Robert H. Gilman
Akzo Chemicals Inc.
Houston
To reduce the financial impact of impending gasoline and diesel regulations, it will be necessary to reevaluate refinery unit operations in conjunction with innovative catalyst and process technology.
The challenge will be to comply with these regulations without excessive retail gasoline prices.
In addition, the industry will need to maintain profitability to remain competitive with other industries. Presently, industry experts predict that capital expenditure requirements for gasoline reformulation will exceed $20 billion.' Catalyst technology and operational changes will be needed to decrease the required capital for gasoline reformulation.
A study, based on recognized correlations, and pilot plant and commercial data from technical service work done by Akzo Chemicals Inc., was done to show how various processes and catalysts can be used to minimize the capital expenditures to produce reformulated gasoline. Although capital investment will be necessary to meet a reformulated gasoline slate by 1994, the investment could be just under $58 million for the 100,000-b/d refinery configuration used in the study.
BACKGROUND
The U.S. Congress is presently debating the reformulated gasoline specifications in the reauthorization of the 1970 Clean Air Act. Promulgation of this law is expected to occur in late 1990 with provisions coming into force beginning in 1992.
The Subcommittee on Environmental Protection is targeting a 50% reduction in ozone-forming and carbon monoxide emissions from cars and light duty trucks by the year 2000 .3 This coincides with the projected increase in gasoline volume, at 0.7% annually to 1995, and road octane, (R+M)/2, from 89.3 to 89 .8.4
These demands will have to be met without the conventional octane and volume boosters, butanes and tetraethyl lead (TEL), that were available in the early 1980's. This is the result of meeting the U.S. Environmental Protection Agency's (EPA) Phase 2 summertime volatility limits of 8 psi Rvp and the 95% phase-out of TEL in North America by 1992.
Furthermore, the mandated gasoline reformulation will include a reduction in high octane producing aromatics and light olefins.
A National Petroleum Refiners Association gasoline survey, completed in 1989, indicates that the U.S. gasoline pool contains, on average, 32% aromatics and 13% olefins.5 Therefore, the proposed standards represent a 10% reduction in aromatics and a three-fold reduction in light olefins.
A more stringent requirement will be a reduction in benzene to 0.8 vol %. Blended gasoline can contain up to 5% benzene.'
Major sources of aromatics in gasoline originate from catalytic reformers and fluid catalytic cracking units (FCCUs). Reformate contains up to 70% aromatics compared to 20-27% from the FCCU.
A major portion of the benzene in the gasoline is generated in the reformer. Primary sources of olefins are the FCCU and its propylene conversion units and coking units.
REFINERY OUTLOOK
The reformulated gasoline standards will prompt a change in the sources for gasoline. The amount of operational changes and capital expenditures will depend on the refinery type.
A refiner with downstream petrochemical facilities should have the flexibility to further process the refined products. Small refiners will likely choose to sell their gasoline to blending companies.
A mid-sized refiner without chemical facilities may have to spend substantial capital unless it decides to integrate with another refiner or petrochemical plant in close proximity.
The FCCU will continue its prominent role as the major contributor to the gasoline pool. However, its contribution will change by supplying more feedstock to units such as methyl tertiary butyl ether (MTBE) and alkylation. These units will contribute more to the gasoline pool because they produce gasoline with lower vapor pressure and virtually no aromatics and olefins. They also destroy light olefins that react with ozone.
Isomerization units will have to be built to increase the octane of the light straight-run (LSR). Also, it is possible that the front-end of the heavy straight-run will be isomerized, rather than reformed, to reduce benzene production.
Hydrogen processing will be critical in meeting stricter standards on transportation fuels while satisfying feed pretreatment requirements for various units. Therefore, the crude quality will determine how the hydrogen balance in a refinery is handled, depending on whether the reformer operates at reduced rates or hydrogen is imported.
REFORMER
It is apparent that the reformer will contribute less to the reformulated gasoline pool, based on the fact that the reformer generates up to 70 vol % aromatics, of which 5 vol % is benzene. The reduction can be accomplished by either reducing the reformer throughput and severity, or by extractive distillation.
Raising the initial boiling point (IBP) of the heavy straight-run (HSR) to 212 F. in the crude flash tower will remove a majority of the C7 naphthenes. This will lower benzene production to less than 1.5 vol % on low pressure units such as continuous catalytic reformers (CCR) or regenerative reformers, making it necessary to adjust severity to minimize further production of benzene from hydrocracking in the reformer.
This approach will decrease the octane enhancement of the LSR from the isomerization unit. Naphthenes are low octane performers and not converted in the isomerization unit.
However, some naphthenes, such as dimethyl cyclopentane and cyclohexane, possess (R + M)/2 octanes of 91 and 80, respectively. If an isomerization unit needs to be constructed, naphthenes represent nonconvertible feed which will increase the capital cost for increased capacity.
Also, changes in reformer operation will affect the plant-wide hydrogen balance. Therefore, the refinery will have to improve on hydrogen utilization,
Another alternative is to perform extractive distillation of the reformate to remove the aromatics. This will not affect the hydrogen supply. But the capital expenditure requirements and utility costs for extractive distillation will require attractive prices for light aromatics.
CATALYTIC CRACKING
The FCCU will continue to be the centerpiece of the refinery operation for two important reasons: It contributes more than 50% of the gasoline pool, and it is at the heart of the refinery and, therefore, influences unit operations for a majority of the units in the refinery.
For those reasons, the operation of the FCCU will be critical for producing reformulated gasoline. FCCU operations will need to be flexible, and they are governed by the unit's hardware, feed, and catalyst.
Of all of the FCCU operating variables, the refiner will have the most freedom in changing the catalyst. The catalyst must provide excellent coke selectivity while minimizing aromatics and olefin production because most refiners will choose to operate the FCCU in the overcrack mode.
Operating in the overcrack mode will tend to assure attractive octanes. The quality of the FCC feed and the catalyst's coke selectivity will determine the limits of overcracking.
FCC feed pretreatment will allow further overcracking and flexibility in handling poorer quality feeds. The level of feed pretreatment will be affected by the reduction in available hydrogen by reduced reformer operations. Stricter diesel specifications for sulfur and possibly aromatics will also put a drain on available hydrogen.
It is apparent that overcracking will be necessary to reduce bromine number by converting some olefins to LPG. Also, overcracking will be used to transalkylate benzene to xylenes.
In the 1980's, catalyst manufacturers provided octane-boosting catalysts to fill the octane void resulting from lead phase-out. This technology evolved into low nonframework alumina (NFA) zeolite catalysts possessing high silica-to-alumina ratios (SAR).
Low NFA catalysts generated even more attractive octanes and improved coke selectivity. The catalyst architecture best suited for gasoline reformulation will contain a high silica-to-alumina ratio (SAR) exchanged with rare earth and accompanied by a very selective matrix.
Rare-earth exchange not only improves activity maintenance, but it also promotes hydrogen transfer to convert olefins generated by primary cracking to paraffins. An active catalyst will generate high conversions at low riser temperatures and probably higher feed contaminant levels. This will be required to maximize gasoline and optimize branched and olefinic compound production.
Octane catalysts that exhibit low hydrogen transfer rates permit olefins from primary carbenium ions to rearrange and promote isomerization. Isomerization improves mid-cut octane performance.
Rare-earth promotion decreases bromine number and increases conversion. Besides long paraffinic chains, olefins in the high boiling fractions of the gasoline tend to crack to their front-end counterparts which possess higher octanes and are suitable for alkylation or etherification .6
At a constant riser temperature, rare-earth promotion reduces the amount of isobutylene generated by tending to make isobutane from isobutylene by hydrogen transfer. Also, it appears that rare earth promotes transalkylation at the higher conversions. Transalkylation converts benzene to alkylbenzenes, such as toulene and xylenes .6
A selective matrix and zeolite will be vital to overcracking because they reduce thermal cracking products such as coke and light gases. Because wet-gas compressor and air blower capacities will probably determine the amount of overcracking, both coke and fuel gas production should be minimized. A selective matrix can act as a metal trap to limit dehydrogenation, thereby lowering dry gas.
Low NFA zeolites and crystalline matrices favor C4 and heavier production. Both produce highly olefinic C4S that are attractive feeds for the alkylation and MTBE units.
ZSM-5 additives also can be utilized to increase the octane of the gasoline pool by improving the research octane number of the FCC gasoline while producing light olefins for alkylation. ZSM-5 converts the low-octane normal paraffins to lighter olefins. The small pore diameter prevents access to convert branched or ringed hydrocarbons.7
Besides proper catalyst selection, an improved feed nozzle and a high-efficiency reactor stripper can improve FCC yields and operation. Both can assist overcracking by reducing the coke generated in the FCC.
Air blower demands can be reduced, and thermal cracking can be minimized. The stripper can reduce the required air for burning coke by eliminating hydrocarbon carryover to the regenerator. This will also minimize the regenerator dense-phase temperature.
The feed nozzle should offer good radial distribution of the feed to provide well distributed feed-to-catalyst contact. It is suggested that higher velocity designs are more suited to this application.
Shortened riser contact times, obtained by modifying the riser dimensions, probably could lessen olefin and aromatic production.
A light paraffinic gas oil will allow for higher conversions. Heavier endpoint gas oils can be upgraded by hydrotreating to increase conversion due to coke and gas production. Hydrotreating the gas oil feed will reduce the coke precursors by saturation of polynuclear aromatic (PNA) compounds.
The FCCU should operate in the overcrack mode because downstream units, such as MTBE, alkylation, and isomerization units, will contribute more to the reformulated gasoline pool. The gasoline products from these units have attractive octanes and benefit gasoline composition relative to olefins, aromatics, and Rvp.
Overcracking should be performed with a high-activity catalyst and maximum cat-to-oil ratio while minimizing riser temperature. For the same catalyst type, temperature influences di-olefin production, a catalyst poison for downstream alkylation and MTBE units.
HYDROPROCESSING
Hydroprocessing is necessary to improve the final product quality of transportation fuels as well as pretreatment for certain catalytic units. As the reformer contribution lessens, the available hydrogen becomes increasingly scarce.
Therefore, hydrogen usage should be conservative. Hydrogen should be cascaded from the various hydrotreating units if this has not been done already.
Also, hydrotreating should be selective by more efficient fractionation and feed selection to the hydrotreater. For instance, a highly selective FCC catalyst possibly will allow either charging coker feed or operating the FCC pretreater in a less severe operation. In other words, feed pretreatment would reduce sulfur, nitrogen, and metals, but minimize aromatic saturation.
ALKYLATION
Alkylation will play a more prominent role in gasoline reformulation because alkylate possesses a low Rvp (4 psi) and virtually no olefins and aromatics. Also, alkylates generated from C3-C5 olefins are attractive for both sulfuric acid (H2SO4) and hydrofluoric acid (HF) processes.
Furthermore, the alkylation unit can convert photochemically reactive C5 olefins to an attractive gasoline-blending component. Alkylation unit throughput will increase due to the inclusion Of C5s and the operation of the FCC in the overcrack mode.
This will significantly increase the loading in the top section of the FCC debutanizer. Therefore, a depentanizer could be needed, or the debutanizer could be revamped with high-efficiency packing.
Proper control of the unsaturated gas plant deethanizer will reduce the debutanizer overhead's volume by minimizing hydrogen and lightends carryover.9
Also, the placement of an MTBE and/or tertiary amyl methyl ether (TAME) unit upstream of the alkylation unit will reduce the feed to the alkylation unit by 10%. MTBE and TAME production will remove isobutylenes (MTBE feed) and isoamylenes (TAME feed). These units take advantage of processing additional propylene and butylene.
Besides other benefits, MTBE requires a lower material cost than alkylate. This is dependent on the availability of methanol compared to isobutane.10
One commercial experience showed that sulfuric acid consumption rose 19% after the installation of an MTBE unit due to the carryover of methanol and various ethers.10 Industry experts believe that mild hydrogenation of the alkylation feed will be required to reduce acid consumption and acid-soluble oils (ASO) as well as converting butene-1 to butene-2. ASOs are an operational headache to strip out of the circulating acid and are a hazardous waste.
ETHERIFICATION UNITS
Oxygenates, commercially produced as methanol or ethanol ethers, are highly considered as substitutes to the light aromatics being removed from the gasoline. Primary reasons include: similar octanes to the light aromatics, attractive vapor pressures to replace butanes, and available oxygen to allow for complete combustion of CO to CO2-1
In 1988, an EPA waiver to the 1970 Clean Air Act allowed for 15% MTBE or 2.7 wt % oxygen in gasoline blends. That oxygen content is expected to be specified for reformulated gasoline. Corresponding oxygenate levels for 2.7 wt % oxygen in gasoline are: 15% for MTBE, 17% for ethyl tertiary butyl ether (ETBE), and 17% for TAME.'
Another waiver allows the blending of ethers up to 10% MTBE. A waiver has been applied for which would allow blending mixed ethers to 15%, as with MTBE.
MTBE is the only ether currently produced in the U.S. and comprised about 1.4% of the U.S. gasoline pool in 1988. There exists about 100,000 b/d of MTBE production capacity in North America along with about 29,000 b/d under construction and another 84,000 b/d under evaluation.1
MTBE is produced by reacting methanol with isobutylene.
Isobutylene generated from a typical refinery FCCU can produce 1,000-3,000 b/d of MTBE.
FCC catalyst selection can influence the production of isobutylene at the expense of its saturated counterparts, isobutane and n-butane.
ETBE and TAME are not produced in the U.S. ETBE production could be economical if the existing federal tax credit for ethanol used in fuel is applied to ethanol use in ETBE.
TAME is produced by reacting methanol with isoamylenes provided by the FCCU. TAME enjoys the benefit of high octane quality and low blending vapor pressure.
TAME raises octane 10 numbers and reduces Rvp from 16 psi of isoamylene to 1 psi for TAME. Also, TAME units are a means of removing photochemically reactive C5 olefins from gasoline."
Major concerns for etherification units are: alcohol and ether carryover to the alkylation unit, poisons to the alkylation acid catalyst," and future feedstock supply. Presently, isobutylene is in plentiful supply because of Canadian and Saudia Arabian production.
However, these sources will enjoy high demand by 1993 as worldwide alkylation and etherification capacity increases.1
ISOMERIZATION
An isomerization unit will be necessary to increase the octane number of the light straight-run. This unit converts normal paraffins to isoparaffins.
For example, a once-through C5-C6 isomerization unit will yield up to 77% isopentane with 92 RON and 84 MON compared to 61.7 RON and 70 MON for normal pentane."3 Naphthenes and benzene should be removed from the isomerization feed because they do not isomerize and raise recycle rate.
The isomerization reactor is similar to a reformer. The reactor uses a platinumbased catalyst and operates at a low pressure. Therefore, a refinery can retrofit a cyclic reformer to be an isomerization reactor.
CATALYTIC POLYMERIZATION AND DIMERSOL
Catalytic polymerization and dimersol units were not considered in gasoline reformulation. These units generate gasoline that is completely olefinic and has low MON values.
The Dimersol process dimerizes propylene to isohexene. Polymer gasoline is essentially branched C6-C9 olefins.
CASE STUDY
A case study was conducted to illustrate the choices that refiners will have regarding feed, product distribution and quality, and capital expenditures to meet reformulated gasoline specifications. The case study was based on a typical 100,000-b/d refinery.
The refinery layout and capacities provided in Table 1 were gathered from the 1990 edition of the Oil & Gas Journal Data Book. It is not intended to represent any actual refinery. Also, it is assumed that the refinery does not have a downstream petrochemical facility. The process unit yields are based on published correlations, pilot plant data, and commercial data from Akzo's technical service activities.
For this particular study, the crude charged into the refinery is a light Arabian crude. Light Arabian represents 10% of U.S. crude imports and is similar to West Texas Intermediate and Louisiana Sweet crudes.
The crude oil properties and fraction yields are shown in Table 2. The refinery has to purchase 11,000 b/d of 212-325 F. heavy straightrun naphtha to load out the reformer because the heavy straight-run naphtha cut from crude distillation was narrowed to 212-325 F., reducing the amount available for reforming. The cut was narrowed to remove reformer benzene precursors in the front-end and to increase kerosine for in-demand jet fuel from the back-end.
Tables 3-7 contain the feed-rates and corresponding yields for the various operating units. Table 4 represents the yields generated from the overcrack of vacuum and Coker gas oils using a high-SAR zeolite, selective matrix and Re2O3. The relative quantity of saturates can be altered by adjusting the rare earth.
Table 5 shows the C3-C5 expected product distribution in the FCC depentanizer based on the refinery's fractionation efficiencies of the catalytic light ends. A depentanizer was installed to handle the 22% increase in the debutanizer overhead throughput due to overcracking and removal Of C5S from the gasoline front-end for further processing in the MTBE, TAME, and alkylation units. These units' yields also are provided.
Table 8 represents the resultant reformulated gasoline pool that essentially has met all of the reformulated specifications proposed in the Clean Air Act, as well as possessing an 89.9 (R + M)/2 octane. Rvp and octanes incorporate blending values.
The benzene content of the reformate is expected to be less than 1.5 vol % for regenerative reformers and CCRS. Likewise, benzene and Rvp will be low for FCC gasoline due to overcracking. Isobutane for alkylation and MTBE was purchased to meet the gasoline volume requirements.
Tables 9-12 reflect the hydrotreating requirements for kerosine, light and heavy naphtha, and distillate. Table 13 summarizes the refinery-wide hydrogen balance which is positive for this particular feed.
In all probability, a higher endpoint feed would have required more production or importation of hydrogen. Also, hydrogen was budgeted to achieve a 10 vol % aromatics reduction in the distillate.
Table 14 represents a capital expenditure of $57.7 million (1990) for required construction to meet the reformulated gasoline specifications. Primarily, the capital is concentrated on the alkylation expansion, an MTBE/TAME unit, and a new C5-C6 isomerization unit.
This capital includes only inside battery limits construction costs. Outside battery limits capital requirements include tankage, with proper pollution abatement equipment, in conjunction with additional utilities and wastewater treatment facilities.
ACKNOWLEDGMENTS
The author wishes to thank Bill Wilson, Donald Keyworth, James Williams, and Terry Reid for their assistance, suggestions, and contributions to this article.
REFERENCES
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- Masters, K. R., and Proshaska, E. A., "Add MTBE Unit Ahead of Alkylation," Hydrocarbon Processing, August 1988.
- Miller, D., and Piel, W., "Ether Options: MTBE/TAME & ETBE," Paper No. AM-89-58, National Petroleum Refiners Association annual meeting, San Francisco, Mar. 19-21, 1989.
- Dixon, P. H. O., Amico, V. J., and Strain, B., "Catalytic Distillation Technology and MTBE Production," Paper No. AM-89-44, National Petroleum Refiners Association annual meeting, San Francisco, Mar. 19-21, 1989.
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