TECHNOLOGY Gasification converts a variety of problem feedstocks and wastes

05/27/1996

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David L. Heaven 
Fluor Daniel Inc. 
Irvine, Calif.

High temperature, en- trained-flow gasification has been practiced commercially for more than 40 years. Gasification converts petroleum-based fuels to a clean fuel gas that, when fired in a gas turbine, produces minimal emissions of SO₂, NO_x, particulates, volatile organic compounds (VOCs), and CO.

Gas cleaning also allows removal and control of volatile metals that may be classified as hazardous air pollutants (HAPs).

The technology is moving, however, from its principal use as a source of hydrogen and carbon moNO_xide for chemicals production to a broader application as a useful and economic refining tool.

Gasification can provide a solution to many of the problems associated with recent trends in the petroleum refining industry. The growing prevalence of heavy, sour, metals-laden crudes, the highly competitive nature of the refining industry, and environmental regulations all work together to make gasification an increasingly attractive process option.

Gasification offers a solution to these constraints because of its ability to handle a wide variety of feedstocks, including intermediate refinery streams, petroleum coke, and even waste products.

The flexibility of gasification processes provides refiners with a range of value-added products-electricity, steam, hydrogen, and chemicals-that can be derived from low-value or waste streams.

The environmental performance of gasification is unmatched by competing means of dealing with low-value refinery streams or coke.

Economic drivers

The reasons for including a gasifier in a refinery often derive from the combination of crude oil quality trends and increasingly severe restrictions on levels of sulfur dioxide emissions from combustion of heavy fuels.

Forecasts indicate that crudes will be progressively heavier and also higher in sulfur content. Some crude oils, particularly Mexican Maya crude and several Venezuelan crudes, also have much higher metals contents than the crudes for which the typical refinery is configured.

At the same time, environmental restrictions are forcing fuel oil sulfur reductions in many parts of the world. The value of high-sulfur fuel oils is expected to drop significantly as these legislative restrictions further restrict the market.

Another potential reason for including a gasifier is the desire to use the products to generate electricity, thus reducing costs and emissions (in areas where refinery firing of residual fuels is still allowed), or to produce additional hydrogen.

Refiners often will find it profitable, however, to examine upgrading or conversion processes for their high-sulfur stocks. If the metals content of the fuel oil blend stocks is low, the problem may be addressed with resid hydrotreating. But catalyst poisoning rates increase directly with metals content. Hydrotreating becomes impractical somewhere in the range of 300-500 ppm total metals in the unit feedstock.

Conventional heavy-resid conversion processes for high-metals stocks, such as coking processes, are no longer the final solution they once were. High-sulfur, high-metals coke can no longer be directly fired in boilers in many parts of the world. Firing in fluid-bed combustors often is not permitted because of limited sulfur recovery and disposal problems with the heavy metals in the spent bed.

The market for high-sulfur, high-metals coke has constricted to the point where some U.S. refiners are faced with negative netbacks on their coke production.

Virtually any heavy resid or coke may be processed in gasifiers while meeting environmental regulations anywhere in the world. Typical gasifier emissions and product options are discussed later in this article.

Refinery integration

Integration of a gasifier into a refinery begins with two fundamental, interrelated questions:

• What are the process economics of gasification when applied to various potential feedstocks?
• What are the market opportunities for various potential end products of gasification?

The first question depends on the value of the end product and the capital and operating costs associated with the necessary process equipment. A few observations, however, are possible.

Gasification would rarely be applied to heavy oil feedstocks whose value exceeds $10/bbl. Zero or negative-value stocks generated at the refinery usually can be processed profitably, even when selling end-product electricity at the "avoided cost" prices currently offered by many utilities.

Viewed in this perspective, low-sulfur resids and high-sulfur atmospheric resids usually are not candidates for gasification. Low-metals, high-sulfur vacuum resids and visbreaker tars may be profitable as gasification feedstock, but the economics for such projects must be evaluated relative to hydroprocessing technologies. High-metals, high-sulfur vacuum resids are likely to be attractive gasification feedstocks.

In this final case, certain "concentrating technologies" may be synergistically profitable if installed upstream of the gasification unit. Such technologies include coking and solvent deasphalting. While several gasification projects under way in Italy are based on visbreaker tar feedstock from existing units, the typical 80% visbreaker bottoms yield makes it a less-effective concentrating technology for clean-sheet designs.

The second question pertains to scaling the size of the gasification facility to match the available markets for the ultimate end product. Depending on the size of the gasifier, the steam, electricity, and perhaps hydrogen, may be fully absorbed within the host refinery. Most gasifiers, however, will be of such a size, as dictated by feedstock availability, that product sales will be necessary.

Some typical, potential products from gasification are listed in the next section. To give sense to the market-side question, approximate yields for two potential end products are:

• Gasification of 1 ton of petroleum coke could produce about 1 ton of ammonia.
• Gasification of 1,000 b/d of heavy oil could produce about 32 mw of net electrical power.

Leading into the discussion of product opportunities, Table 1 [23922 bytes] shows typical compositions for synthesis gas produced from heavy oil and petroleum coke. Either feed produces syngas that may serve as a basic energy source for production of steam, electricity, or both.

Alternatively, carbon moNO_xide and hydrogen are basic chemical building blocks for production of many chemicals. If hydrogen is the desired primary end product, the carbon moNO_xide may be reacted almost entirely to produce hydrogen via steam shift:

CO + H₂O CO₂ + H₂

This process produces a high overall yield of hydrogen for refinery use. Such a process is used by Star Enterprise at its Convent, La., refinery, and will be used by Shell Nederland when the construction project at its Pernis refinery is completed.

Although syngas produced from heavy oil is richer in combined carbon moNO_xide plus hydrogen, either syngas can be used to manufacture a wide range of end products, following removal of sulfur components and, where necessary, other impurities.

Power generation

Electricity can be produced using the well-established gas turbine combined cycle technology commonly applied in refinery systems using natural gas or refinery gas. The combined cycle will be more efficient than direct combustion in a steam plant.

Minor modifications to the gas-turbine combustion and fuel-handling systems have been developed and tested, and are now used commercially by several manufacturers. These modifications are necessary to accommodate the low heating value of syngas (1/8 to 1/2 that of natural gas).

For optimum economics, the combined cycle can be integrated with the gasification system in several ways. The most common practice of steam-side integration was used in the 120-mw, cool-water integrated gasification combined cycle (IGCC) system installed by Southern California Edison and its partners in 1984.

Steam produced in the syngas coolers can be superheated in the gas turbine's heat recovery steam generator, making it suitable for modern steam turbines. Recently, IGCC designs also have incorporated integration on the air side by extracting air from the gas turbine to supply the air separation plant, with return of nitrogen to the gas turbine as a NO_x-control medium. This results in both additional net power and reduced emissions from the same basic equipment.

Several refinery-oriented IGCCs are under construction. Texaco Inc.'s refinery at El Dorado, Kan., will use a General Electric (GE) Model 6000B, 40-mw system for in-house power generation from petroleum coke and waste oils, plus some supplemental natural gas. It is scheduled for operation this year.

Shell's refinery at Pernis, The Netherlands, will use two GE 6000B machines and steam turbine generators to supply refinery needs and export some power to the grid. It is scheduled for start-up in early 1997.

Some large plants are in the detailed-design stage in Italy. The Saras SpA refinery in Sardinia and the ISAB refinery in Sicily have joined separately with independent power-producer developers to sell power to the grid using heavy oil feeds. These plants are, respectively, 550 mw and 500 mw.

At least 15 other, similar projects are in various stages of planning and development, indicating a growing trend toward power generation from IGCC as the efficient solution to utilization of high-sulfur fuel.

Chemicals, coproduction

Gasification technology has the unique ability to generate electricity, chemicals, or both, depending upon the choice of downstream equipment. The synergy of coproduction can improve the overall economics of an IGCC project.

The primary components of the fuel gas (carbon moNO_xide, hydrogen, and carbon dioxide) can be separated from the syngas mixture and sold as pure components, or they can be reacted with other compounds to make a wide range of more complex chemicals. Fig. 1 [25785 bytes] shows a typical integrated-energy facility and several potential products.

Products that can be manufactured from syngas include: methanol, isobutylene, methyl tertiary butyl ether (MTBE), acetic anhydride, tertiary amyl methyl ether (TAME), oxo alcohols, CO₂, high-cetane diesel, ammonia, gasoline, urea, chloromethanes, formaldehyde, dimethyl terephthalate (DMT), acetic acid, methyl methacrylate (MMA), acetaldehyde, methylamine, and isobutanol.

Of these chemicals, methanol is the parent product for producing most of the other chemicals. For example, methanol is a raw material for production of MTBE, TAME, formaldehyde, acetic acid, acetaldehyde, acetic anhydride, chloromethanes, DMT, MMA, and methyl -

amine. The production economics of methanol therefore are of major importance in planning a derivatives chemical industry.

The ability to produce chemicals from syngas has been well proven, with a number of plants now in operation. An example is the Eastman Chemical Co. facility in Kingsport, Tenn., which converts coal-derived syngas to methanol and carbon moNO_xide. These are reacted with other chemicals to produce cellulose acetate. A plant in Germany produces oxo-chemicals from syngas, and operating plants in India, Japan, and China produce ammonia.

There are also promising developments in Fischer Tropsch (FT) technology, which converts synthesis gas to a range of liquid hydrocarbon products. Shell is operating a large FT demonstration plant in Malaysia based on syngas from natural gas.

Many of the chemicals on this list are produced by process sequences which begin with steam reforming of natural gas. Gasification provides an alternative to steam reforming which can sharply reduce NO_x emissions from the overall plant.

Sasol Ltd.'s very large complexes in South Africa include nearly 100 gasifiers, and much of their syngas production is associated with production of a wide variety of chemicals. Fischer Tropsch technology is employed extensively and Sasol has announced several new developments.

Coproduction also can enhance the availability and reliability of an IGCC plant. Some coproduction approaches include an additional gasifier, which can be used to maintain the plant's design fuel-gas flow should one of the other gasifiers be out of service. During the rest of the time, the syngas is used to produce methanol or other valuable coproducts.

Methanol can be used as a back-up fuel for the combined cycle during scheduled and unscheduled gasification plant outages. One study indicates that using methanol as a back-up fuel can improve the equivalent generation availability of the overall plant by 5-6%.

Reliability

The expected reliability and availability of gasification units have received much attention. A cursory review might suggest that the complexity of a gasification combined cycle plant would lead to reduced availability. In fact, however, the individual plant systems are generally very reliable, which, when combined with effective sparing, leads to very positive results.

Recent operating experience at several plants indicates an availability of 90% is achievable for a single gasification train, sparing only the pumps. Supporting areas such as air separation, sulfur recovery, and water systems, have availability as high as 99%.

Single-train IGCC plants (without spare gasifiers) are projected to have an equivalent availability of at least 85%. If back-up fuel is available to the gas turbine, the power generation availability can approach 94-95%-that of a natural-gas-fired combined cycle plant.

Alternatively, a spare gasifier may be installed and operated in parallel with the other gasifiers. This is practiced at a coal gasification plant in Ube, Japan, and at Eastman's Tennessee plant, and results in syngas availability exceeding 98%.

Emissions comparison

Gasification of petroleum coke, residual oil, and Orimulsion (an on-purpose emulsion of water and Orinoco tar) has received much attention, primarily because of the environmental benefits of this technology. Table 2 [43641 bytes]compares estimated emissions from IGCC with those from natural-gas-fueled combined cycle (NGCC) and other competing technologies.

In general, emissions from an IGCC unit approach those of a natural gas-fired combined cycle unit.

Each gasification technology licensor offers a design that allows slagging of the feed metals with high ash-fusion temperatures, and their subsequent encapsulation in an inert frit. This may require the addition of flux.

Overall, solid waste produced by an IGCC plant is dramatically less than that produced by a boiler with flue gas desulfurization or by a circulating fluid-bed boiler plant.

Of the compounds listed in Table 2 [43641 bytes], CO₂ is the only component in the IGCC stack gas that has a significantly greater flow rate than in an NGCC system. Compared with other solid fuel options, however, IGCC has lower CO₂ emissions due to its inherent high efficiency. Further, water use in IGCC plants can be minimized to reflect local availability and cost constraints.

Investment costs

The costs for gasification are somewhat variable, depending on economy of scale, local labor costs, and applicable engineering standards. Further, gasification costs usually are estimated in combination with the downstream processing equipment necessary for delivery of a syngas suitable for conversion to the designed end product. Accordingly, gasification investment costs are best addressed on a project-specific basis. Some limited comment on gasification in an IGCC plant, however, is possible.

An IGCC plant operating on heavy oil is somewhat less complex than a coal-based IGCC and costs are marginally less. Whereas coal gasification often has been quoted at $1,400-1,600/kw at various conferences and in technical reports, value of heavy-oil-based IGCC plants may be taken as $1,200-1,500/kw for preliminary planning purposes. The cost can be improved even more by using some of the produced steam in the refinery, rather than routing it through a condensing steam turbine.

Gasification process

This section addresses refinery applications of high-temperature, entrained flow, slagging gasifiers. While other gasifier types have found application on certain coals and, in some cases, petroleum coke, the entrained-flow gasifier is dominant in commercial experience with refinery feedstocks. Fig. 2 [22645 bytes] shows a block flow diagram of an entrained flow gasifier.

Typical high-temperature, entrained flow gasifier operating conditions are:

• Temperature, 2,350-2,600^o F.
• Pressure, 400-1,200 psig
• Residence time, 2-5 sec.

Heavy oils are processed in the lower end of this temperature range and petroleum cokes in the higher end. The basic gasification reactions are affected only slightly by pressure; consequently, gasification pressure generally is selected for best fit with downstream processing requirements.

For example, gasification, when integrated with a combined cycle power block, may operate at pressures as low as 400 psig, while gasification combined with ammonia or methanol synthesis would be designed for the high end of the pressure range. Greater single-train capacity can be another motive for selecting a higher pressure.

Gasification technologies for refinery applications are offered by Destec Energy Inc., Houston; Noell-LGA Gastechnik GmbH, Leipzig, Germany; a Shell subsidiary, Shell Synthetic Fuels Inc.; and Texaco Inc. Heavy oil gasification has been licensed by Shell and Texaco for 40 years. Both companies have demonstrated coke gasification technology and offer technology licenses.

Noell has operated a demonstration plant during the past decade, and recently has begun to offer equipment and technology for gasification of either heavy oil or petroleum coke. Destec has tested coke gasification at one of its plants and will license its technology. Additionally, Shell Synthetic Fuels will build and operate gasification facilities to fee-process a refiner's heavy oil or coke into a synthesis gas.

These gasifiers may use either air or oxygen as the oxidant in the gasification reactions. Several studies have confirmed a clear advantage, however, to using oxygen. While an oxygen plant adds capital, its cost is less than the premium cost of sizing the entire gasification plant to handle the extra volume of nitrogen that otherwise would be introduced with air. Data given in this article are based on oxygen-blown gasification.

The refinery gasification projects listed in Table 3 [36532 bytes] are under active development or construction. All of these gasifiers are oxygen blown.

Oxygen plants

The design of an air separation plant is an important part of the design of a refinery gasification project. The air separation unit (ASU) provides the oxygen to efficiently convert the residual oil, petroleum coke, or other hydrocarbon feedstock to a medium-BTU syngas. Oxygen purities for such applications typically are 95% and higher.

Potential refinery uses include not only the gasification plants discussed here, but also air enrichment to fluid catalytic cracking or sulfur recovery units. In addition, the oxygen plant can be designed to recover nitrogen for refinery use and to produce rare gases. The economic benefit of coproduction depends on local markets and prices for these chemical coproducts.

Refinery gasification projects often require air separation plants producing 1,000 tons/day O2 or more. Industry has significant, long-term experience in providing such facilities. More than 120 plants have been constructed worldwide, with sizes exceeding 1,000 tons/day of oxygen (some by a great deal). Oxygen is delivered at pressures as high as 1,250 psig.

Air separation unit safety is an important consideration for all gasification facilities, and is reflected in the design and operation of every air separation plant.

Many air separation plants are located within refinery and chemical facilities. Design features that enhance safe operation include:

• Molecular sieve air purifiers to adsorb water, carbon dioxide, and certain problem hydrocarbons before they enter the cryogenic processing equipment
• Continuous, on-line analysis for contaminants
• Careful evaluation of materials of construction for oxygen compatibility in both cryogenic and hot processing environments
• Containment of oxygen compressors within barriers designed to protect personnel and equipment
• Multiple temperature and pressure sensors to quickly spot deviations from normal operating conditions.

All major air separation companies have safety performance records that are among the best in the Chemical Manufacturers Association. These companies belong to trade organizations such as the Compressed Gas Association and the International Oxygen Manufacturers Association, which share information on safety-related issues.

Air separation unit reliability is essential to the operation of any oxygen-using facility. Oxygen plants are designed for reliable operation through the use of proven components for major items such as compression equipment and minor items like instruments and valves.

All air separation plants are designed for process computer control. While industry-wide reliability data are not published, the air separation process is highly reliable. Typical specifications for gasification applications require oxygen-generator availabilities of 98%.

A simplified schematic of an air separation unit and related facilities is shown in Fig. 3 [20313 bytes]. Air is compressed to overcome pressure drop in the system and to provide the energy required to separate and recover oxygen and nitrogen. The air purification step removes water, carbon dioxide, and other freezable atmospheric contaminants.

The heat-exchange section cools the incoming air stream to about -270^o F. against exiting product streams. Most basic cryogenic distillation systems consist of two distillation columns: one operating near the incoming air supply pressure and a second operating at about one third of the incoming air pressure. Liquid products can be withdrawn from the distillation area to replenish storage.

The warm product streams are then compressed to the delivery pressures required by the gasifier.

Development trends

Gasification has potential for future technological improvements. New and more efficient partial-oxidation burners and gasifiers are being tested and soon will become commercially available, extending run length and plant availability.

New technologies and licensors are entering the market. The Prenflow process has been chosen as the basis for Repsol Petroleo SA's plant in Puertollano, Spain, which will use a mixture of coal and petroleum coke. Prenflow does not yet offer its technology under license.

For IGCC plants, a promising development is the replacement of the conventional, low-temperature, wet scrubbing of syngas with hot gas cleanup to remove sulfur compounds (H2S and COS), nitrogen compounds (NH3 and HCN), particulates, halogens, alkali metals and other trace materials. Hot gas cleanup avoids the cooling and subsequent reheating of the syngas, and thus has potential for improving the energy efficiency and capital cost of an IGCC plant.

Hot gas cleanup is being commercialized by Westinghouse Electric Corp., Schumacher, Lurgi AG, and Pall Corp. It is also the target of many research organizations in several countries:

• GE Power Generation is testing a process based on zinc ferrite, zinc titanate, or both. The GE Environmental Systems Inc. technology will be demonstrated at the Tampa Electric IGCC facility in Pol county, Florida.
• Phillips Petroleum Co. is working with Zi-Sorb, a sorbent based on zinc activated with nickel.
• IGC, Kawasaki, Japan, utilizes an undisclosed sorbent in a moving-bed reactor.
• Haldor Tops e, Lyngby, Denmark, is developing a sorbent based on SnO2.
• Foster Wheeler International Corp. is testing a process based on metal oxides deposited on a silica-alumina support.

The capture of particulates, halogens, and alkali metals from the gasifier is already possible with ceramic filters, pneumatic injection of a powdered sorbent, or a fixed bed of coarse grain sorbents. The removal of nitrogen compounds is not yet possible, but companies can rely on the elimination, by selective catalytic reduction techniques, of the NOx formed during combustion.

Important developments are taking place in the power generation block. Gas turbine technology is continually moving towards higher efficiencies and lower cost. At Power-Gen Europe last year in Amsterdam, General Electric announced the G and H technologies, which have potential combined cycle efficiencies of 60% on an lower-heating-value fuel basis. These turbines are expected to be in operation before the turn of the century.

ABB Power Generation presented a new family of gas turbines, GT24 and GT26, using two-stage firing to achieve increased efficiency and reduced emissions.

Siemens Power Corp. also presented the 3A family of gas turbines, a joint development with Pratt & Whitney bringing in advanced aircraft-engine technology.

Improvements such as these will further improve the economics of coke or heavy-oil-based IGCC plants.

Equipment, contracting

A large choice of commercially proven equipment is available to support any level of gasification capacity and to process the syngas as needed to produce the desired end products.

When considering electrical production, the upper limit on single-train IGCC capacity is set by the size of the largest gas turbines available today. The GE-7FA, Westinghouse 501FA, or Siemens 84.3 turbines permit a single-train, net power output (gross output minus internal consumption) as high as 275 mw, corresponding to feed rates of 76-80 tons/hr heavy oil or 90-97 tons/hr coke.

Moreover, under the U.S. Department of Energy's advanced turbine systems program, General Electric and Westinghouse are developing single-train power generation units that will increase the upper limit substantially.

Below these maximum capacities there is an ample choice of commercially proven gas turbines. For example, with a GE-7E frame or a Westinghouse 501D frame, the net power output is 104-111 mw, equivalent to 28-31 tons/hr heavy oil or 35-38 tons/hr coke.

The lower capacity limit of a single-train unit is set by economy of scale considerations. A single module of 90-100 mw, based on a GE-6F frame, still may be economically viable; the corresponding feed rate is about 25 tons/hr oil or 35 tons/hr coke.

The capacity of the single gasifier vessels available today can match the range of generation capacities indicated previously, although, at net power output greater than 300-350 mw, it may be more convenient to use two gasifiers in parallel to achieve greater flexibility and plant availability. All other components of an IGCC complex-such as heat recovery, syngas scrubbing, sulfur recovery, process water treatment, auxiliaries etc.-can be designed and manufactured as single-line for all the indicated capacities.

In the case of chemicals production, a single train of gas cleanup, shift conversion, and other processing equipment can handle the syngas produced by gasifying 8,000 b/d or more of heavy oil.

Qualified engineering, procurement, and construction services for gasification projects are available from several major contractors, under either cost-reimbursable or competitive lump-sum terms. In some cases, it may be desirable to combine the approaches by performing preliminary engineering under reimbursable terms, then converting to lump-sum terms when the project parameters have become well defined.

In 1995, four competitive lump-sum bids were submitted in Europe for four major IGCC projects, based on the use of low-value refinery feedstocks. Three of these projects are progressing through the detailed engineering, procurement, and construction phases.