator, heating the catalyst will

take additional time, as the cooler will be taking some heat out as the

entire system is being heated. This is because water is circulating through

the tubes and the fluffing air is on. Water circulation is required to protect

the tubes and some air flow is recommended to keep the air lances clear

of catalyst. The minimum amount of fluffing air should be used throughout

the startup to minimize this heat removal effect.

e. When the regenerator circulating catalyst inventory has been heated to

900°F (480°C), catalyst circulation to the reactor can be started. Continue

heating the regenerator catalyst to a target value around 1250°F (675°C)

in preparation for cutting in feed.

8. Start the Gas Concentration Unit Wet Gas Compressor

In order to control catalyst circulation between the reactor and regenerator, it is

necessary to have a constant pressure on the main column. Starting the wet

gas compressor at this time allows a better control over the pressure and

removes this task from the very busy time when feed is cut in. However, it may

not be possible to start the compressor now if fuel gas supply is insufficient or

molecular weight is too low. In that case, pressure control is maintained as

before, with a fuel gas purge to the LCO stripper and venting to flare at the

overpressure control valve. The wet gas compressor can be started after feed

is started to the riser.

a. It is advisable to start the wet gas compressor early and have it operating

smoothly before circulating catalyst. Set the process controls in

preparation for compressor startup as follows:

(1) Set the main column overpressure control to hold the system

pressure at 10 psig (0.7 kg/cm2).

157048 Procedures Page 24

(2) Manually open both compressor spillback control valves and their

bypasses.

(3) Set the compressor speed control on manual at minimum speed or

open the suction valve fully.

b. Start the compressor interstage cooler fans and open the cooling water to

the trim cooler.

c. Increase the fuel gas makeup to the LCO stripper to provide an operating

cushion before starting the compressor.

d. Start the compressor auxiliaries and the compressor according to the

manufacturer's instructions.

e. Keep the compressor operating on total spillback until feed is charged to

the reactor. The discharge valve can be cracked open slowly to help

pressure up the gas concentration unit at this time but be careful to do

this very slowly so that the main column pressure is not sucked down

quickly.

9. Start Catalyst Circulation

The following procedure is general in nature and the specific arrangement of

the reactor and regenerator system needs to be carefully considered. The

velocity in the lift zone, upper riser and cyclones needs to be considered at all

times to ensure smooth catalyst circulation and to minimize catalyst losses.

For all types of riser terminations the velocity throughout the riser should

always be greater than 10 ft/sec (3 m/sec) when circulating catalyst. 15 ft/sec

(4.5 m/sec) is preferred. This will ensure smooth catalyst flow. When heating

up or circulating with steam only the heat demand and therefore the catalyst

circulation and cyclone loading is very low so that the cyclone efficiency is not

critical.

157048 Procedures Page 25

Once startup naphtha (if used) or feed is introduced to the unit the additional

heat required to vaporize the hydrocarbon increases the catalyst circulation

and therefore the cyclone loading quickly. Before starting these streams the

catalyst separation efficiency of the riser termination device and cyclones must

be increased to minimize losses to the main column.

For a direct connect, SCSS, VSS or VDS riser termination systems the cyclone

inlet velocity should be increased to 35 ft/sec (11 m/sec) or greater with the

startup steam to the wye before starting raw oil or startup naphtha to the riser.

Note that this velocity includes the stripping steam vapor flow. This is very

important for direct connect or SCSS systems. The vortex chamber on VSS

and VDS riser termination systems is less sensitive to changes in velocity than

other types of termination devices so that this is not as critical but it is still

recommended.

For vented risers the velocity out of the riser is critical for catalyst separation.

Catalyst should not be circulated with startup naphtha or feed with less than 35

ft/sec (11 m/sec) riser exit velocity. This velocity does not include the stripping

steam vapor flow.

a. When the regenerator has reached 900°F (480°C), the unit is ready to

start catalyst circulation. Temporarily stop the flow of oil from the MCB

circulation up to the LCO and HCO sections of the main column.

Shutdown the HCO and LCO circulation pumps if the inventory in these

sections is lost. When catalyst circulation is first started, it is possible that

catalyst can be carried into the main column. It is best to contain these

fines in the bottoms rather than having them spread through the LCO and

HCO circuits.

b. Check the spent catalyst standpipe for any condensate. Crack open the

spent slide valve occasionally to drain condensate into the regenerator.

The P controller for the reactor and regenerator should be set at a

negative (reactor higher) 1.5 psig (0.1 kg/cm2) or more if required to keep

the spent catalyst slide valve P positive to provide a steam buffer

157048 Procedures Page 26

(reactor) between the air in the regenerator and hydrocarbon in the main

column.

c. Set the lift and/or startup steam to the wye to maintain a velocity of 15

ft/sec (4.5 m/sec) throughout the riser. If sufficient fuel or natural gas is

available, lift gas flow can be started to help reduce the steam

requirement. This flow can come from the normal lift gas source (sponge

absorber) as recycle if the wet gas compressor is operating, or can be

piped in externally and vented at the main column overhead receiver if

the compressor is not operating.

d. Feed steam to the Optimix feed distributors should be set at 150% of

design to ensure that catalyst can not plug the nozzles.

e. Adjust the stripping steam and fluffing steam flows to design rates.

f. Check the P across the regenerated catalyst slide valve and blast the

standpipe with air if there is low or no P. Slide valve differential

pressures will be erratic at low catalyst circulation rates.

g. Start opening the regenerated catalyst slide valve with the reactor

temperature controller in manual. Closely watch the reactor temperature

which will rise as soon as catalyst begins to circulate. If no response is

observed after several minutes, blast the regenerated catalyst standpipe

again.

h. The catalyst circulation from the reactor back to the regenerator should

be started as soon as possible to minimize any potential mud formation

(catalyst + condensate) in the spent catalyst standpipe. Do not wait until

the reactor level is fully established to start catalyst flow to the

regenerator. As soon as catalyst creates an increasing P across the

spent slide valve, open the valve on manual to start returning catalyst to

the regenerator. If the P does not increase across the valve, blast the

standpipe with steam.

157048 Procedures Page 27

i. The reactor level should be increased without delay, particularly if the

cyclone diplegs are to be submerged in the catalyst bed. It is possible that

some catalyst can be lost to the main column before the diplegs are

submerged, but if the stripper level is raised smoothly and quickly,

catalyst losses will be minimized. It is important that a good flow of

catalyst is leaving the stripper back to the regenerator during this period.

On units without submerged diplegs the level may be increased more

slowly.

j. As the reactor stripper level is increased, it may be necessary to bring in

more catalyst from storage to maintain levels in the regenerator. On units

with submerged diplegs this should be done before the stripper level

approaches the bottom of the diplegs. The catalyst level should never be

held just below the diplegs for any reason as it is possible to create a

vacuuming action through the cyclones if the seal is lost and draw

catalyst up the diplegs and out to the main column. Once the catalyst

level approaches the diplegs, they should be submerged as quickly as

possible.

k. Place the reactor level controller on automatic as soon as possible. The

reactor temperature controller should be maintained in manual.

10. Raise Reactor Temperature

a. As catalyst circulation is started, raise the reactor temperature smoothly

at a rate of 200-300°F (110-170°C) per hour. For certain reactor

configurations, it may be important how fast the skin temperatures are

increased. In some cases, special guidelines will be specified. It is useful

to record the reactor skin temperatures during the heatup for future

reference and analysis of developed stresses during the thermal

expansion.

157048 Procedures Page 28

b. When the reactor temperature has reached 600°F (315°C), startup

naphtha flow can be started to the riser. Startup naphtha may be used to

increase the catalyst flow and open the slide valves further for better

control. It smoothes the transition when feed is cut into the riser. It also

aids in wetting the main column trays with hydrocarbon and helps

displace water in the main column. Startup naphtha is an optional step in

the procedure. Any type of light naphtha, straight run or cracked, can be

used.

Increase the startup steam to achieve a cyclone inlet velocity of 35 ft/sec

(riser outlet velocity for vented riser terminations) before starting naphtha

flow to ensure that the separation efficiency is good as the catalyst

circulation rate and cyclone loading will increase significantly with the

heat required to vaporize the naphtha. As the naphtha is vaporized and

the cyclone (or riser outlet) velocity increases the startup steam may be

reduced.

Add additional naphtha to the main column overhead receiver as needed.

This naphtha will be recycled through the main column, to the overhead

receiver, back to the riser. Keep raising the reactor temperature at the

specified rate when naphtha is added.

c. It is important that the bottom of the main column be maintained as hot as

possible during the reactor heatup to prepare for eventual cracked

product flows. The steam generators should be used to heat the bottoms

and maintain at least 350°F (175°C) in the bottom of the column. A high

temperature will ensure that all water and much of the naphtha is driven

overhead to minimize the accumulation in the column.

d. Continue to heat up the regenerator catalyst inventory to 1250°F (675°C)

as the reactor temperature is increased. Torch oil can be used to maintain

this temperature while the reactor is being prepared for starting feed.

Make sure the combustor density is maintained above 4 lb/ft3 (65 kg/m3)

157048 Procedures Page 29

when torch oil is fired (or the level is maintained above the torch oil guns

in a bubbling bed or RFCC regenerator).

e. At some point after stable catalyst circulation has been established, and

both spent and regenerated catalyst slide valves have good P across

them, the reactor-regenerator P controller can be adjusted to a positive

value (regenerator pressure higher) to help balance the two slide valve

P's. Make sure the slide valve low P override controllers are

commissioned.

f. Increase the reactor temperature to a target point around 980°F (525°C)

and the regenerator temperature to ~1250 – 1300 ºF (675 - 705°C).

Maintain stable catalyst flow and levels before starting feed to the riser.

11. Charge Oil to the Reactor Riser

Feed can be started to the riser as soon as the preceding operations have

been stabilized.

a. Stop backing steam into the main column steam generators and fill them

with boiler feed water to prepare for eventual heat removal/steam

production. This should be done slowly to avoid excessive thermal shock

when the tubes are changed from hot steam to cooler BFW.

b. Set the feed flow through the bypass valve to the main column at

approximately 10% of design charge rate. The flow may be lined up

through the main column bottoms recycle flow meter. The bottoms

recycle meter is convenient to use for starting feed to the riser because

the normal feed control valve is too large to accurately control such small

flows.

c. Feed steam should be set at 150% of design. Stripping steam and fluffing

steam flows should be at design.

157048 Procedures Page 30

If startup naphtha is in service the cyclone inlet velocity (riser outlet

velocity for vented risers) should already be greater than 35 ft/sec (11

m/sec).

If startup naphtha is not used then the startup steam rate should be

increased to achieve a cyclone inlet velocity (riser outlet velocity for

vented risers) of 35 ft/sec (11 m/sec) or greater.

d. Prior to starting feed to the riser, be sure to drain all free water from the

feed line between the diverter valve and the feed nozzle block valves.

Start feed to the riser by switching the feed bypass switch to the normal

position. This will close the valve on the line to the main column and open

the line to the riser. Begin opening the regenerated catalyst slide valve

further at the same time to provide the additional heat required to

maintain riser temperature and velocity.

NOTE: Start feed very slowly at first to avoid thermal shock to the feed

distributor tips. The feed distributor tips can be cracked if

subjected to excessive thermal shock.

When cutting in oil, catalyst circulation must be increased to

maintain the reactor temperature. Do not allow the temperature

to drop below 930°F (500°C). Should the reactor temperature

drop too low, feed can be reduced until the temperature is

increased again. Initially, the regenerator temperature may drop

until catalyst containing coke enters the regenerator. Try to

maintain the combustor temperature around 1250°F (675°C).

e. Begin increasing the feed rate smoothly in increments of 10-20% through

the normal feed control valve. As the feed rate is increased, startup

naphtha can be smoothly backed out. The lift steam rate can also be

reduced. It is best to wait until the feed rate is up to 40-50% before

beginning to reduce the startup naphtha and startup and feed steam

157048 Procedures Page 31

rates. The reduction should be done gradually so that riser velocity does

not suddenly drop.

f. As the circulation of relatively cool catalyst from the reactor to the

regenerator increases the regenerator temperatures will decrease

temporarily until spent catalyst with coke has displaced the clean catalyst

in the stripper. Additional torch oil will be required to keep the regenerator

temperature at 1250 –1300 ºF (675-705 ºC)

When spent catalyst starts entering the regenerator and the coke starts

burning the regenerator temperatures will increase. Torch oil flow can be

reduced and eventually stopped. The air heater firing can also be reduced

and eventually stopped. The combustor temperature should be

maintained around 1275-1300°F (690-705°C). The regenerator upper

dense bed temperature should be slightly higher than the combustor.

g. Continue increasing the feed rate smoothly in 5-10% increments to the

design value. During this time, gradually increase the air rate to the

regenerator as necessary. Adjust the reactor-regenerator P controller as

needed to balance the spent and regenerated catalyst slide valve P's.

157048 Procedures Page 32

C. ESTABLISH NORMAL OPERATING CONDITIONS

At the completion of the unit startup, stabilize the unit operation using the following

process control guidelines:

Reactor Variables Control

Raw Oil Charge Rate As desired.

Raw Oil Preheat Temperature Set to balance coke yield, conversion, and

gasoline RON requirements.

Lift Steam

And

Lift Gas

Total flow set to achieve optimum lift zone

velocity, typically 10-20 ft/sec (3-6 m/sec).

Flows may be used in any ratio depending on

wet gas compressor, main column overhead

or sour water stripping constraints. Lift gas is

beneficial for metals passivation in units with

high nickel on Ecat (>3000 wppm)

Feed Steam Typically 1-2 wt% of design feed rate. Should

be adjusted to optimize yields. May be used

at high flow rates during startup and

emergencies.

Reactor Temperature Adjust to obtain desired conversion, yield

pattern, coke yield and gasoline RON.

Reactor Pressure Indirectly set by main column receiver

pressure.

Reactor Catalyst Level Set to cover the top stripping grid or to seal

the diplegs in units with submerged primary

cyclone diplegs.

157048 Procedures Page 33

Reactor Variables Control

Stripping Steam Use just enough to strip the catalyst of

residual hydrocarbons. Typical rate is 1.7-2.5

lb (kg) per 1000 lb (kg) of catalyst circulation.

Adjust by observing effect of changes on

regenerator temperature.

Main Column Bottoms Recycle Normally zero. During turndown or when light

feeds are processed, some recycle may be

necessary to increase coke and help the unit

heat balance.

Naphtha to Riser Used to assist catalyst circulation during

startup and to help control the regenerator

temperature when the unit is behind in

burning (old style unit – partial combustion

operation).

HCO Recycle For units operating in maximum distillate

production, used to increase coke yield or

improve LCO yield.

157048 Procedures Page 34

Regenerator Variables Control

Combustion Air Rate Adjust for sufficient air to burn all coke off

spent catalyst. Maintain 1-2% excess oxygen

in the flue gas for full combustion units.

Typical value for full combustion is 14 lb (kg)

air per lb (kg) coke. The air/coke ratio on

partial combustion units is lower and is

adjusted to control the heat of combustion.

Combustor Temperature Adjust for proper coke and CO combustion

and minimize afterburning. Typical value

1275°F (690°C) minimum.

Combustor Density Adjust to optimize coke and CO combustion.

Normal value between 5-10 lb/ft3 (80-160

kg/m3).

Regenerated Catalyst

Temperature

Function of coke operation. May be

influenced by catalyst cooler if present.

Dense bed normally 20-50°F (10-30°C)

above combustor temperature. Dilute phase

normally 10-20°F (5-10°C) above dense.

Reactor-Regenerator

Differential Pressure

Adjust to obtain stable and balanced spent

and regenerated catalyst slide valve P's.

Slide Valve P's Dependent on reactor-regenerator pressure

and catalyst levels. Normal values between 5-

12 psi (Low pressure over-ride typically set

about 2 psi (0.14 kg/cm2).

157048 Procedures Page 35

Regenerator Variables Control

Upper Regenerator Catalyst

Level

Adjusted by additions and withdrawals to

maintain a suitable catalyst surge capacity for

the unit.

Torch Oil Rate Used during startup to aid in catalyst

inventory heatup. The use of torch oil should

be minimized for the protection of the

catalyst.

Air to Catalyst Cooler Used to control the catalyst cooler duty and

therefore the regenerated catalyst

temperature. A minimum air rate of 10-20% of

design should be maintained at all times. The

maximum air rate specified for the cooler

should never be exceeded. On flow through

catalyst coolers the air rate can be adjusted

to keep the cooled catalyst slide valve in a

good operating range.

Catalyst Cooler Slide Valve A secondary control for adjusting heat

removal. Can be used to limit T across

cooler to about 200°F (100°C).

157048 Procedures Page 36

Fractionation Section Variables Control

Main Column Receiver Press Adjust as required by the reactor-regenerator

P, and the relative main air blower discharge

pressure and wet gas compressor suction

pressure.

Overhead Receiver Temp Generally maintained around 110-120°F (40-

50°C).

Main Column Top Temperature Set to control the endpoint of the unstabilized

gasoline.

Main Column Reflux Rate Controlled on cascade by the overhead

temperature controller. Reflux rate is set by

the overhead condenser duty required to heat

balance the column after the duty of the lower

pumparound streams are set. Primary

adjustment is with the MCB steam

generators.

Heavy Naphtha Product Draw

Rate

Set to control the draw temperature and

endpoint of the heavy gasoline product.

LCO Product Draw Rate Set to control the LCO draw and LCO product

endpoint or to control the MCB temperature.

Cycle Oil Circulation Rates Set by the process requirements of the

associated heat exchangers.

157048 Procedures Page 37

Fractionation Section Variables

Control

Main Column Bottoms Circulation

Rate

Adjust flow to steam generators to balance

the main column heat removal and set

overhead reflux flow. Minimum total flow back

to column must satisfy disc and donut liquid

rate of 6 gpm per ft2 (15m3 per m2) of column

area..

Main Column Bottoms Temp Controlled primarily by the LCO product draw

rate. Quench from the steam generators may

be used to subcool the liquid in the bottom of

the column. Maximum bottoms temperature is

generally ~680ºF (360ºC) but is dependant on

feed type and reactor severity.

Unstabilized Gasoline Yield Depends on charge rate and conversion.

Controlled by the level in the overhead

receiver.

Main Column Bottoms Product

Rate

Adjust to control the main column bottoms

level.

Cycle Oil Stripping Steam Rate Adjust for product flash point specification.

Net Overhead Gas Flow Depends on charge rate, reactor severity and

catalyst condition. Controlled by the wet gas

compressor speed or spillbacks to control the

main column overhead receiver pressure.

Flush Oil Adjust as required to keep catalyst out of

instruments, and flush the main column

bottoms pump packing gland and wear rings.

157048 Procedures Page 38

D. NORMAL SHUTDOWN

The shutdown of the FCC Unit is essentially the reverse of the startup steps. It

should be carried out in an orderly and planned sequence. Some main points to

remember are:

1. Maintain good catalyst fluidization and circulation through the reactor and

regenerator throughout the shutdown. Increase riser steam to ensure

smooth catalyst circulation.

2. Always decrease the charge rate before decreasing the air rate. Maintain

excess oxygen in the flue gas at all times and keep the regenerator hot to

ensure the catalyst is fully regenerated.

3. Make sure all pumparound circuits are flushed out to eliminate problems

with heavy oils or catalyst fines.

During scheduled shutdowns, the catalyst section and the main column exchanger

circuits will usually be inspected and cleaned. Depending on the work to be done,

the main column might have to be water washed for entry. The Gas Concentration

Unit will be pumped out and purged with steam. If columns are to be entered, they

will need to be water washed.

Precautions must be taken to cool the reactor sufficiently before allowing air to enter

the vessel. This is done to guard against the possibility of auto-ignition of hot coke

deposits in the reactor or vapor line. The reactor should be cooled below 350°F

(175°C) before any manways or nozzles are opened. Riser and stripping steam

should be used to assist cooling the vessel as required.

The following procedure describes a full shutdown for maintenance entry to vessels.

Depending on the reason for the shutdown, the full procedure may not be followed,

and catalyst may or may not be left in the regenerator. In most cases, catalyst will

be transferred from the reactor to the regenerator during a shutdown. These

157048 Procedures Page 39

procedures should be considered only guidelines. Detailed shutdown instructions

should be prepared by the refiner for his specific unit.

If the shutdown is temporary, the unit may be maintained in an operating mode and

catalyst circulation continued. However, circulating hot catalyst on steam for long

periods of time will damage the catalyst. Therefore, if the shutdown will be for

several days, it is usually best to stop catalyst circulation.

Procedure

1. Notify offsites and utility systems well in advance that the FCC Unit will be

shutting down. Prepare the regenerator by withdrawing catalyst to drop

the upper regenerator level to a low value. This will make room for the

eventual transfer of the catalyst in the reactor and reduce the time

needed to unload the unit catalyst inventory.

2. Slowly begin reducing the reactor temperature to 900°F (480°C). At the

same time, begin reducing the naphtha and LCO product flows. This will

make the main column bottoms material lighter, aiding in flushing out the

bottoms circuits.

3. The regenerator temperatures will begin to drop when the reactor

changes are made. Adjust the recirculation catalyst and catalyst cooler to

keep the combustor hot, around 1250°F (675°C), to ensure all coke is

burned off the catalyst.

4. Maintain the main column bottoms level low around 30%. Control the

level by drawing more or less bottoms product to storage.

5. Begin decreasing the raw oil charge rate in increments of 5 to 10% to

50% of design. For full combustion units decrease the combustion air rate

as the charge is reduced, but always maintain excess oxygen in the flue

gas (2-5% provides a good safety margin) and good cyclone velocities.

On partial combustion units reduce the air rate to control the heat of

157048 Procedures Page 40

combustion and move towards full combustion as the regenerator

temperature drops. Control the regenerator temperature at 1250-1300ºF

(675-705ºC). Maintain balanced main column heat removal and product

draw temperatures by decreasing pumparound circulations and product

flows as required.

6. As the raw oil charge rate is reduced, increase the lift steam and the feed

steam to assist catalyst circulation. Begin reducing the reactor pressure to

increase vapor velocity in the riser and the cyclones. Lift gas flow to the

riser may need to be reduced as the gas production is decreased. When

control of the lift gas becomes difficult or unstable, shutdown the flow and

block in the control valve.

7. As the coke make decreases, the regenerator will cool off. Reduce the

catalyst cooler air rate and begin closing the cooled catalyst slide valve.

The slide valve may be closed completely but do not stop the fluidizing air

until catalyst is removed from the regenerator. Fire the air heater when

needed to hold the combustor temperature at 1225-1250°F (665-675°C).

Torch oil may be used but should be avoided if possible due to its harmful

effect on the catalyst.

8. The main column overhead gas production will decrease as the reactor

temperature and charge rate are decreased. Check that the spillback

valves for the wet gas compressor remain in a controlling range. Start fuel

gas flow into the LCO stripper vapor return line if needed to maintain main

column pressure control as the unit is shut down.

9. Slowly decrease the reactor-regenerator P controller to a negative value

(reactor pressure higher than the regenerator) in preparation for cutting

feed. This is intended to create a higher pressure buffer of steam in the

reactor between the air in the regenerator and hydrocarbon in the main

column.

157048 Procedures Page 41

10. Prepare to bypass feed from the riser. Make sure the main column has a

low level in the bottom. Keep the regenerator at a lower pressure than the

reactor and put the regenerated catalyst slide valve on manual control.

Increase riser steam to maintain catalyst circulation, bypass raw oil to the

main column, and reduce the flow of oil. Keep raw oil flowing in and out of

the main column until it is verified that any catalyst carried over to the

column during shutdown has been flushed out.

11. With the catalyst circulating on steam, begin dropping the reactor level to

transfer catalyst into the regenerator. Begin withdrawing catalyst from the

regenerator to the hopper to make room for the reactor inventory. Start

decreasing the air heater outlet temperature at 100-200°F (50-100°C) per

hour. When the regenerator temperatures have dropped below 1000°F

(540°C) close the regenerated catalyst slide valve and stop circulating

catalyst to the reactor. Maintain steam flow to the riser.

12. When oil is bypassed from the reactor, the gas make will decrease very

rapidly. Shutdown the wet gas compressor according to the

manufacturer's instructions and block it in. Nitrogen purge the compressor

casing.

13. After the wet gas compressor is shut down, block in the pressure

controller on the sponge absorber overhead line. Pressure as much liquid

as possible back to the main column or to the debutanizer from the other

gas concentration columns. After all the liquid is pumped out, depressure

the columns to the fuel gas system. When the fuel gas header pressure is

reached, depressure the remaining gas to flare.

14. As the main column starts to cool, stop the withdrawal of naphtha and

LCO to the sidecut strippers. The naphtha and cycle oils will then

overflow their accumulators, wash down the column, and dilute the

bottoms material. Open the bypass on the net bottoms product to the raw

oil line and start bottoms circulation as during startup. Switch the flushing

header source from LCO/HCO to the raw oil line. When the column and

157048 Procedures Page 42

bottoms circuit is adequately flushed, pump out all circuits, the sidecut

strippers, and the column bottoms. Shut down the flushing headers.

When the column is empty, depressure it to flare. Pump out the overhead

receiver to the primary absorber column. Steam out the raw oil charge

line, the heat exchange train, and the reactor bypass line to the main

column from the raw oil pump discharge.

15. When all the catalyst has been transferred from the reactor into the

regenerator, close the spent catalyst slide valve. Lock both slide valves

closed. Unload catalyst from the upper regenerator to the hopper. Open

the recirculation and cooled catalyst slide valves to drop catalyst from the

standpipe and cooler into the combustor, where it will be carried back to

the upper regenerator. When all the catalyst is removed from the

regenerator, close the unloading valves, shut off the air heater and blind

the fuel gas line. Continue cooling the regenerator with the main air

blower. When the regenerator temperatures are slightly above the blower

discharge temperature, the air blower can be shutdown.

16. Connect vacuum hoses to the catalyst unloading connections throughout

the catalyst section and systematically clean out any remaining catalyst.

Vacuum catalyst from the unloading nozzles provided at the air heater,

the bottom of the riser, the bottom of the reactor stripper cone, and the

upper regenerator cone. When cleaning the reactor riser, the regenerated

catalyst slide valve should be temporarily opened to unload any

remaining catalyst from the regenerator standpipe.

17. When the main column is empty, start steam to the bottom and stripping

steam to the sidecut strippers. Be sure fuel gas to the LCO stripper is

shutoff and blinded. Maintain steam flow to the riser, feed distributors and

reactor stripper. Open the vents on top of the main column and overhead

receiver, and drain condensate from the low points.

18. When the reactor and main column are hydrocarbon free, decrease the

riser and column bottoms steam flows until only a trace is showing at the

157048 Procedures Page 43

drains located at the vapor line blind. Remove the blind in the vapor line

vent, open the vent and install the vapor line blind. Increase the steam

flows and continue to steam out for several more hours. Drain

condensate from all low points.

19. Connect steam hoses and steam out all pumparound circuits. Drain

condensate from low points When the steamout is completed, be sure

vents and drains are fully open before stopping steam to avoid pulling a

vacuum.

20. When the main column has cooled to 100°F (40°C), start plant water to

the overhead receiver. Start the reflux pump and send water to the top of

the column. Drain at the bottoms and low points. When water flushing is

complete, blind where required for entry.

21. When the gas concentration columns are empty, steam out the unit as

required. Any column which will be opened for entry should be water

washed after steaming.

22. When the reactor and regenerator have cooled to 300°F (150°C), the

manways can be opened to ventilate and cool the vessels. Install air

movers as required. Note that when the reactor and regenerator are

entered, hot catalyst can still be present, particularly in any diplegs which

are closed by their flapper valves.

23. Install blinds to isolate all vessels to be entered. A specific blind list

should be prepared for each particular unit.

157048 Procedures Page 44

E. EMERGENCY PROCEDURES

Emergencies on an FCC Unit may come in many forms. The operator must first

recognize the problem and then take quick action. Response will depend to a large

extent on plant design and individual features, the potential danger from the event,

and specific circumstances present at the time of the event. As it is impossible to

foresee every potential situation, operator judgment, anticipation and training are

key components for handling emergencies successfully. The best protection is a

thorough understanding of the process, the equipment and the potential dangers

involved.

The most important aspect of any emergency situation is how to make it safe;

personnel safety, environmental safety, and equipment safety are the major

objectives for any emergency handling program. Once the safety issues are under

control, then the less important concerns, such as maintaining or restoring unit

operation can be addressed.

Most FCC Unit emergencies will eventually involve a fundamental decision: should

raw oil charge to the riser be stopped for a period of time to correct the problem? If

this action is necessary, the basic steps to keep in mind are:

1. Increase lift steam, feed steam and stripping steam.

2. Bypass raw oil to the main column and stop lift gas.

3. Establish a negative reactor-regenerator pressure differential (reactor at

higher pressure).

4. Reduce the reactor pressure if possible.

These steps remove the hydrocarbon from the reactor, establish a steam

barrier between the regenerator and the main column, and maintain good

vapor velocity in the riser to assist catalyst circulation. Once these conditions

are established, the problem area can be investigated and corrected.

157048 Procedures Page 45

It is emphasized that every emergency situation must be handled individually

depending upon the conditions existing at that particular time. The following

procedures must be considered as only guidelines which are not unit specific. Each

refiner is responsible for preparing a detailed set of procedures, specific to his unit,

for handling any type of emergency event.

1. Oil Reversal

This is one of the most severe emergency events which can develop on the

FCC unit, but thanks to built-in safety features in the design, is a very rare

event in today's modern unit.

A reversal can develop due to a sudden increase in reactor or main column

pressure, or a sudden decrease in regenerator pressure. The higher pressure

in the base of the riser can cause oil to backflow up the regenerated catalyst

standpipe into the regenerator. Once in the regenerator, the oil will burn

rapidly, resulting in extremely high temperatures. A severe reversal can cause

temperatures to exceed 2000°F (1100°C), well over the design temperature of

the regenerator internals. Fortunately, today's slide valves are designed to

close within 5 seconds and if the valve low P override is in service, the

amount of oil which could potentially reach the regenerator is considerably

reduced.

If a reversal occurs, the following actions should be taken:

a. Bypass the raw oil charge, increase steam to the riser, increase feed

steam and close the regenerated and spent catalyst slide valves. Adjust

the reactor-regenerator P to a negative value (reactor pressure higher)

and reduce the reactor pressure. Stop lift gas and block in the control

valves.

b. Check the regenerator temperatures. If they pass 1400°F (760°C),

decrease the combustor air rate. Increase fluidizing air to the catalyst

cooler and open the cooler slide valve to help remove heat.

157048 Procedures Page 46

c. If the regenerator temperatures continue to rise, start a small circulation

of catalyst to the reactor. This will help remove some of the heat from the

regenerator. However, do not allow the reactor temperature to exceed

1000°F (540°C).

d. If it is not possible to circulate catalyst with riser steam, decrease the air

rate as much as possible and wait for the oil to burn off and temperatures

to drop. Do not shutdown the air blower if it can be avoided, as a lengthy

unit shutdown may develop to clean coke out of the regenerator. Monitor

and record regenerator temperatures every five minutes.

e. Add fuel gas to the LCO stripper to maintain main column and reactor

pressure. Shutdown the wet gas compressor if necessary and control the

pressure from the overhead receiver overpressure control valve.

f. If it is expected that raw oil feed will be stopped for a long period, begin

pre-startup main column bottoms circulations. When temperatures drop

below 1300°F (700°C) in the regenerator, start increasing the air rate and

internal catalyst circulation. Use the air heater or torch oil if necessary to

hold the catalyst at 1200°F (650°C), then continue with the unit restart per

the normal procedures.

2. Behind in Burning / Afterburning

While not necessarily an emergency, getting behind in burning or afterburning

can develop into one if not recognized and addressed.

The high efficiency regenerator is designed for complete CO combustion and a

small percentage of excess oxygen should always be maintained to avoid

getting behind in burning. However, although extremely difficult, it could be

possible that some sudden and unusual feedstock changes might cause this

problem to develop. A conventional unit operating in partial combustion is the

typical situation where behind in burning is a concern.

157048 Procedures Page 47

It is essential that the coke be burned off the catalyst at the same rate it is

produced. This is easily achieved in full CO combustion by maintaining a small

amount of excess oxygen in the flue gas. In partial CO combustion, however,

excess oxygen is not present and the burn characteristic is represented by the

CO2/CO ratio. It is much easier to change the coke production fast enough to

exceed the oxygen availability in partial combustion. When all the coke is not

burned, the unit gets "behind in burning" with the result that coke begins to

accumulate on the catalyst. The catalyst may turn dark gray or black in color

and will start to lose activity, causing a drop in conversion. Coke formation in

the reactor will continue and the overall coke accumulation on the catalyst can

snowball, eventually forcing feed to be bypassed.

Afterburn can be defined as CO combustion in the regenerator dilute phase.

There will always be some minor degree of afterburn and it is not a problem

until it becomes excessive. It is undesirable because there is little catalyst

present in this area to absorb the heat and very high temperatures can

develop.

Signs that the unit is behind in burning are:

a. The temperature difference between the regenerator dilute phase and the

dense bed is less than usual, and

b. The catalyst is noticeably darker in color.

The following actions should be taken to catch up in burning:

(1) Increase the air rate to the regenerator. Take care, however,

because when the extra coke is burned off, there will be an

increasing amount of excess oxygen in the regenerator and

afterburning may occur. To avoid this, air rate increases should be

made gradually.

157048 Procedures Page 48

(2) Increase internal catalyst circulation through the recirculation slide

valve.

(3) Monitor the regenerator temperatures to make sure the dilute phase

and flue gas temperatures are increasing.

(4) Draw frequent regenerated catalyst samples. Compare these to

check that the catalyst is becoming whiter, indicating that the

accumulated coke is gradually being burned off. This is the only way

to know for sure if the problem is being resolved.

(5) In the event that increasing the air rate does not correct the problem,

reduce the reactor temperature, drop the raw oil charge rate, and/or

start naphtha quench to the riser.

An afterburn problem is indicated by the following:

a. Increasing T between the regenerator dilute phase and the dense bed.

b. Increasing regenerator dilute phase temperature.

The following actions should be taken to reduce the afterburn:

(1) Increase the combustor temperature by increasing the catalyst

recirculation rate.

(2) Increase the combustor density by increasing the catalyst

recirculation rate.

(3) Increase the regenerator pressure if possible.

(4) Add CO combustion promoter or increase the rate of promoter

addition.

157048 Procedures Page 49

(5) For a conventional bubbling bed regenerator, increase the

regenerator catalyst level.

3. Circulating Water Pump Failure

This procedure is in reference to the loss of the flue gas cooler circulating

water flow and the catalyst cooler circulating water flow. This could also be

caused by a loss of the boiler feedwater supply.

a. Switch to the spare pump if this has not automatically occurred from the

low flow switch auto-start control.

Flue Gas Cooler:

b. If the flue gas cooler circulating water cannot be restored, bypass oil from

the riser immediately. This is required to prevent high temperatures in the

flue gas cooler tubes and downstream piping. The maximum allowable

temperature for the cooler tubes is usually 700°F (370°C).

c. Increase lift steam and feed steam to the riser to maintain reactor

pressure so that air cannot enter from the regenerator. Stop the lift gas

and block in the control valve.

d. Close the regenerated and spent catalyst slide valves to stop catalyst

circulation.

e. Shutdown the main air blower as quickly and safely as possible to

eliminate hot flue gas flow through the flue gas cooler.

f. Start fuel gas to the LCO stripper. Continue running the wet gas

compressor on total spillback.

g. If feed to the riser is stopped for more than four hours and the reactor

instruments are purged with air (DA), block in the purges. This will

157048 Procedures Page 50

minimize the possibility of auto-ignition of coke due to an accumulation of

oxygen.

h. When the water circulation is restored, start the main air blower and bring

the unit back on stream following the normal startup procedure. Restart

the DA purges just prior to beginning catalyst circulation if these had been

stopped.

Catalyst Cooler:

i. Stop the fluidizing air and close the cooler slide valve. The catalyst in the

cooler should be allowed to become stagnant and cool off to minimize the

overheating of the tubes.

j. It is not necessary to bypass feed from the riser. Unit operation will have

to be adjusted due to the loss of heat removal from the cooler. Reactor

severity will have to be reduced or the feedstock made lighter.

4. Main Air Blower Failure

Loss of the main air blower requires that the unit be shutdown. Usually this is

due to failure of the blower lube oil system, though faulty instrumentation may

also be responsible.

a. Immediately bypass oil from the riser to the main column. This must be

done quickly as the regenerator pressure will drop, causing a loss of

regenerated catalyst slide valve P which could set up the potential for an

oil reversal. Increase riser steam and feed steam.

b. Check that the air blower discharge check valve closes completely

following the blower shutdown to ensure that no catalyst backs into the

blower.

157048 Procedures Page 51

c. Fully close the catalyst slide valves. The valves would eventually close

due to loss of differential pressure across them after the blower fails, but

they should be manually closed as fast as possible. Reduce fluidizing air

to the catalyst cooler to a minimum.

d. Start fuel gas to the LCO stripper as quickly as possible. This may allow

the wet gas compressor to continue operating with the spillbacks fully

open. Reduce the main column receiver pressure as low as possible.

e. Decrease the main column pumparound flows as possible to hold heat in

the column. Stop all net product flows except the bottoms to storage.

Establish the main column bottoms recirculation using the bottoms

product bypass to the raw oil charge line. If the main column top

temperature drops below 230°F (110°C) before oil can be restarted to the

riser, back steam into the bottoms steam generators and provide heat to

the circulating bottoms stream.

f. If feed to the riser is stopped for more than four hours and the reactor

instrumentation is purged with air (DA), block in the purges. This will

minimize the possibility of auto-ignition of coke due to an accumulation of

oxygen.

g. Restart the main air blower when it is ready for service. Begin internal

catalyst circulation in the regenerator through the recirculation catalyst

slide valve. If the regenerator temperature is above 800°F (430°C), torch

oil can be used to reheat the catalyst back to 1200°F (650°C). If it is

below 750°F (400°C), light the air heater first. Be sure to raise the reactor

pressure above the regenerator pressure after the blower is restarted.

h. When the catalyst temperature is at 1200°F (650°C), follow the normal

startup procedure. Restart the DA purges in the reactor just prior to

restarting catalyst circulation if these had been stopped.

157048 Procedures Page 52

5. Wet Gas Compressor Failure

Usually the gas compressor would be lost due to failure of the lube oil system

or instrumentation. If this occurs, the main column pressure will be controlled

by the overhead receiver overpressure controller vent to flare. The unit can be

kept on stream for a short period at reduced throughput if the flaring can be

tolerated. If the compressor cannot be restarted soon, the unit will have to be

shutdown.

a. Bypass oil from the riser to the main column and increase steam to the

riser and feed distributors. Keep catalyst circulating to the reactor if the

shutdown will be for a short duration. Establish a reactor pressure higher

than the regenerator.

b. Continue internal catalyst circulation in the regenerator and use torch oil

to keep the catalyst at 1200°F (650°C).

c. Start just enough fuel gas to the LCO stripper to maintain pressure control

on the main column.

d. Reduce the main column pumparound flows to keep the main column hot.

Back steam into the bottoms steam generators as needed to heat the

circulating bottoms stream.

e. Restart the wet gas compressor as soon as possible. Bring the unit back

on stream following the normal startup procedure.

6. Raw Oil Charge Pump Failure

If the charge pump fails and cannot be restarted immediately, the unit will need

to be shutdown. This could also result from a loss of charge from storage.

157048 Procedures Page 53

a. Increase riser steam and feed steam. Keep catalyst circulating to the

reactor if the shutdown will be for a short duration.

b. Start fuel gas to the LCO stripper to maintain pressure in the main

column. Establish a reactor pressure higher than the regenerator.

c. Keep the wet gas compressor running on total spillback in preparation for

restarting charge to the riser.

d. Continue internal catalyst circulation in the regenerator and use torch oil

as needed to maintain the catalyst at 1200°F (650°C).

e. When the charge pump is available, bring the unit back on stream

following the normal startup procedure.

7. Main Column Bottoms Circulating Pump Failure

The main column bottoms circulation circuits remove about 25% of the heat

from the reactor vapors. If the flow is lost for more than ten minutes, the unit

will need to be shutdown since the bottoms residence time and temperature

would increase to the point where coke formation would begin. The loss of

bottoms circulation could also result in heat damage to the disc and donut

trays and fines carried up the column.

a. The first priority is to get the material out of the column and try to keep

the bottoms temperature down. Try to start the spare pump immediately.

Reduce the charge rate to 75% of design and drop the reactor

temperature by 50°F (30°C). Decrease column product draws slightly to

aid in quenching the bottoms.

b. If it is not possible to start the spare pump immediately, continue

decreasing the charge rate. Increase steam to riser when the charge rate

is below 60% of design to assist catalyst circulation. If it is not possible to

start either pump within ten minutes, increase the riser steam and feed

157048 Procedures Page 54

steam, bypass the raw oil charge to the main column, and stop the raw oil

feed. Establish a reactor pressure higher than the regenerator. Keep

catalyst circulating to the reactor if the shutdown will be for a short

duration.

c. Continue internal catalyst circulation in the regenerator and use torch oil

to maintain the catalyst at 1200°F (650°C).

d. Add fuel gas to the LCO stripper as needed to maintain main column and

reactor pressure. Keep the wet gas compressor running on total spillback.

e. When a bottoms pump can be restarted, pump the column bottoms down

to a normal level. Restart the normal bottoms circulation and follow the

normal startup procedure.

8. Slide Valve Failure

It may be necessary to manually operate a slide valve during an emergency

condition resulting from the following faults:

a. Hydraulic Oil Supply Failure

b. Controller Malfunctions

c. Physical Damage to the Valve

The slide valve has many redundant safety features to minimize the potential

for loss of control. Four methods are provided to move the slide valve:

1. Electronic actuator (hydraulic power)

2. Local manual positioner (hydraulic power)

157048 Procedures Page 55

3. Local handpump (hydraulic power and manpower)

4. Local handwheel (manpower)

a. Hydraulic Oil Supply Failure

A loss of hydraulic oil pressure could occur due to a loss of the hydraulic

oil pump or a ruptured hydraulic oil line. The loss of pressure will result in

the loss of control of the slide valve and should leave the valve in the

position it occupied when the failure occurred (fail in place). The slide

valve must immediately be put on manual control. If the unit operation is

steady, a major upset need not result. However, the unit will drift off

control over time and immediate action should be taken.

(1) For those cases where the hydraulic lines remain intact, the slide

valve main hydraulic oil accumulator will provide enough fluid to the

actuator to move the valve two full strokes. However, if the valve has

not moved within approximately four minutes, the accumulator will

have depressured and be unable to move the valve.

(2) When the main accumulator pressure is depleted, switch to the

reserve accumulator which will again provide two full strokes of the

valve or about four minutes of operating time. When the reserve

accumulator is switched on, it will activate the control board alarm

"Reserve Accumulator in Service". To extend the use of the reserve

accumulator, the board operator can switch the reserve accumulator

in and out of service to make valve position changes.

(3) When the reserve accumulator pressure is low, the "Reserve

Accumulator Low Pressure" alarm will be activated in the control

room. At that time it will be necessary for a field operator to manually

move the valve with the local handpump or handwheel. Refer to the

manufacturer's instructions for this operation.

157048 Procedures Page 56

(4) When operating the regenerated catalyst slide valve by handwheel,

watch the valve P very closely. If P is lost, a flow reversal could

develop.

(5) If the hydraulic oil pressure can be reestablished quickly, put the

valve back into regular operation. For a prolonged failure, the unit

will need to be shutdown. Do not attempt to operate any slide valve

by the handwheel for normal operation. This manual action is much

too slow to react to sudden process changes.

b. Controller Malfunctions

A slide valve will close upon the loss of its actuator electronic power or

instrument signal. There is no alarm for these failures and they will only

be apparent to the board operator when he sees the slide valve drifting to

the closed position. In this case, the slide valve should be operated using

the hydraulic oil system local manual positioner, the local handpump or

the handwheel. When operating the slide valve locally, care must be

taken to maintain a positive slide valve P. If the electronic input signal

can be reestablished quickly, put the valve back into regular operation.

For a prolonged failure, the unit will need to be shutdown.

c. Physical Damage to the Valve

The loss of slide valve control could be the result of excessive disc

erosion or a broken stem.

Corrective actions to be taken depend on which valve is affected:

(1) Spent Catalyst Slide Valve Failure

(a) The worst situation occurs if control of the valve is lost in an

open position and the valve cannot be closed. For this case,

increase riser steam and feed steam. Bypass raw oil charge to

157048 Procedures Page 57

the main column and shut down the charge pump. Establish a

reactor pressure higher than the regenerator and reduce the

main column pressure.

(b) Since the valve is stuck open, it is possible that the reactor

could empty of catalyst. This may allow air to enter from the

regenerator which could result in a fire or explosion. Continue

catalyst circulation using steam to the riser to hold a reactor

catalyst level. Allow the regenerator temperatures to fall to

1000°F (540°C) and maintain this level with torch oil or the air

heater. Having a lower catalyst temperature will allow more

catalyst to be circulated without generating a high reactor

temperature.

(c) Shutdown the wet gas compressor and allow the main column

to cool down. Pump out as much oil as possible. Start steam to

the bottom of the column and vent from the overhead receiver

to flare. Maintain enough pressure to keep the reactor pressure

above the regenerator.

(d) Start unloading as much catalyst as possible from the

regenerator without losing circulation to the reactor. Continue

with the shutdown procedure to eventually install the reactor

vapor blind, and prepare the regenerator for entry and repair of

the valve. If the level of catalyst is lost in the reactor and the

spent catalyst slide valve loses its P, the air blower should be

shutdown immediately and steam to the riser increased as

much as possible to keep air out of the reactor.

(2) Regenerated Catalyst Slide Valve Failure

(a) If control of the valve is lost with the valve in an open position,

increase the riser steam and feed steam while decreasing the

raw oil charge to 60% of design. Increase the riser steam as

157048 Procedures Page 58

necessary to keep catalyst circulating through the riser. Reduce

the reactor pressure as possible to assist catalyst flow up the

riser.

(b) Allow the reactor temperature to drop to reduce coke make but

do not go below 900°F (480°C). As the regenerator

temperatures drop, transfer as much catalyst as possible to the

storage hopper without losing the recirculation and regenerated

catalyst flows.

(c) When the raw oil charge rate is decreased to 60% of design,

start a small flow of dry steam to the main column bottoms.

(d) When prepared, bypass the raw oil to the main column and

shut down the charge pump. Immediately shutdown the main

air blower, riser steam and feed steam. Maintain reactor

stripping steam. With no steam to transport the catalyst, it will

slump and plug the riser wye section. This is done to prevent

any air from entering the reactor. While this is less than

desirable for easily restarting operation, it is a necessary safety

protection for the unit.

(e) Fully close the spent catalyst slide valve to maintain a reactor

level. Increase steam into the main column bottoms. Increase

the reactor stripping steam to maximum to purge the reactor.

(f) After bypassing charge, shutdown and block in the wet gas

compressor.

(g) Continue steaming the main column and vent pressure to the

flare. Pump out the oil from all circuits in preparation for

installing the reactor vapor blind. Continue with the shutdown

procedures to isolate and prepare the reactor and regenerator

for entry to repair the valve.

157048 Procedures Page 59

(3) Recirculation Slide Valve Failure

(a) Usually, failure of this valve does not require a unit shutdown

unless it fails near its fully closed position. Small adjustments to

other operating variables should make it possible to keep the

unit on stream.

(b) If the valve is stuck in one position, there will be no direct

control over the combustor temperature. Check the regenerator

temperatures, combustor catalyst density and main air blower

discharge pressure.

(c) If the valve is stuck too far open, the catalyst density in the

combustor will increase which will increase the blower

discharge pressure. If the air flow becomes limited as a result,

adjustments can be made to the regenerator pressure to

compensate.

(d) If the valve is stuck too far closed, the catalyst density and

temperature will decrease, and there may not be enough heat

to complete the coke combustion or enough catalyst to absorb

the heat from the combustion. This could lead to afterburning in

the upper regenerator. In this case, the air rate can be

decreased slightly to compensate. In severe cases, the charge

rate and reactor temperature should be reduced to decrease

the coke make.

(4) Flue Gas Slide Valve Failure

If the control of one of the discs is lost on the double disc valve, it

may be possible to control the reactor-regenerator differential

pressure using only the second operable disc. However, in the event

that adequate P control cannot be maintained, or that control of

both discs is lost, then the unit would need to be shut down.

157048 Procedures Page 60

If the valves fail toward the closed position resulting in a rising

regenerator pressure, the main air blower would have to be

shutdown immediately. The rising regenerator pressure would stop

spent catalyst transfer and create a dangerous situation in which air

could be forced into the reactor.

On the other hand, if the valves were to fail toward the open

position, the regenerator would depressure as if the main air blower

had failed. Therefore, the unit should be handled as in a main air

blower failure.

(5) Catalyst Cooler Slide Valve Failure

The loss of control on this valve will not require a unit shutdown. The

cooler will either take more or less heat out of the regenerator than

desired, depending on whether the valve is too far open or closed.

This situation can usually be handled by adjusting the cooler

fluidizing air to compensate. In the extreme case, the reactor and

feedstock conditions may have to be adjusted to make more or less

coke.

9. Catalyst Cooler

a. Loss of Circulating Boiler Feed Water

The following steps must be taken if circulating water flow cannot be

restarted to the cooler. With the loss of circulating water, the catalyst

cooler tube temperature will quickly increase to the surrounding catalyst

temperature.

(1) To minimize heat transfer, immediately stop fluidizing air flow to the

catalyst cooler.

(2) Confirm that the cooled catalyst slide valve has closed.

157048 Procedures Page 61

(3) Depressure the catalyst cooler steam drum to 50 psig (3.5 kg/cm2).

This will reduce the metallurgical stress on the cooler tubes.

(4) Determine the cause of the water circulation failure and make

necessary repairs.

(5) To avoid thermally shocking the tubes, let them cool to below 450°F

(230°C) before restarting the water circulation. Use the

thermocouples located in the cooler as an indication of the tube

temperature.

(6) Restart water circulation and watch for a high BFW makeup rate

indicating a tube is leaking.

(7) When water circulation is stable, begin fluidizing air to the cooler.

Adjust the air rate for the desired heat removal. If air will not flow

through the lances, it may be necessary to attach a higher pressure

gas source, air or nitrogen, to the header to help blow the lances

free.

b. Catalyst Cooler Tube Rupture

If a tube in the catalyst cooler ruptures, as indicated by a slight pressure

surge in the regenerator and a sudden increase in boiler feed water

demand, the following actions must be taken:

(1) The circulating water pumps must be shutdown and the makeup

water stopped.

(2) Stop fluidizing air to the cooler.

(3) Confirm that the cooled catalyst slide valve has closed.

(4) Depressure the steam drum and isolate the system.

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(5) It is possible to leave the cooler in this state and continue the FCC

operation indefinitely. The stagnant catalyst in the cooler will

eventually cool to protect the tubes against high temperature.

Shutdown of the FCC unit can be planned for a later date to repair

the ruptured tube.

In both of the above situations, loss of the catalyst cooler will require an

adjustment in FCC operating conditions to compensate for the lost heat

removal and limit regenerator temperature. This may require a reduction

in charge rate or a lighter feedstock. The FCC unit does not need to be

shutdown in either event.

10. Lift Gas Failure

Lift gas is not required to keep the FCC unit operating. Usually, lift steam can

be used to compensate for any loss of lift gas. The system is designed to shut

off lift gas to the riser when oil charge is bypassed.

a. Loss of Lift Gas

Increase lift steam to the riser. If lift gas cannot be restored, block in and

isolate the line.

b. Upset in Gas Concentration Unit

If an upset occurs which increases the heavy material in the lift gas (greater than 10% C3+), reduce or discontinue the lift gas, increasing the

lift steam to compensate. The C3+ material can crack to large quantities

of light gas which could upset the compressor and absorbers.

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11. Instrument Air Failure

Loss of instrument air will result in all control valves moving to their fail

position. If instrument air cannot be restored immediately, the unit must be

shutdown.

a. The raw oil charge is bypassed to the main column on air failure. The

charge pump should be shut down until air is restored.

b. Steam to the riser and feed distributors opens fully on air failure. Lift gas

to the riser will fail closed.

c. The main air blower governor will fail to the minimum speed and the anti-

surge snort valve will fail open. The catalyst slide valves will not fail as

they are electrohydraulic, so they must be closed by operator action. If

instrument air cannot be restored quickly, the blower may be left running

and the snort valve, recirculation catalyst slide valve and flue gas slide

valves and be adjusted to reestablish catalyst circulation in the

regenerator. The catalyst temperature can then be maintained at 1200°F

(650°C) using the air heater or torch oil in preparation for the unit restart.

d. The wet gas compressor spillback valves will fail open. Unless sufficient

fuel gas can be put into the LCO stripper to maintain column pressure,

the compressor should be shut down.

e. The circulating main column bottoms control valves to the steam

generators will fail open. If instrument air is not restored quickly, close the

block valves and use the bypass valves to reduce these flows and

minimize cooling in the main column.

f. Usually an instrument air failure will be of short duration. When air is

restored, control valve action will return and the unit can be restarted

according to the normal startup procedure.

157048 Procedures Page 64

12. Electrical Power Failure

In a general power failure, all process equipment will shut down except those

pumps and compressors driven by steam turbines. The power pack for

instrumentation will fail momentarily until the emergency power system cuts in,

restoring instrument circuits.

In the event of a power failure, the following actions should be taken:

a. Increase lift steam and feed steam to the riser, bypass the raw oil charge

to the main column and close the raw oil charge control valve. If it is

expected that the power outage will be temporary, continue catalyst

circulation using steam. Stop lift gas flow. Establish a reactor pressure

higher than the regenerator and reduce the pressure in the main column.

b. Close the catalyst cooler slide valve and reduce fluidizing air to minimum

flow to minimize heat removal in the regenerator. If catalyst circulation is

continued, use the air heater to maintain the catalyst at 1200°F (650°C).

The turbine driven circulating water pumps for the catalyst cooler and flue

gas cooler should continue operating.

c. If the wet gas compressor is motor driven, it will shut down. If turbine

driven, keep the compressor running on total spillback. In either case,

start fuel gas to the LCO stripper to maintain column pressure.

d. The main column bottoms pumps are turbine driven and will continue

operating. Maintain circulation but flow through the steam generators may

have to be stopped if BFW makeup has stopped. With all column

pumparounds and overhead reflux stopped, the column will hold heat for

some time.

e. When power is restored, restart all pumps and follow the normal startup

procedure.

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13. Cooling Water Failure

If cooling water failure occurs for a period greater than about ten minutes, the

unit will probably need to be shut down. The largest potential danger is to the

wet gas compressor. Loss of cooling water to the interstage cooler will result in

a high suction temperature to the second stage which can cause significant

damage to the compressor. If cooling water cannot be restored, take the

following action:

a. Shutdown the wet gas compressor and bypass raw oil charge to the main

column. Increase lift steam and feed steam to the riser. Stop lift gas flow

and block in the control valve.

b. Maintain reactor pressure by starting fuel gas to the LCO stripper.

Establish a reactor pressure higher than the regenerator.

c. Continue catalyst circulation using riser steam if it is expected that cooling

water will be restored within a reasonable period. If not, catalyst

circulation to the riser can be stopped.

d. Continue internal catalyst circulation in the regenerator and use torch oil

to maintain the catalyst at 1200°F (650°C).

e. When cooling water is restored, bring the unit back on stream following

the normal startup procedure.

14. Steam Failure

Since the FCC unit is a major steam producer, it is less susceptible to steam

failures. When a boiler failure does occur, steam pressure will begin dropping.

Non-critical users will be shed first, so the FCC unit has time for an orderly

shutdown. A main objective is to purge hydrocarbon from the reactor before

steam is lost completely. The following actions should be taken:

157048 Procedures Page 66

a. Bypass raw oil charge to the main column and shutdown the charge

pump. Increase lift steam, feed steam and stripping steam to maximum

flows to purge the reactor quickly.

b. Continue catalyst circulation on riser steam for a short period, then close

the regenerated and spent catalyst slide valves.

c. Since the main column bottoms pumps are turbine driven, they will not be

operating for long. Therefore, cool the main column quickly to lighten the

material in the bottom to avoid coking when flow has been lost. Pump out

bottoms to hold a low level. Shutdown the wet gas compressor and begin

to depressure the main column to flare. Start steam to the main column

bottom to help purge the column.

d. The main air blower is usually turbine driven and will eventually be

stopped. Internal catalyst circulation in the regenerator can be maintained

until that time. If it is expected that steam will be restored within a short

period, keep the catalyst hot with the air heater until the blower shuts

down.

e. When steam is restored, start turbines carefully due to the potential for

condensate in the lines. Restart the unit according to the normal startup

procedures.

F. CATALYST HANDLING

Handling FCC catalyst is a relatively simple job. FCC catalyst is a relatively

strong material and will function quite well if not seriously abused. Because of

its characteristic of being easily fluidized, it is easily moved to and from the unit

using the principles of a pneumatic conveyor.

157048 Procedures Page 67

Storage is provided usually in two large hoppers, one for fresh catalyst and the

other for equilibrium catalyst (removed from the unit). Capacity of these

hoppers may vary from 100-500 tons, depending on the size of the unit. The

fresh catalyst hopper will have an automatic catalyst loader, and is usually

slightly smaller than the equilibrium hopper. The equilibrium hopper must be

sized to hold the entire catalyst inventory of the unit, plus some contingency.

Both hoppers have relief valves to prevent overpressuring, and a variety of

loading and unloading lines. Instrumentation is limited to several pressure

gauges and a level gauging device. Both hoppers are usually built to withstand

a full vacuum. A steam ejector is used to provide this vacuum to unload

catalyst into the hopper. Refer to Figure 5.

1. Loading Catalyst to the Hopper

Catalyst is delivered from the manufacturer in trucks, railcars, or large

plastic-lined boxes. Equilibrium catalyst usually leaves the refinery in the

same manner. Before the catalyst is loaded to the hopper, all lines and

vessels should be inspected. The important points to check are:

a. All lines and vessels are built according to specification.

b. Pressure taps are open and the level gauging devices are working.

c. The lines and vessels are free of foreign material, especially water

or oil. The air lines should be checked by blowing all lines until they

are clean and dry. The large diameter loading lines can be blown

using the hot air from the regenerator during dryout. Any water in the

lines or hoppers will form a sticky mud which makes normal handling

impossible as this wet catalyst is extremely difficult to remove.

Prolonged blowing with air or cleanout by hand will work, but the

best method is prevention by keeping the system dry.

157048 Procedures Page 68

The next step is to load catalyst to the appropriate hopper. This is

important because of the tremendous activity difference between fresh

and equilibrium catalyst. Mistakes here can be highly embarrassing.

The catalyst may be loaded to the hopper by blowing it in from the truck

or railcar, evacuating the hopper and pulling it in, or a combination of the

two. A vacuum can be pulled on the hoppers by commissioning the

ejector after lining up the valves to the appropriate hopper (Figure 5).

Open the loading valves first at the top of the hopper, then at the catalyst

loading area. The catalyst should flow freely.

If the catalyst arrives on site in boxes, a cone shaped open hopper can be

used to transfer it to the catalyst hopper. The appropriate hopper would

be evacuated, and a small amount of carrying air supplied at the base of

the cone to help move the catalyst.

The amount of catalyst in the hopper should be measured regularly. A

chart showing tons of catalyst as a function of outage will give a quick

inventory reference. This can be calculated knowing the hopper volumes

as a function of height (be careful when calculating the cone section at

the base) and the catalyst densities of approximately 50 Ib/ft3 (800

kg/m3) for fresh catalyst and 55 Ib/ft3 (880 kg/m3) for equilibrium catalyst.

More exact values of these multipliers can be obtained from the catalyst

data sheets or calculated after a known weight of either catalyst has been

loaded into its appropriate hopper. Knowing the amount of catalyst

remaining in the hoppers is the only way to control inventory and to

determine how much catalyst is being used in the unit.

Using the hopper level gauging devices may not always provide accurate

catalyst level measurements. These have a tendency to sink in the

catalyst and give false readings. Also, the catalyst may form a cone inside

the hopper which can give a false reading. A proper measurement can be

obtained by depressuring the hopper and letting it settle for at least 1

157048 Procedures Page 69

hour. Then the gauging hatch is opened and the outage measured with a

hand tape.

2. Loading Catalyst to the Regenerator

The procedure for loading the catalyst to the regenerator begins with

pressuring up the hopper. Blower air is good for this purpose because it is

hot and dry, although dry plant air can also be used. If possible, the air

should be injected at the base of the hopper so that it will fluff the catalyst

as it flows upward. The pressure in the hopper must be higher than the

pressure in the regenerator, or the catalyst will not move. Refer to Figure

5.

a. Make sure the regenerator is ready to receive catalyst. Refer to the

normal startup procedures.

b. Gauge the hopper and pressure it to 40 psig (2.8 kg/cm2) by adding

air through the bottom.

c. Line up the loading line from the hopper to the regenerator start the

carrying air to the line while leaving the block valve under the hopper

closed. Set the air rate to achieve a velocity of ~50 ft/sec (15 m/sec)

in the line or so that the pressure at the end of the line increases by

~1-2 psi (0.1-0.2 kg/cm2) if no FI is provided.

f. Open the catalyst loading valve at the bottom of the hopper slowly

until the loading line pressure rises 10-15 psi (0.7-1.0 kg/cm2),

signifying that catalyst is flowing through the line. The catalyst block

valve should be 1/4 to 3/4 open. The operator can avoid plugging

the line by carefully watching the pressure gauge and/or carrying air

FI on the loading line at the base of the hopper. With normal loading,

the gauge will oscillate slightly around a pressure about 5-10 psi

(0.35 –0.7 kg/cm2) above the regenerator pressure. If this gauge on

the loading line shows an increase in pressure, the catalyst hopper

157048 Procedures Page 70

block valve should be closed. The carrying air can then clear the line

before excess catalyst can plug it. The optimum catalyst transfer

technique is best determined through trial and error operation for

each specific installation.

g. Maintain the hopper pressure by adding air to the bottom of the

hopper as this generally gives smoother catalyst flow. However, if

this operation reduces the loading rate, the hopper can be pressure

from the top.

h. When the correct regenerator inventory is achieved, close the

loading valve at the bottom of the hopper. Blow out the loading line

and close the loading valves at the regenerator, leaving the loading

line under plant air pressure.

i. Gauge the hopper and determine the quantity of catalyst transferred

during the loading.

Plugging Problems

If there is a problem with the catalyst bridging above the block valve at

the bottom of the hopper, quickly opening and closing the valve 1-2 turns

will usually break the bridge. If this fails, blast the bottom of the hopper

with air.

The catalyst loading line may plug occasionally. When this happens,

close the catalyst block valve at the base of the hopper. Starting at the

regenerator and working back to the hopper, fully open the blast points

one by one. If this fails, pounding on the line with a non-sparking hammer

will work as a last resort. When the pressure gauge on the loading line at

the base of the hopper falls to just above the regenerator pressure, the

line is clear. High pressure air or nitrogen may be used to clear a plug,

but do not exceed safe working pressure of the line.

157048 Procedures Page 71

3. Fresh Catalyst Makeup

For loading fresh catalyst, an automatic loader usually works quite well.

These feed catalyst to the regenerator in small amounts on a steady

basis. This is much better than dumping a day's supply into the unit in 20

minutes, leading to a marked activity change. The fresh catalyst loading

line is usually much smaller than the large line used for initial catalyst

loading. The smaller line has a larger volume of air per unit area passing

through it, which decreases the potential of plugging problems.

The rate of fresh catalyst makeup will vary depending on unit

performance objectives, feedstock quality and how well the unit "holds"

catalyst. Some refiners add only enough fresh catalyst to balance losses.

Others add makeup at a higher rate to maintain a certain activity level and

then periodically withdraw equilibrium catalyst to balance unit inventory.

The level of metals in the feedstock will have a strong impact on catalyst

makeup rates.

4. Unloading Catalyst from the Regenerator

The pressure in the regenerator is the driving force to unload catalyst to

the equilibrium hopper. Commission the steam ejector and line up the

valves to pull a vacuum on the equilibrium hopper. Then open the

unloading valves, first on the hopper, then on the regenerator. It is usually

not necessary to use the blast connections, although they are available if

needed. Withdraw the appropriate amount of catalyst by watching the

regenerator level. When the unloading is finished, close the regenerator

block valve. Clean out the unloading line by opening the nearest blast

point. Then shut off the ejector and bleed enough air into the hopper to

raise it to atmospheric pressure.

157048 Procedures Page 72

5. Catalyst Valve Purges

An air purge is normally provided to the seat and bonnet of all valves in

the catalyst loading/unloading system. This is to prevent catalyst from

collecting in these areas and interfering with valve operation. Forcing a

valve shut when the seat is full of catalyst will only damage the valve.

For proper operation, open the purges and clear the seat and bonnet

before the valve is operated. Do not leave the purges on during the

loading operation as excessive valve erosion can result. Rather, purge

the valves each time they will be adjusted and particularly just before the

valves are closed.

G. SPECIAL OPERATIONS

1. Catalyst Sampling

When drawing hot catalyst samples, gloves, long sleeve clothing and face

shields should always be worn. Always use a metal container to collect

the sample. Refer to Figure 6 for the valve locations in the following

procedure for drawing catalyst samples.

a. Spent Catalyst Sample

NOTE: Air should never be used when purging into the reactor or

the spent standpipe as oxygen can initiate coke burning.

(1) The reactor level controller should be switched to manual as

purging the sample connection could upset the slide valve

differential pressure controller.

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(2) Check that all blast and sample connection valves are closed,

then open sample valve E and steam valve B. Vent steam to

the atmosphere until it is dry.

(3) Close sample valve E and open the nozzle valve F. Steam

purge the sample line into the standpipe.

(4) Open sample valve E and reduce the steam flow through valve

B until a small flow of catalyst is obtained. If catalyst does not

flow out of sample valve E, close valve E and blast the

standpipe through steam valve C. Repeat the step until catalyst

can be obtained.

(5) Take the sample and close valve E.

(6) Open steam valve B and purge into the standpipe.

(7) Close nozzle valve F and then steam valve B.

(8) Open sample valve E.

(9) Put the reactor level control back in automatic.

b. Regenerated Catalyst Sample

(1) The reactor temperature controller should be switched to

manual as purging the sample connection could upset the slide

valve differential pressure controller.

(2) Check that all blast and sample connection valves are closed,

then open sample valve E and air valve A. Vent air to the

atmosphere until it is dry.

157048 Procedures Page 74

(3) Close sample valve E and open the nozzle valve F. Air purge

the sample line into the standpipe.

(4) Open sample valve E and reduce the air flow through valve A

until a small flow of catalyst is obtained. If catalyst does not flow

out of sample valve E, close valve E and A, and blast the

standpipe through steam valve C. Repeat the step until catalyst

can be obtained.

(5) Take the sample and close valve E.

(6) Open air valve A and purge into the standpipe.

(7) Close nozzle valve F and then air valve A.

(8) Open sample valve E.

(9) Put the reactor temperature control back in automatic.

2. Blasting Catalyst Standpipes

Sample and blast connections are located just above the spent,

regenerated, and recirculation catalyst slide valves. There may also be

blast connections located higher on the regenerated standpipe. These

connections are used not only to sample catalyst but also to clear the

standpipes of any plugs which might occur. The following is a procedure

for blasting these standpipes using steam (refer to Figure 6).

NOTE: Air should never be used to when purging into the reactor or

spent standpipe.

a. Place the appropriate slide valve controller in manual when blasting

a standpipe.

157048 Procedures Page 75

b. Check that all blast and sample valves are closed, then open sample

valve E and steam valve C. Vent steam to the atmosphere until it is

dry.

c. Close sample valve E and open nozzle valve F. Purge steam into

the standpipe until the plug is cleared. Do not blast for extended

periods (more than several minutes) with the steam valve full open.

Potential erosion to the standpipe refractory is a concern. It is better

to use short intermittent blasts than one long continuous blast.

d. Close nozzle valve F and steam valve C.

e. Open sample valve E.

f. Place the slide valve controller back in automatic control.

3. Direct Fired Air Heater

The direct fired air heater is used to heat up the circulating catalyst

inventory during startup or maintain heat during temporary shutdowns.

The heater is only fired when the main air blower is operating. A

potentiometer should be connected to the temperature indicator located

at the outlet of the air heater so the field operator can monitor the

temperature locally when the heater is fired.

Refer to the manufacturer's operating manual for detailed operating

information. The general heater steps are as follows:

a. Pull the blind in the air heater fuel gas line after the main air blower

is put in operation.

b. Switch on the ignition power.

c. Adjust the inlet damper to direct less air behind the burner block.

157048 Procedures Page 76

d. Open the fuel gas line supplying gas to the pilot burner. Press the

button on the local panel supplying power to the pilot ignitor. Use the

observation ports to confirm that the pilot has been lit.

e. When the pilot has been lit, slowly open the main burner gas valve

until a flame is obtained. Use the observation ports to confirm that

the main burner is firing.

f. Adjust the inlet damper to get a proper flame color.

g. While the air heater is relatively simple to operate, the following

precautions should be observed:

(1) An operator should be stationed at the air heater to monitor the

flame any time the heater is in operation.

(2) If the air flow to the regenerator stops for any reason, the fuel

gas supply valves must be shut off immediately.

(3) The fuel gas to the heater must be free of any liquid. Slugs of

liquid hydrocarbon can cause damage due to high

temperatures.

4. Flushing System

The flushing oil system is required for two reasons:

a. The main column bottoms contains catalyst fines which can settle

out and plug instruments and small piping, and which can erode

pumps and control valves.

b. Maintenance on the packing of the hot main column bottoms pumps

is reduced if the packing glands are cooled by a flushing stream.

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The throat bushings and wear rings of the main column bottoms pumps

are flushed with hot heavy cycle oil taken from the circulating HCO pump

discharge. Hot material is used to avoid the thermal stresses which could

result if a cooled oil was injected into the hot pump casing. HCO is used

since LCO would flash and cause pump cavitation. The flush rate is

adjusted by closing the inlet flush valve, observing the static pressure,

and opening the flush valve until the pressure increases about 10 psi (0.7

kg/cm2).

Light cycle oil is used for all other flushing services with the exception that

raw oil is used during startup and can be used during an emergency. On

units with resid feed stocks light gas oil from storage should be used as a

backup instead of raw oil. The flushing oil is taken from the LCO product

cooler outlet and passes through a 30 mesh strainer, which should be

cleaned whenever the P exceeds 15 psi (1 kg/cm2).

The main column bottom level instrument and sight glass similarly flushed

to prevent the accumulation of catalyst. A 1/8 inch (3 mm) restriction

orifice is used to regulate the flow to each location.

The main column bottoms pump packing glands are flushed with LCO

through a lantern ring to cool the shaft and packing. The flush is returned

to the main column with the circulating HCO return. This flush is adjusted

by closing both the supply and return valves, and observing the lantern

ring pressure. The flushing supply valve should then be adjusted so that

the flush oil pressure is 15 psi (1 kg/cm2) higher, while the return valve is

adjusted to maintain the return temperature above 150°F (65°C). It is

advisable to mark the desired flush oil pressures on the gauges so that

adjustments can be easily made.

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5. Main Air Blower Discharge Check Valve

a. Application

The main air blower discharge check valve is a swinging disc type

valve installed on the discharge of the air blower for safety reasons.

The weight of its disc is balanced to cause the valve to close when

air flow stops, preventing the reverse flow of air and catalyst through

the blower. The valve is equipped with a spring loaded air cylinder

and an oil dashpot. The air cylinder provides an automatic device

which assists the valve to close quickly, while the dashpot dampens

the excessive swinging of the disc under a low or pulsating flow

condition so that the disc does not slam on the seat.

b. Counterweights

The steel disc of the valve is of heavy construction to resist distortion

from pressure loads or high temperatures. Counterweights are

provided so that the full weight of this disc will not have to be carried

by the gas stream going through the valve. By counterweighting

approximately 75% of the disc weight, the valve opens wide under

the design flow condition and results in minimum pressure drop

through the valve. Counterweighting to hold the valve open when

there is no gas flow through the valve must not be done as this

negates the safety protection of the valve. If the disc is moved off the

seat by manually pulling on the counterweight lever when there is no

gas flow through the valve, the disc should return to the seat freely

and rapidly upon release of the counterweight lever.

c. Air Cylinder

The external spring loaded air cylinder is designed to assist in the

rapid closure of the valve under emergency conditions. It can not be

used to open the valve and under normal operating conditions with

157048 Procedures Page 79

air pressure supplied to the cylinder, there is no physical connection

nor restriction to the movement of the valve.

Air pressure in the range of 60 to 125 psig (4 to 9 kg/cm2) is

required to offset the air cylinder spring force. The air pressure

supplied to the cylinder is through a 3-way solenoid valve which is

activated by the main air blower discharge flow transmitter low flow

switch. This valve operates such that when it is actuated, it vents the

air pressure in the cylinder to atmosphere. Once the cylinder is

depressured, its spring force acts to jolt the valve disc loose so that

it may close freely. The release of air from the cylinder, however,

does not assist in the closing action.

There are two advantages associated with using this type of

externally actuated check valve. If the valve tends to stick open after

several months of operation, the cylinder's spring provides a break-

away force to start the valve closing. Also, the air cylinder is tripped

before the blower stops rotating, so that the spring forces the disc

nearer to the seat before air flow stops. This ensures that the valve

will seat before reverse flow can develop.

While the spring in the air cylinder exerts a substantial force, the

closing force creates only a relatively small back pressure. This is

important from the standpoint of operation, because even in the

event of accidental tripping, flow through the valve will continue.

Thus, if the shutdown system should malfunction while the blower is

operating normally, the unit can continue in operation until the

instrumentation is repaired.

d. Oil Dashpot

The oil dashpot contains a loose fitting piston which moves through

an oil filled cylinder. As the check valve disc moves, it moves the

piston through the oil, forcing oil from one side to the other through a

157048 Procedures Page 80

bypass line containing a regulating check valve. This valve restricts

the oil flow as the disc opens, preventing rapid opening, while

allowing unobstructed oil flow and rapid movement of the disc when

the check valve closes. This system will dampen the action of the

disc in a low flow or pulsating condition to protect the valve seat.

The regulating valve should be set initially in a 3/4 open position to

provide some restriction to the oil flow on opening of the disc. Before

the check valve is put into operation, the dashpot should be filled

through the plug on the bypass connection with a light lubricating oil

such as SAE 10W.

6. Slumped Riser During Shutdown

With raw oil charge bypassed, riser flow is maintained usually with only

steam. If this steam is stopped during catalyst circulation, or the

regenerated catalyst slide valve is maintained open manually with

insufficient steam to the riser, the catalyst can slump and fill the wye

section and bottom of the riser. If such a situation develops with hot

catalyst and oil present, the wye section stagnant catalyst can coke up

and require hammer and chisel to remove. If such a situation develops

with cooler catalyst and condensate, catalyst mud can form which is also

difficult to remove. Thus, it is imperative that steam always be maintained

to the riser during shutdown situations, at least until the regenerated

catalyst slide valve has been closed and the riser is free of catalyst.

Should a slump occur, blast points at the bottom of the wye section

should be used to clear the plug with steam if possible. Steam can also

be blasted through the normal lift steam line.

If mud has formed and cannot be blasted clear, the 4 inch (150 mm)

blankoff connection at the base of the wye can be opened to attempt to

drain the wet catalyst. A vacuum hose can be connected to assist pulling

the catalyst out.

157048 Procedures Page 81

If all attempts fail, the lift or feed distributor in the wye should be pulled to

allow entry for manual removal of the catalyst.

NOTE: Always assume the catalyst will be hot and take all necessary

safety precautions.

157048 Procedures Page 82

Figure 1: Reactor/Regenerator Section

Products to

MainColumn

FlueGas

Startup Naphthafrom Main Column

Overhead

Lift Gas from GasConcentration Unit

Steam

LiftSteam

StartupSteam

HS

FO

FC

Main ColumnBottoms Recycle

Raw Oilfrom Preheat

Reactor Bypass toMain Column

AtomizingSteam

FIC

FIC

FIC

FIC

FIC

FIC

FIC

FluffingSteam

StrippingSteam

FICPrestripping

Steam

Air

FuelGasPilotGas

Direct Fired AirHeater

Split RangeSteam

Torch Oilfrom HCOor Raw Oil

FIC

FCC-P001

157048 Procedures Page 83

Figure 2: Main Column Lower Section

Raw Oilfrom

SurgeDrum

MCBProduct

Steam toSuperheater

ReactorProductVapor

CW

MCBQuench

Disc and DonutMinimum Flow

LIC

DebutanizerReboiler

FIC

FIC

FIC

FIC

Torch Oil

Pump Flushing Oil

FCC-P002

FIC

T Startup HeatingSteam Trap

StartupSteam

HS

FO

FC

FIC

Raw Oil toReactor

FIC

StartupFilling Line

To LCOPumparoundReturn Line

CirculationBypass

StartupCirculation/

Recycle

TorchOil

FlushingOil

157048 Procedures Page 84

Figure 3: Main Column Upper Section

PSV

CW

Wet GasCompressor FirstStage Spillback

To Wet Gas CompressorSuction Drum

To Flare HeaderFC

Signal to Wet GasCompressor Controls

PICPRC

Net Overhead Liquidto High Pressure

Receiver

Sour Water

LICTIC

FIC FIC

HCNProduct

HCO

CW

FIC

FI

LCOProduct

LCO toFlushing Oil

FI

CWBFWPreheater

FIC

GasConcentration

Unit HeatExchangers

GasConcentration

Unit HeatExchangers

Startup Filling fromRaw Oil/MCB

StartupFuel Gas

StartupCirculation

Bypass

StartupCirculation

Bypass

Steam

FCC-P003

HCNStripper

LCOStripper

157048 Procedures Page 85

Figure 4:

Reactor Vapor Line Blind

Vent toSafe

Location

Steam

PI

DG

Blind orSpacer

Blind orSpacer Drains

ReactorOverhead

Vapor

FCC-P004

157048 Procedures Page 86

Figure 5: Catalyst Handling Facilities

GRATING

"DA"

CatalystHopper

EverlastingValves

Plant Air

Plant Air

CatalystVolume Pot

PlantAir

CatalystMakeupLogic

Controller

PlantAir

Plant Air

RO

Catalyst Makeup toRegenerator FCC-P005

Sight FlowGlass

FI PG

"DA"

FIC PI

To Atmosphere orESP Inlet

Steam

Ejector

Catalyst Fillingand Withdrawal

To/FromRegenerator

Catalyst Loadingand Unloadingfrom Shipping

Containers

RemovableSpoolpiece(blankoffwhen notunloading

Ecat)

LI

ManualGauging

Hatch

Air Purge

157048 Procedures Page 87

Figure 6: Catalyst Standpipe Blast and Sample Point

PlantAir

SamplePoint

F

E

D

C

BA

Steam

Min

RO

StrainerCatalyst

Standpipe

FCC-P006

157048 Safety

Page 1

SAFETY

A. GENERAL

Safety is a broad field that covers a variety of topics from fire fighting to toxic

chemicals. Awareness of safety in the refinery is extremely important. As a basis for

a safety program, regulations and guidelines from government and professional

groups should be studied for their effect on this unit and then implemented by the

refinery staff. The staff must develop its own coordinated plant-wide method of

implementing safe and proper procedures, and of handling emergencies, which

should include:

1. Training to develop the operator's knowledge of equipment operation, and the

nature of the FCC unit.

2. Good communication among all involved groups concerning activities in

progress, and of prime importance, as well, is the use of common sense.

3. Emergency planning and practice drills.

The following discussion is not intended to supersede or otherwise replace refinery

safety practices, but rather, should be used as a supplement or reminder of some of

the important safety features.

B. PRECAUTIONS FOR ENTERING VESSELS

The reactor must be adequately cooled before air is admitted into the vessel. If the

reactor is not sufficiently cooled, auto-ignition of hot coke deposits in the reactor or

its vapor line may result. The reactor must be cooled to below 300°F (150°C) before

any manways or nozzles are opened. Riser or stripping steam can be used to help

cool the vessel.

157048 Safety

Page 2

The following safety precautions should be followed to protect personnel entering a vessel against toxic materials, such as H2S, which are present in the RCC Unit:

1. The vessels should be isolated by positive action, such as blinding, to exclude

all sources of hydrocarbon, steam, etc.

2. An air mover should be installed at the vessel's manway to sweep away any

vapors and provide a continuous supply of fresh air.

3. Responsible personnel must test the atmosphere in the vessel for explosivity,

toxic fumes, oxygen content, dust, etc. Permission for vessel entry should be

given only after this testing has been done.

4. Personnel entering the vessel must be equipped with a pressure demand

respirator that is in proper working condition, and is connected to a suitable

fresh air supply.

5. Separate air supplies which are independent of electrical power should be

available for immediate use and transfer to personnel in the vessel.

6. Personnel entering the vessel should wear a safety harness with a properly

attached safety line.

7. If the work is to be performed at a high level above the bottom of the vessel,

such as cyclone inspection, scaffolding and support flooring must be built to

prevent falls.

8. There should be a minimum of two backup men at the vessel manway in

continuous surveillance of the personnel in the vessel.

157048 Safety

Page 3

9. There should be spare pressure demand respirators, complete with their own

separate air supplies, to allow backup personnel to enter the vessel quickly in

case of an emergency. This spare equipment must be compact enough to

allow the users to enter through the manway while wearing the equipment.

10. It is recommended that any personnel working in a vessel which has an inert

or contaminated atmosphere not be permitted to move too far away from the

entryway, or into any tight areas, such as through a fractionator tray manway.

If the person should develop some difficulty in an inaccessible area to a point

where he could not function properly or lost consciousness, it would be

extremely difficult for the surveillance team to assist or move the person by

use of his safety line.

C. HIGH TEMPERATURE PRECAUTIONS

A hazard that is commonly encountered on an RCC Unit is the rapid heating of

unloading lines and the catalyst storage hopper when catalyst is unloaded from the

regenerator. The unloading lines and hopper will heat up very quickly from their

normal ambient temperature. Anyone working around the uninsulated lines or

vessels should be warned that these will get hot. Combustible materials and trash

should be kept away from the unloading lines and equilibrium catalyst hoppers.

D. WATER VAPORIZATION HAZARD

The danger of vaporizing water in a liquid-full vessel exists anywhere in the refinery

where a heating source exists and a water pocket can form. In the FCC unit, this is

most likely to occur in the main column bottoms circuit. Anytime a vessel such as a

slurry settler, or a bottoms coke strainer or filter is opened for maintenance,

particular care must be paid to removing all free water and slowly heating the vessel

back up to operating temperature. This is true for the bottoms heat exchangers as

well. If water is heated in a hydrostatically full vessel, it will follow its vapor liquid

equilibrium curve and begin increasing in pressure. If the vessel design pressure is

157048 Safety

Page 4

exceeded and the vessel cracks and relieves the internal pressure, the superheated

water will expand approximately 1600 times in volume, resulting in a catastrophic

failure of the vessel. This is similar to a classic boiler explosion mechanism.

Operating and maintenance procedures must be written and followed to prevent

equipment water pockets and rapid heating.

E. CHEMICAL HAZARDS

The hydrocarbons, catalyst, and chemicals encountered in an RCC Unit are not

hazardous as long as they are handled according to safe refinery practices. If they

are mishandled, or allowed to escape into the atmosphere, some of them may be a

hazard to the health of anyone in the area. It is recommended that the refiner

determine the allowable safe limits according to laws, rules, and regulations issued

by various agencies which apply to the material in question.

It is suggested that methods ASTM D-170, ASTM E-300, and UOP 516 be followed

regarding sampling techniques.

Hazardous materials present in the RCC Unit, and their emergency treatments,

include:

1. Catalyst

Fluid cracking catalyst is a fine dust capable of causing eye and lung irritation. When

unloading catalyst cars, drawing samples, etc., goggles or a face shield should be

worn. If the circumstances are such that the working atmosphere becomes dusty, a

dust mask should also be worn. The Material Safety Data Sheet provided by the

catalyst manufacturer needs to be consulted for additional detailed information.

When drawing hot regenerated catalyst samples, gloves and long sleeved clothing

should always be worn. In case of hot catalyst leaks, care must be exercised to

avoid the contact with hot catalyst on unprotected skin.

157048 Safety

Page 5

Loose catalyst is a relatively poor conductor of heat. While the surface of a pile of

catalyst may be cool, the interior may be very hot. Personnel should not walk over or

work around piles of spilled catalyst.

2. Iron Sulfide

Iron sulfide is a black or gray powder deposit found in vessels where sulfur corrosion

has occurred. It is easily mistaken for coke. The danger of iron sulfide lies in its

"pyrophoric" properties. It will ignite spontaneously when exposed to air, which is

most likely to occur in recently opened refinery vessels.

A vessel suspected of containing iron sulfide must be thoroughly steamed out and

washed with water before air is permitted to enter. Any suspected deposits must be

kept wet until they can be removed and disposed of properly.

3. Heavy Cracked Hydrocarbons

Heavy cracked oils are skin irritants. When drawing samples, draining equipment,

and cleaning vessels or exchangers, suitable care should be exercised to avoid skin

contact. In case of actual contact, the skin should be thoroughly washed with hot

soapy water, and any oil-saturated clothing should be removed.

Should any hydrocarbon enter the eye, the recommended First Aid is to wash with a

copious amount of clean water and obtain trained medical assistance as quickly as

possible.

4. Light Cracked Hydrocarbon Liquids

Hydrocarbons in the gasoline boiling range will remove the natural oil from the skin,

leaving it unprotected and subject to irritation or infection. Those gasoline streams

which contain aromatics will be particularly dangerous. Benzene is a poison, and

heavier aromatics have a narcotic effect.

157048 Safety

Page 6

In case of exposure, no time should be lost in removing any gasoline-soaked

clothing and washing the skin with hot soapy water. First Aid for eye injuries is

the same as that discussed above under "Heavy Cracked Hydrocarbons."

5. Aromatic Hydrocarbons

a. Benzene2

The most toxic hydrocarbon present in the unit is benzene. The danger in

exposure to benzene lies in its carcinogenic effect on the body's blood-forming

organs, an effect which is cumulative with each exposure. This aromatic

component is contained in the gasoline and heavy naphtha streams in the unit.

If clothing, including gloves, becomes wet from benzene, immediately remove the

clothing. Wash the skin areas exposed to benzene with soap and water. Take a

complete bath if the body area is wetted with benzene. Do not wear clothing that

has been wet with benzene until the garment has been washed and dried.

Wearing clothing that has been wet with benzene almost assures that the person

will inhale benzene vapors over a long period of time with serious hazard to

health.

Avoid draining benzene on the ground or into the sewers where it can vaporize

and create a health hazard. If benzene is accidentally spilled, flush it from the

area and the sewer catch basin with large quantities of cold water. Do not use hot

water or steam which further vaporizes the benzene. If you must enter an area of

high benzene vapor concentration resulting from a spill, wear a pressure demand

respirator.

2

For detailed information to take on exposure and potential hazards, consult Chapter XVII of OHSA Publication 1910.1028, Appendix A.

157048 Safety

Page 7

Though not specifically a health hazard, a problem resulting from benzene entering

the sewer is that benzene is much more soluble in water than any other

hydrocarbons. This places an extra load on the effluent treating system.

b. Toluene, Xylenes, and Heavier Aromatics3

These aromatic compounds are present in the gasoline and heavy naphtha streams

in the unit. These compounds are only mildly toxic and do not have the destructive

effect on the blood-forming organs as does benzene. Their principal effect is skin,

eye, and respiratory irritation. If clothing becomes wet with such aromatics, remove

the clothing, bathe, and put on fresh clothing. Avoid breathing aromatic vapors.

All employees should be alerted as to the early signs and symptoms of excessive

absorption of aromatics, and all workers should report such symptoms to the

Medical Department. In addition, all employees should, of course, be advised of the

hazards involved and precautions to be taken when working with aromatics.

6. Light Hydrocarbon Vapors

The inhalation of any light hydrocarbon vapor should be avoided. Such vapors can be toxic, since they may contain aromatics, H2S, or other lethal compounds.

A person who has breathed quantities of hydrocarbon vapors should be removed

from the area and kept warm and quiet. If necessary, artificial respiration with or

without the use of oxygen should be administered and medical aid summoned.

Professional medical attention should be obtained at once.

3

See attached sheets for further hazard information.

157048 Safety

Page 8

7. Hydrogen Sulfide (H2S)3

Hydrogen sulfide is present in the gases produced by the cracking of hydrocarbons

containing sulfur. It will occur in the overhead receiver gas and will be dissolved in

the unstabilized gasoline.

Hydrogen sulfide is one of the most poisonous gases known. Exposure to an atmosphere containing less than 0.1% H2S may be fatal in 30 minutes or less. At

very low concentrations, hydrogen sulfide has the characteristic odor of rotten eggs,

but at higher concentrations, or extended exposure at low concentrations, the sense

of smell is paralyzed so that personnel may be unaware of its presence.

Extreme care must be exercised when opening lines and equipment which have contained even low concentrations of H2S, and an H2S detector should be used.

When drawing samples, venting instruments, bleeding pumps, etc., precautions

should be taken to avoid breathing the vapors.

A person exposed to H2S may become excited or dizzy, may stagger, and can

ultimately lose consciousness. First Aid consists of removal from the area and the

administration of artificial respiration with or without oxygen if breathing has stopped.

The patient should be kept warm and medical aid summoned.

157048 Safety

Page 9

8. Flue Gas

Flue gas from the regenerator contains little or no oxygen. Asphyxiation can result if

a person enters an improperly ventilated duct or a low area where the high density of

flue gas will cause it to accumulate.

Asphyxiation may be preceded by symptoms of dizziness, headache, or shortness of

breath.

RCC flue gas is very dangerous since it contains carbon monoxide, which is toxic. A

concentration of 0.4% can be fatal in about one hour. One visible symptom of carbon

monoxide poisoning is a bluish-red color of the skin.

First Aid in cases of flue gas asphyxiation or poisoning consists of keeping the victim

warm and administering artificial respiration and oxygen, if necessary, obtain

professional medical attention immediately.

157048 Safety

Page 10

HYDROGEN SULFIDE

EXPOSURE

CALL FOR MEDICAL AID.

VAPOR POISONOUS IF INHALED.

Irritating to eyes.

Move to fresh air.

If breathing has stopped, give artificial respiration.

If breathing is difficult, give oxygen.

IF IN EYES, hold eyelids open and flush with plenty of water.

HEALTH HAZARDS

PERSONAL PROTECTIVE EQUIPMENT: Rubber-framed goggles; approved

respiratory protection.

SYMPTOMS FOLLOWING EXPOSURE: Irritation of eyes, nose and throat. If high

concentrations are inhaled, hyperpnea and respiratory paralysis may occur. Very

high concentrations may produce pulmonary edema.

TREATMENT FOR EXPOSURE (THRESHOLD LIMIT VALUE): 10 ppm

SHORT-TERM INHALATION LIMITS: 200 ppm for 10 min., and 50 ppm for 60 min.

TOXICITY BY INGESTION: Hydrogen sulfide is present as a gas at room

temperature, so ingestion not likely.

LATE TOXICITY: Data not available.

VAPOR (GAS) IRRITANT CHARACTERISTICS: Vapor is moderately irritating such

that personnel will not usually tolerate moderate or high vapor concentration.

157048 Safety

Page 11

LIQUID OR SOLID CHARACTERISTICS: Minimum hazard. If spilled on clothing and

allowed to remain, may cause smarting and reddening of the skin.

ODOR THRESHOLD: 0.0047 ppm.

157048 Safety

Page 12

TOLUENE

EXPOSURE

CALL FOR MEDICAL AID.

VAPOR

Irritating to eyes, nose and throat.

If inhaled, will cause nausea, vomiting, headache, dizziness, difficult breathing, or

loss of consciousness.

Move to fresh air.

If breathing has stopped, give artificial respiration. If breathing is difficult, give

oxygen.

LIQUID

Irritating to skin and eyes.

If swallowed, will cause nausea, vomiting or loss of consciousness. Remove

contaminated clothing and shoes.

Flush affected areas with plenty of water.

IF IN EYES, hold eyelids open and flush with plenty of water.

IF SWALLOWED and victim is CONSCIOUS, have victim drink water or milk. DO

NOT INDUCE VOMITING.

HEALTH HAZARDS

PERSONAL PROTECTIVE EQUIPMENT: Air-supplied mask; goggles or face shield;

plastic gloves.

157048 Safety

Page 13

SYMPTOMS FOLLOWING EXPOSURE: Vapors irritate eyes and upper respiratory

tract; cause dizziness, headache, anesthesia, respiratory arrest. Liquid irritates eyes

and causes drying of skin. If aspirated, causes coughing, gagging, distress, and

rapidly developing pulmonary edema. If ingested causes vomiting, griping, diarrhea,

depressed respiration.

TREATMENT FOR EXPOSURE: INHALATION: remove to fresh air, give artificial

respiration and oxygen if needed; call a doctor. INGESTION: do NOT induce

vomiting. Call a doctor. EYES: flush with water for at least 15 min. SKIN: wipe off,

wash with soap and water.

TOXICITY BY INHALATION (THRESHOLD LIMIT VALUE): 100 ppm.

SHORT-TERM INHALATION LIMITS: 600 ppm for 30 min.

TOXICITY BY INGESTION: Grade 2; LD50 0.5 to 5 g/kg

LATE TOXICITY: Kidney and liver damage may follow ingestion.

VAPOR (GAS) IRRITANT CHARACTERISTICS: Vapors cause a slight smarting of

the eyes or respiratory system if present in high concentrations. The effect is

temporary.

LIQUID OR SOLID CHARACTERISTICS: Minimum hazard. If spilled on clothing and

allowed to remain, may cause smarting and reddening of the skin.

ODOR THRESHOLD: 0.17 ppm.

157048 Safety

Page 14

XYLENES

EXPOSURE

CALL FOR MEDICAL AID.

VAPOR

Irritating to eyes, nose and throat.

If inhaled, will cause headache, difficult breathing, or loss of consciousness.

Move to fresh air.

If breathing has stopped, give artificial respiration. If breathing is difficult, give

oxygen.

LIQUID

Irritating to skin and eyes.

If swallowed, will cause nausea, vomiting or loss of consciousness. Remove

contaminated clothing and shoes.

Flush affected areas with plenty of water.

IF IN EYES, hold eyelids open and flush with plenty of water.

IF SWALLOWED and victim is CONSCIOUS, have victim drink water or milk.

DO NOT INDUCE VOMITING.

HEALTH HAZARDS

PERSONAL PROTECTIVE EQUIPMENT: Approved canister or air-supplied mask;

goggles or face shield; plastic gloves and boots.

SYMPTOMS FOLLOWING EXPOSURE: Vapors cause headache and dizziness.

Liquid irritates eyes and skin. If taken into lungs, causes severe coughing, distress,

and rapidly developing pulmonary edema. If ingested, causes nausea, vomiting,

cramps, headache, and coma; can be fatal. Kidney and liver damage can occur.

157048 Safety

Page 15

TREATMENT FOR EXPOSURE: INHALATION: remove to fresh air, administer

artificial respiration and oxygen if required; call a doctor. INGESTION: do NOT

induce vomiting; call a doctor. EYES: flush with water for at least 15 min. SKIN: wipe

off, wash with soap and water.

TOXICITY BY INHALATION (THRESHOLD LIMIT VALUE): 100 ppm.

SHORT-TERM INHALATION LIMITS: 300 ppm for 30 min.

TOXICITY BY INGESTION: Grade 3; LD50 50 to 500 g/kg

LATE TOXICITY: Kidney and liver damage.

VAPOR (GAS) IRRITANT CHARACTERISTICS: Vapors cause a slight smarting of

the eyes or respiratory system if present in high concentrations. The effect is

temporary.

LIQUID OR SOLID CHARACTERISTICS: Minimum hazard. If spilled on clothing and

allowed to remain, may cause smarting and reddening of the skin.

ODOR THRESHOLD: 0.05 ppm.

157048 Environmental

Page 1

ENVIRONMENTAL

Introduction

The refiner today is facing ever tighter environmental regulations. This section will

discuss some of the normal FCCU pollutants and potential methods for their

reduction. It is assumed that each refiner will be familiar with the restrictions placed

on him by the appropriate authorities, as these widely varying and ever-changing

rules are beyond the scope of this book.

There are four primary sources of emissions from the FCCU. These are:

• Regenerator Flue Gas • Sour Water • Main Column Bottoms Catalyst Fines • Fired Heater Stack Gas

The major source is the regenerator flue gas, it will be discussed first.

Regenerator Flue Gas

The flue gas flow rate is about 105 - 110% (wt) of the inlet air rate on a dry basis.

The composition of the gas will vary with the mode of regeneration, i.e., partial or

complete combustion, and with other factors such as feedstock composition.

Typical uncontrolled emission concentrations are shown in Table 1. Normally, the breakdown of the flue gas will be 75-80 vol% N2 + Argon, 15-22 vol% CO + CO2

and 8 -12% water vapor.

157048 Environmental

Page 2

TABLE 1

FCCU REGENERATOR UNCONTROLLED

FLUE GAS EMISSIONS FLUE GAS CONCENTRATIONS

Species

Bubbling Bed

Partial

Combustion

Bubbling Bed

Complete

Combustion

High Efficiency

Regenerator

Complete

Combustion

CO 90,000 ppm <500 ppm <100 ppm

Particulates

(note 2)

20-30 lb/mm SCF

350-450 mg/Nm3

15-30 lb/mm SCF

250-450 mg/Nm3

Opacity

(note 2)

25-50% 20-50%

SOx

(note 3)

200-2000 ppm

Hydrocarbons <200 ppm <10 ppm <10 ppm

NH3 <200 ppm <10 ppm <10 ppm

NOx 50-100 ppm 150-350 ppm <60 ppm

Notes: 1. All ppm concentrations are by volume

2. No external particle removal such as ESP or WGS

3. No SOx reduction such as catalyst additives or WGS

157048 Environmental

Page 3

CO, Hydrocarbons, and NH3

The amount of hydrocarbons and NH3 present will depend primarily on the

feedstock characteristics and operating severity. Hydrocarbon and NH3 are

normally present in only trace quantities, while CO and CO2 from coke combustion

are major constituents of the flue gas. The disposal of these pollutants can best be

handled by burning them, either in a complete combustion regenerator or with a CO

boiler. In most cases complete combustion is the favored method for a variety of

economic and process reasons. Complete combustion will convert most CO and hydrocarbons to CO2 and water vapor, while the higher oxygen atmosphere of the

complete combustion unit decreases the amount of ammonia formed. This

observation is based on commercial plant experience; the mechanism of ammonia

formation has not been definitely proven.

Particulates

The particulates from the FCCU regenerator cyclones are primarily catalyst fines of

less than 40 microns and the particulate loading is in the range of 15-30 lb/MMSCF

(250-450 mg/Nm3). In addition to the catalyst fines, some condensables such as

sulfates will be present if the sampling temperature is low enough. In the USA, the

temperature specified by EPA Method #5 is 248°F + 25°F (120°C). At this temper-

ature some sulfur compounds and hydrocarbons will condense, which may cause a

higher particulate measurement.

In the United States the particulate level in the flue gas is typically limited to 1 lb of

solids per 1000 lb of coke burned or approximately 4.7-6.5 lb/MMSCF of flue gas

(80-110 mg solids/Nm3); the European regulation varies from 80-500 mg/Nm3.

Future regulations may reduce this value to 50 mg/Nm3.

These environmental regulations typically require an electrostatic precipitator (ESP)

or wet gas scrubber (WGS) to bring particulate emissions down to an acceptable

level. The precipitator is the less expensive of the two options in many cases,

depending on flow rates, pressures, temperatures, and particulate loadings, but

157048 Environmental

Page 4

neither one is inexpensive to construct or operate. Disposal of the collected wastes

can be difficult. The precipitator yields dry catalyst fines which can be used for

landfill or as a raw material for cement. The scrubber generates a waste liquid or

slurry stream high in fines and solids, which must be further treated. The removal of SOx is an added advantage for the scrubber system, with efficiencies of up to 95%

claimed by some manufacturers.

Improvements in third stage separator (TSS) technology which uses cyclonic

separators external to the regenerator have improved efficiency to the point where

tit may be considered a less expensive alternative capable of meeting

environmental regulations. Historically though, TSS use has been limited primarily

to protection of power recovery equipment and did not eliminate the need for the

ESP or WGS.

Opacity

Opacity is the quality or state of a substance which renders that substance

impervious to rays of light. Opaque stack emissions that block all light would have

an opacity of 100%, while clear emissions that do not attenuate light have an

opacity of zero. Another scale which is sometimes used for gray or black emissions

is the Ringelmann Number, going from 0 (clear) to 5 (opaque). A Ringelmann

Number of 1.5 would correspond to an opacity of 30%.

A high opacity for an FCCU regenerator stack would be caused by:

1. Catalyst fines (either greater content or shift to smaller PSD) 2. Unburned hydrocarbons 3. Condensibles such as SOx and NH3 4. Water vapor

157048 Environmental

Page 5

Each of these would have a separate solution, and would normally be accompanied

by other problems. Large amounts of catalyst fines from the stack could indicate

excessive attrition or poor cyclone performance. If the plume were caused by

unburned hydrocarbons, this would indicate poor regenerator operation.

Control of condensables such as SOx are discussed elsewhere in this section.

Water vapor is sometimes mistaken for catalyst fines. This vapor usually does not

cause problems meeting environmental regulations and it should not be excessive;

large increases in water output should be investigated if the water vapor rate is

excessive.

Sulfur Oxides The flue gas sulfur oxides are formed when sulfur in the coke is oxidized to SOx in

the regenerator. These oxides are primarily SO2 (~90%), with lesser amounts of

SO3 (~10%); the total SOx increases as feed sulfur increases and depends on the

type of compounds containing the sulfur.

There are basically two methods of reducing SOx besides feed pretreatment: using

a catalyst additive, i.e. a “SOx control catalyst" and wet gas scrubbing (dry

scrubbing with limestone has also been used, but it is impractical for most refiners). The SOx control catalyst additive is injected independent of the FCC catalyst (a

small injection device is required) and is typically 3-10% of the catalyst inventory. The additive adsorbs SOx in an oxidizing environment (regenerator) and liberates

sulfur as H2S in a reducing environment (reactor). SOx control additives can

typically remove 10-20 lb SOx/lb additive down to a limit of ~300 vppm in the flue

gas. This process relies on oxidizing the SO2 to SO3 and is therefore typically more

effective in a complete combustion unit with excess oxygen present.

UOP has acquired the right to license the Exxon Wet Gas Scrubbing (WGS)

process (see Figure 1) to UOP-licensed FCC or RFCC units. The WGS process removes both SOx and particulates from the FCC or RFCC flue gas. The WGS uses

a venturi device which provides intimate contacting of the flue gas with a mildly

alkaline solution. The system can also tolerate large solids carryover from the

regenerator if an upset should occur. The catalyst fines are removed as moist filter

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cakes and the water effluent contains dissolved salts (sodium sulfate). Wet gas scrubbing can remove up to 90% of the SOx from the flue gas down to <50 vppm.

Precise economic comparisons between using a SOx control catalyst and the WGS

process are difficult because the value assigned to particulates removal has a major effect on the selection. In general, the SOx control catalyst will be more attractive at

low-to-moderate amounts of SOx removal (below 1000 vol ppm) and the WGS is

more attractive for removing large quantities of SOx (above 1500 vol ppm) or for

meeting very low SOx emissions (<200 vppm). Between 1000 and 1500 ppm of SOx

removed, the choice depends on a number of factors including variability of installed

cost, presence of existing particulate removal equipment, local environmental laws, utility and chemical costs and relative amount of SOx removal.

Nitrogen Oxides

The amount of NOx emitted from the regenerator is highly dependent upon several

variables such as mode of operation, regenerator style, excess O2, promoter

concentration, coke distribution, feed nitrogen, and dense bed temperature. Studies

have shown that about half of the feed nitrogen goes to coke on catalyst, but only

about 10% of the nitrogen in coke goes to NOx. It is believed that the NOx emission

is limited by the reaction of CO + NO to form N2 and CO2. Thus, when Pt CO

promoter is added to a unit, CO is converted to CO2 so quickly that there is less CO

available to react with the NOx and NOx emissions increase. In a partial burn

operation, there is always CO available to react with the NOx formed so emissions

are lower. Good coke and air distribution is important so that concentrations of CO,

O2 and NOx are evenly distributed throughout the regenerator. There are

fundamental differences in the operation of a bubbling bed operating in full

combustion with CO promoter and a high efficiency regenerator operating in full

combustion without the need for CO promoter.

Bubbling Bed Regenerator

The bubbling bed type regenerator burns coke from spent FCC catalyst in a back-

mixed dense phase fluidized bed. The regenerator consists of a closed cylindrical

pressure vessel sized to contain a dense phase fluidized bed of catalyst in the

bottom of the vessel and multiple sets of cyclone separators within the dilute phase

existing in the upper portion of the vessel.

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Spent catalyst enters the regenerator at the side of the vessel at the surface of the

fluidized dense phase of catalyst. Air for coke combustion is distributed uniformly

across the cross-section of the vessel near the bottom of the fluidized bed through

an air distributor. The carbon burning reactions proceed largely in series, with coke

burning to CO first and then CO burning to CO2. Since the fluidized bed is

substantially back-mixed, there is a rather wide distribution of residence times for

both the combustion reactants and products. Further, since fluidized dense beds

mix better vertically than laterally, it is difficult to mix reactants (air and coke)

uniformly across the cross-section of the vessel. This leads to non-uniform burning

profiles and requires longer average residence times, higher quantities of excess

oxygen and higher levels of Pt combustion promoter to assure that the catalyst is

burned clean (regenerated fully) and that CO is fully converted to CO2 to avoid

exceeding CO emission limits. This combination of factors, i.e. long residence

times, non-uniform burning profiles, higher required levels of excess oxygen (~2

mol%), and higher required levels of Pt combustion promoter, result in this style of

regenerator typically producing on the order of 3 to 4 times the NOx emissions

relative to the equivalent High Efficiency Combustor style regenerator.

Combustor Style Regenerator

The High Efficiency Combustor style regenerator burns coke from the spent catalyst

in a quasi-plug flow fast fluidization burning zone. The High Efficiency style

regenerator is divided into two separate zones. The lower section is the combustor

zone where the coke burning occurs. The upper section of the regenerator (second

zone) serves to hold a reservoir of regenerated catalyst and also contains multiple

sets of cyclones in the dilute phase of the upper regenerator. Very little, if any, coke

burning occurs in this upper portion of the regenerator vessel.

Spent catalyst (carrying the coke), air and a substantial quantity of hot clean

regenerated catalyst are mixed together in the bottom of the combustor. The

combustor vessel is sized so that it operates in the velocity and density regime

characterized as fast fluidization. This permits quasi-plug flow transport of material

from the bottom of the combustor vessel upward and out to the upper regenerator

through a vapor/catalyst disengaging device. The moderate operating density of the

combustor (burn zone) permits rapid and uniform mixing of material entering the

bottom of the combustor. The recycle of hot regenerated catalyst permits a degree

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of control over residence time and initial rates of coke combustion. The quasi-plug

flow behavior of the fast fluidized bed assures relatively narrow and controlled

residence time distributions. Overall, the High Efficiency Combustor style of

regenerator provides better control of the burning zone.

The results of the better (or more efficient) control of the burn zone in the

Combustor style regenerator are that:

Oxygen is used more efficiently so that lower levels of excess oxygen are

required to completely burn the coke to CO2 while minimizing CO emissions

Generally Pt combustion promoter is not needed (at design rates) to accelerate

the burn to completion because hot recycled catalyst is used to increase the

burning rate by preheating the combustion reactants (air and coke on spent

catalyst)

The preheating effect of recycling hot regenerated catalyst, combined with the

efficient mixing and uniform residence time distribution in the combustor permits

the time spent in the combustor to be minimized

The net result of these combustion characteristics of the Combustor style

regenerator is that substantially lower levels of NOx are produced.

Plant Upsets

The values given for pollutant concentration in Table 1 are for normal plant

operation. During upsets these numbers may be grossly exceeded. An example of

this would be an oil reversal into the regenerator. Massive amounts of hydrocarbons

may be emitted. While the FCCU has been designed for safe operation, something

as simple as a sticky slide valve may thwart initial corrective action. The best way to

minimize these upsets is careful attention to the unit, with well trained operators that

understand what action should be taken, and why it is done.

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Main Column Overhead Receiver Sour Water

Wash water is used in the FCCU to remove ammonia, cyanides, and some sulfur

compounds which can cause corrosion and fouling in the unit. The water is injected

into the interstage cooler of the wet gas compressor at a rate of ~2 GPM/1000 BPD

(5-7 vol% of fresh feed). The water goes through the coolers and is pumped from

the interstage receiver to the high pressure separator. From here it circulates back

to wash the main column overhead condensers, and leaves the plant from the

overhead receiver water boot.

In many units stripping, lift and feed atomizing steam in the reactor will double the

amount of water drained over the amount injected in the gas concentration unit.

The concentrations of the various contaminants in the water will depend on the feed

concentrations and the total sour water rates. For a 2 GPM/1000 BPD water

injection rate, the concentrations shown in Table 2 would be expected for a unit with

a feed sulfur of 1-2% and less than 1000 ppm of feed nitrogen.

TABLE 2

FCC SOUR WATER

CONCENTRATION IN MC OVHD WATER

Mode of Regenerator Operation Partial Complete Pollutant Combustion Combustion

Sulfide, ppm 3000 – 4000 3000 – 4000

Ammonia, ppm 1000 – 2000 1000 – 2000

Cyanide, ppm 40 – 150 30 – 50

Phenols, ppm 100 – 300 200 – 600

Hydrocarbons, ppm 100 – 2000 100 – 2000

All values are ppm by weight. The pH of the water from the overhead receiver should be in the basic range, pH = 8-9.

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Some refiners do not show pollutant levels as high as the values given in Table 2,

especially if the feed sulfur or nitrogen is low. The difference between the partial

and complete combustion mode of regenerator operation would involve oxygen

carryover with the regenerated catalyst, different oxidation levels in the regenerator

and other factors. The normal disposal method for the sour water is a sour water

stripper. The overhead vapor stream from the stripper is normally sent to a Claus-

type unit, although in some cases it may be simply burned. The stripper bottoms is

sent to waste water treatment; it has also been used for the crude unit desalter.

MCB Catalyst Fines

Catalyst fines leaving the reactor with the hydrocarbon product are concentrated in

the bottom of the main column and leave the unit with the bottoms product. Some of

these fines settle out in the product tank so that the tank needs to be cleaned

occasionally. The oil soaked fines removed from the tanks are considered

hazardous waste and must be disposed of properly. Catalyst fines in the bottoms

product can also cause problems with heaters and boilers firing heavy fuel oil.

Because of the high cost of tank cleaning and problems with downstream heaters

catalyst fines removal technology is being added or considered by many refiners.

UOP, through an alliance with Pall Corporation, offers filtration technology capable

of reducing the fines in the bottoms product to less than 50 wppm. Cyclonic

separation devices and slurry settlers are also in use but are less effective.

Fired Heater Stack Gas

Any environmental problems with the FCC fired heaters would be the same as

those encountered with the other refinery heaters. Efficient firing normally reduces CO content in the stack gas to a minimum. SOx and NOx can be minimized by

hydrotreating the fuel. Low Nox burners are also an effective means of NOx

reduction in fired heaters and boilers. Flue gas treating could also be used to

reduce emissions. Proper furnace operation will minimize emissions problems with

the stack gas.

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Fugitive Hydrocarbon Emissions

This category would cover hydrocarbon vapors from leaks, sampling or storage.

Refineries have always tried to minimize these losses, because uncontrolled

hydrocarbons are a fire and safety hazard, in addition to an economic loss. Closed

sampling systems and controlled venting on storage tanks will probably become

more common in the future.