Gas-to-liquids (GTL) technology is spreading around the world.

New technologies and high demand to sell and use stranded gas make GTL a high-growth industry for some companies and some countries that seek the best uses for their resources.
GTL offers some major advantages over the other two primary means of transporting natural gas. First, a GTL plant can be placed anywhere gas is available, and it can start small and grow as markets for the product grow. In many places, that makes more economic sense than building a pipeline from, say, the North Slope of Alaska to the southern tier of Canadian provinces.
Second, a GTL plant doesn't require the same infrastructure that a liquid natural gas (LNG) operation requires. The operator doesn't have to get access to ships built specifically to handle the liquid. That massive infrastructure requires substantial supplies of natural gas, and it doesn't grow easily to meet demand.
As scientists overcome the technological obstacles, the number of places in the world that support GTL plants grows exponentially.
Technology
All the methods for converting gas to liquids depend on the Fischer-Tropsch catalytic method. It isn't new. It has been around since the 1920s, long before the South African Coal, Oil and Gas Corp. (Sasol) built the first large-scale commercial plant in that country in 1955, according to a paper presented by T.G. Kaufmann, R.A. Fiato and G.C. Lahn of ExxonMobil Research and Engineering Co. and R.F. Bauman of ExxonMobil Process Research Laboratories for the World Petroleum Congress in Calgary, Alberta. The paper is titled "Advances In ExxonMobil AGC-21 Gas-to-Liquids Technology."
ExxonMobil's AGC-21 three-step process is one of the more advanced techniques incorporating more than 400 patents in the United States and 1,500 patents worldwide. The company refined its process at its 200-b/d plant in Baton Rouge, La., and is working toward larger-scale operations.
Basically, the company combines natural gas with steam and oxygen into a synthesis gas containing a 2-to-1 ratio of hydrogen to carbon monoxide.
It feeds that synthesis gas through a proprietary Fischer-Tropsch hydrocarbon synthesis step that coverts the H2/CO mix into heavy hydrocarbons with the help of a cobalt-based catalyst in a new-type slurry reactor.
That pariffinic product has a substantial amount of material with a boiling point above 650°F (343°C) but is solid at ambient temperatures and melts above 250°F (121°C).
In the final step, ExxonMobil converts that material into final hydrocarbon products through a hydroisomerization process that can be modified to adjust the end products.
ExxonMobil integrates the process steps to minimize the costs of steam and power generation and water treatment, according to the paper, and the technology can be combined with oil and gas production and treatment systems to increase efficiency.
In this process, the thin-layer cobalt catalysts and the slurry reactor produce higher hydrocarbon content products than traditional plants. In addition, the slurry reactor is simpler and costs less than traditional fixed-bed reactors, and it is easily scalable. That makes the technology well suited to large-scale projects in the 50,000-b/d to 100,000-b/d range.
As a result of technological improvements, ExxonMobil has doubled its early reactor productivity. In monetary terms, that means fewer reactors are needed for a given plant capacity.
At the tail end of the plant, the AGC-21 upgrading system converts the hydrocarbon synthesis system wax into clear, colorless liquids that are biodegradable, burn clean and have only a minor odor. They have no sulfur, nitrogen or aromatics and are excellent feedstocks for refining and petrochemical uses. A plant can produce nearly 80% diesel fuel.
As technology improved, costs fell. Today's product costs less than half of GTL products in 1990.
According to the authors of the paper, GTL plants will be commercial in any area with ample gas resources, including the Middle East, West Africa and the North Slope of Alaska. In Alaska, the liquid could be piped down the Trans-Alaska Pipeline.
Still ExxonMobil, BP and Phillips Petroleum seem to lean toward a natural gas pipeline for their stranded gas on the North Slope, and they've commissioned a US $75 million study to assure they make the right decision. It also is examining an LNG plant.
"LNG requires large economies of scale. It would require a multibillion-dollar investment up front" for infrastructure, including a pipeline to an LNG plant on the Cook Inlet, said Sir John Browne, chief executive officer of BP. "Gas-to-liquids has smaller economies of scale. Plants could be phased, reducing oil losses and up-front exposure."
BP engineers discovered that about half the capital cost of a GTL plant is in the reformer used to make synthetic gas from natural gas. Most systems require a large oxygen plant. BP's system uses a smaller reformer that doesn't require an oxygen plant. It uses ceramic membranes to draw oxygen from the air. As in the ExxonMobil model, fewer and smaller units mean lower costs.
GTL has another drawback in addition to technology that still is developing. The process consumes about 35% of the natural gas that goes into it, compared with 12% consumption in producing LNG, Browne said.
BP is ready to test its system. It has committed to build a pilot GTL plant at a cost of $86 million at Nikiski, Alaska, on the Cook Inlet. It has started site work on the plant and plans to produce 300 b/d of synthetic crude from 3 MMcf/d of natural gas.
GTL plans are in the works around the world. Rentech Inc. of Denver, Colo., with GTL Resources and Worley Engineers of the United Kingdom are studying the potential for a 10,000-b/d floating GTL plant offshore West Africa or off Australia's Northwest Shelf.
Rentech also is working with Indonesia's Pertamina on the feasibility of a 5,000-b/d to 15,000-b/d GTL plant in Indonesia.
Royal Dutch/Shell has an operating GTL plant in Bintulu, Malaysia. It started operating again last year after being shut down by a fire in the air-separation unit in 1997. That plant produces 12,000 b/d of product, and Shell wants to build a new generation of plants that can produce 70,000 b/d.
The government of Trinidad and Tobago is looking for partners to help build GTL plants to supplement expanded LNG production from the gas-rich islands.
US-based Reema International said it wants to put $300 million from an undisclosed investor into a GTL plant in Trinidad with plans to bring it on line sometime in 2003. If everything goes according to plan, that plant will use 100 MMcf/d of gas to produce 10,000 b/d of diesel, naphtha and other products.
Since Trinidad and a consortium of companies agreed to expand LNG production from the island's vast gas reserves at about the same time, it's reasonable to assume returns from production are similar.
Sicor of Houston, Texas, planned to send a delegation to Ethiopia to sign development contracts for at least one GTL plant, and feasibility studies are scheduled to start on a 10,000-b/d to 50,000-b/d plant in Bolivia if that government can approve amendments to its hydrocarbons law.
Other plans in the works include a deal between Statoil and the National Iranian Oil Co. on a possible plant near Assaluyeh, Iran, and an agreement between Shell International Gas, Egypt's General Petroleum Corp. and the Egyptian Oil Ministry to study a 75,000-b/d GTL plant.
According to Hart's Gas-to-Liquids News, nine GTL plants are operating, including pilot plants. Another six plants are under development with plans to start before 2004, and another eight plans are under discussion.
Decisions about GTL are not easy. Charles Baisden with the National Gas Co. of Trinidad posed a face-off of disadvantages of GTL and LNG.
Disadvantages of LNG include:
• high capital costs;
• low value-added and downstream potential; and
• low net-backs compared with other domestic gas-based industries.
Disadvantages of GTL include:
• questionable readiness in view of expected breakthroughs before 2005;
• questionable economics under pessimistic market prices and realistic gas pricing scenarios;
• caution by investors in moving forward ahead of potential advances; and
• reluctance among finance organizations and high-level decision-makers in light of the state of the technology.
In spite of the reluctance, a feasible GTL technology is coming. Every major oil company is working on at least one version, and some are studying more than one. With that array of talent assigned to making GTL work, it's only a matter of time.