Gas Hydrate Petroleum Systems in Marine and Arctic Permafrost Environments
Published:December 01, 2009
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Timothy S. Collett, 2009. "Gas Hydrate Petroleum Systems in Marine and Arctic Permafrost Environments", Unconventional Energy Resources: Making the Unconventional Conventional, Tim Carr, Tony D’Agostino, William Ambrose, Jack Pashin, Norman C. Rosen
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A growing body of evidence indicates that a large volume of natural gas is stored in gas hydrates and that the production of natural gas from gas hydrates appears to be technically feasible. There are numerous research projects underway to investigate the geological origin of gas hydrate, their natural occurrence, the factors that affect their stability, and the possibility of using this vast resource in the world energy mix. Highly successful cooperative research projects, such as the various phases of the Mallik gas hydrate production project in northern Canada, have for the first time tested the technology needed to produce gas hydrates, and other highly successful gas hydrate research studies have been conducted in Japan, India, China, South Korea, northern Alaska, and the Gulf of Mexico. All of these projects have contributed greatly to an understanding of the energy resource potential of gas hydrates throughout the world.
Gas hydrates are naturally occurring “ice-like” combinations of natural gas and water that have the potential to provide an immense resource of natural gas from the world’s oceans and polar regions. Gas hydrates are known to be widespread in permafrost regions and beneath the sea in sediments of outer continental margins. It is generally accepted that the volume of natural gas contained in the world’s gas hydrate accumulations greatly exceeds that of known gas reserves (reviewed in Collett, 2002). There is also growing evidence that natural gas can be produced from gas hydrates with existing conventional oil and gas production technology (Moridis et al., 2008; Dallimore et al., 2008a, 2008b; Yamamoto and Dallimore, 2008; Anderson et al., 2008).
This review is intended to provide an up-to-date analysis of the geologic controls on the occurrence of gas hydrates in nature, with a focus on understanding their energy resource potential. This review starts with a discussion of what is a gas hydrate and a description of some of their more important physical properties. The concept of the gas hydrate petroleum system is introduced and described. The results of some of the more important international gas hydrate research projects are discussed.
Gas Hydrate Structures and Physical Properties
Natural gas hydrate is a combination of two common substances, water and natural gas. If gas and water meet under suitable conditions of high pressure and low temperature, they join to form an ice-like solid subtance. Vast areas of the earth’s oceans and polar regions are underlain by conditions conducive to gas hydrate formation (Figs. 1 and 2).
Gas hydrates are crystalline compounds that result from the three-dimensional stacking of “cages” of hydrogen-bonded water molecules. Generally, each cage can hold a single gas molecule. The empty cagework is unstable, and requires the presence of encapsulated gas molecules to stabilize the clathrate crystal. The compact nature of the hydrate structure makes for highly effective packing of gas. A volume of gas hydrate expands between 150- and 180-fold when released in gaseous form at standard pressure and temperature (1-kPa, 20°C).
Clathrate hydrates can form in the presence of gas molecules over the size range of 0.48 – 0.90 nanometers (nm). There are three distinct structural types and the structure that is formed depends on the size of the largest guest molecules. There are considerable complexities in the structure-size relation; however, methane and ethane individually form Structure I (sI) hydrate, but in certain combinations also form Structure II (sII) hydrate. Propane and isobutane form sII hydrate, either individually or in combination with ethane and methane. Normal-butane and neopentane form sII hydrate only when methane is present as well, and larger hydrocarbon molecules (C5-C9) form Structure H (sH) hydrate, again where methane is present.
On a macroscopic level, many of the mechanical properties of gas hydrates resemble those of ice because hydrates contain about 85% water on a molar basis. For a complete description of the structure and physical properties of gas hydrates, see the summary by Sloan and Koh (2008).
Gas Hydrate Petroleum System
In recent years, significant progress has been made in addressing key issues on the formation, occurrence, and stability of gas hydrate in nature. The concept of a gas hydrate petroleum system, similar to that guides current conventional oil and gas exploration, is gaining acceptance. In a gas hydrate petroleum system, the individual factors that contribute to the formation of gas hydrate can be identified and quantified: these include (1) gas hydrate pressure-temperature stability conditions, (2) gas source, (3) gas migration, and (4) the growth of the gas hydrate in suitable host sediment or “reservoir.” In the following discussion, these geologic controls on the stability and formation of gas hydrate in nature will be reviewed and evaluated. This review ends with a description of a series of hypothetical gas hydrate petroleum systems in which the geologic controls on the occurrence of gas hydrate are further discussed.
Gas hydrate stability conditions
Gas hydrates exist under a limited range of temperature and pressure conditions such that the depth and thickness of the zone of potential gas hydrate stability can be calculated. Depicted in the temperature/depth plot in Figure 3 are a series of subsurface temperature profiles from an onshore permafrost area and two laboratory-derived gas hydrate stability curves for different natural gases (modified from Holder et al., 1987). This gas hydrate phase diagram (Fig. 3) illustrates how variations in formation temperature, pore pressure, and gas composition can affect the thickness of the gas hydrate stability zone. In this example phase diagram, the mean annual surface temperature is assumed to be -10°C; however, the depth to the base of permafrost (0°C isotherm) is varied for each temperature profile (assumed permafrost depths of 305 m, 610 m, and 914 m). Below permafrost, three different geothermal gradients (4.0°C/100 m, 3.2°C/100 m, and 2.0°C/100 m) are used to project the sub-permafrost temperature profiles. The two gas-hydrate stability curves represent gas hydrates having different gas chemistries. One of the stability curves is for a 100% methane hydrate; the other is for a hydrate that contains 98% methane, 1.5% ethane, and 0.5% propane. This example phase diagram is constructed assuming a hydrostatic pore-pressure gradient of 9.795 kPa/m [0.433 psi/ft].
The zone of potential gas hydrate stability in the phase diagram (Fig. 3) lies at the depths between the two intersections of the geothermal gradient and the gas-hydrate stability curve. For example in Figure 3, the temperature profile projected to an assumed permafrost base of 610 m intersects the 100% methane-hydrate stability curve at about 200 m, thus marking the upper boundary of the methane-hydrate stability zone. A geothermal gradient of 4.0°C/100 m projected from the base of permafrost at 610 m intersects the 100% methane-hydrate stability curve at about 1,100 m; thus, the zone of potential methane-hydrate stability is approximately 900 m thick. However, if permafrost extended to a depth of 914 m and if the geothermal gradient below permafrost is 2.0°C/100 m, the zone of potential methane-hydrate stability would be approximately 2,100 m thick.
Most gas hydrate stability studies assume that the pore-pressure gradient is hydrostatic (reviewed by Collett, 2002). Pore-pressure gradients greater than hydrostatic correspond to higher pore-pressures associated with depth and a thicker gas-hydrate stability zone, whereas a pore-pressure gradient less than hydrostatic corresponds to a thinner gas hydrate stability zone. The gas-hydrate stability curves in Figure 3 have been obtained from laboratory data published by Holder et al. (1987). The addition of 1.5% ethane and 0.5% propane to the pure methane gas system shifts the stability curve to the right, thus deepening the zone of potential gas-hydrate stability. It is well known that dissolved salt can depress the freezing-point of water. Salt, such as NaCl, when added to a gas-hydrate system also lowers the temperature at which gas hydrates form.
It has been shown that the availability of large quantities of hydrocarbon gas from both microbial and thermogenic sources are an important factor controlling the formation and distribution of natural gas hydrates (Collett, 1993; Kvenvolden, 1993; Collett, 2002; Collett et al., 2008b). Carbon isotope analyses indicate that the methane in many oceanic hydrates is derived from microbial sources. However, molecular and isotopic chemical analyses of gas evolved from recovered hydrate samples indicate a thermal origin for the gas in several hydrate occurrences such as those from the Gulf of Mexico, northern Alaska, Mackenzie Delta, Caspian Sea, and Black Sea (reviewed by Collett, 2002).
Microbial gas is produced by the decomposition of organic matter by microorganisms. Thus, abundant organic matter is needed for the formation of microbial methane. Due to the relatively low organic carbon content of most sediment, production of microbial methane internally within the gas hydrate stability zone alone is a limiting factor for the development of significant gas hydrate accumulations. Paull et al. (1994) have shown that gas recycling and upward migration of methane from deeper sources in a marine sedimentary sequence is essential for the formation of significant gas-hydrate accumulations.
Thermogenic methane is generated during the thermochemical alteration of organic matter. As discussed above, most of the gas within the sampled gas hydrate occurrences in the world has been shown to be derived from microbial sources. Thus, most of the published gas hydrate assessments have focused on assessing only microbial gas sources. However, recent studies in northern Alaska (Collett et al., 2008a) and Canada (Dallimore and Collett, 2005) have again documented the importance of thermogenic gas sources to the formation of highly concentrated gas hydrate accumulations. For the most part, the role of thermogenic-derived gas in most gas hydrate field studies has likely been underappreciated.
As shown, a highly concentrated gas-hydrate accumulation contains a substantial volume of gas, which is potentially derived from microbial and/or thermogenic sources. Also, as discussed above, in most cases 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 accumulations are in sediments that have not been deeply buried or subjected to temperatures high enough to form thermogenic gas. Thus, the gas within most hydrate accumulations has to have been concentrated in the hydrate stability zone by a potential combination of processes ― one of which, gas migration, would appear to be a critical component within most gas hydrate petroleum systems.
Methane, along with other hydrate forming gases, migrates within a sedimentary section by one of three processes: (1) diffusion, (2) gas dissolved within migrating water, or (3) as a bubble ― a separate gas phase. Migration of gas by diffusion is a slow process and, for the most part, would not likely result in the movement of enough gas to form a concentrated gas hydrate accumulation (Xu and Ruppel, 1999). However, the migration of gas by advection as either a dissolved component in water or as a separate gas phase can be a highly efficient process.
Two basic models have been proposed to describe the interrelation between advective gas migration and the formation of gas hydrate. In a model originally proposed by Hyndman and Davis (1992), water (having a dissolved aqueous phase of methane and other potential hydrate formers) moving upward into the hydrate zone encounters decreasing methane solubility, which results in exsolving of methane and the formation of gas hydrate. Numerous field and laboratory studies show that methane hydrate forms only where the concentration of methane in the pore waters exceeds solubility. In most marine settings (outside of areas of active methane venting), no gas hydrate is present in sediments near the seafloor because the concentration of dissolved methane is low. The other basic model for the formation of gas hydrate in sediments involves the upward migration of methane as a bubble phase (separate gas phase) into the hydrate stability zone, and hydrate nucleation takes place at the bubble and pore-water interface. Both models require permeable pathways to allow for the migration of water and/or a gas phase (i.e., bubble), but the gas-phase migration model requires relatively enhanced fluid flow pathways in comparison to the aqueous migration model. It is generally concluded that both pore-water flow and bubble gas-phase migration in sediments are focused along permeable pathways such as fault systems or porous-permeable sediment layers. Therefore, if effective migration pathways are not available, it is unlikely that a significant volume of gas hydrate would accumulate.
The study of gas-hydrate samples indicates that the physical nature of in-situ gas hydrates is highly variable (reviewed by Sloan and Koh, 2008). Gas hydrates are observed (1) occupying pores of coarse-grained rocks; (2) nodules disseminated within fine-grained rocks; (3) a solid substance, filling fractures; or (4) a massive unit composed mainly of solid gas hydrate with minor amounts of sediment. Most gas hydrate field expeditions, however, have shown that the occurrence of concentrated gas hydrate is mostly controlled by the presence of fractures and/or coarser grained sediments in which gas hydrate fills fractures or is disseminated in the pores of sand-rich reservoirs (Collett, 1993; Dallimore and Collett, 2005; Riedel et al., 2006; Collett et al., 2008a, 2008b; Park et al., 2008; Yang et al., 2008). Torres et al. (2008) conclude that hydrate grows preferentially in coarse-grained sediments because lower capillary pressures in these sediments permit the migration of gas and nucleation of hydrate. The growth of gas hydrate in clay-rich sediments, however, is more poorly understood and appears to be limited to mostly massive occurrences.
In review articles by Boswell and Collett (2006) and Boswell et al. (2007), four different gas hydrate play types were identified and compared within a “gas hydrate resource pyramid” (Fig. 4). Resource pyramids are commonly used to display the relative size and producibility of different types of energy resources. Within a resource pyramid the most promising and accessible resources are depicted at the top and the most technically challenging are shown at the base. The pyramid shape results from the natural tendency for the most abundant elements of a resource group to also be the most difficult to extract. At present, four different gas hydrate play types or occurrences are known (as depicted in Fig. 4): (1) sand-dominated reservoirs, (2) clay-dominated fractured reservoirs, (3) massive gas hydrate formations exposed on the seafloor, and (4) low-concentration disseminated deposits encased in largely impermeable clays. The first two of these play types, have been described as “worthy of further exploration” as both provide the “reservoir” permeability necessary for the formation of highly concentrated hydrate accumulations (Boswell et al., 2007).
The apex of the gas hydrate resource pyramid (those resources that are closest to potential commercialization) is represented by high gas-hydrate saturated accumulations in sand-dominated reservoirs in arctic regions. Collett (1995) assigned an in-place resource of 16.7 trillion cubic meters (590 trillion cubic feet) for Arctic sand-dominated reservoirs on the North Slope of Alaska. No similar assessments exist for other Arctic permafrost settings.
The next most prospective gas hydrate resources are those of moderate-to-high concentrations within sandstone reservoirs in marine environments. Due to the relatively distal nature of the deep marine geologic settings, the overall abundance of sand within the shallow geologic section is generally low. Also, the extraction of these resources is subject to the high costs of deep water exploration and development. The most favorable marine hydrate accumulations, however, will likely be in the vicinity of existing production infrastructure such as in the Gulf of Mexico. Recently, the MMS (Frye, 2008) has estimated that the Gulf of Mexico contains about 190 trillion cubic meters (~6,710 trillion cubic feet) of gas in highly concentrated hydrate accumulations within sand reservoirs.
Production testing and modeling has shown that concentrated gas hydrate occurrences in sand reservoirs are conducive to existing well-based production technologies. For both arctic and marine hydrate-bearing sand reservoirs, there are no apparent technical roadblocks to resource extraction; the remaining resource issues deal mostly with the economics of hydrate extraction.
On the gas hydrate resource pyramid (Fig. 4), resources associated with sand-dominated reservoirs are at the top; however, there are massive deposits of gas hydrate generally encased in fine-grained muds and shales, the most promising of which occupy fracture systems. However, unlike sand systems where grain-supported reservoirs result in high matrix permeability and for which there are promising production concepts, exploitation of methane in shale-encased fractured accumulations will require improved extraction technologies.
The majority of marine gas hydrate accumulations that have been studied to date are in fine-grained, clay-dominated sediments associated with surficial seep-related massive gas hydrate deposits (reviewed by Milkov and Sassen, 2002). This type of hydrate deposit commonly is associated with mounds that lie exposed on the sea floor. In many cases, these mounds appear to be dynamic and connected to deep fracture-filled gas hydrate systems that also act as conduits for gas migration from below the hydrate stability zone. Commercial recovery of gas from mound features is unlikely due to economic and technology hurdles and also constrained by the probable destruction of sensitive sea-floor ecosystems.
At the base of the gas hydrate resource pyramid (Fig. 4) are finely disseminated accumulations, typified by the Blake Ridge on the Atlantic margin of the United States, in which there are large volumes of gas hydrate at low saturations (~10% or less) over extensive regions. Most of the in-place global gas hydrate “resources” may reside within this resource class. The prospects for economic recovery of natural gas from this highly disseminated resource however are extremely limited using current technologies, and major improvements in extraction methods are required to enable commercial exploitation of such deposits.
Because conventional production technologies favor sand-dominated gas hydrate reservoirs, sand reservoirs are considered to be the most viable economic target for gas hydrate production and will be the prime focus of most future gas hydrate exploration and development projects.
Examples of gas hydrate petroleum systems
This section of the report deals with the description of a series of hypothetical gas hydrate petroleum systems. In a gas hydrate petroleum system, most of the gas within the hydrate stability zone has migrated from below by advective processes. In the first gas hydrate formation model presented in the gas migration section of this report, water with dissolved methane, transported from below into the hydrate stability zone, becomes relatively enriched in methane, with the methane exsolving from the upward migrating water and forming hydrate within available sediment pores or, in the case of clay-rich sediments, possibly forming their own void space. Depicted in Figure 5A-C are three hypothetical gas hydrate accumulations that form by the upward advection of methane-saturated waters in a uniform (fine-grained) marine sedimentary section having no natural fractures. In Example 1 (Fig. 5A), the system is characterized by low water/methane flux rates, resulting in the formation of a limited, low-saturation hydrate accumulation above the base of the methane hydrate stability zone. The hydrate system depicted in Example 2 (Fig. 5B) is characterized by relatively higher water/gas flux rates (in comparison to Example 1) that have lead to the formation of a thick hydrate deposit immediately overlying the base of the hydrate stability field and is underlain by free-gas. With continued water/gas migration and sedimentation, as depicted in Example 3 (Fig. 5C), the base of the hydrate stability zone moves upward, keeping the same relative depth to the sea floor. The hydrates emerging from the bottom of the upward migrating stability zone dissociate and the evolved gas again migrates up into the overlying hydrate stability zone and reforms gas hydrate. It has been proposed in studies of the Blake Ridge gas hydrate occurrence that the recycling of gas along the upward advancing hydrate stability boundary would yield a relatively more concentrated gas hydrate accumulation in the sedimentary section just above the base of the stability zone (Paull et al., 1994). It is important to note that the addition of an enhanced permeable pathway, such as a fault, would likely significantly alter the appearance of the resulting gas hydrate accumulations depicted in Figure 5A-C. The hypothetical methane solubility curves and methane concentration gradients depicted in Figure 5A-C have been extrapolated from the work of Bhatnagar et al. (2008) and Malinverno et al. (2008).
In the second gas hydrate formation model presented in the gas migration section of this report, methane also migrates from below but as a separate bubble phase. Depicted in Figure 6A-C is an additional set of hypothetical gas hydrate petroleum systems in which the sedimentary section is assumed to be dominated by clay-rich sediments having low permeabilities to water or free gas migration. All three of these examples depicted in Figure 6A-C, require secondary permeable pathways to allow for the migration of a free-gas phase (i.e., bubble), such as a fault system (Fig. 6A) or porous-permeable sediment layer (Fig. 6B). The migration pathways are mostly fracture systems or sand layers that also serve as the porous-permeable reservoirs in which highly concentrated gas hydrate accumulations can grow. Figure 6C depicts a “combination” gas hydrate occurrence in a combined sand and fracture reservoir, in which case the fracture system has also acted as a gas migration conduit. Although only free-gas phase (i.e., bubble) migration is assumed for the examples depicted in Figure 6A-C, it is possible that methane-rich water could be transported along the same enhanced migration conduits into the overlying hydrate stability zone, where it could contribute to the formation of highly concentrated gas hydrate accumulations as the methane comes out of solution.
Some of the best documented gas hydrate occurrences in fractured clay systems have been discovered in (1) the Keathley Canyon area of the Gulf of Mexico, (2) numerous sites in the Krishna-Godavari basin in the offshore of India, (3) the Ulleung basin off the east coast of South Korea, and (4) several sites along the Cascadia continental margin of North America. Examples of gas hydrate formed within marine sand units that provide permeable pathways across the base of the gas hydrate stability zone are in the Nankai Trough area of Japan and the Alaminos Canyon, Walker Ridge, and Green Canyon regions of the Gulf of Mexico. Examples of gas hydrate accumulations within fracture systems and sand layers will be further described in the next section of this report.
Occurrence of Gas Hydrates
The research findings of some of the more notable gas hydrate research projects are summarized below, with a focus on the “national” led gas hydrate programs. These national efforts are typically led by a central government agency, which is responsible for funding and managing these efforts. As shown in Figure 2, gas hydrates have been recovered at about 40 locations throughout the world. However, only a limited number of accumulations have been examined and delineated with data collected by deep scientific drilling operations. Included in the following discussion are descriptions of several of the best known drilled marine and onshore permafrost-associated gas hydrate accumulations in the world.
Gulf of Mexico, United States
The occurrence of gas hydrates in the Gulf of Mexico was confirmed during DSDP Leg 96 when numerous gas hydrate samples were recovered from sub-bottom depths ranging from 20 to 40 meters below the sea floor (mbsf) in the Orca Basin (Sites 618 and 618A), which is located about 300 km south of Louisiana beneath about 2,000 m of water. Near-surface (0-5 m) marine sediment coring has also recovered numerous gas hydrate samples on the Louisiana continental slope.
In 2005, the Chevron-led Gulf of Mexico Gas Hydrate Joint Industry Project (JIP), conducted scientific drilling, coring, and downhole logging to assess hydrate-related hazards in fine-grained sediments with low concentrations of gas hydrate (Ruppel et al., 2008). This expedition (Gulf of Mexico Gas Hydrate Joint Industry Project Leg I) targeted two deep-water locations in the Atwater Valley and Keathley Canyon areas of the Gulf of Mexico. Although gas hydrate was not physically recovered from the Keathley Canyon core hole, other indicators of gas hydrate, such as elevated downhole measured electrical resistivity, suggests the probable occurrence of gas hydrate in the KC151-2 well. Analysis of downhole measured resistivity and resistivity-at-the-bit (RAB) images from the KC151-2 hole revealed the occurrence of fracture filling gas hydrate at relatively high concentrations. The analysis of downhole well log data from the two JIP Atwater Valley wells shows little evidence of significant gas hydrate occurrences, other than several thin, possibly stratigraphically controlled gas-hydrate-bearing intervals.
The next phase of the Gulf of Mexico JIP is being extended to coarser grained sediments having much higher expected gas hydrate concentrations. On May 6, 2009, the Gulf of Mexico JIP, including DOE, USGS, and MMS research scientists, have completed the first-ever drilling project having the expressed goal to collect geologic data on gas-hydrate-bearing sand reservoirs in the Gulf of Mexico. The 2009 drilling project, named the Gulf of Mexico Gas Hydrate Joint Industry Project Leg II, features the collection of a comprehensive set of logging-while-drilling (LWD) data through expected gas-hydrate-bearing sand reservoirs in seven wells at three locations in the Gulf of Mexico.
The semi-submersible drilling vessel Helix Q4000 was mobilized at sea in the Gulf Mexico and drilling was conducted in the Walker Ridge, Green Canyon and the Alaminos Canyon blocks (http://www.netl.doe.gov/technologies/oil-gas/FutureSupply/MethaneHydrates/2009GOMJIP/index.html; viewed August 25, 2009). The LWD sensors just above the drill bit provided important new information on the nature of the sediments and the occurrence of gas hydrate. The full research-level LWD data set on formation lithology, electrical resistivity, acoustic velocity, and sediment porosity enabled the greatly improved evaluation of gas hydrate in both sand and fracture dominated reservoirs. The two holes drilled at Walker Ridge yielded evidence of a laterally continuous thick fracture-filling gas hydrate section, but more importantly both wells also encountered sand reservoirs, between 10- to 15-m-thick, nearly saturated with gas hydrate. Gas-hydrate-bearing sands were also drilled in two of the Green Canyon wells, with one occurrence slightly >30 m thick.
Initial interpretation of the Alaminos Canyon drilling results is that the sands appear to exhibit uniformly low gas hydrate saturation over a large area. Nevertheless, the discovery of thick hydrate-bearing sands at Walker Ridge and Green Canyon validates the integrated geological and geophysical approach used in the pre-drill site selection process in order to predict hydrate accumulations before drilling, and provides increased confidence in assessment of gas hydrate volumes in the Gulf of Mexico and other marine sedimentary basins. The presence of significant gas hydrate accumulations as both pore-filling sands and fracture-filling material in shallow muds make both Walker Ridge and Green Canyon likely locations for future energy resource studies. While the primary goal of this JIP is to better understand the safety issues related to gas hydrates, the results of the program will also allow a better assessment of the commercial potential of marine gas hydrates.
Also in the Gulf of Mexico, at the Alaminos Canyon 818 site (AC818), gas hydrate is interpreted to occur within the Oligocene Frio volcaniclastic sand at the crest of a fold that is shallow enough to be in the hydrate stability zone (Smith et al., 2006). Examination of the well log data obtained from the Frio section of the Chevron Tiger Shark well drilled in AC818 indicates approximately 18 m of sand (3,209 to 3,227 m drilling depth), porosity of about 30%, and downhole measured resistivity in the range 30 to 40 ohm-m. Initial volumetrics derived from downhole log data show very high gas hydrate saturations (up to 80% of available pore volume).
North Slope, Alaska, United States
Before the recently completed coring and down-hole-logging operations in the BP Exploration (Alaska) Mount Elbert well in Milne Point, the only direct confirmation of gas hydrate on the North Slope has been from the Northwest Eileen State-2 well, drilled in 1972, located in the northwest part of the Prudhoe Bay Field.
Gas hydrates also are inferred to occur in an additional 50 exploratory and production wells in northern Alaska based on downhole log responses calibrated to the known gas hydrate occurrences in the Northwest Eileen State-2 well. Most of the well-log inferred gas hydrates occur in six laterally continuous sandstone units; all are geographically restricted to the area overlying the eastern part of the Kuparuk River Field and the western part of the Prudhoe Bay Field. The volume of gas within the gas hydrates of the Prudhoe Bay-Kuparuk River area, which has come to be known as the Eileen Gas Hydrate Accumulation, is estimated to be about 1.0 to 1.2 trillion cubic meters.
Among current Arctic studies, BP Exploration (Alaska), Inc. (BPXA) and the DOE have undertaken a project to characterize the commercial viability of gas hydrate resources in the Prudhoe Bay, Kuparuk River, and Milne Point Field areas on the Alaska North Slope. As part of this effort, the Mount Elbert Gas Hydrate Stratigraphic Test Well was completed in February 2007 and yielded one of the most comprehensive data sets yet compiled on naturally-occurring gas hydrates (Boswell et al., 2008). In 2005, extensive analysis of BPXA’s proprietary 3-D seismic data and integration of that data with existing well log data (enabled by collaborations with the USGS and the BLM), resulted in the identification of more than a dozen discrete and mapable gas hydrate prospects within the Milne Point area. Because the most favorable of those targets was a previously undrilled, fault-bounded accumulation, BPXA and the DOE decided to drill a vertical stratigraphic test well at that location (named the “Mount Elbert” prospect) to acquire critical reservoir data needed to develop a longer-term production testing program. Gas hydrates were expected and found in two stratigraphic sections. An upper zone, (Unit D) contained ~14 m of gas hydrate-bearing reservoir-quality sandstone. A lower zone (Unit C) contained ~16 m of gas hydrate-bearing reservoir. Both zones displayed gas hydrate saturations that varied with reservoir quality as expected, with typical values between 60% and 75%. The Mount Elbert gas hydrate stratigraphic test well project included the acquisition of pressure transient data from four short-duration pressure-drawdown tests using Schlumberger’s wireline MDT (Boswell et al., 2008). These tests were conducted open-hole and were designed to build upon the knowledge gained from cased-hole MDT tests conducted during the Mallik 2002 testing program. The MDT and NMR log data from the Mount Elbert well also confirmed the presence of a mobile pore-water phase even in the most highly gas-hydrate saturated intervals. Gas hydrate dissociation and production was confirmed in the later stages of each test in which the pressure was drawn down below gas hydrate equilibrium conditions. Additional work anticipated within this effort includes a long-term production testing program designed to determine reservoir deliverability under a variety of production/ completion scenarios.
Mackenzie River Delta—Mallik, Canada
The JAPEX/JNOC/GSC Mallik 2L-38 gas hydrate research well, drilled in 1998 near the site of the Mallik L-38 well, included extensive scientific studies designed to investigate the occurrence of in-situ natural gas hydrate in the Mallik Field area (Dallimore and Collett, 2005). Approximately 37 m of core was recovered from the gas hydrate interval (878-944 m) in the Mallik 2L-38 well. Pore-space gas hydrate and several forms of visible gas hydrate were observed in a variety unconsolidated sands and gravels interbedded with non-hydrate bearing silts. Because of the success of the 1998 Mallik 2L-38 gas hydrate research well program, the Mallik site was elevated as an important gas hydrate production test site by the execution of two additional gas hydrate production research programs: (1) The Mallik 2002 Gas Hydrate Production Research Well Program; and (2) 2006-2008 JOGMEC/NRCan Mallik Gas Hydrate Production Research Program.
In June of 2005, the partners in the Mallik 2002 Gas Hydrate Production Research Well Program publicly released the results of the first modern, fully integrated field study and production test of a natural gas hydrate accumulation (Dallimore and Collett, 2005). During the Mallik 2002 testing program, the response of gas hydrates to heating and depressurization was evaluated. The results of three short duration gas hydrate tests demonstrate that gas can be produced from gas hydrates exclusively through pressure stimulation. Thermal stimulation experiments were designed to destabilize gas hydrates by using circulated hot water to increase the in-situ temperature. Gas was continuously produced throughout the test at varying rates with maximum flow rate reaching 360 cubic meters per day (Dallimore and Collett, 2005). The total volume of gas flowed was small reflecting that the test was a controlled production experiment rather than a long duration well test. It also demonstrated the difficulty of heating a relatively large rock mass by conductive heat flow alone.
As described by Dallimore et al., (2008b) and Yamamoto and Dallimore (2008), the 2006-2008 JOG-MEC/NRCan Mallik Gas Hydrate Production Research Program was designed to build on the results of the Mallik 2002 project by having the main goal of monitoring long term production behavior of gas hydrates. The primary objective of the winter 2006-2007 field activities was to install equipment and instruments to allow for long term production gas hydrate testing during the winter of 2007-2008. After completing drilling operations, a short pressure drawdown test was conducted to evaluate equipment performance and assess the short term “producibility” of the gas-hydrate-bearing section. During the most successful 12.5 hours of the test, at least 830 m3 of gas were produced. The test results verified the effectiveness of the depressurization method even for such a short duration. The following winter (2007/2008), the team returned to the site to undertake a longer term production test and implemented countermeasures to overcome the problems encountered in the previous year’s program. The 2007/ 2008 field operations consisted of a six day pressure drawdown test, during which “stable” gas flow was measured at the surface. The 2007/2008 testing program at Mallik established a continuous gas flow ranging from 2,000 to 4,000 m3/day.
Nankai Trough, Japan
The presence of extensive BSRs in the Nankai Trough was confirmed with seismic surveys carried out as a part of METI’s domestic geophysical survey program. The 1999/2000 Nankai Trough drilling and coring program targeted an area of a prominent BSR located about 50 km from the mouth of the Tenryu River in central Japan at a water depth of 945 m (Takahashi and Tsuji, 2005). This drilling project, consisting of a pilot well and three post survey wells, confirmed the existence of gas hydrate in the intergranular pores of turbiditic sands based on the analysis of downhole-logging data, and observations from both conventional and pressure cores. Gas hydrate was determined to fill the pore spaces in these deposits, reaching saturations up to 80% in some layers. Individual hydrate-bearing sand layers were <1 m thick, and the cumulative thickness of the hydrate-bearing sands totalled about 12 to 14 m.
A multi-well drilling program titled “METI Toaki-oki to Kumano-nada” was successfully carried out in early 2004 (Takahashi and Tsuji, 2005). A total of sixteen sites were drilled at water depths ranging from 720 to 2,030 m. Based on the analysis of the both the available downhole log data and core observations, three different types of gas hydrate occurrences were identified: (1) sand with pore-filling hydrate; (2) silt with pore-filling hydrate; and (3) nodular or fracture-filling massive hydrate in fine-grain sediments. Analysis of pressure cores and downhole log data indicate that average gas hydrate saturations in the cored sand layers ranged from 55 to 68%, with the average sediment porosities ranging from 39 to 41%.
NGHP Expedition 01, India
NGHP Expedition 01 was designed to study the occurrence of gas hydrate off the Indian Peninsula and along the Andaman convergent margin and had special emphasis on understanding the geologic and geochemical controls on the occurrence of gas hydrate in these two diverse settings. During its 113.5-day voyage (April 28 – August 19, 2006), the research drill ship JOIDES Resolution (JR) cored or drilled 39 holes at 21 sites (one site in Kerala-Konkan, 15 sites in Krishna-Godavari, four sites in Mahanadi and one site in Andaman deep offshore areas), penetrated more than 9,250 m of sedimentary section, and recovered nearly 2,850 m of core. Twelve holes were logged using logging-while-drilling tools, and an additional 13 holes were wireline logged. NGHP Expedition 01 was among the most complex and comprehensive methane hydrates field ventures yet conducted. All of the primary data collected during NGHP Expedition 01 are included in the NGHP Expedition 01 Initial Reports (Collett et al., 2008b).
NGHP Expedition 01 established the presence of gas hydrates in Krishna-Godavari, Mahanadi, and Andaman basins. The expedition discovered one of the richest gas hydrate accumulations yet documented (Site 10 in the Krishna-Godavari Basin), documented the thickest and deepest gas hydrate stability zone yet known (Site 17 in Andaman Sea), and established the existence of a fully-developed gas hydrate system in the Mahanadi Basin (Site 19). For the most part, the interpretation of downhole-logging data and linked imaging of recovered cores, analyses of interstitial water from cores, and pressure core imaging from the sites drilled during NGHP Expedition 01 indicated that the occurrence of gas hydrate was controlled mostly by the presence of fractures and/or coarser grained (mostly sand-rich) sediments (Collett et al., 2008b).
Drilling Expedition GMGS-1, China
In June of 2007, a deep water gas hydrate drilling and coring program was successfully completed by the Guangzhou Marine Geological Survey (GMGS), China Geological Survey (CGS), and the Ministry of Land and Resources of P. R. China (Wu et al., 2008). Drilling expedition GMGS-1 was carried out from April to June 2007 in the Shenhu Area on the north slope of South China Sea. During Expedition GMGS-1, eight sites were drilled in water depths of up to 1,500 m. Each site was wireline logged to depths of up to 300 mbsf using a set of high-resolution slim wireline tools. Five of the eight sites occupied during the expedition were cored. Gas hydrate was detected at three of the five core sites. The sediments were predominantly clay containing a variable amount of silt-sized particles including fora-minifera. The sediment layers rich in gas hydrate were about 10 to 25 m thick and were found just above the base of the predicted gas hydrate stability zone (BGHSZ) at all three sites. Analysis of pressure cores confirmed that the gas hydrate occurred within fine-grained foraminifera-rich clay sediments, which had gas-hydrate saturations ranging from 20 to 40%.
Drilling Expedition UBGH1, South Korea
In November of 2007 South Korea completed its first large-scale gas hydrate exploration and drilling expedition in the East Sea: Ulleung Basin Gas Hydrate Expedition 1 (UBGH1). Leg 1 of UBGH1 included the drilling of five logging-while-drilling holes in the Ulleung Basin, which was used to select a sub-set of three sites that were more likely to contain gas hydrate for Leg 2 drilling and coring operations. Coring during Leg 2, at water depths between 1,800 to 2,100 m, confirmed the presence of gas-hydrate-bearing reservoirs up to 150 mbsf (Park et al., 2008). Gas hydrate was recovered at all three core sites, occurring as veins and layers in clay-rich sediments and as pore-filling material within the silty/sandy layers. At one site, a 130-m-thick hydrate-bearing sedimentary section of interbedded sands and clays was penetrated. Analysis of pore-water freshening revealed average gas hydrate saturations of about 30% for the hydrate-bearing sand layers.
Gas hydrates represent both scientific and technological challenges, and much remains to be learned about the geologic, engineering, and economic factors controlling their ultimate energy resource potential. The review of international interest in gas hydrates provides a clear understanding of the motivations and incentives behind some of the more successful gas hydrate research and development programs. However, the motivations for these efforts and research direction vary significantly. The evaluation of gas hydrate as an energy source is clearly a long-term endeavour that requires significant financial investment.