ONE OF THE HOTTEST TRENDS in the global petroleum industry in 1997 involved a technology that is three fourths of a century old.
Economic conversion of natural gas to synthetic fuels, one of the "Holy Grails" of the energy industry for decades, took startling steps in 1997.
For the first time since the discovery of the Fischer-Tropsch synthesis process in 1923, gas-to-liquids conversion processes may be competitive with conventional petroleum products on the world market. And the technology doesn`t require an oil price of $30-40/bbl, as was the case with the failed synthetic fuels projects of the late 1970s and early 1980s.
After spending several hundred million dollars on research over several decades, several companies or groups late in 1996 and early in 1997 disclosed advances they claimed could make use of natural gas deposits deemed too remote or marginal for commercial development under conventional natural gas or liquefied natural gas schemes.
Converting these stranded gas resources-estimated to amount to as much as 14 quadrillion cu ft-to high-quality liquid fuels eliminates the barriers of: prohibitive costs for transportation and treating; inflexible, long-term contracts; and extreme financial and market risk. With a 10:1 conversion ratio-10 Mcf of pipeline-quality gas converts to 1 bbl of syntheticproduct-thesestranded reserves represent the equivalent of several hundred billion barrels of oil.
Potential resource
"It is hard to imagine a development with greater potential impact on supplies and suppliers of clean fossil fuels," said William S. Pintz, East-West Center, Honolulu, in a 1997 analysis. "Huge resources of stranded gas-shut in, flared, vented, and reinjected, representing a heavy burden of unrecovered costs and approximately half the world`s 5,000 tcf of proven reserves-now have the potential for profitable conversion to recoverable, booked assets of enormous value to companies and countries involved."
This trend has major implications for the future scope of the global energy industry, contends Pintz, among them:
- Many instant opportunities to convert stranded gas resources into marketable liquid products and yield a giant, immediate boost in the size and diversity of recoverable oil and gas resources worldwide.
- A major change in the traditional value relationship between oil and gas.
- A shift in capital investment toward natural gas in areas of the world where conversion to synthetic fuels is cheaper than extraction and processing of heavy, high-sulfur crude oil.
- A new approach in decision-making for explorationists who now will be able to focus on attractive natural gas prospects in regions hitherto avoided, leading to lower finding costs, higher success rates, and an increase in booked reserves.
- A much broader slate for conventional refineries, enabling them to use high-quality syncrude as a blending stock to bolster product yield and quality and cutting or even eliminating capital investments driven by environmental regulations on product characteristics.
- A new source of clean middle distillates, offering new options for refiners grappling with surging demand and new product specifications in this rapidly growing market.
- Valuable byproducts, such as electric power, water, and steam, generated from GTL conversion plants and creating power and process opportunities in remote locations.
- A secure, economic alternative for clean fuel for power projects hitherto reliant on LNG; this offers the prospect of nearly eliminating future grassroots LNG projects.
- Significant economic benefits for developing countries with undeveloped or underutilized gas resources.
Process evolution
Companies and governments have for decades been using Fischer-Tropsch chemistry to produce clean synthetic fuels, mainly from coal.
In the most well-known examples, politics rather than economics drove the process. The Nazis used it to fuel the German war machine in World War II after being cut off from oil supplies in Romania and the Caspian Sea region oil fields. Fischer-Tropsch chemistry is also at the heart of a 150,000 b/d synfuels industry in South Africa-the target of an international oil embargo during much of the 1980s.
Sasol`s development work began in 1955, using fluidized beds to produce synfuel from synthesis gas derived from coal and more recently using a slurry phase reactor and fused iron catalysts for full GTL production.
Later attempts to commercialize GTL technology were technically feasible if commercially short of the mark.
Mobil Corp. in 1986 built a plant that processed natural gas from a giant gas field off new Zealand into methanol, then into gasoline. With the oil price collapse, the New Zealand plant was no longer economic and was sold to Fletcher Challenge Ltd. in 1993; it now produces only methanol.
Royal Dutch/Shell in 1993 started up a GTL plant in Sarawak, Malaysia, that produces 12,000 b/d of middle distillates and some specialty waxes from natural gas. That effort, too, says Pintz, is considered uneconomic at current prices. Shell`s Bintulu plant fits a particular market niche and design not likely to be repeated elsewhere. Shell began work on its own GTL process in Amsterdam in 1973 as an offshoot of work in synfuel production from various sources that it had undertaken since the 1940s.
These were followed by announcements in 1996 by Exxon Corp. and Syntroleum Corp., Tulsa, of breakthroughs in GTL technology and economics.
In addition, Catalytica Inc., Mountain View, Calif., has received U.S. government funding to develop its own method to bypass part of the gas-to-liquids chain.
Exxon process
Exxon in November 1996 unveiled its GTL technology, dubbed Advanced Gas Conversion-21 (AGC-21), which it contends is competitive with oil prices at about $20/bbl (for West Texas intermediate crude).
AGC-21, proved in a pilot plant at Exxon`s Baton Rouge, La., refinery, involves three stages.
First, natural gas reacts with oxygen and steam in a fluid catalytic bed to yield a synthesis gas of hydrogen and carbon monoxide. Then, the synthesis gas is sent to a slurry reactor to react with catalysts to produce paraffinic hydrocarbons. These hydrocarbons are upgraded through a mild hydroisomerization process in a conventional fixed-bed reactor to produce high-grade synthetic liquids.
The critical breakthrough in the Exxon technology was the company`s development of proprietary catalysts for each of the three stages. The yield can be shifted to maximum output of diesel and jet fuel or naphtha and cat cracker feed, as the market demands. The high quality of the products is another competitive edge the process features by eliminating impurities including sulfur, nitrogen, nickel, and aromatics-a definite plus for the current push to reduce or eliminate certain polluting emissions from motor fuels.
Exxon plans
Exxon`s unveiling of AGC-21 came in the context of its announcement of negotiations with Qatar General Petroleum Corp. (QGPC), the state petroleum company of Qatar, regarding the application of its proprietary GTL technology to massive North gas field.
North field, located in the Persian Gulf, is one of the world`s largest gas fields. The project Exxon and QGPC envision would convert 500 MMcfd-1 bcfd of natural gas to 50,000-100,000 b/d of middle distillates and other products, such as naphtha or catalytic cracker feedstock for refiners. An an optimum-size project model implies gas reserves of 5-10 tcf with a 30-year field life.
Exxon contends AGC-21 is technologically ready for scaling up to a commercial level and suitable for remote, significant gas deposits. The proposed project covered by the feasibility study Exxon performed for QGPC would cost $1.2-2.4 billion. This, says Pintz, would translate to a plant investment of about $24,000/b/d, well below the $30,000/b/d considered the economic cutoff for synthetic fuels products at current oil prices.
Exxon also says that AGC-21 can operate with flexible output yields, requiring little or no incremental capital outlay to shift product slates: from conventional diesel and distillates to 52° gravity petrochemical feedstocks with no sulfur or other contaminants.
The company has booked gas reserves totaling 42 tcf and unbooked proven and possible gas reserves totaling 67 tcf. The latter includes huge deposits that are in remote, high-cost locations far from market (the Prudhoe Bay gas cap on Alaska`s North Slope) or technologically difficult and costly to extract (extremely high CO2-content Natuna gas field off Indonesia in the South China Sea). Selective application of AGC-21, by Exxon`s reckoning, can push a big chunk of those unbooked reserves into the booked column.
Syntroleum process
Work on developing the Syntroleum process began late in 1984, with the first patents issued in 1989.
That was followed by a 2 b/d pilot plant that operated during 1990-91. While these pilot runs were successful, they demonstrated the need to develop a proprietary catalyst system that could be tailored to the synthetic gas environment the process creates. Syntroleum developed several proprietary catalyst systems for use with variations of the process and continues to focus much of its resources in this area.
Syntroleum has built its process concept around an effort to keep a lid on capital costs.
In a typical Fischer-Tropsch process, more than half of the capital cost has been related to the production of synthesis gas, which is usually generated from natural gas through steam reforming or partial oxidation with oxygen-which requires an air separation plant-or a combination of the two.
In addition to being costly, these approaches involve inherent problems that must be overcome in order to produce an acceptable synthetic gas for the Fischer-Tropsch reaction; they also eliminate nitrogen from the syngas stream as an unwanted inert.
However, nitrogen is integral to the Syntroleum process, where the syngas step is based on autothermal reforming (ATR) with air in a proprietary-design, low-cost reactor. ATR entails placing a catalyst in a refractory-lined carbon steel reactor vessel, then feeding air and gas into the vessel at the right ratio and pressure to produce a nitrogen-diluted syngas within the desired hydrogen/carbon monoxide ratio of about 2:1. The syngas ratio can be further adjusted by introducing a small volume of steam or carbon monoxide into the reactor.
In a typical Fischer-Tropsch process, as much as 50% of the syngas would be diluted with nitrogen.
Syntroleum can incorporate nitrogen into the process because the Fischer- Tropsch section has no recycle loop; this avoids any buildup of nitrogen in the system, thus allowing the use of nitrogen-diluted syngas without impairing performance.
Accordingly, the Syntroleum Fischer-Tropsch reactor configuration is sized comparably but is less complicated than recycle systems because it eliminates the recycle compressor loop.
Syntroleum has focused its efforts on commercializing designs that could be adapted to a wide range of conditions. They entail:
- Two ATR designs.
- Three heat-integration designs.
- FourFischer-Tropschreactor designs for optimum flexibility; the fixed-bed horizontal reactor, for example, lends itself to platform, barge, and ship-mounted applications.
Two Fischer-Tropsch catalyst systems, the newest of which offers some added cost-saving changes to the process configuration.
Catalyst development
Syntroleum developed a high-alpha catalyst system built around a proprietary, highly active cobalt catalyst.
This catalyst produces a waxy synthetic crude that is mainly uniform straight-chain hydrocarbon molecules with relatively low (below 10%) methane yields. The waxy syncrude is then hydrocracked to produce fuels. With conventional hydrocracking and fractionation, processing the syncrude can be tailored for optimum yield of diesel or kerosine.
Work on the catalyst began in 1994, with partial funding from three undisclosed major oil companies. The objective was to develop a catalyst that limits the growth of hydrocarbon chains to eliminate wax production while simultaneously minimizing the production of C3-C4 hydrocarbons.
Multiweek test runs in a fluid bed reactor at the pilot plant yielded results that suggest added efficiencies, including: a lower operating pressure; the use of higher-capacity fluidized-bed reactors that cannot be used effectively with the high-alpha, wax-producing catalyst; and the elimination of a hydrocracking step.
Syntroleum then signed an agreement with an undisclosed international catalyst manufacturer to produce and supply the company`s proprietary catalysts to Syntroleum and its licensees.
Cost benefits
In tackling the problem of traditionally high capital costs for synthetic fuels plants, Syntroleum noted industry studies that found that a GTL plant could prove economic at installed capital costs of less than $30,000/b/d.
Syntroleum collaborated with Bateman Engineering, Denver, to develop several commercial-scale design and capital cost estimates.
In a 1995 study, the focus was on a 5,000 b/d first-generation GTL plant designed to yield diesel, kerosine, and naphtha. The study pegged the cost at $135 million, or $27,000/b/d. A subsequent study of a second-generation-design plant of 5,600 b/d delivered an installed-cost estimate of $97 million, or $17,300/b/d.
Syntroleum Pres. Mark Agee, in a talk to the American Institute of Chemical Engineers in Houston in 1997, noted that significant economies of scale are achievable with the process, especially for air compression trains.
"Preliminary review of a maximum-train size configuration indicates the likelihood of constructing a 20,000-25,000 b/d single-trainfacilityfor$12,000-14,000/b/d," Agee said. "That is roughly the same cost as a world-scale conventional refinery, a truly revolutionary development.
"When natural gas can be converted and refined into superior finished fuels for the same capital cost as a conventional crude refinery, a significant shift is likely to occur in the way investments are made in the energy industry."
Agee noted, however, that because of the limited applicability of large plant designs, the major goal in developing the Syntroleum technology has been to achieve low capital costs at relatively small scales. This would allow a GTL application to most of the world`s natural gas fields.
"At one end of the scale is a possible 500 b/d plant for isolated areas, justified by enabling the producer not only to monetize the gas that cannot be flared but, most importantly, to produce and sell the oil shut in by inability to dispose of the associated gas."
Syntroleum has begun work with a major oil company to adapt a design for a 2,000-2,500 b/d, barge-mounted plant in a remote location at an initial estimated cost of $55 million. Another adaptation could be a 100,000 b/d natural gas "refinery."
Syntroleum by late 1997 had licensed its process to London`s AMEC Process & Energy, Texaco Inc., ARCO, Marathon Oil Corp., and YPF SA.
ARCO and Syntroleum late in October 1997 unveiled a joint venture in which ARCO will construct a pilot-scale, GTL plant at its Cherry Point, Wash., refinery, with lab-scale studies to occur at Syntroleum`s labs in Tulsa. The pilot plant, slated to start up by fourth quarter 1998, will produce 70 b/d of synfuels ranging from diesel to heavy waxes.
Shell`s process
The Shell Middle Distillate Synthesis (SMDS) process is at the heart of an $850 million project at Bintulu, Sarawak, that can produce 12,500 b/d of middle distillates as well as raffinate and waxes.
The Bintulu plant, which started up in May 1993, is fed by 100 MMcfd from gas fields off Sarawak and 2.5 metric tons/day of oxygen.
It uses Shell`s proprietary gasification processtoproduceacarbonmonoxide/hydrogen syngas from the natural gas and oxygen. The Fischer-Tropsch process incorporates a proprietary Shell metallocene catalyst to synthesize heavy paraffins. The waxy product is then hydrocracked with a proprietary catalyst to produce middle distillates. The middle distillates are then fractionated in a conventional distillation unit.
Optimum scope for an SMDS GTL plant would entail 50,000 b/d of middle distillates, costing $1.5 billion and dedicated gas reserves totaling 3 tcf.
Shell contends such a project would be economic with oil prices at $15-20/bbl, with the breakeven point determined by whether low cost gas is available and plant construction costs are kept low.
Because the Bintulu SMDS plant is small and comparatively uneconomic in comparison with conventional middle distillates production, Shell decided to target specialized, high-return wax markets.
Middle distillates from Bintulu are used by Shell and by customers, particularly in California, to add to their diesel fuels to bring them into compliance with stringent emissions regulations.
Because of their high quality, waxes and raffinates from Bintulu are in demand for a range of applications from lubricants and drilling fluids to candles and packaging. But the wax market is not large enough to sustain another plant like Bintulu SMDS without decimating prices.
BP`s entry
Joining the GTL fray is British Petroleum Co. plc, which claims a breakthrough in plant design for the first stage of the GTL process, which accounts for more than half the capital cost of a GTL plant: reacting methane with steam or oxygen to produce syngas.
BP and Kvaerner AS, Oslo, have developed a compact reformer to cut plant size and cost.
This is achieved by removing heat from the catalyst-filled steel tubes within the reformer, thus enabling components to be packed together more closely, reducing the reformer`s size.
BP completed reformer design trials at Warrensville, Ohio, and separately developed a cobalt-based catalyst at a fixed-bed pilot plant at Hull, U.K.
The next step calls for BP and Kvaerner to build a demonstration plant to prove that both parts of their GTL process work together. BP puts the capital cost for this approach at $20,000/b/d.
First commercial plant?
But it is one of the GTL pioneers that is likely to be the first to build a full-scale, commercial GTL plant.
Sasol signed a memorandum of understanding with QGPC and Phillips Petroleum Co. to build a 20,000 b/d GTL plant at Ras Laffan, Qatar .
Exxon had been favored to win the first GTL plant deal, after long negotiations with QGPC to build a GTL plant there.
Sasol`s winning design will be based on its proprietary Sasol Slurry-Phase Distillate (SSPD) process, proven with a 2,500 b/d plant producing diesel fuel at the company`s Sasolburg complex near Johannesburg since 1993.
Sasol expected to complete a feasibility study sometime early in 1998 to fully assess the economics and viability of the Qatar plant.
Sasol`s SSPD
In addition to diesel, the SSPD process converts natural gas into high-quality kerosine and naphtha.
Sasol bases SSPD on the Fischer-Tropsch process and uses iron-based catalysts developed from the original iron catalysts used by the Germans.
The SSPD process involves three phases, all of which Sasol says have been commercially proven. The first step is natural gas reforming, in which gas is converted to syngas.
Then follows the Fischer-Tropsch process conversion of syngas into waxy hydrocarbons in the slurry-phase reactor developed and licensed by Sasol. The final stage is upgrading to middle distillates.
Since 1955, Sasol has operated the Arge process, which takes place in a tubular, fixed-bed reactor, to make wax from syngas at Sasolburg.
From this, Sasol developed SSPD, completing a 100 b/d laboratory model in 1990 to enable study of hydrodynamics, heat transfer, and product separation.
The development of the slurry-phase reactor has enabled Sasol to increase throughput-per-reactor, so that planned, full-scale GTL plants will consist of one or more units of 10,000 b/d capacity.
The Sasol slurry-phase distillate reactor is fed at the bottom with preheated syngas. This is distributed in a slurry of liquid wax and catalyst particles. As gas bubbles up through the slurry, it diffuses and is converted into more wax. Produced wax is separated from the slurry in a proprietary process.
Sasol says a single SSPD module will convert 100 MMcfd of natural gas into 10,000 b/d of liquid transport fuels. Such a plant would cost $300 million to build. Additional modules would decrease the per-unit cost.
"At a gas price of 50¢/MMBTU," said Sasol, "the feedstock cost is less than $5/bbl of product. Other fixed and variable costs are estimated at a further $5/bbl of product, resulting in a direct cash cost of production of about $10/bbl."
Sasol has also developed the Sasol Advanced Synthesis (SAS) process to convert synthesis gas to gasoline and light olefins.
An early version of the SAS process has been used since 1955 to produce 150,000 b/d of liquids from coal at Secunda and 7,500 b/d/reactor at the Mossgas plant.
Sasol has developed new SAS reactors that will have capacities to produce up to 20,000 b/d of syncrude. Seven of these are being installed at Secunda during 1996-99 to replace 16 existing reactors.
Indian project
A smaller-scale GTL project is in the offing in India, which faces soaring growth in demand for liquid fuels amid less-promising potential for growth in domestic oil production.
Behind the Indian project is Rentech Inc., Denver. The company has developed a GTL process and built a 250 b/d pilot plant at Pueblo, Colo., in 1993 to prove the technology.
Rentech`s process involves steam reforming of methane to make syngas that is bubbled through a slurry containing a proprietary iron catalyst to produce straight-chain hydrocarbons.
The Pueblo plant was shut down because of inadequate gas supply and has been shipped to Kumchai gas field in northeastern India, where as much as 4 MMcfd of gas has been flared. State-owned Oil & Natural Gas Corp. (ONGC) approached Rentech in 1995 after a feasibility study of ways to use Kumchai`s flared gas.
The Kumchai plant is to have a capacity of 360 b/d of clean diesel and waxes after its steam reformer is expanded and the plant reconfigured for different gas composition. It is scheduled to start up in mid-1998.
Texaco is negotiating with Rentech to accelerate commercial exploitation and licensing of the process.
Catalytica
As the company name suggests, the key to Catalytica`s approach to GTL is catalysts. Rather than take the same route to syngas production as other companies, Catalytica aims to develop a process to convert gas to methanol or synfuels involving direct oxidation.
Catalytica received $2 million from the U.S. Department of Commerce to develop its direct methane oxidation (DMO) process under a 3-year program.
The company said conversion of natural gas to methanol or syncrude typically relies on an indirect conversion process to yield syngas, which is complex and requires several steps.
Many attempts have been made to develop a DMO process to yield syngas, said Catalytica, but the reaction is difficult to run efficiently, and all attempts to develop a commercially viable process have failed.
The company believes its new group of catalysts, which it describes as highly selective, single-site, homogeneous catalysts, could cut methanol plant costs in half, saving more than $100 million/plant.
More significantly, it said, "Natural gas could be converted to gasoline and other fuels by way of the direct oxidation route at costs competitive with products derived from crude oil."
Catalytica said it has demonstrated feasibility of its DMO process in prototype systems, which have converted methane to a methanol derivative in one-pass yields as high as 70%.
DOE programs
The U.S. Department of Energy in 1997 selected Air Products plc, Walton-on-Thames, U.K., to lead an $84 million research program to develop a new membrane technology to cut the cost of syngas production.
In addition to a number of laboratories and universities, the project team includes ARCO, Chevron Corp., and Norsk Hydro AS and the Babcock & Wilcox unit of contractor McDermott International Inc., Alliance, Ohio.
Air Products thinks the new membrane technology may replace current cryogenic methods of making feedstock oxygen. The new membrane is a wafer-thin rare-earth oxide ceramic sheet through which air is passed. The membrane separates out the air`s oxygen.
If there is natural gas at the other side of the membrane, the oxygen-which comes in as highly reactive ions-will react with it to produce carbon monoxide and hydrogen.
The project`s first stage is to build a lab-scale plant; the second will be to build a 12 Mcfd experimental unit, and the third will be to construct a "pre-commercial" scale plant at La Porte, Tex., with capacity to produce 15 MMcfd of syngas.
Air Products thinks this program will cut the cost of making syngas by at least 30% and maybe as much as 50%. A field project is at least 5 years away, the company said.
Another key application for the membrane could be production of hydrogen from natural gas, a crucial development in the efforts to commercialize hydrogen as a motor fuel.
DOE also reported in 1997 that its Pittsburgh, Pa., laboratory was able to react natural gas with hydrochloric acid and oxygen to form methyl chloride.
A Dow-Corning project showed the technology is technically feasible, but low methanol prices make it noncommercial. Dow is working on an alternative route involving new reaction chemistry and better economics.
The Idaho National Engineering & Environmental Laboratory is in the early development phase of producing acetylene by injecting natural gas into a super-hot stream of hydrogen plasma. Acetylene can be used to turn hydrocarbon liquids into specialty chemicals.
DOE is also sponsoring a Cryenco Inc. and Los Alamos National Laboratory project to use sound waves to help liquefy gas.
This effort lends itself to small, more compact modules than the typical LNG plant. It would burn some of the gas to generate sound waves, which would drive an "orifice pulse tube" refrigerator. In theory, this system could make LNG for half the cost of traditional refrigeration of small volumes.
DOE sees advanced, lower-cost GTL technology becoming commercialized in the U.S. by 2010, with the result of reducing U.S. oil imports by as much as 500,000 b/d by then.
Other efforts
Also in 1997, a group unveiled plans to develop a ceramic membrane technology for converting natural gas to syngas.
The group consists of Norway`s Den norske stats oljeselskap AS (Statoil), Amoco Production Co., BP Chemicals Ltd., Praxair, and Sasol Ltd.
Statoil claims the new membrane will enable oxygen separation from air to be carried out alongside partial oxidation in a single unit, drastically cutting synthesis gas capital and production costs.
Sasol and Statoil also disclosed a joint venture to develop a floating GTL unit that could be fitted to a production ship or semisubmersible.
Sasol and Statoil hope to convert associated gas in offshore oil fields into synthetic crude oil so this can be mixed with produced crude and exported to shore.
Energy equation changed?
East-West Center`s Pintz thinks that the latest developments in GTL technology "radically alter the energy equation."
With that prospective change, the outlook for oil price stability improves dramatically, he contends: "Any upward pressure on prices should be relieved by the introduction of a large, additional proven source of liquid hydrocarbon fuels.
"Concerns about adequacy of supplies should also be pushed back farther into the future."
GTL will provide significant new options for meeting global energy demand, "creating great opportunities for some, threats to others, and challenges to all," Pintz said.
Perhaps first to feel that threat will be the liquefied natural gas industry.
"Prior to development of conversion technology, LNG was considered not just the first option for the large, distant power markets of Asia and Europe, often it was the only option," Pintz said. "That situation has changed dramatically. Many large LNG proposals face cost inflation, which mature technology has been unable to overcome, and their viability is questionable at present prices.
"At the same time, LNG sponsors face a new competitor, customers find they now have an option, and the emerging gas-to-synfuels industry sees a big opening."
Demand for LNG is forecast to double during the next 20 years, spurred in large part by growth in power generation. East-West Center estimates that expected volume of LNG is equivalent to 1 million b/d of synfuels, or incremental growth of 50,000 b/d/year, making LNG customers a likely target for GTL.
But synfuels producers may see their best opportunity in rocketing demand for middle distillates. East-West Center reckons middle distillates demand will jump by 3 million b/d during the next decade, orincrementalgrowthof300,000 b/d/year.
"Refiners will scramble to turn this new competitor into a partner with a solution to two problems: inadequate capacity to produce middle distillates and inability to meet stricter product specifications without costly new investment."
Pintz said that the energy industry may be at the threshold of another "strategic inflection point" with commercial GTL technology that could be a company maker (or a company breaker). He asks, "Is this the nascent megatrend that will overshadow all others as the 20th century winds down?
"For the world, there is the welcome prospect of additional decades of cleaner fossil energy, to be supplied by...whom? For all energy players, it`s decision time."
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Plant at Motunui, N.Z., which currently produces only methanol, was the site of one of the world`s few commercial-scale plants to produce liquid fuels, namely gasoline, from natural gas.
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