National Gas Hydrate Program Research Articles

Physical property characteristics of gas hydrate-bearing reservoir and associated seal sediments collected during NGHP-02 in the Krishna-Godavari Basin, in the offshore of India

Abstract India's National Gas Hydrate Program Expedition 02 (NGHP-02) was conducted to better understand geologic controls on gas hydrate occurrence and morphology, targeting coarse-grained sediments along the lower continental slope offshore eastern India. This study combines seismic, logging-while-drilling data, and a petroleum system approach to provide a regional geologic and lithologic context for: 1) gas hydrate morphology and distribution, and 2) effects of fine-grained sediments (clays and other grains smaller than 63 μm) on gas production in NGHP-02 Area B in the Krishna-Godavari Basin. Area B seismic data show a buried anticline/syncline structure with strong reflectors, R1 and R2, that delineate two of the five lithologic units: Unit I (shallowest), II (R1), III, IV (R2) and V (below the bas of gas hydrate stability). Throughout Area B, gas hydrate morphology depends on its placement within these units. Specifically, core- and grain-scale measurements indicate fines content exerts a primary control on the gas hydrate distribution and morphology. Units I, II and III are generally fine-grained. On the anticline crest, these units host primarily grain-displacing gas hydrate veins linked to pore-occupying gas hydrate in thin, localized, coarser-grained deposits. Diatoms in Unit III increase porosity with depth, reaching ∼70% where it contacts Unit IV, the gas hydrate reservoir associated with reflector R2. The Unit III lithology and porosity allow fluid and dissolved-phase methane to escape Unit IV and form gas hydrate in the fine-grained overburden. Within Unit IV, fine-grained layers are interbedded with coarser-grained gas hydrate reservoir sands, and the fines content even in the sands is high enough to impact hydraulic and mechanical properties during gas production. Fluid motion during gas production can mobilize fines, which can then clog pore throats, limiting production rates. Pore-water freshening during gas hydrate dissociation can increase fines mobilization, particularly given the smectite identified in the fine-grained interbeds.

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

Abstract 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 300 m and sub-sea depths of 2400 m 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.

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. 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.

Assessing the geomechanical stability of interbedded hydrate-bearing sediments under gas production by depressurization at NGHP-02 Site 16

Abstract Establishing the geomechanical stability of marine sediments in the vicinity of a production well is one of the key design considerations in planning offshore gas production from marine hydrate reservoirs. This paper presents an assessment of the sediment stability at India's National Gas Hydrate Program, Expedition 2 (NGHP-02) Site 16 Area B offshore eastern India, for which gas production is to be carried out by depressurization. One important feature of the study is that extensive calibration of constitutive model parameters has been conducted based on laboratory test data from pressured core samples. From analysis perspective, the site is challenging because the hydrate reservoir consists of thin layers of hydrate-bearing sands interbedded with mud. Moreover, depressurization at the depth of a reservoir more than 2750 m below sea surface will lead to a pore pressure drop, and accordingly an effective confining stress increase as high as 25 MPa. In dealing with thin interbedded hydrate-bearing strata, meshing requirements for flow and geomechanical analysis are quite different from those for reservoirs with thicker massive layers, An axisymmetric model and one-way coupling simulations were thus adopted for this study, in which the geomechanical study utilizes pore pressure and hydrate saturation output from the flow study, but the flow study does not takes the porosity changes from the geomechanical analysis. Instead, the reduction of porosity due to sediment deformation in the flow study is based on a pressure-dependent pore compressibility relationship derived from geomechanical modeling. The rationality is validated through back computing the pore compressibility from the geomechanical deformation results. The study shows that large compression in the reservoir will result in movement of the sediments from above and below, as well as laterally in smaller magnitudes; and the sediment is deemed stable during the gas production period.

Permeability anisotropy and relative permeability in sediments from the National Gas Hydrate Program Expedition 02, offshore India

Gas and water permeability through hydrate-bearing sediments essentially governs the economic feasibility of gas production from gas hydrate deposits. Characterizing a reservoir's permeability can be difficult because even collocated permeability measurements can vary by 4–5 orders of magnitude, due partly to differences between how various testing methods inherently measure permeability in different directions and at different scales. This study uses a customized flow anisotropy cell to investigate geomechanical and hydrological properties of hydrate-bearing sediments focusing on permeability anisotropy (i.e., horizontal, kh, to vertical, kv, permeability ratio) and relative permeability. Two cores recovered during India's National Gas Hydrate Program Expedition 02 (NGHP-02) are tested in this study. Near in situ effective vertical stress, ∼ 2 MPa, the permeability anisotropy is approximately kh/kv = 1.86 for the “seal core” (from a fine-grained non-reservoir overburden sedimentary section) and kh/kv = 4.24 for the gas hydrate reservoir core with tetrahydrofuran (THF) hydrate saturation Sh = 0.8. Permeability anisotropy increases exponentially with effective vertical stress, as described by kh/kv = α(σv/MPa)β, with α = 1.6, β = 0.22 for seal sediment and α = 3, β = 0.5 for THF hydrate-bearing sediment. Results imply the measured permeability from permeameter tests with vertical flow may underestimate the reservoir's flow performance, which is mainly horizontal (radial) toward a vertical well. Hydrate in sediment increases the gas-entry pressure and residual water saturation, but decreases the water retention curve's shape factor (m), resulting in a steeper curve. Distributions of available pore space sizes for flow in sediment with and without THF hydrate (Sh = 0.8) follow a log-normal distribution. Hydrate formation decreases the apparent mean pore size from ∼10 μm to ∼2 μm, without evidently changing the pore size distribution's standard deviation. Gas hydrate dissociation increases effective permeability and relative permeability to gas.

Gas hydrate saturation and morphology from analysis of pressure cores acquired in the Bay of Bengal during expedition NGHP-02, offshore India

India's National Gas Hydrate Program Expedition 2 (NGHP-02) completed an ambitious pressure coring program as part of their effort to evaluate gas hydrate in coarse-grained reservoirs in the Bay of Bengal. The 75 successful pressure cores were used to measure gas hydrate saturation, examine the morphology of the gas hydrate at in situ conditions, and to provide samples for further laboratory work. Pressure core quality was assessed via pressure-temperature records and X-ray computed tomographic reconstructions of cores. Gas hydrate saturations were measured by using the gas from quantitative degassing experiments in methane mass balance calculations. Gas hydrate morphology was determined from X-ray computed tomographic reconstructions, P-wave velocity, and gamma density measured under pressure using PCATS, the Pressure Core Analysis and Transfer System. Gas hydrate saturations reached 65–85% in the pores of sandy reservoir sediments, and were near full saturation in gravelly sediments. Clayey interlayers between reservoir sediments had gas hydrate saturations near 10%, with no evidence of gas hydrate veins in X-ray computed tomographic (CT) reconstructions. Veins of gas hydrate were visible in X-ray images of clayey non-reservoir sediments; at some locations the full complement of gas hydrate was contained in X-ray-resolveable veins, but in others the veins only accounted for part of the total gas hydrate burden in the sediment, implying that some gas hydrate was finely distributed in the pore space or in veins below the resolution of the X-ray CT data. At one location low-density, biosilica-rich silty clays hosted pore-filling gas hydrate at saturations of 45%, with only slightly elevated P-wave velocities. Gas hydrate saturation and morphology from all the pressure cores are presented here and placed into geological context. • Pressure core quality must be critically examined before using data. • Gas hydrate saturations reached 65–85% in the pores of sandy reservoir sediments. • Clayey interlayers between reservoir sediments had hydrate saturations near 10%. • Visible veins did not contain all the gas hydrate in many clayey samples. • Low-density biosilica-rich silty clays contained 45% pore-filling gas hydrate.

Permeability variation and anisotropy of gas hydrate-bearing pressure-core sediments recovered from the Krishna–Godavari Basin, offshore India

Abstract Permeability measurements were conducted on gas hydrate-bearing pressure-core sediments recovered from the Krishna–Godavari Basin during India's National Gas Hydrate Program Expedition 02. Pressure cores collected in the deep seabed of the Indian Ocean were cut and stored under high pressure and low temperature on the D/V Chikyu using pressure core analyzing tools. A total of 25, 1.2-m storage chambers were transferred to Japan from India for pressure core studies using pressure-core analysis tools at the National Institute of Advanced Industrial Science and Technology. The sediment core's pressure and temperature were maintained within the hydrate stability conditions during the entire process of transfer and loading into a triaxial testing apparatus called TACTT to preserve the hydrate, which can simulate the in-situ effective stress state under triaxial conditions. The hydrate saturation of the samples was in the range of 50–90%. It was found that the initial effective water permeability was in range of 0.01 mD to tens of mD, depending on the hydrate saturation and the mean particle size of the host sediment. The hydrate pore space morphology is also a critical factor, and results suggest hydrates are forming in the pore centers of sand grains as pore filling, but also as a sediment grain coating. In a first for gas hydrate-bearing pressure cores, the permeability anisotropy was established via vertical and horizontal flow tests combined with a pore fluid flow simulation. The horizontal/vertical permeability ratio was found to be 4. Additionally, the effective stress dependency of permeability was investigated by performing flow tests at different effective stresses. Due to decreasing porosity and particle crushing, the permeability dropped by approximately 90% for an effective stress increase of 10 MPa.

Multi-measurement approach for establishing the base of gas hydrate occurrence in the Krishna-Godavari Basin for sites cored during expedition NGHP-02 in the offshore of India

The 2015 National Gas Hydrate Program of India's second expedition, NGHP-02, acquired logging and coring datasets for constraining the base of the gas hydrate occurrence zone (deepest GH) and the theoretical base of gas hydrate stability zone (BGHS). These data are used here for two primary goals: to constrain the deepest occurrence of gas hydrate relative to predicted stability limits and the observed BSR, and to characterize the nature of the contact between gas hydrate-bearing sediment and the underlying gas hydrate-free sediment. A consensus depth for the deepest GH is derived for each NGHP-02 coring site from downhole indicators of gas hydrate occurrence obtained from well-log electrical resistivity and acoustic data, pressure core compressional wave velocity measurements, and conventional core measurements of anomalously low temperatures. To establish the theoretical BGHS, models of gas hydrate phase stability with depth are compared with downhole temperature profiles derived from: 1) assuming a constant geothermal gradient consistent with downhole temperature measurements, and 2) assuming constant heat flow using a geotherm through the downhole temperature measurements and incorporating thermal conductivity calculated from borehole logging data. Although the deepest NGHP-02 GH occurrences are controlled at several sites by a lithologic boundary, most sites have deepest GH occurrences within a single coarse-grained lithology. Cutoffs within a single coarse-grained lithology, which occur for the primary NGHP-02 Area B gas hydrate reservoir, will inhibit pore-pressure drawdowns used to extract methane from gas hydrate as an energy resource.

PCATS triaxial testing: Geomechanical properties of sediments from pressure cores recovered from the Bay of Bengal during expedition NGHP-02

Abstract The Indian National Gas Hydrate Program Expedition 02 (NGHP-02) was the most comprehensive gas hydrate drilling expedition carried out to date. From 74 pressure cores that were successfully recovered from various site locations offshore India, 19 subsamples were obtained for further detailed geotechnical analysis using the PCATS Triaxial apparatus to investigate the geomechanical behaviour of the cores, including small-strain stiffness, Gmax, undrained shear strength, Su, as well as direct-flow measurements of permeability, k. Samples tested included fine-grained muds with no appreciable hydrate through to coarse-grained sands that contained extensive hydrate within the pore space. Although the subsampling and transfer of pressure cores into the PCATS Triaxial under zero effective confining stress, σ′, remains challenging, 12 samples were successfully transferred and underwent detailed geotechnical characterization. During consolidation, after reapplication of in-situ σ′, all samples experienced axial and radial consolidation, with variations between samples seemingly dependent on the degree of sample disturbance, stress relaxation between coring and testing, hydrate saturation, Sh and grain size, D50. The largest values of Gmax were obtained from samples with high Sh in the pore space, with values much higher than that expected for similar sediments without hydrate under comparable σ’. Samples with high permeability had both high Sh and larger grain size, suggesting that in coarse-grained sediments sufficient pathways are available for reasonable fluid flow even with high hydrate saturations. Triaxial testing and unconfined compression tests highlighted the influence of hydrate on increasing sediment strength, although the size of the sediment grains appeared to have an important control on the magnitude of the strength increase and the overall stress-strain behaviour. The results from the detailed geotechnical characterization of the recovered pressure cores will be invaluable in helping India identify potential locations for future gas production wells, and assess the long-term performance of such reservoirs.

Regional stratigraphic framework and gas hydrate occurrence offshore eastern India: Core-log-seismic integration of National Gas Hydrate Program Expedition 02 (NGHP-02) Area-B drill sites

Abstract The Indian National Gas Hydrate Program Expedition 02 (NGHP-02) was designed to study the occurrence of gas hydrate along the passive continental margin of the Indian Peninsula in the Bay of Bengal. Twelve holes were logged and measured with logging-while-drilling (LWD) and five holes were cored in Area-B of NGHP-02. The LWD and coring results in Area-B helped to understand the geological significance of sequence stratigraphy in Krishna-Godavari Basin and identified the occurrence of gas hydrate. This study summarized the log- and litho-units in Area-B and establish three integrated units based on the core-log-seismic integration. Most of the downhole log and core inferred gas hydrate occurrences are in the Late Miocene Integrated-Unit B with several sets of reservoir sections exhibiting favorable conditions for hosting gas hydrate. The gas hydrates reservoirs associated with reflectors R1 and R2 were identified and the R1 reservoirs are characterized by fracture- and pore-filling gas hydrate, and the R2 is in sand-rich sediments with pore-filling gas hydrate at high saturations. The thickness variations associated with the R1 and R2 are possibly associated with the development anticlinal structure and are likely related to syn-sedimentary growth of the folding structures. Major gas hydrate zones exist in and around the R1 and R2 near the BSR depth, and mostly have coincident with the fractures and mass-transport deposits. The spatial distribution of gas hydrate in the R1 and R2 reservoirs is highly influenced by the anticlinal structure. This study can be considered a good case for the future gas hydrate studies and explorations in the nearby areas.

Origin of low-chloride fluid in sediments from the eastern continental margin of India, results from the National Gas Hydrate Program Expedition 02

Abstract National Gas Hydrate Program Expedition 02 was conducted in 2015 by D/V Chikyu in the western Bay of Bengal, India. Analyses of interstitial water in sediment from four drilling sites along the eastern and western transect in the Krishna–Godavari Basin show that dissolved chloride (Cl−) concentrations decreased with depth from seawater values (>550 mM) near the sediment surface to 300–400 mM at 350–400 m below seafloor (mbsf), suggesting the upward advection of low-Cl– fluid. Excursions of Cl− concentrations toward low values in gas hydrate zones were attributed to the presence of fresh water released by dissociation of gas hydrate during core recovery. At Sites in the western transect, Cl− concentrations below the gas hydrate reservoir (around 280 mbsf) were ca. 60 mM and ca. 45 mM lower than those from above the reservoir, and δ18O and δD values were 1–2‰ and 0.7–1.3‰ higher than those from above the reservoir, respectively. These results suggest that a fraction of migrating low-Cl– fluid is trapped in the gas hydrate zone, causing decreases of δ18O and δD in the residual water due to isotopic fractionation during gas hydrate formation. From mass-balance calculations, we estimated that 10–20% of the advected fluid is trapped at the gas hydrate zone. At all sites, the δ18O and δD values below the gas hydrate zone, representing relatively unaltered low-Cl– fluid, were 0.5–1‰ higher and ca. 13–15‰ lower than those of seawater, respectively. This trend is consistent with water derived from the dehydration of clay minerals, which generally occurs in deeply buried sediments. The contribution of clay mineral dehydration is relatively large at the western transect compared to that in the eastern transect. Our results imply that fluid advection contributes to the accumulation of gas hydrate in the study area.

Equivalent formation strength as a proxy tool for exploring for the location and distribution of gas hydrates

Abstract Gas hydrate-bearing layers are normally identified by a seismic imaged bottom simulating reflectors (BSR) or by downhole log responses because of their high acoustic velocity and electric resistivity compared to surrounding formations. These gas hydrate characteristics can also result in contrasting in-situ formation compressive strengths. Here, we describe gas hydrate-bearing layers based on equivalent strength (EST), which relates to in-situ compressive strength, in five exploration boreholes drilled during the Indian National Gas Hydrate Program Expedition 02 (NGHP-02). For Site NGHP-02-23, a representative site for those that were established during NGHP-02, the EST evaluated from drilling parameters shows a constant trend of ∼2 MPa, with some strong peak values in the 0–271.4 m-below-seafloor (mbsf) interval, and a sudden increase up to 4 MPa above the BSR depth (271.4–290.0 mbsf). Below the BSR, the EST stays at ∼2 MPa to the bottom of the hole (378 mbsf). Comparing the EST with logging data and a core sample description suggests that the EST depth profiles reflect the formation lithology and gas hydrate content. The EST increases in sand-rich and gas hydrate-bearing zone. In the lower gas hydrate layers in particular, the EST curve shows the same approximate trend with that of P-wave velocity and resistivity measured during downhole logging. Similar relationships between EST, hydrate layer, and log responses are confirmed in other four sites drilled nearby in NGHP-02 Area B. These results suggest that the EST, as a proxy for in-situ formation strength, can indicate the location and extent of the gas hydrate as well as borehole logging. Although the EST was calculated after drilling, utilizing the recorded surface drilling parameters (weight on bit, top drive torque, RPM and rate of penetration) in this study, the EST can be acquired during drilling using real-time drilling parameters. In addition, the EST only requires drilling performance data without any additional tools or measurements, making it a simple and economical tool for the exploration of gas hydrates.

Downhole physical property-based description of a gas hydrate petroleum system in NGHP-02 Area C: A channel, levee, fan complex in the Krishna-Godavari Basin offshore eastern India

India's second National Gas Hydrate Program expedition, NGHP-02, collected logging while drilling and sediment core data in Area C offshore eastern India, to investigate controls on the distribution and peak saturations of methane gas hydrate occurrences in buried channel, levee and fan deposits. Physical property results are presented here for the four Area C coring sites: NGHP-02-07, targeting an upper continental-slope channel deposit; NGHP-02-08 and −09, targeting levee deposits on either side of a channel further downslope, and NGHP-02-05, targeting a sequence of fan deposits extending out from the slope base. Coarse-grained sediment exists at each site, but site-specific differences in clay distribution provide significant controls on the gas hydrate distribution and saturation. At NGHP-02-07, only the upper ∼4 m of a ∼42 m-thick, relatively low clay-content, coarse-grained interval is inferred to be gas hydrate-bearing. NGHP-02-07 has a relatively thin, high-permeability overburden seal, and methane-rich fluid likely leaks from the primary reservoir. NGHP-02-08's levee deposit seal is similarly permeable near the reservoir, but becomes less permeable toward the seafloor. Relative to NGHP-02-07, methane is retained more effectively in the NGHP-02-08 reservoir, but that reservoir is interbedded with layers of high clay-content, low gas hydrate saturation sediment, limiting the maximum gas hydrate content for NGHP-02-08. NGHP-02-09, the second levee deposit site, has a thicker, less permeable overburden than NGHP-02-08, combined with >50 m-thick, low clay-content reservoir sediments. Correspondingly, NGHP-02-09 has a thicker gas hydrate-bearing reservoir with consistently higher gas hydrate saturations than NGHP-02-08. NGHP-02-05 has abundant coarse-grained material spread over nearly the entire drilling interval, but the sediment is poorly sorted. Gas hydrate is distributed among several primarily coarse-grained layers, but gas hydrate saturations are limited by relatively high clay contents, and an overlying seal that is too thin and permeable to effectively retain methane in the reservoir. • Clay content provides a primary control on the distribution and peak saturation of gas hydrate. • Gas hydrate was not observed to form in the coarse-grained, primary reservoir where the clay fraction exceeded ~0.3. • Overlying fine-grained sediment is a more effective low-permeability seal than the gas hydrate-saturated reservoir is. Imperfect seals in Area C can be linked with incomplete occupation of the coarse-grained sediment by gas hydrate.

Repeated large-scale mass-transport deposits and consequent rapid sedimentation in the western part of the Bay of Bengal, India

Abstract The National Gas Hydrate Program Expedition 02 was conducted in early 2015 using the Drilling Vessel Chikyu in the western part of the Bay of Bengal, India. During drilling off Vishakhapatnam, NE India, some bottom-simulating reflectors were penetrated, and numerous mass-transport deposits (MTDs) were identified. The recovered cores were composed of post-late Miocene muddy slope deposits containing the late Miocene–Pliocene hiatus that is widespread in that region. Based on detailed visual core descriptions and calcareous nannofossil biostratigraphy, two major MTD-rich intervals were identified: the Pleistocene interval above the hiatus, and the middle–late Miocene interval below it. Although the MTDs in both intervals are composed of variously coloured clay–silt blocks in an olive-black or olive-grey silty clay matrix (muddy MTDs), the Pleistocene MTDs consist of larger-sized blocks (mostly less than a few metres but with some &gt;10 m) without clear shear fabrics, whereas the Miocene MTDs contain smaller blocks (&lt;0.1 m) with asymmetrical shear fabrics. The muddy blocks are composed of older components (Pliocene–Cretaceous) compared with the depositional ages of the MTDs. The high abundance of MTDs above the hiatus and the depositional ages of the interbedded coherent layers indicate that large-scale MTDs occurred repeatedly during the Pleistocene. Such repeated MTDs contributed to maintaining the high sedimentation rate in this area and potentially provided stable pressure and temperature conditions for the formation of gas hydrates.

National Gas Hydrate Program Expedition 01 offshore India; gas hydrate systems as revealed by hydrocarbon gas geochemistry

Abstract The National Gas Hydrate Program Expedition 01 (NGHP-01) targeted gas hydrate accumulations offshore of the Indian Peninsula and along the Andaman convergent margin. The primary objectives of coring were to understand the geologic and geochemical controls on the accumulation of methane hydrate and their linkages to underlying petroleum systems. Four areas were investigated: 1) the Kerala-Konkan Basin in the eastern Arabian Sea, 2) the Mahanadi and 3) Krishna-Godavari Basins in the western Bay of Bengal, and 4) the Andaman forearc Basin in the Andaman Sea. Upward flux of methane at three of the four of the sites cored during NGHP-01 is apparent from the presence of seafloor mounds, seismic evidence for upward gas migration, shallow sub-seafloor geochemical evidence of methane oxidation, and near-seafloor gas composition that resembles gas from depth. The Kerala-Konkan Basin well contained only CO2 with no detectable hydrocarbons suggesting there is no gas hydrate system here. Gas and gas hydrate from the Krishna-Godavari Basin is mainly microbial methane with δ13C values ranging from −58.9 to −78.9‰, with small contributions from microbial ethane (−52.1‰) and CO2. Gas from the Mahanadi Basin was mainly methane with lower concentrations of C2-C5 hydrocarbons (C1/C2 ratios typically >1000) and CO2. Carbon isotopic compositions that ranged from −70.7 to −86.6‰ for methane and −62.9 to −63.7‰ for ethane are consistent with a microbial gas source; however deeper cores contained higher molecular weight hydrocarbon gases suggesting a small contribution from a thermogenic gas source. Gas composition in the Andaman Basin was mainly methane with lower concentrations of ethane to isopentane and CO2, C1/C2 ratios were mainly >1000 although deeper samples were

우리나라 가스 하이드레이트 연구･개발

Gas hydrate project in Korea was initiated by Korea Institute of Geoscience and Mineral Resources (KIGAM) in 1996. To understand the potential of gas hydrate presence in the Ulleung Basin, East Sea, KIGAM collected the geophysical data and sediment samples in the southwestern part of the basin from 1997 to 1999. Bottom simulating reflector firstly was identified from the seismic data acquired in 2008. Regional geophysical surveys and geological studies have been also carried out by KIGAM from 2000 to 2004. KNOC also collected seismic data from 2001 to 2003. Based on the results from these preliminary researches, “Korean National Gas Hydrate Program” was launched in 2005. The program has been supported by the government, and carried out by KIGAM, KNOC and KOGAS under the management of Gas Hydrate R&D Organization. The program has undertaken geophysical survey programs and coring for the identification of gas hydrate occurrences, the assessment of gas hydrate resources in the basin, development of optimum production technology, environmental impact studies, and test production. The gas hydrate test production which originally was planned to be performed in 2015, is postponed to study further for safer and more successful testing. Currently, the second national program is being planned.

Hydrate quantification: Integrating full-waveform inversion, seismic attributes, and rock physics

Hydrate quantification from seismic data is a two-pronged challenge. The first is creating a velocity field with high enough resolution and accuracy such that it is a meaningful representation of hydrate variability in the host sediments. The second is constructing a rock-physics model that accounts for the appropriate growth of the hydrate and allows for the interpretation of the velocity field in terms of hydrate saturation. In this paper, both challenges are addressed in a quantification workflow that uses 2D seismic and colocated well logs. The study area is situated in the Krishna-Godavari Basin, offshore eastern Indian coast, where hydrate was discovered in the National Gas Hydrate Program Expedition 01 (NGHP-01). The workflow hinges on a rock-physics model that expresses total hydrate saturation in terms of primary (matrix) and secondary (fractures, faults, voids, etc.) porosities and their respective primary and secondary saturations and incorporates hydrate-filled secondary porosity into the rock as an additional grain type using the Hashin-Shtrikman bounds. The model is first applied to a set of well logs at a colocated site, NGHP-01-10, following which the application is extended into the seismic domain by (1) the incoherency attribute as a proxy for secondary porosity and (2) a full-waveform inversion-based P-wave velocity ([Formula: see text]) model as a proxy for primary saturation. The remaining — the primary porosity and secondary saturation — are assumed to remain the same across the seismic profile as at the site NGHP-01-10. The resulting, seismically estimated, hydrate saturation compares well with saturations from core depressurization at colocated sites NGHP-01-10 and NGHP-01-13. The quantification workflow presented here is potentially adaptable to other geographical areas with the caveat that empirical relations between porosity, saturation, and seismic attributes may have to be locally established.

Composition and origin of authigenic carbonates in the Krishna–Godavari and Mahanadi Basins, eastern continental margin of India

The mineralogical and stable isotopic composition of authigenic carbonates from the Krishna–Godavari (KG) and Mahanadi Basin provide a deeper insight into the processes inducing carbonate formation in the sediments of the eastern continental margin of India in the Bay of Bengal. Authigenic carbonate cements, (micro) nodules, bioturbation casts and tubes from 12 core locations drilled during the Indian National Gas Hydrate Program (NGHP) Expedition 01 were investigated for this study. Three main processes responsible for authigenic carbonate precipitation are identified: organoclastic sulfate reduction, anaerobic oxidation of methane and methanogenesis. Evidence of vigorous methane seepage is indicated in carbonates recovered at Sites 7, 10, 12 (KG Basin) and 19 (Mahanadi Basin). These methane-derived carbonates display typical paragenetic carbonate mineralogies (aragonite, high-Mg calcite with >15 Mol% MgCO3, Ca-rich dolomite). Two separate horizons of methane derived-carbonates are correlated between 4 drill holes (up to ∼16 km apart). The upper horizon has been dated with 14C (40,100–51,600 a BP 1950) and clearly indicates that methane seepage has been much more vigorous in the past, possibly due to the effect of lower sea level on the gas hydrate stability zone across the margin.

Geologic implications of gas hydrates in the offshore of India: Krishna–Godavari Basin, Mahanadi Basin, Andaman Sea, Kerala–Konkan Basin

Gas hydrate resource assessments that indicate enormous global volumes of gas present within hydrate accumulations have been one of the primary driving forces behind the growing interest in gas hydrates. Gas hydrate volumetric estimates in recent years have focused on documenting the geologic parameters in the “gas hydrate petroleum system” that control the occurrence of gas hydrates in nature. The primary goals of this report are to review our present understanding of the geologic controls on the occurrence of gas hydrate in the offshore of India and to document the application of the petroleum system approach to the study of gas hydrates.National Gas Hydrate Program of India executed the National Gas Hydrate Program Expedition 01 (NGHP-01) in 2006 in four areas located on the eastern and western margins of the Indian Peninsula and in the Andaman Sea. These areas have experienced very different tectonic and depositional histories. The peninsular margins are passive continental margins resulting from a series of rifting episodes during the breakup and dispersion of Gondwanaland to form the present Indian Ocean. The Andaman Sea is bounded on its western side by a convergent margin where the Indian plate lithosphere is being subducted beneath southeast Asia.NGHP-01 drilled, logged, and/or cored 15 sites (31 holes) in the Krishna–Godavari Basin, 4 sites (5 holes) in the Mahanadi Basin, 1 site (2 holes) in the Andaman Sea, and 1 site (1 hole) in the Kerala–Konkan Basin. Holes were drilled using standard drilling methods for the purpose of logging-while-drilling and dedicated wireline logging; as well as through the use of a variety of standard coring systems and specialized pressure coring systems.NGHP-01 yielded evidence of gas hydrate from downhole log and core data obtained from all the sites in the Krishna–Godavari Basin, the Mahanadi Basin, and in the Andaman Sea. The site drilled in the Kerala–Konkan Basin during NGHP-01 did not yield any evidence of gas hydrate. Most of the downhole log-inferred gas hydrate and core-recovered gas hydrate were characterized as either fracture-filling in clay-dominated sediments or as pore-filling or grain-displacement particles disseminated in both fine- and coarse-grained sediments. Geochemical analyses of gases obtained from sediment cores recovered during NGHP-01 indicated that the gas in most all of the hydrates in the offshore of India is derived from microbial sources; only one site in the Andaman Sea exhibited limited evidence of a thermogenic gas source. The gas hydrate petroleum system concept has been used to effectively characterize the geologic controls on the occurrence of gas hydrates in the offshore of India.

Gas hydrate distribution and carbon sequestration through coupled microbial methanogenesis and silicate weathering in the Krishna–Godavari Basin, offshore India

The National Gas Hydrate Program Expedition 01 cored ten sites in the Krishna–Godavari basin, located on the southeastern margin of India. A comprehensive suite of pore water solute concentrations and isotope ratios were analyzed to investigate the distribution and concentration of gas hydrate along the margin, in situ diagenetic and metabolic reactions, and fluid migration and flow pathways. Gas hydrate was present at all of the sites cored, and in situ microbial methanogenesis leads to estimates of depth-integrated average gas hydrate saturations that are typically <5%. Deep-sourced fluid and gas migration produces gas hydrate saturations up to 68% along an isolated coarser-grained stratigraphic horizon at Site 15 and up to 41% within a fractured clay-dominated system at Site 10. Our results show that the CO2 produced through net microbial methanogenesis is effectively neutralized by silicate weathering throughout the sediment column drilled at each site (∼100–300 m), buffering the pore water pH and generating excess alkalinity via the same reaction sequence as continental silicate weathering. Most of the excess alkalinity produced by silicate weathering in the Krishna–Godavari basin is sequestered in Ca- and Fe-carbonates as a result of ubiquitous calcium release from weathering detrital silicates and dissolved Fe production within the methanogenic sediments. Formation of secondary hydrous silicates (e.g. smectite) related to incongruent primary silicate dissolution acts as a significant sink for pore water Mg, K, Li, Rb, and B. The consumption of methane through anaerobic oxidation of methane, sequestration of methane in gas hydrate, and sequestration of dissolved inorganic carbon in authigenic carbonates keeps methanogenesis as a thermodynamically feasible catabolic pathway. Our results combined with previous indications of silicate weathering in anoxic sediments in the Sea of Okhotsk, suggest that silicate weathering coupled to microbial methanogenesis should be occurring in continental margins worldwide, providing a net sink of atmospheric CO2.