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3.3 SPECIFICATION SHEETS3.3.1 Average (Radiant) Flux Density3.3.2 Process Tube Design Temperature and Pressure3.3.3 Decoking Pressure and Temperature3.3.4 Items Included in Scope of Each Heater3.3.5 Site and Utility Data3.3.6 Fuel Data3.3.7 Materials of Construction and Corrosion Allowance

3.4 AUXILIARY EQUIPMENT3.4.1 Reboiler Circulation System and Control3.4.2 Decoking Effluent Quench Drum3.4.3 Emergency Shutdown System

3.5 EXAMPLE SPECIFICATION SHEETS3.6 ADVANTAGES AND DISADVANTAGES

4.0 CRUDE OIL HEATER4.1 GENERAL4.2 CALCULATIONS

4.2.1 Heater Selection and Flowsketch4.2.2 Pressure Profile4.2.3 Flash Calculations4.2.4 Convection Section Heat Recovery

4.3 SPECIFICATION SHEETS4.3.1 Average (Radiant) Flux Density4.3.2 Process Tube Design Temperature and Pressure4.3.3 Decoking Pressure and Temperature4.3.4 Items Included in Scope of Each Heater4.3.5 Site and Utility Data

4.3.6 Fuel Data4.3.7 Materials of Construction and Corrosion Allowance

4.4 AUXILIARY EQUIPMENT4.4.1 Decoking Effluent Quench Drum4.4.2 Emergency Shutdown System

4.5 EXAMPLE SPECIFICATION SHEETS

5.0 STEAM - HYDROCARBON REFORMER5.1 GENERAL5.2 REFORMER CALCULATIONS

5.2.1 Background5.2.2 Calculations

5.3 SPECIFICATION SHEETS

5.3.1 Average (Radiant) Flux Density5.3.2 Reformer Catalyst Data5.3.3 Process and Convection Coil Design Temperature and Pressure5.3.4 Items Included in Scope of Each Heater5.3.5 Site and Utility Data5.3.6 Fuel Data

5.4 AUXILIARY EQUIPMENT

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5.5 EXAMPLE CALCULATIONS AND SPECIFICATION SHEETS5.5.1 Example Calculations for Overall System Heat Balance5.5.2 Example Specification Sheets

6.0 MATERIALS OF CONSTRUCTION6.1 TUBE MATERIALS

7.0 UTILITY REQUIREMENTS

8.0 REFERENCES, CODES AND STANDARDS8.1 REFERENCES8.2 CODES AND STANDARDS

9.0 REFERENCE ARTICLES

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1.0 INTRODUCTION

1.1 GENERAL

Fired heaters or furnaces are used extensively in the process industry. Some familiarexamples are open hearth blast furnaces, cement kilns, refinery crude oil heaters andglass furnaces. We will limit our discussion here, however, to fired heaters commonlyused in the chemical process industry, i.e., direct fired tubular heaters. We will use thewords "fired heater" and "furnace" in this context even though they do not fully define thenormal process-type heater.

You, as a Process Engineer, are responsible for specifying required process parameterssuch as heat duty, flow, and fuel composition as well as basic furnace configuration. Thetask force Mechanical Engineer assigned to fired heaters can assist in formulating abasic configuration for the furnace. Using all this information the vendor does the

mechanical design, specifying the number of tubes, tube length, and other detailedinformation. In short, FDI specifies the performance requirements for a fired heater whilethe vendor actual designs it.

This section provides some examples of calculations and specification data sheets forseveral types of fired heaters. All are widely used throughout the refining andpetrochemical industries. You should note that the examples presented here are takenfrom actual FDI projects.

1.2 CHARACTERISTICS AND USE OF FIRED HEATERS

All furnaces have a fire-box or combustion space where a fuel is burned, and a stackthrough which flue gases are discharged to the atmosphere. Fuel is usually natural gas,

refinery gas or fuel oil, but it may be coal or coke. The heat released in the fire-box isused directly or indirectly to produce a physical or chemical change on a processmaterial.

Fired heaters or "process furnaces" common to the refining and petrochemical industriesare direct fired tubular heaters. These are generally of two types, cabin or box(Figure 1-1) and cylindrical or vertical (Figure 1-2). The fluid to be heated is contained intube coil rows disposed along the walls and ceiling of the combustion chamber. Theprincipal mode of heat transfer is radiation. A "convection" section is generally added toincrease the efficiency of the furnace by extraction of additional h eat from thecombustion flue gas enroute to the stack. For more details on fired heater geometry seereference article entitled Fired Heaters I. In a direct fired tubular heater, radiant heatfrom the open-burner flames in the fire-box heats the process material flowing through

the heater tubes. In an indirect heater, the burner flames are enclosed on the sides bywalls, and thus the flames heat these walls. The walls in turn radiate heat to the processmaterial in the heater tubes (or other enclosure).

There are two general categories of direct fired tubular heaters. We will refer to these assimple heaters and reactor heaters. A simple heater, such as a crude oil heater, does

just what its name implies; it raises the temperature of a process material. In doing so, itmay vaporize some or all of that material. A familiar type of simple heater is anincinerator.

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Figure 1-1

BOX HEATER COMPONENTS

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Figure 1-2

VERTICAL HEATER COMPONENTS

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Table 1-1

TYPICAL FIRED HEATER APPLICATIONS

ServiceTypical Process OutletTemperature, oF (oC)

Tower Feed Preheater 400 - 750 (204 - 399)

Reboiler 350 - 650 (177 - 343)

Thermal Cracker 850 - 1,000 (454 - 538)

Visbreaker (Soaker) 900 (482)

Thermal Naphtha Reformer (Soaker) 1,000 - 1,025 (538 - 554)

Cat Reformer 900 - 1,050 (482 - 566)

Hydrogenation Preheater 400 - 700 (204 - 371)Hydrocracking 700 - 850 (371 - 454)

Steam Cracking (Ethylene) 1,500 + (815 + )

Dealkylation (Thermal) 1,400 + (760 + )

Waste Incinerator 2,500 - 3,500 (1,371 - 1,927)

Heating Oil Circulating System 300 - 700 (149 - 371)

Steam-Methane Reformer 1,450 - 1,500 + (788 - 815 +)

1.3 SPECIFICATION SHEETS

The Process Engineer is responsible for completing all necessary process calculationsprior to initiating the fired heater specification sheets. The Process Engineer andMechanical Engineer are jointly responsible for completing the fired heater specificationsheets, such as forms E-0522A-I, the Steam-HC Reformer Specification Sheets, andforms E-553A-H, the Fired Heater Specification Sheets. This section contains completedexamples of these specification sheets and the calculations pertaining to each.

The following FDI specification forms for fired heaters are routinely used:

Description Form

Incinerator E-460A-FSteam-HC Reformer E-522A-I

Fired Heater E-553A-H

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1.4 DATA SOURCES

The Process Engineer should complete the following items before starting fired heatercalculations:

Process Flow DiagramHeat and Material BalancePressure-Temperature-Metallurgical Survey

General specifications for fired heaters are written by the Mechanical Engineers. A copyshould be obtained as soon as it is available. In some cases the client's specificationsare used. These should be read prior to starting calculations, otherwise you may have tostart over. Process guidelines may be issued in the form of job bulletins or they mayhave been developed in book form. Other books such as Process Design Guidelines forGas Plants, Design Manuals, etc. should be read when applicable.

A preliminary plot plan is usually available in the early stages of a job. If one is notavailable, you can make your own sketches and refer to previous similar jobs. In anycase, you must update your pressure and temperature survey and revise yourcalculations as information is developed or received throughout the job. It may becomenecessary to revise the fired heater specification.

Physical properties may be obtained from computer runs, Vol. II General Data, or othersources. Your lead engineer should give you some guidelines in order to maintainuniformity on the job. In addition, refer to Section III, References for Physical Properties.

1.5 TERMS AND DEFINITIONS

Air Heater,Air Preheater

Heat transfer apparatus through which combustion air ispassed and heated by medium of higher temperature, steamor other fluid (such as the products of combustion).

Arch The flat of sloped portion of the heater radiant sectionopposite the floor.

Atomizer A device to reduce a liquid fuel to a fine spray. Atomizationmeans are normally either steam, air or mechanical.

Anchor Sometimes called tieback; a metallic or refractory devicewhich retains the refractory or insulation in place.

Balanced

Draft Heater

A heater in which the combustion air is supplied by a fan and

the flue gases are removed by a fan.

Breeching Enclosure which collects the flue gases after the lastconvection coil for transmission to the stack or the outletductwork.

Bridgewall Sometimes called Divisional Wall; a refractory wall separatingtwo adjacent heater zones.

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BridgewallTemperature

The flue gas temperature leaving the radiant section.

Burner A device for the introduction of fuel and air into a heater atthe desired velocities, turbulence and concentration toestablish and maintain proper ignition and combustion.Burners are classified by the types of fuel fired, such as; oil,gas and combination gas and oil.

Casing A metal plate covering used to enclose a fired heater.

CokingAllowance

A thickness which increases pressure drop due to a build-upof deposit on the inner surface of a coil expressed inmillimeters. This value shall be used in calculating the fouledpressure drop.

Convection

Section

The portion of the heater in which the heat is transferred to

the tubes primarily by convection.

Corbel A projection from the refractory surface generally used toprevent flue gas bypassing in the convection section.

CorrosionAllowance

Corrosion rate times tube design life, expressed inmillimeters.

Crossover The interconnecting piping between any two heater coilsections.

Damper A device for controlling the heater draft by regulating thevolumetric flow of gas or air.

Draft The negative pressure of the flue gas measured at any pointin the heater, expressed in millimeters of water.

Duct A conduit for air or flue gas flow.

Efficiency,Fuel

Heat absorbed divided by the net heat of combustion of thefuel as heat input, expressed as a percentage.

Efficiency,Thermal

Heat absorbed divided by total input to the heater system,expressed as a percentage.

Excess Air The amount of air above the stoichiometric requirement forcomplete combustion, expressed as a percentage.

Explosion Door A door in a heater setting designed to be opened by a

predetermined gas pressure.

Extended Surface Refers to the heat transfer surface in the form of fins or studsadded to the bore tubes.

FluxDensity(Average)

The total heat absorbed divided by the total exposed heatingsurface of the coil.

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FluxDensity

(Maximum)

The maximum local heat transfer rate in the coil section.

ForcedDraftHeater

A heater in which the combustion air is supplied by a fan.

FoulingResistance

Resistance to heat transfer caused by a build-up of residueon the inner surface of the coil.

Header Sometimes called return bend, common reference for a 180degree cast or wrought fitting, which connects two or moretubes.

Header Box Internally insulated structural compartment, separated fromthe flue gas stream, which is used to enclose a multiplicity of

headers.

HeatAbsorption

The total heat absorbed by the coil(s) excluding anycombustion air preheat.

Heat Release The total heat liberated from the specified fuel, using thelower heating value of the fuel.

Heating Value,Higher (HHV)

The total heat obtained from the combustion of a specifiedfuel at 15 oC (59 oF).

Heating Value,Lower (LHV)

The higher heating value minus the latent heat ofvaporization of the water formed by combustion of hydrogenin the fuel; also called the net heating value.

Induced DraftHeater

A heater in which a fan is used to remove flue gases.

Natural DraftHeater

A heater in which a stack effect induces the combustion airand removes the flue gases.

Pilot A small burner which provides ignition energy to light themain burner.

Plenum Sometimes called "windbox" is a chamber surrounding theburners which is used to distribute air to the burners or toreduce combustion noise.

Plug Type Header A return bend, normally cast, which is provided with one or

more openings to enable inspection, mechanical tubecleaning or draining.

Primary Air The portion of the total combustion air which first mixes withthe fuel.

Radiant Section The portion of the heater in which the heat is transferred tothe tubes primarily by radiation.

Secondary Air Air supplied to the fuel to supplement primary air.

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Shield Section Section containing those tubes which shield the convectionsection tubes from direct radiation.

Sootblower A mechanical device for discharging steam or air to cleanheat absorbing surfaces.

Stack A vertical conduit, to discharge flue gas to the atmosphere.

Strakes Sometimes called spoilers, they are metal attachments to theoutside of the stack that reduce wind-induced vibration.

Tube Guide A device used with floor supported vertical tubes to preventtubes from buckling, and with top supported vertical tubes torestrict movement.

Tube Pass As material enters the heater, its total flow is divided amongseveral groups of tubes. Each of these groups is called a

tube pass.

Volumetric HeatRelease

The heat released divided by the net volume of the radiantsection which excludes the volume of the coils and refractorydividing walls.

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1.0

2.0 PROCESS DESIGN CRITERIA

2.1 GENERAL

Before discussing the examples presented in this section, we want to give you someprocess design guidelines for fired heaters. Unless otherwise noted, what we presenthere will apply to process heaters in general. Details that are specific to a particular typeof fired heaters are discussed either in the corresponding example (presented later in thissection) or in the appropriate FDI design manual or other reference. You should refer tothese as needed.

Our discussion here will provide you with some of the fundamental means needed forcalculating and specifying process heaters. You should note that the numerical values ofcertain parameters given in our discussion, e.g., furnace efficiencies and radiant heatfluxes, are based on experience and "generally accepted practice" in the processindustry. As such, they should not be construed as "hard and fast" rules but rather asguidelines. With this in mind, let's now proceed with our discussion.

2.2 RADIANT HEAT FLUX AND RADIANT EFFICIENCY

You, the Process Engineer, or the Mechanical Engineer, must specify the allowableradiant heat flux for a process heater. Note that as heat flux increases, the tube lifedecreases but so does the initial cost of the heater. You must, therefore, choose a valuethat strikes a compromise between these factors. Sometimes, the client prefers tospecify the radiant heat flux. If, however, the decision is left to you, refer to Table 2-1 forsome typical average radiant flux for various types of heaters. You should also consultwith a heater specialist in the Mechanical Engineering Department. (Values of tubeside

pressure drop and mass velocity are also given in Table 2-1).

You must also specify the absorbed duty for a fired heater. This is the duty required tocarry out the desired physical or chemical change in the process fluid. The furnacevendor, in turn, calculates the fired duty of the heater, i.e. the heat that must be suppliedby the burners in order to transfer the absorbed duty. In most cases, the heat absorbedin the radiant section ranges from about 45 % to 55 % of the net heat input whenoperating with 20 to 30 percent excess air. High flux heaters and "all radiant' types(without a convection section) tend toward the low end of the efficiency range. Heatersfor services with low process temperatures and low heat fluxes have radiant efficienciesin the upper end of the range.

For a reasonable estimate of heater performance, you can assume that 50 % of the net

heat release is absorbed in the radiant section. How much of the remaining heat can beabsorbed from the flue gas is discussed in Section 2.4 of these design criteria.

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Table 2-1

TYPICAL AVERAGE DESIGN PARAMETERS FOR VARIOUS HEATERS

Average RadiantFlux (2)(3)

Minimum CoilPressure Drop

MassVelocity

Btu/hr ft2 psi lb/ft2sec

SingleFired

DoubleFired

SingleFired

DoubleFired

H2Reformers (1) 14,000 20,000 20 25 150

Naphtha/KeroseneLight Gas Oil

12,000 15,000 25 30 175

Heavy Gas Oil 10,000 12,500 30 35 200

Crude 10,000 12,500 100 150 225

Atmos./Vacuum Resid 9,000 11,000 100 150 250

kW/m2 MPa kg/m2sec

H2Reformers (1) 44.2 63.1 0.138 0.172 732

Naphtha/KeroseneLight Gas Oil

37.9 47.3 0.172 0.207 854

Heavy Gas Oil 31.5 39.4 0.207 0.241 976

Crude 31.5 39.4 0.689 1.034 1,098

Atmos./Vacuum Resid 28.4 34.7 0.689 1.034 1,220

Notes:

(1) I.D. Basis

(2) The maximum average heat flux to any tube in the convection section, based on bare outsidediameter surface, shall not exceed the maximum average flux allowable in the radiant section.Steam generation coils may have up to 40,000 Btu/hr ft2(126.2 kW/m2) maximum average flux.

Source: Fluor Daniel Process Design Criteria Manual.

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Table 2-2

HEATER SELECTION GUIDE (1)

Service Horizontal Vertical Helical

IndividualPass

Control

MultiPass

Control

IndividualPass

Control

MultiPass

Control

Noncoking

Below 30 MM Btu/hr (8.8 MW) X

Single Phase X X

Vaporizing (below 600 oF) (316 oC) X X

Hydrotreater (below 600

o

F)(316 oC) X X

Hydrogen Reformer X

Hydrogen X

Coking

Single Phase X X

Vaporizing X X

Hydrotreater (2) X X

Coker X

Visbreaker X

Crude/Vacuum X

Notes:

(1) If required to meet low pressure drop requirements, heaters handling 100 % vapor at inlet andoutlet conditions may be designed with arbor type coils.

(2) H2added to feed oil.

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2.3 FURNACE HEAT LOSSES AND MECHANICAL DRAFT OPERATION

The principle heat loss from a fired heater is the heat carried off by the flue gas leavingthe stack. The principle methods for improving heater efficiency, therefore, are reductionof the flue gas volume and reduction of stack temperature. For a given fired duty, theamount of fuel and the amount of air theoretically required for complete combustion arefixed. The only way we can reduce flue gas volume, then, is through reduction in theamount of excess air supplied to the burners. But, excess air is required for completecombustion of the fuel and stable burner operation. Furthermore, on a weight basis, fluegas must escape from the furnace stack at the same rate that air and fuel are supplied tothe burners. In the case of a natural draft heater, the flue gas must be hot enough, i.e.,have sufficient buoyancy, to do this. So, to lower both the amount of excess air and theflue gas temperature, furnace designers have turned to mechanical draft fired heaters.

Mechanical draft typically enables heaters to operate in the upper end of the radiant

efficiency range given in Section 2.2 of this discussion. Such heaters employ an induceddraft fan to pull flue gas out of the stack. Since much of the energy required for escapeis supplied by the fan, the flue gas can leave the radiant section at a lower temperaturethan in a natural draft furnace. A forced draft fan is used on the inlet side to pushambient air into the furnace combustion chambers. Modern mechanical draft furnacescan operate at 10 % excess air when fired with natural gas and 10-20 % excess air whenfired with clean liquid fuels. Despite the benefits of mechanical draft operation,considerable heat can still be lost from the stack. To further improve furnace efficiency,stack gas heat recovery is necessary. We discuss this in Section 2.4, the next part ofthese design criteria.

Before we move on, however, let's look at two more sources of heat loss from process

furnaces. First, heat is transmitted from heater surfaces to the outside air by radiationand convection. Losses of 1 to 1 1/2 percent of the fired duty for natural draft furnacesare normal. For mechanical draft furnaces having an air preheater, losses of 2 to 2 1/2percent of the fired duty can be expected. Air preheaters require extensive runs of hotair (Air preheat is discussed further in Section 2.4.) In general, heat losses should notexceed 3 % of the fired duty and the maximum metal casing temperature should notexceed 180 oF (82 oC) at ambient temperature of 80 oF (27 oC) in still air. Second, thefurnace combustion chamber and convection section operate under slightly negativepressure. If leaks are allowed to develop, quantities of excess air greater than what isrequired for complete fuel combustion will be pulled into the furnace. This results inadditional heat loss from the flue stack. Losses due to leaks, however, generally resultfrom poor plant maintenance rather than design. In order to competently specify aprocess heater, you must be aware of all of the heat losses discussed here. The furnace

vendor must take these into account in the mechanical design of a heater.

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2.4 CONVECTION HEAT RECOVERY

By using stack gas heat recovery you can, in general, design fired heaters for overallthermal efficiencies of from 83-91 %. This is considerable since the highest radiantefficiency for a process heater is about 55 %. It should come as no surprise then, thatconvection section heat recovery is an integral part of specifying and designing firedheaters.

In specifying a flue gas hat recovery system, you must first calculate the amount of heatavailable for recovery. This can be related to the furnace radiant duty as follows:

Convection Duty = (Radiant Duty)

Overall Thermal Efficiency

Radiant Efficiency 1.0

You can obtain the radiant duty from the process heat and material balance if theprocess fluid only goes through the radiant section. Otherwise you will have to split theprocess duty between the radiant and convection sections.

In the early stages of a job, vendor data for your particular heater will not be available, soyou will have to estimate the radiant and overall efficiencies. And, as we mentionedabove, you may also have to estimate the split in process duty between the radiant andconvection sections. For guidance, you should refer to the design data for similarheaters on past jobs and to the appropriate FDI design manual. Also, you should consultwith a heater specialist to the Mechanical Engineering Department.

Instead of using the above equation, you can calculate the amount of flue gas heatavailable for recovery using a computer program (consult with a computer specialist).

The output for this program should include temperature-enthalpy data for the stack gas.Using this data, you can plot a cooling curve and find the amount of available heat. Useof this method is discussed in detail in Section 5.2 of this manual, Reformer Calculations.Even though the example presented there is a steam-hydrocarbon reformer, thediscussion of the Furnace Calculation Program applies to fired heaters in general. Youshould refer to that part of our discussion for further information.

The second major step in specifying convection section heat recovery is to decide whatto do with the available heat. There are three options generally available. First, you canheat the process fluid before it goes to the radiant section. This reduces the furnaceradiant duty and size and thus can significantly reduce the initial cost of the heater.Second, you can use the stack gases to generate steam in either a waste heat boiler orin steam coils fitted into the flue stack. This is often the preferred choice if the steam can

be used in the plant. Third, you can preheat the incoming combustion air. This is oftendone as it does the most to improve furnace efficiency. We should point out that the useof air preheat requires mechanical draft operation. The relatively high friction losses inthe air preheater and associated duct work make natural draft operation infeasible.

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The expected overall thermal efficiencies for mechanical draft fired heaters range up to91 % with air preheat and up to 89 % using only a waste heat boiler. For natural draft

heaters, the maximum expected efficiencies range from 84 to 88 %. Most convectionheat recovery schemes usually employ air preheat and one of the other two types ofrecovery we have discussed. We will now present a few examples of such schemesalong with some further discussion.

Figure 2-1 shows a typical fired reboiler flow scheme. Material from the column sump isfirst heated in the convection section and then in the radiant section. Heating theprocess fluid in the convection section reduces the radiant duty and overall size of thefurnace. An induced draft fan pulls flue gas out of the stack and through the airpreheater, while the combustion air is pressured through the air preheater by a forceddraft fan. Here the flue gas heats the incoming combustion air on its way to theburners.With air preheat included, overall thermal efficiencies as high as 91 % can beachieved. See the article entitled Fired Heaters - IV ... located at the end of this manual

for a discussion on the types of air preheaters available.

Figure 2-2 shows another typical convection heat recovery scheme for a fired heater.For heaters with fired duties on the order of one to several hundred million Btu per hour,and with radiant efficiencies of around 50 %, there is considerable heat that can berecovered from the flue gas. Generally, the convection heat recovery schemes for suchheaters are an integral part of the plant steam balance. For the case shown in Figure2-2, we are preheating the feed and generating steam in the convection section. Thesteam drum operates at saturated conditions. It is really a surge drum for both water andheat. Use of it allows better control of steam generation and superheating in theconvection coils. Without the upper three "economizer" coils, this type of heater wouldhave an overall thermal efficiency of about 58 %. With them, its overall efficiency is

around 85 %.

Before concluding our remarks here, we should tell you about the limitations in flue gasheat recovery. First, the maximum average heat flux rate to any tube in the convectionsection, based on bare outside diameter surface, shall not exceed the maximum averageflux rate allowable in the radiant section. Steam generation coils, however, may have upto a 40,000 Btu/hr ft2 (126.2 kW/m2) maximum average flux rate. Second, for steamgeneration coils, the limiting approach temperature is 50 oF (28 oC). The controllingresistance to heat transfer is obviously on the flue gas side of the coil. The filmcoefficients on this side are on the order of 0.2-20 Btu/hr ft 2oF (1.14-114 W/m2oC) versus1,000 - 3,000 Btu/hr ft2oF (5,680-17,030 W/m2oC) on the vaporizing side. Extended heattransfer surface, e.g., fin tubes, and relatively high approach temperatures are used tocompensate for this. Experience has shown that for stable operation, 50 oF (28 oC)

should be the lowest approach temperature for this service. Third, the amount of heatthat you can ultimately extract from the flue gas is often limited by the SO

3content of the

gas. Sulfur in furnace fuels partially ends up as SO3 in the stack gas. If the stack

temperature gets low enough, this will combine with condensing moisture to producesulfuric acid. The obvious result is severe corrosion problems in the convection section.The acid dew point in flue gases is normally in the range of 300-350 oF (149 -177 oC).We will say more about this in Section 2.6 of this section dealing with combustion.

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Figure 2-1

TYPICAL FIRED REBOILER FLOW SCHEME WITH AIR PREHEAT

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Figure 2-2

FIRED HEATER WITH STEAM GENERATIONFOR WASTE HEAT RECOVERY

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2.5 IMPORTANT PROPERTIES OF FUELS

The type, composition and heating value of the fuel used obviously determines both thedesign and operation of the furnace burners. At the same time, some of these fuelproperties determine the type and amount of pollutants emitted from the stack as well asthe corrosion and fouling tendencies in the convection section. The important fuelproperties that you need to be aware of are listed and discussed below.

2.5.1 Fuel Heating Values (Heats of Combustion)

a. Gaseous Fuels

Pure component heats of combustion (Btu/SCF or kJ/Nm3) for organicgases are given in such references as Perry's Chemical EngineersHandbook and the GPSA Engineering Data Book. If the fuel gas has

two or more components, you should calculate a more average heatingvalue. To do this, multiply the mole fraction of each component times itsrespective heating value and take the sum. The lower heating value(LHV) is used in these calculations.

Often, the principle furnace fuel is a refinery or plant fuel gas. Such fuelgas is usually a mixture of by-product and waste gases from variousunits at the site. Its composition can change considerably as the variouscontributing units are taken on or off line or operated at varying rates.For such fuels, you should determine the range of compositions the gascould logically have and calculate the LHV and HHV (higher heatingvalue) for each of these compositions. Alternately, you could estimate

the heating values according to the following equations:

HHV = 215 + 51.7 MLHV = 155 + 49.1 M

where:

M = Gas Molecular Weight

You should note that the LHV equation also correlates saturatedhydrocarbons with hydrogen to within 35 Btu/SCF (1,380 kJ/Nm3) up to44 molecular weight. Based on the results of these calculations, youneed to report the range of heating values, compositions and molecular

weights for the fuel gas.

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b. Liquid Fuels

A chart for determining the net and gross heats of combustion of fuel oilsand petroleum fractions is given in Figure 2-3. Alternately, you canestimate the heating values of liquid fuels using the following equations:

HHV (Btu/lb) = 323.5 (wt % H2) - 115 (wt % S) + 15,410LHV (Btu/lb) = HHV - 94 (wt % H2)

(Note: To obtain kJ/kg values multiply Btu/lb values by 2.326)

c. Solid Fuels

For combustion data on coal, you should refer to Perry's ChemicalEngineers Handbook. The data contained in Perry's is limited; however,methods for estimating coal heating values are given. Also, there arevarious references in the Fluor-Houston Library that contain data oncoal. But, the best approach is to obtain combustion data on the specificcoal to be used on the project in question.

2.5.2 Vanadium Content (Liquid Fuels)

During combustion, the vanadium in fuel oil forms oxides. The resultingvanadium slag is extremely corrosive to metal if allowed to deposit. Above1,250 oF (677 oC), the slag will erode metal surfaces.

2.5.3 Chloride, Fluoride and Sodium Content (Liquid Fuels)

During combustion, these elements form oxides and complex salts. Likevanadium compounds, these are extremely corrosive toward metal if allowed todeposit. Also, they will erode metal surfaces at temperatures above 1,250 oF(677 oC). In addition, sodium compounds often attack refractory materials.

2.5.4 Sulfur Content

As mentioned earlier, the sulfur in fuel burns to SO2 and SO

3. The SO

2, of

course, is an air pollutant regulated by the Federal EPA. The SO3combines with

any condensing moisture in the stack gas to make highly corrosive H2SO

4. We

will say more about this in the next part of our discussion, Section 2.6 dealingwith combustion.

2.5.5 Other Considerations

a. Heat Release

Heat release for process heaters shall be based on the LHV (lowerheating value) of the fuel. Fuel oil and/or gas composition analysis shallbe supplied with the heater specification. Vanadium, sodium and sulfurshould be included in the fuel analysis.

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Figure 2-3

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b. Fuel Gas

Fuel gas should normally be supplied upstream of the fuel control valveat 35 psig (0.241 MPag), and at 20 psig (0.138 MPag) to the burner.Provisions must be made to ensure that no condensation occurs in thefuel lines. Together, these measures will allow adequate flow control ofthe furnace fuel gas. Consult with the heater representative ofMechanical Engineering regarding burning of low pressure or low heatingvalve gases.

c. Fuel Oil

To ensure stable and complete combustion, fuel oil must be atomized atthe burners. This can be done by using either mechanically atomizedburners or steam atomized burners. Mechanically atomized burners

require fuel oil supplied at 500 psig (3.447 MPag). The high pressure oilforces its way into the combustion chamber through tiny openings in theburner nozzle. In the process, it disperses into a mist of tiny droplets. Insteam atomizing burners, on the other hand, steam is injected into thefuel oil are a ratio of 0.5 lb (kg) steam to 1.0 pound (kg) of oil. The oil isnormally supplied at 150 psig (1.034 MPag). The steam should be atleast 30 psi (0.207 MPa) above the fuel oil pressure and should have atleast 50 oF (28 oC) superheat.

Note that heavy fuel oil systems should be recirculating loop type. Onebarrel of oil should be circulated through the system for each barrelconsumed at the design heat release of the burners. Light fuel oil

systems, on the other hand, may be dead end types. Regardless ofconfiguration, the system should deliver fuel oil to the burners at aviscosity of 30 centistokes.

d. Pilot Burners

Pilot burners are supplied as an integral part of the main burner. Theyare most often installed where it is desired to simplify burner ignitionprocedures (particularly with oil firing), where an extreme turndown to afixed, minimum load is required, where intermittent on-off operation isrequired or where extreme modulation of firing rate is needed.

The primary disadvantage of pilot burners is that they constitute a

potential source of gas leakage into the firebox. The possibility alwaysexists of a pilot being accidentally extinguished, permitting gas to beadmitted to the heater during a shutdown. Also, because of their smallport drillings, pilot burners clog easily and should be routinely inspectedand cleaned.

Pilot burners are almost always gas-fired and are usually fueled from anindependent source such as a propane or LPG drum or a natural gasleader which is not part of the regular refinery fuel gas system. If thepilots are fueled from the main burner supply line, the gas offtake to the

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piles must be upstream of the control and block valves for the mainburner supply.

A typical heat release from a pilot is 50,000 to 100,000 Btu/hr(15 to 30 kW).

e. Soot Blowers

Soot removal is often required on heaters fired with fuel oil. It is notneeded if the heater is only fired with fuel gas. The main cause ofoutside tube deposits is high vanadium, sulfur, sodium and ash contentin the fuel oil. They must be provided on heaters with convection tubesand primary fuel oil firing if fuel contains:

1. More than 50 ppm vanadium

2. More than 3 % sulfur3. More than 25 ppm sodium4. High ash content

Ash deposits in the radiant sections of the heater can be expected to befluid or semi-molten, and are therefore fairly good conductors of heat.Because of the obvious cleaning problem encountered at these highertemperatures and the fact that little heat transfer is lost, attempts are notnormally made to keep these areas clean, although blowers are availablefor cleaning furnace walls. Use of cleaning equipment is usuallyconfined to the convection section.

If extended surface tubes are used in the convection section with oilfiring, the extended surface should consist of studs or thick fins ratherthan conventional fins.

Soot blowers clean the outside of tubes by blasting them with highvelocity steam or air. Steam is usually used in process heaters. Sootblowing equipment is available in two basic designs: (1) rotating-elementtype and (2) retractable-lance type.

The rotating type consists of a pipe, several nozzles in the pipe, amechanical drive assembly, an automatic valve and controls. The piperemains inside the heater and thus is subjected to the high temperatureand corrosive conditions. This type is less effective in removing deposits

because the steam supply is distributed among several small nozzlesand each stream is relatively small.

A more effective device is the retractable-lance type. This type remainsretracted from the heater when not in use. When used, it is moved intothe heater by a drive motor and simultaneously rotated. Steam flowsthrough only two nozzles, which gives the jets greater energy andcleaning range. This type is exposed to the heater conditions only duringthe cleaning cycle when steam flowing through the tube keeps the tube

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cool. The rate of travel is about 6 ft/min (1.83 m/min) and rotation aboutonce per inch of travel length. This type may also be used in a vertical

position if clearance is a problem. Maximum travel length is about40 feet (12.2 m).

Steam is usually 150 to 200 psig (1.034 to 1.379 MPag) but 400 to 600psig (2.758 to 4.137 MPag) is more effective and should be considered ifit is available. Steam consumption of the lance type is about 8,000 to12,000 lbs/hr (3,630 to 5,440 kg/hr) per blower. The blower operatesabout 2.5 minutes once each eight hours. The nonretractable type usesabout 10,000 to 14,000 lbs/hr (4,540-6,350 kg/hr) for about 40 seconds.Total steam consumption is about the same for the two types.

Controls may be provided to operate the blowers on a predeterminedcycle. Otherwise, an increase in stack temperature or fuel flow can be

used to indicate that blowing is needed.

Soot blowing may all 10 % to the cost of a heater installation. If there isuncertainty about the need for soot blowers, provision may be made forfuture installation by allowing space between tube banks and accessdoors in heater walls.

Drive motors for soot blowers can be either electric or air, althoughelectric drive is most common.

2.6 COMBUSTION CALCULATIONS AND CONSIDERATIONS

Based on your specifications, the furnace vendor will decide how much excess air theheater needs, do a combustion heat and material balance and calculate the flue gascomposition. You may have to perform these calculations yourself early in the job todetermine the amount of recoverable heat in the stack gas. As we mentioned earlier,you can do this by hand or by computer. Whichever way you go about this, you need tohave an understanding of the principles of combustion stoichiometry. To illustrate theseprinciples, we have included an example calculation in Section 2.12.1. The textbookentitled, Steam, Its Generation and Use, by Babcock & Wilcox is also useful reference.Another consideration is the generation of SO

2, SO

3and NO

xin the combustion process.

Sulfur in fuel burns to SO2 and traces of SO

3 during theoretical combustion. The

presence of excess air greatly enhances the production of SO3. At present, there is a

federal regulation on the sulfur contents of fuel for new or modified refinery heaters. This

regulation does not apply to process heaters in other types of industrial plants. There areno other federal regulations governing emissions from process heaters, but many stateshave set regulations. Texas, for instance, limits sulfur dioxide emissions from processheaters to 440 ppm in the stack gas. Sulfur trioxide, on the other hand, poses more of acorrosion problem than an environmental one. SO

3 combines with water vapor in the

stack gas to form H2SO

4. If the stack gas cools below its acid dew point - as it could in

the convection heat recovery section - then aqueous H2SO

4 condenses on the stack

internals. You should always determine the lower temperature limit for heat recovery in

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the convection section. Figure 2-4 will enable you to do this once you know the SO3

content of the flue gas.

How does one determine the SO3content of the furnace stack gas? To answer this, let's

look at an example calculation. Consider a furnace fuel oil of the composition given inthe example calculations in Section 2.12.2. First, we must calculate the number of molesof each fuel component in some given amount of fuel. here we chose 100 lb of fuel asour basis. Now, most of the sulfur in the fuel will form SO2in the flue gas and some willform SO

3. In practice, the maximum SO

3level in furnace flue gases is found to be 5 % of

the SO2 concentration. This is higher than that predicted by equilibrium considerations,

but closely agrees with actual measurements. Using this along with the total moles ofsulfur in our 100 lb (basis) sample, we can calculate the relative number of moles of SO

2

and SO3 in the flue gas. From here the stoichiometry calculations required to find the

complete stack gas composition and the subsequent use of Figure 2-4 are ratherstraightforward. Therefore, we leave it to you to follow our example calculations at the

end of this subsection on your own. Before we move on, however, we should mentionone more thing. Once you have found the acid gas dew point for a particular heater, youshould add a safety factor to that temperature. In the absence of client specifications orother guidelines, the lower flue gas temperature limit should 50 oF (28 oC) above the aciddew point. This will cover operating conditions different from design. Watch out forturndown operations. You may have to provide bypasses for the process fluid controlledaccording to the stack temperature. We will say more about turndown in Section 2.8.

Nitrogen oxides are a by-product from most combustion operations. They form bythermal fixation of molecular nitrogen in the combustion air. NOx also forms fromnitrogen compounds in the fuel. The Federal EPA regulations, made effective inDecember 1971, impose a national limit on NOx emissions from new boilers of over

250 MM Btu/hr (73.3 MW) heat release. Various states and municipalities have alsopassed laws limiting the emission of NOx from combustion units. Reference tot he legalrestrictions of various locations is required to determine limits imposed on process firedheaters. Consult with an environmental engineer.

Tests show that certain restrictions can be met on fired heaters without modification orspecial designs because of their smaller size and design characteristics. Relatively lowflame burst temperature due to low heat flux and distributed of burner arrangement iscredited. However, problems may arise with large forced draft burners and from fuelnitrogen content greater than 0.3 % wt. Your responsibility is to inform the vendor of NO

x

regulation requirements so he can design for them.

2.7 INSTRUMENTS AND SAFETY DEVICES

In specifying a process heater, you should have a basic understanding of how to safelycontrol it. Our purpose here is to familiarize you with the fundamental control variables,instruments, and safety devices common to almost all fired heaters. You shouldrecognize that for any specific heater the control scheme will probably be considerablymore complicated than we show here.

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Figure 2-4

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2.7.1 Primary Control Variables

a. Process Flow Rate

Low process flow causes overheating and coking in the tubes. Coking inturn causes higher pressure drop and more overheating. The end resultis lower tube and refractory life. Most heaters shut down automaticallyfor low process flow in any one tube pass. (As material enters theheaters, its total flow is divided among several groups of tubes. Each ofthese groups is called a tube pass.)

b. Firing Rate

The firing rate is usually controlled by adjusting the fuel flow according tothe heater process outlet temperature. This is depicted in Figure 2-5.

Note, however, that vaporizing streams may have little outlettemperature variation with heat input. In that case, another controlvariable must be chosen. Most heaters shut down automatically for lowfuel pressure or flow.

c. Air Supply

This is normally controlled by adjustable dampers either in the flue stackor inlet air duct. Manual control is common for natural draft heaters, butautomation will improve the thermal efficiency of the heater.

If forced or induced draft fans are used, the air flow can be controlled

either by fan plenum dampers or fan (driver) speed control. (The plenumis a chamber surrounding the burners. It is used to distribute air to theburners and reduce combustion noise.) The air flow control is usuallyset automatically according to the fuel flow rate as shown in Figure 2-6.In this way a constant air to fuel ratio can be maintained.

At this point we should mention that the control scheme shown inFigure 2-6 is for heaters fired with fuels of fixed composition. Often, theprinciple furnace fuel is a refinery or plant fuel gas. As we mentionedearlier, the composition of such gas can vary considerably. This requiresa more complicated control scheme than the one we have shown here.Such a scheme might include an automatic chromatograph to monitorfuel gas composition. This information, along with heater process outlet

temperature, can be fed to a process control computer. The computerthen can be programmed to calculate the required fuel and air flowratesand reset the respective flow controllers. The exact control requirementsfor any given heater will vary depending on the service it is in, themagnitude of changes in fuel gas composition, etc. You should consultyour Lead Engineer and the Control System Engineer assigned toprocess heaters for help in setting up such a control scheme.

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Figure 2-5

TYPICAL CONTROL SYSTEM FOR A NATURAL (DRAFT) HEATER

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Figure 2-6

TYPICAL HEATER CONTROL SCHEME WITH FORCED (DRAFT)

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2.7.2 Secondary Instrumentation

a. Individual Outlet Temperature Indicators for Each Tube Pass

The furnace operators use these as guides to adjust the flows throughthe tube passes. They should be located very close to where the passesleave the firebox (combustion chamber).

b. Firebox Temperature Indicators

These allow the operators to balance the firing between the variousburners in the firebox and to monitor the refractory temperature levels.Under normal conditions, the readings from the various indicators shouldnot differ by more than 100 oF (55 oC).

c. Flue Gas Temperature Indicators at the Bridgewall and in the Stack

The bridgewall, sometimes called the division wall, is a refractory wallseparating two adjacent heater zones. The bridgewall temperature is thetemperature of the flue gas leaving the radiant zone. Temperatureindicators mounted here and in the flue stack provide an indication ofstack temperature, furnace operating efficiency, overfiring, tube foulingand tube rupture.

d. Tubeskin Thermocouples

These warn of excessive temperatures where metal strength might be

dangerously reduced. Using the reading from them, operators canestimate tube life. And these thermocouples provide yet another way ofmonitoring the firing of the furnace.

e. Draft Gauges

These are usually inclined manometers. They provide air and flue gaspressure drop and flow data. They are used when adjusting burners andto indicate limiting operating conditions.

f. Individual Control

Combination heaters handling multiple services are acceptable providing

the overall heater design permits individual control of each servicewithout affecting other process services.

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2.7.3 Safety Shutdowns and Alarms

An instrument controlling an important variable, such as fuel or process flowrate,sounds an alarm when that variable starts getting out of its respective controlrange. If the variable gets far enough away from its setpoint, then the instrumentoften can automatically shut down the furnace. The primary shutdowns includelow process flow and low fuel flow or pressure. Others that are sometimesincluded, but usually as alarms only, are high process flow, high processtemperature, high stack temperature, flame failure, high tube skin temperatureand low draft pressure.

Each installation must be studied to determine which failure can lead to trouble.The protective control system should be designed so that it cannot in itself leadto an unsafe condition and that it will not make start-up difficult or lead tounnecessary shutdowns. The greatest danger is from a fuel system that may fail

long enough for the flame to extinguish and then reintroduce fuel while therefractory is hot enough to ignite the fuel.

Since automatic shutdown devices can be a hindrance during start-up, it isrecommended that they only be used where abnormal conditions could cause adangerous situation before corrective action could be taken. Also, if shutdowninitiating devices must be bypassed to start a unit, visual indication in the centralcontrol room must be provided.

2.7.4 Safety Devices

a. Purging and Snuffing Steam

Upon shutdown of a heater for any reason, steam should be directed intothe firebox and header box (an internally insulated compartment,separated from the flue gas stream, which is used to enclose amultiplicity of headers or manifolds). The steam serves two purposes.First, it snuffs out the burner flames and second, it inerts the atmospherein the firebox and in the header box. This prevents ignition of residualfuel or process material that may leak from damaged tubes. Automaticsystems are sometimes provided; however, most systems are manual.

Steam connections should be distributed throughout the combustionchamber. Together, these connections should be of sufficient size andquantity to deliver within 15 minutes, a volume of steam at atmospheric

pressure equal to three times that of the combustion chamber. Thesteam supply should have a pressure of at least 50 psig (0.345 MPag).Higher pressure steam, however, results in smaller lateral sizes. Aminimum of two 1" connections made of 18-8 Cr-Ni are usually installedat opposite ends of each radiant chamber. Connections should also beprovided on the convection header boxes. The snuffing steam systemshall have a valved manifold located at a safe distance (typically 50 feet)(15.2 m) from the furnace for providing snuffing steam to the variousfurnace sections.

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b. Peep Doors

These allow operators to see the internals of the radiant section. Theycan thus visually check for tube or burner damage or monitor the tubesduring decoking.

2.8 OFF DESIGN CONDITIONS

2.8.1 Turndown Operation

Often, plant personnel will operate a fired heater at lower than design throughput.This is called turndown operation. If you are aware of special turndownconditions at which the client wishes to be able to operate, you should indicatethis under "Remarks" on the specification data sheets. The vendor will take thisinto account in the mechanical design of the heater. Generally, the minimum

operating range of the burners is 25-35 % of the normal design duty.Satisfactory turndown operation may require special instrumentation or one ormore auxiliary burners. To illustrate why, let's look at an example.

Consider the fired heater shown in Figure 2-2. Assume that we are operating theheater at 75 % throughput. Now consider the convection section where wegenerate and export steam to the other parts of the plant. Let's say that theplant does not have enough boiler capacity to make up for any cutback in steamproduction here. At 75 % of design throughput, fired duty is about 75 % of itsdesign value. And, it follows that there is about three-fourths as much flue gasgoing up the stack relative to the design case. Now, if we keep the water flowthrough the convection coils at design rates, we might still be able to extract

enough heat to maintain design steam production. But, in the process, we willmost likely cool the flue gas below its acid dew point. From our earlierdiscussion, this is clearly an untenable situation. In this case, one or moreauxiliary burners are needed in the stack. During turndown operation, theoperators can fire these burners to put sufficient heat into the flue gas tomaintain the desired level of steam production and keep the flue gas above itsacid dew point. Alternately, stainless steel tubes may be used in the uppermostconvection coil along with a stainless steel liner in the stack itself. Stainless steelwill not corrode in an acid environment; however, this material is very expensiverelative to carbon steel.

Now, if it is not critical to maintain design steam production at all times, then wemight choose to limit steam production at reduced furnace firing rates. To do

this, we could provide a bypass for the boiler feedwater around the preheat coil.Flow through the bypass could be controlled to maintain stack exit temperaturesafely above the acid dewpoint. During turndown operation, the bypass will openallowing colder boiler feedwater to enter the steam drum. This changes thesystem heat balance, lowering the overall steam production. As you can see,client preferences and site specific considerations can dictate whataccommodations are needed for turndown operation.

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Before leaving this subject, let's look at one more example. Consider the firedreboiler shown in Figure 2-1. In this case, the convection section is used to heat

the process fluid and the incoming combustion air. For a reduced processthroughput, the fired duty and air flow are proportionally lower. Since nosignificant imbalance in the various heat duties should result, special burners orinstruments are probably not needed. Note that in this case, turndown operationof the system as a whole is likely to be limited by the design of the associateddistillation column.

2.8.2 Overdesign

Fired heaters are often capable of satisfactory operation at nominally higher thandesign duties and process throughputs. Such "overdesign" is inherent in mostprocess equipment. As you are probably aware, the heat transfer and pressuredrop correlations used in the design of fired heaters all have varying degrees of

uncertainty. To compensate for this, the vendor allows for more heat transfersurface, a greater number of tubes, extra firing, etc. The vendor can thenconfidently guarantee the required performance of the heater. Sometimes theclient specifies the amount of overdesign for various parts of the furnace. If,however, this is left up to you (and the vendor), the following two generalguidelines may be used. First, burners and flues should be specified to permitoperation at 125 % of design heat release and 30 % excess air for fuel gas or40 % excess for fuel oil. Second, fired heater duty should generally be designedfor continuous service at 10 % above the normally expected process operatingduty. This should be defined as normal flow at a lower inlet temperature. Theseguidelines also compensate for variations in operations elsewhere in the unit,e.g., fouling in an exchanger that preheats the furnace feed.

2.9 MISCELLANEOUS GUIDELINES

2.9.1 Heater Selection

Heater type selection is the joint responsibility of the Process and mechanicalEngineers. You can refer to Table 2-2 for general guidance. You should firstreview the article entitled "Fired Heaters -1" taken from the July 19, 1978 issue ofChemical Engineering. A copy of this article, included at the end of this article,discusses the various types of fired heaters listed in Table 2-2.

Occasionally, several different services ("coils") may be placed in a single heaterwith a cost saving. This is possible if the services are closely tied to each other

in the process. Catalytic reforming preheater and reheaters in one casing is anexample. Desulfurizer reactor heater and stripper reboiler in one casing isanother example. This arrangement is made possible by using a refractorypartition wall to separate the radiant coils. The separate radiant coils may becontrolled separately over a wide range of conditions by means of their owncontrols and burners. If a convection section is used, it is usually common to theseveral services. If maintenance on one coil is required, the entire heater mustbe shut down. Also, the range of controllability is less than with separateheaters.

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Each of these heater types may be shop fabricated if size permits. Shopfabrication reduces costs. However, shop fabrication should not be forced to the

extent of getting an improperly proportioned heater.

2.9.2 Heater Tube Design Conditions

a. Design Temperature

Tube design fluid temperature shall be set according to the following:

Outlet TemperatureDesign Fluid Temperature

Up to 750 oF (399 oC) Outlet temperature + 10 %750 oF (400 oC) or over Outlet temperature + 75 oF (42 oC)

For vacuum or coking services, maximum oil film temperature should notbe more than 50 oF (28 oC) above the maximum bulk oil temperature.

b. Design Pressure

Design pressure shall be set according to the following:

Maximum Operating Pressure Design Pressure(Under Fouled Conditions)

- Up to 1000 psig (6.895 MPag) operating + 10 %

- 1,000 psig or over (6.895 MPag) operating + 100 psi(6.895 MPa)

Normal suction pressure plus shutoff differential pressure of anupstream pump (only if heater can be closed in against thepump).

Upstream pump suction pressure at pump source reliefconditions plus normal pump differential pressure (only if heatercan be closed against the pump).

150 psig, minimum (1.034 MPag).

Full vacuum (15 psi (0.103 MPa) external pressure) and 150psig (1.034 MPag) minimum internal pressure for vacuumservice.

2.9.3 Process Tube and Fitting Corrosion Allowance

Where corrosion rates are available, heater tubes shall have sufficient corrosionallowance for 100,000 hours operation. Where corrosive rates are not available,the corrosion allowance guidelines from the Process Design Criteria Manualgiven below may be used.

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Material Corrosion Allowance

Carbon Steel & Low Chrome(up to 4 %)

1/8"

Alloy (above 4 % chrome) 1/16"

2.9.4 Pressure Drop

The process engineer must specify allowable pressure drop. Pressure drop isthe main factor in determining tube size and number of parallel passes.

Heater designers like to see high allowable pressure drop because this reducesthe number of parallel passes and tube size, hence, cost. It also reduces theprocess piping, valving and controls required. If a maximum skin temperature orfilm temperature is specified, higher pressure drop permits these criteria to bemet with less heater surface. These savings, however, are balanced by thehigher pumping cost.

Large heaters justify more pressure drop than small heaters because the largerflow rates require more parallel passes at the usual diameters and lengths ofheater tubes.

When the process fluid is heated in both the radiant and convection sections ofthe heater, consider providing a combined allowable pressure drop. This lets theheater designer utilize the available pressure drop in an optimum design.

Manifolds are the piping outside the heater box which connect the passes to

process piping. Sometimes they are furnished by the heater manufacturer whenthe thermal expansion of the manifold and the heater tubes can be handled bestby one designer, or whenever it is economical to use extruded header openings.Sometimes they are furnished by Fluor Daniel as part of the process piping.Unless it is certain that the heater vendor will furnish the manifolds and includethe manifold pressure drop in the allowed pressure droop for the heater, then theprocess engineer should allow for it in the process piping pressure drop.

See Table 2-1 for a listing of typical pressure drops for various types of heaterservices.

2.9.5 Piping Considerations

a. Multipass Heaters

Process engineers often specify that piping to multipass heaters must besymmetrical. Piping designers will interpret this instruction literally, and avery expensive manifold can result. If the heater has an odd number ofpasses, it is impossible to have symmetrical piping. It may be moreeconomical to allow a few extra psi in the pumps and achieve equal flowresistance by means of a globe valve on each pass. However,symmetrical piping is very important on heaters which cannothave

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individually controlled passes and which have low pressure drops, i.e.,catalytic reformer heaters. Also, keep in mind that similar equivalent

lengths and head are required and not absolute symmetry.

Multipass heaters in vaporizing service should have flow control on eachpass if practical. This usually means flow indicators and hand operatedglobe valves, but occasionally automatic flow control is used. Do notforget to allow pressure drop for this control.

b. Two-Phase Flow

Certain processes (desulfurizers, hydrocrackers) have heat exchangetrains which preheat the feed to the furnace. Hydrogen recycle may alsobe mixed with the feed. This situation causes a two-phase feed to theheater. It is very desirable to flow control each pass to a multipass

heater and this cannot be done with two-phase flow. The use of singlepass heaters is one solution, but the tubes may become very large.Some other solutions to the problem which may be considered are:

Heat Hydrogen recycle in a separate heater.

Separate the two-phase mixture in a vessel and flow controleach phase separately.

Use parallel trains with single pass heaters.

Slugging and vibration has been encountered in heater outlet lines with

two-phase flow when the velocity is too low. The followingrecommendations should help prevent these problems from occurring inthese situations.

1. Calculate the velocity and mix density at the highest and lowestpressure of the line. A large pressure drop in the line mayrequire intermediate velocity and density calculations and linesize changes. Pressure drop is to be calculated in the usual wayfor two-phase flow.

2. Plot the velocity versus diameter on the limiting velocity chart,Figure 2-7. The actual velocity in the line must be equal to orhigher than the limiting velocity at the mixture density. Consider

the effect of reduced plant throughput.

If the velocity is too low, either the line size must be decreased andhigher pressure drop allowed, or the mixture density must be varied bychanging the vapor/liquid ratio; or a piping design must be used asdescribed in the following paragraph.

Piping design has a significant effect on slugging. If slugging will occuraccording to the limiting velocity chart and the line may not bereduced

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due to pressure drop limitations, then the larger line may be usedprovided the horizontal portions are sloped downward and a P-trap is

added to the vertical portion. Two methods of sloping the line are shownin Figure 2-8.

In all cases, even if slugging is not indicated on the limiting velocity chart,all upward changes in direction should be vertical and not sloped. Thiswill prevent a liquid pocket from forming at the bend which wouldultimately lead to slugging as shown in Figure 2-8.

c. Burner Piping

Burner valves are usually special globe or needle valves with positionindicators. Gas burner valves are located close to the burners, but farenough away to protect the operator from flashback. Oil burner valves

are located close to the peepholes. When atomizing steam is required, acheck valve is provided in the steam line to prevent oil from backing intothe steam system.

2.9.6 Heater Grid

You should prepare a heater grid as part of the specification for any heater invaporizing service where the pressure drop through the tubes is 50 psi(0.345 MPa) or greater and where the process material is a mixture ofcomponents, e.g., crude oil or naphtha. Typically, crude and vacuum heatersand fired reboilers fall into this category. A heater grid graphically shows theequilibrium relationships between temperature, pressure, enthalpy and

vapor-liquid distribution for the process material. Figure 2-9 shows an exampleheater grid. The exact temperature-pressure equilibrium path through the heatercannot normally be predicted in advance and varies with vendor design. Theheater grid enables the vendor to extrapolate the equilibrium data as needed inthe design.

To prepare a heater grid, you must first estimate the pressure profile for theprocess flowpath. You can refer to Table 2-1 for guidelines for minimumpressure drop through the heater. From the column or crude tower computersimulation, you know the pressure and temperature of the process material atthe tower inlet and the required duty of heater. You must decide on the percentvaporization in the heater. This is usually on the order of 40-50 % for reboilersand 50-75 % for crude and vacuum heaters. When dealing with a crude or

vacuum heater, you know the pseudo-composition of the process material, i.e.,ASTM distillation data, characterization factors, etc., and its flowrate from theprocess heat and material balance. In the case of a reboiler, however, you mustestimate the process stream composition based on the composition andflowrates of both the bottoms liquid and the liquid leaving the bottom tray. Onceyou determine the process material composition for the reboiler loop, and set thepercent vaporization, then the process flowrate is fixed. you can then runcomputer flash calculations on the material for various temperatures, over therange of system pressures. Using the results, you can construct a heater grid as

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shown in Figure 2-9. For vacuum column heaters, the procedure we haveoutlined here is further complicated by

Figure 2-7

LIMITING VELOCITY - 2 PHASE FLOW IN VERTICAL LINES

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Figure 2-8

PIPING DESIGN FOR TWO-PHASE FLOW

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Figure 2-9

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the need for a trial and error calculation to optimize the size of the line betweenthe heater and the column. Refer to the Fluor Daniel Crude and Vacuum Unit

Design Manual for more details.

2.10 DECOKING

Coke is a residue of heavy aromatic compounds often formed on heat transfer surfacesfrom which hydrocarbons are evaporated. In general, coke deposits can be expected onthe insides of fired heater tubes in hydrocarbon service above 600 oF (316 oC). Theheavier the hydrocarbons, the greater their coking tendency is. The presence ofhydrogen and/or steam tends to retard coke formation. Some coking and noncokingfurnace applications are listed below.

Coking Services

Atmospheric and vacuum pipe stillsH

2treater preheaters and interheaters

Thermal reformingVisbreakingSteam crackingCrude

Noncoking Services

Hydrocarbon operations below 600 oF (316 oC)Reforming furnaces (high H

2)

For a process heater in coking service, you must specify tube temperature and pressureduring decoking. Usually, pressures are in the range of 10-50 psig (0.069-0.345 MPag).Tube temperatures must be kept below 1300 oF (704 oC). You must also specify thenecessary auxiliary equipment such as the decoking quench drum, steam and air flowmeters, etc.

Decoking of furnace tubes is, in general, carried out as follows. The operators first shutthe heater down and remove any process material remaining in the tubes. next, they putsteam through the tubes at rates of 15-20 lb/sec ft2 (73.2-97.6 kg/m2 sec) and fire theheater to yield a flue gas temperature of 1,350 oF (732 oC). This cracks about 90 % ofthe coke off the tubes. next, the operators reduce the steam rates to around 5-7 lb/secft2 (24.4-34.2 kg/m2 sec) and cut back on firing to lower the flue gas temperature to1,200 oF (649 oC). Next, they gradually admit air in with the steam to burn off the

remaining coke. The burning process is monitored by watching tube temperature andCO2levels in the furnace effluent. Tubes must be kept below 1,300

oF (704 oC) and CO2should stay below 19 % in the effluent gas. Visual monitoring of the tubes to watch forhot spots is a must. Sometimes the operators choose to decoke at night when hot spotsare easier to see.

For a heater in coking service, you should specify a permanent steam-air decokingsystem. One such system having two-directional manifolds appears in Figure2-10.

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These are called "two directional" since steam and air can flow in either direction throughthe furnace tubes. Using this type of system, only one tube pass can be decoked at a

time. Water is injected into the decoke effluent from each pass to stop the cracking andcombustion processes and to cool the material off. A knockout drum is needed to catchthe quench effluent. The drum should drain or be pumped out to an API separator whereoil, water and coke solids can be separated.

Figure 2-11 shows an alternate decoking system. In this system, all furnace tubes aredecoked at the same time. This saves considerable time and, hence, results in greateron-stream time for both the heater and the unit in general. Steam and air injection is inone direction only and this simplifies the manifolding at the heater. Here the decokingeffluent is quenched to 1,000 oF (538 oC) upstream of the knockout drum. Water is theninjected into the drum to further cool the effluent. There are, however, severaldisadvantages to this type of system compared to the two-directional type. Since thedecoking steam is not condensed by the initial water injection, the knockout drum must

be bigger and must operate at a higher temperature. The venting rate from the drum ishigher since the incoming steam is not condensed. In practice, the cracking step in thedecoking process is not as effective as for a two-directional system.

2.11 REVIEW AND REVISIONS

As with most process equipment, at least one revision of equipment specification datasheets will be required. The process information provided on the "Revision A" datasheets usually doesn't change in subsequent issues. It can and does change if someonefinds an error in it or if the vendor recommends a change that is acceptable to FluorDaniel and the client. Remember, furnace designers have developed numerousproprietary designs for tubular heaters to make efficient use of fuel and provide

satisfactory and economic mechanical design. You should always take advantage of thevendor's greater knowledge of heater design. The case of the steam-hydrocarbonreformer presented in Section 5.0 provides an example. In a note on page 2 of theoriginal data sheets, we specifically gave the vendor permission to alter the convectionheat recovery scheme to improve reformer efficiency. As it turns out, the vendor didn'tchange the heat duties or steam flows, bit did change the water circulation rate throughthe steam generation coil. The Process Engineer originally specified a ratio of fourpounds of water circulated for every one pound of steam generated. The vendorchanged this ratio to 9/1 due to undesirable two-phase flow/boiling heat transfercharacteristics at the lower circulation rate. For the most part though, the furnacedesigner provides information that must be added to the specification sheets. This isusually transmitted to Fluor Daniel in letters and on drawings. The task force mechanicalEngineer assigned to fired heaters adds this information to the specification sheets. The

vendor provides mechanical design details for the radiant and convection sections, thetubes, the burners, the air preheater, etc. The designer also provides heaterperformance data based on burner tests made with the same type of fuels to be used inthe plant. You should review the "Approved for Construction" specification sheets foreach of the examples presented in this section. This will give you an overview of theamount and type of vendor data that is needed to fully specify a fired heater.

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Figure 2-10

TWO-DIRECTIONAL STEAM-AIR DECOKING SYSTEM

1.0

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Figure 2-11

ALTERNATE STEAM-AIR DECOKING SYSTEM

1.0

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2.12 EXAMPLE CALCULATIONS

2.12.1 Boiler Efficiency Calculation

a. Basic Data

1. Fuel gas from overall material balance, Case I 2/9/79 by JRL.

2. Diesel one barrel = 5.4 x 106 Btu LHV or 5.8 x 106 Btu HHVFX-B, 2/12/79.

Assume diesel data based on attached charts

38 oAPI S.G. = 0.835

1 BBL = 292.1 lb

LHV = = 18.484 Btu/lb5.4 x 106 Btu

BBLBBL

42 galGal

8.33x 0.835 lb

or HHV = 21,393 Btu/lb

C/H wt Ratio = 6

wt wt % lbs/BBL MOL/BBLC: 6 86 251 20.92 CH: 1 14 41 20.50 H

2

7 100 292

MW = 2051BBL = 1.43 MOLES

1.43 MOL Diesel 20.92 CO2+ 20.5H

2O

O2Required: 31.17 MOL

b. Heat Balance

Base firing on 100 MOL/hr gas = 2.76 x 106Btu/hr

Oil fired duty = - 2.76 = 0.31 x 106Btu/hr2.76

0.9

Total fired duty = 3.07 x 106Btu/hr

Diesel Required = = 0.057 BBL/hr0.31 x 106 Btu/hr

5.4 x 106 Btu/BBL

1.0

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COMP MW

(a)

MOL/hr(b) O2X

O2REQ

MOL/hr

FLUE GAS COMPONENTS COMBUSTION CALCULATIONS

CO2 SO2 H2O O2 N2 CO (c) LHV Btu/lb (a)(b)(c) Heat

Released Btu/hr

H2 2.02 0.5 - -1 - 51,623

CO 28.01 0.5 1 - - - 4,347

CO2

44.01 - 1 - - - -

CH4 16.04 2.01 - 2 - 21,495

C2H6 30.07 3.52 - 3 - 20,418

C2H4 28.05 3.02 - 2 - 20,275

C3H8 44.10 5.03 - 4 - 19,937

C3H6 42.08 4.53 - 3 - 19,687

C4H10 58.12 6.54 - 5 - 19,678

C4H6 56.11 6.04 - 4 - 19,493

N2+ A 28.01 - - - - -1 -

H2S 34.08 1.5 -1 1 - 6,537

COS 60.08 1.5 1 1 - - 4,149

S02 64.06 - -1 - - -

H2O - - -1 - -

DIESEL 205 1.43 11.8 31.17 20.92 - 20.50 - 18,484 5,4 X 106

Total MOL/hr 1.43 31.17 20.92 20.50 Assume None Total 5.4 X 10

5

LHVTheo. O2Reqd., MOL/hr 31.17 or 6.25 x 10

6HHV

Excess O2Reqd., MOL/hr 20% 6.2316.23

Total O2supplied, MOL/hr 37.40 Assume C/H Wt Ratio = 6

and MW 205

N2supplied (O2x 3.76) MOL/hr 140.641140.64

Total Dry Air, MOL/hr 178.04

H2O in Air (Dry air x 0.0212) MOL/hr 3.7713.77

Total Wet Air 181.81

FLUE GAS

COMPONENTS, MOL/hr

20.92 24.27 6.23 140.64

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COMP MW

(a)

MOL/hr(b) O2X

O2REQ

MOL/hr

FLUE GAS COMPONENTS COMBUSTION CALCULATIONS

CO2 SO2 H2O O2 N2 CO (c)LHV Btu/lb (a)(b)(c) Heat

Released Btu/hr

H2 2.02 7.83 0.5 3.92 - -17.83 - - 51,623 816,500

CO 28.01 1.91 0.5 0.96 11.91 - - - - 4,347 232,561

CO2

44.01 27.18 - - 127.18 - - - - - -

CH4 16.04 1.25 2.0 2.5011.25 - 22.50 - - 21,495 430,975

C2H6 30.07 0.46 3.5 1.6120.92 - 31.38 - - 20,418 232,426

C2H4 28.05 0.28 3.0 0.8420.56 - 20.56 - - 20,275 159,240

C3H8 44.10 0.22 5.0 1.1030.66 - 40.88 - - 19,937 193,429

C3H6 42.08 0.21 4.5 0.9530.63 - 30.63 - - 19,687 173,970

C4H10 58.12 0.13 6.5 0.8540.52 - 50.65 - - 19,678 148,679

C4H6 56.11 - 6.0 -4 - - 4- - - 19,493 -

NH3 17.03 0.0810.08 - -

N2+ A 28.01 55.27 - - - - - - 55.27 - 446

H2S 34.08 0.002 1.5 0.0031 - 10.002 10.002 - - 6,537 -

COS 60.08 - 1.5 - - 1- - - - 4,149 -

S02 64.06 - - - -1- - - - - -

H2O 5.01 - - - -15.01 - - - -

C5 + 86.17 0.19 7.5 1.81

6

1.14 -

7

1.33 - - 19,415 317,868Total MOL/hr 100.02 14.54 20.77 55.35 Assume None Total 2.76 x 106Btu/hr

Theo. O2Reqd., MOL/hr 14.54

Excess O2Reqd., MOL/hr 20% 2.9112.91 72.7 Btu/SCF say 73

Total O2Supplied, MOL/hr 17.45

N2supplied (O2x 3.76) MOL/hr 65.61165.61

Total Dry Air, MOL/hr 83.06

H2O in Air (Dry air x 0.0212) MOL/hr 1.7611.76

Total Wet Air 84.82

FLUE GAS COMPONENTS, MOL/hr 34.77 0.002 22.53 2.91 120.96

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BOILER FREQUENCYSTACK LOSSES

CO2 SO2 H2O O2 N2 TOTAL

MOLS F.G. from 100 MOL/hr Gas 34.77 0.002 22.53 2.91 120.96

MOLS F.G. from 0.057 BBL/hr

Diesel

1.19 N/L 1.38 0.36 8.02

TOTAL MOLS/hr F.G. 35.96 23.91 3.27 128.98

Average Mcp 80 oF 500 oFBtu/MOL oF

10.1 8.2 7.25 7.05

Heat Cont. (Mcp) (F.G.) (T) Btu/hr 152,542 - 82,346 9,957 381,910 626,755

Atomizing Steam Neglect

Total Stack Losses @ 500 oF Btu/hr 626,755

Average Mcp 80 oF 450 oFBtu/MOL oF

10 8.2 7.25 7.05

Heat Cont. (Mcp) (F.G.) (T) Btu/hr 133,052 75,543 8,772 336,444 553,811