Flexible Solutions for Increased Production

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Flexible solutions for increaseddiesel production

S

ince 1998, diesel demand in the US has

increased by approximately 40% and is

expected to continue increasing as distillate

margins outperform gasoline in the long term. As a result, reners have been, and will continue

to be, increasingly compelled to evaluate their

processing options to expand diesel production,

while at the same time complying with non-road

ultra-low sulphur diesel (ULSD) regulations and

also competing with diesel imports and the

consequences of the reduction of bunker/fuel oil.

These trends continue as feedstock quality

declines, while governments and consumers

demand increasingly cleaner fuels, and as crude

prices uctuate widely within short periods oftime.

Despite market variations, the higher margin

for diesel over gasoline has remained, although

the gap is decreasing (see

Figure 1). These trends have

forced reners to develop exi-

ble plans in taking advantage

of price uctuations in market

conditions.

Although Table 1 shows the

wider range of issues thatimpact renery diesel produc-

tion, this article will not cover

topics such as hydrocarbon

stream reconguration, hydro-

gen management, advance

process control, best practices

for unit reliability or turn-

around management. Instead,

it will focus on diesel gains via

distillation changes along with

Robert Karlin and Aris Macris Shell Global Solutions (US) Inc Raul Adarme and Kathy Wu Criterion Catalyst & Technologies LP

optimisation of FCC and hydroprocessing units.1

The right solution will depend on the individual

renery’s conguration and marketing position.

The best solution should develop out of deliber-ate evaluation of the application of technologies

and their integration within the renery to

improve return on investment as a result of

improving the rener’s ability to control the

gasoline-to-diesel ratio.

Distillation An easy way to increase diesel production in

reneries is through distillation, since adjusting

product cut points in the crude tower or in

conversion units can favour diesel productionover gasoline. Other opportunities for increasing

diesel through distillation can include:

• Crude towers (atmospheric and vacuum)

www.digitalrefining.com/article/1000610 PTQ Q4 2009 1

Distillation changes and optimised hydroprocessing units represent a broadrange of technical and economic options for increasing production of diesel

2

1

3

4

5

6

7

8

9

0

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

(U)LSD gasoline

N. AmericaULSD

(U)LSD over LSFO value

(U)LSD over HSD/HO value

Three-quarter rolling average

Diesel price vs other fuels – Gulf Coast

B / $ ,

D

S H s v e c i r p

D S L ) U (

B / $ ,

O F S L r o

e n i l o s a g s v e c i r p

D S L ) U (

70

60

50

40

30

20

10

0

–10

–20

Source: CERA data

Figure 1 Historical margins of diesel over gas oil and fuel oil (LSFO)

http://www.digitalrefining.com/article/1000610




Maximise diesel while keeping ash point and

90% or 95% boiling point constant or expanding

crude tower capacity.

• Fractionation towers serving: ■ FCCU: include heavy naphtha and increase

light cycle oil (LCO) production without intro-

ducing a tail end ■ Delayed coking unit: revamp to increase

capacity and recovery

■ Hydrocrackers: adjust product cutpoints

(eg, recycle oil 5% boiling point) or revamps to

increase capacity or match changing yield slate

■ Hydrotreaters: Revamps to allow for diesel

production capacity increase.

These distillation-related revamps typically

require feasibility studies to identify and dene

options for increasing diesel production, while

2 PTQ Q4 2009 www.digitalrefining.com/article/1000610

considering the requirements for implementa-

tion and capital expenditure. These studies also

consider how technologies such as Shell GS

tower internals add value, particularly when

more severe operation is required. As reference,

Table 2 provides the advantages of Shell GS’s

several vessel and tower internals that couldcontribute to distillation revamps for increasing

diesel production.

Internal advantages commentsTo illustrate crude unit revamps for increasing

diesel recovery in a generic crude unit (atmos-

pheric tower and vacuum tower), Table 3

summarises the options concerning tower inter-

nals, pumparound location and steam usage,

while maintaining the same product

Enabling technology/ Distillation Hydrocracking FCCU FCCU ULSD Catalyst Reactor Refinery opportunities pretreating hydrotreating technology internals operationsNon-capitalOptimise cutpoints of feedstocksand product mix from alldiesel-producing units •

Optimal disposition of intermediate

streams •

Improve product quality control •

Improve unit reliability & operability •

Crude selection • • • • • • Improve utilisation of process catalysts • • • • •

Small capital Upgrade reactor internals •

Upgrade tower internals •

Evaluate and perform low-costdebottlenecking revamps • • • • • • • • Balance H

2demand with supply • • • • •

Large capital CDU/VDU reconfigurations • • • •

Conversion unit fractionation •

Revamping DHT/HCU/MHCU/CFH • • • • •

Revamping CFH to MHCU • • • •

Grassroots MHCU/HCU/DHT • • • • •

Integrated CDU/HVU/HCU/DHT solutions • • • • • • •

Areas of opportunity for increasing diesel production

Table 1

Internal Advantages CommentsShell calming section trays 10–20% capacity gain vs conventional CDU, DCU, HCU main fractionator Shell HiFi trays 10–30% capacity gain vs conventional Gas plants, light ends, HT, strippers, pumparounds of main fractionator Shell SMS(M) separator internals Up to 100% gain vs conventional Key separators in various unitsSchoepentoeter inlet device Improves separation Broad applicability on many columns and vesselsShell ConSep trays 30–50% capacity gain above high-capacity trays Large capacity with high efficiency & reliable turndown

High-capacity internals

Table 2





specications. The type of crude unit revamp

represented in Table 3 would provide a potential

increase of 3 vol% to 4500 bpd more diesel in a150 000 bpd renery. This additional diesel will

affect the downstream ULSD hydrotreater oper-

ation, which would need to be considered in a

nal economic evaluation.

Similar approaches for increasing distillate

production have been used to debottleneck

conversion unit fractionation sections while

maintaining diesel product specications.

Projects have ranged from small to large Capex,

with small Capex projects using tower internals

and/or changing tower pressure using pump-arounds and steam, which

allows for minimum changes to

the existing fractionation tower,

to handle the increased distil-

lates production. In contrast,

large Capex projects have

involved more signicant

changes, such as the addition of

a tower to handle additional

product fractionation —

discussed here in the context ofhydrocracking and catalytic

feed hydrotreating.

As an alternative to cutpoint

changes, the list of crudes the

renery can run could be

expanded to change the distil-

lates-to-naphtha ratio in the

crude tower and, at the same

time, to increase utilisation of

the diesel-producing units


within the renery. This effort is simplied by a

crude database and the associated tools available

to evaluate the compatibility and protability ofnew crudes. Once the right crude or crude blend

is selected, crude tower operations should be

optimised, which may require small Capex

debottlenecking.

Hydrocracking Most of the conversion capacity of hydrocrackers

operating in North America is geared to the

gasoline market. Nevertheless, many hydroc-

rackers have some exibility for switching from

gasoline to distillate mode by adjusting process

Base Case 1 Case 2 Case 3 Case 4Description of change Baseline unit Increase CDU VGO recycle Reconfigure vac Route HAGO operation internal reflux to CDU tower for top from CDU to VDU

diesel productVol% of total diesel product 33 34 34 35 36Vol% of total diesel in crude recovered 91 93 94 96 98Probable Capex required Zero (base) Zero to low Low Med to high Med to high

Comments Typical operation Shift in heat Case 1 + VDU space dependent. Case 3 + additionalremoval profile additional Additional frac bed piping & controls

could affect piping possible incremental preheat train/ & controls loss of HVGO due

furnace firing to higher VDU dP

The % of total diesel is at constant diesel TBP 90% and flash point. Crude distillation unit (CDU); heavy atmospheric gas oil (HAGO); vacuum distillation unit (VDU);

light vacuum gas oil (LVGO). Special care would be required to avoid introducing a bottoms tail that could affect HDS units.

Increasing diesel recovery in a crude distillation unit

Table 3

10

20

30

40

50

60

70

80

90

100

0Naphtha mode Distillate mode Revamp

% l o v ,

d l e i y e t a l l i t s i D

CAPEX

Catalyst

Internals

Diesel op

Normal op

Figure 2 Example of increasing hydrocracker diesel yield





parameters, such as cracking conversion, liquid

recycle rate and product cut points, without

requiring Capex. Further increases in diesel

production and quality from existing assets can

be achieved through changes in catalyst andinvestment in small or large revamp projects.

Clearly, each hydrocracker is unique and

requires a detailed analysis of feed diet, operat-

ing constraints and desired yield to adjust and

optimise operations. Maintaining exibility to

adjust to market conditions and building in the

capability to handle a variety of feeds will allow

for maximum protability from the

hydrocracker.

The remainder of this section discusses

options for increasing diesel in

existing hydrocracking units and

the development of grassroots

units for current and future

crude sources.

Increasing diesel fromhydrocrackersFigure 2 illustrates the potential

increase in distillate yield based

on a single- or two-stage hydroc-

racker, for which the main

fractionator bottoms are used in

diesel pool blending. Feed qual-

ity, especially the nal boiling

point, needs close monitoring in

these units to meet diesel

specications.

Hydrocracker distillate mode

operation is typically achieved byswitching from a recycle opera-

tion to a once-through operation

while lowering conversion, which

increases diesel (bottoms)

production, as depicted in Figure

3.

Lower conversion may result in

lower distillate quality due to an

increase in aromatics and a resul-

tant drop in American Petroleum

Institute (API) gravity. A drop inproduct quality can be overcome

through the use of a more distil-

late-selective catalyst that will

improve distillate quality via

higher hydrogenation activity

while improving distillate yields.

Hydrocracking catalystsFigure 4 shows the middle distillate selectivity

and cracking activity of exible and naphtha-se-

lective catalysts.In many reneries, an improvement in distil-

late yield and quality has been realised by

switching from a naphtha catalyst to a conven-

tional, exible catalyst. Table 4 illustrates the

advantages of this change in catalysts in a North

American renery.

At this renery, the hydrocracker was

constrained by the gas make from the hydroc-

racker. Since the gas make and hydrogen

consumption were lower for the exible catalyst,


20

0

40

60

80

100

120

80 70 60 50

Overall conversion

f f

% l o v ,

d l e i y n e g o r d y h e v i t a l e R

Relativehydrogen

Naphtha

Distillate

5% loss involume gain

Figure 3 Reducing conversion in HCU to maximise diesel

Z-2723

Z-3723

Z-3733

Z-853

Z-863

Z-723

Z-733

Z-803

Z-753

Flexible

Naphtha

Cracking activity

y t i v i t c e l e s e t a l l i t s i d e l d

d i M

New generation

Z-3xxx: HDA , HDS

State of the art

Conventional

Z-2xxx: HC , ISO

Figure 4 Reducing conversion in HCU to maximise diesel





the feed rate to the unit could be increased to

match the renery’s capacity to handle the gas

generated from the hydrocracker and supply

hydrogen to the hydrocracker. The increase in

the feed rate, combined with the increased selec-

tivity of the catalyst, meant increased barrels of

distillate production. The lower activity of the

exible catalyst compared to the naphtha cata-

lyst did not limit the hydrocracker’s overall

catalyst cycle, since the cracking catalyst’s

temperature window still tted within the

pretreat catalyst’s operating temperature

window.

Although the reactor loop pressure drop was

not an issue in this example, lowering the reac-

tor pressure drop is always benecial to

hydrocracker operation, particularly if it is a

limiting factor for the hydrocracker feed rate

and/or cycle life. The catalyst shape TX has been

designed to reduce pressure drop across thereactor high-pressure loop.2

Hydrocracker revampsFigure 3 shows that an attempt to maximise the

distillate yield by lowering conversion resulted in

reduced hydrogen consumption. Increasing the

feed rate to utilise the available hydrogen can

recover the losses in volume gain across the

hydrocracker.

Thus, the primary modication to gasoline

hydrocrackers to improve distillate yield andthroughput involves a revamp of the fraction-

ation section(s). Hydrocracker revamps for

maximising the distillate range from:

• Small Capex: debottleneck -

ing projects, reactor internals,

tower internals

• Medium Capex: additional

fractionation capacity

• Large Capex: modifying the

reactor section to signicantly

increase throughput.Since, hydrocracker debot-

tlenecking revamps are unique

to each renery, this article

focuses on a higher-level

description of revamps.

Small Capex revamps

Shell GS has maximised distil-

late yield through minor

modications to the fractiona-

tion section of hydrocrackers. In gasoline

hydrocrackers where light and heavy naphtha

are drawn from the main fractionator, the heavy

naphtha draw has been redesigned as a distillate

draw. This modication, for example, increased

the cut point of the fractionator bottoms from

~195°C to ~290°C. It also increases the boiling

range of the recycle oil, thus signicantly mini-mising the cracking of light and middle distillate

products to light naphtha.

Another common hydrocracker revamp

involves replacing existing reactor internals with

Shell GS reactor internals. Some gasoline

hydro-crackers that were designed for an all

vapour phase quench zone have required new

internals based on changes in feed and conver-

sion. It is well documented that this strategy of

minimal capital investment increases liquid

yield. These benets have been seen in over 300hydroprocessing applications, including hydroc-

rackers owned and operated by reners

worldwide.


Table 4

Gas make, scfb -15%Naphtha, vol% ff -1.4Distillate, vol% ff +1.8Unconverted (UCO), vol% ff BaseFeed rate, bpd +15%

Distillate, bpd +20%H2 consumption, MMscfd Base

Commercial results for catalyst changeto increase distillate production

Figure 5 Cross-section of TL Trilobe shape compared to the new TX Trilobe shape

2

4

6

8

10

12

0

10 2 3 4 5 6

TX

2

4

6

8

10

12

0

10 2 3 4 5 6

TL





Replacement of older generation internals with

new internals enabled the catalyst volume in the

reactors to be increased by 11%.2 As a result

of new reactor internals, combined with the

implementation of the new TX catalyst shape,the unit now provides a more protable opera-

tion, indicated by:

• Lower weighted average bed temperature

(WABT), although at higher throughput and

higher conversion (roughly 2–3% higher)

• Signicantly lower liqueed petroleum gas

(LPG) make (previous enhanced oil recovery

(EOR) limiter) and hydrogen consumption from

the hydrocracker

• Increase in total distillate API and yield from

the unit at a constant overallconversion along with improved

yield stability over the catalyst cycle

(Figure 6).

The benets of the modications

to the hydrocracker were approxi-

mately $3 million per year.

Medium Capex revamps

For some reneries, the opportu-

nity to bring heavier feeds into a

hydrocracking unit is desirable, butin cases where the fractionator

bottoms is diesel pool blending

material, adding heavier feed to the

hydrocracker is likely to render the

diesel unsuitable for blending. The

addition of a vacuum asher

(depicted as the red column in Figure 7) to

recover diesel uncouples feed back-end from

diesel cold properties and enables the processing

of heavier/better feeds for maximising the distil-

late yield.Once the means are in place to lift distillate

from the bottoms product, increasing feed heavi-

ness and/or changing catalyst type are the next

steps in maximising distillate yields. The addi-

tion of light vacuum gas oils (LVGO, ~5–20%

depending on the unit) will improve the overall

diesel yield from the feed. Essentially, LVGO will

crack to two diesel molecules, while atmospheric

gas oils tend to crack to diesel and light naphtha.

Changing catalysts to a more diesel-selective


Days on stream

5

10

15

20

25

00 200 400 600 800 1000 1200 1400

Current

Previous

% ,

d e e f

h s e r F

Figure 6 Commercial example of higher distillate yield from Shell GSreactor Internals

Off gases

Naphtha

H2H2

2nd stage feed

1st stage feed

Distillate

Bleed

Figure 7 Illustration of a hydrocracker fractionation section revamp withthe addition of a vacuum flasher

LVGOAdditional LVGO to base feedrate, vol% +13

Catalyst NaphthaGas make, wt% ff -1.1Light naphtha, vol% ff -2.4Heavy naphtha, vol% ff -5.9Distillate draw, vol% ff +6.0UCO (distillate), vol% ff +1.4Distillate production, bpd +30%H

2 consumption, MMscfd Base

WABT, °F +6Total liquid product SFCaromatics, wt% Base

Increase in distillate productionfrom a gasoline hydrocracker through

additional fractionation

Table 5





catalyst will improve distillate yield and quality.

Table 5 illustrates the potential increase in distil-

late production from a base case, described as a

gasoline hydrocracker already operating in distil-

late mode with the additional fractionation of

distillate from the bleed stream. In

the LVGO case in the right-hand column, addi-

tional LVGO is added to the feed to improve

distillate production. The addition of a vacuum

asher has been utilised in at least one North

American hydrocracker to maximise diesel

production.

LVGOLarge Capex revamps

Larger Capex hydrocracker revamps include

paralleling of the stages (conversion to single

stage). These types of revamps will signicantly

increase the feed to the hydrocracker (more than

100%), but they depend on the number of cata-lyst beds available in the rst- and second-stage

reactors. In one North American renery, where

this type of revamp occurred, a portion of the

FCC feed was directed to the revamped hydroc-

racker in return for high-quality bottoms product

from the hydrocracker. A number of other modi-

cations are required for this type of revamp to

succeed, including areas in the fractionation

section.

Grassroots hydrocrackers for difficult feedsFor maximum diesel production, grassroots

hydrocrackers may be hard to justify in the

current economic environment. They are,

however, denitely part of the long-term strategy

of maximising diesel, especially if lower-priced,

heavier, sour feedstocks are used more in

the future.

Making diesel from difficultfeeds and heavy oil fractions

Signicant growth in the produc-tion of renery feeds from

bitumen-based reserves has been

achieved recently and is expected

to continue to grow throughout

the next decade. Canadian and

Venezuelan sweet synthetic

blends, and Canadian sour crudes

are now providing alternative

feedstocks for reners.

In addition to the change in

crude quality they present, difcult streams such

as heavy coker gas oils (HCGO), deasphalted oils

(DAO) and deep-cut heavy vacuum gas oil

(HVGO) have been economically attractive to

upgrade to diesel. Upgrading these crudes and

difcult feeds to clean fuels requires an under-

standing of the feed quality and chemistry

involved, familiarity with operating experience

from processing such feedstocks, and expertise

in combining catalyst technology for heavy gas

oil service and reactor internals, which has

provided reners with the opportunity to process

these feeds economically.

Recent licences An example of a key conversion process unit is a

state-of-the-art DAO hydrocracking unit achiev-

ing 60% conversion, processing DAO feed from

a solvent deasphalting (SDA) unit.3 The combi-

nation of SDA and hydrocracking provides aexible and economical solution to convert

heavy oil to high-quality ultra-clean fuels from

the hydrocracker, such as:

• Kerosene meeting Jet A1 fuel specications,

with sulphur <10 ppmw

• Diesel meeting Euro V specications, with

sulphur <10 ppmw

• Unconverted oil for producing 10 ppmw

sulphur FCC gasoline.

Step changes in middle distillates production

(jet plus diesel) can be achieved from increas-ingly more complex and more expensive residue

upgrading options (see Figure 8). Each technol-

ogy increases net present value (NPV) by

producing higher-value products. When Capex is

not a constraint, applying higher complexity,

high conversion technology, such as delayed


Relative kerosene + diesel, t/d

Residue conversion unit

500

1000

2000

3000

1500

2500

3500

0Shell

deepflashDeep thermal

crackerDelayed

cokerVisbreakerBase

VDU

d / t ,

d l e i y e t a l l i t s i d e l d d i M

Figure 8 Summary of middle distillates comparison for expanded refinery





coking, results in maximum middle distillate

production and highest NPV.

CFH/FCCFCC continues to serve an important role in the

rening industry producing gasoline, with an

estimated 350–400 FCCUs operating worldwide and over 100 in North America. Heavier

and sourer feeds, combined with lower product

sulphur requirements, have required pretreat-

ment of the feed in a catalytic feed hydrotreater

(CFH) or post-treatment of the FCC products in

various hydrotreating units. Continuing

changes in product pricing and quality have

raised questions of how best to utilise CFH/

FCC assets to balance gasoline and diesel

production.

Obtaining maximum distillate yield from theCFH/FCC complex can be achieved via:

• Improving FCC technology and catalysis to

increase conversion of vacuum gas oil feedstocks

into more valuable middle distillates, gasoline

and olen products

• Operating FCCU distillation to optimise the

gasoline-to-diesel ratio in accordance with

downstream hydrotreating capabilities and

market demand

• Recovering diesel from a CFH or converting a

CFH to mild hydrocracking in markets where

diesel is valued higher than gasoline.

FCCUs An FCCU can be operated in different modes to

increase distillate production using:

• Different FCC catalysts

• Lower conversion

• Product cut points (FCC heavy naphtha to

LCO).

Benets and costs from changes in FCC opera-

tion are unit dependent and require thorough

evaluation of each FCCU.

Shell GS introduced the middle distillate and

light olens selective (MILOS) process technol-

ogy as a longer-term, higher Capex opportunity

to increase diesel production and olens from an

FCCU.6 One of the most important features of

the MILOS technology is its exibility to take

advantage of market conditions and seasonaldemands, with capability to operate at:

• Maximum propylene and diesel mode or

• Maximum propylene (maximum conversion)

mode.

MILOS can process a wide variety of feed

components, such as rafnate, FCC naphtha,

coker naphtha, gas-to-liquid (GTL) wax, vegeta-

ble oils and palm oil.

LCO produced from MILOS is higher than that

produced by conventional FCCUs and with

better cetane. Incremental LCO produced fromthe FCC (conventional or MILOS) will have to be

hydrotreated before it goes to the ULSD pool.7,8

Catalytic feed hydrotreating Although the main purpose of a CFH unit is to

improve the quality of the FCC feed, there is an

opportunity to produce diesel from a CFH unit if

it can be fractionated from the hydrotreated

VGO before it goes to the FCCU. Diesel boil-

ing-range material is usually part of the CFH

feed, and more diesel is produced as carbon-sul-phur bonds are broken during the

desulphurisation process. Distillate yield can be

improved by increasing CFH severity and

increasing the VGO conversion through modied

operating strategies or catalyst systems.

Criterion’s Ascent catalysts have enabled reners

to achieve both ULSD (directly from the CFH

unit) and Tier-II gasoline (directly from the

FCCU) production.5 Typically, a CFH unit oper-

ating at moderate to high severity is required to


CFH operating conditionsCatalyst system DN-3551Capacity, bpd 80 000Pressure, psig 2000Gas-to-oil ratio, scfb 4500Feed type SR VGO, coker gas oil,

coker naphthaAPI 22Sulphur, wt% 2.5Nitrogen, ppmw 1050ASTM D2887 10%, °F 516ASTM D2887 90%, °F 1150Metals, ppm <8 ppmCCR, wt% 1.1

Gas oil product API 32Sulphur, ppmw <75

Nitrogen, ppmw 20 Metals, ppmw <0.3

CCR, wt% <0.3 Diesel product sulphur, ppmw <8

Feed and operating conditions

Table 6





produce a ULSD diesel-blending stream.

Reducing the diesel product’s end boiling point

may be necessary, and diesel cetane depends on

the CFH feed. ULSD for the North American

market is easier to make from a CFH, as it does

not have such stringent cetane requirements as

European diesel.

In one renery, the addition of a delayed

coking unit eliminated the need for the

high-pressure residue hydrotreating unit to

process residue. This enabled the high-pressure

hydrotreater to be used as a CFH. Working with

Criterion, the client was able to use this existing

asset at a high level of performance, to provide

both direct production of ULSD from the unit

and low-sulphur gasoline production from

the downstream FCCU. Table 6 summarises the

feed and operating conditions of this unit.

Distillation capabilities are required to produce

ULSD from a CFH unit. The addition of a frac-tionator in series with an existing stripper will

allow for diesel production. Many recent Shell

GS CFH designs include an integrated stripper/

fractionator to recover ULSD.

Producing diesel from a CFH unit will require a

unit-wide feasibility study to ensure the safety

and reliability of the unit is preserved. Hydrogen

consumption, recycle gas requirements and cata-

lyst bed temperature control have to be within the

design margins of the CFH unit. As the severity of

the CFH unit increases, additional light hydrocar- bons and ammonia are produced, which may

cause corrosion issues for the product cooling and

separation equipment in the CFH unit. Possible

solutions can be evaluated through a closer look

at the existing water wash system and amine

treating equipment.

Mild hydrocracking (MHC)Operation of a CFH to produce more middle

distillate can be achieved by increasing conver-

sion. This more severe operation operates in amild hydrocracking mode at higher reactor

temperatures with the existing catalysts and, in

many cases, modifying the catalyst system to

include a more active conversion catalyst such as

an amorphous silica-alumina (ASA) or zeolite.

The difference in operating mode can be seen in

Table 7.

Depending on the conversion and distillate

selectivity required, all alumina, alumina/ASA or

alumina/zeolite stacked systems can be consid-

ered. Higher conversions can be achieved by

alumina/ASA stacks and even higher by

alumina/zeolite stacks compared to a total

alumina system. Figure 9 summarises internal

pilot plant work for cases where a set catalyst

volume is available.

Although operation in the MHC mode using

only the existing reactor volume offers many

potential advantages, it can also have technicaland economic constraints. The relevance of these

constraints varies from renery to renery and a

careful technical and economic evaluation is

needed before converting the unit’s operation.

Several issues need to be considered:

• Product separation capabilities may be a seri-

ous issue, depending on existing conguration;

where a fractionation section is in place, the

tower internals can provide a low-cost solution

for increased diesel production

• The increased conversion will result in more vapour trafc, which needs to be accommodated

for safe operation of the unit

• Additional requirements for water wash, gas

treating and fractionation section equipment

constraints need to be reviewed and addressed

• Conversion of VGO streams may leave the

FCC under-utilised, unless there is additional

FCC feed available, (for instance, from imports),

or there is additional FCC pretreat capacity

(through debottlenecking)

• Additional hydrogen should be available because unit expansion and/or higher conver-

sion will require more hydrogen consumption

• The MHC operation will result in additional

naphtha that may need additional processing

• Seasonal demand factors may lead to opera-

tion with gasoline in the summer and middle

distillate in the winter, so the advantage can only

be realised for a part of the year

• The FCC pretreat unit will have shorter cycles

operating in the MHC mode


Table 7

CFH operation MHC operationCatalyst system options Total alumina Total alumina,

alumina/ASA,alumina/zeolite

Typical WABT, °F 680–750 715–795Conversion to 650°F minus vol% 5–10 10–50

Feed and operating conditions






internals or performing other small

debottlenecking revamps. Depending

on the renery economics, a rener

may also conclude that a new unit is

necessary for maximum diesel

production.

Improved hydrotreating catalysts A strong ULSD catalyst portfolio is a

key enabler for upgrading diesel

quality to meet the sulphur speci-

cation and also to have the ability to

treat more difcult feeds. This is

particularly the case when upgrad-

ing requirements go beyond sulphur

specications and address the

following key elements:

• Maximising activity to reduce the volume of

catalyst to achieve ULSD targets, freeing up

reactor volume for additional feed capacity orother upgrading catalyst system options

• Providing a range of CoMo and NiMo cata-

lysts to control hydrodesulphurisation (HDS),

hydrodenitrogenation (HDN) and hydrodearo-

matics (HDA) in feed preparation for additional

upgrading catalyst system options

• Offering the ability to control hydrogen

consumption to balance the higher hydrogen

requirements associated with additional upgrad-

ing requirements. Criterion has developed CoMo

and NiMo ULSD catalysts that provide very highHDS activity/performance.8

These new catalysts can produce ULSD in a

reactor volume, which is 75% of that required

with rst-generation ULSD catalysts. Therefore,

reners who designed their ULSD units with

rst-generation catalysts can take advantage of

the additional activity to increase run length,

process more barrels, or process tougher feeds

such as LCO and light coker gas oil (LCGO).

As feed capacity increases and feed quality

becomes more difcult, more complex revampsand possibly a new unit design may be required.

Dewaxing catalystsReners who market ULSD in cold climates may

also have the opportunity to increase diesel

production by maintaining a high-diesel

end-point during the winter months or utilising

a more diesel-selective dewaxing catalyst in their

existing distillate HDS/dewaxing units.

Shell GS and Criterion have developed selec-

• Typically, cycles are halved (although this

depends on the feed, operating conditions and

conversion target). A higher Capex solution is to convert the CFH

unit to a mild hydrocracker, with the addition of

catalyst volume (an additional reactor) and the

necessary revamp to take full advantage of the

higher conversion in the unit and increase both

the selectivity of the product and the operating

cycle of the unit. Similar issues need to be

resolved in the revamp to a mild hydrocracker.

In addition to CFH units being converted to

mild hydrocracking, in 2002 Criterion and Shell

GS, working with the Naftan Renery, revampeda distillate hydrotreater (DHT) unit to MHC

operation. The project made maximum use of

existing hardware at the renery in Novopolotsk,

Belarus.7

The mild hydrocracker conversion of VGO to

distillates is typically in the order of 45 wt% with

ultra-low sulphur fuels produced simultaneously.

The unit has experienced more than twice the

expected cycle length due to the excellent stabil-

ity performance of the selected catalyst system

and the use of updated reactor internals.

Diesel hydrotreating/ULSD With the initial wave of ULSD production well

established, attention has turned toward maxim-

ising diesel production in these new assets, as

well as looking forward to future requirements. A

rener has the ability either to increase the feed

rate to these units, or to process more difcult

feeds by utilising improved hydrotreating cata-

lysts, adding dewaxing catalysts, installing reactor

Overall 700°F + conversion, wt%ff

22

24

26

28

30

32

2015 20 25 30

f f

% t w ,

d l e i y e t a l l i t s i d

e l d d i M

Alumina

Alumina/zeolite

· Higher conversion levels

· Lower MD yields

Alumina/ASA

· 4% higher conversion

· 4% higher MD yields

Figure 9 Summary of catalyst systems to achieve varying levels ofconversion






capability to respond to market variation,

particularly when pursuing a targeted gaso-

line-to-diesel ratio.

Depending on a rener’s business goals and

the existing renery conguration, technical

solutions are available that encompass the whole

renery or focus on individual units.

Distillation and hydroprocessing are key tech-

nologies enabling enhanced production of diesel.

Combining unit know-how with best available

technologies and attention to renery-wide inte-

gration will provide optimal, renery-specic

solutions.

The authors wish to thank and acknowledge the contributions

of many colleagues in the preparation and review of this paper:

Sal Torrisi, Larry Kraus and Ward Koester, Criterion Catalysts &

Technologies; Robert Redelmeier, Keith Whitt, Vito Bavaro, Russ

Anderson, John Baric and Dave Dupree, Shell Global Solutions.

References

1 Hu M, Anderson R, Adarme R, Ouwehand C, Smegal J, The era

of ULSD — new challenges and opportunities for hydrocracking

processes, NPRA 2006 Annual Meeting, AM 06-46.

2 Sharpe A, Jones B, Hruska V, Baumgartner G, Anderson

R, Adarme R, Hu M, Ouwehand C, Boer M, A success story:

significant improvement in hydrocracker profitability with ULSD

production through customised catalyst systems, state of the art

reactor internals and outstanding technical cooperation, NPRA

2007 Annual Meeting, AM-07-67.

3 Blew W (Grupo Lotos), Baric J (Shell Global Solutions), Residue

upgrading opportunity with Shell DAO hydrocracking technology,RRTC, Apr 2008, Moscow, Russia.

4 Baric J, Selecting the residue conversion scheme for optimised

diesel production, ARTC, Mar 2009, Kuala Lumpur, Malaysia.

5 Carlson K, De Haan D, Jongkind H, Continued gains in FCC

performance: gains in process capability used effectively in clean

fuels production, ERTC, Nov 2008, Vienna, Austria.

6 Nieskens M, MILOS — Shell’s ultimate flexible FCC technology

in delivering diesel/propylene, NPRA 2008 Annual Meeting, AM-

08-54.

7 Artuch A, Shishov O, Yakubenka U (Naftan Refinery),

Samolienko I, Scheffer B, Kalospiros N, McNamara D (Criterion

Catalyst & Technologies) Kenna C, Snaijer A (Shell Global

Solutions), Increased upgrading at low cost: customised revamp

of a distillate hydrotreater into a mild hydrocracker, BBTC, Apr

2005, Moscow, Russia.

8 Torrisi S, Kraus L, Beyond ULSD, NPRA 2009, AM-09-11.

9 Huve L, Robertson M, Linde B, Pankratov L, Kalospiros N, Gitau

M, Ultra low sulphur diesel with dewaxing: a key technology for

profitable supply of high quality ULSD diesel, RRTC, Apr 2006,

Moscow, Russia.

Robert Karlin is a Senior Hydroprocessing Specialist, Shell

Global Solutions (US) Inc. He is based in Houston, Texas, and

tive cracking (SDD-800) and isomerisation

(SDD-821) dewaxing catalysts.8,9 Selecting the

right hydrotreating catalyst in combination with

SDD-800 allows for a drop-in option for many

existing ULSD units looking for a reduction in

the ULSD cloud point or improvement in cold

ow properties. SDD-800 is formulated to mini-

mise naphtha and light gas production in

selective cracking dewaxing mode and, when no

dewaxing is required, the dewaxing bed can

simply be switched off by quenching. In existing

dewaxing units, the diesel produced for an

equivalent improvement in cloud point is 5–10

wt% higher than with conventional dewaxing

catalysts8 and will allow for higher diesel produc-

tion instead of naphtha.

Small Capex revampsIn addition to catalyst activity and type, reactor

internals, especially for older generation HDSunits, are key to any successful revamp for a

capacity increase to take advantage of the

latest catalysts. Shell GS reactor internals for

gas-liquid distribution (HD Trays) and interbed

quenching (Ultra Flat Quench) have signicantly

enhanced the operation of lower- pressure HDS

units. Their designs utilise “lter trays” installed

in the top of the lead reactor(s) to mitigate pres-

sure drop and make better use of reactor volume

by reducing the volume of catalyst previously

used for pressure drop control.In a particular application, employing these

internals has allowed for ~30% higher catalyst

volume to be used which, with a higher activity

catalyst, resulted in a ~85% capacity increase

based on barrels processed.

To fully achieve the capacity increase provided

by the catalyst and reactor internals, evaluation

of other equipment should be performed to

ensure the successful implementation of any

expansion project. Issues to be evaluated include

hydrogen consumption, treat gas rates, quenchcapacity, recycle loop pressure drop, furnace

capacity, product stripping, water wash, and

corrosion, to mention a few.

ConclusionThe correct solution for increasing diesel

production should develop out of evaluation of

the application of technologies and their integra-

tion within a renery. Flexibility within

an overall renery approach can increase the






Kathy Wu is Senior Hydrocracking Tech-Service Engineer, Criterion

Catalyst & Technologies LP. She is based in Houston, Texas, and is

responsible for hydrocracking technical support in the Americas

for Criterion Catalysts and Zeolyst International.

Email: [email protected]

is responsible for Shell Global Solutions’ hydroprocessing

technology and design efforts.


Aris Macris is Licensing Technology Manager, Shell Global

Solutions (US) Inc. He is based in Houston, Texas, and is

responsible for Shell Global Solutions’ licensing technical

hydroprocessing efforts in the Americas.


Raul Adarme is Global Manager, Hydrocracking, Criterion

Catalyst & Technologies LP. He is based in Houston, Texas, and is

responsible for the hydrocracking catalyst business for Criterion

Catalysts and Zeolyst International.


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