Refining Options for MTBE-Free Gasoline by fta11207

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									     Refining Options for MTBE-Free Gasoline



                                   Melissa Graham
                                     Pam Pryor

                                   STRATCO, Inc.


                                  Michael E. Sarna

                                Purvin & Gertz, Inc.



INTRODUCTION

On December 9, 1999, the California Air Resources Board (CARB) approved Phase III gasoline
regulations, which prohibit the use of methyl tertiary butyl ether (MTBE) in California’s
reformulated gasoline (RFG) starting December 31, 2002. California RFG contains
approximately 12 vol% MTBE, in part to meet the oxygen requirement of the 1990 Clean Air
Act Amendments. Additionally, MTBE has favorable distillation characteristics and provides
octane and dilution benefits to the gasoline pool. As California refiners evaluate blending options
regarding MTBE-free gasoline, refiners across the country recognize that they may possibly face
similar challenges. Despite increasingly stringent regulations, alkylate continues to be an
excellent gasoline blending component. Alkylation of additional propylene, butylene and
amylene feeds can help refiners meet the challenges ahead.



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BACKGROUND

Over 20 years ago, MTBE was initially used in gasoline blends for its octane benefit. Over the
years, MTBE use has been supported for several reasons. In 1990, Congress passed the Clean Air
Act Amendments, which mandated the use of RFG in areas of the United States experiencing the
worst air quality. The act required that RFG contain a specific oxygen content on the basis that
higher levels of oxygen in the fuel would help cars burn gasoline cleaner. Of several oxygenate
alternatives available, MTBE has been the oxygenate chosen most often to meet the 2.0 wt %
oxygen requirement set forth by these regulations. As more areas have been added to the RFG
program, both through mandate and voluntary “opt-in” decisions, the amount of RFG sold in the
U.S. has grown from approximately one-fourth of the total gasoline market in 1995, to
approximately one-third of the market in 1999. MTBE use has increased proportionally with this
growth.

Although the benefits of MTBE are numerous, issues with MTBE have surfaced during the past
several years. Specifically, MTBE has been found in ground and surface water, creating public
concern. Between 5% and 10% of drinking water supplies in areas consuming RFG have shown
detectable levels of MTBE1 and a number of surface waters have also tested positive for MTBE
at low levels. Several sources have been documented to cause MTBE contamination. Leaking
underground storage tanks appear to be the major contributor to groundwater contamination.
Although the majority of the tanks have been upgraded, the improved designs are not leak-proof.
Gasoline spills to ground and surface water also appear to be another source of contamination.
Finally, recreational watercraft that have two-stroke engines discharge unburned fuel in their
exhaust and appear to be contributing to the surface water contamination problem.

In 1997, the EPA issued an advisory that recommended a maximum concentration of 20 – 40
ppb MTBE in drinking water, to avoid unpleasant taste and odor. This recommendation is well
below the concentration levels expected to cause potential human health effects. Although most
of the problems with MTBE contamination have been below 20 ppb, consumer taste and odor
concerns have still been raised. California is considering even stricter limits, including a primary
content limit of 13 ppb to address health concerns and a secondary content limit of 5 ppb to
address aesthetic issues.


REGULATORY AND LEGISLATIVE ACTION

While there is support to simply address the source of the contamination, emphasis has also been
placed on the use of MTBE and other oxygenates. With the increasing public concern over
contamination issues, several actions have occurred on the state and federal level regarding the
future use of MTBE. In November 1998, the EPA appointed the Blue Ribbon Panel to evaluate
the use of oxygenates in gasoline. The panel not only evaluated the use of MTBE in gasoline, but
also the oxygenate requirement in the Clean Air Act. In July 1999, the panel concluded its
investigation and offered recommendations to enhance water protection and balance both clean
air and water issues.

1
    The Blue Ribbon Panel on Oxygenates in Gasoline, “Executive Summary and Recommendations,” July 27, 1999.

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Specifically, the Panel:



    •   Recommended a comprehensive set of improvements to the nation’s water protection
        programs, including over 20 specific actions to enhance Underground Storage Tank, Safe
        Drinking Water, and private well protection programs;

    •   Agreed broadly that use of MTBE should be reduced substantially (with some members
        supporting its complete phase out), and that Congress should act to provide clear federal
        and state authority to regulate and/or eliminate the use of MTBE and other gasoline
        additives that threaten drinking water supplies;

    •   Recommended that Congress act to remove the current Clean Air Act requirement – that
        2% of RFG, by weight, consist of oxygen – to ensure that adequate fuel supplies can be
        blended in a cost-effective manner while reducing usage of MTBE; and

    •   Recommended that EPA seek mechanisms to ensure that there is no loss of current air
        quality benefits.2




Subsequent to these recommendations, legislation has been brought before the United States
Congress to address waiving of the oxygen requirement of the 1990 Clean Air Act Amendments
and decreasing the use of MTBE. One of the most recent legislative proposals, Senate Bill 1886,
would allow states to opt out of the oxygenate mandate, while still abiding by the remaining
regulations of the RFG program. While this bill does not mandate the removal of MTBE, many
believe that MTBE use is likely to decrease if the RFG oxygen requirement is waived. Several
other bills have been introduced addressing the phase-down or phase-out of MTBE from
gasoline. Although widespread agreement on the need for oxygenates in RFG and the potential
human health effects of MTBE has not been reached, the government is responding to public
concern on this issue.

To this date, no bills have been signed into law, but several groups, including the American
Petroleum Institute (API), Northeast States for Coordinated Air Use Management (NESCAUM)
and the American Lung Association (ALA), have united to support legislative efforts to reduce
the use of MTBE. NESCAUM represents the states of New York, New Jersey, Massachusetts,
New Hampshire, Vermont, Rhode Island, Connecticut and Maine. The group concluded a study
on the RFG and MTBE issue in August 1999, in response to the increased detection of MTBE in
ground and surface water. In this report, the group strongly recommended a phase-down and cap
on MTBE use and called for a repeal of the federal oxygen mandate.

In addition to the federal and regional action on this issue, individual local communities and
states have responded to the MTBE contamination issue as well. In October 1998, Maine
requested permission to opt out of the federal RFG program. The EPA approved this request on

2
 The Blue Ribbon Panel on Oxygenates in Gasoline, “Panel Calls for Action to Protect Water Quality While
Maintaining Air Benefits from National Clean Burning Gas,” Press Release July 27, 1999.

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February 1, 1999, on the condition that Maine develop a state fuel program that is able to
maintain the same air quality benefits that have been observed with RFG.

The following year, the Tahoe Regional Planning Agency based in Carson City, Nevada,
outlawed the use of two-stroke engines on Lake Tahoe starting June 1, 1999. The ordinance was
in response to increasing levels of MTBE in the lake.

Also, in July 1999, the New Hampshire Department of Environmental Services requested that
the EPA grant permission for the state to opt out of the RFG program until January 1, 2002. The
EPA has not yet responded to this request.

Finally, this past winter, in December 1999, the California Air Resources Board (CARB)
approved the Phase III gasoline regulations that prohibit the use of MTBE in gasoline sold in the
state after December 31, 2002. Additionally, California governor Gray Davis’ administration has
asked the EPA to waive the RFG oxygenate requirement to give refiners more flexibility in
blending gasoline.


REPLACING MTBE

Due to the amount of regulatory and legislative activity throughout the nation regarding the
MTBE contamination issue, refiners are investigating options to blend RFG with lower levels of
MTBE or MTBE-free gasoline. When replacing the volume of MTBE in the gasoline pool, its
distillation characteristics, octane and dilution benefits, and the federal RFG program oxygen
requirement must be considered.

MTBE has a blending octane in the range of 106-110 and is used in more than 80% of
oxygenated fuels.3 While several replacement options exist, no single alternative can match all of
the benefits of MTBE. Alternatives to MTBE include other ethers, alcohols and alkylate.

Ethers

Although other ethers, such as tertiary amyl methyl ether (TAME) and ethyl tertiary butyl ether
(ETBE) are available for blending, their current quantities are limited and their toxicology is not
well known. Due to similar chemical structure, there is concern that the other ethers may have
environmental problems similar to MTBE. Furthermore, CARB Phase III specifications do not
allow the use of ETBE or TAME unless the California Environmental Policy Council establishes
that the use of these ethers will not adversely impact public health or the environment. Finally,
consumers may not be open to other petrochemical derived oxygenates based on the experience
with MTBE. Therefore, it seems unlikely that refineries would see these other ethers as a feasible
replacement.




3
 EPA. “MTBE Fact Sheet #3 Use and Distribution of MTBE and Ethanol.” Publication # EPA 510-F-97-016
January 1998.

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Alcohols

Tertiary butyl alcohol (TBA) and ethanol are two alcohol alternatives that are currently used to
meet the oxygen requirement of RFG. Like TAME and ETBE, TBA quantities are limited and its
toxicology is currently not well understood. Therefore, it too does not appear to be a viable
alternative to MTBE.

Ethanol appears to be the most likely oxygenate to replace MTBE, even though the benefits and
challenges of using ethanol are strongly debated. If the federal oxygen mandate is not waived
and MTBE is phased out, ethanol is likely to emerge as the best solution for most of the refiners
that must meet the minimum oxygen requirement.

Ethanol is the oxygenate currently used in approximately 8% of the RFG in the United States. It
is readily biodegradable and its toxicology is well understood. With a blending octane of
approximately 113, ethanol provides octane and dilution benefit to the gasoline pool.
Additionally, the unique interaction between ethanol and the other gasoline components lowers
the T50 distillation point of the overall gasoline blend.4 A mixture of relatively polar ethanol and
relatively non-polar gasoline exhibits the characteristics of a thermodynamically non-ideal
solution. This non-ideality causes the solution to exhibit a higher vapor pressure than can be
predicted using a simple equation of state thermodynamic model. This higher vapor pressure
translates to lower boiling points for the mixture, and in the case of ethanol and gasoline, a lower
T50. The degree of boiling point reduction is related to the concentration of ethanol in the
gasoline. This characteristic can prove very beneficial, as noted in the analyses of several cases
presented in this paper, when ethanol is blended with components having higher T50 values.

Despite octane and T50 benefits, ethanol has disadvantages as well. Adding ethanol to the
gasoline pool raises the vapor pressure of the gasoline. The vapor pressure of the gasoline blend
increases with ethanol content up to approximately 2 vol% and then levels off. With
approximately 2 vol% ethanol in the blend, the RVP increases by approximately 1.3 psi, which
remains constant or slightly decreases with further increases in ethanol. This allows refiners to
blend ethanol at a concentration above the minimum required oxygen level without additional
RVP penalty. Because of this RVP increase, ethanol blending requires refiners to meet even
lower vapor pressure specifications for the other blending components to satisfy regulations. A
second disadvantage is that ethanol does not have the same dilution potential as MTBE, when
each is used to meet the minimum RFG oxygen content. Due to the higher oxygen content of
ethanol, approximately 6 vol% is needed to meet the 2.0 wt% requirement versus 12 vol% of
MTBE. Therefore, MTBE provides greater dilution and contributes more volume to the gasoline
pool. Another disadvantage of ethanol is the associated transportation and blending challenges.
Due to ethanol’s water solubility characteristics, it must be shipped separately from the gasoline
and blended at terminals to avoid water contamination problems.

Controversy surrounds several other ethanol issues as well. Supply issues have been raised
concerning whether producers could provide ethanol fast enough to replace MTBE. Additionally,
ethanol enjoys federal and some state tax subsidies, which are necessary for ethanol to
economically compete with MTBE. Finally, the use of ethanol fuels increases acetaldehyde
4
    William Scott. “Challenges of Producing California Cleaner Burning Gasoline.” Clean Fuels 2000 Conference.

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emissions that lead to peroxy acyl nitrates (PANs), which are ozone precursors. Debate on the
level of increase and the impact on the environment has not been resolved.

Alkylate

Whether or not the oxygen mandate is waived, it appears unlikely that ethanol will satisfy all of
the volume and benefits currently provided by MTBE, so refiners will need to make other
adjustments to the gasoline pool. Incremental alkylate continues to be an attractive option to add
to the gasoline pool. Blending more alkylate helps lower benzene, aromatics and sulfur levels
through dilution. (Alkylate contains neither benzene, nor other aromatics, and very little sulfur.)
Additionally, alkylate consists of branched paraffins having low RVP, high octane and low
octane sensitivity.

Alkylate can be produced through two main processes - alkylation and dimerization with
hydrogenation. The alkylation process involves contacting light olefins (propylene, butylenes
and amylenes) with isobutane in the presence of a strong acid catalyst to form alkylate product.
The dimerization process involves catalytic dimerization of butylenes to isooctene (and other
heavier iso-olefins) and then hydrogenation of the isooctene to isooctane. Numerous companies
license each of these processes, and STRATCO continues to be the world leader in licensing
alkylation technology.

Current domestic alkylate production is over 1.1 million barrels per day. Blending capacities of
alkylate vary from region to region. Refiners in California report blending as high as 20 - 25%
alkylate into finished CARB premium gasoline while other domestic regions blend up to 12 -
15% alkylate. Interest continues to grow in alkylating more light olefins, particularly propylene
and amylenes, to provide additional octane barrels. Based on research findings by STRATCO,
the economics for alkylating these additional olefins are more attractive than previously thought.
Specifically, segregating the olefins and alkylating each olefin type under unique reaction
conditions can provide significant benefits.


REFINING OPTIONS

When replacing MTBE, the choice of replacement blendstocks will depend not only on
regulations, especially concerning minimum oxygen content, but also on individual refinery
economics. Together with Purvin & Gertz, Inc., STRATCO has completed case study analyses
for conceptual West Coast and Gulf Coast coking refineries. Similar scenarios were developed
for the two refinery models to study the effect of adding incremental alkylation capacity to
reduce the impact on gasoline production from elimination of MTBE from the blends. Typical
refineries on the West and Gulf Coasts produce both conventional and reformulated gasoline,
which offers some relief to the problem. However, to better demonstrate the impact of producing
RFG without MTBE, the conceptual refiners studied produce 100% reformulated gasoline.




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Typical gasoline blending components and their properties are shown below.

                                      TABLE 1
                          BASE CASE BLENDING COMPONENTS

                          % of Pool
                        West    Gulf Octane        Sulfur    RVP          A/B/O1         T50      T90
                        Coast Coast (R+M)/2        wppm       psi          vol %          ºF       ºF
Butane                    0.5     0.8   92           5       52.0       0.0/ 0.0/ 0.0     28       28
C5-208 (Hydrotreated)    16.8    18.6 68-73          1       10.0       2.0/ 1.0/ 0.0    130      180
Alkylate                  9.5     6.1 92-94          5        4.0       0.0/ 0.0/ 0.0    210      258
C5/C6 Isomerate           6.9     0.0 78-82          1       12.0       0.0/ 0.0/ 0.0    125      150
Reformate                28.5    26.6 95-100         1        4.0      54.0/ 0.9/ 0.0    250      318
FCC Gasoline              0.0    36.2 85-87         160       7.0      29.0/ 1.0/ 25.0   218      300
C5-340 FCC Gasoline      17.3     0.0 84-86         79        7.6      25.4/ 1.2/ 30.1   200      270
C5-340 FCC Gasoline       4.6     0.0 81-83          8        7.6      23.0/ 0.9/ 10.0   200      270
(Hydrotreated)
340-430 FCC Gasoline      4.3      0.0   82-84       50       0.5      48.0/ 0.0/ 0.0    300      360
(Hydrotreated)
MTBE                     11.7    11.7     110        5        8.0       0.0/ 0.0/ 0.0    130      132
                        100.0   100.0

       Notes:
       1
         A/B/O = Aromatics/Benzene/Olefins

The study revealed that at constant crude throughput, gasoline production will decrease for the
refiners studied. Additionally, blending ethanol will increase the required amount of pentane
removal from the gasoline pool in order to meet RVP specifications. Determining an economical
disposition for the excess pentanes will be an additional challenge for refiners. While there is no
simple processing alternative that can eliminate the shortfall in gasoline production caused by an
MTBE ban, several options can be used to minimize the loss.

The options studied are outlined below. Each option involved shutdown of the MTBE unit and
increases in the amount of alkylate available for gasoline blending.

   •   Send the incremental i-C4= to the alkylation unit.
   •   Add ZSM to FCC catalyst to produce more olefins for alkylation.
   •   Separate FCC C5 olefins for additional alkylate production.

The study assumes that ethanol would be the only acceptable oxygenate if the mandate were to
persist. To test the effect of ethanol in the gasoline pool, each processing alternative was studied
without ethanol blending, in addition to a case with a 2 wt % oxygen minimum.




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The cases evaluated for each refinery are described below.

                                        TABLE 2
                                   CASE DESCRIPTIONS

    Case          Description                                     Oxygen

    I             Base Case with MTBE allowed                     2 wt % min. (as MTBE)
    II-A          Incremental i-C4 Olefins to Alkylation          2 wt % min. (as Ethanol)
    II-B          Incremental i-C4 Olefins to Alkylation          No Oxygen
    III-A         Case II with ZSM addition to FCC                2 wt % min. (as Ethanol)
    III-B         Case II with ZSM addition to FCC                No Oxygen
    IV-A          Case II with C5 olefins to Alkylation           2 wt % min. (as Ethanol)
    IV-B          Case II with C5 olefins to Alkylation           No Oxygen

Each case involves modifications to the refinery flow scheme and additional equipment.
Subsequently, the refinery capital and operating costs increase for each alternative. All of the
cases require expanding the alkylation unit and the associated mercaptan removal and selective
hydrogenation units. A depentanizer must be added to reject pentanes from the light straight run
(LSR) in order to compensate for the increased RVP in each case that uses ethanol.

Purvin & Gertz evaluated each case using a new NLP (Non-linear Program) refinery modeling
technique that optimizes non-linear equations. The new refining models include the actual
CARB Predictive Model in the West Coast version and the EPA Complex Model in the Gulf
Coast version, both of which contain non-linear relationships. The refinery gasoline blending
model is constrained by the pollutant levels calculated from the Predictive or Complex Models.
Additional constraints include the cap limits for vapor pressure, sulfur, aromatics, benzene,
olefins, T50 and T90. The unusual non-linear effects of ethanol blending were also incorporated in
the refinery model. This modeling technique enables a higher degree of blending flexibility and
produces a more unique solution than models that incorporate only linear solving techniques. In
addition, the need for trial and error comparison against the Predictive or Complex Models is
eliminated, which significantly reduces the time to reach a solution for a given problem.


West Coast Refinery

The West Coast refinery case evaluations are based on a coking facility that processes 200,000
BPD of Alaska North Slope crude and produces 100% CARB Phase II gasoline (CaRFG II), jet
fuel, 30% CARB compliant diesel and 70% low sulfur diesel. The overall refinery flow scheme
is shown in Figure 1. While most West Coast refineries do produce some conventional gasoline,
the objective of the current study is to demonstrate the impact of producing compliant gasoline
within the constraints of an MTBE ban.




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                                     FIGURE 1
                    WEST COAST BASE CASE (CASE I) REFINERY FLOW

                                                              W EST COAST REFINERY
                                                            BASE CASE - CaRFG II
                                                                        SATURATE
                                                                                   G AS TRE ATING                                           FUEL GAS
                                                                           G AS
                                                                          PLANT    LPG TREATING
                                                                                                                                            PROPANE

                                                                                                                                            BUTA NE

      MET H ANO L

      MT BE                                                                                                       ISO M ER IZA TIO N
                     HY DR O G E N
                                                                                   NA PHT H A
      NAT URAL         PLANT
                                                                                      HDT
      G AS

                                                                                                                  REFORMER
                                                                                                    Splitter
                                     KEROSENE
                                      TR EA TE R
                                                                                                                          GASO LINE
                                      DIES EL HDT                                                                         TREATER
                                       (HIG H SEVER ITY)                                            Splitter
      CR UD E                                                                                                                               GASO LIN E
                                                                                                                     Depentanizer             (MTBE)


                                       DIS TILLA TE
                                     HYDROCRACKER                                                                         GASOL INE
                                                                                                                            HDT




                                          VG O                                                                                   H 2 SO 4
                                     HYD ROTREA TER
                                                                                                                                  ALKY



                                                                                                     SELECT IVE
                                                                                                        HDT               MTBE
                                                           LPG

                                                           N APH T HA

                                          FC C             LC O                                                                                JET
                                                           SLU R R Y

                                                                                                                                             DIES EL
                                                           LPG
                                                                                                                                             SLURRY
                                                           NAPH T HA
                                        DELAYE D

          P
                                                           LC G O
                                                                             LPG TREA TING
                                         COKER             HC GO

                                                                                                                                              COKE




The West Coast facility has an FCC unit operating between 75% and 80% conversion, a VGO
hydrotreater, a delayed coker, a distillate hydrocracking unit, a semi-regen reforming unit
producing 95 RON reformate, a C5/C6 isomerization unit, a high severity diesel hydrotreater,
FCC gasoline splitter, heavy FCC gasoline hydrotreating, MTBE unit and sulfuric acid alkylation
unit processing C3 and C4 olefins. The base capacities for each unit are shown in Table 3.




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                                      TABLE 3
                          WEST COAST BASE UNIT CAPACITIES

Unit                                  BPD      Unit                                      BPD
Crude                              200,000     FCC Gasoline Splitter                   32,270
Vacuum                              92,100     FCC Gasoline Depentanizer                    0
Saturate Gas Plant                  81,511     FCC Gasoline Treater                    21,278
Saturate LPG Treating               15,432     FCC Gasoline Hydrotreater               10,991
LSR Hydrotreating                   69,011     FCC C5 Extractive Treater                    0
LSR Splitter                        69,356     Selective Hydrogenation                 17,544
LSR Depentanizer                         0
LSR Isomerization                    8,649     Sulfuric Acid Alkylation (alkylate product)
                                                   =
MTBE                                 1,744      C3 alkylate                              6,075
                                                   =
Reformer                            40,000      C4 alkylate                              5,592
                                                   =
Kerosene Treater                    27,593      C5 alkylate (Includes C5 paraffins in feed) 0
Diesel Hydrotreater                 20,803     Total                                    11,667
Distillate Hydrocracker             37,635     Delayed Coker                            47,020
VGO Hydrotreater                    54,980     Hydrogen Plant, MMSCFD                       77
FCC                                 55,757     Sulfur Recovery, STPCD                      255
Unsaturate LPG Treater              17,232

Besides eliminating MTBE and adding ethanol in California, the cap limits for several other
compounds will also change as the new gasoline formulation must meet CARB Phase III
specifications. To incorporate these new regulations, the sulfur cap was reduced from 80 wppm
to 30 wppm, the benzene cap was reduced from 1.2% to 1.1%, and the RVP cap was increased
from 7.0 psi to 7.2 psi. The olefin content remains at 10%, the T50 remains at 220ºF and the T90
remains at 330ºF.




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The results of the West Coast refinery study are summarized in Table 4 and each case is
individually described below.

                                      TABLE 4
                            WEST COAST REFINERY RESULTS

      Gasoline Production                                Incremental    Variable      Process Capacity*
        Pool              Pentane      Ethanol Isobutane Alkylate      Operating
       Volume Change       Sales      (MTBE) Purchased Production        Costs                    New
Case    BPD        %       BPD          BPD       BPD       BPD      $/bbl of crude Expansion Additions
I      123,172                 0      (13,243)        0       Base        Base
II-A   103,516    -16.0    8,321        6,286     1,737     +2,466       +0.03        2,4,6,7      1
II-B   103,279    -16.2      196            0     1,765     +2,466       +0.01        2,4,6,7      1
III-A 101,833     -17.3    9,310        6,184     2,872     +4,386       +0.11        2,3,6,7      1
III-B 110,436     -10.3        0            0     1,518     +4,386       +0.10        2,4,6,7
IV-A 114,321       -7.2    1,471        7,815     5,473    +11,528       +0.16         4,6,7      1,5
IV-B 108,504      -11.9        0            0     1,352     +5,831       +0.22       2,3,4,6,7     5

       *Process Capacity Notes:

       1. LSR Depentanizer
       2. Isomerization
       3. Distillate Hydrocracking
       4. FCC Gasoline Hydrotreating
       5. FCC Gasoline Depentanizer
       6. Olefin Treating (mercaptan removal and selective hydrogenation)
       7. Alkylation

WC Case II-A (Incremental i-C4= to Alkylation, 2 wt% oxygen as ethanol minimum)

In this case the refinery MTBE unit is shutdown and the alkylation unit is expanded to process
the incremental i-C4 olefins. Additional supplies of isobutane are purchased. The shutdown of
the MTBE unit, discontinuation of MTBE purchase, and removal of pentanes from the gasoline
pool, are only partially offset by the increases from incremental alkylate production and ethanol
addition. The net reduction of gasoline production in this case is 16% and requires the addition
of a depentanizer, incremental increases in alkylation unit, isomerization and FCC gasoline
hydrotreating capacity. The variable operating costs are 0.03 $/bbl higher than the base case.

WC Case II-B (Case II-A with no ethanol)

Significantly less pentane is removed from the gasoline pool in this case compared to Case II-A.
However, because ethanol is not blended, the gasoline production is nearly equal. The biggest
difference in this case is that a smaller depentanizer and gasoline hydrotreater are required.
Significantly more isomerization capacity is needed to make up for the shortfall in octane. As
expected, the variable operating costs are 0.01 $/bbl higher than the base case.


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WC Case III-A (ZSM added to FCC, 2 wt% oxygen as ethanol minimum)

In this case, additional light olefins are produced by adding 4% ZSM-5 to the FCC catalyst. The
incremental C3 and C4 olefins are processed in an expanded alkylation unit. While the production
of olefins in the FCC increases, the production of FCC naphtha decreases. The pentane removal
from the gasoline pool is about equal to Case II-A. The increase in C4= alkylate blended into
gasoline causes the T50 of the pool to increase, which in turn requires that more of the heavy
FCC gasoline be sent to the hydrocracker. The net result is a slightly higher loss of gasoline
production than Case II-A with similar capital additions. Additional alkylation and hydrocracker
capacity are required. The variable operating costs are 0.11 $/bbl more than the base case.

WC Case III-B (Case III-A with no ethanol)

Very little pentanes must be removed in this case. And because the light hydrocarbons are
included in the gasoline blend, more of the heavy FCC gasoline can be blended against the T50
constraint. This results in a net gasoline production that is only 10.3% less than the base case.
The depentanizer can be eliminated and no increase in the hydrocracker capacity is necessary.
However, as in Case II-B, more isomerization capacity is required to offset the reduction in
octane. Additional FCC gasoline hydrotreating capacity is also required. The variable operating
costs are 0.10 $/bbl higher than the base case.

WC Case IV-A (Alkylation of FCC C5 Olefins, 2 wt% oxygen as ethanol minimum)

In this case, the FCC gasoline is further fractionated to isolate the C5s, which are treated to
remove mercaptan sulfur and diolefins and then sent to the alkylation unit. This case requires the
most complex modifications to the refinery, as shown in Figure 2. As compared to the base case,
the production of alkylate is doubled for this option. Because the amylenes are alkylated, the
RVP of the overall gasoline pool can be reduced and 80% less LSR pentanes must be removed
than in Case II-A. The amount of ethanol is increased to almost 10% in the premium gasoline,
allowing a net gasoline production that is only 7.2% below the base case, which is the best of all
the alternatives studied. The case requires an FCC gasoline depentanizer in addition to an LSR
depentanizer. More FCC gasoline treating is required, as well as a major alkylation unit
expansion. The variable operating costs are 0.16 $/bbl more than the base case.




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                                          FIGURE 2
                             WEST COAST CASE IV-A REFINERY FLOW


                                                                 W EST COAST REFINERY
                                                                  MODIFIED - CaRFG III
                                                                      SATURATE
                                                                                 GAS TRE ATING                                                FU EL GA S
                                                                         GAS
                                                                        PLANT    LPG TREA TING
                                                                                                                                              PR OPANE


                                                                                                                                               BUTA NE

                                                                                                                                              PENTANE
                                                                                                 Splitter
    ISO BUT AN E                                                                                                  Depentanizer
                   HY DR O G E N
                                                                                 NA P HT H A
    NAT URAL         PLANT
                                                                                    HD T                               ISO M ER IZA TIO N
    GAS



                                   KEROSEN E                                                                           REFORMER
                                    TR EATER

                                                                                                   EXTRACTIVE
                                    DIESEL HD T                                                     TREATER
                                     (HIGH SEVER ITY)                                                                     Depentanizer
    CR U D E                                                                                                                                  GASO LIN E
                                                                                                                                               (E thanol)
                                                                                                                               GA SO LINE
                                                                                                            Splitter           TR E AT E R
                                     DISTILLATE
                                   HYDROCRAC KER                                                                                 GA SO LINE
                                                                                                                                    HD T



                                        VG O
                                   HYD ROTREA TER                                                                                 H 2 SO 4
                                                                                                                                  ALKY

                                                                                                        SELECT IVE
                                                                                                           HDT
                                                        LPG

                                                        N APH T H A

                                        FC C            LC O                                                                                     JE T
                                                        SLU R RY

                                                                                                                                               DIES EL
                                                        LPG
                                                                                                                                               SLUR RY
                                                        N APH T H A
                                     DELAYED            LC G O



           P
                                                                           LPG TREA TING
                                      COKER             H C GO

                                                                                                                                                COKE




WC Case IV-B (Case IV-A with no ethanol)

Because the dilution and T50 effects from ethanol are eliminated in this case, additional FCC
gasoline must be rejected to the hydrocracker to avoid a high T50 of the pool. This reduces the
amount of amylene alkylation. However, since ethanol no longer contributes to the gasoline pool
RVP, there is no need to reject any of the pentanes. Therefore, gasoline production is less than in
Case IV-A, but is only 11.9% less than the base case. The LSR depentanizer is eliminated and
the extent of the changes in the FCC gasoline fractionation and treating is less than in Case IV-A.
As in Case IV-A, an FCC gasoline depentanizer is required along with additional mercaptan
removal and selective hydrogenation capacities. Additionally, more isomerization and
hydrocracker capacities are required. The variable operating costs for this case are 0.22 $/bbl
over the base case.




                                                                       AM-00-53
                                                                        Page 13
Gulf Coast Refinery

The conceptual Gulf Coast refinery case evaluations are based on a coking facility that processes
200,000 BPD of Isthmus crude and produces 100% Federal Reformulated gasoline, jet fuel, 30%
low sulfur diesel and 70% conventional diesel. The overall refinery flow scheme is shown in
Figure 3. In actuality, most of the Gulf Coast refineries currently produce significant volumes of
conventional gasoline. The conceptual refinery in this study produces all RFG to better
demonstrate the impact of producing compliant gasoline within the constraints of a possible
MTBE ban. Producing some conventional gasoline will lessen the impact on refinery
modifications required.

                                    FIGURE 3
                   GULF COAST BASE CASE (CASE I) REFINERY FLOW

                                                     GULF COAST REFINERY
                                                    BASE CASE - RFG PHASE II
                                                                                                                                      FUEL GA S
                                                                               GAS TREATING
                                                                    SATURATE
                                                                       GAS
                                                                      PLANT
                                                                                                                                       MIXED
                                                                               LPG TREA TING
                                                                                                                                        C3's

                                                                                                                                      BUTA NE

      METH ANO L
                                                                                        Splitter
      MT BE
                    HY DR OG E N
      NAT URAL        PLANT
      GAS                                                                                             NA P HT H A
                                                                                                         HD T       REFORMER

                                   KEROSENE
                                    TR EA TE R




      CR U D E                                                                                                                        GASO LIN E
                                    DIES EL HDT
                                                                                                                                        (MT BE)
                                                                                                                      GASOL INE
                                                                                                                      TREATER




                                        VG O                                                                               H 2 SO 4
                                   HYD ROTREA TER
                                                                                                                              ALKY



                                                                                                   SELECT IVE
                                                                                                      HDT             MTB E
                                                     LP G

                                                     N A PH T H A

                                       FC C          LC O                                                                                JE T
                                                     SLU R RY

                                                                                                                                       DIES EL
                                                     LP G
                                                                                                                                       SLURRY
                                                     NA PH T H A
                                     DELAYE D

          P
                                                     LC G O
                                                                         LPG TREATING
                                      COKER          HC GO

                                                                                                                                        COKE




The Gulf Coast facility contains an FCC unit operating at about 80% conversion, a VGO
hydrotreater, a delayed coker, CCR reforming unit producing 95 to 100 RON reformate, diesel
hydrotreater, MTBE unit and sulfuric acid alkylation unit processing C3 and C4 olefins. Many
Gulf Coast refineries have C3/C4 splitters and sell the C3s for recovery of petrochemical grade
propylene. The study uses current propane/propylene transfer prices to account for such C3 sales.
The model takes into account the price difference between gasoline and C3= sales to determine

                                                                    AM-00-53
                                                                     Page 14
how much, if any, C3= should be alkylated and included in the gasoline pool. The base capacities
for each unit are shown in Table 5.

                                     TABLE 5
                            GULF COAST BASE CAPACITIES

Unit                                  BPD      Unit                                      BPD
Crude                              200,000     FCC Gasoline Splitter                        0
Vacuum                              79,960     FCC Gasoline Depentanizer                    0
Saturate Gas Plant                  55,565     FCC Gasoline Treater                    37,442
Saturate LPG Treating                6,403     FCC Gasoline Hydrotreater                    0
LSR Hydrotreating                   32,641     FCC C5 Extractive Treater                    0
LSR Splitter                        51,867     Selective Hydrogenation                 19,706
LSR Depentanizer                         0
LSR Isomerization                        0     Sulfuric Acid Alkylation (alkylate product)
                                                   =
MTBE                                 1,955      C3 alkylate                                  0
                                                   =
Reformer                            32,805      C4 alkylate                              6,271
                                                   =
Kerosene Treater                    26,960      C5 alkylate (Includes C5 paraffins in feed) 0
Diesel Hydrotreater                 45,495     Total                                     6,271
Distillate Hydrocracker                  0     Delayed Coker                            35,660
VGO Hydrotreater                    61,990     Hydrogen Plant, MMSCFD                       21
FCC                                 61,990     Sulfur Recovery, STPCD                      348
Unsaturate LPG Treater              18,902

The requirements for producing EPA Reformulated gasoline are less restrictive than that for
CARB Phase II or Phase III gasoline. Consequently, the impact of a possible MTBE ban is
severe for a Gulf Coast refiner, but less than that for the West Coast refiner.




                                          AM-00-53
                                           Page 15
The results of the Gulf Coast refinery study are shown in Table 6 and each case is individually
described below.
                                           TABLE 6
                           GULF COAST REFINERY RESULTS

      Gasoline Production                           Incremental    Variable     Process Capacity*
        Pool              Pentane Ethanol Isobutane Alkylate      Operating
       Volume Change       Sales  (MTBE) Purchased Production       Costs                  New
Case    BPD         %      BPD     BPD       BPD       BPD      $/bbl of crude Expansion Additions
I     103,455                  0 (10,500)        0       Base        Base
II-A   96,661      -6.6    5,706    7,626      849     +2,734       +0.07         6,7        1
II-B   99,319      -4.0        0        0    4,771     +8,585       +0.19         6,7        2
III-A  96,542      -6.7    6,250    8,631    1,338     +3,661       +0.08         6,7        1
III-B  95,478      -7.7      583        0    3,114     +6,546       +0.16         6,7       1,2
IV-A   99,901      -3.4    1,641    6,740    2,839     +7,993       +0.17         6,7       1,5
IV-B   97,330      -5.9        0        0    4,876    +11,108       +0.21         6,7       2,5

       *Process Capacity Notes:

       1. LSR Depentanizer
       2. Isomerization
       3. Distillate Hydrocracking
       4. FCC Gasoline Hydrotreating
       5. FCC Gasoline Depentanizer
       6. Olefin Treating (mercaptan removal and selective hydrogenation)
       7. Alkylation

GC Case II-A (Incremental i-C4= to Alkylation, 2 wt% oxygen as ethanol minimum)

The base case Gulf Coast refinery sells the C3 olefins, converts the i-C4= in the MTBE unit, and
alkylates only the n-C4 olefins. In Case II-A the MTBE unit is shutdown and the incremental i-C4
olefins are processed in an expanded alkylation unit. Based on the economic evaluation
performed within the model, all of the C3= is sold in this case. As was the case for the West
Coast refinery, the shutdown of the MTBE unit, discontinuation of MTBE purchase and removal
of pentanes from the gasoline pool are only partially offset by the increase in alkylate production
and ethanol addition.

The C4= alkylate T50 is approximately 232°F, compared to about 212°F for a mixed C3=/C4=
alkylate. As a result, ethanol was added to both regular and premium grades at volumes higher
than that required to meet the minimum oxygen content in order to depress the blended T50. The
net gasoline production in this case is 6.6% less than the base case. The addition of a
depentanizer and incremental increases in alkylation unit capacity are required. The variable
operating costs increase by 0.07 $/bbl over the base case as a result of the changes. This increase
is higher on a percentage basis than it would be for the West Coast refiner because the base costs
are lower for the Gulf Coast refiner.


                                            AM-00-53
                                             Page 16
GC Case II-B (Case II-A with no ethanol)

No pentane removal is required in this case. The removal of ethanol causes a serious octane
shortage and the percentage of premium gasoline in the pool is reduced from 22 to 10% even
though isomerization capacity was added and some of the C3= was alkylated. The gasoline
production is higher than in Case II-A and is only 4% lower than the base case. Significant
isomerization capacity is needed to make up for the shortfall in octane. As expected the variable
operating costs are highr than Case II-A at 0.19 $/bbl over the base case.

GC Case III-A (ZSM added to FCC, 2 wt% oxygen as ethanol minimum)

In this case, additional light olefins are produced by adding 4% ZSM-5 to the FCC catalyst. The
incremental C4 olefins are processed in an expanded alkylation unit and the additional C3 olefins
are sold. While the production of olefins in the FCC increase, the production of FCC naphtha
decreases. Since the C3= produced in the FCC unit is sold instead of being alkylated, there is no
increase in gasoline production as a result. The net result is slightly less gasoline production
compared to Case II-A. The capital additions are similar to Case II-A. Addition of a LSR
depentanizer is required. The variable operating costs are 0.08 $/bbl more than the base case.

GC Case III-B (Case III-A with no ethanol)

Considerably less pentanes must be removed than in Case III-A. A small portion of the C3= is
alkylated and added to the gasoline pool. However, eliminating ethanol lowers the volume of
gasoline produced to slightly less than in Case III-A. The net gasoline production is 7.7% less
than the base case. By eliminating ethanol, the percentage of premium gasoline in the pool is
only 10% despite adding an isomerization unit. The variable operating costs are 0.16 $/bbl more
than the base case.

GC Case IV-A (Alkylation of FCC C5 Olefins, 2 wt% oxygen as ethanol minimum)

The FCC gasoline is fractionated to remove the C5s, which are then treated and sent to the
alkylation unit. All of the propylene produced is sold. This case requires the most complex
modifications to the refinery, as shown in Figure 4. Because the amylenes are alkylated, the RVP
of the gasoline pool can be reduced and less pentane must be removed than in the other Gulf
Coast cases. The amount of ethanol is increased to 9.5% in the premium gasoline. The net
gasoline production is only 3.4% below the base case, which is the best of all the alternatives
studied. The case requires an FCC gasoline depentanizer and an LSR depentanizer. C5 mercaptan
removal and selective hydrogenation capacity are required as well as a major alkylation unit
expansion. The variable operating costs are 0.17 $/bbl more than the base case.




                                           AM-00-53
                                            Page 17
                                         FIGURE 4
                            GULF COAST CASE IV-A REFINERY FLOW

                                                              GULF COAST REFINERY
                                                                MODIFIED - RFG II
                                                                     SATURATE
                                                                                GAS TRE ATING                                                 FUEL GA S
                                                                        GAS
                                                                       PLANT    LPG TREA TING
                                                                                                                                              MIXED C3


                                                                                                                                               BUTA N E

                                                                                                                                              PENTANE
                                                                                                Splitter
      ISO BUT AN E                                                                                            Depentanizer
                     HY DR OG E N
                                                                                NA P HT H A
      NAT URAL         PLANT
                                                                                   HD T                             ISO M ER IZA TIO N
      GAS



                                    KEROSENE                                                                        REFORMER
                                     TR EA TE R




      CR U D E                                                                                    EXTRACTIVE                                  GASO LIN E
                                      D IES EL HDT
                                                                                                   TREATER
                                                                                                                       Depentanizer            (E thanol)



                                                                                                                             GA SO LINE
                                                                                                                             TR E AT E R




                                          VG O
                                    H YD ROTR EA TER                                                                               H 2 SO 4
                                                                                                                                    ALKY

                                                                                                       SELECT IVE
                                                                                                          HDT
                                                       LP G

                                                       NA PH T H A

                                        FC C           LC O                                                                                      JE T
                                                       SLU R R Y

                                                                                                                                               D IES EL
                                                       LP G
                                                                                                                                               SLURR Y
                                                       NA PH T H A
                                       DELAYE D        LC G O
                                                                          LPG TREA TING


          P
                                        COKER          HC GO

                                                                                                                                                COKE




GC Case IV-B (Case IV-A with no ethanol)

Removal of ethanol creates a problem for blending the C5 alkylate because the T50 depression
characteristics of ethanol cannot be taken advantage of to reduce the overall pool T50. Propylene
is alkylated owing to the shortfall in octane. The alkylation unit charge is the highest for this case
at almost double that in the base case. Owing to the elimination of the ethanol, there is no need to
reject any of the pentanes. The gasoline production is less than in Case IV-A, and represents a
5.9% reduction from the base case. The LSR depentanizer is eliminated and isomerization
capacity is required to make up for the loss of ethanol. The variable operating costs for this case
are 0.21 $/bbl over the base case.




                                                                     AM-00-53
                                                                      Page 18
THE ROLE OF ALKYLATE

As refiners investigate options to make up for the shortfall in gasoline production due to the
removal of MTBE, increasing alkylation capacity continues to be an attractive option. For each
of the cases investigated for this study, STRATCO reviewed the required process modifications
determined by Purvin & Gertz, and investigated their impact on refinery alkylation unit
operations. STRATCO’s evaluation assumes standard design criteria for the alkylation unit. In
every case, STRATCO assumed that the unit configuration would include a depropanizer,
deisobutanizer and debutanizer.

For both the West Coast and Gulf Coast refiners, additional Contactor™ reactors were required
in each case to process the olefin feeds at the optimum reaction conditions. Fractionation and
refrigeration capacity analyses would also be required. Adding propylene feed to the unit greatly
affected the fractionation requirements of the depropanizer. As expected, incremental propylene
had a greater affect on compressor requirements, than did additional butylenes or amylenes.

For both refiners in this study, STRATCO assumed typical design requirements for the unit
modifications. For an actual revamp, STRATCO would optimize the design to minimize
modifications of the refiner’s existing equipment.


West Coast Refinery

The table below describes the impact on alkylation unit operations and alkylate properties for
each West Coast refinery case.

                                   TABLE 7
                     WEST COAST REFINERY ALKYLATION UNIT

                  Alkylate,       Olefin      Acid Use,    Alkylate       Octane,
        Case        BPD           Feed          TPD        RVP, psi      (R+M)/2        Notes
        I          11,667         C3/C4         109          4.0           93.4          1, 3
        II-A       14,133         C3/C4         114          4.0           93.5          2, 3
        II-B       14,133         C3/C4         114          4.0           93.5          2, 3
        III-A      16,053         C3/C4         136          4.0           93.4          2, 3
        III-B      16,053         C3/C4         136          4.0           93.4          2, 3
        IV-A       23,195        C3/C4/C5       149          6.9           91.7          2, 4
        IV-B       17,498        C3/C4/C5       127          5.4           92.6          2, 4

       Notes:
       1
         C4 feed olefins are supplied as MTBE raffinate
       2
         C4 feed olefins are supplied as mixed butylenes
       3
         Acid consumption based on spending range of 99.5 – 90.0 wt%, optimum reaction conditions,
       and contaminant free feed.
       4
         Acid consumption based on spending range of 99.5 – 87.0 wt%, optimum reaction conditions,
       and contaminant free feed.


                                            AM-00-53
                                             Page 19
In determining alkylate properties and acid consumption, STRATCO assumed segregated olefin
processing would be used in each instance. Separately processing different olefin types can have
significant benefits in terms of acid consumption and alkylate octane.

The acid consumption rates shown in Table 7, are based on a fresh acid strength of 99.5 wt% and
do not account for the effect of contaminants in the unit feed stream. In commercial application,
contaminants will consume acid and increase overall unit acid consumption. The required fresh
acid rate for a unit will depend on actual contaminant levels and the fresh acid strength.

Compared to the incremental alkylate production for cases II, III and IV, acid consumption
increases were modest. The small changes in acid consumption can be attributed to the
isobutylene present in the feed when the MTBE unit is shut down. The reaction intermediates, or
sulfates, formed from n-butylene are relatively stable and those from propylene are very stable.
These sulfates dilute the acid in the reaction zone, requiring higher acid makeup rates. However,
isobutylene is highly reactive with these sulfates, producing more alkylate and freeing up more
acid. In Case IV, alkylating amylenes separately in the final stage allows lower acid spending
strengths and results in considerable additional acid savings.

Figure 5 below shows the percent change in capacity and operating costs for each case as
compared to the base case. For the West Coast refiner, increases in operating costs were small
relative to the corresponding increase in alkylate capacity.

                                                                   FIGURE 5
                                                             WEST COAST REFINERY
                                                 ALKYLATE PRODUCTION AND UNIT OPERATING COSTS

                                          100%


                                          90%


                                          80%
     % Change from Base Case (Case I) .




                                          70%


                                          60%


                                          50%


                                          40%


                                          30%


                                          20%


                                          10%


                                           0%
                                                   WC-IIA   WC-IIB          WC-IIIA           WC-IIIB    WC-IVA   WC-IVB

                                                                 Alkylate Production   Operating Costs


                                                                            AM-00-53
                                                                             Page 20
Figure 6 shows the percent change in utility, chemical and total operating costs for each case as
compared to the base case. In most of the cases, decreased acid consumption on a per barrel basis
offset increased utility costs. Operating costs per barrel of alkylate decreased incrementally as
more butylenes and amylenes were fed to the unit.


                                                              FIGURE 6
                                                        WEST COAST REFINERY
                                           ALKYLATION OPERATING COSTS PER BARREL ALKYLATE

                                            WC-IIA              WC-IIB         WC-IIIA           WC-IIIB            WC-IVA           WC-IVB
                                    10%


                                     5%


                                     0%
 .
 % Change from Base Case (Case I)




                                    -5%


                                    -10%


                                    -15%


                                    -20%


                                    -25%


                                    -30%


                                    -35%

                                                     Utility Costs per bbl   Chemical Costs per bbl        Operating Costs per bbl




                                                                                AM-00-53
                                                                                 Page 21
Gulf Coast Refinery

STRATCO also evaluated the cases presented for a Gulf Coast refiner. The impact on the
alkylation unit for this refiner is shown below.

                                    TABLE 8
                      GULF COAST REFINER ALKYLATION UNIT

                   Alkylate,      Olefin      Acid Use,     Alkylate       Octane,
        Case         BPD          Feed          TPD         RVP, psi      (R+M)/2        Notes
        I            6,271          C4           44           4.0           96.0          1, 3
        II-A         9,005          C4           44           4.0           95.4          2, 3
        II-B        14,856        C3/C4         117           4.0           93.7          2, 3
        III-A        9,932          C4           47           4.0           95.4          2, 3
        III-B       12,817        C3/C4          84           4.0           94.4          2, 3
        IV-A        14,264        C4/C5          60           6.7           93.0          2, 4
        IV-B        17,379       C3/C4/C5        95           6.2           92.6          2, 5

       Notes:
       1
         C4 feed olefins are supplied as MTBE raffinate
       2
         C4 feed olefins are supplied as mixed butylenes
       3
         Acid consumption based on spending range of 99.5 – 90.0 wt%, optimum reaction conditions,
       and contaminant free feed.
       4
         Acid consumption based on spending range of 99.5 – 87.0 wt%, optimum reaction conditions,
       and contaminant free feed.
       5
         Acid consumption based on spending range of 99.5 – 88.0 wt%, optimum reaction conditions,
       and contaminant free feed.

Due to the effect of propylene sales on the Gulf Coast, there is a wider range of outcomes for the
different alkylation unit operating cases. Again, for cases that had propylene and amylene feeds,
STRATCO estimated acid consumption and alkylate properties assuming that propylene,
butylenes, and amylenes would be processed separately. The acid consumption rates shown in
Table 8, are based on a fresh acid strength of 99.5 wt% and do not account for the effect of
contaminants in the unit feed stream. In commercial application, contaminants will consume acid
and increase overall unit acid consumption. The required fresh acid rate for a unit will depend on
actual contaminant levels and the fresh acid strength.




                                            AM-00-53
                                             Page 22
In Figure 7 the percent change in capacity and operating costs from the base case is shown for
each alternative. For the Gulf Coast refiner, the increase in operating costs was higher when
propylene was fed to the alkylation unit.

                                                                FIGURE 7
                                                          GULF COAST REFINERY
                                              ALKYLATE PRODUCTION AND UNIT OPERATING COSTS

                                       200%


                                       180%


                                       160%
  % Change from Base Case (Case I) .




                                       140%


                                       120%


                                       100%


                                       80%


                                       60%


                                       40%


                                       20%


                                        0%
                                              GC-IIA   GC-IIB        GC-IIIA           GC-IIIB          GC-IVA   GC-IVB

                                                                Alkylate Production   Operating Costs




                                                                     AM-00-53
                                                                      Page 23
As shown in Figure 8, adding propylene to the unit had a noticeable impact on acid consumption
and utility costs for the cases investigated. Conversely, amylene feeds lowered per barrel
operating costs.

                                                                 FIGURE 8
                                                           GULF COAST REFINERY
                                              ALKYLATION OPERATING COSTS PER BARREL ALKYLATE

                                               GC-IIA           GC-IIB           GC-IIIA           GC-IIIB            GC-IVA           GC-IVB
                                       40%


                                       30%


                                       20%
  % Change from Base Case (Case I) .




                                       10%


                                        0%


                                       -10%


                                       -20%


                                       -30%


                                       -40%


                                       -50%

                                                        Utility Costs per bbl   Chemical Costs per bbl       Operating Costs per bbl




BENEFITS OF SEGREGATED OLEFIN PROCESSING

The alkylate properties and acid consumption estimates presented in this paper assume that the
C3 and/or C5 olefins are processed separately. To maximize the benefits of segregated processing,
STRATCO assumed 100% propylene operation for the initial acid stage of alkylation for any
case including a C3 feed. Alkylation of mixed olefins can lead to undesirable reactions between
olefins and reaction intermediates producing heavy alkylate isomers, which lower alkylate
quality. Additionally, processing olefins in separate reaction zones can reduce acid consumption.

Under typical butylene alkylation conditions, propylene and amylenes produce a much lower
octane alkylate than butylenes especially when processed together. For example, the West Coast
refiner case IV-B (with a unit feed of C3=, C4=s and C5=s) gives a 1.5 (± 0.5) lower octane number
when processing all olefins in a common reaction zone, versus processing the olefins separately.

                                                                                 AM-00-53
                                                                                  Page 24
Propylene and amylenes also consume sulfuric acid at a higher rate than butylenes. However, by
taking advantage of segregated olefin processing, octane and acid consumption penalties can be
minimized.

For segregated olefin feeds, reaction zone conditions are tailored to optimize alkylate quality and
acid consumption for each olefin type. These operating variables include isobutane
concentration, olefin space velocity, temperature, and acid strength. Mixed butylene alkylation is
typically carried out with a 9:1 isobutane to olefin volume ratio at 45ºF and an olefin space
velocity of 0.3 hr-1. Mixed butylenes produce maximum alkylate octanes when alkylated at acid
strengths of 92 – 94 wt %.

Favorable reactor conditions for propylene alkylation include higher acidity and isobutane
concentration, and lower olefin space velocity than for butylenes. Propylenes are best fed to the
high strength reactors in the unit to reduce overall acid consumption. This is due to the stability
of propyl sulfate reaction intermediates formed in the reaction zone. Propyl sulfates are very
stable compared to the sulfate intermediates formed with butylenes or amylenes. This stability
leads to a buildup of propyl sulfates in the acid phase and consequently appears to result in high
acid consumption. However, STRATCO research indicates that these sulfates can be recovered,
boosting alkylate yield and reducing acid consumption. This is achieved by sending the acid
from the propylene stage to another alkylation stage where isobutane and non-propylene olefins
are present. In this downstream reactor, the propyl sulfates will react to form alkylate and release
the acid to act as a catalyst for additional alkylation. In a unit with staged acid flow, if propylene
is fed only to the higher acid strength Contactor reactors, the propyl sulfates will react by the
time the acid is withdrawn from the lowest strength settlers. This downstream reaction of propyl
sulfates manifests as a drop in apparent acid consumption in the lower strength acid stages.

The preferred operating conditions for alkylating amylenes are similar to butylene alkylation.
However, the octane and acid consumption response to different operating conditions is not
necessarily the same. In particular, amylene alkylation is more affected by reaction temperature
and isobutane concentration. Additionally, the optimum acid strength for amylene alkylation is
lower than that for butylene alkylation, and the acid can be spent at lower strength without any
added risk of an acid runaway in the unit.5 Segregating the olefins and processing the amylenes
in the lowest acid strength reaction zone can lead to significant savings in acid costs.

In addition to optimizing individual reaction zone conditions, segregated processing eliminates
interactions between different olefins in the alkylation process, which can affect acid
consumption and/or octane. Non-linear trends are common for propylene blends with butylenes
or amylenes.6 Of particular importance for refiners returning to a mixed butylene feed, from an
MTBE raffinate feed, segregated processing of propylene and butylenes can minimize alkylate
quality penalties resulting from the interaction of isobutylene and propyl sulfates. The potential
benefits of removing propylene from other olefins depends on the overall feed composition for a
specific alkylation unit.

5
  J. Randall Peterson, David C. Graves, Ken Kranz and David M. Buckler. “Improved Amylene Alkylation
Economics.” NPRA Annual Meeting 1999.
6
  Ken Kranz and David C. Graves. “Olefin Interactions in Sulfuric Acid Catalyzed Alkylation.” 215th National
Meeting, American Chemical Society 1998.

                                                   AM-00-53
                                                    Page 25
Alkylate quality and operating costs can often be improved when different olefins are alkylated
separately. Reacting different olefin feeds in separate reactors can reduce acid consumption costs
and improve overall alkylate quality by optimizing reactor conditions for each olefin type and
avoiding undesirable interactions between olefins. Depending on the refiner’s overall economic
objective – reduced acid consumption, improved octane, or both – STRATCO can optimize the
processing scheme for a particular olefin feed composition.

STRATCO’s on-going research continues to present new information regarding optimum
processing conditions and configurations for various olefin feeds. This growing information base
allows STRATCO to provide the best possible alkylation unit design.


SUMMARY

Refiners on the West Coast will soon be faced with the challenge of making MTBE-free
gasoline. Additionally, domestic refiners outside of this region may face similar restrictions in
the future.

Based on the results of this study, refiners may have difficulty maintaining current gasoline
production rates without increased crude throughput. Additionally, refiners’ options are
complicated by the ongoing debate on the minimum oxygen requirement. Obviously, no matter
what the outcome, refiners will have to show creativity in filling the volume and octane void that
will result from removing MTBE. As refiners investigate their alternatives, alkylate continues to
be an excellent product for replacing octane barrels in the gasoline pool.

Alkylating additional propylene and amylenes can help refiners increase gasoline production. By
utilizing the benefits of segregated olefin processing, STRATCO can help refiners process these
additional olefins economically and effectively to produce quality alkylate.




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REFERENCES
API. “Ten Frequently Asked Questions about MTBE in Water.” API Soil & Groundwater Research Bulletin No. 3
     March 1998. (Available on the internet at http:/www.api.org/ehs)
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Blue Ribbon Panel on Oxygenates in Gasoline. “Panel Calls for Action to Protect Water Quality while Maintaining
     Air Benefits from National Clean Burning Gas.” Press Release July 27, 1999.
Bureau of National Affairs, Inc. “Groups Align Behind MTBE Reductions, Urge Congressional Action on
     Oxygenates.” Washington D.C., February 7, 2000.
Bureau of National Affairs, Inc. “Citing MTBE Threat to Lake Tahoe, State Supports Personal Watercraft Ban.”
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California Air Resources Board. “The California Reformulated Gasoline Phase 3 Amendments Title 13, California
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     January 21, 2000. (Available on the internet at http:/www.dhs.ca.gov/ps)
California Environmental Protection Agency Air Resources Board. “ARB Bans MTBE and Modifies Rules for
     Cleaner Burning Gasoline.” News Release December 9, 1999. (Available on the internet at
     http:/www.arb.ca.gov/newsrel/nr120999.htm)
EPA. “Fact Sheet: Drinking Water Advisory: Consumer Acceptability Advice and Health Effects Analysis of
     Methyl Tertiary-Butyl Ether.” Publication # EPA-822-F-97-009 December 1997. (Available on the internet at
     http:/www.epa.gov)
EPA. “MTBE Fact Sheet #3 Use and Distribution of MTBE and Ethanol.” Publication # EPA-610-F-97-016 January
     1998. (Available on the internet at http:/www.epa.gov)
Kranz, Ken and David C. Graves. “Olefin Interactions in Sulfuric Acid Catalyzed Alkylation.” 215th National
     Meeting, American Chemical Society 1998.
Northeast States for Coordinated Air Use Management. “Northeast States Announce Unified MTBE Strategy.” Press
     Release January 19, 2000. (Available on the internet at http:/www.NESCAUM.org)
Northeast States for Coordinated Air Use Management. “RFG/MTBE Findings & Recommendations.” August 1999.
Peterson, J. Randall, David C. Graves, Ken Kranz, and David M. Buckler. “Improved Amylene Alkylation
     Economics.” Annual Meeting NPRA March 1999.
Pryor, Pam. “Alkylation Current Events.” STRATCO Alkylation Seminar September 1999.
Pryor, Pam. “Strategies for Avoiding Octane Deficits.” World Fuels Conference October 1999.
State of New Hampshire Department of Environmental Services Public Information & Permitting Office. “State
     Seeks Waiver from Federal Gasoline Requirements Water Quality Benefits Cited.” Press Release July 21, 1999.
     (Available on the internet at http:/www.des.state.us/press9.htm)
United States Congress. Bill Summary & Status for the 106th Congress. (Available on the internet at
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Vautrain, John H. “California Refiners Anticipate Broad Effects of Possible State MTBE Ban.” Oil & Gas Journal
     Jan. 18, 1999: 18-22.
William Scott. “Challenges of Producing California Cleaner Burning Gasoline.” Clean Fuels 2000 Conference.




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