Annual Meeting March 20-22, 2011
Marriott Rivercenter San Antonio, TX



## AM-11-57 The Challenges & Opportunities of 10 ppm Sulfur Gasoline

Presented By:

Delphine Largeteau Technology Manager Axens Houston, TX

Jay Ross Marketing Manager Axens Houston, TX

Marc Laborde Axens Houston, TX

Larry Wisdom Axens Houston, TX

N

Washington, DC
20006 www.npra.org ational Petrochemical & Refiners Association 1667 K Street, NW Suite 700 202.457.0480 voice
202.457.0486 faxThis paper has been reproduced for the author or authors as a courtesy by the National Petrochemical & Refiners Association. Publication of this paper does not signify that the contents necessarily reflect the opinions of the NP RA, its officers, directors, members, or staff. Requests for authorization to quote or use the contents should be addressed directly to the author(s)AM-11-57 Page 1 

### The Challenges & Opportuniti es of 10 ppm Sulfur Gasoline

Axens Delphine Largeteau Jay Ross Marc Laborde Larry Wisdom

Introduction
The worldwide refining industry has undergone a ma jor transformation in the last decade due to changes in regulatory and market forces such as fluctuating crude prices, tighter regulation on product quality and refinery emissions, shifting cr ude quality and fundamental changes in fuel demands. These forces can be seen clearly in the North American market where crude quality has become heavier due to increasing amounts of lowe r cost heavy, sour Canadian bitumen and where regulations have become more severe by limiting the sulfur level in fuels to 15 wppm in diesel and 30 wppm in gasoline. In addition to these feed and product quality changes the overall transportation fuels demand is shifting from a tradit ionally gasoline-oriented to increasingly dieseloriented market.

The gasoline and diesel pool regula tory specifications, which are cons tantly evolving, have been in the forefront of refiners’ challenges in the last te n years. In particular, the gasoline sulfur and benzene regulations have been main drivers for th e recent remodeling of th e refinery configuration. This transformation has been seen all around the wo rld but particularly in Europe, Asia and North America. Other countries are following the tr end and a common worldw ide gasoline sulfur specification is on the horizon. Indeed the overall ga soline sulfur content is likely to level off at 10 ppm across the globe. As a conseq uence most refiners will face renewed challenges to be able to meet the new Ultra Low Sulfur Gasoline (ULSG) sp ecifications, however in view of other market forces there may also be new opportunities for refiners.

This paper will identify thes e new opportunities by reviewing the proc essing options and consequences of such regulation focusing mainly on North American refineries. This review will draw upon the European experience to meet 10 pp m ULSG regulations thr ough high severity FCC gasoline post-treating t echnology (such as Prime-G+ TM ) and examine the application of this experience to the North American market an d revamp of existing selective FCC Naphtha desulfurization units.

Another processing option adopted by many Asian refi ners is severe FCC feed pre-treatment (Cat Feed Hydro Treating or CFHT) as a way to lim it FCC emissions and avoid or minimize gasoline post-treatment. The paper will discuss the i ssues, challenges and oppo rtunities around the CFHT option in terms of increasing severity and cost. This will include an examination of the optimum level of desulfurization and hydrogen uptake in the hydrotreated FCC feed, impact on FCC performance and margins, and the opportunity to adjust the refinery Diesel/Gasoline ratio by operating in the Mild Hydr ocracking (MHC) mode.AM-11-57 Page 2 Gasoline Sulfur Regulation
There has been a steady downward tr end in the sulfur content of fu els to reduce the emissions from cars and trucks. Many countries mandated the pr oduction of Low Sulfur Gasoline (LSG) some time ago, but in recent years regulations in Western Eu rope, some Asian countries and California in the USA have called for even tighter specificati ons to lower the gasoline sulfur to 10 ppm.

The different regional approaches to gasoline su lfur specification are illustrated in the Table 1 showing a clear trend towards ULSG.

Table 1 Current Gasoline Sulfur Specification
REGION Gasoline Sulfur, wppm

EUROPE: EU 2005 Specification 50 EU 2009 Specification 10

USA: Tier 2 (2004-2006) 30 CARB 3 (California) 10 2010+ CARB 4 (California) 5

JAPAN: 2007 Specification 10

As shown in Figure 1, other countr ies are following the same path to either meet their domestic regulatory specifications or be able to expor t and sell on the interna tional ULSG market.

Source: Source: International Fuel Quality Center, www.IFQC.org

Figure 1 Maximum Gasoline Sulfur Limit in the World

Although the majority of countries still have gasoline sulfur sp ecifications well above 10 ppm, the overall trend clearly shows that in the near future ULSG pr oduction will become the norm worldwide. Chile: 15ppm since July 2010 EU: 10 ppm since 2009 Japan/ S Korea: 10 ppm since 2007

Hong Kong: 10 ppm

since July 2010 CA: 10 ppm for CARB 3 in 2008

Chile: 15ppm since July 2010 EU: 10 ppm since 2009 Japan/ S Korea: 10 ppm since 2007

Hong Kong: 10 ppm

since July 2010 CA: 10 ppm for CARB 3 in 2008AM-11-57 Page 3 Current Refinery Configuration
Refinery configurations vary widely depending on crude availability, local demand, export markets and regulatory constraints. In the same way each market has its own set of dynamics and means of complying with the new fuel regulations.

In Europe regulations for ULSG were adopted ea rly and somewhat influenced by a market demand which is more heavily skewed toward diesel than gasoline. The options for ULSG compliance were influenced by:

- Processing of relatively light and low sulfur crude oil

- Relatively good quality FCC f eed (little cracked gasoil su ch as heavy coker gasoil)

- Undercutting of FCC gasoline to maximize diesel production.

The EU 10-ppm ULSG is produced mainly by us ing moderate severity FCC post-treatment.

Many CFHT units installed in Asian refineries were designed to meet modern fuels and emission regulations. As such, many are designed for high desulfurization level to meet refinery and SOx regulations from the FCC flue gas resulting in low sulfur F CC gasoline. Consequently, most refineries in Japan have met the new ULSG limit of 10 ppm by adding low se verity post-treatment units.

In the US, the refinery configuration was infl uenced by a large gasoline demand coupled with limited fuel-oil outlet resulting in the installation of bottom-of-the barrel c onversion units and high FCC feed sulfur. The US Tier 2 gasoline sulfur and CARB regulations led to a sharp increase in the number of FCC feed pre-treatm ent and FCC gasoline post-treatmen t units over a s hort period of time as shown in Figure 2. Essentially all of the US refineries now have pre and/or post treatment units to ensure compliance w ith gasoline sulf ur regulation.

Figure 2 FCC Pre-treatment & Gasoline Post-treatment Trend in US Refineries

When the Tier 2 regulations were proposed, many were convinced that CFHT would be the solution of choice due to the resulting large improvement in FCC performance. However, the high capital cost requirement for the FCC pretreatment option c oupled with low refinery margins resulted in the wide application of FCC post-treatm ent to reduce gasoline sulfur.

Another factor that also can infl uence the decision between the pre- treatment and post-treatment is FCC flue gas emissions. Limits on refinery emissions and in particular those from the FCC have led to refinery-specific regulation vi a consent decrees with the EPA re sulting in much lower SOx and NOx emissions. The ‘preferred’ refinery configur ation may well have been different had the limits on emissions and product sulfur been regulated in concert. Pre-Treat Only

Post-Treat Only

Pre & Post Treatment

2001 2010AM-11-57 Page 4 More recently there has been an important trend to ward processing of increasingly heavier crudes in particular heavy Canadian crude or bitumen. By the year 2015, there is an expected increase of about 2 Million BPD of Canadian bitumen which will be largely exported to the US as raw bitumen (DilBit) or synthetic bitumen (Syn Bit) after partial upgrading at the production site. These very heavy crudes are a challenge for processing in exis ting refinery assets due to a high acid content (TAN), high aromaticity and low hydrogen content al ong with very high contaminant content: S, N, Con Carbon, and metals. A sampling of heavy crude components which may be considered potential FCC feed are show in Table 2 to highl ight the challenges of processing Bitumen derived materials.

Table 2 FCC Feed Quality from Heavy Feeds As a result of these feedstock trends and renewe d focus on cleaner fuels, lower emissions and even a shift in the gasoline / diesel production, the topic of pre-trea tment v post-treatment is upon us again. More specifically we will focus on the pre- treat and post-treat issues around the FCC as it relates to FCC performance, emissions and le vel of product gasoline post-treatment required.

FCC Pretreatment Options
The benefits of FCC feed pretreatment in a CFHT are well known and extend beyond simply reducing the sulfur level in the F CC feed. The reduction in sulfur a nd other contaminants is helpful in terms of reducing the FCC product sulfur level and lowering the fl ue gas emissions from the FCC, but the interaction with improved feed quality and increased FCC performance is also very important as will be discussed. Environmental regulations and in particular the need to produce very low sulfur gasoline have put increased emph asis on the CFHT performance and reliability.

Co-currently, the lower demand fo r fuel oil coupled with the pr ocessing of heavier crudes has resulted in the installation of residue conversion units such as delayed cokers. These conversion units produce significant amounts of hydrogen defici ent, heteroatom rich (N and S) Vacuum Gasoils (VGO, HCGO) which need to be deeply hydr otreated prior to conver sion in the FCC unit. Canadian Bitumen Coker HCGO Syn. Bitumen Mexican Blend Arabian Light

VGO

API Gravity 13 13 18 22 26 Sulfur (w%) 3.3 4 - 5 1.7 2.2 2.2 Nitrogen (ppm) 2100 4000 1500 1000 700 Hydrogen (w%) 10.7 10.5 11.5 11.7 12.4
ATB

API Gravity 5.7 9 6 17 Sulfur (w%) 4.9 3.6 3.6 3.1 Nitrogen (ppm) 5000 3500 3000 1900 Hydrogen (w%) 9.2 10.8 9.8 11.4 Con.Carbon(w%) 15.3 11.2 11.6 8.1 Ni + V (ppm) 325 200 258 49AM-11-57 Page 5 As a result, modern CFHT units need to proce ss increasingly more refractory feedstocks while achieving high desulfurization levels to meet ga soline sulfur specifi cations. The increased contaminants also make it more difficult for the CFHT to upgrade the quality of the FCC feed to maintain the required yield of gasoline and LPG. In addition to the objective of hydrodesulfurization, hydrodenitrogenation and pol ynuclear aromatics (PNA) saturation, processing of cracked stocks in a CFHT, often with high end-point to maximize refinery economics, require s a careful selection of the catalytic system to take into account the potential fo r higher metals (Ni, V, As, Si...), asphaltenes along with the higher fouling propensity of these aromatic rich feeds.

On the other hand, this problem can turn into an opportuni ty to increase the se verity of the CFHT not only to meet sulfur targets but also to change th e refinery Diesel/Gasoline ratio by operating in the Mild Hydrocracking (MHC) mode and take advantag e of low cost natural gas to further increase volume swell. These adjustments will require some modifications to the operating conditions, selection of optimum catalytic system and distributor internal s, increased hydrogen consumption and likely upgrades throughout the unit. One of the challenges of operating in the MHC mode is the ability to meet Ultra Low Sulfur Diesel (U LSD) specifications throughout the MHC cycle. Moderate pressure MHC units generally do not meet the required diesel sp ecifications therefore post treatment is required. One attractive option to meet this challenge is the HyC-10TM technology developed by Axens to integrate the diesel upgr ading within the MHC high pressure loop while decoupling operating conditions 1 2 . Another important factor in MH C/CFHT design is the ability to maintain desulfurization targets while meeting optimum VGO quality throughout the cycle length.

In conclusion, a deep understanding of the feedst ock type and the chemical reactions involved in a CFHT (kinetics, thermodynamics, contamination/poi soning) coupled with their impact on the FCC operation is paramount to selecting the optimum CFHT operating conditions and design of the optimum catalyst system. The following section w ill examine the influence of the CFHT operation on the FCC unit performance.

FCC Performance in Relation to CFHT
The FCCU has long been the workhorse in the refine ry to achieve relatively low cost conversion of heavy crude components (VGO, HCGO and some atmo spheric residue) into gasoline, butenes for high octane alkylate production, propylene and LCO diesel bl end components. Although the chemistry and catalyst systems can be comple x, generally speaking the FCCU is a hydrogen redistribution system with some carbon rejection as coke that is consumed in the process. The performance of the FCC and yield of valuable pr oducts is therefore linked to the hydrogen content of the feed. This trend is shown in Figure 3 where the conversion potential and gasoline yield increase sharply with the hydrogen content of the feed.

The CFHT therefore has a vital role in improving the FCC feed quality to enhance the yield and overall refinery profitability. As the feed cont aminants of sulfur and nitrogen are reduced to improve product quality and reduce FCC emissions , multi-ring aromatics are saturated and the crackability of the feed increases . As seen in the figure belo w sharp gains in conversion and gasoline yield result from the first incremental increase in hydrogen and there is some degree of diminishing returns. When propyl ene yield is of interest the in creased hydrogen input is always beneficial and in many cases high hydrogen input can be justified, partic ularly when hydrogen is relatively inexpensive 3

.AM-11-57 Page 6 As the severity of the CFHT incr eases there is also the opportunity of co-produced diesel in the CFHT via mild hydrocracking to shift the overall refinery balance between gasoline and diesel. Defining the optimal balance between severi ty, hydrogen input, cracki ng, and FCC mode of operation within the existing constr aints of a refinery configura tion is therefore very complex.

Figure 3 FCC Yield vs. Feed Hydrogen Content

Within the context of ULSG, the more tradition al role of the CFHT to consider is that of desulfurization and the impact on th e FCCU gasoline produced. As th e sulfur content in the FCCU feed decreases and the extent of feed hydrotreating increases, the types of sulfur left in the FCC feed alter and the amount of sulf ur found in the gasoline decrease s. Figure 4 demonstrates this general trend for feeds that are hydrotreated and for non-hydrotre ated feeds of varying sulfur
content.

1 10 100 1000 10000

0.01 0.1 1 10 Feed Sulfur, W%Gasoline S, wppm

Straight Run
Hydrotreated

Figure 4 FCC Gasoline Sulfur vs. Feed Sulfur & Treatment 35 40 45 50 55 60 65 70 75 80 85

10.5 11.0 11.5 12.0 12.5 13.0 13.5 Feed H, Wt%Wt%

0 2 4 6 8 10 12 14 16 18 20Wt% Conversion
Gasoline
Fuel Oil P r o

p

y

l e

n

e P o

t e

n

t i a

l

P

r o

p

y

l e

n

e P o

t e

n

t i a

lAM-11-57 Page 7 A short-hand means of describing the gasoline sulfur is as a ratio to th e feed sulfur with virgin feed tending to a ratio of 10 and hydrotreated feed to a bout 20 (feed sulfur / gasoline sulfur). There are several important cavea ts to this simple rule: it relates to standard cut C5-430°F TBP cut point gasoline only, it depends on the conv ersion level in the FCC, it can depend on the severity/pressure level of the CFHT. There are co mmercial units with CFHT feed e xhibiting ratios of 35:1 and 10:1 therefore this is only a shorthand estimate without the benefit of a model. In addition, this does not consider the impact of catalyst effects wh ich can shift the sulf ur content by 10-30%.

If one were to target the new ULSG pool sulfur level of 10 ppm, we can see that the CFHT must reduce the feed sulfur to about 200 -300 ppm. This will be true even if we consider that the FCCU gasoline is only about 1/3 of the p ool and the other blend stocks are nearly sulfur-free as refiners will leave some margin below 10 ppm to ensure compliance.

When looking at the sulfur in the FCC gasoline one needs to be very clear about the gasoline cut point and the distillation tail on the produced gasoline product. In Figure 5 we can see a carefully analyzed commercial FCCU gasoline and the cumulative full range gasoline sulfur vs. TBP.

0 20 40 60 80 100

25 50 75 100 125 150 175 200 225 250 Temp, CCumulative Sulfur, %

Thiophene C1-Thiophene BenzoThiophene

C2-Thiophene Alkyl-BenzoThiophenes

Mercaptans S S

Figure 5 FCC Gasoline Sulfur Profile

The above figure clearly demonstrates the importa nce of defining the gasoline boiling range when discussing the sulfur level. In the US market, gaso line has been traditionally ‘over-cut’ relative to the standard 430°F (221°C) cut and often extended to 450-480°F thereby including not only benzothiophene but also some methyl-benzothiophen es in the gasoline. Th ese compounds enter the gasoline cut just at the standard cut point and complicate accurate measurement of gasoline sulfur from non-ideal industrial samples. With the increas ed interest in distilla te production, undercutting the gasoline to less than 430°F will significantly help control the sulfur level when producing ULSG – as is done in Europe.

Considering the dependence of FCC gasoline on bot h CFHT performance and precise fractionation of the gasoline product, meeting ULSG targets th rough CFHT alone is po ssible but challenging. There will be little room for error or deterior ation in CFHT performance over the course of a production run or cycle.AM-11-57 Page 8 FCC Post-treatment Options to meet ULSG
In order to comply with low sulf ur gasoline regulation, a majority of refiners in North America and across the world have already invested in a FCC post-treatment unit s . Howe ver, processing schemes vary greatly from one site to another dependi ng on the sulfur specifi cation, overall refinery configuration and crude diet as de scribed earlier in this paper a nd as illustrated in Table 3.

Table 3 FCC Gasoline Post-Treatment Unit Design

Typical Feed Sulfur, wppm Product Sulfur, wppm Western Europe 200 – 1,000 10 - 20
North America 500 – 2,000 30 -50
California 100 - 300 10 -20
South America 500 – 2,000 30 - 100 Japan / Korea 50 - 200 10

Most refineries in California and Japan are equi pped with FCC feed pre- treaters which explain the low sulfur level in the FCC naphtha. Conversely, FCC naphtha sulfur tends to be high in the Americas and high severity post-treaters will be required to meet a 1 0 ppm gasoline sulfur target.

The Prime-G+ process selectively desulfuriz es the FCC Full Range Naphtha (FRCN) while ensuring minimal octane loss. It is by far the most widely used cracked ga soline desulfurization technology with over 190 Prime-G+ li censed units throughout the world 4 . The technology has proven to be the most flexible process on the ma rket with several Prime-G+ processing schemes offered according to the targeted severity of the unit - Figure 6.

Low/Moderate HDS

Prime-G+ 1-stage HDS

Moderate/High HDS

Prime-G+ 1 st Step (SHU & Splitter) / 1-stage HDS Prime-G+ 2-stage HDS

Figure 6 Prime-G+ Processing Schemes FCC FRN HDT SHU ULSG

FCC FRN

HDT SHU ULSG LN

FCC FRN HDT
1&2 SHU ULSGAM-11-57 Page 9 Figure 6 (Continued)

Very High HDS

Prime-G+ 1 st Step (SHU & Splitter) / 2-stage HDS

Depending on the existing Prime-G+ configurati on, meeting new ULSG re gulations at 10 ppm while using the existing assets coul d be achieved in different ways.

First, one potential solution which does not require any additional investment would be to simply increase severity (essentially reactor temperatur e) to lower the existing Prime-G+ product sulfur. The increased HDS level would lead to higher oc tane loss and hydrogen consumption coupled with a potential cycle length reduction. Switching to higher selectivity and activity Prime-G+ catalysts may help mitigate these drawbacks but could prove insufficient in many cases.

Another solution would involve the co-processing of other sulfur ri ch streams in the Prime-G+ unit that previously did not require any treatment to meet the earlier sulfur specifications. The streams could be light streams such as Light Coker Naphth a or Visbroken Naphtha th at can be handled in the Prime-G+ first step (Selective Hydrogenation Un it – SHU - and Splitter section). Light straight Run Naphtha, Natural Gasoline coul d also be co-processed either in the SHU upstream of the splitter or directly in to the HDS section. One of the draw backs of co-processing is possible hydraulics limitations in the unit. In addition, adding sulfur rich streams could lead to a higher HDS level coupled with higher octane loss and again potential for cycle length reduction.

An alternative option would be to decrease the Prime-G+ feed sulfur to maintain a similar HDS level across the unit to ensure constant octane lo ss and cycle length. Loweri ng the feed sulfur could be achieved in different ways. The short term solutions w ould be to use sulfur reduction additives in the FCC or process low sulfur crudes. Both of th ese options have limitations and are generally not practical for significant sulfur reduction without a heavy penalty on refinery flexibility. More realistically, a reduction of the F CC Naphtha end point or changes in the CFHT could be envisioned to reduce the sulfur in the F CC Naphtha. In Western Europe, it is common to reduce the FCC Naphtha end-point as it also maximizes the diesel production to meet the market demand.

As most refineries are equipped with a FCC post-treatment unit to control gasoline sulfur, it is instructive to take a closer look at the revamping options around the selective FCC Naphtha desulfurization unit to meet the new ULSG requirements. There are a number of possibilities to revamp an existing selective FCC Naphtha desulfuri zation unit to meet tighter sulfur specifications that display different levels of complexity and associated cost: FCC FRN

HDT
1&2 SHU ULSG LNAM-11-57 Page 10 1. Option 1: Install a Prime-G+ 1 st step if not existing

2. Option 2: Add a SHU (Selective Hydrogenation Un it) or HDS reactor if the cycle length is a limitation for the new product sulfur target

3. Option 3: Route the Medium Cat. Na phtha (MCN) cut to the NHT/Reformer

4. Option 4: Process the Medium Cat. Naphtha (MCN) and the Heavy Cat. Naphtha (HCN) streams separately

5. Option 5: Install a second stage HDS section

In option 1, the installation of a FCC naphtha splitter downstream of the existing (or new) SHU is the Prime-G+ 1 st step. The SHU operating conditions and SHU catalyst design allow for the selective hydrogenation of the di olefins which may foul the desulf urization section and also the conversion of light sulfur species such as me rcaptans to heavy boili ng sulfur compounds. As a result of the chemical reactions taking place in the SHU, the downstream splitter produces a sweet, low-sulfur Light Cat Naphtha (LCN) stream ri ch in olefins and a H eavy FCC Naphtha (HCN) which is routed to the HDS section. Such HCN stream with its lower olefins content can be selectively desulfurize d through the use of tailored catalysts to meet the ULSG targ et while controlling the olefins saturation and thus octane loss. The addition of the splitter reduces th e throughput to the HDS section and hydrogen consumption. This solu tion also allows the co-processing of other streams containing sulfur such as coker naphtha, visbroken naphtha, straight run naphtha or natural gasoline.

For option 2, the addition of a SH U upstream of an existing splitter will produce a sweet low-sulfur LCN stream and provide similar benefits as described in opti on 1. In case cycle length becomes limited, implementation of an additional HDS react or in series with the existing one can be envisioned. Option s 1 and 2 are easy to implement and le ad to moderate cap ital expenditure.

The typical block flow diagram of Option 3 is presented in Figure 7.

Figure 7 FCC Naphtha Heart Cut (MCN) to Reformer

LCN SRN HCN Coker N

HCN FRCN MCN MoGas PoolSplitterSplitter
Reformer NHT Isom

Prime-G+Benfree

LCN SRN HCN Coker N

HCN FRCN MCN MoGas PoolSplitterSplitter
Reformer NHT Isom

Prime-G+BenfreeAM-11-57 Page 11 This option involves revamping the existing splitter in to a 3-cut column in or der to withdraw a heart cut (MCN) rich in olefins and which contains some sulfur and exhibits a moderate octane number (especially MON). The MCN is then mixed with th e normal feed to the NHT unit and reformer unit. Sending the MCN to the reformer will lead to a gasoline octane gain. However, there may be limitations in terms of capacity for both NHT and re former sections that need to be carefully assessed and taken into account for the evaluation of the overall revamp cost. In addition potential increased benzene production in th e reformer could lead to issues in meeting the MSAT II gasoline benzene specifications. The addition of an in tegrated reformate spli tter/benzene hydrogenation (Benfree TM ) solves this issue 5

.
While this solution offers some advantages in term s of octane, the decreased gasoline yield should also be considered. Overall, this option may be attractive but has more implications than just making modifications to the existi ng FCC post-treatment section.

Decoupling of the MCN and HCN can also be utilized to treat thos e two streams in two separate selective HDS sections. This is option 4 and is illustrated in Figure 8.

Figure 8 Decoupling MCN & HCN Processing

This innovative and patented scheme by Axens ha s the additional advantage to offer greater flexibility to route the desulfurized HCN either to the Mogas or Diesel Pool according to the economics of the refinery 6 . Both MCN and HCN selective HDS sections are designed to minimize octane loss while achieving 10 ppm product sulfur . Compared to the previous option, option 4 incurs more revamping cost as a new MCN HDS s ection needs to be installed. But the additional cost could be easily offset by the improved octane retention compared to treating the combined MCN and HCN in a single one-stage selective HDS section at ULSG levels and by the additional flexibility that this option offers.

The last option that is being explor ed in this pape r is the inclusion of a second stage HDS section to minimize octane loss and maintain or even increas e the catalyst cycle length. The typical block flow diagram is presented in Figure 9. Although shown below with the splitter upstream of the HDS to Mogas or Diesel ULS MCN:

150-300 °F

to Mogas

FRCN Prime-G+ Selective Hydrogenation Ultra Low S LCN to
Pool, TAME or Alky UnitSplitter

SHU MCN HDS

HCN HDS Process Integration

ULS HCN:

300°F-FBP to Mogas or Diesel ULS MCN:

150-300 °F

to Mogas

FRCN Prime-G+ Selective Hydrogenation Ultra Low S LCN to
Pool, TAME or Alky UnitSplitter

SHU MCN HDS

HCN HDS Process Integration

ULS HCN:

300°F-FBPAM-11-57 Page 12 section, Axens has also the experience of desi gning a two-stage HDS s ection on full range FCC Naphtha with no upstream splitter.

In a typical one-stage HDS configuration, the olef ins saturation, and thus octane loss, increases rapidly above 98% HDS. At high HDS level, the addition of a second-stage HDS section helps improve octane retention and minimize hydrogen consumption.

Figure 9 Revamp of Prime-G+ HDS into 2-stage Configuration

Several Prime-G+ units have been designed fo r two-stage operation a nd many are in operation. Although this option requires additional capital investme nt, there is a real in centive to pursue this solution when the refinery is octa ne-tight or hydrogen constrained.

These several options provide commercially prove n solutions for refiners to meet new ULSG specifications with existing or modified post-treatm ent units. In view of the low refinery margins and octane-long position resulting from the ethanol mandate, the debottlenecking of a selective FCC Naphtha desulfurization unit will likely be the preferred solution for many refiners assuming no significant changes in their crude diet.

A number of refiners are however envisioning the processing of h eavy crudes such as those derived from Canadian Oil Sands due to their lower cost coupled with geopolitical re asons. Processing of these heavy crudes require s a comple te refinery reconfigur ation with bottom of the barrel conversion units such as coking or ebullated bed hydrocrack ing. As described earlier, the resulting VGO and HCGO streams are very refractory with high levels of sulfur a nd nitrogen and very low hydrogen content. Such feeds require deep pre-treatment prior to feeding the FCC unit to maintain acceptable yields. Since FCC pre-treatment (CFHT) is manda tory in those cases, one may wonder whether a post-treatment unit is required or not.

In the next section, an economic comparison betw een the options with FCC Pretreatment only or in combination with post-treatment will help better illustrate the pros a nd cons for each solution. HCN 150°F+ H 2 Make-up Ultra-Low Sulfur Gasoline to Mogas H2S

FRCN Prime-G+ Selective Hydrogenation Ultra Low S LCN to
Pool, TAME or Alky UnitSplitter

SHU 2 nd Stage HDS 1 st Stage HDS

HCN 150°F+ H 2 Make-up Ultra-Low Sulfur Gasoline to Mogas H2S

FRCN Prime-G+ Selective Hydrogenation Ultra Low S LCN to
Pool, TAME or Alky UnitSplitter

SHU 2 nd Stage HDS 2 nd Stage HDS 1 st Stage HDS 1 st Stage HDSAM-11-57 Page 13 Economic Evaluation: FCC Pre-treatment vs. FCC Pre-treatment & FCC Naphtha Post-treatment

An economical study was conducted to determine th e best scenario between the FCC Feed pretreatment alone and post-treatment options as well as the optimum desulfurization and cycle length for the CFHT when considered in combination with a post-treatment. We considered a refinery being reconfigured to process Heavy Canadian Crudes and maintaining its FCC Unit. The VGO feedstock consists in a 55,000 BP D blend of straight run VGO a nd Heavy Coker Gas-Oil with 4.2 wt% sulfur. Due to the refractivenes s of this feed, it has to be hydrot reated in a high pressure unit prior to feeding the FCCU. The followi ng three (3) cases were envisioned:

 Case 1: A high HDS CFHT unit capable to pr oduce a 10-wppm Gasoline pool sulfur without the need of a F CC Post-treatment unit for a 4 year cycle length.

 Case 2: A moderate HDS CFHT designed for a 4- year cycle length with a FCC Posttreatment unit (Prime-G+) designed for a 4-year cycle length, to meet ULSG specifications.

 Case 3: Similar to Case 2 but considered a 2-year cycle length target for the CFHT unit combined with a Prime-G+ unit designed for a 4- year cycle length. It is assumed that during the CFHT catalyst change-out, the refinery would either change crude diet or process stored hydrotreated gasoil material.

For all cases, a relatively high pressure was selected for th e CFHT to ensure good hydrogen addition during the whole run. Reactor residence time was adjusted to meet the CFHT HDS and cycle length requirement – Figure 10.

99.5%

92.9% 92.9%

90% 92% 94% 96% 98% 100%

Case 1 Case 2 Case 3CFHT HDS

0 1 2 3 4 5Cycle Length, years

Figure 10 CFHT HDS & Cycle Length

In all cases, hydrogen is supplied from a SMR plant.

A block flow diagram illustrating the 3 different cas es with the various configurations along with the corresponding products considered fo r the economics is shown in Figure 11.AM-11-57 Page 14 Figure 11 Case Studies Block Flow Diagram

The economic evaluation was based on a Discounted Cash Flow (DCF) analysis assuming a depreciation period and project dur ation of 10 years. In addition, a profitability index comparison in terms of Net Present Values (NPV) and Internal Rate of Retu rn (IRR) was conducted. The prices for investment, catalysts, utilities, feedstock and finished products were based on 2010 averaged values assuming the plant to be located in the USA serving a domestic market.

For all 3 considered cases, projections on CFHT and FCC operations were conducted leading to expected product yields and hydrogen requirement for each case. As one could have expected, the implementation of a high severity C FH T (Case 1) leads to better product yields in the FCC but has a major drawback of driving hydrogen consumption up. Results in terms of main product yields and hydrogen cost for each case are presented in Tabl e 4. The evaluation was based on a US Natural Gas price of $4.4/MMBTU.

Table 4 Study Results – Product Yields & Hydrogen Requirement

Case Units Cycle Length Case 1 CFHT

4 yr Case 2 CFHT + Post-treat 4 yr + 4 yr Case 3 CFHT + Post-treat 2 yr + 4 yr

Gasoline Yield, Vol.% / VGO Feed 61.9 56.3 55.0
Diesel + LCO Yield, Vol.% / VGO Feed 27.2 27.6 28.0
Propylene Yield, Vol.% / VGO Feed 7.8 7.5 7.3
Butenes Yield, Vol.% / VGO Feed 8.8 8.3 8.1 Hydrogen Cost, $/bbl Feed 4.9 3.9 3.8 VGO Prime-G+ Distillate (400-650°F)

Gas Oil (650°F+)

Case 1 = 230 wppm S
Case 2 & 3 = 3,000 wppm S

LCO
Slurry 10 wppm S Gasoline Pool C 1 - C 4

Gasoline C 1 - C 4



### FCC CFHT

Case 1
Case 2 & 3 Gasoline Case 2 & 3

Case 1 VGO Prime-G+ Distillate (400-650°F)

Gas Oil (650°F+)

Case 1 = 230 wppm S
Case 2 & 3 = 3,000 wppm S

LCO
Slurry 10 wppm S Gasoline Pool C 1 - C 4

Gasoline C 1 - C 4



### FCC CFHT

Case 1
Case 2 & 3 Gasoline Case 2 & 3

Case 1AM-11-57 Page 15 The H 2 cost for Case 1 is almost 30 % higher than that of Case 2 or Case 3. However, the yield improvement is quite significant between Case 1 a nd Case 3. Case 2 provides a slight improvement in terms of yields with an almost constant H 2 consumption compared to Case 1.

With regards to the operating cost (OPEX) of the different cases, the study took into consideration the hydrogen, octane and util ity costs. Compared to the other factors, the hydrogen cost was by far the major contributor to the OPEX. In addition to the operating cost, a detailed Total Capital Investment (TCI) was developed to estimate th e CAPEX for each case study to compare the 3 options.

The trend illustrated in Figure 12 clearly shows th at Case 1 has a much higher capital requirement than the other two Cases due to the significantly higher desulfurization and cycle length requirements for the CFHT.

Figure 12 Total Capital Investment (TCI) Impact

Both Net Present Value (NPV) and Internal Rate of Return (IRR) are shown in Figures 13 and 14. The high severity CFHT without post-treatment, Ca se 1, was considered as the basis and the IRR and NPV of the other cases were compared to Case 1. 50 60 70 80 90 100

Case 1 Case 2 Case 3 TCI, % / Case 1 Base

50 60 70 80 90 100

Case 1 Case 2 Case 3 TCI, % / Case 1 BaseAM-11-57 Page 16 Figure 13 NPV Results

Figure 14 IRR Results

The NPV results favor Case 1 with a high HDS/l ong cycle length CFHT and no post-treatment over more moderate HDS CFHT cases coupled with a pos t-treatment unit. On the other hand, the IRR is most favorable for Case 3 with the lowest cost CFHT option (moderate and 2-year cycle) coupled with a 4-year cycle post-treatment Prime-G+ unit.

In addition, a sensitivity case was examined to determine the impact of natural gas (NG) cost on the NPV results. The findings are highlighted in Table 5 and show the impact of NG on relative NPV’s. Assuming a Natural Gas price co rresponding to the 2008 price, whic h was twice as much as the basis of 4.4 $/MMBTU, the difference in NPV between the three cases diminishes somewhat. 80 85 90 95 100

Case 1 Case 2 Case 3 NPV @10%, % / Case 1
Base

80 85 90 95 100

Case 1 Case 2 Case 3 NPV @10%, % / Case 1
Base

0 1 2 3 4 5 6 7

Case 1 Case 2 Case 3 IRR, additional IRR points / Case 1

Base 0 1 2 3 4 5 6 7

Case 1 Case 2 Case 3 IRR, additional IRR points / Case 1

BaseAM-11-57 Page 17 Table 5 Study Results – Hydrogen Cost Sensitivity Study

Case Study Case 1 Case 2 Case 3

NPV @10% : Nat. Gas = 4.4 $/MMBTU ( 2010 Price ) Base Base x 0.94 Base x 0.94

NPV @10% : Nat. Gas = 8.9 $/MMBTU ( 2008 Price ) Base Base x 0.96 Base x 0.97

The economic study shows an IRR advantage for a moderate severity CFHT with 2-year cycle coupled with post-treatment over longer cycle (and cost) CFHT at the same severity and more severe CFHT without post treatment: Case 3 over Cases 2 & 1. Case 3 becomes more attractive when hydrogen cost increases as the gap in NPV between Case 1 and 3 decreases.

The issue of SOx and NOx control in FCC flue gas is not addressed in the above analysis. The high severity CFHT (Case 1) may enable directly me eting the 50 and 40 ppmv targets for SOx and NOx while a scrubber would be necessary to meet such constraints with Cases 2 and 3. The addition of the scrubber for Cases 2 and 3 decr eases the IRR differen tial between Case 1 an d the other cases by 1 point while conversely the NPV differential betw een Case 1 and Cases 2 and 3 is increased by approximately 1%.

It is important to note that in spite of a trend in favor of Case 3, the c onclusion drawn from this particular study is case specific an d cannot be generalized to other cases that may have different configurations and project premise.

Case 2 which represents the same scenario as Case 3 except for the CFHT cycle length which is in sync with the FCC and the post-treatment units (4 years cycle length), does not show any advantages compared to Case 3 in terms of NPV or IRR. One could have assumed that designing a CFHT in sync with the downstream units compar ed to limiting the CFHT cycle length to only 2 years would be an advantage. This is because the post-treatment unit brings the additional flexibility to continuously operate during a CF HT catalyst change-out. Despite hi gher feed sulfur (that could be partially limited with a change in crude diet during the CFHT catalyst change-out) the design of the post-treatment unit with the Prime-G+ tec hnology is robust enough to handle this higher severity requirement during the catalyst change-out.

This flexibility is clearly illustrated in Figure 15 which shows operating data on a Prime-G+ unit in a refinery processing heavy crude s and equipped with a FCC pre-trea tment. When the CFHT is in operation the normal feed sulfur to the Prime-G+ unit is t ypically below 200 wppm. Despite turnarounds or operation upsets on th e CFHT unit, which can lead to feed sulfur as high as 900 wppm, the product sulfur in the Prim e-G+ unit can be perfectly maintain ed to the target value of 20 wppm at all times.AM-11-57 Page 18 Figure 15 Prime-G+ Operation Flexibility

The flexibility brought by adding a post-treatmen t to the compulsory FCC pretreater when processing heavy crudes should be underlined and is a major advant age over the pre-treatment alone solution. In a 10-wppm gasoline pool sulfur, the refinery becomes a chemical plant with no margin for error and relying on the CFHT alone leaves little flexibility.

In summary, coupling a CFHT with a FCC Napht ha post-treatment unit brings the following advantages:

• Lowers the CFHT severity and opens the possibility to revamp an existing CFHT.

• Allows designing the CFHT unit for a cycle length of 2 years instead of 4 years.

• Simplifies the Prime-G+ post-treatment de sign to typically a single-stage unit.

• Improves the refinery reliability and flexibility:

• CFHT upset may be compensated by the Prime-G+ post-treatment unit.

• CFHT severity may be decreased if needed.

• FCCU operation is more flexible in terms of riser temperature, fractionation quality.

• FCC gasoline end-point may be increased when margins favor gasoline production while still controlling FCC naphtha sulfur through post-treatment. - 200 400 600 800 1,000 1,200

7/1/04 6/16/05 6/1/06 5/17/07 5/1/08 4/16/09Sulfur, ppm

0 10 20 30 40 50 60Prod. S, ppm

- 1

2 3 4 5 6

7/1/04 6/16/05 6/1/06 5/17/07 5/1/08 4/16/09Octane Loss

0 10 20 30 40 50 60Prod. S, ppm FRCN Processing – Prod S maintained at target value (20 ppm) despite FRCN quality variations due to FCC pretreat operation - 200 400 600 800 1,000 1,200

7/1/04 6/16/05 6/1/06 5/17/07 5/1/08 4/16/09Sulfur, ppm

0 10 20 30 40 50 60Prod. S, ppm

- 1

2 3 4 5 6

7/1/04 6/16/05 6/1/06 5/17/07 5/1/08 4/16/09Octane Loss

0 10 20 30 40 50 60Prod. S, ppm FRCN Processing – Prod S maintained at target value (20 ppm) despite FRCN quality variations due to FCC pretreat operationAM-11-57 Page 19 Conclusion

Most countries are moving towards limiting sulfur level in transportation fuels to 10 wppm. Meeting new ULSG regulations at 10 wppm while using existing FCC post-treatment assets can be achieved in numerous ways depending on the cons traints and requirements of each refiner while using commercially proven solutions. Low refinery margins coupled with capital constraints will likely make the revamping of existing FCC post- treatment units the preferred option for most refiners.

As light crudes production declines, refiners in the Americas will increasingly process heavier crudes resulting in hydrogen defici ent gasoil streams requi ring hydrotreating to maintain or improve the performance of the FCC Unit. Although every situation is site specific, th e combination of Pretreat and Post-treat solutions ar ound the FCC Unit will often provide the best combination in terms of flexibility and economical benefits to most No rth American refineries. As a licensor of CFHT, FCC and FCC post-treatment technologies, Axens is ideally positioned to ta ilor and offer the best solutions for each specific case.

References: 1. J. Bonnardot et al, Direct Production of Euro -IV Diesel at 10 pm Sulfur via the HyC-10 Process, ERTC 9 th Annual Meeting, Nov. 2004 2. P. Sarrazin et al, New mild hydrocracki ng route produces 10-ppm-sulfur diesel, Hydrocarbon Processing, Feb. 2005 3. R. Roux et al, Resid to Petrochemicals Technology, ERTC 13 th Annual Meeting, Nov. 2008 4. Q. Debuisschert, Prime-G+ Commercial Perf ormance of FCC Naphtha Desulfurization Technology, AM-03-26, NPRA An nual Meeting, March 2006 5. D. Largeteau et al, Benzene Management in a MSAT 2 Environment, AM-08-11, NPRA Annual Meeting, March 2008 6. Q. Debuisschert et al, Technol ogy Solutions addressing gasoli ne and diesel imbalances, Platts European Refining Market 4 th Annual Meeting, Sept. 2010