Gas monetization technologies remain tantalizingly on the brink

Gas-to-liquid must prove economically and environmentally efficient to break into the evolving gas market.

David Wood, David Wood & Associates and Saeid Mokhatab, Contributing Editor, LNG, World Oil

Despite being one of the most abundant energy sources on the planet, more than one-third of global natural gas reserves remain stranded so that they cannot be economically delivered to market.¹ About 70% of internationally traded gas is exported by pipeline, and the remaining 30% by Liquefied Natural Gas (LNG).

Over the last two decades, several other technologies have been evaluated and proposed for monetizing previously remote gas reserves, Fig. 1. These include Gas-To-Liquid (GTL), gas-to-wire, Compressed Natural Gas (CNG) and gas-to-solid technologies. The latter two technologies are in the research and development stage and, although the potential of these options has been explored in the past decade, no commercial projects exploiting them have been sanctioned. This article reviews the status of these technologies and identifies the hurdles preventing them from being commercialized on a wider scale.

Fig. 1 Technologies available to transport natural gas long distances.

DEVELOPING GAS RESOURCES

Remote natural gas, both non-associated and produced in association with crude oil, presents significant handling challenges. Gas cannot easily be transported by tanker, and long-distance undersea gas pipelines are extremely expensive, and are not technically or economically feasible in remote deep water. Growing global energy demand, diminishing oil resources, introduction of no-flaring rules, fiscal penalties and the environmental benefits of low greenhouse gas emissions from the burning of natural gas all lend urgency to the search for commercially viable technologies for handling and transporting gas over long distances.

The hydrocarbon liquid content of natural gas (i.e., Natural Gas Liquids, NGLs; Liquid Petroleum Gas or LPG; and pentane plus) continue to provide valuable revenue streams for gas field development. For this reason, IOCs prefer an integrated approach that facilitates NGL and gas revenues from upstream field development, as well as control over gas feedstock supply for downstream gas conversion plants. IOCs emphasize the total value of integrated upstream and downstream gas supply chains.

Anti-flaring legislation is encouraging development of stranded gas in many countries. Once a common industry practice, flaring is now widely discouraged, and many countries, including Nigeria and Norway, are instituting anti-flaring or emission policies and taxes to discourage wasting gas. In addition, a growing number of IOCs are introducing policies to reduce or halt flaring, and are pushing the development of gas conversion technologies.

Countries in West Africa are selling gas as a feedstock at very low prices-less than $0.25/MMBtu-to encourage employment and investment in gas conversion facilities. Gas-rich nations such as Qatar, Trinidad, Malaysia and Norway are integrating their marketing strategies to more efficiently produce numerous gas-derived products, and are building specialized gas-conversion hubs where numerous plants are located in close proximity. By creating such hubs, planners can allow multiple facilities to share processing and pretreatment infrastructure, utilities, ports, administrative offices, fire-fighting equipment, skilled labor and other specialized resources to mitigate capital costs. As a result, gas-rich nations diversify revenue while allowing developers to reduce capital costs.2

BRINGING STRANDED GAS TO MARKET

Alternative options for marketing stranded gas can be divided into three broad categories: export markets, combined-commodity projects and local or regional markets. Distance to market and size of the gas resource influence technologies that might be used to exploit remote gas fields. Large baseload LNG and Fischer-Tropsch GTL projects require very large reserves to justify the capital required to develop the upstream infrastructure. Figure 2 highlights how the technologies broadly fit together in a framework of production volume versus distance-to-market. There appear to be niches in this framework for projects to exploit CNG and smaller-scale LNG and GTL projects for gas fields with modest reserves. These alternatives have the potential to extend and diversify current global gas trade movement. The three broad markets identified are further characterized as:

Fig. 2 Production volume vs. distance to market for gas technologies.

Export markets. Nearly 8 Tcf of natural gas is converted annually to export products that are considered gas-derived, including LNG, methanol, ammonia, Fischer-Tropsch-derived middle distillates, olefins, synthetic waxes and lubricants, Di-Methyl Ether (DME), carbon black and a new product class called bioproteins. Falling trade barriers, declining interest rates and efficient transportation have expanded the demand for these products, leading to high levels of growth and investment.

Combined-commodity projects. Metal smelting projects consume large amounts of gas or electricity, are scale-intensive, and have relatively low transportation costs. In many instances, the cost savings achieved by using stranded gas outweigh the combined costs of transporting raw materials into the country and then transporting the refined goods out. Trinidad and Tobago, for example, is rapidly expanding its aluminum-smelting and iron-reduction infrastructure. Project developers can transport alumina into Trinidad, and then transport refined aluminum out more economically than they can transport low-cost energy into large bauxite-producing nations such as Australia, Guinea and Jamaica. The primary challenge for combined-commodity project developers is the complexity of identifying and executing multiple market and logistical strategies simultaneously. These projects often require the combined efforts of multiple corporations, governments and banks.

GAS-TO-LIQUID BACKGROUND

Direct conversion of methane into marketable petroleum liquid is not yet possible in commercial quantities. An intermediate step of partial oxidation of methane into hydrogen and carbon monoxide, called synthesis gas or syngas, is the process route to a wide spectrum of liquid products, Fig. 3. Unfortunately, syngas production is energy and capital intensive, and therefore costly, directly consuming about 25% of the total capital requirements of current methane conversion routes.

Fischer-Tropsch GTL. The chemical steps in producing larger, more complex liquid hydrocarbon molecules from naturally occurring fossil fuels are not new. Creating methane from hydrogen and carbon monoxide was first achieved by Paul Sabatier and Jean Senderens in 1902. Franz Fischer and Hans Tropsch further developed the synthesis to oxygenated products and liquid hydrocarbons in 1923. Fischer-Tropsch (FT) GTL is an application of the basic FT process, in which syngas is reacted in the presence of an iron or cobalt catalyst. End products are determined by the length of the hydrocarbon chain that, in turn, is determined by catalyst selectivity and reaction conditions.

FT-GTL is a three stage process: syngas generation, FT transformation and product upgrade. Possible end products include kerosene, naphtha, methanol, di-methyl ether, alcohols, waxes, synthetic diesel and gasoline, and water or carbon dioxide produced as byproducts. Natural gas or coal can be the raw feedstock.

Non-FT-GTL. In 2005, researchers from Texas A&M University published an article about a revolutionary gas-to-ethylene process that is a more direct conversion process than Fischer-Tropsch because it doesn’t require the production of syngas, making it far less expensive.³ The process is licensed by Synfuels International, Inc. and involves the separation and hydrogenation of acetylene to form ethylene using a catalyst formed by Synfuels.⁴

Methanol-to-Gasoline (MTG). Mobil developed the “M-gasoline” process to make gasoline from methanol. Mobil’s zeolite catalyst enabled a natural gas-to-gasoline project that operated from 1986 to 1997 in Motunui, New Zealand, producing about 14,000 bpd. Gas-to-gasoline economics mirrored oil-price volatility. The New Zealand MTG plant was a technical success, but a commercial failure with capital costs in excess of US$70,000 per barrel per day. The plant produced gasoline at costs above $30/bbl, when refinery-produced gasoline was trading at $15-$25/bbl.

Future commercial applications of the MTG process, using a fluid bed reactor, are anticipated, exploiting their higher efficiency and lower capital cost. The process is relatively simple, with no need to refine the intermediate methanol product, however the process does require the costly syngas step to produce methanol. MTG is commercially dependant on the final cost of production, plus freight to the consumer compared to the prevailing crude oil-derived gasoline retail price in the region. Also, outside the US most countries are focusing on middle distillate fuels for transportation where diesel markets are growing more rapidly than gasoline markets. MTG plants are therefore more likely to focus on producing gasoline for the US market.

MTG could directly compete with FT-GTL technologies in some areas, as both processes have the advantage of producing a transportation fuel that is compatible with existing distribution systems and infrastructure, which is a current advantage over hydrogen fuel.

GTL PROCESS EFFICIENCY AND MARKET SIZE

Technical advances in GTL processes are focused on lowering capital expenditures, establishing economies of scale and improving operating and energy efficiencies for large-scale FT-GTL plants.

In 2007, the global LNG industry produced about 170 million metric tons (mt) per year, and LNG is set to double that production over the next decade. The 2007 volume of LNG represents about 22 Bcfd of natural gas feedstock. A similar volume of gas feedstock at an FT-GTL plant would manufacture about 1.5 million bpd of premium quality diesel, a volume that represents only 5% of the global diesel market, indicating that GTL has huge market potential without running the risk of over-supply.

The manufacture of LNG involves a physical transformation from a gaseous state to a cryogenic liquid state with a thermal (energy) efficiency of up to 92%. In contrast, FT-GTL involves a chemical transformation of methane molecules into long-chain hydrocarbons. FT-GTL is energy intensive with a thermal efficiency of only about 60%. Previous research has claimed that such thermal efficiencies are not sufficient to make FT-GTL process commercial.⁵ Carbon efficiency is similar, about 77%, while LNG production can boast a carbon efficiency of 92%.

The environmental credentials of FT-GTL must also be discussed. The ultimate ultra-low-sulfur, high-performance diesel produced from FT-GTL processes is clean and involves lower greenhouse gas emissions than refinery-derived diesel. However, when the full cycle of emissions is considered, including emissions from the FT-GTL plant, the construction of the plant, and mining and manufacture of the catalysts, FT-GTL diesel is at best environmentally neutral from a global impact perspective of greenhouse gases. Redistribution of emissions can hardly be claimed as environmentally beneficial.

FT-GTL ECONOMICS

Economies of scale being sought by technology holders in 2004-5 were aimed at driving production costs of FT-GTL plants down into the $3-$5/bbl window. Labor, catalysts and utilities are the main direct operating costs involved. The new plants, commencing with the 34,000-bpd Oryx plant commissioned in Qatar in 2006, need to demonstrate that low production costs can be achieved in association with forecasts. Uncertainties associated with plant operating efficiencies and the volatility of oil prices are making some operators, governments and financial backers reluctant to progress with a large number of new plants. The pace at which GTL progresses worldwide will depend upon the performance of the Oryx plant and Shell’s Pearl 140,000-bpd GTL project in Qatar, which received final investment decision in early 2007.

Various reports from 2000 to 2005 suggested that FT-GTL could remain profitable in a modest-oil-price environment, i.e. $15-$25/bbl (Brent), with most reports favoring around $20/bbl. Shell stated that a stand-alone SMDS (Shell’s Middle Distillate Synthesis) project in the Middle East would be financially attractive with crude prices as low as $15/bbl.⁶ The gas feedstock supply must be available at a very low price, about $0.50/MMBtu or lower, to get close to the $15/bbl goal. In 2004, the capital cost estimates for building the Pearl plant were about $4 billion, rising to $6.5 billion for the fully integrated upstream field development and GTL plant. By 2007, the fully integrated budget had risen to more than $14 billion due to inflation. Such dramatic cost inflation caused other operators, like ExxonMobil and ConocoPhillips, to withdraw from similar-scale FT-GTL projects they had negotiated with Qatar.

Transportation costs from remote GTL plants also need to be factored. Moving FT-GTL diesel by marine tanker from a Middle East plant to the US could cost as much as $3/bbl. Transporting from the Middle East to Europe would be cheaper, but would still amount to $1.50/bbl. From the Middle East to East Asia would be the cheapest route at about $1/bbl.

Structuring developments as integrated projects also boosts economic returns and secures commitments for the several billion dollars of upfront capital required to build a commercial scale FT-GTL plant. Figure 4 illustrates the components of integrated and stand-alone projects. The project’s contractual structure significantly impacts the revenue streams available to the foreign operators and, perhaps more crucially, offers guarantees (or not) concerning the security of feedstock gas supply to a GTL plant at commercially viable prices. Several countries (e.g., Venezuela) have failed to grasp that integrated projects, whether for GTL or LNG, stand a better chance of support and commitment from international operators and investors.

SEARCHING FOR FT-GTL TECHNOLOGY ADVANCES

Higher prices for LNG around the world since 2005 have made LNG projects more attractive, creating problems for potential GTL ventures. Hence, IOCs are not prepared to sanction large-scale GTL plants using scaled-up technologies in a high-construction-cost environment.

Also, GTL progress in large gas-holding nations remains on hold, due to costs, and political and investment issues. In areas of political stability, like the North Slope in Alaska, technological and cost breakthroughs are required to enable GTL to unlock stranded gas, where much of the cost is tied into a pipeline to a southern Alaska plant location.

Adjunct technology might have a significant impact on costs, such as ceramic membranes that selectively extract oxygen from air. Various US, Australian and other researchers-both governmental and private-have been developing ceramics for the past five years. Infusing oxygen into the syngas-making process is essential, since pure oxygen boosts efficiency, but cryogenic oxygen production is expensive. Encouraged by the ceramic membrane results, the Ionic Transport Membrane Syngas Project, a 12-member industry, university and US National Laboratory consortium, began an eight-year project in 1998 to develop ceramic membrane technology that would allow syngas production at 25% less cost.

DEVELOPING SMALL FIELDS WITH FT-GTL

Large amounts of stranded gas and flared gas are located in fields too small for large-scale projects, and are often associated with oil or NGLs. These fields are of little interest to large IOCs, and cannot support a large-scale GTL plant. There are, however, technologies focusing on these smaller scale opportunities. One technology being developed by CompactGTL, a UK-based technology company, uses a streamlined syngas-FT process module to convert 50 MMcfd of associated gas into 5,000 bpd of unfractionated syncrude. The technology, which costs about $300 million in capital, can avoid substantial gas re-injection costs that are the alternative as no-flaring rules are enforced. This technology has captured the attention of Petrobras for possible deepwater offshore deployment on an FPSO vessel to avoid gas re-injection costs, and to add 10% to the revenue stream of a volatile oil field.

Other large companies like Statoil (in collaboration with PetrSA) and Eni have developed small pilot plants to demonstrate their own FT-GTL technologies. They are competing with the major IOCs for larger-scale GTL projects, but lack the patents and extensive pilot project experience to convincingly offer large-scale solutions. They may elect to develop their technologies on smaller-scale projects to improve their credibility in GTL prior to seeking alliances with gas-rich NOCs.

DME AS AN ALTERNATIVE GTL PROCESS

Di-methyl ether (DME, CH₃-O-CH₃) is a simple oxygenate that has physical properties similar to LPG, enabling it to be handled in a similar way. DME’s boiling point is -25°C at atmospheric pressure, rising to ambient temperatures under 5-6 bars (atmospheres) of pressure. Existing LPG tankers and receiving terminals could be easily converted to handle DME distribution. DME has been produced on a small scale by dehydration of methanol as a premium-price specialist chemical, and has potential as a clean, versatile and easily handled fuel that can be manufactured at a lower cost than FT-GTL diesel. However, to be price competitive in the fuel market, more efficient, larger-scale DME production processes are being developed.

In recent years, a number of new processes have been developed and offered for license by Air Products, Topsoe and JFE (a Japanese steel producer) involving a direct route to DME from synthesis gas, avoiding the intermediate step of generating methanol. The JFE process has progressed through a series of successful pilot plant tests since 2004, demonstrating energy efficiencies of 75%. These tests have involved a demonstration of the single-step DME process using a 100 mtpd (about 30 kmtpy) plant in Kushiro, Japan. The process involves a slurry-type reactor to more easily remove the large amount of heat generated by a single-step exothermic reaction.

In 2004, Total, as part of a Japanese consortium involving JFE and in conjunction with Qatar Petroleum, agreed to conduct a technical and economic feasibility study in Qatar of a 2 million-mtpy (6,000 mtpd) commercial DME plant with the objective of exporting to east Asian markets.

BP has also been involved in DME research and development with academic institutions in China, which commenced construction of its largest DME-from-coal project in late 2006 with an output of 3 million mtpy. The project is budgeted at $2.6 billion, will dwarf China’s existing output of 120,000 mtpy, and demonstrates the country’s commitment to developing DME markets in China as a clean energy alternative to burning coal.

Some of the challenges for DME are downstream. DME has potential to be used as a clean fuel in power plants, as a transportation fuel for both heavy goods vehicles and cars, and as substitute for LPG. However, some of the upstream cost savings relative to FT-GTL are offset by costs incurred in modifying engines and burner tips to handle DME.

OTHER TECHNOLOGY OPTIONS

Other options identified in Fig. 1 broaden the potential technologies beyond pipeline, LNG and GTL solutions, and are worthy of consideration when evaluating how to develop remote or stranded gas reserves.

Gas-to-wire. High Voltage DC transmission lines offer the most technically viable solution to moving large quantities of electric power over large distances (up to about 1,500 km), and keeping line losses less than 10%. Alternating current technology is only viable over short distances before suffering unacceptable line losses. However, HVDC is capital intensive and requires costly converter stations at either end of the transmission line. Indicative costs for a 1,200-km, 500-kV bipolar HVDC line to transmit 3 GW of power would cost close to US$2 billion. Additional costs for installing, operating and maintaining gas turbines at the remote site would be incurred. A conceptual project to locate a power plant on an FPSO adjacent to a GOM gas field 75 km offshore has been described.⁷ While HVDC cables are now being used more widely to transport electricity, no projects have been sanctioned to develop remote gas fields using HVDC technology, because distance, cost and efficiency of remote generation make other options more attractive.

Gas-to-solids. The concept of storing and transporting stranded gas to market as dry hydrates, hydrate pastes and hydrate in crude oil slurries has been extensively researched and laboratory tested for more than a decade. Gas hydrates are clathrates in which the guest gas molecules are occluded in a lattice of host water molecules, and are commonly encountered in the industry as a production problem in pipelines.

BG Group, Marathon, NTNU and others have worked on a range of gas-to-solids transportation technologies, and tested them at small-scale pilot plants, where concepts include storage and transport of gas.⁶ Even though these studies have shown that storing natural gas in hydrates is feasible, applications have not progressed beyond the laboratory stage because of complexities of the process, slow hydrate formation rates and costs.

Compressed Natural Gas (CNG). CNG offers proven technology that can provide an economic solution for remote offshore gas developments with small to medium reserves, or for associated gas reserves in large oilfield developments. CNG would be applicable where subsea pipelines are not viable because of distance, ocean topography, limited reserves, modest demand or environmental factors, and where LNG is also not economical due to its high cost of liquefaction and regasification facilities, and due to community or safety issues. Safety and security are issues for CNG, but the community-related safety and environmental issues that have prevented permitting of LNG receiving terminals onshore are eliminated by locating CNG offloading facilities tens of kilometers offshore.

Energy consumed in operating a CNG project is about 40% that of an LNG project, and about 15% that of a methanol or GTL project. Greater than 85% of CNG project costs are likely to be associated with ships, which are based upon conventional bulk carriers with at least four competing certified containment designs,⁸ of which the Sea NG (Canada)-patented Coselle (Fig. 5) is the first of to receive American Bureau of Shipping (ABS) approval for construction. According to ABS, Sea NG is expected to award construction of three Coselle CNG carriers in late 2007, but this has yet to be announced. These first vessels are intended to service projects in the Caribbean or Mediterranean Sea. Coselle CNG ships will be deployed to carry only moderate volumes of natural gas (30 to 500 MMcf) over medium distances (200-2,000 km), with a single Coselle carrying about 3MMcfg.

Feasibility studies to develop gas reserves in White Rose Field offshore eastern Canada have considered CNG technology for several years, using two or three vessels each with capacity of up to 1.2 Bcf of gas, with each vessel costing as much as US$300 million to build. In March 2006, GAIL, India’s state-owned gas company, issued a tender that attracted eight bids to build the world’s first CNG ship to transport gas from 650 km offshore Myanmar to India. However, that gas has been secured by China as part of a pipeline project across Myanmar. Other projects recently considered for possible CNG transportation include Papua New Guinea to New Zealand, and Trinidad to Jamaica.

No project has made a firm decision to proceed with one specific vessel design, and no CNG ship-building projects have been sanctioned worldwide. However, in January 2007, Japan’s Marubeni and Teekay joined Sea NG in a global alliance to develop CNG ships. The involvement of these major backers could finally get a commercial CNG project started.

LNG projects. Small, isolated demand centers, within reach of LNG baseload terminals, are attractive for small-scale LNG carriers operating direct deliveries, and for trans-shipment markets using micro-carriers along coastal routes. This model was developed in Japan and is being considered in Norway. Onboard regasification vessels, such as Excelerates’ EnergyBridge system operating the Gulf Gateway in the GOM, are also attracting interest, with a project completed to receive them in Teeside UK in 2007, and projects planned in Northern Brazil and Poland progressing in 2007.

However, small-scale liquefaction processes have not made commercial progress, in spite of being able to process a wide variation of feed gas compositions, and remove up to 70% of carbon dioxide as a contaminant from the feed gas. Each module could produce 5,000-50,000 mtpy of LNG, still too small to sustain all other offshore development costs involved.

Larger-scale regasification Gravity Based Structures (GBS) for shallow waters are approved for the GOM, although none are yet sanctioned for construction based upon cost. In Italy, the North Adriatic GBS LNG terminal is under construction for ExxonMobil and Qatar Petroleum and due for completion in 2008, and will have a 4.7 mtpy capacity. Large floating regasification terminals are also now being considered. In December 2007, ExxonMobil announced a proposal with BlueOcean Energy to build a floating regasification terminal about 20 mi off the coast of New Jersey and 30 mi south of Long Island, with a designed capacity of 1.2 Bcfd. Until now, plans for new onshore LNG receiving terminals in the Northeast US have been thwarted by public planning objections, and this project may lead gas import entry into other markets with onshore access restrictions (e.g. California).

CONCLUSIONS

FT-GTL has huge potential, but must prove technologically, economically and environmentally efficient before it can be considered a serious rival to LNG in developing and monetizing stranded gas reserves on a large scale.

FT-GTL reached a key milestone when world-scale-capacity plants began being planned, constructed and commissioned. Qatar has played a large role in moving the industry into the 100,000+ bpd scale. However, the cost of building and operating the plants will determine whether FT-GTL follows LNG in sustaining 10% year-to-year growth. With crude oil prices significantly above $50/bbl, some will argue that GTL can compete in the petroleum product markets even if GTL plant costs rise above $50,000/bbl of product capacity. However, the GTL industry has to demonstrate that it can efficiently deliver sustained production from large-scale plants, and will be able to compete in long-run crude oil prices of $30/bbl and below.

All eyes in the industry will be on the Oryx FT-GTL plant and the rival DME-GTL feasibility study being lead by Total and a Japanese consortium.

Much research is still ongoing with respect to other GTL processes, but none have reached large-scale commercialization, although further development, particularly in methanol or DME-to-gasoline plants, should be expected in this high-price gasoline market.

The environmental benefits of GTL products have been well demonstrated and have much potential in improving air quality in cities facing transportation fuel emission pollution. However, on a full-cycle environmental analysis, GTL fuels do not significantly outperform refinery fuels because GTL plants and their components involve substantial emissions. The problem is primarily connected to the low energy efficiency of syngas generation, and the low carbon efficiencies of FT conversion processes. Breakthroughs are required to improve these efficiencies.

Other technologies for unlocking stranded gas, including gas-to-wire, gas-to-solid, CNG and micro-liquefaction, are far from being commercialized in spite of many years of research and testing. CNG could be the first of these to establish a niche market, if high gas prices do not persuade investors to back LNG and pipeline solutions. The emergence of small-scale LNG transportation and shipboard regasification technologies provides some hope that these promising technologies will be considered as markets recognize their potential to out-perform conventional but expensive baseload gas transportation techniques.

LITERATURE CITED

¹ Thackeray, F. and G. Leckie, “Stranded gas: a vital resource,” Petroleum Economist, 69, 5, 2002.
² Wood, D. A., “LNG risk profile 1: Where we are: Relationships evolve along the gas supply chain,” Oil & Gas Journal, 103, 4, January 2005.
³ Hall, K. R., “A new gas to liquids (GTL) or gas to ethylene (GTE) technology,” Catalysis Today, 106, 1-4, Oct. 2005, pp. 243-246.
⁴ Synfuels International, Inc., “The Synfuels process,” Synfuels Technology Overview, http://www.synfuels.com/technology.html.
⁵ Fleisch, T., Sills, R., Briscoe, M. and J. F. Fteide, “GTL-FT in the emerging gas economy, in fundamentals of gas to liquids,” Petroleum Economist, January 2003, pp. 39-41.
⁶ Fischer, P.A., “How operators will bring ‘Worthless’ gas to market,” World Oil, 222, 11, November 2001.
⁷ Hill, P. J., Inozu, B., Wang, T. and J. J. Bergeron, “Offshore power generation using natural gas from remote deepwater developments,” OTC 14289 presented at Offshore Technology Conference, Houston, Texas, May 6-9, 2002.
⁸ Hatt, J., “Newfoundland poised to capture natural gas benefits,” Ocean Resources Online, December 2003.

THE AUTHORS
	David Wood is an international energy consultant specializing in the integration of technical, economic, risk and strategic information to aid portfolio evaluation and management decisions. He holds a PhD from Imperial College, London. Research and training concerning project contracts, economics, gas/LNG/GTL, portfolios and risk analysis are key parts of his work. He is based in Lincoln, UK, and operates worldwide. He can be contacted at woodda@compuserve.com, website www.dwasolutions.com.
	Saeid Mokhatab consults for multinational companies and research organizations in the natural gas industry. His areas of expertise include technical and commercial aspects learned while working in senior technical and managerial positions at several international oil and gas EPCM projects, partnerships and joint ventures as a solution integrator and key source of expertise.