Challenges_Opportunities_10ppm_2.pdf

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Challenges and opportunities of 10 ppmsulphur gasoline: part 2

An emerging worldwidestandard for ultra-low-sulphur gasoline (ULSG) as

well as the challenges of increasedheavy crude supplies and thegasoline/diesel imbalance demand

careful consideration and selectionof processing options. Part 1 of thisarticle (see PTQ, Q3 2012) discussedcommercially proven configurationsthat are available to meet theseconstraints and maintain profitabil-ity. An economic study, presentedhere, was also conducted to deter-mine the best scenario to meetULSG requirements: severe FCCfeed pretreatment alone or lesssevere pretreatment coupled with

FCC gasoline post-treatment. Theimpact of catalytic feed hydrotreater(CFHT) cycle length requirements,with and without post-treatment,was also examined.

An existing refinery reconfiguredto process heavy Canadian crudeswhile maintaining its FCC unit wasassumed. The VGO feedstockconsists of a 55 000 b/d blend of

Economic evaluation of processing options for ultra-low sulphur gasoline compares

severe pretreatment with a combination of pre- and post-treat solutions

DELPHINE LARGETEAU, JAY ROSS, MARC LABORDE and LARRY WISDOM

Axens

straight-run VGO and heavy cokergas oil with 4.2 wt% sulphur. Dueto the refractory nature of this feed,it has to be hydrotreated in a high-pressure unit prior to feeding theFCC unit, and the resulting gasolineconstitutes about one-third of thetotal gasoline pool and all of thepool sulphur. The following threecases were considered:

Case 1: A high HDS CFHT unitand FCC unit capable of producing10 wppm gasoline pool sulphurwithout the need for a FCC post-treatment unit with a CFHT cyclelength of four years to match theFCC unit Case 2: A moderate HDS CFHTdesigned for a four-year cyclelength with a FCC post-treatment

www.eptq.com PTQ Q4 2012 1

96

100

98

94

92

0 Case 1 Case 2 Case 3

CFHTDHS,

%

90

3

5

4

2

1 Cyclelength,

years

0

CFHT HDS

Cycle years

92.9% 92.9%

99.5%

Figure 1 CFHT HDS and cycle length

VGO

Case 1

Cases 2&3

Gas oil (650F+)

Distillate(400-650F)

Gasoline

Gasoline

LCO

Slurry

C1- C

4

4.2wt% S 230 wtppm S

3000 wtppm S

CFHT FCC Prime-G+

C1- C

4

Cases 2&3

Case 1

ULSG pool

Figure 2 Case studies block flow diagram


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2 PTQ Q4 2012 www.eptq.com

price of $4 MMBTU, resulting in ahydrogen cost of $3.300 MSCF.

The hydrogen cost for Case 1 isalmost 25% higher than for Case 2or Case 3; however, the yieldimprovement is quite significantover the lower severity CFHT cases.Between the lower severity CFHT

cases, the yields and hydrogenconsumption are rather similar, withthe more severe and longer cycleCase 2 providing a slight improve-ment in terms of yields over Case 3commensurate with the smallincrease in hydrogen consumption.

With regards to the operating cost(opex) of the different cases, thestudy took into consideration thehydrogen, octane and utility costs.Compared to the other factors, the

hydrogen cost was by far the majorcontributor to the opex. In additionto the operating cost, a detailedtotal capital investment (TCI) wasdeveloped to estimate the capex foreach case.

The TCI trend illustrated inFigure 3 clearly shows that Case 1has a much higher capital require-ment than the other two cases dueto the significantly higher desul-phurisation and cycle lengthrequirements for the CFHT.

Both net present value (NPV) andinternal rate of return (IRR)comparisons are shown in Figures4 and 5. High-severity CFHT with-out post-treatment, Case 1, wasconsidered as the basis, and the IRRand NPV of the other cases werecompared to Case 1.

The NPV results favour Case 1with a high HDS/long cycle lengthCFHT and no post-treatment overmore moderate HDS CFHT cases

coupled with a post-treatment unit.On the other hand, the IRR is mostfavourable for Case 3 with the

unit (Prime-G+), also designed for afour-year cycle length to meetULSG pool specifications Case 3: Similar to Case 2 but witha two-year cycle length target for theCFHT unit combined with a Prime-G+ unit designed for a four-yearcycle length. During the CFHT cata-

lyst change-out, the Prime-G+ unitwill operate at a higher severity tomeet pool sulphur requirements.

For all cases, a relatively highpressure was selected for the CFHTto ensure good hydrogen additionduring the whole run. Reactor resi-dence time was adjusted to meetthe CFHT HDS and cycle lengthrequirement (see Figure 1). Thevery severe level of HDS and four-year cycle length in Case 1 naturally

lead to a much larger CFHT thanthe other cases. High-purity hydro-gen is supplied from a steammethane reforming plant.

A blockflow diagram illustratingthe three different cases with thevarious configurations along withthe corresponding products consid-ered for the economics is shown inFigure 2.

The economic evaluation wasbased on a discounted cash flow(DCF) analysis assuming a depreci-ation period and a project durationof 10 years. In addition, a profitabil-ity index comparison in terms ofnet present value (NPV) and inter-nal rate of return (IRR) was

conducted. The prices for invest-ment, catalysts, utilities, feedstockand finished products were basedon 2011 averaged values, assumingthe plant to be located in the USserving a domestic market. Pricesare presented in Table 1.

For all three cases considered,projections on CFHT and FCCoperations were conducted, leadingto expected product yields andhydrogen requirements. As one

could have expected, the implemen-tation of a high-severity CHFT(Case 1) leads to better productyields in the FCC unit, but has amajor drawback of driving uphydrogen consumption. Results interms of main product yields andhydrogen cost for each case arepresented in Table 2. The evalua-tion was based on a natural gas

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90

70

60


TCI,%(

case1)

50

Base

Figure 3 TCI impact

Feedstock, $/bbl 96Natural gas, $/MMBtu 4.0Hydrogen, $/MSCF 3.300LPG, $/bbl 69Propylene, $/bbl 140Butenes, $/bbl 112Gasoline premium, $/bbl 127

Diesel/LCO, $/bbl 131Fuel oil, $/bbl 104

Price considerations

Table 1

Case Case 1 Case 2 Case 3

New units CFHT CFHT + CFHT +

post-treat post-treat

Cycle length 4 yr 4 yr + 4 yr 2 yr + 4 yrGasoline yield, vol%/VGO feed 61.9 56.3 55.0Diesel + LCO yield, vol%/VGO feed 27.2 27.6 28.0Propylene yield, vol%/VGO feed 7.8 7.5 7.3

Butenes yield, vol%/VGO feed 8.8 8.3 8.1Hydrogen cost, $/bbl feed 4.71 3.73 3.66

Study results product yields and hydrogen requirement

Table 2


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www.eptq.com PTQ Q4 2012 3

lowest cost CFHT option (moderateand two-year cycle) coupled with afour-year cycle post-treatmentPrime-G+ unit.

A sensitivity case was examinedto determine the impact of naturalgas cost on the NPV results. Thefindings are highlighted in Table 3,where pricing is contrasted to the2011 basis above. Assuming ahigher natural gas price ($6MMBTU vs $4 MMBTU), the cost ofhydrogen increases and the differ-ence in NPV between the threecases diminishes somewhat.

From an IRR perspective, theadvantage of Case 3 increases whenhydrogen cost increases and thegap in NPV between Case 1 and 3decreases.

Surprisingly, Case 2 with a four-

year CFHT cycle in sync with theFCC cycle does not show an NPVor IRR advantage over the shortercycle Case 3 for either natural gaspricing scenario. One could haveassumed that designing a CFHT insync with the downstream units,compared to limiting the CFHTcycle length to only two years,would be an advantage. However,the four-year cycle post-treatmentunit brings the additional flexibility

to continuously operate during aCFHT catalyst change-out. Despitehigher feed sulphur (that could bepartially limited with a change incrude diet during the CFHT catalystchange-out), the design of the post-treatment unit with the Prime-G+technology is robust enough tohandle this higher severity require-ment during the catalystchange-out.

This flexibility is clearly illustratedin Figure 6, which shows operating

data on a Prime-G+ unit in a refin-ery processing heavy crudes andequipped with a FCC CFHTpretreater. When the CFHT is inoperation, the normal feed sulphurto the Prime-G+ unit is typically

below 200 wppm. Despite turna-rounds or operation upsets on theCFHT unit, which can lead to feedsulphur as high as 900 wppm, theproduct sulphur from the Prime-G+unit can be maintained at the target

value of 20 wppm at all times.When processing full-range cut

naphtha (FRCN), the sulphur

content in the product is main-tained at the target value (20 ppm,see Figure 6) despite variations in

FRCN quality thanks to the FCCpretreatment option.

The flexibility brought by addinga post-treatment to the compulsoryFCC pretreater when processingheavy crudes should be underlinedand is a major advantage over thepretreatment alone solution. Inorder to produce a gasoline poolwith less than 10 wppm, the refin-ery becomes a chemical plant withno margin for error; relying on the

CFHT alone leaves little flexibility.In summary, coupling a CFHT

with a FCC naphtha post-treatment

unit brings the followingadvantages: The CFHT severity is lowered,

which offers the possibility torevamp an existing CFHT It is possible to design the CFHTunit for a cycle length of two yearsinstead of four The Prime-G+ post-treatmentdesign is simplified to typically asingle-stage unit The refinerys reliability and flex-ibility are improved: CFHT upset may be compen-sated by the Prime-G+

post-treatment unit CFHT severity may bedecreased if needed/permitted

95

105

100

90

85


NPVa

t10%(

case1)

80

Base

Figure 4 NPV results

3

5

4

7

6

2

1


IRR,additionalIRRp

oints

(case1)

0Base

Figure 5 IRR results

Case study Case 1 Case 2 Case 3NPV @10%: nat. gas = $4 MMBTU (case 2011) Base Base x 0.93 Base x 0.93NPV @10%: nat. gas = $6 MMBTU Base Base x 0.94 Base x 0.94

Study results hydrogen cost sensitivity study

Table 3


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or improve the performance of theFCC unit. Although every situationis site specific, the combination ofpre- and post-treat solutions aroundthe FCC unit will often provide thebest combination in terms of flexi-bility and economic benefits to mostNorth American refineries.

References

1 Bonnardot J, et al, Direct production of Euro-

IV diesel at 10 pm sulphur via the HyC-10

process, ERTC 9th Annual Meeting, Nov 2004.

2 Sarrazin P, et al, New mild hydrocracking

route produces 10-ppm-sulphur diesel,

Hydrocarbon Processing, Feb 2005.

3 Roux R, et al, Resid to petrochemicals

technology, ERTC 13th Annual Meeting, Nov

2008.

4 Debuisschert Q, Prime-G+ commercial

performance of FCC naphtha desulphurizationtechnology, AM-03-26, NPRA Annual Meeting,

Mar 2006.

5 Largeteau D, et al, Benzene management in a

MSAT 2 environment, AM-08-11, NPRA Annual

Meeting, Mar 2008.

6 Debuisschert Q, et al, Technology solutions

addressing gasoline and diesel imbalances,

Platts European Refining Market 4th Annual

Meeting, Sept 2010.

Delphine Largeteau is Technology Manager for

Olefins & Light Oil Hydroprocessing, Axens. She

joined Axens in 1998 as Process Engineer. She

holds a degree in chemical engineering from

Universit Technologique de Compigne (UTC)

in France and a masters in refining, engineering

and gas from the IFP School.

Jay Ross is a Technology and Marketing

Manager covering the field of transportation

fuels. He has over 30 years of experience in the

refining and petrochemical industry. He holds a

degree in chemical engineering from Princeton

University. He has served on the NPRA and

ERTC expert panels, and authored several

patents and numerous technical papers.

Marc Laborde is Strategic Marketing Engineer

in Axens Marketing Department. He holds a

degree in chemical engineering from Ecole

Nationale Suprieure de Chimie in Caen and a

masters in refining, engineering and gas from

the IFP School.

Larry Wisdom is a Senior Executive at Axens

in charge of marketing the companys heavy

ends technologies in North America. During

his 30-year career, he has co-authored more

than 30 papers on heavy oil upgrading and has

been awarded two patents. He holds a BS inchemical engineering and a MBA in marketing

and finance from the University of Kansas.

4 PTQ Q4 2012 www.eptq.com

FCC unit operation is moreflexible in terms of fractionationquality FCC gasoline end-point may beincreased when margins favourgasoline production while stillcontrolling FCC naphtha sulphurthrough post-treatment.

The issue of SOx and NOx controlin FCC flue gas is not addressed inthe above analysis. The high-

severity CFHT (Case 1) may allowthe typical 50 and 40 ppmv targetsfor SOx and NOx to be achieveddirectly, while a flue gas scrubberwould be necessary to meet suchconstraints with Cases 2 and 3. Theaddition of the scrubber for Cases 2and 3 decreases the IRR differentialto Case 1 by one point, whileconversely the NPV advantage overCase 1 is increased by approxi-mately 1%.

It is important to note that inspite of a trend in favour of Case 3,the conclusion drawn from this

particular study is case specific andcannot be generalised to other casesthat may have different configura-tions and project premise.

ConclusionMost countries are moving towardslimiting the sulphur level in trans-portation fuels to 10 wppm.Meeting new ULSG regulations at10 wppm while using existing FCC

post-treatment assets can beachieved using commerciallyproven solutions in numerous waysdepending on the constraints andrequirements of each refinery. Lowrefinery margins coupled with capi-tal constraints will likely make therevamping of existing FCC post-treatment units the preferred optionfor most refiners.

As light crudes productiondeclines, refiners will increasingly

process heavier crudes, resulting inhydrogen-deficient gas oil streamsrequiring hydrotreating to maintain

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Octane loss

Figure 6 Prime-G+ operation flexibility

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Challenges_Opportunities_10ppm_2.pdf