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 fax 
This 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 NPRA, 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 & Opportunities of 10 ppm Sulfur Gasoline 

Axens

Delphine Largeteau Jay Ross 

Marc Laborde Larry Wisdom 

 

Introduction 

The worldwide refining industry has undergone a major 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 crude 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 lower 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 traditionally gasoline-oriented to increasingly dieseloriented market. 

The gasoline and diesel pool regulatory specifications, which are constantly evolving, have been in 

the forefront of refiners’ challenges in the last ten years. In particular, the gasoline sulfur and 

benzene regulations have been main drivers for the recent remodeling of the refinery configuration. 

This transformation has been seen all around the world but particularly in Europe, Asia and North 

America. Other countries are following the trend and a common worldwide gasoline sulfur 

specification is on the horizon. Indeed the overall gasoline sulfur content is likely to level off at 10 

ppm across the globe. As a consequence most refiners will face renewed challenges to be able to 

meet the new Ultra Low Sulfur Gasoline (ULSG) specifications, however in view of other market 

forces there may also be new opportunities for refiners. 

This paper will identify these new opportunities by reviewing the processing options and 

consequences of such regulation focusing mainly on North American refineries. This review will 

draw upon the European experience to meet 10 ppm ULSG regulations through high severity FCC 

gasoline post-treating technology (such as Prime-G+TM) and examine the application of this 

experience to the North American market and revamp of existing selective FCC Naphtha 

desulfurization units. 

Another processing option adopted by many Asian refiners is severe FCC feed pre-treatment (Cat 

Feed Hydro Treating or CFHT) as a way to limit FCC emissions and avoid or minimize gasoline 

post-treatment. The paper will discuss the issues, challenges and opportunities 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 Hydrocracking (MHC) mode. 
AM-11-57 

Page 2 

Gasoline Sulfur Regulation 

There has been a steady downward trend in the sulfur content of fuels to reduce the emissions from 

cars and trucks. Many countries mandated the production of Low Sulfur Gasoline (LSG) some time 

ago, but in recent years regulations in Western Europe, some Asian countries and California in the 

USA have called for even tighter specifications to lower the gasoline sulfur to 10 ppm. 

The different regional approaches to gasoline sulfur 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 countries are following the same path to either meet their domestic 

regulatory specifications or be able to export and sell on the international 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 specifications well above 10 ppm, the 

overall trend clearly shows that in the near future ULSG production 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 2008
AM-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 early 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 feed (little cracked gasoil such as heavy coker gasoil) 

- Undercutting of FCC gasoline to maximize diesel production. 

The EU 10-ppm ULSG is produced mainly by using 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 FCC gasoline. Consequently, most 

refineries in Japan have met the new ULSG limit of 10 ppm by adding low severity post-treatment 

units. 

In the US, the refinery configuration was influenced by a large gasoline demand coupled with 

limited fuel-oil outlet resulting in the installation of bottom-of-the barrel conversion 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-treatment and FCC gasoline post-treatment units over a short 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 with gasoline sulfur 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 coupled with low refinery margins resulted in the 

wide application of FCC post-treatment to reduce gasoline sulfur. 

Another factor that also can influence 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 via consent decrees with the EPA resulting in much lower SOx and 

NOx emissions. The ‘preferred’ refinery configuration 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 2010
AM-11-57 

Page 4 

More recently there has been an important trend toward 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 (SynBit) after partial upgrading at the production site. These very 

heavy crudes are a challenge for processing in existing refinery assets due to a high acid content 

(TAN), high aromaticity and low hydrogen content along 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 highlight the challenges of processing Bitumen derived 

materials. 

Table 2 FCC Feed Quality from Heavy Feeds

As a result of these feedstock trends and renewed focus on cleaner fuels, lower emissions and even 

a shift in the gasoline / diesel production, the topic of pre-treatment 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 level 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 FCC feed. The reduction in sulfur and other contaminants is helpful 

in terms of reducing the FCC product sulfur level and lowering the flue 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 emphasis on the CFHT performance and reliability. 

Co-currently, the lower demand for fuel oil coupled with the processing of heavier crudes has 

resulted in the installation of residue conversion units such as delayed cokers. These conversion 

units produce significant amounts of hydrogen deficient, heteroatom rich (N and S) Vacuum 

Gasoils (VGO, HCGO) which need to be deeply hydrotreated prior to conversion 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 49 
AM-11-57 

Page 5 

As a result, modern CFHT units need to process increasingly more refractory feedstocks while 

achieving high desulfurization levels to meet gasoline sulfur specifications. 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 polynuclear aromatics (PNA) saturation, processing 

of cracked stocks in a CFHT, often with high end-point to maximize refinery economics, requires a 

careful selection of the catalytic system to take into account the potential for 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 opportunity to increase the severity of the CFHT 

not only to meet sulfur targets but also to change the refinery Diesel/Gasoline ratio by operating in the 

Mild Hydrocracking (MHC) mode and take advantage 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 internals, 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 (ULSD) specifications throughout the MHC cycle. 

Moderate pressure MHC units generally do not meet the required diesel specifications therefore 

post treatment is required. One attractive option to meet this challenge is the HyC-10TM technology 

developed by Axens to integrate the diesel upgrading within the MHC high pressure loop while 

decoupling operating conditions 1 2. Another important factor in MHC/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 feedstock type and the chemical reactions involved in a 

CFHT (kinetics, thermodynamics, contamination/poisoning) 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 will 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 refinery to achieve relatively low cost conversion of 

heavy crude components (VGO, HCGO and some atmospheric residue) into gasoline, butenes for 

high octane alkylate production, propylene and LCO diesel blend components. Although the 

chemistry and catalyst systems can be complex, 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 products 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 contaminants 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 below sharp gains in conversion and 

gasoline yield result from the first incremental increase in hydrogen and there is some degree of 

diminishing returns. When propylene yield is of interest the increased hydrogen input is always 

beneficial and in many cases high hydrogen input can be justified, particularly when hydrogen is 

relatively inexpensive 3

. 
AM-11-57 

Page 6 

As the severity of the CFHT increases 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 severity, hydrogen input, cracking, and FCC mode of 

operation within the existing constraints of a refinery configuration is therefore very complex. 

Figure 3 FCC Yield vs. Feed Hydrogen Content 

Within the context of ULSG, the more traditional role of the CFHT to consider is that of 

desulfurization and the impact on the FCCU gasoline produced. As the 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 sulfur found in the gasoline decreases. Figure 4 demonstrates this 

general trend for feeds that are hydrotreated and for non-hydrotreated 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

20

Wt%

Conversion

Gasoline

Fuel Oil

Propylene PotentialPropylene Potential
AM-11-57 

Page 7 

A short-hand means of describing the gasoline sulfur is as a ratio to the feed sulfur with virgin feed 

tending to a ratio of 10 and hydrotreated feed to about 20 (feed sulfur / gasoline sulfur). There are 

several important caveats to this simple rule: it relates to standard cut C5-430°F TBP cut point 

gasoline only, it depends on the conversion level in the FCC, it can depend on the severity/pressure 

level of the CFHT. There are commercial units with CFHT feed exhibiting 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 which can shift the sulfur 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 pool 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, C

Cumulative Sulfur, %

Thiophene

C1-Thiophene

BenzoThiophene

C2-Thiophene

Alkyl-BenzoThiophenes

Mercaptans

S

S

Figure 5 FCC Gasoline Sulfur Profile 

The above figure clearly demonstrates the importance of defining the gasoline boiling range when 

discussing the sulfur level. In the US market, gasoline 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-benzothiophenes in the gasoline. These 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 increased interest in distillate 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 both CFHT performance and precise fractionation 

of the gasoline product, meeting ULSG targets through CFHT alone is possible but challenging. 

There will be little room for error or deterioration 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 sulfur gasoline regulation, a majority of refiners in North America and 

across the world have already invested in a FCC post-treatment units. However, processing schemes 

vary greatly from one site to another depending on the sulfur specification, overall refinery 

configuration and crude diet as described earlier in this paper and 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 equipped 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 10 ppm gasoline sulfur target. 

 

The Prime-G+ process selectively desulfurizes the FCC Full Range Naphtha (FRCN) while 

ensuring minimal octane loss. It is by far the most widely used cracked gasoline desulfurization 

technology with over 190 Prime-G+ licensed units throughout the world 4. The technology has 

proven to be the most flexible process on the market 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+ 1st Step (SHU & Splitter) / 1-stage HDS Prime-G+ 2-stage HDS 

Figure 6 Prime-G+ Processing Schemes 

FCC 

FRN SHU HDT

 ULSG

FCC 

FRN

HDT

SHU ULSG

LN 

FCC 

FRN HDT 

1&2 SHU

ULSG
AM-11-57 

Page 9 

Figure 6 (Continued) 

Very High HDS 

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

Depending on the existing Prime-G+ configuration, meeting new ULSG regulations at 10 ppm 

while using the existing assets could be achieved in different ways. 

First, one potential solution which does not require any additional investment would be to simply 

increase severity (essentially reactor temperature) to lower the existing Prime-G+ product sulfur. 

The increased HDS level would lead to higher octane 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 rich 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 Naphtha or Visbroken Naphtha that can be handled in 

the Prime-G+ first step (Selective Hydrogenation Unit – SHU - and Splitter section). Light straight 

Run Naphtha, Natural Gasoline could also be co-processed either in the SHU upstream of the 

splitter or directly into the HDS section. One of the drawbacks 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 loss and cycle length. Lowering the feed sulfur could 

be achieved in different ways. The short term solutions would be to use sulfur reduction additives in 

the FCC or process low sulfur crudes. Both of these 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 FCC Naphtha end point or changes in the CFHT could be envisioned 

to reduce the sulfur in the FCC 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 desulfurization unit to meet tighter sulfur specifications 

that display different levels of complexity and associated cost: 

FCC 

FRN

HDT

1&2

SHU ULSG

LN 
AM-11-57 

Page 10 

1. Option 1: Install a Prime-G+ 1st step if not existing 

2. Option 2: Add a SHU (Selective Hydrogenation Unit) or HDS reactor if the cycle length 

is a limitation for the new product sulfur target 

3. Option 3: Route the Medium Cat. Naphtha (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+ 1st step. The SHU operating conditions and SHU catalyst design allow for the 

selective hydrogenation of the diolefins which may foul the desulfurization section and also the 

conversion of light sulfur species such as mercaptans to heavy boiling 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 rich in olefins and a Heavy FCC Naphtha (HCN) 

which is routed to the HDS section. Such HCN stream with its lower olefins content can be 

selectively desulfurized through the use of tailored catalysts to meet the ULSG target while controlling 

the olefins saturation and thus octane loss. The addition of the splitter reduces the throughput to the 

HDS section and hydrogen consumption. This solution 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 SHU upstream of an existing splitter will produce a sweet low-sulfur 

LCN stream and provide similar benefits as described in option 1. In case cycle length becomes 

limited, implementation of an additional HDS reactor in series with the existing one can be 

envisioned. 

Options 1 and 2 are easy to implement and lead to moderate capital 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

Pool

Splitter

Splitter

NHT Reformer

Isom

Prime-G+

Benfree

LCN

SRN

HCN

Coker N

HCN

FRCN

MCN

MoGas

Pool

Splitter

Splitter

NHT Reformer

Isom

Prime-G+

Benfree
AM-11-57 

Page 11 

This option involves revamping the existing splitter into a 3-cut column in order 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 the 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 reformer 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 the reformer could lead to issues in meeting the MSAT II gasoline 

benzene specifications. The addition of an integrated reformate splitter/benzene hydrogenation 

(BenfreeTM) solves this issue 5

. 

While this solution offers some advantages in terms 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 existing FCC post-treatment section. 

Decoupling of the MCN and HCN can also be utilized to treat those 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 has 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 section 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 explored in this paper is the inclusion of a second stage HDS section to 

minimize octane loss and maintain or even increase 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 Unit

Splitter

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 Unit

Splitter

SHU

MCN

HDS

HCN

HDS

Process

Integration

ULS HCN:

300°F-FBP
AM-11-57 

Page 12 

section, Axens has also the experience of designing a two-stage HDS section on full range FCC 

Naphtha with no upstream splitter. 

In a typical one-stage HDS configuration, the olefins 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 for two-stage operation and many are in operation. 

Although this option requires additional capital investment, there is a real incentive to pursue this 

solution when the refinery is octane-tight or hydrogen constrained. 

These several options provide commercially proven solutions for refiners to meet new ULSG 

specifications with existing or modified post-treatment 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 heavy crudes such as those derived 

from Canadian Oil Sands due to their lower cost coupled with geopolitical reasons. Processing of 

these heavy crudes requires a complete refinery reconfiguration with bottom of the barrel conversion 

units such as coking or ebullated bed hydrocracking. As described earlier, the resulting VGO and 

HCGO streams are very refractory with high levels of sulfur and 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 mandatory in those cases, one may wonder whether a 

post-treatment unit is required or not. 

In the next section, an economic comparison between the options with FCC Pretreatment only or in 

combination with post-treatment will help better illustrate the pros and cons for each solution. 

HCN

150°F+

H2 Make-up

Ultra-Low

Sulfur Gasoline 

to Mogas

H2S

FRCN

Prime-G+

Selective

Hydrogenation

Ultra Low S LCN to

Pool, TAME or Alky Unit

Splitter

SHU 2nd Stage

HDS

1st Stage

HDS

HCN

150°F+

H2 Make-up

Ultra-Low

Sulfur Gasoline 

to Mogas

H2S

FRCN

Prime-G+

Selective

Hydrogenation

Ultra Low S LCN to

Pool, TAME or Alky Unit

Splitter

SHU 2nd Stage

HDS

2nd Stage

HDS

1st Stage

HDS

1st Stage

HDS
AM-11-57 

Page 13 

Economic Evaluation: FCC Pre-treatment vs. FCC Pre-treatment & FCC Naphtha 

Post-treatment 

An economical study was conducted to determine the 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 BPD blend of straight run VGO and Heavy Coker Gas-Oil with 4.2 

wt% sulfur. Due to the refractiveness of this feed, it has to be hydrotreated in a high pressure unit 

prior to feeding the FCCU. The following three (3) cases were envisioned: 

 Case 1: A high HDS CFHT unit capable to produce a 10-wppm Gasoline pool sulfur 

without the need of a FCC 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 the 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 3

CFHT HDS

0

1

2

3

4

5

Cycle 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 cases with the various configurations along with 

the corresponding products considered for 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 duration of 10 years. In addition, a profitability index comparison 

in terms of Net Present Values (NPV) and Internal Rate of Return (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 CFHT (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 Table 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

C1 - C4

Gasoline

C1- C4

CFHT FCC

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

C1 - C4

Gasoline

C1- C4

CFHT FCC

Case 1

Case 2 & 3

Gasoline 

Case 2 & 3

Case 1
AM-11-57 

Page 15 

The H2 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 and Case 3. Case 2 provides a slight improvement 

in terms of yields with an almost constant H2 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 utility 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 the CAPEX for each case study to compare the 3 

options. 

The trend illustrated in Figure 12 clearly shows that 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, Case 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 Base
AM-11-57 

Page 16 

 Figure 13 NPV Results 

 Figure 14 IRR Results 

The NPV results favor Case 1 with a high HDS/long cycle length CFHT and no post-treatment over 

more moderate HDS CFHT cases coupled with a post-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 corresponding to the 2008 price, which 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

Base
AM-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 meeting 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 decreases the IRR differential between Case 1 and the other cases by 

1 point while conversely the NPV differential between 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 conclusion drawn from this 

particular study is case specific and 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 compared 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 CFHT catalyst change-out. Despite higher 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+ technology 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 crudes and equipped with a FCC pre-treatment. When the CFHT is in 

operation the normal feed sulfur to the Prime-G+ unit is typically below 200 wppm. Despite 

turnarounds or operation upsets on the CFHT unit, which can lead to feed sulfur as high as 900 

wppm, the product sulfur in the Prime-G+ unit can be perfectly maintained 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-treatment to the compulsory FCC pretreater when 

processing heavy crudes should be underlined and is a major advantage 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 Naphtha 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 design 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 4/16/09

Sulfur, ppm

0

10

20

30

40

50

60

Prod. S, ppm

-

1

2

3

4

5

6

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

Octane Loss

0

10

20

30

40

50

60

Prod. 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 4/16/09

Sulfur, ppm

0

10

20

30

40

50

60

Prod. S, ppm

-

1

2

3

4

5

6

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

Octane Loss

0

10

20

30

40

50

60

Prod. S, ppm

FRCN Processing – Prod S maintained at target value (20 ppm) despite FRCN quality variations 

due to FCC pretreat operation
AM-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 constraints 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 deficient gasoil streams requiring hydrotreating to maintain or improve 

the performance of the FCC Unit. Although every situation is site specific, the combination of Pretreat and Post-treat solutions around the FCC Unit will often provide the best combination in terms 

of flexibility and economical benefits to most North American refineries. As a licensor of CFHT, 

FCC and FCC post-treatment technologies, Axens is ideally positioned to tailor 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 9th Annual Meeting, Nov. 2004 

2. P. Sarrazin et al, New mild hydrocracking route produces 10-ppm-sulfur diesel, 

Hydrocarbon Processing, Feb. 2005

3. R. Roux et al, Resid to Petrochemicals Technology, ERTC 13th Annual Meeting, Nov. 2008

4. Q. Debuisschert, Prime-G+ Commercial Performance of FCC Naphtha Desulfurization 

Technology, AM-03-26, NPRA Annual 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, Technology Solutions addressing gasoline and diesel imbalances, 

Platts European Refining Market 4th Annual Meeting, Sept. 2010