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All sourcesNASA NTRSDOE OSTI
DOE OSTI2024

Characterization of the Structural–Stratigraphic and Reservoir Controls on the Occurrence of Gas Hydrates in the Eileen Gas Hydrate Trend, Alaska North Slope

One of the most studied permafrost-associated gas hydrate accumulations in Arctic Alaska is the Eileen Gas Hydrate Trend. This study provides a detailed re-examination of the Eileen Gas Hydrate Trend with a focus on the gas hydrate accumulation in the western part of the Prudhoe Bay Unit. This integrated analysis of downhole well log data and published geophysical data has provided new insight on structural, stratigraphic, and reservoir controls on the occurrence of gas hydrates in the Eileen Gas Hydrate Trend. This study revealed the relatively complex nature of the gas hydrate occurrences in the Eileen Gas Hydrate Trend, with gas hydrates present in a series of coarsening upward, laterally pervasive, mostly fine-grained sand beds exhibiting high gas hydrate saturations. Most of the gas hydrate-bearing reservoirs in the Eileen Gas Hydrate Trend are laterally segmented into distinct northwest- to southeast-trending fault blocks, occur in a combination of structural–stratigraphic traps, and are only partially hydrate filled with distinct down-dip water contacts. These findings suggest that the traditional parts of a petroleum system (i.e., reservoir, gas source, gas migration, and geologic timing of the system formation) also control the occurrence of gas hydrates in the Eileen Gas Hydrate Trend.

20 FOSSIL-FUELED POWER PLANTS↗
DOE OSTI2019

A preliminary study of the gas hydrate stability zone in a gas hydrate potential region of China

Abstract Due to its significance for gas hydrate accumulation, the gas hydrate stability zone (GHSZ) is an essential condition for successful gas hydrate exploration and is usually controlled by three main factors: gas components, geothermal gradient, and permafrost thickness. Based on the core and conventional log data of gas hydrate potential region, the CSMHYD program was adopted to simulate the influences of above three factors on the thickness of the GHSZ. When the gas components of the gas hydrate were CH 4 , C 2 H 6 , and C 3 H 8 , with the CH 4 percentage ranging from 50% to 100%, the average GHSZ thickness can reach 1000 m according to the forward simulation results. When the gas hydrate was composed of CH 4 and one of C 2 H 6 , C 3 H 8 , H 2 S, and CO 2 , the influence order of the above four gases on the thickness of GHSZ is as follows: H 2 S ＞ C 2 H 6 ＞ C 3 H 8 ＞ CO 2 . Under the gas components of 90% CH 4 , 5% C 2 H 6, and 5% C 3 H 8 , the thickness of GHSZ decreased rapidly as the geothermal gradient increased following an exponential relation with a correlation of 99.92% and increased slowly as permafrost thickness increased following a linear relation with a correlation of 99.9%. In addition, the thickness of a gas hydrate favorable reservoir was determined by comprehensive log methods as 500 m. We conclude that a reservoir within 500 m below the permafrost layer is favorable for gas hydrate reservoir formation.

Xiao, Kun↗
DOE OSTI2018

2D micromodel study of clogging behavior of fine-grained particles associated with gas hydrate production in NGHP-02 gas hydrate reservoir sediments

Fine-grained particles (fines) commonly coexist with coarse-grained sediments that host gas hydrate. These fines can be mobilized by liquid and gas flow during gas hydrate production. Once mobilized, fines can clog pore throats and reduce reservoir permeability. Even where particle sizes are smaller than pore-throat sizes, clogs can form due to clusters of fines. For certain types of fines, particularly swelling clays, cluster sizes depend on pore-fluid chemistry, which changes as pore-fluid freshens during gas hydrate dissociation. Fines can also be concentrated by a moving gas/liquid interface, increasing the chances of pore-throat clogging regardless of fines type. To test the relative significance of these clogging mechanisms, 2D micromodel experiments have been conducted with different pore-throat widths (20, 40, 60 and 100 µm), single-phase pore-fluids (deionized water and 2M-sodium-chloride solution), and moving gas/liquid interfaces on specimens from Sites NGHP-02-09 and NGHP-02-16 (NGHP-02: National Gas Hydrate Program Expedition 02) as well as a selection of pure fines (silica silt, mica, calcium carbonate, diatoms, kaolin, and bentonite). Clogging depended on the ratio of particle-to-pore throat size, and also on pore-fluid chemistry because the pore-fluid chemistry changes effectively increased or decreased the fine’s cluster size relative to the pore-throat width. These interactions can be predicted based on the fine’s electrical sensitivity (defined by Jang and Santamarina, 2016). The fine-grained sediment component (grain size < 75 μm) from the primary gas hydrate reservoir layers at Sites NGHP-02-09 and -16 show clogging via blocking or size exclusion (sieving) due to the large particles. Clogs also formed due to bridging or blocking by clusters of the smaller particles. In conclusion, clogging generally occurred for pore-water sediment concentrations so low (0.2% by mass or less), that it was difficult to resolve the enhanced clogging in the presence of the gas/liquid meniscus.

09 BIOMASS FUELS↗
DOE OSTI2017

Gas hydrate reservoirs and gas migration mechanisms in the Terrebonne Basin, Gulf of Mexico

Here, the interactions of microbial methane generation in fine-grained clay-rich sediments, methane migration, and gas hydrate accumulation in coarse-grained, sand-rich sediments are not yet fully understood. The Terrebonne Basin in the northern Gulf of Mexico provides an ideal setting to investigate the migration of methane resulting in the formation of hydrate in thin sand units interbedded with fractured muds. Using 3D seismic and well log data, we have identified several previously unidentified hydrate bearing units in the Terrebonne Basin. Two units are >100 m- thick fine-grained clay-rich units where gas hydrate occurs in near-vertical fractures. In some locations, these fine-grained units lack fracture features, and they contain 1-4-m thick hydrate bearing-sands. In addition, several other thin sand units were identified that contain gas hydrate, including one sand that was intersected by a well at the location of a discontinuous bottom-simulating reflector. Using correlation of well log data to seismic data, we have mapped and described these new units in detail across the extent of the available data, allowing us to determine the variation of seismic amplitudes and investigate the distribution of free gas and/or hydrate. We present several potential source-reservoir scenarios between the thick fractured mud units and thin hydrate bearing sands. We observe that hydrate preferentially forms within thin sand layers rather than fractures when sands are present in larger marine mud units. Based on regional mapping showing the patchy lateral extent of the thin sand layers, we propose that diffusive methane migration or short-migration of microbially generated methane from the marine mud units led to the formation of hydrate in these thin sands, as discontinuous sands would not be conducive to long-range migration of methane from deeper reservoirs.

03 NATURAL GAS↗
DOE OSTI2022

Neural net detection of seismic features related to gas hydrates and free gas accumulations on the northern U.S. Atlantic margin

Bottom-simulating reflections (BSRs) that sometimes mark the base of the gas hydrate stability zone in marine sediments are often identified based on the reverse polarity reflections that cut across stratigraphic layering in seismic amplitude data. On the northern U.S. Atlantic margin (USAM) between Cape Hatteras and Hudson Canyon, legacy seismic data have revealed pronounced BSRs south of the deepwater extension of Hudson Canyon and more subtle ones from offshore Delaware south to Cape Hatteras, where the reflections sometimes follow stratigraphic layering. Using high-resolution seismic data acquired during the 2018 Mid-Atlantic Resource Imaging Experiment and a supervised neural net, we identify seismic features associated with gas hydrates and/or the top of gas between Hudson Canyon and Cape Hatteras. Using seismic attributes especially sensitive to the presence of gas, we train a neural network algorithm on seismic data from an area with strong BSRs and then apply the model to the rest of the data set. The results indicate that gas hydrate and/or shallow free gas are significantly more widespread on the northern part of the USAM than previously known. Seismic indicators of gas extend landward from the 2000 m isobath to the upper continental slope in sectors with (offshore Virginia) and, to a lesser extent, without (offshore New Jersey) pervasive upper slope methane seeps. Higher sand content and intermediate sediment thickness, factors related to the container size and gas charge in a petroleum systems framework, are associated with more robust gas indicators.

Geochemistry & Geophysics↗
DOE OSTI2019

India National Gas Hydrate Program Expedition 02 Summary of Scientific Results: Gas Hydrate Systems Along the Eastern Continental Margin of India

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 less than 300m and sub-sea depths of 2400m or more. These settings pose significant challenges to current modeling capabilities. First, the thinly-interbedded 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.

Collett, Tim↗
DOE OSTI2019

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 less than 300m and sub-sea depths of 2400m or more. These settings pose significant challenges to current modeling capabilities. First, the thinly-interbedded 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.

Boswell, Ray↗
DOE OSTI2017

Investigating the influence of lithologic heterogeneity on gas hydrate formation and methane recycling at the base of the gas hydrate stability zone in channelized systems

In marine environments, gas hydrate preferentially accumulates in coarse-grained sediments. At the meso- to micro-scale, however, hydrate distribution in these coarse-grained units is often heterogeneous. We employ a methane hydrate reservoir simulator coupling heat and mass transfer as well as capillary effects to investigate how capillary controls on methane solubility affect gas and hydrate accumulations in reservoirs characterized by graded bedding and alternating sequences of coarse-grained sands and fine-grained silt and clay. Simulations bury a channelized reservoir unit encased in homogeneous, fine-grained material characterized by small pores (150 nm) and low permeability (~1 md in the absence of hydrate). Pore sizes within each reservoir bed between vary between coarse sand and fine silt. Sands have a median pore size of 35 microns and a lognormal pore size distribution. We also investigate how the amount of labile organic carbon (LOC) affects hydrate growth due to microbial methanogenesis within the sediments. In a diffusion-dominated system, methane movies into reservoir layers along spatial gradients in dissolved methane concentration. Hydrate grows in such a way as to minimize these concentration gradients by accumulating slower in finer-grained reservoir layers and faster in coarser-grained layers. Channelized, fining-upwards sediment bodies accumulate hydrate first along their outer surfaces and thence inward from top to bottom. If LOC is present in thin beds within the channel, higher saturations of hydrate will be distributed more homogeneously throughout the unit. When buried beneath the GHSZ, gas recycling can occur only if enough hydrate is present to form a connected gas phase upon dissociation. Simulations indicate that this is difficult to achieve for diffusion-dominated systems, especially those with thick GHSZs and/or small amounts of LOC. However, capillary-driven fracturing behavior may be more prevalent in settings with thick GHSZs.

Daigle, Hugh↗
DOE OSTI2020

In situ and laboratory evidence for high electrical anisotropy in marine gas hydrate

Marine gas hydrate is electrically resistive compared to the surrounding hydrate-free formation, a property that is exploited in borehole logging and also by marine controlled-source electromagnetic (CSEM) surveys. Well logging shows that hydrate can be electrically anisotropic, with vertical resistivities up to 10 times higher than horizontal resistivities, although the use of logging tools capable of measuring anisotropy is the exception rather than the rule. Marine CSEM methods are well known to be sensitive to anisotropy in seafloor sediments, and, for example, we have observed anisotropies of more than an order of magnitude using CSEM to map offshore relic permafrost.

02 PETROLEUM↗
DOE OSTI2019

Development of Deepwater Natural Gas Hydrates

Deepwater natural gas hydrate resources potentially exceed all other conventional and non-conventional hydrocarbon resources on a world-wide basis. However, before these offshore gas hydrate resources can be classified as reserves, it must be demonstrated that gas hydrates can be produced under conditions thatmake economic sense. The purpose of this paper is to provide an overview of the technical issues that will challenge the development of deepwater natural gas hydrates.

Hancock, Steven↗
DOE OSTI2018

Burial-driven methane recycling in marine gas hydrate systems

Natural gas hydrate may be buried with sediments until it is no longer stable at a given pressure and temperature, resulting in conversion of hydrate into free gas. This gas may migrate upward and recycle back into the hydrate stability zone to form hydrate. As of yet, however, no quantitative description of the methane recycling process has been developed using multiphase flow simulations to model burial-driven gas hydrate recycling. In this study, we present a series of 1D multiphase transport simulations to investigate the methane recycling process in detail. By invoking the effects of capillary phenomena on hydrate and gas formation in pores of varying size, we find that a free gas phase can migrate a significant distance above the bulk base of hydrate stability. Since the top of the free gas occurrence is often identified as the base of the hydrate stability zone from seismic data, our results demonstrate that not only could this assumption mischaracterize a hydrate system, but that under recycling conditions the highest hydrate saturations can occur beneath the top of the free gas occurrence. We show that the presence of pore size distributions requires a replacement zone through which hydrate saturations progressively decrease with depth and are replaced with free gas. This replacement zone works to buffer against significant gas buildup that could lead to fracturing of overlying sediments. In conclusion, this work provides a framework for simulating flow and transport of methane within the 3-phase stability zone from a mass conservation perspective.

58 GEOSCIENCES↗
DOE OSTI2017

The Increasingly Complex Challenge of Gas Hydrate Reservoir Simulation

Gas hydrate reservoir simulation is a complex endeavor. Reliable simulation capability will allow the proper design of field tests and the interpretation of field test data that are necessary to advance the understanding of the response of gas hydrate reservoirs to production activities. Increasing appreciation of the complexity of gas hydrate reservoirs, as well as continued uncertainty in key petrophysical parameters, requires great care in the design of simulation studies. This report outlines select emerging issues that greatly impact the relevance of numerical simulation resulting, including reservoir heterogeneity, geomechanics, log and core data interpretation, grid size, and others.

Boswell, Ray↗
DOE OSTI2018

Antiagglomerants Affect Gas Hydrate Growth

In gas clathrate hydrates, inclusion gas molecules stabilize crystalline water structures. In addition to being fundamentally interesting, gas hydrates attract significant practical attention because of their possible application in various high-tech technologies. However, gas hydrates pose health, safety, and environmental risks when they form within oil and gas pipelines, as well as within hydrocarbon-producing and treatment facilities. Among available strategies to control and sometimes prevent hydrate plug formation is the use of surface-active low-molecular-weight compounds, known as antiagglomerants (AAs). AAs prevent the agglomeration of small hydrate particles into large plugs. It is not clear whether AAs promote or frustrate hydrate growth. We present two molecular mechanisms by which AAs promote and frustrate, respectively, hydrate growth. Our results could lead to innovative methodologies for managing hydrates in high-tech applications, as well as for securing the safety of oil and gas operations.

37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗