After petroleum is gone, what then?

Analysis of seven organic carbon sources discusses possible alternatives for transportation fuels

Dire predictions regarding the availability of petroleum and continuation of our present civilization are indicated by the title of a recent presentation, "The peak of world oil production and the road to the Olduvai Gorge," which predicts the crash of civilization in 2030.

1 There are other more conservative predictions for just a peak in petroleum production in 2005.² In a previous paper, the author projected the peak in oil production in 2040.³

Recently, the Energy Information Administration projected a 2.2% annual increase in oil production through the year 2020.

4 Continued improvements in exploration, drilling and production technologies provide the capability for continued oil production rate increases.⁵

Still, it is obvious that there is a finite amount of petroleum on planet Earth that can be produced for a reasonable price. That reasonable price is the price at which liquid fuels can be produced from sources other than petroleum. These alternative sources of U.S. liquid fuels are the topic of this presentation.

All reasonable liquid fuels contain carbon; hence, a subtitle for this article could be, "Organic carbon sources for alternative transportation fuels." These alternative sources of organic carbon are numerous and far more abundant than petroleum. Technologies for conversion of alternative organic carbon sources into transportation fuels range from "proven and ready to use" to "wishful and uncertain." The price for this conversion ranges from "almost competitive today" to "outrageously high."

The logic for ignoring global warming in this study and the relation of alternative carbon sources to the proposed use of hydrogen as an alternative transportation fuel are given in later discussions. Principal conclusions drawn are: 1) organic carbon is central to providing liquid transportation fuels, after petroleum is "gone"; 2) coal and lignite are abundant, environmentally benign sources of organic carbon for liquid fuels; and 3) processes for the conversion of coal to liquid fuels are proven.

The following alternative U.S. sources of organic carbon for transportation fuels are considered in this presentation:

These organic carbon sources are discussed here, followed by a review of the chemical processes by which organic carbon can be converted into liquid transportation fuels.

Natural gas. This is the most convenient fuel for small-scale stationary uses. For this reason, there is a long-term logic for conserving natural gas for this purpose. Long-term logic and medium-term economics result in different decisions and, in a free society, medium-term economics wins. In this circumstance, gas has become an attractive fuel for large-scale generation of electricity, despite recent price surges.⁶

Natural gas is abundant. Its worldwide reserves approximate that of petroleum. Gas is an excellent engine fuel, but it is also very inconvenient to carry on the vehicle using it, and driving range is limited. For this reason, conversion of gas to liquid transportation fuels will be discussed later.

Coal and lignite. These are the U.S.'s most abundant and usable domestic organic carbon sources. The technologies for large-scale, environmentally benign mining are already proven, since coal is still the dominant fuel for electric utilities. It is estimated that 2,800 billion tons (Bt) of coal potentially are available in the U.S.⁷ On a heating value basis, this is equivalent to about 9,650 Bbbl of petroleum.

Western (Greenriver) oil shale. Western oil shale is abundant in Colorado, Utah and Wyoming. Considerable investment has been made in mining / processing technologies. In the period of about 1940 to 1980, oil shale was thought to be the next source of liquid transportation fuels. However, the environmental problems associated with mining and disposal of the spent shale are immense. In this circumstance, issuing permits for commercial shale utilization would be difficult and expensive. The amount of oil shale that exists is large: 2,000 Bbbl domestically and 12,000 Bbbl on our planet.^8,9

Devonian shale. This is also known as eastern shale or black shale. The resource is located in Ohio, Kentucky, Tennessee and Indiana. It is exceedingly abundant, 800 Bboe have been identified just near outcrops, and the deeper resources have not been estimated.

10 Utilization of this shale has not been demonstrated on a large scale, since the pyrolysis processes used for Greenriver shale do not provide an adequate yield of liquid products.

Natural gas hydrates. These are a significant problem in pipelining natural gas, but a problem that has been effectively managed. Gas hydrates as found in nature, in deep permafrost and deep ocean sediments are an immense opportunity for energy production. The amount of gas contained in the hydrates is truly vast relative to conventional natural gas resources.¹¹ But no process has been demonstrated to recover gas from these hydrates. In addition, the potential impact on the environment may be large. In this circumstance, natural gas hydrates remain a "wishful" but still vast source of fuels.

Biomass residues. These are available in limited and scattered amounts. Forestry and lumber production residues are already effectively used as boiler fuel. Municipal solid waste and most agricultural residues are still not an economic source of energy; and a tipping fee is necessary for their disposal. These residues could be converted to liquid fuels, but it is more expedient to use them as a local boiler fuel, relying on existing technologies, when economic.

Intentionally grown biomass. Since by-product biomass residues are not economic as bulk energy sources, it would not be expected that intentional growth of biomass for energy would be economic either. Intentionally grown biomass for energy must directly compete for land and irrigation water resources, with more profitable food and fiber crops. In addition, the potential amounts of intentionally grown biomass are small relative to transportation fuel demand.

The carbon conversion processes to be considered in this section include the following:

The following brief reviews of these processes indicate their general nature and state of development.

Conventional petroleum refining. This is mentioned as a carbon-conversion process since proven modifications of the existing refining process potentially can convert all the carbon present in petroleum into liquid transportation fuels. When petroleum prices were relatively low, refiners found that it was cost effective to produce liquid transportation fuels with coking / cracking processes. In this circumstance, the "excess" organic carbon in petroleum was rejected as coke and then gasified along with refinery wastes. The resulting synthesis gases can be burned for boiler fuel or used for production of petrochemicals and hydrogenation of petroleum products.¹³ Refiners even market excess electricity that results from cogeneration.

Significant increases in petroleum prices serve to change this circumstance, and thus make it desirable to increase the yields of liquid transportation fuels from petroleum. This task is accomplished by using hydrogenation / hydrotreating to produce liquid transportation fuels. In addition, the potential exists for using coal or lignite as both a source of fuel and hydrogen for a petroleum refinery. By this means, it will be possible to produce more than one barrel of transportation fuel per barrel of crude petroleum processed.

For this reason, conventional petroleum refining is listed as a means of converting organic carbon to transportation fuels. The proposed modification of petroleum refineries will happen on an incremental basis as the price of oil is perceived to stabilize at a moderately high level, perhaps $30/bbl. The incentives to refine heavy oil and tar will also increase as the price for conventional petroleum stabilizes at a higher level.

Gasification and reforming. The objective of gasification and reforming processes is to convert organic carbon into synthesis gas, a mixture of carbon monoxide and hydrogen. This gas can then be reacted to produce a variety of liquid fuels, and also "petrochemicals." The essence of the gasification process is the reaction of carbon with water:

This reaction is written in an overly simplified form to stress the fact that the gasification reaction is "unburning" water. When hydrogen-containing fuels are burned to release energy, water is a product of combustion. When water is converted to hydrogen by gasification, about the same amount of energy must be supplied. In terms of thermochemistry, gasification is a strongly endothermic process, and this fact is a central feature in designing gasification processes. The necessary energy for the gasification reaction is frequently supplied by adding pure oxygen to the reaction mixture.

The stated equation is also oversimplified because carbon dioxide is also produced and the reaction is reversible. Chemical equilibrium is reached among the species present, so the immediate yields are not 100% of the desired products. The endothermic nature of the gasification process makes the overall thermal efficiency of gasification processes to liquid fuels and petrochemical about 50%, despite energy conservation efforts.

Coal gasification is commercial now, despite the above factors and the difficulty of processing solids at high pressures. Eastman Chemicals in Kingsport, Tennessee, built its initial plant in 1983, and then expanded it in 1991, proving the attractiveness of coal gasification under Eastman's circumstances. It processes 2.1 MMt of coal per year for production of acetic anhydride.

Coal gasification is also accomplished at the Great Plains Synfuel Plant in Beulah, South Dakota, where 6.3 MMt of lignite are being converted into 5.4 Bscf of synthetic natural gas. When South Africa was economically isolated due to its apartheid policies, it built the SASOL coal gasification facilities to provide an internal source of liquid transportation fuels - the facilities continue in operation today.¹⁴

Synthesis gas. Gasification of natural gas and other light hydrocarbons is termed "reforming." Natural gas is much easier to convert to synthesis gas than coal, since coal is a solid containing considerable ash. The energy required for gasification either can be supplied by partial oxidation of the natural gas, or by heating a natural gas and steam mixture in a furnace called a reformer. Production of ammonia, methanol, acetic acid, etc., is accomplished in many national and international facilities today by means of these steam reformers producing synthesis gas.

Synthesis gas can be processed into a wide variety of liquid fuels. Shell is producing premium diesel in Malaysia from natural gas liquids. FT synthesis is also employed in South Africa SASOL facilities. Methanol is produced directly from synthesis gas today. In theory, methanol is a very good SI engine fuel, but it is not widely used.

Methanol can be converted directly to high-octane gasoline by the Mobil M-gasoline process. This process was to be commercialized in New Zealand, but low petroleum prices have confused the situation. Synthesis gas can be converted into dimethyl ether, which is a good diesel fuel, whereas methanol is not.¹⁵

Currently, announcements for new natural-gas-to-liquid fuel plants are frequent. One example is the 75,000-bpd plant for Egypt, to begin operation in 2005, using Shell's middle distillate synthesis process.¹⁶

It should be noted that wood and other organic materials can be gasified, and the synthesis gas used to produce liquid fuels that are, incidentally, environmentally friendly and renewable. It is noted that in WWII, civilian vehicles were operated directly with gas generated by wood gasifiers mounted on the car. This use of solid fuel to operate a vehicle was very inconvenient, and the on-car gasifiers were rapidly abandoned when WWII was over, again illustrating the need for convenient liquid transportation fuel.

In summary, gasification can convert both coal and natural gas to good liquid transportation fuels by commercially proven processes. Long-term projections of petroleum prices and uncertainties associated with these price projections are crucial concerns with regard to the construction of synthetic liquid fuel facilities using gasification technologies.

Pyrolysis. Also termed "destructive distillation," pyrolysis is, superficially, a very simple process. Heat any material containing organic carbon in the absence of oxygen, and it will be converted into three products: liquid oils, combustible gases and char. Manufacture of metallurgical coke, and production of charcoal are examples of commercial pyrolysis processes. Coal tar from the pyrolysis of coal for coke was the major source of simple organic chemicals known as "petrochemicals," before petrochemicals existed.

Pyrolysis of Greenriver oil shale, termed "retorting," is the process of choice for production of shale oil. At least two oil shale processes have been demonstrated in a reasonably large-scale: the Union (now Unocal) retort and the gas-combustion retort. Unocal closed its commercial, but still federally subsidized, 10,000 bpd oil shale plant near Parachute Creek, Colorado, in June 1991.¹⁷

It is expected that the economics of oil shale retorting will be less attractive than coal gasification, although some individuals might question that point. The environmental impact of mining oil shale and then disposing of the spent shale ash containing such toxic residues as arsenic is considerable. In addition, significant amounts of water are required for the overall retorting process.

Pyrolysis can also be applied to coal, prior to burning the remaining char in electric power plants. By this means, organic hydrogen and carbon will be conserved for liquid fuels, and only the remaining carbon would be burned for electric power production. Superficially, this is an attractive concept, and it has received minimal testing. The author attempted to facilitate further development of this process without success in the 1980s.¹⁸ Coal pyrolysis may become more attractive as petroleum reserves decrease. The economics of coal pyrolysis vs. coal gasification for liquid fuels are not obvious at this time.

Hydrogenation. This is inherently an expensive process, requiring hydrogen at high pressures and special catalysts. It is basically a known process, and is applied to petroleum products as needed, particularly to remove unwanted constituents such as sulfur and aromatics. Hydrogenation has been considered for direct liquefaction of coal.

It has been tested on a small-scale to get increased yields of oil from the eastern, Devonian oil shale - the HYTORT process. Process developers estimated that 400 Bbbl oil could be made available from Devonian shale using the process.¹⁹ For large-scale production of liquid fuels from alternative carbon sources, hydrogenation is not considered economically attractive. The author is not aware of HYTORT being reconsidered in recent years.

Fermentation. Ethanol is a good fuel for SI engines. Producing ethanol via fermentation makes it a renewable and environmentally friendly fuel. It is also perceived as supporting the rural economy, when the fermentation feed stock is starch or sugar - it is doubtful that a statistical analysis of corn price and volume would verify that this perception is true. The costs for ethanol are rather high relative to gasoline, and food-quality materials are being used for their fuel value.

Despite these inherent disadvantages, tax incentives have been provided for use of ethanol in gasoline. Commercially, ethanol for solvent and industrial usage is produced as an ordinary petrochemical, i.e., the hydration of ethylene directly with water.

In another proposed fermentation process, cellulose is hydrolyzed by either acids or enzymes into sugars. The sugars are then fermented into ethanol. This process uses an economical, non-food starting material - cellulose as contained in wood or even municipal solid waste. Cellulose hydrolysis has been tried for over 50 years without sustained commercial success. There are inherent reaction rate and reaction yield constraints that prevent its success. The concept has been reviewed relatively recently.

While not a fermentation process, another source of biomass-based transportation fuel should be noted. That source is vegetable oils and animal fats that can be converted into a good diesel fuel, by a relatively simple chemical process, transesterification with methanol.

This process reduces the viscosity of vegetable oils so they become a good diesel fuel frequently called biodiesel. The major problem with biodiesel is that the primary raw material, vegetable oil, costs on the order of $3/gal. Used cooking oils and inedible tallow are available in limited amounts. They also have value in animal rations and in pet foods.

Hydrogen for fuel cells is receiving increasing attention as a potential route for transportation fuels. It should be noted that the most economic source of hydrogen is the reforming of natural gas, as discussed earlier. This concept is already being used for fuel-cell-powered buses in California, ²¹ but there is little mention of cost on an unsubsidized basis. Coal gasification is also a potential source of hydrogen for fuel cells. Low-molecular-weight hydrogen would be a more difficult fuel to transport on a vehicle than even natural gas, which is already considered inconvenient for use as a transportation fuel.

Hydrogen also has special safety issues. For this reason, on-board reforming of hydrocarbons to produce hydrogen is being considered. Designing an economic miniaturized reformer for on-vehicle hydrogen production would seem a difficult, if not impossible task.

This topic is not considered in this paper, for a good reason. The limited reductions in emissions of fossil carbon dioxide, which might be specified by the Kyoto accord, are more easily accomplished at electric power generation facilities, not on vehicles. Several options to reduce fossil CO₂ emissions associated with electric power production, including:

Using a selection of the above options for reducing fossil CO₂ emissions associated with electric generating facilities is far more easily accomplished than constraining the use of carbon-containing liquid transportation fuels.

In summary, the above discussions indicate that: 1) premium transportation fuels from natural gas via gasification are commercial now in some locations, and these facilities are expected to increase; 2) proven commercial technology exists for coal gasification, to produce premium transportation fuels; 3) other sources of organic carbon for transportation fuels are more difficult to process economically, so they will not be developed for the foreseeable future; and 4) the rate at which facilities for gasification / reforming natural gas and coal are built will depend on companies' and independent investors' perceptions of stable, relatively high prices for petroleum.

This article was prepared from the paper, "After the petroleum is gone, what then? Organic carbon sources for alternative transportation fuels," presented at the 48th Annual Southwestern Petroleum Short course, April 25 - 26, 2001, Lubbock, Texas

¹ Duncan, R. C., "The peak of world oil production and the road to the Olduvai Gorge," Summit 2000, Geological Society of America, Reno, Nevada, Nov. 13, 2000.

² Campbell, C. J., and J. H. Laherrere, "The end of cheap oil,"Scientific American, March 1998, pp. 78 - 83.

Barker, H. W., "2005 - Peak in petroleum production or pinching Hubbert's pimple," Paper 45, Proceedings of the 45th Annual Southwestern Petroleum Short Course, Lubbock, Texas, April 21 - 22, 1999, pp. 366 - 378.

⁴ Energy Information Administration, Reported by Reuters News Service, Published by Houston Chronicle, Nov. 29, 2000.

⁵ Nehring, R., "Innovation overpowering reserves depletion in U.S.,"Oil and Gas Journal, Nov. 9, 1998, pp. 87 - 90.

Houston Chronicle News Services, "Natural gas jets past $9 mark,"Houston Chronicle, Dec. 11, 2000.

⁷ Anon., "Energy alternatives: A comparative analysis," The Science and Public Policy Program, University of Oklahoma, Norman, Oklahoma, 1975, p. 1.3.

⁸ Weeks, L. G., "The next hundred years' energy demand and sources of supply,"Geotimes, 1960, pp. 18 - 21, 51 - 55 (As cited in Youngquist, 1999).

Youngquist, W., "Shale oil - The elusive energy,"Hubbert Center Newsletter 98/4, http://hubbert.mknes.edu/news/v98n4/young-quist.html. (1998).

¹⁰ Janka, J. C., and J. M. Dennison, "Devonian oil shale," Synthetic Fuels from Oil Shale Symposium, Institute of Gas Technology, Chicago, Dec. 3 - 6, 1979, p. 24.

¹¹ Collett, T. S., and V. A. Kuuskraa, "Hydrates contain vast store of world gas resources,"Oil and Gas Journal, May 1998, pp. 90 - 95.

¹² Parker, H. W., "Engine fuels from biomass,"ASME Trans-Journal of Energy Resources Technology, Dec. 1981, pp. 344 - 351.

¹³ Rhodes, A. K., "Kansas refinery starts up coke gasification unit,"Oil and Gas Journal, Aug. 5, 1996, pp. 32 - 36.

Parker, H. W., "Logic behind transportation fuels from coal and lignite,"Chemical Technology, Crown Publications, Bedfordview, South Africa, Jan. 2000, pp. 3 - 5.

¹⁵ Rouhi, A. M., "Amoco, Ahaldor Topsoe develop dimethyl ether as alternative diesel fuel,"Chemical and Engineering News, May 25, 1995, pp. 37 - 39.

¹⁶ Anon., "Shell clinches deal to build GTL plant in Egypt,"Oil and Gas Journal, Dec. 11, 2000, p. 69.

Anon., "Unocal to close sole U.S. commercial oil shale plant,"Oil and Gas Journal, April 8, 1991, p. 38.

¹⁸ Parker, H. W., "Liquid synfuels via pyrolysis of coal in association with electric power generation,"Energy Progress, March 1982, pp. 4 - 8.

¹⁹ Feldkirchner, H. B., and J. C. Janka, "The HYTORT process," Symposium Papers: Synthetic Fuels from Oil Shale, Atlanta, Georgia, Dec. 3 - 6, 1979, pp. 489 - 518.

²⁰ McCoy, M., "Biomass ethanol inches forward,"Chemical and Engineering News, Dec. 1998, pp. 29 - 32.

²¹ Hummel, G., S., Lelewer and H. Skip, "Benefits of methane reforming / hydrogen generation for early alternative fueling stations," Paper 315b, American Institute of Chemical Engineers Annual Meeting, Los Angeles, California, Nov. 12 - 17, 2000.

From http://www.chemlink.com.au/gtl.htm -

Gas to liquids

Natural gas can be use to produce bulk petrochemicals, including methanol and ammonia, but these are relatively small users of the gas reserves with limited markets. Liquid and other petroleum products are cheaper to transport, market, distribute to large markets. These can be moved in existing pipelines or products tankers and even blended with existing crude oil or product streams. Further, no special contractual arrangements are required for their sale with many suitable domestic and foreign markets.

New technology is being developed and applied to convert natural gas to liquids in gas to liquids technology (GTL). The projects are scalable, allowing design optimisation and application to smaller gas deposits. The key influences on their competitiveness are the cost of capital, operating costs of the plant, feedstock costs, scale and ability to achieve high utilisation rates in production. As a generalisation however, GTL is not competitive against conventional oil production unless the gas has a low opportunity value and is not readily transported.

GTL not only adds value, but capable of producing products that could be sold or blended into refinery stock as superior products with less pollutants for which there is growing demand. Reflecting its origins as a gas, gas to liquids processes produces diesel fuel with an energy density comparable to conventional diesel, but with a higher cetane number permitting a superior performance engine design.[1] Another “problem” emission associated with diesel fuel is particulate matter, which is composed of unburnt carbon and aromatics, and compounds of sulfur. Fine particulates are associated with respiratory problems, while certain complex aromatics have been found to be carcinogenic. Low sulfur content, leads to significant reductions in particulate matter that is generated during combustion, and the low aromatic content reduces the toxicity of the particulate matter reflecting in a worldwide trend towards the reduction of sulfur and aromatics in fuel.
1.1.1 Technology

It is technically feasible to synthesise almost any hydrocarbon from any other; and in the past five decades several processes have been developed to synthesise liquid hydrocarbons from natural gas.

There are two broad technologies for gas to liquid (GTL) to produce a synthetic petroleum product, (syncrude): a direct conversion from gas, and an indirect conversion via synthesis gas (syngas)[2]. The direct conversion of methane, (typically 85 to 90 per cent of natural gas), eliminates the cost of producing synthesis gas but involves a high activation energy and is difficult to control. Several direct conversion processes have been developed but none have been commercialised being economically unattractive.

Methanex is working with catalyst producer Synetix, an ICI subsidiary, and engineering firm ABB Lummus Global to develop and commercialise a synthesis gas process.

Indirect conversion can be carried out via Fischer-Tropsch (F-T) synthesis or via methanol.
1.1.2 Fischer-Tropsch

The discovery of F-T chemistry in Germany dates back to the 1920s and its development has been for strategic rather than economic reasons, as in Germany during World War II and in South Africa during the apartheid era. Mobil developed the "M-gasoline" process to make gasoline from methanol implemented in 1985 in a large integrated methanol-to-gasoline plant in New Zealand. The New Zealand plant was a technical success but produced gasoline at costs above $30 per barrel and required large subsidies from the New Zealand government.
Syngas

The syngas step converts the natural gas to hydrogen and carbon monoxide by partial oxidation, steam reforming or a combination of the two processes. The key variable is the hydrogen to carbon monoxide ratio with a 2:1 ratio recommended for F-T synthesis. Steam reforming is carried out in a fired heater with catalyst-filled tubes that produces a syngas with at least a 5:1 hydrogen to carbon monoxide ratio. To adjust the ratio, hydrogen can be removed by a membrane or pressure swing adsorption system. Helping economics is if the surplus hydrogen is used in a petroleum refinery or for the manufacture of ammonia in an adjoining plant.

The partial oxidation route provides the desired 2:1 ratio and is the preferred route in isolation of other needs.[3] There are two routes: one uses oxygen and produces a purer syngas without nitrogen; the other uses air creating a more dilute syngas. However, the oxygen route requires an air separation plant that increases the cost of the investment.
1.1.3 Conversion

Conversion of the syngas to liquid hydrocarbon is a chain growth reaction of carbon monoxide and hydrogen on the surface of a heterogeneous catalyst. The catalyst is either iron- or cobalt-based and the reaction is highly exothermic. The temperature, pressure and catalyst determine whether a light or heavy syncrude is produced.

For example at 330C mostly gasoline and olefins are produced whereas at 180 to 250C mostly diesel and waxes are produced.

There are mainly two types of F-T reactors. The vertical fixed tube type has the catalyst in tubes that are cooled externally by pressurised boiling water. For a large plant, several reactors in parallel may be used presenting energy savings. The other process is uses a slurry reactor in which pre-heated synthesis gas is fed to the bottom of the reactor and distributed into the slurry consisting of liquid wax and catalyst particles. As the gas bubbles upwards through the slurry, it is diffused and converted into more wax by the F-T reaction. The heat generated is removed through the reactor's cooling coils where steam is generated for use in the process.
1.2 Commercial examples
1.2.1 Sasol

Sasol is a synfuel technology supplier established to provide petroleum products in coal-rich but oil-poor South Africa. The firm has built a series of Fischer-Tropsch coal-to-oil plants, and is one of the world's most experienced synthetic fuels organisations and now marketing a natural-gas-to-oil technology. It has developed the world's largest synthetic fuel project, the Mossgas complex at Mossel Bay in South Africa that was commissioned in 1993 and produces a small volume of 25 000 barrels per day. To increase the proportion of higher molecular weight hydrocarbons, Sasol has modified its Arge reactor to operate at higher pressures. Sasol has commercialised four reactor types with the slurry phase distillate process being the most recent. Its products are more olefinic than those from the fixed bed reactors and are hydrogenated to straight chain paraffins. Its Slurry Phase Distillate converts natural gas into liquid fuels, most notably superior-quality diesel using technology developed from the conventional Arge tubular fixed-bed reactor technology.[4] The resultant diesel is suitable as a premium blending component for standard diesel grades from conventional crude oil refineries. Blended with lower grade diesels it assists to comply with the increasingly stringent specifications being set for transport fuels in North America and Europe.[5]

The other technology uses the Sasol Advanced Synthol (SAS) reactor to produce mainly light olefins and gasoline fractions. Sasol has developed high performance cobalt-based and iron based catalysts for these processes.

The company claims a single module or the Sasol Slurry Phase Distillate plant, that converts 100 MMscfd (110 terajoules per day of gas) of natural gas into 10 000 barrels a day of liquid transport fuels, that can be built at a capital cost of about US$250 million. This cost equates to a cost per daily barrel of capacity of about US$25 000 including utilities, off-site facilities and infrastructure units. [6] If priced at US$0.50/MMBtu, the gas amounts to a feedstock cost of US$5 per barrel of product. The fixed and variable operating costs (including labour, maintenance and catalyst) are estimated at a further US$5 per barrel of product, thereby resulting in a direct cash cost of production of about US$10 a barrel (excluding depreciation). These costs should however be compared with independent assessments.

In June 1999, Chevron and Sasol agreed to an alliance to create ventures using Sasol's GTL technology. The two companies have conducted a feasibility study to build a GTL plant in Nigeria that would begin operating in 2003. Sasol reportedly also has been in discussions with Norway's Statoil, but no definitive announcements have been made.
1.2.2 Statoil

With its large gas reserves, Norway's Statoil has been developing catalysts and process reactors for an F-T process to produce middle distillates from natural gas. The Statoil process employs a three-phase slurry type reactor in which syngas is fed to a suspension of catalyst particles in a hydrocarbon slurry which is a product of the process itself. The process continues to be challenged by catalyst performance and the ability to continuously extract the liquid product.
1.2.3 Shell

Shell has carried out R&D since the late 1940s on the conversion of natural gas, leading to the development of the Shell Middle Distillate Synthesis (SMDS) route, a modified F-T process. But unlike other F-T synthesis routes aimed at gasoline as the principal product, SMDS focuses on maximising yields of middle distillates, notably kerosene and gas oil.

Shell has built a 12 000 bbl/day plant in 1993 in Bintulu, Malaysia. The process consists of three steps: the production of syngas with a H2:CO ratio of 2:1; syngas conversion to high molecular weight hydrocarbons via F-T using a high performance catalyst; and hydrocracking and hydroisomerisation to maximise the middle distillate yield. The products are highly paraffinic and free of nitrogen and sulfur.

Shell is investing US$6 billion in gas to liquids technologies over 10 years with four plants. It announced in October 2000, agreement with the Egyptian government for a 75 000 bbl per day (3.8 million tpa) facility and a similar plant for Trinidad & Tobago.

In April 2001, it announced interest for plants in Australia, Argentina and Malaysia at 75 000 bbls/day costing US$1.6 billion.
1.2.4 Exxon

Exxon has developed a commercial F-T system from natural gas feedstock. Exxon claims its slurry design reactor and proprietary catalyst systems result in high productivity and selectivity along with significant economy of scale benefits. Exxon employs a three-step process: fluid bed synthesis gas generation by catalytic partial oxidation; slurry phase F-T synthesis; and fixed bed product upgrade by hydroisomerisation. The process can be adjusted to produce a range of products. More recently, Exxon has developed a new chemical method based on the Fischer-Tropsch process, to synthesise diesel fuel from natural gas. Exxon claims better catalysts and improved oxygen-extraction technologies have reduced the capital cost of the process, and is actively marketing the process internationally.[7]
1.2.5 Liquid derivatives

Made from gas, the high molecular weight liquid gas-to-liquid products can be hydro-cracked in a simple low-pressure process to produce naphtha, kerosene and diesel that is virtually free of sulfur and aromatics.[8] These derivative fuels are therefore potentially more valuable, notably in the US, Europe and Japan with high environmental standards.
1.2.6 Syntroleum

The Syntroleum Corporation of the USA is marketing an alternative natural-gas-to-diesel technology based on the F-T process.

It is claimed to be competitive as it has a lower capital cost due to the redesign of the reactor; using an air-based autothermal reforming process instead of oxygen for synthesis gas preparation to eliminate the significant capital expense of an air separation plant; and high yields using their catalyst. It claims to be able to produce synthetic crude at around $20 per bbl. The syncrude can be further subjected to hydro-cracking and fractionation to produce a diesel/naphtha/kerosene range at the user’s discretion.

The company indicates its process has a capital cost of around $13 000 per daily barrel of diesel for a 20 000 to 25 000 barrel per day facility and an operating cost of between $3.50 to $5.70 per barrel.[9] The thermal efficiency of the Syntroleum process is reported to be about 60 percent, implying a requirement for about 90 million cubic feet (85 terajoules) per day of dry gas for a $300 to $350 million, 25 000 barrel per day capacity facility. These figures therefore suggests a unit cost of less than $20 per barrel ($3.20 per gigajoule) of diesel fuel. The company claims the required economic scale would be smaller if based on LNG.

Syntroleum Corporation now also licenses its proprietary process for converting natural gas into other synthetic crude oils and transportation fuels. In February 2000, Syntroleum Corporation announced its intention to construct a 10 000 barrel per day (requiring 130 terajoules/day or 800 000 tonnes per year of gas) natural gas-to-liquids plant for the state of Western Australia to become the first location in the world to acquire full access to Syntroleum technology. The project plans to produce synthetic specialty hydrocarbons (polyalphaolefins lubricating oils), naphtha, normal paraffins and drilling fluids.[10] It is estimated to cost US$500 million generating sales of around US$200 million per year at constant prices.

The process is designed for application in plant sizes ranging from 2 000 barrels per day to more than 100 000 barrels per day. Current licensees include ARCO, Enron, Kerr-McGee, Marathon, Texaco, Repsol-YPF and Australia. The company has advised that it is "working on development plans" for gas-to-liquids specialty chemicals plant and is working with DaimlerChrysler to develop super-clean synthetic transportation fuels. The project is helped by $60 million of Australian government funding.[11]

The small scale of the proposed plant is because the autothermal partial oxidation with air and a once-through reactor design has not yet been proven. The smaller scale also avoids the marketing risk of placing large volumes of speciality chemicals and waxes in the marketplace dominated by large suppliers such as Sasol and Shell.

The appeal of the liquid products, which would be straight chain hydrocarbons, is that they would be free from sulfur, aromatics and metals, that can help refiners to meet new guidelines for very low sulfur fuels and general environmental standards. The naphtha however would be low in octane and requires isomerising or reforming if used as a fuel but represents a good petrochemical feedstock. The diesel will have a very high cetane number and be a premium blending product. For reasons of their purity, these synthetic fuels could also be used for fuel cells instead of methanol. As an alternative to fuels, the waxy portion can be converted to lubricants, drilling fluids, waxes and other high value speciality products.
1.2.7 Rentech

Rentech of the Colorado USA, has been developing an F-T process using molten wax slurry reactor and precipitated iron catalyst to convert gases and solid carbon-bearing material into straight chain hydrocarbon liquids. In their process, long straight chain hydrocarbons are drawn off as a liquid heavy wax while the shorter chain hydrocarbons are withdrawn as overhead vapours and condensed to soft wax, diesel fuel and naphtha. It is promoted as suitable for remote and associated gas fields as well as sub-pipeline quality gas.

During 2000, the company acquired a 75 000 tonne per year methanol plant in Colorado, USA for conversion into a GTL facility producing 800 to 1000 bbl/day of aromatic free diesel, naphtha and petroleum waxes.[12] The facility, the first in the US will cost about $20m to convert. Significantly, it will cost around 50 per cent less than a greenfield site because the methanol plant includes a synthesis gas generation unit. Start-up is scheduled for mid-2001.
1.2.8 Gasoline production

There are two methanol-based routes to gasoline. Mobil's methanol-to-gasoline (MTG) process based on the ZSM-5 zeolite catalyst was commercialised in 1985 in a plant now owned by Methanex in New Zealand. Commercial applications of the MTG process are now anticipated to use a fluid bed reactor with their higher efficiency and lower capital cost.
1.2.9 Outlook

Use of GTL for chemicals and energy production is forecast to advance rapidly with increasing pressure on the energy industry from governments, environmental organisations and the public to reduce pollution, including the gaseous and particulate emissions traditionally associated with conventional petroleum-fuelled and diesel-fuelled vehicles. In response there are initiatives worldwide to promote the use of unleaded petroleum in conjunction with a catalytic converter or, alternatively, the use of reformulated, cleaner diesel. One well regarded recent study from Business Communications Co., Inc. estimates total production of GTL to reach $120 billion by 2004, growing 5.5 per cent per year from 1999 to 2004.

However, it also clear that the commercial success of GTL technology has not yet been fully established, and returns from GTL projects will depend projections of market prices for petroleum products and presumed price premiums for the environmental advantages of GTL-produced fuels.

Unit production costs will reflect the cost of the feedstock gas; the capital cost of the plants; marketability of by-products such as heat, water, and other chemicals (e.g., excess hydrogen, nitrogen, or carbon dioxide); the availability of infrastructure; and the quality of the local workforce.
1.2.10 Cost competitiveness

Clearly too, the feedstock gas cost will have an influence as it may vary widely depending on alternative applications. Using gas that otherwise would be flared with zero (or even negative costs by avoiding penalties for violations of environmental regulations or increased costs related to compliance with environmental restrictions) would help the production economics. As one indication, based on current efficiencies, a change in the cost of gas feedstock of $0.50 per thousand cubic feet (per one gigajoule) would shift the synthetic crude oil price around $5 per barrel. This is predicated on that in general the processes requires about 10.5 gigajoules of gas to produce 1 bbl or fuel with variations depending on scale, quality of output and variable production costs traded off against capital costs.

Shell estimates (2001) that a GTL plant processing 600 000 standard cubic feet (0.7 terajoule) of gas per day would cost 60 per cent more than an LNG plant but the readily used products makes LNG cheaper than LNG. 75 000 bbl/day would cost around US$1.6 billion.

Capital costs for GTL projects currently tend to be in a range of double that of refineries, of between $20 000 and $30 000 per daily barrel of capacity (compared with refinery costs of $12 000 to $14 000 per daily barrel), and the cost of GTL-produced fuel could vary by approximately $1.50 per barrel with a shift of $5 000 in capital cost.[13] Estimates of the crude oil prices necessary to allow positive economic returns from a GTL project vary widely, with optimistic estimates ranging as low as $14 to $16 per barrel. More typical estimates indicate that expected oil prices would have to average over $20 per barrel on a sustained basis to lead to commitments for large-scale projects.[14]

Presently there are only three GTL facilities have operated to produce synthetic petroleum liquids at more than a demonstration level: the Mossgas Plant (South Africa), with output capacity of 23 000 barrels per day, Shell Bintulu (Malaysia) at 20 000 barrels per day and the subsidised methanol to gasoline project in New Zealand.[15] A joint project in Nigeria of Chevron and Sasol Ltd has been announced with a 30 000 barrel per day plant that would cost $1 billion using the Sasol Slurry Phase Distillate process. It is expected to begin operations in 2003 at costs claimed to be competitive with crude oil prices around $17 per barrel.[16] The Nigeria project will benefit from the infrastructure already in place for nearby oil and gas production and export facilities, although it is unclear whether, or to what extent, subsidies or other considerations helped to lower the estimated costs.[17]

Sasol has formed a Fischer-Tropsch technology alliance with Statoil of Norway in 1997 to evaluate the economic conversion of associated gas into synthetic crude oil at the point of production obviating the need to flare or reinject associated gas. It is developing barge-mounted gas-to-oil plants that can be floated into place over small natural gas deposits. Sasol claims that its process can produce middle distillates at a capital cost of $30 000 per daily barrel, with operating costs of $5 per barrel (excluding feedstock costs) and a thermal efficiency of 60 percent.

An USA Energy information administration assessment of a hypothetical GTL project estimated the cost of GTL fuel at almost $25 per barrel.[18]

It is relevant to note that, one US oil company has estimated a $5 per bbl penalty in extra refining investment to make a fuel meeting the new low (CARB’s) ultra-low-aromatics and low in sulfur. While the U.S. Department of Energy estimates that F-T diesel could fetch as much as an $8 to $10 a barrel premium.
1.2.11 Assessment

Under conditions that may be considered reasonable, a GTL project with present technology could be cost competitive with crude oil prices around $25 per barrel but any shifts in the key cost factors could significantly raise the competitive price. This uncertainty about world oil prices, rather than the technology has served to limit GTL investment.

GTL fuels used for transport should attract in theory a premium price as they have been shown to reduce vehicle exhaust emissions.[19] The extent of that premium will be dependent on the outlook of environmental legislation in key markets. Given the precedent set with the growing demand for LNG largely for stationary applications, demand for GTL fuels should be anticipated to grow firmly, notably for diesel fuels with the growing emphasis and legislation for low sulfur and aromatic fuels in Europe and the US.

Another environmentally motivated advantage of GTL technology relates to the concern in some countries about the disposition of gas produced in combination with crude oil (called associated-dissolved, or AD, gas). Without local use or infrastructure to ship it to markets, AD gas often is flared or vented into the air, releasing greenhouse gases such as methane and carbon monoxide. A GTL project can use gas that would otherwise be vented or flared as a feedstock. In any event, small isolated gas fields would be ideal applications for this technology given the lower capital cost for the establishment of GTL plant and infrastructure

An often perceived impediment to GTL technology is that it is considered an alternative competitor to LNG projects. However, for very large gas deposits, the two technologies can be applied on a complementary rather than competitive development basis. Joint development of GTL and LNG projects would allow for shared labour and infrastructure, reducing the costs to both projects and accelerating the development of an LNG projects. Indeed, Syntroleum (see earlier) claims GTL based on LNG feedstock has a lower operating cost, or can be produced at smaller scale to be competitive. However, clearly, its main appeal is the ability to utilise stranded gas or gas otherwise flared.

Given the investments around the world in GTL projects and the firming crude oil prices in excess of $20 per barrel, the evidence is that the GTL industry is on the starting blocks. Extensive research and refinements of technology, is pointing to reductions in operating costs. With its synergy to LNG projects, as already evidenced by an intended investment in Western Australia, GTL technology appears to be at the point of viability and most notably for high viscosity lube oil base stocks and for fuels in environmentally sensitive markets.

Clearly too, the economics of production are helped by integration not only with an LNG project, but also with other syngas projects notably methanol and ammonia. The co-production of alpha-olefins, another alternative user of syngas, would also assist the economics of its production.
Economic rate of return US$/Gj or /mmBTU
22 $0.3
18 $0.5
15 0.8

Source: BP. For a US$20,000/bpd GTL plant with crude at US$21/bbl and syncrude at US$25/bbl
Small plant Mid size plant Large plant
Capacity (bpd) 5000 30 000 50 000
Gas conversion rate (mcf/bbl)>13 11 <10
Gas required (Tj/d) 70 350 500
Min reserve for 20 years (Tcf) 0.5 3 5
Typical cost (A$) 400m 1700m 2600m

Source: BP Statistical Review of World Energy.

[1] The Cetane Number indicates how quickly the fuel will auto-ignite, and how evenly it will combust. Most countries require a minimum cetane number of around 45 to 50: A higher cetane number represents a lower flame temperature, providing a reduction in the formation of oxides of nitrogen (NOx) that contributes to urban smog and ground level ozone. Fischer-Tropsch diesel has a cetane number in excess of 70. Naphtha produced is sulfur free and contains a high proportion of paraffinic material suitable as cracker feedstock or the manufacture of solvents.

[2] Synthesis gas is produced by reacting methane (or carbon) with steam at elevated temperatures to yield a useful mixture of carbon oxides and hydrogen. It can be produced by a variety of processes and feedstocks. It may require the indicated compositional adjustment and treatment before use in the following major applications:

° Directly used for methanol synthesis. The dried syngas can be used without further adjustment since there is a net conversion of both CO and CO2 to methanol.

° Ammonia synthesis gas, requiring maximum hydrogen production and removal of oxygen-bearing compounds.

° Oxo synthesis gas, requiring composition adjustment and CO2 removal to give a 1:1 H2:CO synthesis gas.

° Industrial gases, as a source of high purity CO, CO2 or H2,

° Reducing gas, a mixture of CO and H2 requiring CO2 removal before being used to reduce oxides in ores to base metals.

° Fuels either as a substitute fuel gas from a liquid or solid feedstock, or as an intermediate for Fischer-Tropsch or zeolite-based alternative liquid fuel technologies.

[3] The steam reforming process produces a syngas of H2:CO ratio of about 3:1 with the surplus H2 that can be separated by a hollow fibre membrane process. Evaluations suggest the partial oxidation would be the preferred route when the surplus H2 from the steam reforming process has to be disposed of at fuel value. Under these conditions, the product value of syngas by partial oxidation is lower than steam reforming. The partial oxidation process is also slightly less capital intensive.

[4] In the Sasol Slurry Phase reactor, preheated synthesis gas is fed to the bottom of the reactor where it is distributed into the slurry consisting of liquid wax and catalyst particles. As the gas bubbles upward through the slurry, it diffuses into the slurry and is converted into more wax by the Fischer-Tropsch reaction. The heat generated from this reaction is removed through the reactor's cooling coils, which generate steam and the lighter, more volatile fractions leave in a gas stream from the top of the reactor.

[5] New US Environmental Protection Agency (EPA) standards for drastically reduced sulphur content in diesel fuel could impact US chemicals production and markets. The EPA is legislating to reduce the sulphur content in highway diesel fuel from the 500 parts/million (ppm) sulphur to 15 (ppm) in current diesel fuels.

[6] Sasol lower costs can be achieved with larger capacity with two or more modules in parallel.

[7] "Gas to Oil: A Gusher for the Millennium," Business Week (May 19, 1997). This article suggests that the cost of synthetic diesel fuel would be on the order of $20 per barrel and "perhaps as low as $15 per barrel."

[8] Some cetane is sacrificed by light isomerisation to improve low temperature behaviour of the products.

[9] M.A. Agee, "Convert Natural Gas into Clean Transportation Fuels," Hart's Fuel Technology & Management (March 1997), pp. 69-72.

[10] It will be owned by a subsidiary called Syntroleum Sweetwater in which Enron Corporation and Methanex Corporation are equity participants to be located approximately 4 kilometres from the North West Shelf Joint Venture LNG Plant in the north west of the state. Since then Methanex expressed interest in a proposed methanol project for the Northern Territory in Australia.

[11] The Western Australian State Government will provide $20 million in a general infrastructure package including roadways and a desalinisation plant (to provide the cooling water).

The Commonwealth Government has acquired a license for $15 million plus lending the company A$25 million 25 year loan to support R&D in Australia. Under the terms, Syntroleum has agreed to work with approved Australian Universities and research institutions towards advancing GTL technologies. This arrangement provides a reduced royalty structure for this technology and is therefore a sophisticated form of assistance tied to success.

[12] It can also produce hydrogen for stationary fuel cell applications and generate 100-150MW of surplus power.

[13] Capital costs are from Howard, Weil, Labouisse, and Friedrichs, Inc., Fischer-Tropsch Technology (Houston, TX, December 18, 1998), p. 44. Cost impacts were estimated by EIA’s Office of Oil and Gas, based on analysis in Cambridge Energy Research Associates, New Developments in Gas-to-Liquids Technology: Fundamental Change or Just a Niche Role? (Cambridge, MA, August 1997).

[14] Cambridge Energy Research Associates, “Gas-to-Liquids” Two Years Later—Still Just a Niche Opportunity? (Cambridge, MA, October 1999).

[15] Gas-to-Liquids At-a-Glance Reference Guide 1999,” Hart Gas-to-Liquids News, in association with Syntroleum.

[16] Assumptions behind this estimated price level include feedstock gas at $0.50 per million Btu (considered the rough equivalent of $5 per barrel of crude oil, or less at strict Btu equivalence), capacity costs of $25,000 per daily barrel, and operating costs of $5 per barrel. Source: “Advanced Technology Puts Sasol in GTL Driver’s Seat,” Gas-to-Liquids News (July 1999), p. 6.

[17] A memorandum of understanding between Sasol, Qatar General Petroleum Corporation and Phillips Petroleum Company was signed in 1997 for the proposed construction of a Sasol Slurry Phase Distillate process facility. The envisaged, twin-train Sasol Slurry Phase Distillate plant would be built at Ras Laffan in north-east Qatar to produce 20 000 barrels of liquid transport fuels a day.

[18]The US government agency used a capital cost of $10.48 per barrel ($25,000 per daily barrel over 12 years at a 12 per cent discount rate), an operating costs of $5.50 per barrel and feedstock costs equivalent to $8.92 per barrel of crude oil (including conversion losses of 35 percent).

[19] In one test in the US ,100-percent synthetic diesel used in place of No. 2 diesel fuel produced lower levels of nitrogen oxides (by 8 percent), particulate matter (by 31 percent), carbon monoxide (by 49 percent), and hydrocarbons (by 35 percent).

Chemlink Pty Ltd ABN 71 007 034 022. Tel 61 8 9294 3254 Publications 1997. All contents Copyright © 1997. All rights reserved. Information in this document is subject to change without notice. Products and companies referred to are trademarks or registered trademarks of their respective companies or mark holders. URL: www.chemlink.com.au/

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The author
	Dr. Harry W. Parker, since 1970, has been Associate, then Full Professor in the Department of Chemical Engineering, Texas Tech University, Lubbock, Texas. He received his BS degree from Texas Tech University in 1953, and MS and PhD degrees from Northwestern University in 1954 and 1956. He has been involved in energy related research at many levels, including: Phillips Petroleum Co., 1956 - 1970, enhanced oil recovery and oil shale; Engineering Societies Commission on Energy, Washington DC, 1979 - 1981, evaluation of processes and resources for alternative fuels; and Director-Office of agricultural materials USDA / CSREES, Washington, DC, 1993 - 1994, facilitation of agricultural crop usage as energy sources / industrial materials. His research and teaching interests include energy sources and processes, environmental remediation, and industrial uses for agricultural crops. He is an engineering consultant to various energy and environmental firms. Dr. Parker is the inventor / coinventor of 84 U.S. patents. He is a member of AICE and ACS, and is a registered professional engineer in Texas.