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USGS2019

Preface: Marine gas hydrate reservoir systems along the eastern continental margin of India: Results of the National Gas Hydrate Program Expedition 02

The 2015 India National Gas Hydrate Program (NGHP) Expedition 02 was conducted to obtain new information on the occurrence of gas hydrate systems and to advance the understanding of geologic controls on the formation of gas hydrate accumulations in the offshore of India. The ultimate goal of the NGHP effort is to assess the energy resource potential of marine gas hydrates in India. The Guest Editors for this special thematic issue of the Journal of Marine and Petroleum Geology (JMPG) have worked with more than 100 scientists and engineers to prepare the 45 individual reports included in this special issue to address the operational and technical contributions of the NGHP-02 Expedition. This thematic issue on natural gas hydrates in the offshore of India is built on the foundation of five previous JMPG thematic issues that focused on the scientific results of other marine gas hydrate expeditions. These foundational contributions include: (1) the “Scientific Results of the 2005 USDOE-Chevron JIP Drilling for Methane Hydrates Objectives in the Gulf of Mexico” (Volume 25, Issue 9, November 2008), (2) the “Resource and Hazard Implications of Gas Hydrates in the Northern Gulf of Mexico: Results of the 2009 Joint Industry Project Leg II Drilling Expedition” (Volume 34, Issue 1, June 2012), (3) the “Scientific Results of the Second Gas Hydrate Drilling Expedition in the Ulleung Basin (UBGH2), East Sea of Korea” (Volume 47, November 2013), (4) “Geologic Implications of Gas Hydrates in the Offshore of India: Results of the National Gas Hydrate Program Expedition 01” (Volume 58, Part A, December 2014), and (5) “Gas Hydrate Drilling in Eastern Nankai” (Volume 66, Part 2, September 2015). The NGHP-02 Expedition was conducted from 03-March- 2015 to 28-July- 2015 off the eastern coast of India. The first two months of the expedition were dedicated to establishing 25 new research sites that featured the drilling of a dedicated downhole logging hole at each site. The next three months of the NGHP-02 Expedition were dedicated to sediment coring and other downhole measurement operations at 10 of the sites established during the expedition’s first phase. The results of downhole logging, coring and formation pressure testing operations during NGHP-02 have confirmed the presence of large, highly concentrated gas hydrate accumulations in coarse-grained, sand-rich depositional systems throughout large portions of the Krishna-Godavari Basin. Post expedition research and reporting efforts included collaborative analysis of the unprecedented number of shipboard acquired data sets and core samples obtained during NGHP-02. The presentation of the scientific results of the NGHP-02 Expedition has culminated in the publication of the NGHP Expedition 02 Scientific Results Volume, which is represented by this Special Issue of the Journal of Marine and Petroleum Geology. This Special Issue features a series of four reports that summarize the operational and scientific results of NGHP-02 Expedition that are presented in the 41 technical reports included this Special Issue. The first summary report, “India National Gas Hydrate Program Expedition 02: Operational and Technical Summary,” focuses on reviewing the tools and operational procedures for the NGHP-02 Expedition that led to the acquisition of an unprecedented amount of high-quality downhole logging and core data from numerous pore-filling, fracture-filling, and sediment-displacement type gas hydrate occurrences. The summary report titled “India National Gas Hydrate Program Expedition 02 Summary of Scientific Results: Gas Hydrate Systems Along the Eastern Continental Margin of India” documents gas hydrate occurrences discovered during the NGHP-02 Expedition and examines geologic controls on the gas hydrate systems along the Eastern Continental Margin of India.

Journal of Marine and Petroleum Geology↗
USGS2013

Scientific results of the Second Gas Hydrate Drilling Expedition in the Ulleung Basin (UBGH2)

As a part of Korean National Gas Hydrate Program, the Second Ulleung Basin Gas Hydrate Drilling Expedition (UBGH2) was conducted from 9 July to 30 September, 2010 in the Ulleung Basin, East Sea, offshore Korea using the D/V Fugro Synergy. The UBGH2 was performed to understand the distribution of gas hydrates as required for a resource assessment and to find potential candidate sites suitable for a future offshore production test, especially targeting gas hydrate-bearing sand bodies in the basin. The UBGH2 sites were distributed across most of the basin and were selected to target mainly sand-rich turbidite deposits. The 84-day long expedition consisted of two phases. The first phase included logging-while-drilling/measurements-while-drilling (LWD/MWD) operations at 13 sites. During the second phase, sediment cores were collected from 18 holes at 10 of the 13 LWD/MWD sites. Wireline logging (WL) and vertical seismic profile (VSP) data were also acquired after coring operations at two of these 10 sites. In addition, seafloor visual observation, methane sensing, as well as push-coring and sampling using a Remotely Operated Vehicle (ROV) were conducted during both phases of the expedition. Recovered gas hydrates occurred either as pore-filling medium associated with discrete turbidite sand layers, or as fracture-filling veins and nodules in muddy sediments. Gas analyses indicated that the methane within the sampled gas hydrates is primarily of biogenic origin. This paper provides a summary of the operational and scientific results of the UBGH2 expedition as described in 24 papers that make up this special issue of the Journal of Marine and Petroleum Geology.

East Sea Of Korea;Ulleung Basin↗
USGS2007

A problem with estimating the pseudo- activation energy of kerogen thermal maturation from Connan's time-temperature relation in oil genesis.

Connan's time-temperature relation in oil genesis as derived from first-order reaction kinetics is algebraically correct, but its application to natural petroleum generation is invalidated by the assumption that the ratio of initial kerogen concentration to degraded kerogen concentration is constant from deposition to the initiation of intense oil generation. The ratio can only remain constant if no reaction is occurring and, therefore, Connan's data on 'reaction time' in petroleum generation (assumed to be the age of the sediment) only measures the time elapsed since the system formed. Thus, the widely cited pseudo-activation energy of 11-14 kcal/mole computed from Connan's equation for the start of oil generation from kerogen is meaningless.-Author

Journal of Petroleum Geology↗
USGS2007

Organic metamorphism in the Lower Mississippian-Upper Devonian Bakken shales. Part 1: Rock-Eval pyrolysis and vitrinite reflectance

Detailed organic geochemistry has been performed on a large number of Lower Mississippian-Upper Devonian Bakken shales from the North Dakota portion of the Williston Basin, and 28 oils mainly from Mississippian Madison Group rocks from different basinal areas. Here we report results of Rock-Eval pyrolysis and vitrinite reflectance ( R o ) analyses. Variable paleoheat flows in the Williston Basin caused the threshold of intense hydrocarbon generation to occur at different depths in different basinal areas. In higher paleogeothermal gradient basinal areas, this event occurred at depths of 7,650-8,000 ft, and at 10,000 ft or deeper in lower paleogeothermal gradient areas of the Basin. Distinct organic metamorphic imprints in Williston Basin sediments were also caused by extreme, but variable, paleoheat flows in the basin, as well as secondary migration of crude oils from deep basinal source areas. The high paleoheat flows are postulated as being due to a Late Cretaceous - Paleocene aborted rift event. Only a small volume of Bakken shales in restricted areas of the Williston Basin was responsible for the oil found reservoired in Mississippian Madison Group rocks. However, this small shale volume has been responsible for a relatively large amount of crude oil. R o profiles in the Tertiary through Middle Jurassic rocks in the Williston Basin had steep, linear R o versus depth gradients, with strong reversals of R o values occurring in the Lower Jurassic rocks. The lower Mesozoic through Paleozoic rocks of the Basin had strongly suppressed R o values compared to the values in the Tertiary through Middle Jurassic rocks. This was especially true of the R o values in the Bakken shales. This R o suppression was due to a change in organic matter (OM) type from oxygen-rich terrestrially derived OM in the younger rocks, to a hydrogen-rich marine derived OM in the deeper, older rocks. The threshold of intense oil generation (TIHG) occurred in the Bakken shales of the Williston Basin at R o values somewhere between 0.9 and 1.7% (best estimate 0.9), as would be read in oxygen-rich OM. Much higher burial temperatures (and consequently R o values) than usually held to be necessary were required for both the TIHG as well as mainstage hydrocarbon generation in the Bakken shales. These results are most likely applicable in general to source rocks with hydrogen-rich OM. The data of this study have major implications to petroleum exploration as well as to petroleum resource assessment.

Journal of Petroleum Geology↗
USGS2007

Organic metamorphism in the Lower Mississippian-Upper Devonian Bakken shales-II: Soxhlet extraction.

We report on Soxhlet extraction (and subsequent related analyses) of 39 Lower Mississippian-Upper Devonian Bakken shales from the North Dakota portion of the Williston Basin, and analyses of 28 oils from the Basin. Because of the influence of primary petroleum migration, no increase in the relative or absolute concentrations of hydrocarbons or bitumen was observed at the threshold of intense hydrocarbon generation (TIHG), or during mainstage hydrocarbon generation in the Bakken shales. Thus, the maturation indices that have been so useful in delineating the TIHG and mainstage hydrocarbon generation in other studies were of no use in this study, where these events could clearly be identified only by Rock-Eval pyrolysis data. The data of this study demonstrate that primary petroleum migration is a very efficient process. Four distinctive classes of saturated hydrocarbon gas chromatograms from the Bakken shales arose from facies, maturation, and primary migration controls. As a consequence of maturation, the % of saturated hydrocarbons increased in the shale extract at the expense of decreases in the resins and asphaltenes. Measurements involving resins and asphaltenes appear to be excellent maturation indices in the Bakken shales. Two different and distinct organic facies were present in immature Bakken shales. -from Authors

Journal of Petroleum Geology↗
USGS2007

Basin richness and source rock disruption - a fundamental relationship

Primary petroleum migration (expulsion from source rocks) remains the least understood parameter controlling the genesis of oil deposits. It is hypothesised that source rocks must be physically disrupted before meaningful expulsion can occur. Faulting, with accompanying significant fracturing, would appear to be the optimum naturally-occurring process for physical disruption of source rocks. If these hypotheses are valid, intensity of faulting in deeply-buried HC "kitchens' containing mature source rocks should strongly correlate with increasing basin richness. This possible relationship is examined in this paper; it is found that there is a strong correlation of increasing basin richness with increasing structural intensity over and adjacent to basin depocentres. This correlation thus supports the hypothesis that physical disruption of mature source rocks is a necessary, and previously unappreciated, controlling parameter for oil expulsion. -from Author

Journal of Petroleum Geology↗
USGS2007

Hydrocarbon source potential and maturation in eocene New Zealand vitrinite-rich coals: Insights from traditional coal analyses, and Rock-Eval and biomarker studies

The results of traditional methods of coal characterisation (proximate, specific energy, and ultimate analyses) for 28 Eocene coal samples from the West Coast of New Zealand correspond well with biomarker ratios and Rock-Eval analyses. Isorank variations in vitrinite fluorescence and reflectance recorded for these samples are closely related to their volatile-matter content, and therefore indicate that the original vitrinite chemistry is a key controlling factor. By contrast, the mineral-matter content and the proportion of coal macerals present appear to have had only a minor influence on the coal samples' properties. Our analyses indicate that a number of triterpane biomarker ratios show peak maturities by high volatile bituminous A rank; apparent maturities are then reversed and decline at the higher medium volatile bituminous rank. The Rock-Eval S1 +S2 yield also maximizes by high volatile bituminous A rank, and then declines; however, this decline is retarded in samples with the most hydrogen-rich (perhydrous) vitrinites. These Rock-Eval and biomarker trends, as well as trends in traditional coal analyses, are used to define the rank at which expulsion of gas and oil occurs from the majority of the coals. This expulsion commences at high volatile A bituminous rank, and persists up to the threshold of medium volatile bituminous rank (c. 1.1% Ro ran. or 1.2% Ro max in this sample set), where marked hydrocarbon expulsion from perhydrous vitrinites begins to take place.

Journal of Petroleum Geology↗
USGS2007

Oceanic methane hydrate: The character of the Blake Ridge hydrate stability zone, and the potential for methane extraction

Oceanic methane hydrates are mineral deposits formed from a crystalline 'ice' of methane and water in sea-floor sediments (buried to less than about 1 km) in water depths greater than about 500 m; economic hydrate deposits are probably restricted to water depths of between 1.5 km and 4 km. Gas hydrates increase a sediment's strength both by 'freezing' the sediment and by filling the pore spaces in a manner similar to water-ice in permafrost. Concentrated hydrate deposits may be underlain by significant volumes of methane gas, and these localities are the most favourable sites for methane gas extraction operations. Seismic reflection records indicate that trapped gas may blow-out naturally, causing large-scale seafloor collapse. In this paper, we consider both the physical properties and the structural integrity of the hydrate stability zone and the associated free gas deposits, with special reference to the Blake Ridge area, SE US offshore, in order to help establish a suitable framework for the safe, efficient, and economic recovery of methane from oceanic gas hydrates. We also consider the potential effects of the extraction of methane from hydrate (such as induced sea-floor faulting, gas venting, and gas-pocket collapse). We assess the ambient pressure effect on the production of methane by hydrate dissociation, and attempt to predict the likelihood of spontaneous gas flow in a production situation.Oceanic methane hydrates are mineral sits formed from a crystalline `ice' of methane and water in sea-floor sediments (buried to less than about 1 km) in water depths greater than about 500 m; economic hydrate deposits are probably restricted to water depths of between 1.5 km and 4 km. Gas hydrates increase a sediment's strength both by `freezing' the sediment and by filling the pore spaces in a manner similar to water-ice in permafrost. Concentrated hydrate deposits may be underlain by significant volumes of methane gas, and these localities are the most favourable sites for methane gas extraction operations. Seismic reflection records indicate that trapped gas may blow-out naturally, causing large-scale seafloor collapse. In this paper, we consider both the physical properties and the structural integrity of the hydrate stability zone and the associated free gas deposits, with special reference to the Blake Ridge area, SE US offshore, in order to help establish a suitable framework for the safe, efficient, and economic recovery of methane from oceanic gas hydrates. We also consider the potential effects of the extraction of methane from hydrate (such as induced sea-floor faulting, gas venting, and gas-pocket collapse). We assess the ambient pressure effect on the production of methane by hydrate dissociation, and attempt to predict the likelihood of spontaneous gas flow in a production situation.

Journal of Petroleum Geology↗
USGS2007

Abnormal organic-matter maturation in the Yinggehai Basin, South China Sea: Implications for hydrocarbon expulsion and fluid migration from overpressured systems

Three superimposed pressure systems are present in the Yinggehai Basin, South China Sea. A number of commercial, thermogenic gas accumulations have been found in an area in which shale diapirs occur. Because the reservoir intervals are shallow and very young, they must have filled with gas rapidly. The thick (up to 17 km) Tertiary and Quaternary sedimentary succession is dominated by shales, and is not disrupted by major faulting in the study area, a factor which seems to have had an important effect on both hydrocarbon generation and fluid migration. Organic-matter maturation in the deepest, most overpressured compartment has been significantly retarded as a result of the combined effects of excess pressure, the presence of large volumes of water, and the retention of generated hydrocarbons. This retardation is indicated by both kerogen-related parameters (vitrinite reflectance and Rock-Eval T(max)); and also by parameters based on the analysis of soluble organic matter (such as the C15+ hydrocarbon content, and the concentration of isoprenoid hydrocarbons relative to adjacent normal alkanes). In contrast to this, organic-matter maturation in shallow, normally-pressured strata in the diapiric area has been enhanced by hydrothermal fluid flow, which is clearly not topography-driven in origin. As a result, the hydrocarbon generation 'window' in the basin is considerably wider than could be expected from traditional geochemical modelling. These two unusual and contrasting anomalies in organic-matter maturation, together with other lines of evidence, suggest that there was a closed fluid system in the overpressured compartment until shale diapirs developed. The diapirs developed as a result of the intense overpressuring, and their growth was triggered by regional extensional stresses. They served as conduits through which fluids (both water and hydrocarbons) retained in the closed system could rapidly migrate. Fluid migration led to the modification of the thermal regime and the enhancement of organic maturation, as well as the accumulation of commercial volumes of gas in a relatively short time interval.Three superimposed pressure systems are present in the Yinggehai Basin, South China Sea. To date, a number of commercial, thermogenic gas accumulations have been found in an area in which shale diapirs occur. In fact, two unusual and contrasting anomalies in organic-matter maturation have been documented. These two anomalies, together with other lines of evidence, suggest that there was a closed fluid system in the overpressured compartment until shale diapirs developed. The diapirs developed as a result of intense overpowering, and their growth was triggered by regional extensional stresses. They served as conduits through which fluids retained in the closed system could rapidly migrate. Fluid migration led to the modification of the thermal regime and the enhancement of organic maturation, as well as the accumulation of commercial volumes of gas in a relatively short time interval.

Journal of Petroleum Geology↗
USGS2019

India National Gas Hydrate Program Expedition 02 summary of scientific results: Numerical simulation of reservoir response to depressurization

The India National Gas Hydrate Program Expedition 02 (NGHP-02) discovered gas hydrate at high saturation in sand reservoirs at several sites in the deepwater Bay of Bengal. To assess the potential response of those deposits to scientific depressurization experiments, comprehensive geologic models were constructed to enable numerical simulation for two sites. Both sites (NGHP-02-09 and NGHP-02-16) feature thick sequences of thinly-interbedded reservoir and non-reservoir facies at sub-seafloor depths of less than 300 m and sub-sea depths of 2,400 m or more. These settings pose significant challenges to current modeling capabilities. First, the thinly-bedded reservoir architecture complicates the determination of basic reservoir parameters from both log and core data due to measurement resolution issues. Secondly, the fine-scale variation in sediment properties imparts great contrasts in key parameters over very short distances, creating high gradients at multiple scales and varying orientations that necessitate careful design of high-definition simulation grids. Thirdly, the deposits include internal sources of water, as well as a range of complex boundary conditions, including variable permeability within the overlying mud-rich “seals”, that complicate reservoir depressurization. Lastly, because of the unique combination of great water depth and relatively shallow sub-seafloor depth, models designed to maximize the dissociation rate impose large pressure drawdowns on relatively low-strength sediments. This condition renders the proper evaluation and integration of the geomechanical response to hydrate dissociation critical. In this report, we review the history of gas hydrate reservoir simulation, discuss methods for creating geologic input models, and summarize the key findings and implications of the collaborative NGHP-02 numerical simulation effort. Together, the studies confirm the viability of the modeled accumulations for scientific testing and identify key challenges related to the selection of specific test sites and the design of test wells.

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↗
USGS2019

India National Gas Hydrate Program Expedition 02 Summary of Scientific Results: Gas hydrate systems along the eastern continental margin of India

The primary objectives of the India National Gas Hydrate Program Expedition 02 (NGHP-02) were to obtain new data on the occurrence of gas hydrate systems and to advance the understanding of the controls on the formation of gas hydrate accumulations in the offshore of India. In accordance with the ultimate overall goal of the NGHP effort to assess the energy resource potential of marine gas hydrates in India, particular focus was placed on the exploration and evaluation of gas hydrate occurrences at high saturations in sand-rich systems. NGHP-02 operations were conducted from 3-March-2015 to 28-July-2015 off the eastern coast of India and included logging while drilling (LWD) operations at 25 locations, and coring and wireline logging operations at 10 locations, in the Krishna-Godavari and Mahanadi Basins. The formation of highly concentrated gas hydrate accumulations, which are more suitable for energy extraction, requires the presence of relatively coarse-grained sediments with porosity needed to support the migration and accumulation of gas, and the nucleation of gas hydrate. The results of downhole logging, coring and formation pressure testing operations during NGHP-02 have confirmed the presence of extensive sand-rich depositional systems throughout the deepwater portions of the Krishna-Godavari and Mahanadi Basins. Two areas of Krishna-Godavari Basin, referred to as Areas B and C, contain substantial gas hydrate accumulations in sand-rich systems and therefore represent ideal candidate sites for future gas hydrate production testing. This summary and technical report includes a comprehensive synthesis of the geologic, geophysical, geochemical, and physical property data acquired during NGHP-02 as it relates to the controls on gas hydrate occurrence, particularly with regards to sand-hosted accumulations. In the Mahanadi Basin, despite the confirmation of extensive reservoir capacity, gas supply at the NGHP-02 sites was insufficient to charge the reservoirs with gas hydrates. In the Krishna-Godavari Basin, extensive reservoir systems were confirmed with sediment grain-sizes ranging from coarse-silts to gravels. These reservoirs range from fully- to partially filled with gas hydrate. The gas is determined to be from only microbial sources, and in part migrated into the reservoirs from deeper systems. The controls on gas hydrate occurrence are complex and varied; and include substantial reservoir heterogeneity and sufficient permeability throughout the reservoirs and seals that allowed pervasive fluid flow into and through the hydrate-bearing systems. These discoveries are the most significant confirmation of the exploration approach that focuses on direct detection of hydrate reservoirs supported by comprehensive petroleum systems analyses.

Journal of Marine and Petroleum Geology↗
USGS2019

Numerical simulations of depressurization-induced gas production from an interbedded turbidite gas hydrate-bearing sedimentary section in the offshore India: Site NGHP-02-16 (Area-B)

The recent National Gas Hydrate Program Expedition 02 (NGHP-02) identified the existence of gas hydrate-bearing sand reservoirs at a number of sites in the offshore of India including Site NGHP-02-16 in Area-B of the Krishna-Godavari Basin. The architecture of that gas hydrate accumulation is characterized by thin, gas hydrate-bearing, high quality sand layers interbedded with mud layers within a turbidite interval. The lowest gas hydrate-bearing layer contacting a thinly-interbedded saline aquifer designates the base of the gas hydrate stability zone (BGHSZ). The proximity of the BGHSZ and the average temperature around 20oC make the reservoir a favorable target for hydrate destabilization by means of the depressurization method. The results of the reservoir simulations indicate high gas production potential from this marine gas hydrate deposit with manageable concomitant water production using a well completion design that hydraulically isolates layers with water-saturated sands. Using a detailed geological input model, the predicted cumulative gas rates reach 3.1 x 104 m3/day (1.1 mmscf/day) after 90 days of continuous depressurization and demonstrate sustained production rates of 3.0 x 104 m3/day (1.0 mmscf/day) after 5 years of production. The interbedded nature of this gas hydrate occurrence promotes the development of horizontal dissociation interfaces between gas hydrate-bearing sand and mud layers. As a result, non-uniform gas production along the horizontal interfaces becomes a primary determinant of reservoir performance. Simulation cases have been executed to determine the impact of the uncertainty in in situ reservoir permeability and the manner in which intrinsic permeability dynamically changes during dissociation in response to the imposed effective stress increase. The cases where effective permeability is initially low and compaction is highly sensitive to stress result in the least favorable production predictions.

Journal of Marine and Petroleum Geology↗
USGS2020

An international code comparison study on coupled thermal, hydrologic and geomechanical processes of natural gas hydrate-bearing sediments

Geologic reservoirs containing gas hydrate occur beneath permafrost environments and within marine continental slope sediments, representing a potentially vast natural gas source. Numerical simulators provide scientists and engineers with tools for understanding how production efficiency depends on the numerous, interdependent (coupled) processes associated with potential production strategies for these gas hydrate reservoirs. Confidence in the modeling and forecasting abilities of these gas hydrate reservoir simulators (GHRSs) grows with successful comparisons against laboratory and field test results, but such results are rare, particularly in natural settings. The hydrate community recognized another approach to building confidence in the GHRS: comparing simulation results between independently developed and executed computer codes on structured problems specifically tailored to the interdependent processes relevant for gas hydrate-bearing systems. The United States Department of Energy, National Energy Technology Laboratory (DOE/NETL), sponsored the first international gas hydrate code comparison study, IGHCCS1, in the early 2000s. IGHCCS1 focused on coupled thermal and hydrologic processes associated with producing gas hydrates from geologic reservoirs via depressurization and thermal stimulation. Subsequently, GHRSs have advanced to model more complex production technologies and incorporate geomechanical processes into the existing framework of coupled thermal and hydrologic modeling. This paper contributes to the validation of these recent GHRS developments by providing results from a second GHRS code comparison study, IGHCCS2, also sponsored by DOE/NETL. IGHCCS2 includes participants from an international collection of universities, research institutes, industry, national laboratories, and national geologic surveys. Study participants developed a series of five benchmark problems principally involving gas hydrate processes with geomechanical components. The five problems range from simple geometries with analytical solutions to a representation of the world’s first offshore production test of methane hydrates, which was conducted with the depressurization method off the coast of Japan. To identify strengths and limitations in the various GHRSs, study participants submitted solutions for the benchmark problems and discussed differing results via teleconferences. The GHRSs evolved over the course of IGHCCS2 as researchers modified their simulators to reflect new insights, lessons learned, and suggested performance enhancements. The five benchmark problems, final sample solutions, and lessons learned that are presented here document the study outcomes and serve as a reference guide for developing and testing gas hydrate reservoir simulators.

Journal of Marine and Petroleum Geology↗
USGS2014

Comparison of the physical and geotechnical properties of gas-hydrate-bearing sediments from offshore India and other gas-hydrate-reservoir systems

The sediment characteristics of hydrate-bearing reservoirs profoundly affect the formation, distribution, and morphology of gas hydrate. The presence and type of gas, porewater chemistry, fluid migration, and subbottom temperature may govern the hydrate formation process, but it is the host sediment that commonly dictates final hydrate habit, and whether hydrate may be economically developed. In this paper, the physical properties of hydrate-bearing regions offshore eastern India (Krishna-Godavari and Mahanadi Basins) and the Andaman Islands, determined from Expedition NGHP-01 cores, are compared to each other, well logs, and published results of other hydrate reservoirs. Properties from the hydrate-free Kerala-Konkan basin off the west coast of India are also presented. Coarser-grained reservoirs (permafrost-related and marine) may contain high gas-hydrate-pore saturations, while finer-grained reservoirs may contain low-saturation disseminated or more complex gas-hydrates, including nodules, layers, and high-angle planar and rotational veins. However, even in these fine-grained sediments, gas hydrate preferentially forms in coarser sediment or fractures, when present. The presence of hydrate in conjunction with other geologic processes may be responsible for sediment porosity being nearly uniform for almost 500 m off the Andaman Islands. Properties of individual NGHP-01 wells and regional trends are discussed in detail. However, comparison of marine and permafrost-related Arctic reservoirs provides insight into the inter-relationships and common traits between physical properties and the morphology of gas-hydrate reservoirs regardless of location. Extrapolation of properties from one location to another also enhances our understanding of gas-hydrate reservoir systems. Grain size and porosity effects on permeability are critical, both locally to trap gas and regionally to provide fluid flow to hydrate reservoirs. Index properties corroborate more advanced consolidation and triaxial strength test results and can be used for predicting behavior in other NGHP-01 regions. Pseudo-overconsolidation is present near the seafloor and is underlain by underconsolidation at depth at some NGHP-01 locations.

Journal of Marine and Petroleum Geology↗
USGS2011

Physical properties of sediment from the Mount Elbert Gas Hydrate Stratigraphic Test Well, Alaska North Slope

This study characterizes cored and logged sedimentary strata from the February 2007 BP Exploration Alaska, Department of Energy, U.S. Geological Survey (BPXA-DOE-USGS) Mount Elbert Gas Hydrate Stratigraphic Test Well on the Alaska North Slope (ANS). The physical-properties program analyzed core samples recovered from the well, and in conjunction with downhole geophysical logs, produced an extensive dataset including grain size, water content, porosity, grain density, bulk density, permeability, X-ray diffraction (XRD) mineralogy, nuclear magnetic resonance (NMR), and petrography. This study documents the physical property interrelationships in the well and demonstrates their correlation with the occurrence of gas hydrate. Gas hydrate (GH) occurs in three unconsolidated, coarse silt to fine sand intervals within the Paleocene and Eocene beds of the Sagavanirktok Formation: Unit D-GH (614.4 m-627.9 m); unit C-GH1 (649.8 m-660.8 m); and unit C-GH2 (663.2 m-666.3 m). These intervals are overlain by fine to coarse silt intervals with greater clay content. A deeper interval (unit B) is similar lithologically to the gas-hydrate-bearing strata; however, it is water-saturated and contains no hydrate. In this system it appears that high sediment permeability (k) is critical to the formation of concentrated hydrate deposits. Intervals D-GH and C-GH1 have average "plug" intrinsic permeability to nitrogen values of 1700 mD and 675 mD, respectively. These values are in strong contrast with those of the overlying, gas-hydrate-free sediments, which have k values of 5.7 mD and 49 mD, respectively, and thus would have provided effective seals to trap free gas. The relation between permeability and porosity critically influences the occurrence of GH. For example, an average increase of 4% in porosity increases permeability by an order of magnitude, but the presence of a second fluid (e.g., methane from dissociating gas hydrate) in the reservoir reduces permeability by more than an order of magnitude.

Alaska↗