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Chapter 4 Fuel Program Feasibility

4.1 Overview of Refining Operations 

Figure 4-1 shows a process flow diagram for a typical complex refinery, capable of 

making a wide product slate (shown on the right side of the figure) from crude oil (input on the 

left). Following the figure is a brief description of key units and streams focusing more on the 

gasoline producing units.1 It’s important to note that not all refineries have all of these units, 

which is a key factor in both the variation in their baseline sulfur levels as well as their cost of 

sulfur control.

Gasoline

Kerosine

Low Sulfur 

Diesel

Jet Fuel

Off-road

Resid

Distillate Hydrotreater

Vacuum Fluidized Cat Cracker

Tower

Hydrocracker

Reformer

Crude Tower

Naphtha 

Splitter

Straight Run

 Splitter

Gas 

Plant

Aromatics 

Extraction Hydrotreater

Isomerization

H2

H2

H2

H2

H2

Hydrogen Plant Fuel Gas

LPG

Crude 

Oil

Natural

Gas

Aromatics

Polymerization

Alkylation

 A B

Coke

Coker

 Diagram of a Typical Complex Refinery

Fuel Oil

Diesel

Figure 4-1 Process Flow Diagram for a Typical Complex Refinery

Crude Tower

The purpose of the crude tower is to perform a distillation separation of crude oil into 

different streams for additional processing in the refinery and for the production of specific 

products. Crude oil is shipped to the refinery via pipeline, ship, barge, rail, or truck, whereupon 

it is sampled, tested, and approved for processing. The crude oil is heated to between 650 °F and 

700 °F and fed to crude distillation tower. Crude components vaporize and flow upward through 

the tower. Draw trays are installed at specific locations up the tower from which desired side 

cuts or fractions are withdrawn. The first side-cut above the flash zone is usually atmospheric 

gasoil (AGO), then diesel and kerosene/jet fuel are the next side-cuts, in that order. The lightest 
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components, referred to here as straight run naphtha, remain in the vapor phase until they exit the 

tower overhead, following which they are condensed and cooled and sent to the naphtha splitter. 

Naphtha Splitter

The purpose of the naphtha splitter is to perform a distillation separation of straight run 

naphtha into light straight run naphtha and heavy straight run naphtha. The feed can be split 

between the C5’s and C6’s in order to assure the C6’s and heavier are fed to the reformer. 

Naphtha Hydrotreater

The purpose of the naphtha hydrotreater is to reduce the sulfur of light and heavy straight 

run streams before those streams are refined further by the isomerization and reformer units.

Isomerization Unit

The purpose for the isomerization unit is to convert the light naphtha from straight chain 

hydrocarbons to branched chain hydrocarbons, increasing the octane of this stream. The 

isomerate is sent to gasoline blending. 

Reformer

The purpose of the reformer unit is to convert heavy straight run (C6 to C8 or C9 

hydrocarbons) into aromatic and other higher octane compounds (benzene is one of the aromatic 

compounds produced), typically necessary to produce gasoline with sufficient octane. To protect 

the very expensive, precious metal catalyst used in reformers, heavy straight run naphtha must be

hydrotreated first before it is fed to the reformer. As the reformer converts the feed 

hydrocarbons to aromatics, hydrogen and light gases are produced as byproducts. The liquid 

product, known as reformate, is sent directly to gasoline blending, or to aromatics extraction. 

Aromatics Extraction Unit

The purpose of aromatics extraction is to separate the aromatic compounds from the rest 

of the hydrocarbons in reformate using chemical extraction with a solvent to concentrate the 

individual aromatic compounds, (mainly xylene and benzene) for sale to the chemicals market. 

Vacuum Tower

The purpose of the vacuum distillation tower unit is to enable a refinery to produce more 

gasoline and diesel fuel out of a barrel of crude oil. It separates the vacuum gasoil (VGO), which 

is fed to the FCC unit, from the vacuum tower bottoms (VTB) which is sent to the coker, or in 

other refineries is made into asphalt. Because most sulfur contained in crude oil is contained in 

the heaviest part of crude oil, the VGO and VTB are very high in sulfur.

Fluidized Catalytic Cracker

The purpose of the fluidized catalytic cracker is to convert heavy hydrocarbons, which 

have very low value, to higher value lighter hydrocarbons. AGO and VGO are the usual feeds to 
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a fluid catalytic cracker (FCC). The full boiling range cracked product leaves the reactor and is 

sent to a fractionator. The overhead includes propane, propylene, butane, butylene, fuel gas and 

FCC naphtha, which contains a significant amount of sulfur. There are two heavy streams; light 

cycle oil (LCO), which can be hydrotreated and blended into diesel fuel or hydrocracked into 

gasoline; and heavy cycle oil, sometimes called slurry oil, which can be used for refinery fuel. 

Very simple refineries do not have FCC units, and therefore, their gasoline is very low in sulfur.

FCC Feed Hydrotreater or Mild Hydrocracker “A”

FCC feed hydrotreaters and mild hydrocrackers hydrotreat or mildly hydrocrack the feed 

to the FCC unit which provides two distinct benefits. First, by increasing the amount of 

hydrogen in the feed to the FCC unit, the FCC unit increases the conversion of the feed to high 

value light products, particularly FCC naphtha which increases the gasoline yield. Second, 

hydrotreating the feed removes some contaminants in the feed such as nitrogen and sulfur. 

Nitrogen in the feed negatively affects the FCC catalyst. Removing the sulfur in the feed helps 

in two ways. Some of the sulfur in the feed is released by the cracking process and results in 

high SOX emissions that would otherwise have to be controlled by scrubbers – the FCC feed 

hydrotreaters may prevent the need to add a scrubber. Also, FCC feed hydrotreaters remove 

sulfur which can allow a refinery to comply with gasoline sulfur standards. 

FCC Postreat Hydtrotreater “B”

Postreat hydrotreaters solely hydrotreat the naphtha that is produced by the FCC unit to 

reduce its sulfur level which enables compliance with gasoline sulfur standards. The FCC 

naphtha is high in olefins which can be saturated by postreat hydrotreaters resulting in lower 

octane of the FCC naphtha. Vendor companies have developed postreat hydrotreating 

technologies which minimize this octane loss. 

Distillate Hydrotreater

The purpose of the distillate hydrotreater is to reduce the sulfur of distillate, which is also 

called diesel fuel.

Gas Plant

The purpose of the gas plant is to use a series of distillation towers to separate various 

light hydrocarbons for further processing in the alkylation or polymerization units or for sale. 

Alkylation Unit

The purpose of the alkylation unit is to chemically react light hydrocarbons together to 

produce a high quality, heavy gasoline product. Alkylation uses sulfuric or hydrofluoric acid as 

catalysts to react butylene or propylene together with isobutane. Following the main reaction 

and product separation, the finished alkylate is sent to gasoline blending. Alkylate is low in 

RVP. 

Polymerization Unit
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The purpose of the polymerization unit is to react light hydrocarbons together to form a 

gasoline blendstock. A polymerization unit, often referred to as a “cat poly” is somewhat similar 

to an alkylation unit, in that both use light olefins to produce gasoline blendstocks. The feed is 

generally propylene and/or butylene from the gas plant. The product, called polygas is sent to 

gasoline blending.

Coker Unit

The purpose of the coker unit is to process vacuum tower bottoms (VTB) to coke and to 

crack a portion to various lighter hydrocarbons. The hydrocarbons produced by the coker 

include cracked gases, coker naphtha, coker distillate and gas oil. The gas is fed to the gas plant, 

the naphtha to the naphtha hydrotreater after which the heavy coker naphtha is typically fed to 

the reformer, and the distillate either to distillate hydrotreating or to the hydrocracker. 

Hydrocracker

The purpose of the hydrocracker is to crack and “upgrade” the feedstock into higher 

value products. The feedstock to the hydrocracker is usually light cycle oil (LCO) and coker 

distillate, poor quality distillate blendstocks, which are upgraded to diesel fuel, or cracked to 

gasoline. Heavier hydrocarbons such as AGO and HVGO can be feedstocks as well. 

A more complete description for naphtha hydrotreating is contained in Section 4.2.

4.2 Feasibility of Removing Sulfur from Gasoline

The case can be made in two ways that it is feasible to comply with the proposed 10-ppm 

gasoline sulfur standard. First, feasibility can be demonstrated by understanding the 

technologies currently available which can achieve the necessary reductions in sulfur, and that 

these technologies are currently being used to achieve significant reductions in gasoline sulfur. 

The second way to make the case that it is feasible to comply with the proposed 10-ppm gasoline 

sulfur standard is to highlight that refiners in certain countries or other regions are currently 

complying with a 10-ppm gasoline sulfur cap standard. These two cases will be made below, but 

first we will review the source of sulfur in gasoline to understand how sulfur levels can be 

further reduced.

4.2.1 Source of Gasoline Sulfur

Sulfur is in gasoline because it naturally occurs in crude oil. Crude oil contains anywhere 

from fractions of a percent of sulfur, such as less than 500 ppm (0.05 weight percent) to as much 

as 30,000 ppm (3 percent). The average amount of sulfur in crude oil refined in the U.S. is about 

14,000 ppm. Most of the sulfur in crude oil is in the heaviest part, or in the heaviest petroleum 

compounds, of the crude oil (outside of the gasoline boiling range). In the process of refining 

crude oil into finished products, such as gasoline, some of the heavy compounds are broken up, 

or cracked, into smaller compounds and the embedded sulfur can end up in gasoline. Thus, the 

refinery units which convert the heavy parts of crude oil into gasoline are the units most 

responsible for putting sulfur into gasoline. 
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The fluidized catalytic cracker (FCC) unit is a refinery processing unit that creates a high 

sulfur content gasoline blendstock. FCC naphtha contains from hundreds to several thousand 

parts per million of sulfur. The FCC unit cracks large carbon molecules into smaller ones and 

produces anywhere from 25 to 50 percent of the gasoline in those refineries with FCC units. 

Because the FCC unit makes a gasoline blendstock out of the heavier, higher sulfur-containing 

compounds, more than 95 percent of sulfur in gasoline blendstocks comes from streams 

produced in that unit. When complying with the 30-ppm Tier 2 gasoline sulfur standard, refiners 

reduced the sulfur content of the FCC naphtha. The impact of this action is described below in 

subsection 4.2.2. 

Straight run naphtha is a gasoline blendstock which contains a moderate amount of 

sulfur. Straight run naphtha is the part of crude oil which after distillation in the atmospheric 

crude oil tower falls in the gasoline boiling range. The heaviest portion of straight run, which 

would have more sulfur, is normally desulfurized and reformed in the reformer (to improve its 

octane), so its contribution to the gasoline pool is virtually nil.A The light straight run which 

contains the five-carbon hydrocarbons contains on the order of 100 ppm sulfur and if this 

material is not hydrotreated and processed in an isomerizaition unit, it is blended directly into 

gasoline. 

Another refinery unit which produces naphtha with a significant amount of sulfur is the 

coker unit. These units produce coke from the heaviest part of the crude oil. In the process of 

producing coke, a naphtha is produced that contains more than 3,000 ppm sulfur and many very 

unstable olefins. Because this stream is highly olefinic and unstable, refiners tend to hydrotreat 

coker naphtha. Coker naphtha is normally split into two different streams. The six- to ninecarbon hydrocarbons are hydrotreated along with the rest of the heavy naphtha and fed to the 

reformer. The five-carbon hydrocarbon part of coker naphtha is called light coker naphtha and 

usually contains on the order of several hundred parts per million sulfur. Light coker naphtha is 

usually hydrotreated along with the light straight run, and refined further in an isomerization unit 

if the refinery has one.

Other gasoline blendstocks contain little or no sulfur. Alkylate, which is produced from 

isobutene and butylenes that contain a small amount of sulfur, can end up with a small amount of 

sulfur. Most refineries have less than 15 ppm sulfur in this pool, however, some refineries which 

feed coker naphtha to the alkylate plant can have much more. On average, alkylate probably has 

about 10 ppm sulfur. One more gasoline blendstock with either very low or no sulfur is 

hydrocrackate, which is the naphtha produced by hydrocrackers. It is low in sulfur because the 

hydrocracking process removes the sulfur. Ethanol which is eventually blended into gasoline 

usually has very little or no sulfur. However, the hydrocarbon used as a denaturant and blended 

with ethanol at 2 percent is usually natural gasoline, a C5 to C7 naphtha from natural gas 

processing, and it contains anywhere from a few parts per million to a couple hundred parts per 

million sulfur. After the denaturant is blended in, the denatured ethanol contains somewhere 

 

A

 Sulfur interferes in the function of the precious metal catalyst used in the reforming process. As a result, refiners 

historically have desulfurized the heavy straight run naphtha feed to the reformer from several hundred ppm sulfur 

down to less than 1 ppm.
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between 0 and 10 ppm sulfur. To meet current pipeline and California specifications, denatured 

ethanol must be less than 10 ppm sulfur.

4.2.2 Complying with the Current Tier 2 Gasoline Sulfur Standard

It is important to understand the steps that refiners took to comply with the 30-ppm Tier 2 

gasoline sulfur standard because those capital investments and operational changes will play a 

major role in determining the steps that refiners take to comply with a more stringent gasoline 

sulfur standard. 

The Tier 2 sulfur standard was promulgated February 10, 2000.2 The sulfur standard 

requires that refiners reduce their annual average gasoline sulfur levels down to 30 ppm and each 

gallon of gasoline cannot exceed a per-gallon standard of 80 ppm. The sulfur standards were

phased in from 2004 to 2006. The only exceptions were western refiners (GPA) and small

refiners who were given until 2008. Some small refiners had their gasoline sulfur deadlines 

extended through 2010 in the highway diesel fuel sulfur rule in exchange for on-time compliance 

there. As of January 1, 2011, all refineries are complying with the Tier 2 30-ppm sulfur 

standard. 

A refinery’s previous average gasoline sulfur level is an important factor which 

determined whether a refiner would need to make a substantial capital investment to meet the 

Tier 2 gasoline sulfur standards. We believe that those refiners with low gasoline sulfur levels to 

begin with (i.e., gasoline sulfur levels lower than, perhaps, 50 ppm) probably did not invest in 

expensive capital. These refineries have very low sulfur levels due to one or more of a number 

of possible reasons. For example, some of these refiners may not have certain refining units, 

such as a fluidized catalytic cracker (FCC) unit, or a coker, which convert heavy boiling stocks 

to gasoline. As stated above, these units push more sulfur into gasoline and their absence means 

much less sulfur in gasoline. Alternatively, refiners may use a very low sulfur (sweet) crude oil 

which can result in a low sulfur gasoline. Or, these refiners may have already installed an FCC 

feed hydrotreater to improve the operations of their refinery which uses a heavier, higher sulfur 

(more sour) crude oil. As described above, this unit removes much of the sulfur from the 

heaviest portion of the heavy gas oil before it is converted into gasoline. 

Of the refiners in this first category, the refineries with average sulfur levels below 30 

ppm may not have had to do anything to meet the Tier 2 standards. On the other hand, those 

refineries which had sulfur levels above 30 ppm but below some level, such as 50 ppm, probably 

are meeting the 30-ppm sulfur standard by employing operational changes only and avoided

making capital investments. Most of the refineries with gasoline sulfur levels below 50 ppm 

prior to the Tier 2 investments either do not have a FCC unit, or if they do, they probably have an 

FCC feed hydrotreating unit. 

The vast majority of gasoline which was being produced was by refineries with higher 

sulfur levels, and these refiners had to either adapt some existing hydrotreating capital or install 

new capital equipment in these refineries to meet the Tier 2 gasoline sulfur standards. As stated 

above, the FCC unit is responsible for most of the sulfur in gasoline. Thus, investments for 

desulfurizing gasoline involved the FCC unit to maximize the sulfur reduction, and to minimize 

the cost. This desulfurization capital investment can be installed to treat the gas oil feed to the 
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FCC unit, or treat the gasoline blendstock which is produced by the FCC unit. Each method has 

advantages and disadvantages.

4.2.2.1 Using FCC Feed Pretreat Hydrotreating to Comply with Tier 2

Some refiners installed FCC feed hydrotreaters (also known as pretreaters) at their 

refineries to comply with the Tier 2 gasoline sulfur standards. FCC pretreaters treat the vacuum

gas oil, heavy coker gas oil and, in some cases, atmospheric residual feed to the FCC unit using a 

hydrotreater or a mild hydrocracker. These units are designed to operate at high pressures and 

temperatures to treat a number of contaminants in the feed. Besides sulfur, FCC pretreaters also 

reduce nitrogen and certain metals such as vanadium and nickel. These nonsulfur contaminants 

adversely affect the FCC catalyst, so the addition of this unit would improve the functioning of 

the unit. Also, the hydrotreating which occurs in the FCC pretreater reacts hydrogen in the 

feedstock which increases the yield of the FCC unit by increasing the highest profit-making 

products produced by refineries, such as gasoline and light olefins.

3

 While FCC pretreaters 

provide yield benefits that offset the capital costs of adding this type of desulfurization, the costs 

are still high enough that many refiners would have a hard time justifying the installation of this 

sort of unit. For a medium to large refinery (i.e., 150,000-200,000 BPCD), the capital costs may

exceed $250 million. Because of the higher temperatures and pressures involved, utility costs 

are expensive relative to postreat hydrotreating as explained below. Another justification for this 

approach is that it allows refiners to switch to a heavier, more sour crude oil. These crude oils 

are less expensive per-barrel and can offset the increased utility cost of the FCC pretreater, 

providing that the combination of reduced crude oil costs and higher product revenues justify the 

switch. Another benefit for using FCC pretreaters is that the portion of the distillate pool which 

comes from the FCC unit would be partially hydrotreated as well. This distillate blendstock, 

termed light cycle oil, comprises a relatively small portion of the total distillate produced in the 

refinery (about 20 percent of on-road diesel comes from light cycle oil), and like FCC naphtha, 

light cycle oil contributes a larger portion of the total sulfur which ends up in distillate. Thus, 

FCC pretreaters would also help a refiner meet the 15-ppm highway and nonroad diesel fuel 

standards.

In terms of desulfurization capability, FCC preateaters have different abilities to remove 

sulfur from the gas oil feed depending on the unit pressure. FCC pretreaters can be subdivided

into high pressure units (1400 psi and above), medium pressure units (900 to 1400 psi), and low 

pressure units (under 900 psi). High pressure FCC pretreaters are capable of removing about 90 

percent of the sulfur contained in the gas oil feedstock to the FCC unit, while low and medium 

pressure units are capable of removing 65 to 80 percent of the feed sulfur.4 Because there is no 

postreating at many of the refineries with FCC pretreaters, control of the feed to these units is a 

critical determining factor for how well the FCC pretreater will function as desulfurizers. If the 

feed becomes too heavy, the concentration of contaminants increases and the catalyst may lose 

its effectiveness.5

FCC pretreaters improve desulfurization indirectly by improving the desulfurization 

performance of the FCC unit itself. When FCC units crack the vacuum gas oil into naphtha, 

about 90 percent of the sulfur is typically cracked out of the hydrocarbons converted to FCC 

naphtha (or the FCC naphtha contains only about 10 percent of the sulfur present in the feed) and 

is removed as hydrogen sulfide. When FCC units are preceded by FCC pretreaters, the amount 
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of sulfur in the feed which ends up in the FCC naphtha is only about 5 percent, which means that 

about 95 percent of the sulfur in the feed is removed from the FCC feed when it is cracked into 

FCC naphtha. This effect is caused by the additional hydrogen which reacts with the feed 

hydrocarbons. With more hydrogen molecules available in the feedstock after hydrotreatment, 

the FCC cracking reactions can react more hydrogen with the sulfur contained in the feed to 

produce more hydrogen sulfide. 

For complying with Tier 2, refiners which already had or which installed high pressure 

FCC pretreaters were able to comply with the 30-ppm sulfur standard without the need to install 

a FCC naphtha hydrotreater. However, if a refinery had a low pressure, or perhaps even a 

medium pressure FCC feed hydrotreater, they were generally less able to comply with the 30-

ppm gasoline sulfur standard with the FCC hydrotreater by itself, and these refineries were more 

likely to also install an FCC postreater.

4.2.2.2 Using FCC Naphtha Postreat Hydrotreating to Comply with Tier 2

A less capital intensive alternative for reducing FCC naphtha sulfur levels to comply with 

Tier 2 is FCC naphtha hydrotreating (also known as postreaters). FCC postreaters only treat the 

gasoline blendstock produced by the FCC unit. Understandably, this unit is much smaller 

because only about 50 to 60 percent of the feed to the FCC unit ends up as FCC naphtha, a 

gasoline blendstock. The unit is sometimes smaller than that as some refiners which choose to 

use a fixed bed hydrotreater may only treat the heavier, higher sulfur portion of that stream with 

hydrotreating, and then treat the lighter fraction with another lower desulfurization cost 

technology. FCC postreaters operate at lower temperatures and pressures than FCC pretreaters,

which further reduces the capital and operating costs associated with this type of desulfurization 

equipment. Furthermore, the feed to the FCC unit has corrosive properties which require that 

FCC pretreaters use more corrosion-expensive metallurgy, which is not needed for postreaters.6 

For a medium to large-sized refinery, the capital costs are on the order of $70 million for a 

conventional FCC pretreaters – less than half that of an FCC pretreater. 

One drawback of this desulfurization methodology is that the octane value and/or some 

of the gasoline yield may be lost depending on the process used for desulfurization. Octane loss 

occurs by the saturation of high octane olefins which are produced by the FCC unit. Most of the 

olefins are contained in the lighter fraction of FCC naphtha.7 Increased olefin saturation usually

means higher hydrogen consumption. There can also be a loss in the gasoline yield caused by

mild cracking which breaks some of the gasoline components into smaller fractions which are 

too light for blending into gasoline. If there is octane loss, two of the ways that the octane loss 

can be made up is by blending in more ethanol, or by increasing the feed to or the severity of the 

reformer, the aromatics production unit of the refinery. Sometimes vendors of FCC pretreater 

technologies design octane increasing capability into their designs, which is discussed below in 

the section about the individual postreater technologies.

The loss of octane and gasoline yield caused by FCC postreating is lower with 

technologies which were developed prior to the implementation of the Tier 2 program.

8

 These 

processes are termed selective because they achieve the lower sulfur while preserving much of 

the octane and gasoline yield (they were designed specifically for treating FCC naphtha). Octane 

is preserved because the hydrotreating units and their catalysts are specially designed to avoid 
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saturating olefins. These selective processes, or parts of these processes, usually operate at less 

severe conditions which result in less cracking preserving yield compared to conventional 

hydrotreating processes. The less severe conditions also lower the capital and operating costs for 

this process. The lower operating costs arise out of the reduced utility requirements (e.g., lower 

pressure). For example, because these processes are less severe, there is less saturation of 

olefins, which means that there is less hydrogen used. Less olefin saturation also translates into 

less octane loss which would otherwise have to be made up by octane boosting processing units 

in the refinery. The lower capital and operating costs of these newer FCC postreaters are 

important incentives for refiners to choose this desulfurization methodology over FCC 

pretreaters. For this reason, refiners chose to use the more recently developed FCC postreaters 

technologies for meeting the 30-ppm Tier 2 gasoline sulfur standard. 

Not saturating the olefins to preserve octane and limit hydrogen consumption provides a 

different challenge. When the hydrogen sulfide is formed and there is a significant concentration 

of olefins present, the hydrogen sulfide compounds tend to react with the olefinic hydrocarbon 

compounds forming mercaptan sulfur compounds. This reaction is called “recombination” 

because the removed sulfur recombines with the olefinic hydrocarbons contained in the naphtha.9

This is particularly a problem if the light cat naphtha is present in the hydrotreater because the 

highest concentration of olefins is in the light cat naphtha. The recombination reactions occur 

more readily if the hydrotreater is operated more severely (at a higher temperature) to increase 

the sulfur removal, and the feed to the hydrotreater is high in sulfur. However, while operating 

this type of hydrotreater more severely can result in the further removal of the original sulfur 

present in the hydrocarbons, it also can result in the formation of more recombination 

mercaptans that results in a “floor” reached for the amount of sulfur that can be removed from 

the hydrocarbons. This cycle of increased sulfur removal and simultaneous increase in 

recombination results in the saturation of more olefins and increases the consumption of 

hydrogen. There are a number of different vendor-specific technologies that each vendor may

use to avoid or address recombination reactions as discussed below. It is important to note that 

the technologies employed to reduce recombination may require the addition of some capital 

costs which offsets some or perhaps all the capital cost savings due to the milder operating 

conditions of these selective hydrotreater technologies compared to nonselective hydrotreating. 

One means to achieve high levels of desulfurization while avoiding much of the problem 

with recombination reactions is by using a two-stage hydrodesulfurization methodology. A twostage unit has two desulfurization reactors, but instead of just adding additional reactor volume, 

the hydrocarbons exiting the first reactor are stripped of gaseous compounds (most importantly, 

the hydrogen sulfide is removed), injected with fresh hydrogen, and then hydrodesulfurized 

again in the second stage. Both reactors undergo modest desulfurization and hydrogen sulfide 

concentrations remain sufficiently low to avoid recombination reactions. The downside of this 

approach is that the second stage incurs greater capital costs compared to single-stage 

configurations. Because Tier 2 was not too constraining, we believe that refiners installed few, if 

any, two-stage desulfurization units to comply with those gasoline sulfur standards. 

Whatever strategy chosen by the refiner to comply with Tier 2, a critical criterion is that 

the postreater be capable of cycle lengths that match that of the FCC unit, which typically is 5 

years. If the postreater were to require a catalyst changeout before the FCC unit requires a 

shutdown, either the refiner would have to shutdown the FCC unit early to mirror that of the 
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postreater, or need to store up the high sulfur FCC naphtha (this stream would be too high in 

sulfur to blend directly to gasoline under the Tier 2 80-ppm cap standard) until the postreater was 

started up again and is able to hydrotreat the stored up high sulfur FCC naphtha.

We know of six FCC postreater technologies that refiners used to comply with the Tier 2 

gasoline sulfur standards. These are Axens (was IFP) Prime G and Prime G+, Exxon Scanfining, 

CDTech’s CDHydro and HDS, Sinopec’s (was Phillips)S-Zorb and UOP’s ISAL and 

Selectfining. 

Of the list of FCC postreaters , Axens Prime G+, Exxon Scanfining and UOP’s ISAL and 

Selectfining are fixed bed desulfurization technologies. These processes are called fixed bed 

because the catalyst resides in a fixed bed reactor.10 The high sulfur gasoline blendstock is 

heated to a high temperature (on the order of 600 degrees Fahrenheit) and pumped to a high 

pressure to maintain the stream as a liquid. It is then combined with hydrogen before it enters 

the reactor. The reactions occur within the bed of the catalyst. While the petroleum is in contact 

with the catalyst in the reaction vessel, the sulfur reacts with hydrogen and is converted to 

hydrogen sulfide. Also, depending on the process, some of the olefin compounds which are 

present in the cracked stream are saturated which increases the amount of octane lost and 

hydrogen consumed. After the reactor, the gaseous compounds, which include unreacted

hydrogen, hydrogen sulfide, and any light end petroleum compounds which may have been 

produced in the reactor by cracking reactions, are separated from the liquid compounds by a 

gas/liquid separator. The hydrogen sulfide must be stripped out from the other compounds and 

then converted to elemental sulfur in a separate sulfur recovery unit. The recovered sulfur is 

then sold. If enough hydrogen is present, and it is economical to recover, it is separated from the 

remaining hydrocarbon stream and recycled. Otherwise, it is burned with light hydrocarbons as 

fuel gas. 

Despite the similarities, each of these desulfurization technologies has its differences. 

Axens Prime G+ desulfurization process largely preserves olefins as its strategy for diminishing 

octane loss.11,12 13 The Axens process employs a selective hydrogenation unit (SHU) as a first 

step. The role of this unit is to saturate the unstable diolefin hydrocarbons in a hydrogen rich 

environment, and react the light mercaptan and sulfide hydrocarbons together. The SRU also 

converts exterior olefins to interior olefins which results in a small increase in octane. The mild 

operating conditions of the SHU tend to avoid the saturation of monoolefins. After exiting the 

SRU, the FCC naphtha is sent to a distillation column which separates the light FCC naphtha 

(typically comprising about one fourth of the total cat naphtha) from the heavy naphtha. Because 

the light sulfur compounds were reacted together and those compounds no longer fall within the 

light cat naphtha boiling range, the light cat naphtha is low in sulfur and can be blended directly

into gasoline. The heavy cat naphtha which is naturally high in sulfur and which also contains 

the self-reacted light mercaptans and sulfides from the SHU, is sent to a fixed bed hydrotreater. 

The fixed bed hydrotreater contains both cobalt-molybdenum and nickel-molybdenum catalyst. 

An important way that Axens avoids recombination reactions is by separating the light sulfur 

compounds from the light naphtha and keeping the light naphtha out of the fixed bed 

hydrotreater. The desulfurized heavy cat naphtha is blended into the gasoline pool. 

If the feed to the Axens Prime G unit is very low in sulfur, a low capital investment 

option was available to the refiner by feeding the entire FCC naphtha stream to the hydrotreating 
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reactor avoiding the SHU and splitter. This option trades lower capital cost with somewhat 

higher octane loss and hydrogen consumption. Because of the low severity of the hydrotreating 

reactor (low severity is possible because the lower amount of desulfurization that is occurring), 

the amount of octane loss and hydrogen consumption is modest. There are more than 180 Prime 

G+ units operating worldwide.

The first step in Exxon’s fixed bed Scanfining process is to mildly heat the full FCC 

naphtha and pass it through a small reaction vessel which reacts the diolefins to monoolefins.14 15

16 17 18 19

 The full FCC naphtha is then heated further, injected with hydrogen gas and sent to the 

fixed bed hydrotreating reactor which is packed with a catalyst developed jointly between Exxon 

and Akzo Nobel (now Albermele). If the degree of desulfurization is relatively modest, the 

amount of recombination is low and the FCC naphtha is sent to gasoline blending. If, however, 

the degree of desulfurization is higher (due to FCC naphtha with a higher sulfur content), then 

there likely would be an excessive number of recombination reactions. In this case, Exxon 

recommends either one of two different technologies to address the recombination reactions. 

One technology is Zeromer. Zeromer is a fixed bed reactor vessel installed after the main fixed 

bed hydrotreater reactor that specifically designed to hydrodesulfurize the mercaptan sulfur from 

the FCC naphtha without saturating olefins.20 Another technology Exxon developed, in 

conjunction with Merichem, is an extractive mercaptan removal technology named Exomer. The 

Exomer technology differs from other sulfur extraction technologies in that it is capable of 

extracting mercaptans from the entire FCC naphtha pool.21 Like Zeromer, the Exomer 

technology would be an add-on technology installed after the Scanfining fixed bed reactor. 

There are 16 Scanfining units operating in the U.S. 

UOP has licensed two FCC naphtha hydrotreating technologies. When Tier 2 was being 

phased-in, UOP was licensing a technology named ISAL developed by INTEVEP S.A.22 23 The 

ISAL process is different than the other FCC naphtha hydrotreaters because instead of avoiding 

the saturation of olefins as sulfur is being hydrotreated out of FCC naphtha, the ISAL process 

completely saturates the olefins. To avoid a large octane loss, the ISAL process separates the 

olefin-rich, light cat naphtha from the heavy cat naphtha. The light cat naphtha is treated by an 

extractive desulfurization technology such as Merox which does not saturate olefins. Only the 

heavy cat naphtha is sent to the ISAL reactor. To offset the octane loss caused by the saturation 

of the olefins in the heavy cat naphtha as it is being desulfurized, the ISAL catalyst isomerizes 

and conducts some mild cracking and reforming of the heavy cat naphtha. One downside of the 

ISAL process is that, due to the complete saturation of olefins, the hydrogen consumption is 

higher relative to the selective hydrodesulfurization technologies that avoid saturating olefins.

UOP has since developed and licenses its own FCC naphtha desulfurization technology

named SelectFining.24 SelectFining is a selective hydrodesulfurization technology that seeks to 

minimize olefin saturation to minimize both octane loss and hydrogen consumption. 

SelectFining treats the full FCC naphtha. The full range FCC naphtha is first sent to a diolefin 

saturating reactor before being sent to the SelectFining reactor. SelectFining relies on its catalyst 

design to selectively remove sulfur and prevent recombination reactions. UOP recommends a 

two-stage reactor setup for high levels of desulfurization. 
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The next two FCC naphtha desulfurization technologies, CDTech and S-Zorb do not use 

fixed bed reactors, but very different technologies which are also very different from each other. 

Each will be discussed separately.

Although the CDTech process is significantly different from the fixed bed hydrotreating 

technologies, it still uses the same type of catalyst. The CDTech process utilizes catalytic 

distillation.25,26,27 Catalytic distillation is a technology which has been applied for a number of 

different purposes. CDTech is currently licensing the technology to produce MTBE and 

selective hydrogenation processes, including FCC naphtha desulfurization and benzene 

saturation. As the name implies, distillation and desulfurization, via catalyst, take place in the 

same vessel. This design feature saves the need to add a separate distillation column sometimes 

used with fixed bed hydrotreating. All refineries have a distillation column after the FCC unit 

(called the main fractionation column) which separates the FCC naphtha from the most volatile 

components (such as liquid petroleum gases), the distillate or diesel (light cycle oil), and the 

heavy ends or residual oil. However, if a refiner only wishes to treat a portion of the FCC 

naphtha, then a second distillation column would need to be added after the main FCC 

fractionation column to separate off the portion of the FCC naphtha which he wishes not to treat. 

With the CDTech process, the refiner can choose to treat the entire pool or a portion of the pool, 

but choosing to treat a part of the pool can be an option in how the CDTech hardware is applied, 

thus negating any need for an additional distillation column.

The most important portion of the CDTech desulfurization process is a set of two 

distillation columns loaded with desulfurization catalyst in a packed structure. The first vessel, 

called CDHydro, treats the lighter compounds of FCC gasoline and separates the heavier portion 

of the FCC naphtha for treatment in the second column. The second column, called CDHDS, 

removes the sulfur from the heavier compounds of FCC naphtha. All of the FCC naphtha is fed 

to the CDHydro column. The five- and six-carbon petroleum compounds boil off and head up 

through the catalyst mounted in the column, along with hydrogen which is also injected in the 

bottom of the column. The reactions in this column are unique in that the sulfur in the column is 

not hydrotreated to hydrogen sulfide, but they instead are reacted with dienes in the feed to form 

thioethers. Their higher boiling temperature causes the thioethers to fall to the bottom of the 

column. They join the heavier petroleum compounds at the bottom of the column and are sent to 

the CDHDS column. Because the pressure and temperature of the first column is much lower 

than conventional hydrotreating, saturation of olefins is reduced to very low levels. The olefin 

saturation which does occur is necessary to eliminate diolefins. Thus, little excess hydrogen is 

consumed. CDTech offers an option to refiners to put in an additional catalyst section in the 

CDHydro column to increase octane. This octane enhancing catalyst isomerizes some of the 

olefins, which increases the octane of this stream by about three octane numbers, and few of the 

olefins are saturated to degrade this octane gain. The seven-carbon and heavier petroleum 

compounds leave the bottom of the CDHydro unit and are fed into the CDHDS column. There, 

the heavier compounds head down the column and the lighter compounds head up. Both 

sections of the CDHDS column have catalyst loaded into them which serve as hydrotreating 

reaction zones. Similar to how hydrogen is fed to the CDHydro column, hydrogen is fed to the 

bottom of the CDHDS column.

The temperature and pressure of the CDTech process columns are lower than fixed bed 

hydrotreating processes, particularly in the upper section of the distillation column, which is 
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where most of the olefins end up. These operating conditions minimize yield and octane loss. 

While the CDTech process is very different from conventional hydrotreating, the catalyst used 

for removing the sulfur compounds is the same. One important difference between the CDTech 

process and conventional hydrotreating is that CDTech mounts its catalyst in a unique support 

system, while conventional catalyst is usually dumped into the fixed bed reactor. CDTech has 

13 CDHydro/CDHDS desulfurization units in operation in the U.S. 

Phillips Petroleum Co. commercialized and licensed an adsorption desulfurization 

technology called S-Zorb.28 29 In 2007, Phillips sold the S-Zorb process to SINOPEC. S-Zorb 

uses a chemical adsorption process, instead of hydrotreating, as the principal methodology for 

the removal of sulfur from FCC naphtha. Adsorption has the benefit of operating at much lower 

pressure and temperatures, which lowers operating costs. S-Zorb, uses two separate columns and 

is constantly moving an adsorption catalyst from the reactor vessel to the regeneration column, 

and back again.30 The untreated FCC naphtha and hydrogen are fed to the reaction vessel where 

the catalyst catalytically removes the sulfur from the petroleum compound facilitated by the 

hydrogen present in the reactor. The catalyst, which begins to accumulate the removed sulfur, is 

transferred over to the regeneration column on a continual basis where the sulfur is removed 

from the catalyst using hydrogen as the scavenging compound. Then the hydrogen disulfude is 

converted to sulfur dioxide and sent to the sulfur recovery unit. Because the process still relies 

upon catalytic processing in the presence of hydrogen, there is some saturation of olefins, with a 

commensurate reduction in octane. Through a literature search, we believe that 7 S-Zorb 

desulfurization units were originally licensed for Tier 2, but our information sources have 

communicated that only 4 units are actually operating today. 

We conducted a literature search or in some cases asked vendors to name which 

refineries installed their FCC naphtha desulfurization technology to enable compliance with Tier 

2. A summary of the total number of units by vendor and technology type is summarized in

Table 4-1.

Table 4-1 Estimated Number of FCC Desulfurization Technologies Installed to comply 

with Tier 2 by Vendor Company or Technology

Axens 

Prime G

Exxon

Scanfining

CDTech Sinopec SZorbUOP ISAL 

UOP Selectfining

FCC Feed 

HT

No FCC 

Unit

40 16 15 4 1 17 14

4.2.3 Meeting a 10-ppm Gasoline Sulfur Standard

To meet a 10-ppm average gasoline sulfur standard, we believe that the primary strategy

that refiners would adopt would be to further reduce the sulfur level of FCC naphtha. There are 

three primary reasons why we settled on this as the primary strategy we chose for analyzing the 

compliance costs for Tier 3. The first reason is that, even after refiners used hydrotreating to 

reduce the sulfur in the FCC naphtha to comply with Tier 2, FCC naphtha is by far the largest 

contributor of sulfur to the gasoline pool, by virtue of both its volume and sulfur content. Table 

4-2 below summarizes the estimated average volumes and average sulfur levels for the primary

blendstocks typically blended into gasoline for the current Tier 2 situation. By using the 

refinery-by-refinery model to model today’s situation for the typical refinery, we estimate that 
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the FCC naphtha contains about 70 ppm for the typical refinery complying with the 30-ppm Tier 

2 sulfur standard and that gasoline blendstock typically contributes to about 40 percent of a 

refiner’s gasoline pool. Table 4-2 also summarizes the changes in gasoline blendstock sulfur 

levels we believe would occur when complying with the proposed 10-ppm gasoline sulfur 

standard. Using the refinery-by-refinery model, we project that a 10-ppm gasoline sulfur 

standard can be met by a typical refinery by reducing the sulfur level of FCC naphtha from about 

70 ppm to 20 ppm. In fact, for virtually all refineries that have an FCC unit, refiners would not 

be able to comply with the proposed 10-ppm gasoline sulfur standard without further 

desulfurizing the FCC naphtha. The second reason why we believe that refiners would address 

the sulfur in the FCC naphtha is because both vendors and refiners have told us that this is the 

gasoline blendstock stream that they intend to address. Both vendors and refiners have explained 

to us that, for most refineries, FCC naphtha hydrotreaters will already be in place that can be 

retrofitted with only a modest capital cost to realize the sulfur reduction needed. Third, further 

reducing the sulfur of the FCC naphtha as the means to comply with Tier 3 is supported by other 

cost studies. When these studies assessed the costs for further reducing the sulfur levels of 

gasoline, they also focused further reducing the sulfur levels of the FCC naphtha. See the 

subsection at the end of Chapter 5 discussing these other cost studies. 

Table 4-2 Estimated Typical Gasoline Blendstock Volumes and Sulfur Levels after Tier 2 

and Complying with a 10-ppm Sulfur Standard

Gasoline 

Blendstock

30-ppm Tier 2 Gasoline Sulfur 

Standard

10 -ppm Gasoline Sulfur Standard

Volume 

(Percent)

Sulfur (ppm) Volume 

(Percent)

Sulfur (ppm)

FCC Naphtha 37 72 36 22

Reformate 23 0.5 22 0.5

Alkylate 13 5 13 5

Isomerate 3 0.5 3 0.5

Butane 4 10 4 10

Light Straight Run 

Naphtha and 

Natural Gas Liquids

5 34 5 1

Hydrocrackate 3 8 3 8

Ethanol 10 5 12.5 5

Coker Naphtha 2 1 2 1

Other Gasoline 

Blendstocks

1 10 1 1

Total/Sulfur 

Average

100 30 100 10

Reducing FCC naphtha from 70 ppm to 20 ppm would likely be accomplished in different ways 

depending on the desulfurizing technology and configuration used for Tier 2, and whether the 

current capital employed for lowering gasoline sulfur is severely taxed or not severely taxed. For 

purposes of this discussion, we will discuss the likely steps taken to comply with Tier 3 based on 

whether a refiner solely used an FCC pretreater or FCC postreater to comply with Tier 2. While 

we provided an example for a typical refinery needing to reduce its FCC naphtha from 70 ppm to 
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20 ppm to enable compliance with Tier 2, there are many refineries which are not typical and so 

their starting and ending sulfur levels would be different from this example. Despite these 

differences, we believe that every refinery could technically comply with a 10-ppm gasoline 

sulfur standard. This is because gasoline sulfur is easy to remove - the challenge is to comply

while minimizing the cost of doing so. This challenge is further discussed in Section 4.2.3.5

below which discusses the value of the proposed averaging, banking and trading program.

The one exception is the case where a refinery does not have an FCC unit. Refineries in 

this situation would likely already be producing gasoline which is 10 ppm or below. If the 

refinery’s gasoline is above 10 ppm, then the refiner would need to address one or more of 

several different gasoline blendstocks, including light straight run, butane and natural gas liquids. 

This is discussed at the end of this section about other gasoline streams. 

4.2.3.1 Meeting 10 ppm if Refiners Used an FCC Feed Pretreater to Comply with 

Tier 2

If a refiner relied on an FCC pretreater to comply with Tier 2 at a refinery, the refiner 

would likely only be able to achieve 10-ppm sulfur gasoline if their FCC pretreater is a high 

pressure unit.31 32 This is because most refineries which have FCC pretreaters process sour crude 

oils and if the unit is a mid or low-pressure unit, the unit pressure would likely be too low to 

sufficiently desulfurize the FCC feed. This is likely true even if the refiner added reactor volume 

to its existing low or medium pressure FCC pretreater which does cause additional 

desulfurization. The problem with the mid and low pressure FCC pretreaters is that they just 

cannot remove enough of the sulfur in the gas oil feed to the FCC unit to achieve adequately low 

sulfur levels in the FCC naphtha. If a refinery processes moderate to low sulfur crude oil and has

a low to mid-pressure FCC pretreater, however, it may be able to achieve an adequate degree of 

desulfurization in the FCC naphtha to enable the refiner to reduce its gasoline sulfur down to 10 

ppm. Thus, if a refinery cannot achieve a sufficient level of desulfurization with its current or 

revamped FCC pretreater to comply with a 10-ppm gasoline sulfur standard, then the refiner will 

have to install a grassroots FCC postreater. Alternatively, refiners in this situation would be in 

the best situation to take advantage of the averaging aspect of the averaging, banking and trading 

program (ABT). Using the ABT provisions to its advantage, the refiner would achieve the most 

desulfurization that it can with its existing FCC pretreater (perhaps 20 ppm sulfur gasoline), and 

then would need to purchase credits to demonstrate the remainder of its compliance with the 10-

ppm gasoline sulfur standard. This scenario would avoid the need for a refiner to install an 

expensive grassroots FCC postreater. 

While they are expensive to install, FCC pretreaters provide important operating cost 

advantages over postreaters. An important advantage of FCC pretreating is that it occurs 

upstream of the FCC unit and therefore does not jeopardize the octane value of the olefins 

produced in the FCC unit. Another advantage of the FCC pretreater is that it tends to increase 

the yield of naphtha from the FCC unit which improves operating margins for the refinery with 

such a unit. Thus, refiners which are able to use FCC pretreaters to comply with the Tier 3 sulfur 

standard would likely yield a further return on any investment made, and offset some or all of the 

increased operating costs incurred. Perhaps only 5 refineries have high pressure FCC pretreaters 

in the U.S.
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4.2.3.2 Meeting 10 ppm if Refiners Used an FCC Postreater to comply with Tier 2

If a refiner installed an FCC postreater to comply with the Tier 2 gasoline sulfur standard, 

there are several considerations about the current configuration of the postreater which would 

affect how a refiner would use this unit to comply with a 10-ppm gasoline sulfur standard. The 

first issue is what is the degree of desulfurization the postreater is currently facing? It makes 

sense to work through several examples to understand the types of revamps and associated 

investments that might occur. 

For the first example, if the refinery is refining a very sour (high sulfur) crude oil and the 

sulfur of the FCC naphtha exiting the FCC unit is 2,400 ppm, the postreater is currently 

removing almost 97 percent of the feed sulfur assuming that the sulfur level of the FCC naphtha 

exiting postreater is 70 ppm, which is a very high level of desulfurization. When attempting to 

achieve further sulfur reduction in the FCC naphtha, the refiner must be concerned about the 

increased occurrence of recombination reactions and the potential for much more octane loss and 

hydrogen consumption. This refiner would strongly consider adding a second stage, which may

actually reduce the level of recombination reactions and the octane loss currently experienced by 

the postreater. Most all the vendors offer a second stage option. In the case of CDTech, they

call the second reactor, added as part of its second stage, a polishing reactor. We contacted the 

desulfurization engineer at Sinopec who explained that these units could just be turned up and 

that no additional capital investments would be needed. A Conoco-Phillips hydrotreating 

specialist we spoke to confirmed that this would be the strategy for their S-Zorb units. Yet one 

more option, if the refiner is interested in improving its operating margins such as increased 

gasoline production, and has ample capital dollars to spend, the refiner could add an FCC feed 

hydrotreater to increase its yield of FCC naphtha, or a mild hydrocracker to increase its 

production of low sulfur distillate. 

In contrast, if a refiner is processing a very sweet (low sulfur) crude oil, the sulfur level 

exiting the FCC unit may be as low as 300 ppm, and under Tier 2, the level of desulfurization 

necessary to bring that stream down to 70 ppm is about 81 percent which is a very modest level 

of desulfurization. Similarly, a refinery processing a moderately sour crude oil with a medium 

pressure FCC feed hydrotreater could be in a similar situation. The refineries in this situation 

could have a lot more capacity in their existing postreaters to achieve lower sulfur without 

additional capital cost investments. However, many refiners in this situation which invested in 

an FCC postreater for Tier 2 may have minimized their capital investments. For example, a 

refiner may have avoided the capital and operating cost of a splitter with its postreater by

hydrotreating the full range FCC naphtha. Therefore, the increased severity of the postreater 

needed to achieve 20 ppm in the FCC naphtha to meet a 10-ppm gasoline sulfur standard might 

create a larger octane loss and higher hydrogen consumption than what the refinery could easily 

provide without a significant additional capital investment. In this case, the refiner can invest 

some capital in the postreater to minimize the increase in octane loss and hydrogen consumption. 

For example a refiner with an Axens unit in this situation could add the SHU and a splitter. A 

refiner with a Scanfining unit in this situation wishing to minimize the octane loss and hydrogen 

consumption could add a Zeromer or an Exomer unit. Alternatively, if the refiner is processing a 

moderately sour crude oil and has a moderate pressure FCC feed hydrotreater, the refinery may

choose instead to revamp the FCC feed hydrotreater for its operational benefits rather than 

revamp the postreater. 
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The last example of a postreater deserving some discussion is the case where the sulfur 

level exiting the FCC unit is 800 ppm. This is probably most typical of a refinery refining a 

crude oil containing an average amount of sulfur, or, perhaps a refinery refining a very sour 

crude oil but treating the vacuum gas oil with a low pressure FCC feed hydrotreater. The current 

FCC naphtha hydrotreater would be achieving about 90 percent desulfurization when producing 

FCC naphtha with 80 ppm sulfur. In looking to reduce the FCC naphtha down to 20 ppm to 

comply with a 10-ppm sulfur standard, a refiner in this position would not likely consider adding 

a second stage. This is because avoiding the increased octane loss and increased hydrogen 

consumption for the additional increment of sulfur reduction would probably not justify the 

capital costs associated with a second stage. Instead of a second stage, a refiner could revamp 

the existing FCC postreater with additional reactor volume, or add capital for addressing 

recombination reactions, both likely to be a lot less capital intensive than a second stage. A no 

investment option is possible for refiners in this situation, although the increase in octane loss 

and hydrogen consumption is likely to be significant. 

Perhaps the most important part of an FCC hydrotreater is the catalyst used in the unit. 

Due to continuing research, catalysts are constantly being developed which are more active, thus 

achieving greater desulfurization at a lower temperature, and minimize octane loss and hydrogen 

consumption due to lower olefin saturation. When the Tier 2 naphtha desulfurizers were being 

put into service the most recent catalysts were likely used in those units. These catalysts can be 

changed out when the postreater is being taken down for regular maintenance, and new and 

improved catalysts can be used to improve the desulfurization capacity of the unit. If refiners 

indeed need to comply with a 10-ppm gasoline sulfur standard, they would be expected to 

upgrade to the most recent catalyst to minimize their costs. Using the most active catalyst 

available would reduce the capital cost that would need to be incurred and reduce the hydrogen 

consumption and octane loss that would otherwise occur. We are aware of newer lines of 

catalysts being marketed by the various vendors. We can confirm that Axens and UOP have 

introduced more active catalysts since the catalysts were loaded into the FCC postreaters to 

comply with Tier 2, although it is likely that all the vendors now offer improved hydrotreating 

catalysts. 

4.2.3.3 Desulfurizing Other Blendstocks

A more stringent gasoline sulfur standard could require refiners to have to address other 

gasoline streams that are high enough in sulfur to be a concern to the refiners. This is because 

without addressing these gasoline streams, the refiner would have to reduce their FCC naphtha 

even lower in sulfur resulting in high per gallon costs at the lower sulfur levels. The gasoline 

streams that we have identified that could require additional desulfurization include light straight 

run naphtha, natural gas liquids and butane. 

Light straight run naphtha (LSR) is naturally occurring in the crude oil and is 

desulfurized at many refineries before it is sent to an isomerization unit. However, a number of 

refineries don’t have isomerization units and therefore some or perhaps many of these refineries 

may not be treating this stream today. Natural gas liquids (also termed pentanes plus) are 

naphtha streams sourced from natural gas wells which are purchased by refiners and blended into 

the gasoline pool. Depending on the source of the specific naphtha stream being purchased, 

these streams could vary widely in gasoline sulfur, ranging from a few ppm sulfur up to several 
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hundred ppm sulfur. Butane is natural occurring in crude oil and butane is also produced by the 

FCC unit, and to a lesser degree, hydrocrackers. Refiners separate the butane from these various 

streams and then blend it back into their gasoline pool depending on the RVP requirements of the 

gasoline market that the refiner is selling their gasoline into. 

Refiners have multiple options for addressing the sulfur levels of these various streams. 

The LSR and natural gas liquids can be hydrotreated in either the FCC postreaters or the naphtha

hydrotreaters. Because these naphtha streams do not have any olefins, there is essentially no 

octane loss and, therefore, hydrogen consumption is lower compared to hydrotreating FCC 

naphtha. Another way of treating these streams would be to use caustic extraction to extract the 

mercaptan sulfur from these streams. Since only the mercaptans are removed with the extraction 

technology, the final sulfur level won’t be as low compared to desulfurization using 

hydrotreating. Finally, the refiner could choose to simply not purchase the natural gas liquids 

and sell the LSR on the open market as opposed to treating these streams. If a refiner decides to 

not treat the LSR or natural gas liquids, other refiners with excess capacity in their FCC 

postreaters or naphtha hydrotreaters could treat these streams. 

Butane is normally treated using mercaptan extraction technologies. We are aware that 

some refiners have installed at least a few of these units at their refineries to address butane 

sulfur. Because butane is usually relatively low in sulfur to begin with, refiners are likely to only 

pursue desulfurizing this gasoline blendstock if their butane is higher than average in sulfur, or if 

they are considering producing a very low sulfur gasoline, such as 5 ppm. 

In summary, to comply with a 10-ppm gasoline sulfur standard, refiners have a range of 

options available to them, most of which involve reducing the sulfur in the FCC naphtha. If a 

refinery has a high pressure FCC pretreater, the refiner may be able to just turn up the 

hydrotreating severity of that unit. If a refinery has a low or medium pressure FCC pretreater

and no postreater, the refinery would likely need to install a grassroots FCC postreater to comply 

with a 10-ppm gasoline sulfur standard, or achieve the most that it can with its current capital 

and rely on the ABT program. Refiners with FCC postreaters have multiple options. If a 

refinery is short on octane and hydrogen, the refiner is likely to invest in capital to avoid as much 

octane loss and hydrogen consumption as possible. However, if the refiner has a lot of excess 

octane and hydrogen, the refiner may choose to avoid any capital cost investments or only make 

small capital investments and tolerate the higher octane loss and hydrogen consumption by

simply turning up the severity of its current FCC postreater. Refineries with postreaters could 

always invest in an FCC pretreater (hydrotreater or mild hydrocracker) to improve its refinery’s 

margins or to produce more low sulfur diesel fuel. Finally, in blending up their gasoline, some 

refiners may still be blending in some produced or purchased gasoline blendstocks that continue 

to have high enough sulfur levels which would be a concern when faced with a more stringent 

gasoline sulfur standard, and several options exist for addressing the sulfur in these gasoline 

blendstocks. 

4.2.3.4 Demonstrated Compliance with a 10-ppm Gasoline Sulfur Standard

There are multiple cases today where refiners are complying with 10-ppm or lower 

gasoline sulfur programs. The State of California required gasoline sold in the State to meet a 

15-ppm gasoline sulfur standard on average and a 20-ppm cap (California gasoline’s per-gallon 
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sulfur cap dropped to 20 ppm on January 1, 2012). Furthermore, refiners can produce gasoline 

which varies in composition, provided that the California Predictive Emissions Model (which, 

like EPA’s Complex Model, estimates vehicle emissions from fuels of varying composition) 

confirms that the proposed fuel formulation meets or exceeds the emissions reduction that would 

occur based on the default fuel requirements. California refineries are using the flexibility

provided by the Predictive Model to surpass the prescriptive standards for gasoline sulfur and are 

producing gasoline which contains around 10 ppm sulfur on average. They are making this very

low sulfur gasoline despite using Californian and Alaskan crude oils which are poorer quality 

than most other crude oils being used in the U.S. today. Thus, the experience in California 

demonstrates that commercial technologies already exist to permit refiners to produce very low 

sulfur gasoline. 

Japan currently has a 10-ppm gasoline sulfur cap that took effect January 2008. Europe 

also has a 10-ppm sulfur cap that has been adopted by the 30 Member States that comprise the 

European Union (EU) and the European Free Trade Association (EFTA) as well as Albania and 

Bosnia-Herzegovina. Under a 10-ppm cap standard, the gasoline sulfur level likely averages 

about 5 ppm. Although gasoline in Japan and Europe is made from different crude oil sources 

and much of the heavier ends are cut into diesel fuel, these international fuel programs (along 

with California) provide evidence that advanced gasoline desulfurization technologies have been 

deployed and are readily available enable compliance with the proposed Tier 3 fuel program. 

4.2.3.5 Improved Feasibility with the Proposed ABT Provisions 

The averaging, banking and trading (ABT) and small refiner and small volume refinery

aspects of the proposed Tier 3 gasoline sulfur program would ease the feasibility of compliance 

with the program. To make the point, it is useful to first understand compliance if the ABT and 

small refiner and small volume refinery provisions did not exist. Without these provisions, all 

refineries would have to comply with the 10-ppm gasoline sulfur standard by January 1, 2017. 

In the approximate 4 years after finalizing this rulemaking, most refiners would have to make 

capital investments in their refineries to enable compliance with the 10-ppm gasoline sulfur 

standard. These investments include revamped FCC pretreaters and postreaters, and the 

installation of grassroots FCC postreaters. As described above, reaching 10 ppm sulfur in the 

gasoline pool is attainable by each refinery. However, refiners assess the economic feasibility of 

their refineries differently depending on past and expected future economic performance. They

therefore have different tolerances for making capital investments and absorbing increased 

operating costs. This is particularly true during a period of time in which gasoline demand is 

projected to be flat and renewable fuel blending is expected to increase. Refiners who own small 

refineries are concerned about the higher per-barrel costs for the capital installed at those small 

refineries. 

The small refiner and small volume refinery provisions will delay compliance for these 

entities until January 1, 2020. Small refiners need more time because they have smaller 

engineering staffs that they can dedicate to oversee the necessary refinery changes, thus they are 

more likely to complete the necessary changes to their refineries later than large refiners. Also, 

the delay allows the small refiners to experience improved margins for a couple of years when 

other larger refineries are complying with the gasoline sulfur standards. 
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The banking provisions of the ABT program effectively phase in the sulfur standard over 

six years starting in 2014 through the end of 2019. The phase-in allows refiners to stagger their 

investments to their economic advantage. Refineries which are expected to incur the lowest 

costs for achieving lower gasoline sulfur levels can comply early and earn sulfur credits. These 

credits can then be used to demonstrate compliance starting in 2017 by the refineries which are 

expected to incur higher costs for reducing their gasoline sulfur levels allowing those refineries 

to delay investments for lowering their gasoline sulfur. This phasing-in of the gasoline sulfur 

standard will help spread out the preliminary design demands on the vendor companies which 

license the desulfurization technology to refiners, spread out the detailed design demands on the 

engineering companies which provide that service to refiners, spread out the permitting demands 

on the states which must provide environmental permits to refiners, and spread out the demands 

on the fabrication shops which construct the reactors and other major hardware which must be 

installed at refineries to realize the gasoline sulfur reductions. For more on how the proposed 

ABT provisions are expected to help with lead time, refer to Section 4.3.

Finally, the averaging provisions of the ABT program will provide additional flexibility

and help to reduce the costs of the gasoline sulfur program. The averaging provisions will allow 

refiners to reduce the gasoline sulfur levels to under 10 ppm at their lower cost refineries to show 

compliance or help to show compliance at higher cost or financially challenged refineries. 

4.2.3.6 Implications of an Average Gasoline Sulfur Standard Less than 10 ppm

While there may be emissions motivations for further reducing gasoline sulfur levels, 

there are practical reasons for proposing a 10-ppm annual average sulfur standard instead of a 

more stringent standard, e.g., 5 ppm. The lower the sulfur standard, the more costly it is for 

refiners to achieve the lower sulfur standard. We identified several reasons why the costs 

increase so much for more deeply desulfurizing the gasoline pool. 

As desulfurization severity increases, the operating and capital costs associated with 

desulfurizing FCC naphtha also increases. FCC naphtha is very rich in high-octane olefins. As 

the severity of desulfurization increases, more olefins are saturated, further sacrificing the octane 

value of this stream and further increasing hydrogen consumption. Also, as desulfurization 

severity increases, there is an increase in the amount of the removed sulfur (in the form of 

hydrogen sulfide) which recombines with the olefins in the FCC naphtha, thus offsetting the 

principal desulfurization reactions. There are means to deal with the recombination reactions;

however, this probably means even greater capital investments. For example, the most 

expensive capital investment for an FCC postreater is a two stage desulfurization unit. A sulfur 

standard less than 10 ppm would likely require more refiners to invest in a second stage for their 

FCC postreater.

There are several other reasons which further increases the desulfurization cost for a 

gasoline sulfur standard less than 10 ppm beyond the higher FCC postreater cost. Per Table 4-2, 

other refinery streams contain a very modest amount of sulfur, yet a 5-ppm sulfur standard would 

likely require desulfurization of some of these streams. For example, we believe that to comply 

with a 5-ppm gasoline sulfur standard, most refiners would need to treat the butane blended into 

the gasoline pool. Because refineries have different sulfur levels in their non-FCC streams based 

on their feedstock sulfur levels and their configurations, those with higher sulfur levels in other 
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4-21

refinery streams may have to desulfurize additional streams besides butane. Each additional 

individual gasoline stream that requires desulfurization is incrementally a lot more expensive 

than addressing the sulfur from the FCC unit because the amount of sulfur reduction is a lot 

lower, but the capital costs are higher on a per-barrel basis for lower volume gasoline blendstock 

streams. Furthermore, desulfurizing gasoline down to 5 ppm essentially removes the flexibility

offered by the 10-ppm gasoline sulfur standard with ABT program. Each U.S. refinery is in a 

different position today, both technically and financially, relative to the other refineries. In

general, they are configured to handle the different crude oils they process and turn their crude 

oil slate into a widely varying product slate to match their available markets. Those processing 

heavier, sour crudes would have a more challenging time reducing gasoline sulfur under the 

proposed Tier 3 program. Also, U.S. refineries vary greatly in size (atmospheric crude capacities 

range from less than 5,000 to more than 500,000 barrels per day) and thus have different 

economies of scale for adding capital to their refineries. As such, it is much easier for some 

refineries to get their sulfur levels below 10 ppm than for others to reach 10 ppm. This allows 

the ABT program to be used to reduce the cost of the proposed gasoline sulfur standard. If the 

gasoline sulfur standard were to be 5 ppm, this would essentially end the ability of the refiners to 

average sulfur reductions across their refineries thus significantly increasing the costs while 

significantly reducing the desulfurization flexibility. 

Going lower than 10 ppm would cause control costs to quickly escalate as more 

challenged refineries would be forced into much larger investments. Our cost estimates for 5 

ppm versus 10 ppm with averaging bears this out. We estimate the cost for a 10-ppm gasoline 

sulfur standard (assuming intra-company credit trading) to be 0.89 ¢/gal compared to 1.38 ¢/gal 

for the 5-ppm standard. The cost per sulfur reduction for the 10-ppm average standard is 0.89 

¢/gal for the 20 ppm sulfur reduction from Tier 2, or 0.045 ¢/ppm-gal. The cost per sulfur 

reduction for the 5-ppm standard is 0.49 ¢/gal for the 5-ppm sulfur difference from the 10-ppm 

average standard, or 0.098 ¢/ppm-gal, which is over 2 times higher. Therefore, we believe that 

an annual average standard of 10 ppm at the refinery gate with an ABT program appears to be 

the point which properly balances feasibility with costs. 

In much of Europe and Japan, the gasoline sulfur level is capped at 10 ppm. We, 

however, are not considering a 10-ppm cap for the U.S. The U.S. gasoline distribution system 

poses contamination challenges that make it difficult to set and enforce tight downstream pergallon sulfur standards. The U.S. gasoline distribution system poses contamination challenges 

that make it difficult to set and enforce tight downstream sulfur standards. In Europe, Japan, and 

California, finished petroleum products are generally shipped short distances directly from the 

refinery to the terminal with limited susceptibility to contamination. The U.S. has the longest 

and most complex gasoline distribution system in the world, making it harder to control sulfur 

contamination than in other countries. Petroleum products are shipped long distances through 

multi-product pipelines. Further, gasoline goes through the same pipelines and terminals backto-back with jet fuel (containing up to 2,000 ppm sulfur). Products are often in the custody of a 

number of separate companies before reaching the terminal. This system is very effective at 

delivering petroleum products to the bulk of the country, but pipeline transport inevitably

introduces the potential for sulfur contamination of the gasoline being shipped through pipelines. 

Gasoline additives, needed to provide critical fuel performance characteristics (e.g., corrosion 

control, demulsifiers), also contain varying levels of sulfur which contribute to the overall sulfur 

content of gasoline. Therefore, we are proposing a 10-ppm average sulfur standard coupled with 
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higher per gallon caps at both the refinery gate and at all points downstream, as currently exists 

under the Tier 2 program. We believe this is the most prudent approach for lowering in-use 

sulfur while maintaining flexibility considering cost and other factors. These per-gallon caps are 

important in the context of an average sulfur standard to provide an upper limit on the sulfur 

concentration that vehicles must be designed to tolerate. Since there are many opportunities for 

sulfur to be introduced into gasoline downstream of the refinery, these caps also limit 

downstream sulfur contamination and enable the enforcement of the gasoline sulfur standard inuse. For more on our consideration of downstream caps, refer to Section 4.2.4.2. 

4.2.4 Challenges with Lowering Today’s Sulfur Caps

4.2.4.1 Impacts of Lowering the 80-ppm Refinery Cap

We considered lowering the 80-ppm cap standard that applies to refiners under the Tier 2 

program. If we were to lower the cap standard, we analyzed lowering it to two different possible 

sulfur levels, either 50 ppm or 20 ppm. If we lowered the refinery cap standard to 20 ppm, then 

the averaging aspect of the ABT program would essentially not be available to refiners. That is 

because, under a 20-ppm cap standard, we estimate that refiners would average about 10 ppm 

sulfur. Thus, the compliance scenario if the cap standard were 20 ppm would essentially be the 

same as the non-ABT case we analyzed. In this case, refiners would not have much of the 

flexibility offered by the ABT program. 

If the cap standard were to be lowered to 50 ppm, the final compliance scenario under the 

Tier 3 fuels program would be somewhere between the ABT scenario that we analyzed and the 

non-ABT scenario that we analyzed (probably much closer to the ABT case). According to EPA 

batch data, there were 20 refineries that averaged between 40 and 80 ppm sulfur during 2009. 

These refineries are using credits to show compliance with the Tier 2 30-ppm gasoline sulfur 

standard. If the 80-ppm cap were to be reduced to 50 ppm, those refineries that were averaging 

over 40 ppm would be forced to reduce their sulfur levels below the cap even if their financial 

situation is more tenable compared to other refineries. However, even if the cap standard were to 

remain at 80 ppm, most of the 20 refineries that averaged between 40 and 80 ppm under Tier 2 

would have to lower their sulfur anyways because of the stringency of the proposed 10-ppm 

sulfur standard. There would not be sufficient credits available to allow most of those refineries 

remain at high gasoline sulfur levels. Our cost analysis, which assumes intra-company credit 

trading, projects that only one refinery would remain just above 40 ppm when the fuels program 

is fully phased in. For more on our cost analysis, refer to Chapter 5 of the draft RIA. 

Another way that a more stringent cap would affect refiners would be to restrict the 

ability of refiners to process high sulfur FCC naphtha when there is a short term shutdown of the 

FCC postreater. If the FCC postreater goes down, the refinery would likely continue operating 

the FCC unit and store up the high sulfur FCC naphtha. Since the FCC naphtha is too high in 

sulfur to blend directly with gasoline, the refinery would have to either sell the material to other 

refiners, or hydrotreat the stored up FCC naphtha along with the ongoing production of high 

sulfur FCC naphtha once the FCC postreater was back online. If a stringent cap were in place, 

the refiner would have little room for short term production of higher sulfur gasoline if it was 

feeding a larger than normal quantity (stored and new production) of FCC naphtha to the FCC 

postreater. Without this flexibility, the refiner may have to oversize the FCC postreater and FCC 
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4-23

naphtha storage to ensure that, regardless of the higher feed volume needed to process the stored 

material, the FCC naphtha desulfurization unit could continue to desulfurize the FCC naphtha 

down to the required sulfur level that would result in 10 ppm sulfur in the gasoline pool. If the 

cap were to be lowered, a 50-ppm cap standard would clearly continue to provide refiners with 

some flexibility while a 20-ppm cap would not. Even if refiners planned to tolerate some higher 

sulfur batches when hydrotreating stored FCC naphtha, it could not tolerate much volume of 

higher sulfur batched because of the need to average 10 ppm over the calendar year. If such 

outages happen very infrequently, then a small amount of credits could regularly be banked over 

time that would allow for some longer term higher sulfur batches of gasoline as the stored FCC 

naphtha was being hydrotreated. Alternatively, the averaging of sulfur credits would help 

refiners with FCC naphtha hydrotreater outages. Thus, the flexibility of the ABT program 

coupled with a higher cap standard would provide refiners with some flexibility to handle FCC 

unit outages. 

4.2.4.2 Downstream Sulfur Caps 

The feasibility of complying with a downstream sulfur cap is dependent on the 

differential between the refinery/importer gate sulfur cap and the downstream cap. This 

differential must provide sufficient flexibility for worst-case situations when the potential 

sources of sulfur addition downstream of the refinery/importer compound in a single batch of 

gasoline that was introduced into the system at the refinery/importer gate sulfur cap.

We are proposing two potential options for the per-gallon downstream sulfur cap. Under 

the first option, we are proposing to maintain the current 95-ppm downstream sulfur cap. This 

option is associated with the proposed maintenance of the current 80-ppm refinery/importer gate 

sulfur cap and is reflected in the draft regulatory text. Under the second option, we are 

proposing that the downstream sulfur cap would be reduced to 65 ppm. This option is associated 

with the proposed reduction in the refinery/importer gate sulfur cap to 50 ppm. Under both of 

these options, we would be maintaining the current 15-ppm differential between the 

refinery/importer gate sulfur cap and the downstream sulfur cap.

We are also requesting comment on the potential implementation of a downstream sulfur 

cap as low as 25 ppm. This scenario is associated with a reduction of the refinery/importer gate 

sulfur cap to as low as 20 ppm. Under this scenario, the differential between the 

refinery/importer gate sulfur cap and the downstream sulfur cap might be a little as 5 ppm. 

Under all of these potential approaches, the downstream sulfur cap would apply at all 

locations downstream of the refinery or importer gate including the gasoline produced by 

transmix processors and after the use of additives. The potential sources of sulfur addition 

downstream of the refinery/importer gate and issues associated with the feasibility of meeting the 

downstream sulfur caps under consideration are discussed in the following subsections.

4.2.4.2.1 Sulfur Addition Downstream of the Refinery and Importer Gate 

The sulfur content of gasoline can increase downstream of the refinery/importer due to 

contamination during distribution, the use of additives, and the disposition of transmix generated 

during distribution. 
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A small amount of sulfur contamination takes place during distribution as a result of the 

shipment of gasoline over long distances by pipeline and other modes due to the sharing of the 

same distribution assets with other higher-sulfur petroleum products, e.g., jet fuel. Steps can be 

taken to limit sulfur contamination. However, it is an unavoidable feature of the efficient multiproduct distribution system in the U.S. We estimate that sulfur contamination of gasoline can be 

limited to a worst case maximum of 3 or 4 ppm in the future, even for the most involved and 

long-distance distribution pathways.

There are currently no direct regulatory controls on the sulfur content of gasoline 

additives. The contribution to the sulfur content of finished gasoline from gasoline additives is 

accommodated in the differential between the refinery gate and downstream sulfur caps. The 

functional components of some gasoline additives such as silver corrosion inhibitors and 

demulsifiers are inherently high in sulfur content. However, the contribution to the overall sulfur 

content of the finished fuel is very limited. For example, silver corrosion inhibitors can contain 

as much as 30 percent sulfur but because of very low treatment rates can add only 0.17 ppm to 

the sulfur content of the finished fuel.33 At seldom used highest treatment rates, the use of 

gasoline additives upstream of the consumer has the potential to add ~1 ppm to the sulfur content 

of the finished fuel. Aftermarket additives that are added directly into the vehicle fuel tank also 

have the potential to increase gasoline sulfur content. One particular aftermarket performance 

and anti-wear additive can contribute ~2 ppm sulfur to the treated fuel.B34

Transmix is a necessary byproduct of the multi-product refined product pipeline 

distribution system. Batches of different products are shipped in sequence in pipelines without 

any physical barrier between the batches. Transmix is produced when the mixture at the 

interface between two adjacent products cannot be cut into either batch. Transmix typically 

accumulates at the end of pipeline systems far from refineries. There are two methods of 

disposing of transmix. Most transmix is sent to transmix processing facilities for separation into 

salable distillate and gasoline products through use of a simple distillation tower. 

The other means of transmix disposal is for pipeline operators to blend small quantities 

directly into batches of gasoline during shipping. This typically takes place at remote pipeline 

locations where small volumes of transmix accumulate that would be difficult to consolidate and 

ship to transmix processors. Pipeline operators that blend transmix into the gasoline in their 

systems must ensure that the resulting gasoline meets all fuel quality specifications and the 

endpoint of the blended gasoline does not exceed 437 °F.C35 This practice currently can add as 

much as 3 to 5 ppm to the sulfur content of gasoline although we believe that the contribution is 

typically less. 

Transmix processing facilities do not handle sufficient volumes to support the installation 

of currently-available desulfurization units. Therefore, the sulfur content of the products they

produce is predominantly governed by the sulfur content of the transmix they receive. In many 

cases, transmix contains jet fuel which can have a sulfur content as high as 3,000 ppm. Due to 

 

B Aftermarket additives are defined as additives sold to vehicle operators for direct addition to vehicle fuel tanks. 

C

437 F is the maximum endpoint allowed for gasoline in the ASTM International specification for gasoline in 

ASTM D4814. 
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the overlapping distillation characteristics of jet fuel and gasoline, it is unavoidable that some jet 

fuel in transmix will be present in the gasoline produced by transmix processors.

Transmix processors produce ~0.1 percent of all gasoline consumed in the U.S. The 

small volume of transmix-derived gasoline along with the fact that such gasoline is typically 

mixed with other gasoline before delivery to the end user, substantially limits the potential 

impact on gasoline sulfur levels. Furthermore, data provided by the largest operator of transmix 

processing facilities, shown in Figure 4-2, indicates that relatively few batches of the gasoline 

they produce approach 80 ppm sulfur.36 Most batches are approximately 10 ppm above the 

current 30-ppm refinery sulfur average. We anticipate that this 10-ppm differential would likely 

continue under the proposed 10-ppm refinery average sulfur standard.

Figure 4-2 Kinder Morgan Transmix Gasoline Product Sulfur Levels

4.2.4.2.2 Maintaining the Current 15-ppm Differential Between the Refinery 

/Importer Gate and Downstream Sulfur Caps

Under both of the co-proposals for a downstream sulfur cap (95 ppm and 65 ppm), we 

would be maintaining the current 15-ppm differential between the refinery/importer gate sulfur 

cap and the downstream sulfur cap.
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The current 15-ppm differential was established under the Tier 2 program to 

accommodate the sulfur contamination during distribution, the sulfur contribution from transmix 

blending by pipeline operators, the sulfur contribution from the use of additives, and to enable 

compliant gasoline to be produced by transmix processors. Transmix processors need to produce 

gasoline sufficiently below the downstream sulfur cap to accommodate the addition of sulfur 

from the use of additives and contamination during further distribution. Experience under the 

Tier 2 program has shown that a 15-ppm differential is sufficient for downstream parties to 

ensure compliance with the downstream sulfur cap

Our co-proposal to maintain the current 95-ppm downstream sulfur cap with an 80-ppm 

refinery/importer gate sulfur cap represents no change from current requirements. As a result, 

there would be no increased difficulty or additional costs associated with satisfying a 95-ppm 

downstream sulfur cap beyond those that were already incurred under the Tier 2 program. 

Our co-proposal to implement a 65-ppm downstream sulfur cap with a 50-ppm refinery

gate sulfur cap would also maintain the current 15-ppm differential between these sulfur caps 

under the Tier 2 program. Since it is this differential that determines the difficulty in complying 

with the downstream sulfur cap, we expect that there would be no operational changes and 

additional costs for downstream parties associated with satisfying a 65-ppm cap downstream 

sulfur cap beyond those that were already incurred under the Tier 2 program to comply with the 

current 95-ppm downstream sulfur cap.

Under both of the co-proposals, the reduction in the refinery average sulfur standard may

make it somewhat easier to comply with the downstream sulfur cap given that most gasoline 

produced would be at or near 10 ppm sulfur.

4.2.4.2.3 Potential Reduction in the Differential Between the Refinery/Importer 

Gate and Downstream Sulfur Caps

We requested comment on the potential implementation of a refinery gate sulfur cap as 

low as 20 ppm and a corresponding downstream sulfur cap as low as 25 ppm. This was driven 

by vehicle manufacturers concerns about the potential impacts on emissions performance if 

vehicles are exposed to gasoline above the proposed 10-ppm refinery average standard.37 As 

discussed in Sections 1.2 and 5.2 of this draft RIA, the vehicle emissions benefits associated with 

today’s proposal are driven by the proposed reduction in the average sulfur content of gasoline 

from 30 to 10 ppm. We believe that the potential benefits from further reductions in the sulfur 

caps would be minimal. However, further reductions in the sulfur caps could have negative 

impacts on refiners and downstream parties. 

The potential impacts on refiners and additional costs associated with a lower 

refinery/importer gate sulfur cap discussed in Section 4.2.4.1. A reduction in the differential 

between the refinery gate sulfur standard and the downstream sulfur standard could also result in 

negative impacts and additional costs to downstream entities. Reducing the current 15-ppm 

differential between the refinery/importer gate and downstream sulfur caps could limit the ability

of transmix processors to continue to produce finished gasoline, limit the ability of pipeline 

operators to continue to blend transmix in gasoline, and potentially require the direct regulation 
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4-27

of gasoline additive sulfur content which might cause certain gasoline additives to be removed 

from the market. 

Some gasoline additive manufactures relate that it would not be technically possible to 

reformulate their additives to meet a lower sulfur cap. Hence, the implementation of a sulfur cap 

for gasoline additives could result in the withdrawal of some necessary and cost-effective 

gasoline additives (e.g., corrosion inhibitors, and demulsifiers) from the market. Other additive 

manufactures related that there would be significant costs in reformulating their additives to meet 

a lower sulfur cap. Some additive manufactures related that they could not justify the cost of 

reformulation and would need to cease manufacture.

Since gasoline additives may add as much as 3 ppm to the sulfur content of the finished 

fuel, allowing for further sulfur contamination during distribution and for test variability means 

that transmix processors must produce gasoline about 5 ppm below the downstream sulfur cap. 

The sulfur levels in the transmix that processors must cope with would be reduced due to the 

proposed reduction the gasoline sulfur requirements for refiners/importers. However, the 

continued presence of high-sulfur jet fuel in transmix would continue to significantly influence 

the sulfur content of the gasoline produced by transmix processors. Given these considerations, 

a reduction in the differential between the refinery gate sulfur cap and the downstream sulfur cap 

might require that the majority of the gasoline produced by transmix processors to be 

desulfurized, something that is cost-prohibitive to do at transmix processing facilities today. 

Other options for dealing with transmix, however, are just as impractical, including shipping it 

back to refineries for reprocessing. Refiners are typically averse to accepting transmix into their 

facilities for reprocessing due to technical, logistical, and economic constraints. In addition, 

transmix would typically need to be shipped long distances from the ends of the product 

distribution by truck to reach a refinery.

If pipeline operators were further limited in their ability to blend small amounts of 

transmix into gasoline due to a reduction in the differential between the refinery/importer gate 

and downstream sulfur caps, they could be compelled to install additional transmix storage and 

shipping facilities at numerous remote locations to facilitate the shipment of small volumes of 

transmix to transmix processors by truck. One major pipeline operator reported that it has over 

100 locations on its system where transmix can be injected into gasoline, some of which do not 

have tank truck access. Thus, a reduction in the differential between the refinery/importer gate 

and downstream sulfur caps could result in substantial additional costs and potential changes to 

transmix operating practices for the pipeline operators.

4.3 Lead Time Assessment

4.3.1 Engineering and Construction Analysis

Given the complexity of gasoline refining, numerous planning and action steps would be 

required for refiners to complete the refinery changes needed to comply with the proposed Tier 3 

sulfur standards. The steps required to implement these changes include: the completion of 

scoping studies, financing, process design for new or revamped refinery units or subunits, 

permitting, detailed engineering based upon the process design, field construction of the gasoline 
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sulfur reduction facilities, and start-up and shakedown of the newly installed desulfurization 

equipment.

We conducted a more thorough lead time analysis in which we sequenced the estimated 

time to complete scoping studies, process design, permitting, detailed engineering, field 

construction, and start-up and shakedown in advance of production based upon the methodology

used in our recent gasoline and diesel rules.

For the proposed Tier 3 gasoline sulfur program, we estimated refinery lead times 

required for two general types of refinery projects: the construction of new grassroots FCC 

postreaters and the revamp of existing pre and postreaters. For each refinery project, we 

estimated lead times for scoping studies, process design, permitting, detailed engineering, field 

construction, and start-up and shakedown. Estimated required lead times for scoping studies are 

six months. Process design ranged from six months for desulfurization equipment revamping to 

nine months for a grassroots postreater. Based on discussions with refiners, a review of the 

permitting experience for Tier 2 and our current analysis, we estimate that permitting for 

desulfurization equipment revamping and the construction of a grassroots postreater would take 

9 months. However, we estimate the overall lead-times for Tier-3-related revamps to be 

considerably shorter, as described below. The estimates for permitting time are consistent with 

those of EPA’s Office of Air Quality Planning and Standards (OAQPS) and our regional offices, 

both of which have engaged in extensive dialog with potentially affected parties. A discussion of 

the permitting implications of Tier 3 is contained in Section V.B of the preamble. Detailed 

engineering efforts were estimated to require six months for desulfurization equipment 

revamping and nine months for grassroots postreaters. Field construction was estimated to 

require six months for revamped pre-and postreaters and 12 months for grassroots postreaters. 

Start-up and shakedown processes were estimated to require six months for revamped FCC 

treaters and 9 months for grassroots postreaters. There is some degree of overlap among each of 

these steps as shown in Table 4-3.

To allow refiners to complete all these different steps and comply with the 10 ppm 

average gasoline sulfur standard, assuming the Tier 3 proposal were to be finalized by the end of 

2013, we would be providing three years of lead time. In addition to the three years of lead time, 

the proposed rulemaking also provides additional flexibility provided by the ABT program, 

small refinery delays, and hardship provisions. To support this timeline, we conducted several 

analyses of the expected refinery lead time requirements associated with the proposed Tier 3 

standards and found that refinery operators would have more than adequate time to implement 

the required refinery charges. A justification for proposed timeline appears below.

Complying with Tier 3 is expected to involve some grassroots (new) FCC postreaters, but 

mostly we believe that refiners will revamp existing FCC postreaters. Revamping of existing 

FCC postreaters can be accomplished in approximately 2 years, or less (See Table 4-3) 

Grassroots FCC postreaters are expected to require on average about three-years to install and 

start-up (See Table 4-3). In comparision to FCC pretreaters, hydrocrackers and distillate 

hydrotreaters, FCC postreaters are much less costly, low pressure units that take less time to 

scope out, require shorter lead times for ordering the equipment, and less time to install. 

Furthermore, the grassroots FCC postreaters to be installed for Tier 3 are expected to be in a 

moderate to light desulfurization service because the refineries they will be installed in will 
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already be complying with Tier 2 using an FCC pretreater. FCC naphtha from a refinery with an 

FCC pretreater is expected to only contain about 100 ppm sulfur. To comply with Tier 3, 

refiners installing these grassroots FCC postreaters would only need to desulfurize the FCC 

naphtha down to 25 ppm (about a 75% reduction). In comparison, a single-stage FCC postreater 

would have to desulfurze FCC naphtha from as high as 2400 ppm sulfur down to 25 ppm, a 99% 

sulfur reduction. The more moderate desulfurization service of the grassroots FCC postreaters 

needed to comply with Tier 3 would be expected to streamline the scoping and design work.

Table 4-3 Anticipated Compliance Timelines

Months

0-

3

3-

6

6-

9

9-

12

12-

15

15-

18

18-

21

21-

24

24-

27

27-

30

30-

33

33-

36

36-

39

39-

42

42-

45

Revam

p

Pre- &

Postreaters

Scoping 

Studies

Process

Design

Permitting

Detailed 

Engineering

Field 

Construction

Start-up / 

Shakedown

Grassroots Postreater

Scoping 

Studies

Process

Design

Permitting

Detailed 

Engineering

Field 

Construction

Start-up / 

Shakedown

It is useful to compare the proposed lead time for Tier 3 to what was provided for Tier 2. 

In the case of the Tier 2 standard, we provided a three-year lead time along with an ABT 

program and other flexibilities to ease compliance. Refiners, though, commented that the three 

year timeline that we provided was not enough time. For the Tier 2 analysis, we assumed that 

refiners would solely install low-pressure FCC postreaters, which we believe could be scoped 

out, designed, installed and started up within a 3 year time period. However, many refiners 

complied with Tier 2 by installing high-pressure FCC pretreaters which require long lead times 

for the procurement of the required equipment. Furthermore, those refiners that did not install 

high-pressure FCC pretreaters instead installed grassroots FCC postreaters, many of which were 

designed for severe desulfurization service. An additional difference between Tier 3 and Tier 2 

is that for Tier 3 we expect the installation of only 16 grassroots units, along with many revamps, 
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but for Tier 2 virtually all refiners installed both grassroots FCC pretreaters and postreaters. The 

demands on the desulfurization vendors for scoping studies, and on the E & C industry for 

design and construction, and on the refiners to train their operations staff and start up the new 

units, was a lot greater for Tier 2 than what we would expect for Tier 3. The total estimated 

investment cost for Tier 2 versus Tier 3 also highlights the difference in investment demands 

The total investment for Tier-2 desulfurization processing units was estimated to be about 

$6.1 billion, while the total investment for Tier-3 desulfurization processing units is estimated to 

be about $2.1 billion. This simple comparison indicates that the proposed Tier 3 lead time 

should be adequate for refineries to obtain necessary permits, secure engineering and 

construction (E&C) resources, install new desulfurization equipment and make all necessary

retrofits to meet the proposed sulfur standards. 

We assessed the permitting situation in more detail working in conjunction with the 

Office of Air Quality, Planning and Standards (OAQPS). On a refinery-by-refinery basis, we 

provided OAQPS estimates of the additional heating demands for the new and revamped units 

per the desulfurization vendor submissions. OAQPS was able to project which refineries would 

likely trigger NOx, particulate matter and greenhouse gas emission permitting limits, which 

would likely lengthen the permitting process as refiners would need to offset the projected 

emission increases. As it turns out, only 7 of the 16 refineries which are projected to install 

grassroots units were projected to exceed particular permitting limits, and these solely did so 

based on the most conservative assumption that each would produce all the additional hydrogen 

on site using hydrogen plants (as opposed to using existing reforming capacity) and produce the 

electricity on site, to satisfy the needs of the new desulfurization equipment. When we provided 

a second heat demand estimate to OAQPS which assumes that refiners purchase their hydrogen 

and electricity from third parties, none of the refineries which we projected would install 

grassroots units was projected to have emission increases which would require offsets. Thus, 

many of the grassroots units that we project would be installed may end up with a streamlined 

permitting processe.

The various flexibilities that the proposed Tier 3 rule provides to refiners provide refiners 

additional time for complying. These flexibilities include the ABT program, the small refiner 

delay provisions and the hardship provisions. The ABT program allows a refiner, either within 

its own company or by purchasing credits on the open market, to delay higher investment cost 

investments, such as the investments in grassroots FCC postreaters, which would provide 

additional lead time for installing these units. This would occur if refiners would reduce the 

sulfur levels of their gasoline through operational changes or revamps of their existing FCC 

pretreaters and postreaters when the ABT Program begins in 2014. Potentially every refinery

with either an FCC pretreater or an FCC postreater may be capable of generating early credits. 

Furthermore, we project that 66 refineries would revamp their existing FCC postreaters to 

comply with Tier 3. Since revamps can be completed within two years or less, these refiners 

could potentially begin generating early credits during 2016, or before if refiners begin each of 

these revamps in early 2014. During the period between 2014 and 2017, these refineries which 

reduce their gasoline sulfur levels below that required by Tier 2 would generate credits. 

Refineries with higher cost capital investments, such as the grassroots FCC postreaters, could 

then delay making those investments through the purchase of credits. We estimate that sufficient 

credits could be generated early to allow many refineries to delay compliance until as late as 
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2020. The quantitative early credit analysis that we conducted showed that if refiners with an 

existing pretreater or postreater would generate early credits by lowering their gasoline sulfur 

down to 20 ppm starting in 2014 and if revamps were started up in 2016, one year before the 

program start date, that almost 6 times more credits would be available to offset the early credit 

demand by the refiners installing grassroots postreater units, assuming that they start up those 

units in 2018. Even if all grassroots postreaters were assumed to not start up until 2020, there 

would be almost 4 times more early credits available to those refiners installing grassroots 

postreaters assuming that the same early credit generation scenario would occur

Additional flexibility is also provided by the small refineries provisions which delays 

compliance for the refineries which refine less than a net of 75,000 barrels of crude oil per day

until 2020. Three of the 16 FCC postreater grassroots units that we project will be installed 

would be by small refineries. However, small refineries could also decide to comply early and 

generate credits starting as early as 2014. 

As in previous fuel programs, we are proposing hardship provisions to accommodate a 

refiner’s inability to comply with the proposed standard at the start of the Tier 3 program, and to 

deal with unforeseen circumstances that may occur at any point during the program. These 

provisions would be available to all refiners, small and non-small, though relief would be granted 

on a case-by-case basis following a showing of certain requirements; primarily that compliance 

through the use of credits was not feasible. We are proposing that any hardship waiver would 

not be a total waiver of compliance; rather, a hardship waiver would be short-term relief that 

would allow a refiner facing a hardship situation to, for example, receive additional time to 

comply. This hardship provision would allow a refiner to seek a delay in the case that there was 

insufficient time to comply. 

Finally, we believe that in reality, less leadtime than shown in Table 4-3would actually be 

necessary. We held discussions with many refiners during most of 2011, and so they have been 

well aware of Tier 3 and are familiar with the likely requirements. During our subsequent 

discussions with technology vendors and engineering firms, they explained to us that many

refiners have already initiated, and by now, likely completed their scoping studies. Thus, actual 

time needed for designing, installing and starting of new desulfurization equipment for Tier 3 

times would even be less than what we projected because many refineries may have already 

completed required scoping studies in anticipation of the Tier-3 standards. Moreover, lead times 

for those refineries that have yet to start the scoping process can also be expected to decrease, 

since fewer refineries will be competing for the services of the desulfurization vendors.

4.3.2 Permitting Analysis

Our analysis found that GHG emission increases were the most common reason that 

Prevention of Significant Deterioration (PSD) applicability would be triggered, followed by NOX

emissions. Specifically, 19 refineries appeared likely to have significant emissions for one or 

more pollutants and thus would trigger major source New Source Review (NSR). Of these 19

refineries, 13 refineries would need permits for NAAQS-related pollutants. 
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With respect to NAAQS-related pollutants, 6 of these13 refineries were predicted to 

require both PSD and Nonattainment NSR permits. Of the remaining 7 refineries, 2 required 

only a Nonattainment NSR permit while the remaining 5 refineries required a PSD permit. 

In comparison, for the Tier 2 program, EPA expected the need for NAAQS-related NSR 

permits might be widespread among refineries. For the proposed Tier 3 gasoline sulfur standard, 

however, only about 10 refineries would need air permits that address NAAQS pollutants. 

This number could be lower if those refineries apply emission controls, such as selective 

catalytic reduction (SCR) for NOX, to reduce the emission increases below the significance level. 

For refineries that do need a major source NSR permit for NAAQS pollutants, the permitting 

process is expected to take 9 - 12 months. For an in depth assessment of stationary source 

implications, refer to Section V.B of the preamble. 

4.3.3 Employment Constraint Analysis

As in prior rules, we also evaluated the capability of E&C industries to design and build 

gasoline hydrotreaters as well as performing routine maintenance. This includes an employment 

analysis. Two areas where it is important to consider the impact of the fuel proposed sulfur 

standards are: 1) refiners’ ability to procure design and construction services and 2) refiners’ 

ability to obtain the capital necessary for the construction of new equipment required to meet the 

new quality specification. We evaluated the requirement for engineering design, and 

construction personnel, in a manner consistent with the Tier 2 analysis, particularly for three 

types of workers: front-end designers, detailed designers and construction workers, needed to 

implement the refinery changes. We developed estimates of the maximum number of each of 

these types of workers needed throughout the design and construction process and compared 

those figures to the number of personnel currently employed in these areas. 

The number of person-hours necessary to design and build individual pieces of refinery

equipment and the person-hours per piece of equipment were taken from Moncrief and 

Ragsdale38. Their paper summarizes analyses performed in support of a National Petroleum 

Council study of gasoline desulfurization, as well as other potential fuel quality changes. The 

design and construction factors for desulfurization equipment are summarized in Table 4-4.

Table 4-4 Design and Construction Factorsa

Gasoline Refiners

Number of New Pieces of Equipment per Refinery 60

Number of Revamped Pieces of Equipment per Refinery 15

Job Hours Per Piece of New Equipmenta

Front End Design 300

Detailed Design 1,200

Direct and Indirect Construction 9,150

Note:
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a Revamped equipment estimated to require half as many hours per piece of equipment

Refinery projects will differ in complexity and scope. Even if all refiners desired to 

complete their project by the same date, their projects would inevitably begin over a range of 

months. Thus, two projects scheduled to start up at exactly the same time are not likely to 

proceed through each step of the design and construction process at the same time. Second, the 

design and construction industries will likely provide refiners with economic incentives to avoid 

temporary peaks in the demand for personnel. 

Applying the above factors, we projected the maximum number of personnel needed in 

any given month for each type of job. The results are shown in Table 4-5. In addition to total 

personnel required, the percentage of the U.S. workforce in these areas is also shown, assuming 

that half of all projects occur in the Gulf Coast in Table 4-5. Very few refineries are expected to 

require the full 45-month period to complete scoping studies, process design, permitting, detailed 

engineering, field construction, and start-up/shakedown.

Table 4-5 Maximum Monthly Demand for Personnel

Front-End 

Design

Detailed 

Engineering

Construction

Tier 3 Gasoline Sulfur Program

Number of Workers 202 809 6,012

Percentage of Current Workforcea11% 9% 4%

Note:

a Based on current employment in the U.S. Gulf Coast assuming half of all projects occur in the Gulf Coast

To meet the proposed Tier 3 sulfur standards, refiners are expected to invest $2.2 billion 

between 2014 and 2019 and utilize approximately 1,000 front-end design and engineering jobs 

and 6,000 construction jobs. The number of estimated jobs required is small relative to overall 

number available in the U.S. job market. As such, we believe that four years is adequate lead 

time for refineries to obtain necessary permits, secure E&C resources, install new desulfurization 

equipment and make all necessary retrofits to meet the proposed sulfur standards. 

4.3.4 ABT Impacts

We conducted a refinery-by-refinery analysis to determine the impacts on refinery E&C 

demand of implementing the 10-ppm standard without an ABT program. The analysis suggests 

that a greater number of refineries would need to make investments in refinery apparatus and 

upgrades than would have under an ABT program. This would result in a greater demand on the 

E&C industry. Moreover, the analysis also indicated that the demand upon the E&C industry

would be spread over a shorter period than with the ABT case. In particular, our refinery-byrefinery analysis indicates that without an ABT program, 73 refineries would revamp existing 

pre- and postreaters and 21 would install grassroots postreaters in order to meet the proposed 

sulfur standards. The remaining 17 refineries are either already in compliance with the 10-ppm 

standard or expected to comply with simple process changes. This is compared to 66 refineries 
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that would revamp existing pre- and postreaters and 16 refineries that would install grassroots 

postreaters in order to meet the proposed sulfur standards under an ABT program.
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References

1 Meyers, Robert A., Handbook of Petroleum Refining Processes, McGraw Hill, 1997.

2

40 CFR 80 Subpart H

3

Shorey, Scott W., AM – 99-55, Exploiting the Synergy Between FCC and Feed Pretreating Units to Improve 

Refinery Margins and Produce Low-Sulfur Fuels, National Petroleum and Refiners Association’s 1999 Annual 

Meeting.

4 Conversation with Woody Shiflett, Advanced Refining Technologies, October 2011.

5 Barletta, Tony, Refiners must optimize FCC feed hydrotreating when producing low-sulfur gasoline, Oil and Gas 

Journal, October 14, 2002.

6 Conversation with Woody Shiflett, Advanced Refining Technologies, October 2011.

7

Shorey, Scott W., AM – 99-55, Exploiting the Synergy Between FCC and Feed Pretreating Units to Improve 

Refinery Margins and Produce Low-Sulfur Fuels, National Petroleum and Refiners Association’s 1999 Annual 

Meeting. 

8 Brunet, Sylvette, On the hydrodesulfurization of FCC gasoline: a review, Applied Catalysis A: General 278 

(2005) 143 – 172.

9 Leonard, Laura E., Recombination: A Complicating Issue in FCC Naphtha Desulfurization, Prepared for the 

AIChE 2006 Spring National Meeting, April 26, 2006

10 Petroleum Refinery Process Economics, Maples, Robert E., PennWell Books, Tulsa, Oklahoma, 1993.

11 Nocca, J.L., et al, Cost-Effective Attainment of New European Gasoline Sulfur Specifications within Existing 

Refineries, November 1998.

12 Prime G, A Sweet Little Process for Ultra-Low Sulfur FCC Gasoline without Heavy Octane Penalty, IFP 

Industrial Division.

13 Debuisschert, Quentin, Prime G+ Update, 12th European FCC Conference – Grace Davidson Seminar, Seville 

Spain, May 2004.

14 Beck, J.S., Advanced Catalyst Technology and Applications for Higher Quality Fuels and Fuels, Prepr. Pap. Am 

Chem Soc., Div. Fuel Chem, 2004 49(2), 507.

15 McGihon, Ron, Exxon Mobil, FCC Naphtha Desulfurization – New Developments, Presentation at the 2009 

Technology Conference, October 5 &6, Dubai, United Arab Emirates.

16 Ellis, E.S., Meeting the demands of low sulfur gasoline, Petroleum Technology Quarterly Spring 2002.

17 Successful Start-Up of New Scanfining Unit at Statoil’s Mongstad Refinery, November 19, 2003.
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18 Greeley, J.P., Zaczepinski, S., Selective Cat Naphtha Hydrofining with Minimal Octane Loss, NPRA 1999 

Annual Meeting (this document available from docket A-97-10).

19 Halbert, Thomas R., Technology Options for Meeting Low Sulfur Mogas Targets AM-00-11, Presented at the 

2000 Annual Meeting of the National Petrochemical and Refiners Association, March 2000.

20 McGihon, Ron, Exxon Mobil, FCC Naphtha Desulfurization – New Developments, Presentation at the 2009 

Technology Conference, October 5 &6, Dubai, United Arab Emirates.

21 Refining Processes 2004, Hydrocarbon Processing.

22 Upson, Lawrence L., Low-sulfur specifications cause refiners to look at hydrotreating options, Oil and Gas 

Journal, December 8, 1997.

23 Krenzke, David L., Hydrotreating Technology Improvements for Low-Emissions Fuels AM-96-67, Presented at 

the 1996 Annual Meeting of the National Petrochemical and Refiners Association, March 1996.

24 UOP SelectFiningTM Process – New Technology for FCC Naphtha HDS, 2009 

25 CDTECH, FCC Gasoline Sulfur Reduction, CDTECH, Sulfur 2000, Hart’s Fuel and Technology Management, 

Summer 1998.

26 Rock, Kerry J., Putman, Hugh, Global Gasoline Reformulation Requires New Technologies, Presented at Hart’s 

World Fuels Conference, San Francisco, March 1998.

27 Rock, Kerry L., et al, Improvements in FCC Gasoline Desulfurization via Catalytic Distillation, Presented at the 

1998 NPRA Annual Meeting, March 1998.

28 Greenwood, Gil J., Next Generation Sulfur Removal Technology AM-00-12, Presented at the 2000 NPRA Annual 

Meeting, March 2000.

29 Meier, Paul F., S Zorb Gasoline Sulfur Removal Technology – Optimized Design AM-04-14, Presented at the 

2004 NPRA Annual Meeting, March 2004.

30 Printed Literature by Phillips Petroleum Shared with EPA September 1999.

31 Patal, Raj, Advanced FCC Feed Pretreatment Technology and Catalysts Improves FCC Profitability AM-02-58, 

Presented at the 2002 NPRA Annual Meeting, March 2002.

32 Conversation with Woody Shiflett of Advanced Refining Technologies October 2011.

33 Letter to Margo Oge, EPA, from Mike Ricca, Baker Hughes, July 25, 2011.

34 Letter to Caryn Muellerleine, EPA, from Richard Kelly, Marvel Oil Company, July 13, 2011.

35 The requirements for transmix blenders are contained in 40 CFR 80.84(d).

36 Graphs of transmix gasoline product sulfur levels at Kinder Morgan transmix processing facilities e-mail from 

James Holland, Kinder Morgan, August 24, 2011. 
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37 Letter from the Alliance of Automobile Manufacturers to Administrator Lisa Jackson, October 6, 2011.

38 Moncrief, Philip and Ralph Ragsdale, “Can the U.S. E&C Industry Meet the EPA’s Low Sulfur Timetable,” 

NPRA 2000 Annual Meeting, March 26-28. 2000, Paper No. AM-00-57.