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R. Boswell

Publications and source records attributed to R. Boswell.

18 recordsLinked to original sources
USGS2019

India National Gas Hydrate Program Expedition 02 summary of scientific results: Evaluation of natural gas hydrate-bearing pressure cores

India’s National Gas Hydrate Program (NGHP) Expedition-02 was conducted in 2015 with the goal of investigating numerous locations that had been determined to be prospective for gas hydrate at high saturation in sand-rich reservoirs. Initial logging while drilling data revealed extensive sand-rich gas hydrate occurrences at multiple drill sites in two broad areas. These sites were further investigated through the acquisition and analyses of pressure cores designed to document 1) gas hydrate occurrence within the reservoirs; 2) the petrophysical nature of the reservoir and associated seals, in their native state as well as during and after the dissociation of gas hydrate; 3) the geomechanical nature of the reservoir and seals; and 4) the geochemical nature of reservoir fluids. The cores were initially evaluated at sea, and select subsamples were transferred for more extensive analyses at specialized laboratories both in Japan and in the United States. The samples encompassed a wide range of gas hydrate saturation (from 0 to 100%) within reservoir sediments ranging from sandy silts to gravels, providing opportunities to extend and refine insights into the nature of gas hydrate reservoirs gained in previous programs. Select findings and implications of this coordinated pressure-core evaluation program are reported in numerous papers within the NGHP-02 Special Thematic Volume and are summarized here with respect to the following issues: the evaluation and mitigation of core disturbance, the assessment of gas hydrate occurrence and saturation, the geomechanics and petrophysics of both reservoirs and “seals” in situ, and the potential dynamic geomechanical and petrophysical behavior of reservoir and seals during production.

Journal of Marine and Petroleum Geology↗
USGS2019

National Gas Hydrate Program expedition 02: Identification of gas hydrate prospects in the Krishna-Godavari Basin, offshore India

After completing the first expedition of India's National Gas Hydrate Program (NGHP-01) in 2006, it was concluded that for the next expedition (National Gas Hydrate Program 02; NGHP-02), a new drill site review effort should focus on identifying potential deep-water offshore gas hydrate accumulations in sand dominated depositional environments. Therefore, geological and geophysical data analysis and 3D seismic data interpretation along with associated seismic modeling were carried out in three areas of the Krishna-Godavari Basin: Areas B, C, and E. Conventional petroleum exploration approaches of seismic amplitude evaluation were adapted to prospect for potential sand-rich depositional systems within the gas hydrate stability zone. Subsequently, these prospective areas were further assessed through the geological and geophysical evaluation of depositional setting, gas sources, and gas migration pathways. In Area B, prospecting focused on a large anticlinal structure with a prominent bottom-simulating reflector and several key horizons that indicated evidence for potential sand-hosted hydrate occurrences. In Area C, the prospects were distributed throughout various settings within a very large deep-water channel-levee-fan system with complex indications of potential gas hydrate occurrence in sand-prone seismic facies. In Area E, prospects were associated with high amplitude events within inferred channel-levee sequences. Based on the pre-expedition/onboard drill-site evaluation, the 22 most promising sites in the Krishna-Godavari Basin were identified and prioritized to investigate and delineate a total of 17 identified gas hydrate prospects. This paper describes the geo-scientific studies carried out prior to NGHP-02 for site identification, evaluation and prioritization. An important outcome of this study is the identification of two potentially producible gas hydrate systems inferred to host significant quantity of gas hydrate in stratigraphic-structural traps.

Journal of Marine and Petroleum Geology↗
USGS2015

Indian National Gas Hydrate Program Expedition 01 report

Gas hydrate is a naturally occurring “ice-like” combination of natural gas and water that has the potential to serve as an immense resource of natural gas from the world’s oceans and polar regions. However, gas-hydrate recovery is both a scientific and a technical challenge and much remains to be learned about the geologic, engineering, and economic factors controlling the ultimate energy resource potential of gas hydrate. The amount of natural gas contained in the world’s gas-hydrate accumulations is enormous, but these estimates are speculative and range over three orders of magnitude from about 2,800 to 8,000,000 trillion cubic meters of gas. By comparison, conventional natural gas accumulations (reserves and undiscovered, technically recoverable resources) for the world are estimated at approximately 440 trillion cubic meters. Gas recovery from gas hydrate is hindered because the gas is in a solid form and because gas hydrate commonly occurs in remote Arctic and deep marine environments. Proposed methods of gas recovery from gas hydrate generally deal with disassociating or “melting” in situ gas hydrate by heating the reservoir beyond the temperature of gas-hydrate formation, or decreasing the reservoir pressure below hydrate equilibrium. The pace of energy-related gas hydrate assessment projects has accelerated over the past several years. The Indian National Gas Hydrate Program Expedition 01 was designed to study the gas-hydrate occurrences off the Indian Peninsula and along the Andaman convergent margin with special emphasis on understanding the geologic and geochemical controls on the occurrence of gas hydrate in these two diverse settings. During Indian National Gas Hydrate Program Expedition 01, dedicated gas-hydrate coring, drilling, and downhole logging operations were conducted from 28 April 2006 to 19 August 2006.

Krishna-Godivari Basin↗
USGS2011

Examination of core samples from the Mount Elbert Gas Hydrate Stratigraphic Test Well, Alaska North Slope: Effects of retrieval and preservation

Collecting and preserving undamaged core samples containing gas hydrates from depth is difficult because of the pressure and temperature changes encountered upon retrieval. Hydrate-bearing core samples were collected at the BPXA-DOE-USGS Mount Elbert Gas Hydrate Stratigraphic Test Well in February 2007. Coring was performed while using a custom oil-based drilling mud, and the cores were retrieved by a wireline. The samples were characterized and subsampled at the surface under ambient winter arctic conditions. Samples thought to be hydrate bearing were preserved either by immersion in liquid nitrogen (LN), or by storage under methane pressure at ambient arctic conditions, and later depressurized and immersed in LN. Eleven core samples from hydrate-bearing zones were scanned using x-ray computed tomography to examine core structure and homogeneity. Features observed include radial fractures, spalling-type fractures, and reduced density near the periphery. These features were induced during sample collection, handling, and preservation. Isotopic analysis of the methane from hydrate in an initially LN-preserved core and a pressure-preserved core indicate that secondary hydrate formation occurred throughout the pressurized core, whereas none occurred in the LN-preserved core, however no hydrate was found near the periphery of the LN-preserved core. To replicate some aspects of the preservation methods, natural and laboratory-made saturated porous media samples were frozen in a variety of ways, with radial fractures observed in some LN-frozen sands, and needle-like ice crystals forming in slowly frozen clay-rich sediments. Suggestions for hydrate-bearing core preservation are presented.

Alaska↗
USGS2011

Permafrost-associated natural gas hydrate occurrences on the Alaska North Slope

In the 1960s Russian scientists made what was then a bold assertion that gas hydrates should occur in abundance in nature. Since this early start, the scientific foundation has been built for the realization that gas hydrates are a global phenomenon, occurring in permafrost regions of the arctic and in deep water portions of most continental margins worldwide. In 1995, the U.S. Geological Survey made the first systematic assessment of the in-place natural gas hydrate resources of the United States. That study suggested that the amount of gas in the gas hydrate accumulations of northern Alaska probably exceeds the volume of known conventional gas resources on the North Slope. Researchers have long speculated that gas hydrates could eventually become a producible energy resource, yet technical and economic hurdles have historically made gas hydrate development a distant goal. This view began to change in recent years with the realization that this unconventional resource could be developed with existing conventional oil and gas production technology. One of the most significant developments was the completion of the BPXA-DOE-USGS Mount Elbert Gas Hydrate Stratigraphic Test Well on the Alaska North Slope, which along with the Mallik project in Canada, have for the first time allowed the rational assessment of gas hydrate production technology and concepts. Almost 40 years of gas hydrate research in northern Alaska has confirmed the occurrence of at least two large gas hydrate accumulations on the North Slope. We have also seen in Alaska the first ever assessment of how much gas could be technically recovered from gas hydrates. However, significant technical concerns need to be further resolved in order to assess the ultimate impact of gas hydrate energy resource development in northern Alaska.

Alaska↗
USGS2011

Geologic controls on gas hydrate occurrence in the Mount Elbert prospect, Alaska North Slope

Data acquired at the BPXA-DOE-USGS Mount Elbert Gas Hydrate Stratigraphic Test Well, drilled in the Milne Point area of the Alaska North Slope in February, 2007, indicates two zones of high gas hydrate saturation within the Eocene Sagavanirktok Formation. Gas hydrate is observed in two separate sand reservoirs (the D and C units), in the stratigraphically highest portions of those sands, and is not detected in non-sand lithologies. In the younger D unit, gas hydrate appears to fill much of the available reservoir space at the top of the unit. The degree of vertical fill with the D unit is closely related to the unit reservoir quality. A thick, low-permeability clay-dominated unit serves as an upper seal, whereas a subtle transition to more clay-rich, and interbedded sand, silt, and clay units is associated with the base of gas hydrate occurrence. In the underlying C unit, the reservoir is similarly capped by a clay-dominated section, with gas hydrate filling the relatively lower-quality sands at the top of the unit leaving an underlying thick section of high-reservoir quality sands devoid of gas hydrate. Evaluation of well log, core, and seismic data indicate that the gas hydrate occurs within complex combination stratigraphic/structural traps. Structural trapping is provided by a four-way fold closure augmented by a large western bounding fault. Lithologic variation is also a likely strong control on lateral extent of the reservoirs, particularly in the D unit accumulation, where gas hydrate appears to extend beyond the limits of the structural closure. Porous and permeable zones within the C unit sand are only partially charged due most likely to limited structural trapping in the reservoir lithofacies during the period of primary charging. The occurrence of the gas hydrate within the sands in the upper portions of both the C and D units and along the crest of the fold is consistent with an interpretation that these deposits are converted free gas accumulations formed prior to the imposition of gas hydrate stability conditions.

Alaska↗
USGS2011

Regional long-term production modeling from a single well test, Mount Elbert Gas Hydrate Stratigraphic Test Well, Alaska North Slope

Following the results from the open-hole formation pressure response test in the BPXA-DOE-USGS Mount Elbert Gas Hydrate Stratigraphic Test Well (Mount Elbert well) using Schlumberger's Modular Dynamics Formation Tester (MDT) wireline tool, the International Methane Hydrate Reservoir Simulator Code Comparison project performed long-term reservoir simulations on three different model reservoirs. These descriptions were based on 1) the Mount Elbert gas hydrate accumulation as delineated by an extensive history-matching exercise, 2) an estimation of the hydrate accumulation near the Prudhoe Bay L-pad, and 3) a reservoir that would be down-dip of the Prudhoe Bay L-pad and therefore warmer and deeper. All of these simulations were based, in part, on the results of the MDT results from the Mount Elbert Well. The comparison group's consensus value for the initial permeability of the hydrate-filled reservoir ( k = 0.12 mD) and the permeability model based on the MDT history match were used as the basis for subsequent simulations on the three regional scenarios. The simulation results of the five different simulation codes, CMG STARS, HydrateResSim, MH-21 HYDRES, STOMP-HYD, and TOUGH+HYDRATE exhibit good qualitative agreement and the variability of potential methane production rates from gas hydrate reservoirs is illustrated. As expected, the predicted methane production rate increased with increasing in situ reservoir temperature; however, a significant delay in the onset of rapid hydrate dissociation is observed for a cold, homogeneous reservoir and it is found to be repeatable. The inclusion of reservoir heterogeneity in the description of this cold reservoir is shown to eliminate this delayed production. Overall, simulations utilized detailed information collected across the Mount Elbert reservoir either obtained or determined from geophysical well logs, including thickness (37 ft), porosity (35%), hydrate saturation (65%), intrinsic permeability (1000 mD), pore water salinity (5 ppt), and formation temperature (3.3–3.9 °C). This paper presents the approach and results of extrapolating regional forward production modeling from history-matching efforts on the results from a single well test.

Marine and Petroleum Geology↗
USGS2011

Mount Elbert Gas Hydrate Stratigraphic Test Well, Alaska North Slope: Coring operations, core sedimentology, and lithostratigraphy

In February 2007, BP Exploration (Alaska), the U.S. Department of Energy, and the U.S. Geological Survey completed the BPXA-DOE-USGS Mount Elbert Gas Hydrate Stratigraphic Test Well (Mount Elbert well) in the Milne Point Unit on the Alaska North Slope. The program achieved its primary goals of validating the pre-drill estimates of gas hydrate occurrence and thickness based on 3-D seismic interpretations and wireline log correlations and collecting a comprehensive suite of logging, coring, and pressure testing data. The upper section of the Mount Elbert well was drilled through the base of ice-bearing permafrost to a casing point of 594 m (1950 ft), approximately 15 m (50 ft) above the top of the targeted reservoir interval. The lower portion of the well was continuously cored from 606 m (1987 ft) to 760 m (2494 ft) and drilled to a total depth of 914 m. Ice-bearing permafrost extends to a depth of roughly 536 m and the base of gas hydrate stability is interpreted to extend to a depth of 870 m. Coring through the targeted gas hydrate bearing reservoirs was completed using a wireline-retrievable system. The coring program achieved 85% recovery of 7.6 cm (3 in) diameter core through 154 m (504 ft) of the hole. An onsite team processed the cores, collecting and preserving approximately 250 sub-samples for analyses of pore water geochemistry, microbiology, gas chemistry, petrophysical analysis, and thermal and physical properties. Eleven samples were immediately transferred to either methane-charged pressure vessels or liquid nitrogen for future study of the preserved gas hydrate. Additional offsite sampling, analyses, and detailed description of the cores were also conducted. Based on this work, one lithostratigraphic unit with eight subunits was identified across the cored interval. Subunits II and Va comprise the majority of the reservoir facies and are dominantly very fine to fine, moderately sorted, quartz, feldspar, and lithic fragment-bearing to -rich sands. Lithostratigraphic and palynologic data indicate that this section is most likely early Eocene to late Paleocene in age. The examined units contain evidence for both marine and non-marine lithofacies, and indications that the depositional environment for the reservoir facies may have been shallower marine than originally interpreted based on pre-drill wireline log interpretations. There is also evidence of reduced salinity marine conditions during deposition that may be related to the paleo-climate and depositional conditions during the early Eocene.

Alaska↗
USGS2011

Formation pressure testing at the Mount Elbert Gas Hydrate Stratigraphic Test Well, Alaska North Slope: Operational summary, history matching, and interpretations

In February 2007, the U.S. Department of Energy, BP Exploration (Alaska), and the U.S. Geological Survey, collected open-hole pressure-response data, as well as gas and water sample collection, in a gas hydrate reservoir (the BPXA-DOE-USGS Mount Elbert Gas Hydrate Stratigraphic Test Well) using Schlumberger's Modular Dynamics Formation Tester (MDT) wireline tool. Four such MDT tests, ranging from six to twelve hours duration, and including a series of flow, sampling, and shut-in periods of various durations, were conducted. Locations for the testing were selected based on NMR and other log data to assure sufficient isolation from reservoir boundaries and zones of excess free water. Test stages in which pressure was reduced sufficiently to mobilize free water in the formation (yet not cause gas hydrate dissociation) produced readily interpretable pressure build-up profiles. Build-ups following larger drawdowns consistently showed gas-hydrate dissociation and gas release (as confirmed by optical fluid analyzer data), as well as progressive dampening of reservoir pressure build-up during sequential tests at a given MDT test station. History matches of one multi-stage, 12-h test (the C2 test) were accomplished using five different reservoir simulators: CMG-STARS, HydrateResSim, MH21-HYDRES, STOMP-HYD, and TOUGH + HYDRATE. Simulations utilized detailed information collected across the reservoir either obtained or determined from geophysical well logs, including thickness (11.3 m, 37 ft.), porosity (35%), hydrate saturation (65%), both mobile and immobile water saturations, intrinsic permeability (1000 mD), pore water salinity (5 ppt), and formation temperature (3.3–3.9 °C). This paper will present the approach and preliminary results of the history-matching efforts, including estimates of initial formation permeability and analyses of the various unique features exhibited by the MDT results.

Alaska↗
USGS2011

Mount Elbert Gas Hydrate Stratigraphic Test Well, Alaska North Slope: Overview of scientific and technical program

The Mount Elbert Gas Hydrate Stratigraphic Test Well was drilled within the Alaska North Slope (ANS) Milne Point Unit (MPU) from February 3 to 19, 2007. The well was conducted as part of a Cooperative Research Agreement (CRA) project co-sponsored since 2001 by BP Exploration (Alaska), Inc. (BPXA) and the U.S. Department of Energy (DOE) in collaboration with the U.S. Geological Survey (USGS) to help determine whether ANS gas hydrate can become a technically and commercially viable gas resource. Early in the effort, regional reservoir characterization and reservoir simulation modeling studies indicated that up to 0.34 trillion cubic meters (tcm; 12 trillion cubic feet, tcf) gas may be technically recoverable from 0.92 tcm (33 tcf) gas-in-place within the Eileen gas hydrate accumulation near industry infrastructure within ANS MPU, Prudhoe Bay Unit (PBU), and Kuparuk River Unit (KRU) areas. To further constrain these estimates and to enable the selection of a test site for further data acquisition, the USGS reprocessed and interpreted MPU 3D seismic data provided by BPXA to delineate 14 prospects containing significant highly-saturated gas hydrate-bearing sand reservoirs. The “Mount Elbert” site was selected to drill a stratigraphic test well to acquire a full suite of wireline log, core, and formation pressure test data. Drilling results and data interpretation confirmed pre-drill predictions and thus increased confidence in both the prospect interpretation methods and in the wider ANS gas hydrate resource estimates. The interpreted data from the Mount Elbert well provide insight into and reduce uncertainty of key gas hydrate-bearing reservoir properties, enable further refinement and validation of the numerical simulation of the production potential of both MPU and broader ANS gas hydrate resources, and help determine viability of potential field sites for future extended term production testing. Drilling and data acquisition operations demonstrated that gas hydrate scientific research programs can be safely, effectively, and efficiently conducted within ANS infrastructure. The program success resulted in a technical team recommendation to project management to drill and complete a long-term production test within the area of existing ANS infrastructure. If approved by stakeholders, this long-term test would build on prior arctic research efforts to better constrain the potential gas rates and volumes that could be produced from gas hydrate-bearing sand reservoirs.

Alaska↗
USGS2011

Alaska North Slope regional gas hydrate production modeling forecasts

A series of gas hydrate development scenarios were created to assess the range of outcomes predicted for the possible development of the “Eileen” gas hydrate accumulation, North Slope, Alaska. Production forecasts for the “reference case” were built using the 2002 Mallik production tests, mechanistic simulation, and geologic studies conducted by the US Geological Survey. Three additional scenarios were considered: A “downside-scenario” which fails to identify viable production, an “upside-scenario” describes results that are better than expected. To capture the full range of possible outcomes and balance the downside case, an “extreme upside scenario” assumes each well is exceptionally productive. Starting with a representative type-well simulation forecasts, field development timing is applied and the sum of individual well forecasts creating the field-wide production forecast. This technique is commonly used to schedule large-scale resource plays where drilling schedules are complex and production forecasts must account for many changing parameters. The complementary forecasts of rig count, capital investment, and cash flow can be used in a pre-appraisal assessment of potential commercial viability. Since no significant gas sales are currently possible on the North Slope of Alaska, typical parameters were used to create downside, reference, and upside case forecasts that predict from 0 to 71 BM 3 (2.5 tcf) of gas may be produced in 20 years and nearly 283 BM 3 (10 tcf) ultimate recovery after 100 years. Outlining a range of possible outcomes enables decision makers to visualize the pace and milestones that will be required to evaluate gas hydrate resource development in the Eileen accumulation. Critical values of peak production rate, time to meaningful production volumes, and investments required to rule out a downside case are provided. Upside cases identify potential if both depressurization and thermal stimulation yield positive results. An “extreme upside” case captures the full potential of unconstrained development with widely spaced wells. The results of this study indicate that recoverable gas hydrate resources may exist in the Eileen accumulation and that it represents a good opportunity for continued research.

Alaska↗
USGS2009

Preliminary report on the commercial viability of gas production from natural gas hydrates

Economic studies on simulated gas hydrate reservoirs have been compiled to estimate the price of natural gas that may lead to economically viable production from the most promising gas hydrate accumulations. As a first estimate, $CDN 2005 12/Mscf is the lowest gas price that would allow economically viable production from gas hydrates in the absence of associated free gas, while an underlying gas deposit will reduce the viability price estimate to $CDN 2005 7.50/Mscf. Results from a recent analysis of the simulated production of natural gas from marine hydrate deposits are also considered in this report; on an IROR basis, it is $US 2008 3.50-4.00/Mscf more expensive to produce marine hydrates than conventional marine gas assuming the existence of sufficiently large marine hydrate accumulations. While these prices represent the best available estimates, the economic evaluation of a specific project is highly dependent on the producibility of the target zone, the amount of gas in place, the associated geologic and depositional environment, existing pipeline infrastructure, and local tariffs and taxes. ?? 2009 Elsevier B.V.

Energy Economics↗
USGS2009

Occurrence of gas hydrate in Oligocene Frio sand: Alaminos Canyon Block 818: Northern Gulf of Mexico

A unique set of high-quality downhole shallow subsurface well log data combined with industry standard 3D seismic data from the Alaminos Canyon area has enabled the first detailed description of a concentrated gas hydrate accumulation within sand in the Gulf of Mexico. The gas hydrate occurs within very fine grained, immature volcaniclastic sands of the Oligocene Frio sand. Analysis of well data acquired from the Alaminos Canyon Block 818 #1 ("Tigershark") well shows a total gas hydrate occurrence 13??m thick, with inferred gas hydrate saturation as high as 80% of sediment pore space. Average porosity in the reservoir is estimated from log data at approximately 42%. Permeability in the absence of gas hydrates, as revealed from the analysis of core samples retrieved from the well, ranges from 600 to 1500 millidarcies. The 3-D seismic data reveals a strong reflector consistent with significant increase in acoustic velocities that correlates with the top of the gas-hydrate-bearing sand. This reflector extends across an area of approximately 0.8??km 2 and delineates the minimal probable extent of the gas hydrate accumulation. The base of the inferred gas-hydrate zone also correlates well with a very strong seismic reflector that indicates transition into units of significantly reduced acoustic velocity. Seismic inversion analyses indicate uniformly high gas-hydrate saturations throughout the region where the Frio sand exists within the gas hydrate stability zone. Numerical modeling of the potential production of natural gas from the interpreted accumulation indicates serious challenges for depressurization-based production in settings with strong potential pressure support from extensive underlying aquifers.

Marine and Petroleum Geology↗
USGS2009

Toward production from gas hydrates: Current status, assessment of resources, and simulation-based evaluation of technology and potential

Gas hydrates (GHs) are a vast energy resource with global distribution in the permafrost and in the oceans. Even if conservative estimates are considered and only a small fraction is recoverable, the sheer size of the resource is so large that it demands evaluation as a potential energy source. In this review paper, we discuss the distribution of natural GH accumulations, the status of the primary international research and development (R&D) programs, and the remaining science and technological challenges facing the commercialization of production. After a brief examination of GH accumulations that are well characterized and appear to be models for future development and gas production, we analyze the role of numerical simulation in the assessment of the hydrate-production potential, identify the data needs for reliable predictions, evaluate the status of knowledge with regard to these needs, discuss knowledge gaps and their impact, and reach the conclusion that the numerical-simulation capabilities are quite advanced and that the related gaps either are not significant or are being addressed. We review the current body of literature relevant to potential productivity from different types of GH deposits and determine that there are consistent indications of a large production potential at high rates across long periods from a wide variety of hydrate deposits. Finally, we identify (a) features, conditions, geology and techniques that are desirable in potential production targets; (b) methods to maximize production; and (c) some of the conditions and characteristics that render certain GH deposits undesirable for production. Copyright ?? 2009 Society of Petroleum Engineers.

Conference Paper↗
USGS2008

Scientific results from Gulf of Mexico Gas Hydrates Joint Industry Project Leg 1 drilling: Introduction and overview

The Gulf of Mexico Gas Hydrates Joint Industry Project (JIP) is a consortium of production and service companies and some government agencies formed to address the challenges that gas hydrates pose for deepwater exploration and production. In partnership with the U.S. Department of Energy and with scientific assistance from the U.S. Geological Survey and academic partners, the JIP has focused on studies to assess hazards associated with drilling the fine-grained, hydrate-bearing sediments that dominate much of the shallow subseafloor in the deepwater (>500 m) Gulf of Mexico. In preparation for an initial drilling, logging, and coring program, the JIP sponsored a multi-year research effort that included: (a) the development of borehole stability models for hydrate-bearing sediments; (b) exhaustive laboratory measurements of the physical properties of hydrate-bearing sediments; (c) refinement of new techniques for processing industry-standard 3-D seismic data to constrain gas hydrate saturations; and (d) construction of instrumentation to measure the physical properties of sediment cores that had never been removed from in situ hydrostatic pressure conditions. Following review of potential drilling sites, the JIP launched a 35-day expedition in Spring 2005 to acquire well logs and sediment cores at sites in Atwater Valley lease blocks 13/14 and Keathley Canyon lease block 151 in the northern Gulf of Mexico minibasin province. The Keathley Canyon site has a bottom simulating reflection at ???392 m below the seafloor, while the Atwater Valley location is characterized by seafloor mounds with an underlying upwarped seismic reflection consistent with upward fluid migration and possible shoaling of the base of the gas hydrate stability (BGHS). No gas hydrate was recovered at the drill sites, but logging data, and to some extent cores, suggest the occurrence of gas hydrate in inferred coarser-grained beds and fractures, particularly between 220 and 330 m below the seafloor at the Keathley Canyon site. This paper provides an overview of the results of the initial phases of the JIP work and introduces the 15 papers that make up this special volume on the scientific results related to the 2005 logging and drilling expedition.

Marine and Petroleum Geology↗
USGS2008

Site selection for DOE/JIP gas hydrate drilling in the northern Gulf of Mexico

In the late spring of 2008, the Chevron-led Gulf of Mexico Gas Hydrate Joint Industry Project (JIP) expects to conduct an exploratory drilling and logging campaign to better understand gas hydrate-bearing sands in the deepwater Gulf of Mexico. The JIP Site Selection team selected three areas to test alternative geological models and geophysical interpretations supporting the existence of potential high gas hydrate saturations in reservoir-quality sands. The three sites are near existing drill holes which provide geological and geophysical constraints in Alaminos Canyon (AC) lease block 818, Green Canyon (GC) 955, and Walker Ridge (WR) 313. At the AC818 site, 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. Drilling at GC955 will sample a faulted, buried Pleistocene channel-levee system in an area characterized by seafloor fluid expulsion features, structural closure associated with uplifted salt, and abundant seismic evidence for upward migration of fluids and gas into the sand-rich parts of the sedimentary section. Drilling at WR313 targets ponded sheet sands and associated channel/levee deposits within a minibasin, making this a non-structural play. The potential for gas hydrate occurrence at WR313 is supported by shingled phase reversals consistent with the transition from gas-charged sand to overlying gas-hydrate saturated sand. Drilling locations have been selected at each site to 1) test geological methods and models used to infer the occurrence of gas hydrate in sand reservoirs in different settings in the northern Gulf of Mexico; 2) calibrate geophysical models used to detect gas hydrate sands, map reservoir thicknesses, and estimate the degree of gas hydrate saturation; and 3) delineate potential locations for subsequent JIP drilling and coring operations that will collect samples for comprehensive physical property, geochemical and other analyses

Gulf of Mexico↗
USGS2008

Toward production from gas hydrates: Current status, assessment of resources, and simulation-based evaluation of technology and potential

Gas hydrates are a vast energy resource with global distribution in the permafrost and in the oceans. Even if conservative estimates are considered and only a small fraction is recoverable, the sheer size of the resource is so large that it demands evaluation as a potential energy source. In this review paper, we discuss the distribution of natural gas hydrate accumulations, the status of the primary international R&D programs, and the remaining science and technological challenges facing commercialization of production. After a brief examination of gas hydrate accumulations that are well characterized and appear to be models for future development and gas production, we analyze the role of numerical simulation in the assessment of the hydrate production potential, identify the data needs for reliable predictions, evaluate the status of knowledge with regard to these needs, discuss knowledge gaps and their impact, and reach the conclusion that the numerical simulation capabilities are quite advanced and that the related gaps are either not significant or are being addressed. We review the current body of literature relevant to potential productivity from different types of gas hydrate deposits, and determine that there are consistent indications of a large production potential at high rates over long periods from a wide variety of hydrate deposits. Finally, we identify (a) features, conditions, geology and techniques that are desirable in potential production targets, (b) methods to maximize production, and (c) some of the conditions and characteristics that render certain gas hydrate deposits undesirable for production. Copyright 2008, Society of Petroleum Engineers.

Conference Paper↗