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.


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.

horizontal rule

[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).


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