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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 4William 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

Coast Gulf Coast

Octane (R+M)/2

Sulfur wppm

RVP psi

A/B/O1 vol %

T50 ºF

T90 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 (Hydrotreated)

4.6 0.0 81-83 8 7.6 23.0/ 0.9/ 10.0 200 270

340-430 FCC Gasoline (Hydrotreated)

4.3 0.0 82-84 50 0.5 48.0/ 0.0/ 0.0 300 360

MTBE 11.7 11.7 110 5 8.0 0.0/ 0.0/ 0.0 130 132 100.0 100.0

Notes: 1A/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

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.

SATURATEGAS

PLANT

GAS TREATING

LPG TREATING

DIESEL HDT(HIGH SEVERITY)

KEROSENETREATER

DISTILLATEHYDROCRACKER

FCC

DELAYEDCOKER

COKE

LCGO

VGOHYDROTREATER

LPG

NAPHTHA

HC GO

LCO

LPG

NAPHTHA

SLU RRY

SLURRY

DIESEL

JET

NAPHTHAHDT

REFORMER

H2SO4ALKY

SELECTIVEHDT

PROPANE

GASOLINE

FUEL GAS

NATURALGAS

CRUDE

ISOMERIZATION

GASOLINETREATER

WEST COAST REFINERYBASE CASE - CaRFG II

BUTANE

Splitter

Depentanizer

LPG TREATING

(MTBE)

Splitter

GASOLINEHDT

HYDROGENPLANT

METHANOL

MTBE

MTBE

P

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TABLE 3 WEST COAST BASE UNIT CAPACITIES

Unit BPD Unit BPDCrude 200,000 FCC Gasoline Splitter 32,270Vacuum 92,100 FCC Gasoline Depentanizer 0Saturate Gas Plant 81,511 FCC Gasoline Treater 21,278Saturate LPG Treating 15,432 FCC Gasoline Hydrotreater 10,991LSR Hydrotreating 69,011 FCC C5 Extractive Treater 0LSR Splitter 69,356 Selective Hydrogenation 17,544LSR Depentanizer 0 LSR Isomerization 8,649 Sulfuric Acid Alkylation (alkylate product) MTBE 1,744 C3

= alkylate 6,075Reformer 40,000 C4

= alkylate 5,592Kerosene Treater 27,593 C5

= alkylate (Includes C5 paraffins in feed) 0Diesel Hydrotreater 20,803 Total 11,667Distillate Hydrocracker 37,635 Delayed Coker 47,020VGO Hydrotreater 54,980 Hydrogen Plant, MMSCFD 77FCC 55,757 Sulfur Recovery, STPCD 255Unsaturate 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 AdditionsI 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

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.

P

SATURATEGAS

PLANT

GAS TREATING

LPG TREATING

DIESEL HDT(HIGH SEVERITY)

KEROSENETREATER

DISTILLATEHYDROCRACKER

FCC

DELAYEDCOKER

COKE

LCGO

VGOHYDROTREATER

LPG

NAPH THA

HCGO

LCO

LPG

NAPH THA

SLU R RY

SLURRY

DIESEL

JET

NAPHTHAHDT

REFORMER

H2SO4ALKY

SELECTIVEHDT

PROPANE

GASOLINE

FUEL GAS

NATURALGAS

CRUDE

ISO MERIZATION

GASOLINETREATER

WEST COAST REFINERYMODIFIED - CaRFG III

BUTANE

Splitter

Depentanizer

LPG TREATING

(Ethanol)

Splitter

GASOLINEHDT

HYDROGENPLANT

ISOBUTANE

EXTRACTIVETREATER

Depentanizer

PENTANE

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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

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

SATURATEGAS

PLANT

GAS TREATING

LPG TREATING

DIESEL HDT

KEROSENETREATER

FCC

DELAYEDCOKER

COKE

LC GO

VGOHYDROTREATER

LPG

NAPH THA

HC GO

LC O

LPG

NAPH THA

SLU R RY

SLURRY

DIESEL

JET

NAPHTHAHDT REFORMER

H2SO4ALKY

SELECTIVEHDT

MIXEDC3's

GASOLINE

FUEL GAS

NATURALGAS

CRUDE

GASOLINETREATER

GULF COAST REFINERYBASE CASE - RFG PHASE II

BUTANE

Splitter

LPG TREATING

(MTBE)

HYDROGENPLANT

METHANOL

MTBE

MTBE

P

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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 BPDCrude 200,000 FCC Gasoline Splitter 0Vacuum 79,960 FCC Gasoline Depentanizer 0Saturate Gas Plant 55,565 FCC Gasoline Treater 37,442Saturate LPG Treating 6,403 FCC Gasoline Hydrotreater 0LSR Hydrotreating 32,641 FCC C5 Extractive Treater 0LSR Splitter 51,867 Selective Hydrogenation 19,706LSR Depentanizer 0 LSR Isomerization 0 Sulfuric Acid Alkylation (alkylate product) MTBE 1,955 C3

= alkylate 0Reformer 32,805 C4

= alkylate 6,271Kerosene Treater 26,960 C5

= alkylate (Includes C5 paraffins in feed) 0Diesel Hydrotreater 45,495 Total 6,271Distillate Hydrocracker 0 Delayed Coker 35,660VGO Hydrotreater 61,990 Hydrogen Plant, MMSCFD 21FCC 61,990 Sulfur Recovery, STPCD 348Unsaturate 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.

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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 AdditionsI 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.

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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.

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FIGURE 4 GULF COAST CASE IV-A REFINERY FLOW

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.

P

SATURATEGAS

PLANT

GAS TREATING

LPG TREATING

DIESEL HDT

KEROSENETREATER

FCC

DELAYEDCOKER

COKE

LC GO

VGOHYDROTREATER

LPG

NAPHTHA

HC GO

LC O

LPG

NAPHTHA

SLUR RY

SLURRY

DIESEL

JET

NAPHTHAHDT

REFORMER

H2SO4ALKY

SELECTIVEHDT

MIXED C3

GASOLINE

FUEL GAS

NATURALGAS

CRUDE

ISOMERIZATION

GASOLINETREATER

GULF COAST REFINERYMODIFIED - RFG II

BUTANE

Splitter

Depentanizer

LPG TREATING

(Ethanol)

HYDROGENPLANT

ISOBUTANE

EXTRACTIVETREATER

Depentanizer

PENTANE

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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

Case

Alkylate, BPD

Olefin Feed

Acid Use, TPD

Alkylate RVP, psi

Octane, (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 3Acid consumption based on spending range of 99.5 – 90.0 wt%, optimum reaction conditions, and contaminant free feed. 4Acid consumption based on spending range of 99.5 – 87.0 wt%, optimum reaction conditions, and contaminant free feed.

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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

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

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

% C

hang

e fro

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ase

Cas

e (C

ase

I) .

Alkylate Production Operating Costs

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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

-35%

-30%

-25%

-20%

-15%

-10%

-5%

0%

5%

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

% C

hang

e fro

m B

ase

Cas

e (C

ase

I)

.

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

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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

Case

Alkylate, BPD

Olefin Feed

Acid Use, TPD

Alkylate RVP, psi

Octane, (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 3Acid consumption based on spending range of 99.5 – 90.0 wt%, optimum reaction conditions, and contaminant free feed. 4Acid consumption based on spending range of 99.5 – 87.0 wt%, optimum reaction conditions, and contaminant free feed. 5Acid 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.

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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

0%

20%

40%

60%

80%

100%

120%

140%

160%

180%

200%

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

% C

hang

e fro

m B

ase

Cas

e (C

ase

I) .

Alkylate Production Operating Costs

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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

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.

-50%

-40%

-30%

-20%

-10%

0%

10%

20%

30%

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

% C

hang

e fro

m B

ase

Cas

e (C

ase

I) .

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

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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.

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

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

Washington D.C., January 8, 1999. California Air Resources Board. “The California Reformulated Gasoline Phase 3 Amendments Title 13, California

Code of Regulations.” 45-Day Notice Version. California Department of Health Services. “California’s Drinking Water Standards for MTBE.” Last updated

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 http:/thomas.loc.gov)

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.