As gas supplies tighten around the world, gas hydrate is being seriously considered as a potentially enormous natural source by a growing number of energy companies and national governments. Scientific drilling consortia such as the Ocean Drilling Program (ODP) and the Integrated Ocean Drilling Program (IODP) have yielded considerable data about the occurrence of gas hydrate in sediments.

Most recently, the government of India conducted a 113-day drilling program as part of an assessment of the hydrate resource potential of that nation's offshore territory. If the potential envisioned for gas hydrate is to become a commercial reality, the use of information gained from these programs will be critical.

Despite a growing knowledge of gas-hydrate occurrence, many old, erroneous concepts are deeply entrenched within the E&P community. Successful development of natural gas from hydrates will require an accurate understanding of the nature of gas-hydrate formation and occurrences, and especially an understanding of the relationship of gas hydrates to their host sediments-that is, a petroleum-systems approach. Through the integration of information gained during the past five years, production of natural gas from hydrate should be viable in the near term-within the life of recent deepwater leases.

Natural gas hydrate is a solid, crystalline material that forms when gases (such as methane) combine with water under conditions of relatively high pressure and low temperature. The hydrate structure consists of an open latticework of water molecules that is stabilized by the gas molecules residing within regularly located voids or "cages." A single cubic foot of gas hydrate yields approximately 164 cubic feet of gas at atmospheric pressure, along with about 0.8 cubic feet of water.

The physical conditions under which gas hydrate is stable have long been understood for pipelines, and the flow-assurance aspects of gas hydrate have been studied for decades. However, these conditions also exist in sediments along continental margins throughout the world where water depths are greater than approximately 1,600 feet, and in sediments below permafrost in polar regions.

Gas hydrate may occur in these locations at appropriate pressure and temperature conditions within a zone of hydrate stability that extends into the sediments to depths of up to many hundreds of feet. The base of the hydrate-stability zone is primarily determined by the geothermal gradient, as the increasing temperature of the deeper sediments crosses the hydrate-phase boundary. The thickness of the hydrate-stability zone varies with temperature, pressure, gas composition, salinity and other factors, and increases with water depth.

As the pressure and temperature conditions for hydrate stability occur along continental margins throughout the world, the potential for large accumulations of commercial gas-hydrate deposits would appear to be enormous. Other factors, however, are also required. First is an adequate flux of methane (or other hydrocarbon gases) into the sediment. The gas may be biogenic or thermogenic, but with either source there must be a mechanism for migration into the hydrate-stability zone. Sulfate in sediments fluids can react with methane; in locations with an insufficient methane flux, commercially viable gas-hydrate deposits will not be present.

The second factor is lithology. In most locations worldwide, the sediments within the hydrate-stability zone are predominantly shales; where hydrate is present, it comprises only 3% to 5% of the sediment volume. In contrast, sands within the hydrate-stability zone typically have high hydrate saturations within the pore space of the sediment, exceeding 80% saturation in some locations.

During the past 20 years, published literature on gas hydrates involves the debate on the total volume of gas hydrate in the world, and extremely large numbers are typically cited. From an industry perspective, however, that discussion misses the point.

What matters is the volume of gas that is concentrated in sediments that can be commercially recoverable. The vast amounts of hydrate dispersed in deepwater shales have little relevance to resource development.

Exploration for commercial gas-hydrate resources must include assessments of the pressure/temperature conditions of a basin; hydrocarbon source, timing and migration; and sediment distribution. Many of the world's basins have the necessary components for commercial gas-hydrate accumulations, and one of the most promising is the deepwater Gulf of Mexico, where prospect economics are enhanced by the presence of existing infrastructure.

The domestic oil and gas industry has largely avoided serious consideration of commercial gas-hydrate development because of valid economic considerations that have been based on early investigations. New information about hydrate formation and occurrence that has emerged in recent years has not yet been widely incorporated into industry planning. As a result, there are many outdated concepts or myths about the resource potential of gas hydrate that need to be dispelled if the remaining challenges of gas-hydrate development are to be addressed and overcome.



Four myths

Myth No. 1: A gas-hydrate deposit with commercial potential is always associated with a seismic "bottom-simulating reflector" (BSR). The base of the hydrate-stability zone may be identified on seismic data in some locations by a strong reflection with negative amplitude that results from the impedance contrast between hydrate-bearing sediments above the phase boundary and free gas-bearing sediments below. During the 1980s and 1990s, this seismic event, termed a "bottom-simulating reflector" (BSR) because it was observed paralleling seafloor topography and cutting across stratal boundaries in dipping sediments, was the primary means of identifying areas of interest for hydrate investigations. Cores recovered by ODP and IODP expeditions confirmed the presence of gas hydrate in sediments overlying the BSR.

By the late 1990s, hydrate exploration and assessment were commonly viewed as a "BSR hunt." The most pronounced BSRs were off the Carolina coast on the Blake Outer Ridge, and that location became the focus of gas-hydrate investigations for the U.S. In contrast, few BSRs were found in the Gulf of Mexico and, where present, they tended to be far weaker than those along the Atlantic margin. As a result, hydrate studies in the Gulf of Mexico focused primarily on seafloor hydrate mounds and near-seafloor accumulations associated with gas vents rather than on the potential of deeper hydrate reservoirs.

Drilling results during the past five years throughout the world have significantly altered these models. While hydrate is present in the sediments at the Blake Outer Ridge, the concentrations are low, 5% of the rock volume or less. In addition, the sediments in the hydrate-bearing interval are uniformly composed of about 60% clay. The poor reservoir lithology, the low hydrate concentrations, and the lack of infrastructure make the Blake Outer Ridge an unlikely candidate for commercial hydrate development.

A well-defined, mappable BSR is also present in Keathley Canyon at one of the sites drilled in 2005 by the U.S. Department of Energy (DOE) Gulf of Mexico Gas Hydrate joint industry project. In these wells, the sediment within the hydrate-stability zone was predominantly shale and low volumes of hydrate occurred well above the BSR.

Underlying the problem of using a BSR is the nature of the BSR itself. When present, a BSR indicates the existence of minute gas bubbles within the sediment beneath the phase boundary, but conveys little or no information about the overlying hydrate-bearing sediments. The BSR is useful in gas-hydrate assessments for delineating the base of the hydrate-stability zone, but is absent in many prospective basins. In some basins, strong, continuous BSRs may, in fact, delineate locations with poor reservoir lithologies.

Much of the gas-hydrate resource in the Gulf of Mexico occurs in discrete sands totally contained within the zone of hydrate stability and is unrelated to the presence of a BSR. Therefore, hydrate-bearing sands may or may not be associated with a BSR, and, where present, BSRs in sandy intervals often are discontinuous.

A successful exploration approach must consider gas-hydrate reservoirs as part of the broader petroleum system and take into account sand deposition and hydrocarbon migration. Using this approach, the deepwater Gulf of Mexico has excellent potential for commercial development of gas hydrate resources.

Myth No. 2: The best gas-hydrate deposits are in remote areas, far from current operations and under leasing and drilling moratoria. This myth grew out of the early emphasis on BSRs and on the strong scientific focus on the Blake Outer Ridge and other remote locations. The large volume of publications focused on that location was seen to imply that the Atlantic margin was a primary site for future hydrate development, and that, to be prospective, other areas should have comparable BSRs. Researchers studying the Pacific coast also identified gas-hydrate locations offshore California and Oregon.

As these areas were under moratoria and future leasing and drilling programs could be expected to generate significant resistance from a large segment of the public, a natural assumption developed for many in the oil and gas industry that gas-hydrate development would not be able to proceed for decades. In addition, most of the locations on the U.S. Atlantic and Pacific margins are lacking infrastructure, such as platforms and pipelines, severely affecting development economics.

With the information now available, it is clear that gas-hydrate deposits with commercial potential are most likely to occur in basins where stratigraphy and hydrocarbon migration are optimal within the hydrate-stability zone. These basins include the North Slope of Alaska and the deepwater Gulf of Mexico, where there is already oil and gas exploration and development and less political opposition to hydrate development should be expected.

In addition, large volumes of existing seismic data in these basins can be utilized to assess hydrate potential and the abundance of infrastructure significantly enhances the economics of development.

Myth No. 3: Development is 20 or 30 years away and will require entirely new methods of production. If the oil and gas industry's primary objective was to commercialize gas-hydrate-comprising deposits with a few percent of hydrate dispersed in shales (in 10,000 feet of water), an entirely new approach to development would be required and a 30-year timeframe might be overly optimistic. However, the production of gas from hydrate-bearing sands will mainly entail the adaptation of existing industry technology.

In the simplest case, where a hydrate-bearing sand extends down-dip across the phase boundary and includes free gas, simply producing the gas may lower reservoir pressures so that hydrates dissociate (revert to gas and water), feeding more gas into the reservoir. This production approach involves little new technology. Other production scenarios involve heating or other forms of stimulation that will yield higher production rates but also increase operating expense. As with conventional gas reservoirs, hydrate-bearing reservoirs will involve a range of drive mechanisms and the reservoir-engineering aspects need additional study.

In 2002, an international consortium achieved a successful flow test from hydrate-bearing sands at the Mallik structure in the Canadian Arctic. While the rates of production were deliberately kept low, the test validated the producibility of natural gas from hydrate.

Because of increasing gas demand, gas-hydrate research and appraisal programs are being undertaken in several nations, including the U.S. The most ambitious programs are those of India and Japan, with India planning commercial production of gas from hydrate before the end of this decade. Successful development there will doubtless accelerate development programs throughout the world.

Myth No. 4: Hydrate resources in the Gulf of Mexico have no net present value, so they can be ignored in lease sales. In 1998, the solicitor of the U.S. Department of the Interior determined that gas hydrate and associated free gas are included in the potential resources of deepwater outer continental shelf oil and gas leases. The Minerals Management Service, the agency responsible for management and regulation of offshore federal lands, recently completed a new assessment of technically recoverable gas-hydrate resources for the Gulf and other offshore U.S. basins.

This assessment used 3-D-multichannel seismic, logging-while-drilling (LWD) and electric logs, and other data to define sand fairways within the zone of hydrate stability and identify exploration wells that may have encountered hydrate within this sedimentary section. The DOE Gulf of Mexico Gas Hydrate joint industry project is also evaluating locations likely to contain hydrate-bearing sands for additional drilling legs in the spring of 2007 and 2008.

Significant technical, engineering and regulatory challenges will have to be overcome to delineate and begin production from Gulf gas-hydrate deposits. Shortages of natural gas, which could intensify from supply interruptions, will increase pressure to fast-track hydrate exploration and production.

Even before commercial production from gas-hydrate development programs in other countries appears to be imminent, the need to test production methods in the Gulf may be unavoidable. Deepwater operators should already be considering accelerated hydrate research programs to take advantage of the full value of some federal Gulf leases.



New activities

The pace of gas-hydrate research and assessment activity is accelerating with numerous field programs scheduled during the next two years. In early 2007, BP Alaska will drill, log and core a hydrate evaluation well in Milne Point Field on the North Slope. Successful results will likely lead to a production test within a few years.

Canada and Japan are conducting a production test of a hydrate-bearing formation in the Canadian Arctic this winter, and a longer-duration (75- to 80-day) production test during the winter of 2007-08.

China will conduct offshore drilling operations to assess hydrate resource potential this spring; and South Korea will drill for hydrates off its coast this coming fall. Following the initial results of its assessment program, India plans a gas-hydrate production test in 2008.

A growing international consortium of companies and government agencies led by Chevron drilled several wells in the Gulf of Mexico in 2005. Potential sites are currently being evaluated for the next phase of the consortium's program, with drilling operations beginning as early as mid-2007.

Long considered an opportunity for the distant future, gas hydrate is now rapidly emerging as a potential commercial resource. Operators in the Gulf of Mexico need to be aware of the gas potential from hydrates on their leases to assess their value properly. There are abundant opportunities for industry participation in these evaluation efforts. M



Arthur H. Johnson is president of Kenner, Louisiana-based Hydrate Energy International and retired from Chevron where he co-wrote the company's Gulf of Mexico program in 1995 for gas-hydrate studies. Michael A. Smith is U.S. Minerals Management Service team leader for geoscience operations in the Gulf of Mexico.