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Arthur H. Johnson, 2009. "Production of Gas from Hydrate: How Much and How Soon?", Unconventional Energy Resources: Making the Unconventional Conventional, Tim Carr, Tony D’Agostino, William Ambrose, Jack Pashin, Norman C. Rosen
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Resource estimates for gas hydrate that have been reported during the past 30 years have pointed to a truly vast potential, but one that has persistently remained just over the horizon due to technical and economic hurdles. It is only in the last 10 years that commercial development of gas hydrate has been considered in the context of a petroleum system. The new focus is on components such as source, migration, traps, seals, and reservoir lithology. The petroleum system model, combined with recent drilling efforts, has led to revised resource estimates and viable production scenarios.
Most of the world’s gas hydrate occurs in low concentrations in impermeable shales (comprising 3% to 5% of the sediment volume) or as isolated veins that cannot be commercially developed. In contrast, sands within the hydrate-stability zone typically have high hydrate saturations within the pore volume, exceeding 80% saturation in some locations. Although the gas hydrate reservoirs having commercial potential are only a small fraction of the global hydrate volume, they still have resource potential in the thousands of trillion cubic feet (Tcf). Although it is unrealistic to consider the global potential of gas hydrate to be in the hundreds of thousands of Tcf, there is a strong potential in the hundreds of Tcf or thousands of Tcf. The U.S. Minerals Management Service (MMS) estimates a total gas hydrate volume for the Gulf of Mexico of between 11,112 and 34,423 Tcf, and a mean estimate of 6,717 Tcf in place in sandstone reservoirs. A United States Geological Survey (USGS) assessment for the North Slope of Alaska reports a mean estimate of 85.4 Tcf technically recoverable from hydrate.
Gas has been produced from hydrate-bearing reservoirs on a very limited scale through short-term production tests in the Canadian Arctic and on the North Slope of Alaska. A long-term, industry-scale production test is planned for the North Slope in the summer of 2010 and the potential for hydrate development for local use following soon after. Production testing for hydrate in the Gulf of Mexico will follow within a few years. Japan is planning an offshore hydrate production test in 2011. Hydrate development programs are also in progress in India and South Korea.
Overview of Gas Hydrate
Gas hydrate is a vast potential energy resource that has not yet been proven to be commercially viable. Ongoing research programs in the U.S., Japan, India, and elsewhere have made great strides in understanding the formation of gas hydrate, identifying potential reservoirs where hydrate is concentrated, and developing production technologies for commercial exploitation. As technical and economic hurdles are overcome, significant opportunities are emerging for gas hydrate to contribute to the global energy mix.
Gas hydrate is a solid crystalline substance composed of water and natural gas (primarily methane) in which water molecules form a cage-like clathrate structure around the gas molecule. An important characteristic of gas hydrate is that the cage structure concentrates natural gas. When hydrate is either warmed or depressurized so that it is no longer within its stability conditions, it reverts back to water and gas, a process termed “dissociation.” The dissociation of a cubic foot of gas hydrate yields 0.8 cubic feet of water and approximately 160 to 170 cubic feet of gas at standard pressure and temperature (1-kPa, 20°C).
Gas hydrate is stable under conditions of moderately high pressure and moderately low temperature (Fig. 1). The oil and gas industry has long been aware of gas hydrate, as the temperature and pressure conditions under which hydrate is stable often occur in pipelines, leading to blockages. As a result, significant research has been conducted on the kinetics and dynamics of hydrate formation and dissociation. A variety of solutions are used by operators to prevent hydrate blockages including heating and injection of chemicals that inhibit hydrate formation or agglomeration. Sloan and Koh (2008) provide an excellent summary of the physical chemistry of gas hydrate.
The pressure and temperature conditions under which gas hydrate is stable also occur in nature and gas hydrate is widespread in marine sediments of outer continental margins and in sediments in polar regions. Although the volume of natural gas contained in the world’s gas hydrate accumulations may greatly exceed that of other gas reserves (Collett, 2002), a substantial proportion of that gas hydrate is in low-grade accumulations that are unlikely to be developed commercially. There is, however, growing evidence that natural gas can be produced from high-grade gas hydrate accumulations using existing conventional oil and gas production technology (Moridis et al., 2008).
In the marine environment, the pressure and temperature conditions for gas hydrate stability occur at water depths greater than 500 meters at mid to low latitudes and greater than 150 to 200 meters at high latitudes (Max et al., 2006). At these water depths, gas hydrate may occur within a zone of hydrate stability that extends into the sediment to depths of tens to hundreds of meters beneath the seafloor. The thickness of the hydrate stability zone varies with temperature and pressure, typically increasing with increasing water depth as a result of increasing pressure. The base of the hydrate stability zone is largely determined by the local geothermal gradient. At some depth beneath the sea-floor, the temperature will increase to a point where gas hydrate is no longer the stable phase (Fig. 2). As the geothermal gradient varies considerably within and between depositional basins, the thickness of the hydrate stability zone varies significantly at a global scale (Fig. 3).
In Arctic sediments, gas hydrate may occur within and beneath permafrost zones; the upper boundary of the hydrate stability zone is dependent upon local temperature and pressure conditions. As with the hydrate stability zone in the marine environment, the base of the hydrate stability zone in polar environments is largely determined by the geothermal gradient.
An important factor in the formation of high-grade gas hydrate deposits is the lithology of the host sediment. The highest concentrations of gas hydrate occur in sands and gravels where porosity and permeability are high. Cores recovered by drilling programs in both marine and polar locations from coarse-grained sediments have yielded hydrate concentrations of as great as 85% of the sediment pore space. In contrast, shales typically have gas hydrate concentrations of less than 6% of the bulk volume. The total volume of gas hydrate in fine-grained sediments represents the greatest proportion of the world’s gas hydrate, but the prospects for commercial development of natural gas from such a highly disseminated resource are very poor without a major paradigm shift in technology. Gas hydrate also occurs in localized concentrations filling fractures in shales. However, extraction of natural gas from shale-encased fracture accumulations is unlikely to be commercially viable in the near or intermediate term.
Even in locations with appropriate pressure-temperature conditions and excellent potential reservoirs, gas hydrate will not be present without an adequate supply of a hydrate-forming gas such as methane. The availability of gas to a suitable reservoir is dependent on a variety of factors include hydrocarbon source and migration. Gas may be generated from either biogenic or thermogenic sources. Evaluations conducted to date indicate that not enough microbial methane is generated internally within the gas-hydrate stability zone alone to account for the gas content of most hydrate accumulations. In addition most gas hydrate-bearing sediments have never been sufficiently heated or deep buried to yield thermogenic gas. Thus, most of the gas that has formed hydrate must have migrated into the hydrate stability zone from deeper sediments (Collett et al., 2008).
At the time of sediment deposition, the porosity of marine sediments is filled with seawater that is undersaturated with respect to methane, and thus a substantial flux of methane is needed for hydrate to form. Further, seawater contains sulfate that will react with methane. As a result, the methane flux must also be high enough to react with the entire sulfate in order for there to be dissolved methane in the sediment from which hydrate can form. A sulfate-methane transition zone (SMTZ) will occur at some depth beneath the seafloor, marking a boundary between sulfate-bearing sediment above the transition zone and methane-bearing sediment below (Fig. 4). From a resource standpoint, the SMTZ represents an upper limit for potential gas hydrate occurrence in the sediment. If the gas flux rate is low, the SMTZ may extend downward through the sediment to a depth greater than that of the base of the hydrate stability zone as defined by pressure and temperature. In such a case, no hydrate will be present.
The existence of gas hydrate in the West Siberian Basin of Russia was proposed in 1965 (Makogon, 1965) although this information was not widely disseminated to the West. In North America, Arctic sands containing gas hydrate were first logged as a result exploratory drilling in 1972 on both the North Slope of Alaska and in Canada’s Mackenzie Delta. Given the abundance of conventional gas and the lack of pipelines, these discoveries were little more than curiosities until the late 1990s. For example, in the Mackenzie Delta and adjacent Beaufort Sea, more than 70 wells have logged probable or possible gas hydrate, but with over 10 Tcf of conventional gas in the region and no infrastructure to transport gas to customers, little additional work on gas hydrates was undertaken for 25 years.
In the marine environment, gas hydrate-bearing sediments were encountered at a number of sites along continental margins during the early 1970s through investigations carried out by the Deep Sea Drilling Program (DSDP). In 1983, mounds of gas hydrate were discovered on the seafloor in the Gulf of Mexico associated with active vents. During the 1970s and 1980s, however, gas hydrate was viewed primarily as a scientific curiosity and a minor constituent in marine sediments. To-date, the presence of gas hydrate had been confirmed or inferred at more than 100 locations throughout the world through logging, coring, or seismic methods. Although not universally present in polar and continental margin sediments, gas hydrate is a common constituent of sedimentary rocks where the pressures and temperatures are within the hydrate stability zone and there is a sufficient supply of natural gas.
Production of Gas from Hydrate
Proposed approaches for gas recovery from hydrate include dissociation (conversion of the hydrate to gas and water), dissolution, and chemical exchange. Dissociation may be accomplished either by depressurization or thermal stimulation. Each approach has advantages and disadvantages related to operating expense, attainable flow rates, and volumes of produced water. Determination of the optimal approach will depend on specific reservoir conditions.
Depressurization (decreasing the reservoir pressure below hydrate equilibrium) may be accomplished either by producing subjacent free gas from a reservoir or by removing connate water. Production data from Messoyakha Field in the West Siberia Basin (discussed below) and the Barrow Gas fields on the North Slope of Alaska strongly suggest that pressure declines due to the production of free gas from these fields has led to hydrate dissociation in portions of the reservoirs that extend upward into the hydrate stability zone. Reservoir modeling points to depressurization as the most commercially viable production approach for Arctic reservoirs, as existing technology is fully adaptable for this purpose (Moridis et al., 2008). Production may be severely constrained for some reservoirs by the formation of ice and/or the re-formation of gas hydrate due to the endothermic cooling that occurs with gas hydrate dissociation. In addition, in the absence of a free gas leg, large volumes of water may be produced prior to significant gas production. This would have severe environmental and economic impacts.
Thermal stimulation would solve many of the production issues associated with depressurization, but although a number of creative designs for down-hole heating units have been proposed, that technology is not yet ready for deployment. In addition, the expenditure of energy for thermal stimulation will have a negative impact on development economics.
A commercial technology for the dissolution of gas hydrate using undersaturated water is under development by Japan. This approach has the advantage of low energy expenditure and avoids ice formation. The commercial viability of this approach may be limited in some reservoirs by production rates.
Natural gas also may be produced from gas hydrate through a chemical exchange such as a substitution of carbon dioxide for methane. This approach has the advantage of sequestering carbon dioxide while yielding commercial gas production (Graue et al., 2006). The technology involved is at an early stage of development.
Messoyakha Field (discovered in 1967, developed as a conventional gas field, and initial production in 1969) in the West Siberian Basin of Russia and has been cited as the first example of commercial gas production from in-situ gas hydrates. Models have indicated that the upper portion of the 250-foot producing sand at Messoyakha is above the hydrate/free gas phase boundary and contains gas hydrate (Makogon et al., 2005). The wells at Messoyakha have been completed in the free-gas portion of the reservoir; during the early years of production, the pressure declines followed the expected values.
By 1971, the reservoir pressures began to deviate from values predicted from free-gas production alone. This deviation was attributed to the dissociation of gas hydrate, resulting in additional free gas entering the reservoir. When the wells were shut in between 1979 and 1982, reservoir pressures increased to the level of hydrate temperature-pressure equilibrium. Further evidence of hydrate dissociation is found in the low salinities of the water produced with the gas. As the hydrate cage structure excluded sodium and chloride, water that results from dissociation was fresh. The salinity of the water produced at Messoyakha did not exceed 1.5%.
Through 2003, Messoyakha Field has produced 430 Bcf, and Makogon et al. (2005) have stated that 53% of that total has been derived from the dissociation of gas hydrate. The cost of producing the gas at Messoyakha is estimated to be 10-15% higher than for production of conventional gas alone from the same geographical area (Makogon et al., 2005). The increase is primarily due to the use of injected methanol to improve production rates and prevent the reformation of hydrate in flowlines and pipelines.
This interpretation of the Messoyakha data is not accepted by all researchers. No conventional cores have been recovered from the reservoir, and there has been no recent drilling in the field that would allow logging with modern wireline or logging while drilling (LWD) tools to provide a quantitative hydrate assessment. The concerns are summarized by Collett and Ginsburg (1998) and include the possibility that the anomalous pressure data is the result of slow migration of conventional gas through reservoir sands having low permeability. Given the pressures and temperatures that have been recorded in the Messoyakha reservoir, it is likely that gas hydrate is present in the reservoir and that the decrease in pressure during the life of the field has resulted in some volume of hydrate dissociation. A dedicated research drilling program would be useful for clarifying the production issues, as well as for an assessment of the effect of 30 years of dissociation on hydrate-bearing sands, however no additional research is currently planned for Messoyakha Field.
The resource potential of gas hydrate is being actively investigated by government agencies and academic institutions in many countries; several energy companies participate in these studies. The nations having the most active programs are Japan, the United States, India, Canada, South Korea, and the People’s Republic of China. Several other nations are at a preliminary stage of investigation. Collaborative international programs have been of critical importance in gas hydrate research, especially the Ocean Drilling Program and its successor, the Integrated Ocean Drilling Program. These programs have identified hydrate-bearing sediments in dozens of locations (Fig. 5).
While the presence of hydrate-bearings sands had been established in Canada’s Mackenzie Delta in 1972, it was only during the 1990s that the large resource potential of gas hydrates began to generate interest. Canada was interested in better defining its domestic resource base and at the same time, interest in gas hydrate grew in Japan where gas hydrate potential had been inferred by seismic data and conventional gas resources were minimal. In 1998, field operations were conducted at the Mallik structure on the Mackenzie Delta by an international consortium led by JAPEX/JNOC and the Geological Survey of Canada with technical assistance from the USGS. The Mallik 2L-38 well collected core samples, wireline logs and downhole seismic data and confirmed the presence of substantial volumes of gas hydrate. The total volume of gas in place on the Mallik structure was estimated at 3.9 Tcf. The sands and gravels within the hydrate stability zone contained hydrate pore saturations of up to 80%, while the interbedded shales contained little or no hydrate (Collet et al., 1999).
The 1998 Mallik Field program yielded important information on the origin and occurrence of gas hydrate and tested new methods for drilling, coring, and assessing hydrate-bearing sediments. However, it was not designed to assess the production potential of the Mallik reservoir. In 2001, a larger consortium was established that also included the Indian Ministry of Petroleum and Natural Gas, India’s Oil and Natural Gas Corporation Ltd. (ONGC) and Gas Authority of India, Limited (GAIL), Germany’s GeoForschungsZentrum (GFZ), and the Chevron-British Petroleum-Burlington joint venture group.
The consortium drilled two observation wells and a production well on the Mallik structure in 2002 and recovered 480 feet of high-quality cores. As with the Mallik 2L-38, gas hydrate was concentrated in coarse-grained sediments and virtually absent from shales and silts. The most important results of the 2002 Mallik Field program came from a series of production tests. An extended production test would have been optimal from an industry standpoint, but logistical and budget constraints prevented such a test. Instead, a series of carefully designed, low volume production experiments were carried out that assessed the response of hydrate bearing sediments to depressurization and heating. The results of these experiments were integrated into reservoir simulation models.
Three depressurization experiments were conducted in the Mallik 5L-38 well and demonstrated that a reduction in formation pressure alone could yield gas production. In addition, the experiments demonstrated that artificially fracturing the reservoir will greatly enhance production by increasing the surface area of the hydrate-bearing sand. Hydrate-bearing reservoirs had been assumed to be impermeable, but the results of the Mallik test showed that some of the dissociated gas moved into the formation instead of into the wellbore (Mallik 2002 Partners, 2003).
The 2002 Mallik program demonstrated that gas production from hydrate-bearing sands is technically feasible and made a substantial contribution to the understanding of gas hydrates, but fell short of providing all of the data needed to fully calibrate existing reservoir modeling programs to assess the technical viability of commercial production from gas hydrates.
An additional field program was carried out by the Japan Oil, Gas and Metals National Corporation (JOGMEC) and Natural Resources Canada (NRCan) during the winters of 2006-2007 and 2007-2008. In the 2006-2007 phase, equipment and instruments were installed to allow for production testing of a hydratebearing sand during the following winter. The 2006-2007 activities included deepening and logging two of the Mallik wells. The primary operation conducted in 2007-2008 was a six-day pressure drawdown test that established a continuous gas flow of 70,000 to 140,000 cubic feet per day. In total, approximately 460,000 cubic feet of gas and 850 barrels of water were produced. Although verifying that production could be sustained by depressurization alone, the 2006-2007 Mallik test fell short of demonstrating that commercial production is actually achievable from a hydrate reservoir. In particular, a far greater understanding of the response of a hydrate reservoir to long-term dissociation and production is needed.
In response to a lack of domestic energy resources, the government of Japan established a wellfunded gas hydrate research program in 1995 for the nation’s continental margin. Goals for the program include basic research, the identification of significant gas hydrate deposits, assessment of gas hydrate volumes, development of production technology, and assessment of environmental impacts. The research program involves government agencies, corporations, and universities.
In addition to the field operations conducted in the Canadian Arctic (where operations are less expensive than in deep water), Japan has conducted two drilling projects in the Nankai Trough area on its Pacific margin. In late 1999 and early 2000, the Japan National Gas Hydrate Program drilled several closely spaced coring and logging holes at a water depth of 3,100 feet that identified multiple hydrate-bearing sands totaling approximately 50 net feet. Gas hydrate saturation of the pore space of the sands was as high as 80%.
In 2001, the program was expanded and designated “Japan’s Methane Hydrate Exploitation Program,” operated by the Methane Hydrate 2001 Consortium, abbreviated “MH21.” Seismic surveys were conducted in 2001 and 2002, followed by a 16-well drilling program in 2004 in water depths of 2,360 to 6,660 feet. The 2004 program led to the refinement of exploration models and provided a large volume of subsurface data for the characterization of hydrate-bearing sands. In addition, Japan demonstrated the feasibility of horizontal drilling in the shallow subsurface.
Sand-thickness values vary considerably for the 16 wells, owing to stratigraphic variability due to the presence of distributary channels and distal lobes within a submarine fan system composed of very fine-to fine-grained turbidite sands. Individual units range in thickness from less than 2 inches to 3 feet. Average gas hydrate saturations in the sands that contained hydrate range from 55 to 68% and have average porosities of 39-41% (Fujii et al., 2009). Japan has announced plans for a production test in the Nankai Trough by 2011. Japan also plans to have the technology in place for commercial production by 2016.
In 1982, the U. S. Department of Energy (DOE) established the initial American research and development program to investigate the resource potential of gas hydrate, in a coordinated effort with the USGS and several other organizations. During the ten years that this program existed, a large volume of data was compiled that validated the existence of huge volumes of gas hydrate in various parts of the world. As gas hydrate concentrates natural gas it was evident that gas hydrate represented an enormous potential energy resource.
The Methane Hydrate Research and Development Act of 2000 was enacted by Congress following a series of workshops sponsored by DOE and involving participants from the oil and gas industry, academia, and government agencies. The agencies included USGS, MMS, the Naval research Laboratory (NRL), the National Science Foundation (NSF), and the National Oceanic and Atmospheric Administration (NOAA). The legislation called for the Secretary of Energy to establish an interagency methane hydrate program that would:
Conduct basic and applied research to identify, explore, assess, and develop methane hydrate as a source of energy.
Assist in developing technologies required for efficient and environmentally sound development of methane.
Undertake research programs to provide safe means of transport and storage of methane produced from methane hydrates.
Promote education and training in methane hydrate resource research and resource development.
Conduct basic and applied research to assess and mitigate the environmental impacts of hydrate degassing (including both natural degassing and degassing associated with commercial development).
Develop technologies to reduce the risks of drilling through methane hydrates.
Conduct exploratory drilling in support of these activities.
The act created a Methane Hydrate Advisory Committee composed of representatives from industry, academia, environmental organizations, and government agencies. In addition, an Interagency Coordinating Committee was established to ensure communication and cooperation among the various federal organizations involved. The program was reauthorized as part of the Energy Policy Act of 2005, and the Bureau of Land Management (BLM) was included in the interagency organization.
An ODP Drilling program carried out in 1996 (Leg 164) investigated a gas hydrate occurrence in sediments of the Blake Outer Ridge along the southeast margin of the U.S.; this area had been a dominant focus of early U.S. gas hydrate efforts. Unfortunately, the hydrate present at the Blake Outer Ridge was in low concentrations and the host sediment was composed primarily of foraminifera-rich clay. The volume of gas hydrate associated with the entire area, even at low concentration, led to large estimates of gas in place, but with no potential for commercial resource development the focus on the Blake Outer Ridge did little to generate interest from the U.S. oil and gas industry. The program initiated in 2000 continued the study of the Blake Outer Ridge, but with stronger industry guidance the program expanded to include the Gulf of Mexico and North Slope of Alaska.
Gulf of Mexico
With industry input, a primary initial focus of the federal gas hydrate program became assurance of safe conventional deepwater drilling and production operations in the Gulf of Mexico where hydrate-bearing sediments may be present. In 2001, Chevron formed a joint industry project (JIP) and developed with Schlumberger a proposal to conduct research on gas hydrate deposits in the deepwater Gulf of Mexico. The proposal was submitted to the DOE’s National Energy Technology Laboratory in April, 2001 and Chevron was awarded a contract. The Gulf of Mexico JIP was then established as a collaborative government-industry effort that would include university participation. Corporate membership has increased since the JIP was established, and in addition to Chevron and Schlumberger now, includes ConocoPhillips, Halliburton, MMS, Total, JOGMEC, Reliance Industries Limited, The Korean National Oil Company (KNOC), and StatoilHydro.
Substantial technical support for the JIP has been provided by the USGS and NRL. Among the academic institutions contributing to the JIP are Scripps Institute of Oceanography, Georgia Institute of Technology, and Rice University. Additional technical support has been contracted to AOA Geophysics, Aumann & Associates, and GeoTek Ltd.
The initial objective of the JIP was to develop technology, tools, and data to assist in the characterization and prediction of naturally occurring gas hydrates in the deep water Gulf. Additional objectives included understanding the effect of gas hydrate on seafloor stability and gathering data for use in the study of climate change. Resource evaluation was less of a priority during the initial project phase.
In 2005, the JIP drilled, logged, and cored multiple locations in Atwater Valley Blocks 13/14 and Keathley Canyon Block 151. The Atwater Valley results indicated the possibility of minor amounts of hydrate present in the sediment based on measurements of pore-water salinities, although no hydrate was recovered in the cores. The presence of gas hydrate in the Keathley Canyon wells is inferred by resistivity logs and cold spots detected on the recovered cores, although no physical samples of gas hydrate were recovered. Lee and Collett (2008) estimate hydrate saturations of up to 40% in some thin sands in one of the wells, but with saturations averaging approximately 10%.
The U.S. Minerals Management Service (MMS) released a preliminary report on the abundance of biogenically generated gas hydrate in the Gulf of Mexico in February, 2008. The MMS estimated a total gas hydrate volume for the Gulf of Mexico of between 11,112 and 34,423 Tcf and has a mean value of 21,444 Tcf. The MMS modeling predicts a mean estimate of 6,717 Tcf in place in hydrate-bearing sands (Frye, 2008).
Following detailed analyses of the data collected in the 2005 program, the JIP expanded its focus to include coarse-grained sediments that could have commercial potential. The presence of hydrate-bearing sand in the Gulf had been confirmed by the Chevron Alaminos Canyon 818 well that had logged high saturations of gas hydrate in the upper 65 feet of an Oligocene Frio sandstone in a water depth of approximately 9,000 feet. In May, 2009 the JIP conducted a 21-day expedition that drilled and logged a total of seven wells in Walker Ridge Block 313, Green Canyon Block 955, and Alaminos Canyon Block 21. At least 2 of the 3 locations found highly saturated gas hydrate accumulations in reservoir quality sands, and all deposits were found to be in close accordance with pre-drill predictions. Additional analysis of the 2009 program is on-going and due for publication in 2010.
The initial discovery of hydrate-bearing strata on the North Slope of Alaska occurred in 1972 with the drilling, logging, and coring of the Northwest Eileen State-2 well. The presence of gas hydrate in more than 50 other exploratory and development wells has been inferred from well log data (Collett et al., in press). Based on log data, the volume of gas within the gas hydrates of the Prudhoe Bay-Kuparuk River area was estimated by Collett (1993) to range from 35.3 to 42.4 Tcf, volumes that are approximately twice the volume of conventional gas in the Prudhoe Bay field. A potentially larger gas hydrate accumulation is in the vicinity of Tarn field.
With its large resource potential and industry infrastructure, the gas hydrate deposits on the North Slope have been a significant focus of the U.S. Methane Hydrate Research and Development Program. In 2003-2004 Anadarko Petroleum Corporation and DOE drilled a hydrate test termed “Hot Ice.” The target was the Tarn accumulation. However, the well appears to have been drilled too far downdip and did not detect gas hydrate.
BP Exploration (Alaska), Inc. and the DOE established a project in 2002 to characterize and quantify the gas hydrate resources in the vicinity of the Prudhoe Bay, Kuparuk River, and Milne Point fields, and determine their commercial viability. The project was a collaborative effort that has included the USGS, the University of Alaska (Fairbanks), the University of Arizona, and Ryder-Scott Company. During the initial project phases the project team conducted regional geological, geophysical, engineering, and production modeling studies. The Mount Elbert gas hydrate stratigraphic test well was drilled in Milne Point Field in 2007. The well was extensively logged and cored, and then Schlumberger Modular Dynamic Testing (MDT) was conducted in two sandstone reservoirs. Gas was produced from the gas hydrates in each of the tests. A long-term, industry scale production test in planned for 2010. Additional gas hydrate projects are planned for Alaska, including a field test of carbon dioxide substitution in a gas hydrate reservoir and a logging and coring test in the Barrow gas fields.
Other U.S. research
In addition to the Gulf of Mexico and Alaska projects, the U.S. Methane Hydrate Research and Development Program has supported a broad range of research projects. These include university studies, support for international drilling/evaluation programs, and a gas hydrate seafloor monitoring station in the Gulf of Mexico. While some of the funding for the U.S. effort has come from the USGS, MMS, BLM, NOAA, NSF, NRL, most has been through the DOE. Congressional authorizations for the program under the Energy Policy Act of 2005 were for $30 million in 2008, rising to $50 million for 2010 and beyond, the actual appropriations have been for less than half of that amount. As the program evolves to include expensive field operations in Alaska and the Gulf of Mexico, timelines may have to move back as a result of funding shortfalls.
With demand for natural gas far exceeding domestic supply, India is actively pursuing options that include liquid natural gas (LNG) imports, increased offshore drilling for conventional gas production, coalbed methane, and gas hydrate. India established a National Gas Hydrate Program (NGPH) under its Directorate General of Hydrocarbons in 1997. In 2006, NGHP Expedition 01 drilled 39 wells at 21 sites on India’s continental margin. Gas hydrate was recovered from nine of the wells. However, the hydrate typically occurred as fracture fill in fine-grain host sediments and is thus not suitable for commercial development.
The depositional setting of the Bay of Bengal suggests the potential for reservoir-quality sands within the hydrate stability zone and it is likely that India will initiate an NGHP Expedition 02 within a few years.
The People’s Republic of China established the Guangzhou Center for Gas Hydrate Research (CGHR) in 2004 to evaluate the nation’s gas hydrate resource potential and conduct field operations. A drilling expedition was carried out in 2007 in the South China Sea that included eight sites, five of which were cored. Gas hydrate was identified at three of the sites. However, the gas hydrate occurs within fine-grained, foraminifera-rich clay sediments unsuitable for commercial development. Future expeditions may be under consideration.
South Korea established the Korean Gas Hydrate Research and Development Organization (GHDO-K) as a joint government-industry program with goals that include assessing the gas hydrate potential of the Ulleung Basin and establishing the production of natural gas from gas hydrate by 2015. South Korea conducted an initial gas hydrate drilling program in 2007 with five locations drilled and logged. Three of the locations were then cored. Gas hydrate was recovered from all three cored holes, with hydrate occurring in interbedded sand and clays. Future drilling and testing are under consideration.
Other national programs
The need for additional natural gas resources has encouraged the establishment of gas hydrate research programs in several other countries that have deepwater margins. Many of these nations lack the technical or financial resources to pursue drilling operations, or have higher funding priorities with other energy resources. However, opportunities exist for collaborative international efforts in the future. Nations that have initiated gas hydrate investigations at some level include Chile, Ireland, Mexico, New Zealand, and Uruguay.
Eight estimates of global gas hydrate volumes were published between 1977 and 1990 (Kvenvolden, 1993), yielding values of 1015 to 1018 cubic meters (1017 to 1019 cubic feet). There is insufficient data to validate any assessment of global gas hydrate volume however these values have been widely quoted and have formed the basis of many misleading estimates of the resource potential of gas hydrate. The largest proportion of gas hydrate occurs in fine-grained sediments, typically comprising 3% to 5% of the sediment volume and as isolated veins that cannot be commercially developed. Thus, any valid estimate of resource potential must be confined to the high-grade deposits of hydrate-bearing sands and gravels. The gas hydrate reservoirs with commercial potential are only a small fraction of the global hydrate volume. It is unrealistic to consider the global potential of gas hydrate to be in the hundreds of thousands of Tcf; however there is a strong potential for the gas resource from gas hydrate to be in the hundreds of tcf or thousands of Tcf. The relative abundance of the high-grade and low-grade deposits is illustrated by the gas hydrate resource pyramid developed by Boswell and Collett (2006) (Fig. 6).
High-grade gas hydrate deposits are located where pressure-temperature conditions occur with appropriate reservoir lithology and adequate gas input. Other than a few locations, such as the North Slope of Alaska, these parameters have not been adequately quantified at the shallow depths where gas hydrate may be present, even in areas with extensive conventional oil and gas drilling. Thus, the range of value for gas hydrate resource estimates must extend over several orders of magnitude.
The base of the hydrate stability zone may be identified on seismic data by a strong reflection that is commonly termed a “Bottom Simulating Reflector” or “BSR” (Fig. 7). The BSR is caused by an impedance contrast between hydrate-bearing sediments above the phase boundary and gas-bearing sediments below. The association of the base of the hydrate stability zone with the BSR strongly influenced early assessments of gas hydrate potential. Those locations with strong, extensive BSRs were rated as having the highest hydrate resource potential, while locations without BSRs were considered to have little or no hydrate.
Drilling results during the past 10 years have significantly revised this view, with strong BSRs common in fine-grained sediments having low hydrate volumes and poor reservoir potential. In addition, hydrate-bearing sands have been logged in locations without BSRs. The presence of a BSR is, at best, an indicator of the phase boundary at the base of the gas hydrate stability zone and an indicator of the presence of gas, but it conveys little direct information about the amount of gas hydrate that might be present.
Despite the inherent shortcomings of BSRs, hydrate assessment programs have often been viewed as “BSR hunts.” A more successful approach entails an integration of regional and basin stratigraphy as well as an assessment of hydrocarbon source and migration, along with an evaluation of the probable boundaries of the gas hydrate stability zone (Max et al., 2006). In a full petroleum systems approach for resource assessment, a BSR can help constrain the location of the hydrate resource but is only one element of a successful analysis. Geophysical methods that have proven successful in quantifying hydrate accumulations are described by Dutta and Dai (2009).
A successful result from the industry-scale gas hydrate production test planned for the North Slope would prove that commercial development is technically possible; however commercial viability will depend on whether gas hydrate can be competitive with other energy resources. At the global level, natural gas is plentiful and gas hydrate development may be limited to a few specific locations where alternatives are limited. The evaluation programs that will be carried out within the next two years will provide critical information on whether gas hydrate can become a significant energy resource without government subsidies or other incentives.
A critical issue that has restrained industry interest in gas hydrate is that the deposits with the best potential for production are in remote locations without the infrastructure to transport the produced gas to consumers. There are, however, uses for this “stranded gas” in some locations. On the North Slope, gas produced from hydrate may be used for power generation for field operations, reinjection to maintain pressures in oil reservoirs, miscible gas floods, or steam generation for enhanced oil recovery (EOR) and viscous oil projects.
Deep-water hydrate development is moving forward in Japan with substantial government funding, and initial production from the Nankai Trough is scheduled for 2016. The Japanese program plans to reach a maximum production rate of 1 Tcf per year.
India is planning additional hydrate exploratory drilling in the Krishna-Godavari Basin where recent conventional deep-water discoveries will lead to the construction of platforms and pipelines that could be leveraged for hydrate development. However, the discovery of significant conventional oil and gas reserves could also lower the interest in pursuing gas hydrate.
The infrastructure for conventional gas production in the Gulf of Mexico is substantial and growing, and the 2009 drilling program has verified the presence of hydrate-bearing sands in the Gulf. In addition, the Energy Policy Act of 2005 includes an incentive for offshore gas hydrate development with a suspension of royalties on the first 30 billion cubic feet (Bcf) of production per lease. It is uncertain whether this is a large enough incentive to spur industry interest. Gas hydrate development will be especially challenging in the U.S. due to the growth of other natural gas sources, including shale gas and LNG imports. Economic models suggest that a 15% rate of return would be achievable for gas hydrate development in the Gulf at a gas price of $5.50/million cubic feet (Mcf), utilizing subsea completions with tie-backs to existing production facilities. If these models can be validated through field operations, gas hydrate production in the Gulf could progress quickly.
It is likely that gas hydrate development will begin, on a very limited basis, on the North Slope of Alaska within a year or two of a successful hydrate test. Offshore development in the U.S. will likely follow success in Japan and India. The extremely large resource potential of gas hydrate represents a vast opportunity for addressing global energy demand. Wide-spread commercial viability is not yet assured and will require a greater understanding of gas hydrate reservoir characteristics along with improvement in exploration and production tools and technology.