Geology topics

Jun Yoneda

Publications and source records attributed to Jun Yoneda.

18 recordsLinked to original sources

USGS2026

Production of secondary microbial methane from a gas hydrate-bearing reservoir at the HYDRATE P1 Production Test Well (PTW-1) on the Alaskan North Slope

Gas hydrate in the Alaskan North Slope (ANS) is believed to contain as much methane as the known conventional gas accumulations in the Prudhoe Bay field. The JOGMEC-DOE-USGS Collaborative Gas Hydrate R&D Project conducted an extended-duration production test from the sub-permafrost, gas-hydrate saturated B1 sand reservoir (unit B) at the Kuparuk State 7-11-12 Site in the Prudhoe Bay Unit of the ANS. Using compositional and stable isotopic data measured on gas produced from well cuttings and pressure cores collected from the HYDRATE 02 Geo Data Well (GDW), we differentiate primary microbial, secondary microbial, and trace thermogenic gas sources. The upper part of the well contained predominantly primary microbial methane from near the surface to the SV6 stratigraphic horizon at 1133 ft (345.3 m) measured depth (MD). Below that, the gas composition transitioned to a mixture of mostly primary and secondary microbial methane to near the base of ice-bearing permafrost at 1968 ft (599.8 m) MD. With greater depth to 3558 ft (1084.5 m) MD, which includes the D1 sand (unit D), the B1 sand (unit B), and the base of gas hydrate stability at 3113 ft (948.8 m) MD, the gas composition was greater than 98% secondary microbial methane with the remainder being oil-associated thermogenic gas migrated from the deep Sadlerochit Formation. The unit B vertical gas profile derived from degassed pressure cores demonstrated that gas dissolved in the clay-rich sediment intervals bounding the B1 sand reservoir was distinct from dissolved and hydrate-caged gases in the sand-rich hydrate-bearing reservoir. The HYDRATE P1 Production Test Well (PTW-1) targeted and successfully extracted gas dissociated from hydrate gas in the B1 sand for 151 days when using an electrical submersible pump to depressurize the reservoir with subsequent depressurization achieved through the use of a jet pump. Gas produced from PTW-1 was mostly indistinguishable from the gas compositional profile measured through the B1 sand and generally distinct from dissolved gas in the bounding clay-rich sediments, confirming that the upper and lower bounding units limited infiltration into the reservoir during production. Isolation of the bounding units from the reservoir contributed to the unexpectedly high ratio of production gas to water observed during the extended-duration gas hydrate production test at PTW-1.

Alaska↗

USGS2026

Depositional environment and diagenetic history of gas hydrate-bearing sediments of the Alaska North Slope (HYDRATE 02 Geo Data Well)

We characterized the lithological, solid-phase geochemical, and rock magnetic properties of sediment cores from subpermafrost strata on the Alaska North Slope collected as part of the U.S. Department of Energy (DOE), the Japan Organization for Metals and Energy Security (JOGMEC), and the U.S. Geological Survey (USGS) Collaborative Gas Hydrate Research and Development (R&D) Project in Alaska. Pressure cores were recovered from the HYDRATE 02 Geo Data Well (GDW) at the Kuparuk State 7-11-12 site through two hydrate-bearing sand reservoirs, the B1 and D1 sands, and their finer-grained bounding sediments. Both the B1 and D1 sands are quartz-rich, chert-bearing, very fine litharenite sands. These submature to immature sands are poorly to moderately sorted and angular with local fine-scale cross-stratification. The B1 sand has larger grains and a lower clay content as compared to the D1 sand. These sands are the upper portions of upward coarsening progradational sequences. The clay- and silt-rich bounding muds exhibit fine-scale wavy and lenticular laminations, suggesting episodic high energy deposition events. Overall, these sediments were deposited in a shoreface to nearshore marine environment during the Paleogene, modulated by changing depositional energy associated with sea level variation. Organic matter δ 13 C and C/N composition of these sediments indicate a source mixture of land plants and freshwater plankton, with possible minor presence of oil within the B1 sand. These sediments contain high and variable total sulfur (TS) content, suggesting porewater conditions influenced by variable salinity over time. Rock magnetic analyses indicate precipitation of greigite in the mud beneath the D1 sand, in the basal C shale overlying the B1 sand, and the mud beneath the B1 sand, likely due to intervals of sulfate limitation during periods of lower Arctic Ocean salinity. Based on pyrite abundance, TS, and δ 34 S-TS composition, the D1 sand and bounding sediments experienced more substantial sulfide precipitation. The unit E basal shale overlying the D1 sand contains a 0.25 m thick pyrite-dominant sand, indicating local bottom water anoxic conditions. X-ray fluorescence scanning and discrete measurements provide additional supporting interpretation of the depositional and diagenetic processes that have occurred at this site and track the relative amount of drilling fluid contamination with barium abundance in the core samples.

Alaska↗

USGS2026

Permeability and compressibility of “seal” sediment overlying the B1 sand gas hydrate reservoir: Hydrate 02 Geo Data Well, Prudhoe Bay unit, Alaska North Slope

An important element in evaluating the viability of extracting methane from a gas hydrate-bearing reservoir is establishing the effectiveness of the overlying bounding sediment as a seal to prevent gas loss, to enable effective depressurization, and to prevent fluid from entering the reservoir during production. This laboratory study presents results for index properties (e.g., grain density, grain size, and liquid limit), compressibility and swelling indices, and permeability measurements on sediment overlying the gas hydrate-bearing reservoir that was the target of the recent JOGMEC-DOE-USGS collaborative gas hydrate production testing project on the Alaska North Slope (ANS). Sediment analyzed in this study was collected during pressure coring operations in the HYDRATE 02 Geo Data Well (GDW). The ∼6.1 m sediment interval recovered in Cores 13P and 14P (878.74–884.88 m measured depth, MD) exhibited heterogeneous sedimentologic characteristics at the centimeter scale, with sediments ranging from clay to thin silty-sand lithologies. Permeability measurements and index-property correlations indicate the interval’s overall in situ vertical permeability ranges from 0.2 to 3.6 microdarcy (μD). Results for compressibility ( C C = 0.255 ± 0.02) and swelling index ( C S = 0.04 ± 0.01) are consistent with estimates based on mineralogy and liquid limit correlations. Based on the measured compressibility, the ∼3 MPa increase in effective stress during the stable phase of depressurization-induced production is anticipated to have imposed 2.43 cm of compaction per meter in the reservoir overburden, reducing permeability by ∼36%. The overburden sediment’s low in situ permeability (3 to 4 orders of magnitude below permeabilities measured in the gas hydrate-bearing part of the B1 sand (unit B)) suggests the B1 sand′s overburden provides an effective seal. Such a seal promotes efficient production by limiting fluid flow into the reservoir during depressurization-induced gas hydrate dissociation.

Alaska↗

USGS2026

Strength, stiffness, and Poisson’s ratio measurements for cements used in the well completions for the extended-duration gas production test on the Alaskan North Slope

As part of an extended-duration production test from a natural gas hydrate reservoir on the Alaska North Slope, a suite of optical-fiber sensors was encased in the completion cement to provide stable downhole monitoring around each of the four project wells. How the sensors respond to changes in the reservoir over time depends in part on properties of the LiteCRETE, ArcticCem, or Tuned Light cement in which each sensor is encased, and on how well the cement bonded to the well casing, sensors, and sediment formation. Here, we report on physical properties of the cements (compressive and tensile strength, stiffness, and Poisson’s ratio), on the downhole distribution of the cements used in each well, and on the cement bond quality. Physical property measurements are presented for cements sampled during the completion activities for the three wells completed in 2022–2023. Samples were cured while being submerged in water at 2–4 °C, then tested at intervals from ∼30 days to more than one year. After an initial period of rapid increase, cement strengths largely stabilized around 120 days in all cases, meaning that cements in all wells reached their nominal strength plateau four months or more before the production test began. Calculations based on recorded volumes of pumped cement show the subpermafrost, main hole portion of each well is encased only in the higher-density “tail” cement used in that well. Downhole cement evaluation logs from two wells demonstrate how the presence of sensors and other hardware outside the casing interferes with the cement evaluation assessment. Nonetheless, the cement evaluations indicate a generally good bond with the formation and sensors over the gas hydrate reservoir intervals.

Alaska↗

USGS2026

Lithological control of gas hydrate saturation determined by pressure core analysis in sub-permafrost reservoirs of the Alaska North Slope (HYDRATE 02 Geo Data Well)

Quantitatively degassing pressure cores by controlled depressurization is a key approach to characterizing gas hydrate reservoirs by measuring the gas hydrate saturation (S h ) of sediments. We measured S h for 53 core sections from the Alaska North Slope during the JOGMEC-DOE-USGS Collaborative Gas Hydrate R&D Project in Alaska, from subpermafrost sediments that were later subjected to an extended-duration gas production test. We characterized lithologic influences on S h using physical property core scans (P-wave velocity, gamma ray attenuation density, and X-ray computed tomography) and grain size measurements. Pressure cores were recovered from the Hydrate-02 Geo Data Well (GDW) at the Kuparuk State 7-11-12 site through two hydrate-bearing sand reservoirs, the B1 and D1 sands, and their finer-grained bounding sediments. S h reaches very high values (68 to 91% of the pore space) in silty fine sands within the B1 sand, which also contains two lower P-wave velocity intervals (one measured at 30% S h ) within the main reservoir. S h and grain sizes of the B1 sand are generally higher than the D1 sand, which hosts high S h (53 to 73%) within its sandy silt to silty fine sands. The heterogeneous silty clay to silt “seal” sediments directly overlying both reservoirs have low S h (0 to 13%) even in thin, coarser beds, suggesting minimal methane transport between the reservoir and seal. S h decreases with depth downward toward the base of both the D1 and B1 sands, corresponding to decreasing grain size. These transitions are underlain by silty clay to clayey silt sediments with low S h (<10%), similar to the seal sediments. Slow depressurization was used to estimate a brackish salinity based on the pressure and temperature of the onset of hydrate dissociation for two core sections within the B1 sand. We show that S h increases with median grain size, sand content, and porosity but exhibits some variation within the sand beds that is not directly explained by lithology.

Alaska↗

USGS2022

Scientific results of the Hydrate-01 Stratigraphic Test Well Program, Western Prudhoe Bay Unit, Alaska North Slope

The United States Department of Energy, the MH21-S Research Consortium of Japan, and the United States Geological Survey are collaborating to enable gas hydrate scientific drilling and extended-duration reservoir response testing on the Alaska North Slope. To feasibly execute such a test, a location is required that is accessible from existing roads and gravel pads and that can be occupied without disrupting ongoing industry operations. A review of potential locations meeting these criteria determined the likely occurrence of gas hydrate in two fine-grained marginal-marine sands of Tertiary age in the vicinity of the inactive “Kuparuk State 7-11-12” exploration pad in the western Prudhoe Bay Unit (PBU). Existing well and seismic data for that site were insufficient to preclude the potential for free gas occurrence within the deeper (and most prospective) target sand. Therefore, with support from the PBU Working Interest Owners, Alaska Department of Natural Resources, and Petrotechnical Resources Alaska, the Hydrate-01 Stratigraphic Test Well (STW) was drilled in December 2018 to confirm the suitability of the site for future gas hydrate scientific testing. The Hydrate-01 well was successfully drilled to −3290 ft (1003 m) subsea vertical depth at a bottom hole location of approximately 900 ft (∼275 m) east of the surface location. The drilling program featured acquisition of a full suite of logging while drilling data, the collection of side-wall pressure cores, and the installation of distributed temperature and distributed acoustic sensor fiber-optic cables. The log data acquired confirmed the occurrence of gas hydrate at high saturation in two target sands. Integrated evaluation of log and sidewall core data provide petrophysical and geomechanical property information that allow for potential reservoir response to depressurization to be simulated. The deeper “B1 sand” is deemed to be most favorable for reservoir response testing as a result of confirmed gas hydrate occurrence in sediments of high intrinsic permeability, location within 100 ft (30 m) of the base of gas hydrate stability, and minimal risk for direct communication with permeable water-bearing (hydrate-free) zones. The shallower “D1 sand” provides a secondary target that is differentiated by colder in situ temperatures and the interpreted direct hydraulic communication to a lower section of non-hydrate-bearing, water-saturated sand. The Hydrate-01 log data also confirm the occurrence of at least one sub-seismic fault in close proximity to the B1 sand reservoir. To better image the distribution of the gas-hydrate-bearing reservoir sections and associated faults, a three-dimensional (3D) vertical seismic profile was conducted in early 2019 using the distributed acoustic sensors installed as part of the Hydrate-01 STW completion. Detailed two-dimensional (2D) and 3D geologic models have been constructed to enable numerical simulations to inform the planning for potential future scientific tests of reservoir response to depressurization at the site.

Alaska↗

USGS2022

Gas hydrate saturation estimates, gas hydrate occurrence, and reservoir characteristics based on well log data from the hydrate-01 stratigraphic test well, Alaska North Slope

The Hydrate-01 Stratigraphic Test Well was drilled at the Kuparuk 7-11-12 site on the Alaska North Slope in December 2018. Sonic log data provide compressional (P) and shear (S) slowness from which we determine gas hydrate saturation ( S gh ) estimates using effective medium theory. The sonic S gh estimates compare favorably with S gh estimated from resistivity and nuclear magnetic resonance (NMR) logs, showing that gas hydrate occupies up to approximately 90% of the pore space in the target reservoir sands. The informally named B1 sand (2294 feet below mean sea level) shows lower V P / V S ratios than the D1 sand (2770 feet below mean sea level), with the lower part of the B1 sand showing lower V P / V S ratios than the upper part of the B1 sand. This corresponds to a stiffer, or more “cemented”, behavior for the lower B1 sand and less cemented behavior for the D1 sand. This trend could be due to differences in the reservoirs themselves or in the gas hydrate morphology or to both factors. We observe that the presence of gas hydrate in the upper B1 sand has greater impact on hydraulic permeability (measurements suggest a greater difference between intrinsic and effective permeability) than in the D1 sand, possibly related to gas hydrate morphology but more likely due simply to higher gas hydrate saturations in the upper B1 sand. Analyses of S gh relative to porosity, shale fraction, and intrinsic permeability show that reservoir quality (as represented by these three metrics) exerts control on gas hydrate saturation. Grain size and mineralogy data show somewhat smaller grains and better sorting in the D1 reservoir relative to the upper B1 reservoir and smaller grains and greater clay fraction in the lower B1 reservoir relative to the other two reservoir zones. Together, these data suggest that reservoir characteristics play a role in the observed V P / V S patterns, but gas hydrate morphology (possibly varying with saturation) must also be considered.

Alaska↗

USGS2022

Permeability measurement and prediction with nuclear magnetic resonance analysis of gas hydrate-bearing sediments recovered from Alaska North Slope 2018 Hydrate-01 Stratigraphic Test Well

Permeability of porous media, such as oil and gas reservoirs, is the crucial material parameter for predicting their hydraulic behavior. A nuclear magnetic resonance (NMR) analyzer is widely used as a powerful tool to predict permeability of various media. NMR T 2 (transverse or spin–spin) relaxation time distribution, which is related to pore size distribution, gives the information to allow calculation of effective (initial) permeability. In this study, we investigate effective, intrinsic (absolute), and relative water and gas permeabilities of hydrate-bearing pressure core samples. These samples were recovered from the Alaska North Slope 2018 Hydrate-01 Stratigraphic Test Well by sidewall pressure coring and then analyzed in a laboratory using both fluid flow test and NMR analyzer. The peak of the NMR T 2 distribution was measured at 10–20 ms using a laboratory NMR analyzer, which compares well with in situ measurements obtained via logging while drilling NMR data for two samples with high gas hydrate saturations ( S h = 76% and 74%). Further, comparison of laboratory NMR T 2 distribution after hydrate dissociation revealed that the hydrate existed in large pore spaces. Effective permeabilities predicted by the Timur-Coates (TC) model and the Schlumberger-Doll-Research (SDR) model, with T 2 cutoff 33 ms, were about an order of magnitude less than the laboratory measured values. Alternative TC model-based calculations with the T 2 cutoff reduced to 10 ms and a newly developed hydraulic radius model better matched the laboratory data. For the analysis of the intrinsic permeabilities, the TC model with a T 2 cutoff of 33 ms and SDR model were greater than the laboratory derived values, while the hydraulic radius model more closely matched the laboratory-derived values. In addition, permeability measurements were also made relative to gas and water under constant three-phase flow (water–gas–hydrate) conditions. After hydrate dissociation, a relative permeability curve was developed for each of the analyzed core samples based on the Corey petrophysical model. The results indicate that the gas permeability changed rapidly at high water saturation around 90%. Thus, we infer that the selection of relative reservoir parameters should focus on the higher water saturation conditions.

Alaska↗

USGS2022

Comprehensive pressure core analysis for hydrate-bearing sediments from Gulf of Mexico Green Canyon Block 955, including assessments of geomechanical viscous behavior and nuclear magnetic resonance permeability

Quantifying the petrophysical and geomechanical properties of gas hydrate reservoirs is essential for understanding the natural hydrate system and predicting gas production behavior for future resource development. Pressure-core analysis tools were used to characterize methane hydrate–bearing sediments recovered from the Gulf of Mexico Green Canyon Block 955, under an international collaboration with The University of Texas and the National Institute of Advanced Industrial Science and Technology. Pressure-core samples were successfully transferred from Austin, Texas to Sapporo, Japan. Index property measurements (grain size, grain density, hydration number, gas composition, thermal conductivity), along with triaxial compression, consolidation, and permeability tests with a nuclear magnetic resonance (NMR) analyzer were conducted. Compression tests at different strain rates confirmed a strain rate dependence for hydrate-bearing sediment, and an equation for predicting strength as a function of hydrate saturation and strain rate is proposed. Compression and swelling indices were obtained from high-effective stress consolidation tests. Furthermore, secondary compression coefficients for hydrate-bearing sediments were obtained, suggesting that hydrate exhibits creeping behavior on timescales of minutes to hours. A relatively high initial permeability of a few millidarcys was confirmed. In addition, the first NMR signal measurement was performed on a hydrate-bearing pressure core to acquire the NMR transverse or spin-spin ( T 2 ) distribution. Results confirm that the Schlumberger Doll Research model and Timur-Coates model predictions underestimate permeability measured directly via fluid flow. Permeability estimated using specific surface values derived from NMR T 2 distributions is in good agreement with flow test results. Finally, an extended Timur-Coates model was proposed and predicts intrinsic permeability with high accuracy.

Texas↗

USGS2021

Multiple physical properties of gas hydrate-bearing sediments recovered from Alaska North Slope 2018 Hydrate-01 Stratigraphic Test Well

Knowledge of the petrophysical and geomechanical properties of gas hydrate-bearing sediments is essential for predicting reservoir responses to gas production from gas hydrate reservoirs. In December 2018, Stratigraphic Test Well Hydrate-01 was drilled in the western part of the Prudhoe Bay Unit, Alaska North Slope, as part of the technical planning effort for a future long-term gas hydrate production test. Side-wall pressure coring was conducted to recover gas hydrate-bearing sediments from two reservoir sections named Unit B and Unit D. A total of 34 cores were successfully recovered during five runs of a wireline deployed pressure corer, and a total of 17 cores were preserved for advanced laboratory analysis. The samples were frozen inside the pressure core autoclave by liquid nitrogen while at high pressure before being removed and stored under liquid nitrogen at atmospheric pressure. High-resolution X-ray computed tomography showed the samples were high-quality, with undisturbed lithological layers. The Unit B and D sediments were categorized as sand or sandy silt with high hydrate saturation. Gas compositions suggest the hydrates formed with thermogenic and microbial mixed gases. Permeability tests and triaxial compression tests were conducted on the hydrate-bearing sediments. Low strengthening and high permeability at hydrate saturation S h > 80% were observed. There was a small permeability reduction during the triaxial compression tests owing to porosity loss with increasing effective stress in the highly permeable sandy sediment after hydrate dissociation. The apparent minimal changes in porosity and permeability during the tests were due to the low-clay content and low compressibility of the quartz sand grains in the recovered cores. X-ray powder diffraction and thermal conductivity analysis also suggested a high quartz content for the analyzed samples.

Alaska↗

USGS2020

Petrophysical and geomechanical properties of gas hydrate-bearing sediments recovered from Alaska North Slope 2018 Hydrate-01 Stratigraphic Test Well

Knowledge of petrophysical and geomechanical properties of gas hydrate-bearing sediments are essential for predicting reservoir responses to gas production. The same information is also needed for the designing of production well completions such as specifications for artificial lift, test site water storage capacity, and mesh size for the sand control systems. In December 2018, the Stratigraphic Test Well Hydrate-01 was drilled in the western part of the Prudhoe Bay Unit on the Alaska North Slope as part of the technical planning effort for a future long-term production test being planned and led by a collaborative team from the U.S. Department of Energy - National Energy Technology Laboratory (DOE-NETL), U.S. Geological Survey (USGS), and Japan’s Research and Development Consortium for Pore Filling Hydrate in Sand (MH21-S) (Boswell et al., 2020, Collett et al., 2020, Okinaka et al., 2020). Logging-while-drilling (LWD) data were acquired (Haines et al., 2020, Suzuki et al., 2019) and sidewall core sampling depths were selected from the LWD logs. Sidewall pressure coring was conducted to recover gas hydrate-bearing sediments from two reservoir sections named Unit B and Unit D. A total of 34 cores were successfully recovered by 5 runs of a wireline deployed pressure coring system (CoreVault® System - Halliburton). The core analysis plan for this project is shown in Figure 1. Upon recovery, the pressure core autoclaves were transported from the Alaska North Slope to the Stratum Reservoir laboratory in Anchorage Alaska. To access the cores, they were first quenched in liquid nitrogen while still at high pressure in the core system autoclaves (Figure 1a). The cores were next removed from the pressure corer autoclaves with temperature control support from dry ice and stored under liquid nitrogen at atmospheric pressure. A total of 19 disturbed low-quality cores were processed for index property measurements, which included grain size and grain density analysis. Another 4 core samples were depressurized, trimmed, and core plugs were cut from each core and used to measure intrinsic permeabilities of host sediments (Figure 1). Unsteady-state permeability measurements were conducted on two samples to obtain relative water permeability (Rel.-Perm.) to gas and core scale Nuclear Magnetic Resonance (NMR) transverse relaxation time (T2) distribution measurements were performed to evaluate pore size distribution (Figure 1b). A total of 13 remaining high-quality cores with significant gas hydrate concentrations were preserved for advanced laboratory analysis. The National Institute of Advanced Industrial Science and Technology, as a part of the Japanese National Hydrate Research Program (MH21-S, funded by Ministry of Economy, Trade and Industry), received the 13 remaining high-quality core samples at their laboratories in Sapporo, Japan for advanced core analysis. High-resolution X-ray computed tomography (CT) was used to analyze the physical characteristics of the samples, which showed for the most part undisturbed lithological layers. Cores were lathed into cylindrical shapes and prepared for multi property measurements (Figure 1c). As a result, sediment from Unit D was characterized as silty-sand at ~37% porosity with ~80% gas hydrate saturation. An average hydration number n = 6.16 was measured for the recovered gas hydrate samples by Raman spectroscopy. An average intrinsic permeability of ~400 mD and in situ effective permeability (with hydrate) on the order of ~10 mD was measured for a total of five core samples. The Unit B recovered cores consisted of well sorted sand at ~40% porosity with ~95% gas hydrate saturation. An average intrinsic permeability of ~1 Darcy and in situ effective permeability on the order of ~30 mD was measured for the Unit B cores. Additional laboratory measurements yielded small permeability reductions due to porosity loss with increasing effective stress that simulated sediment consolidation along with depressurization in the highly permeable sandy sediment. The apparent limited change in porosity and permeability may be caused by the low compressibility of quartz sand grains in the recovered cores. X-ray diffraction (XRD) and thermal conductivity analysis also indicated a high quartz content within the recovered cores. Completed triaxial compression tests established internal friction angles based on the Mohr-Coulomb's failure criterion, which were calculated at 40° for hydrate-bearing sediment and 29.8° for hydrate free sediment.

Alaska↗

USGS2020

Alaska North Slope 2018 Hydrate-01 Stratigraphic Test Well: Technical results

The Hydrate-01 Stratigraphic Test Well was drilled in December 2018 to confirm that a seismically-identified location within the western Prudhoe Bay Unit might be suitable for extended-duration scientific production testing. The well tested two primary targets: the deeper Unit B is highly favorable due to optimal reservoir temperature and minimal observed risk for direct communication with permeable, hydrate-free water-bearing zones. The shallower Unit D provides a secondary target and opportunity to assess additional scientific and operational issues.

Alaska↗

USGS2019

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

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, which can simulate the in-situ 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, 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.

Krishna–Godavari Basin↗

USGS2019

Pressure core analysis of geomechanical and fluid flow properties of seals associated with gas hydrate-bearing reservoirs in the Krishna-Godavari Basin, offshore India

Physical properties of the sediment directly overlying a gas hydrate reservoir provide important controls on the effectiveness of depressurizing that reservoir to extract methane from gas hydrate as an energy resource. The permeability of overlying sediment determines if a gas hydrate reservoir’s upper contact will provide an effective seal that enables efficient reservoir depressurization. Compressibility, stiffness and strength indicate how overlying sediment will deform as the in situ stress changes during production, providing engineering data for well designs. Assessing these properties requires minimally-disturbed sediment. India’s National Gas Hydrates Program Expedition 2 (NGHP-02) provided an opportunity to study these seal sediment properties, reducing disturbance from gas exsolution and bubble growth by collecting a pressure core from the seal sediment just above the primary gas hydrate reservoir at Site NGHP-02-08 in Area C of the Krishna-Godavari Basin. The effective stress chamber (ESC) and the direct shear chamber (DSC) devices in the suite of Pressure Core Characterization Tools (PCCTs) were used to measure permeability, compressibility, stiffness and shear strength at the in situ vertical stress. Geotechnical properties of the predominantly fine-grained seal layer at in situ vertical stress are in typical clay sediment ranges, with low measured permeability (0.02 mD), high compressibility (Cc = 0.26 – 0.33) and low shear strength (404 kPa). Though pressure and temperature were maintained throughout the collection and measurement process to stabilize gas hydrate, the lack of effective stress in the pressure core storage chamber and the chamber pressurization with methane-free water caused core expansion and gas hydrate in a thin coarser-grained layer to dissolve. The PCCTs can reapply in situ stress with incremental loading steps during a consolidation test to account for sediment compaction. Gas hydrate dissolution can be limited by storing cores just above freezing temperatures, and by using solid spacers to reduce the storage chamber’s free volume.

Marine and Petroleum Geology↗

USGS2019

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, ~ 2MPa, 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 score 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. Hydrates in sediment increase the gas-entry pressure and residual water saturation, but decrease 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.

Journal of Marine and Petroleum Geology↗

USGS2019

Pressure core based onshore laboratory analysis on mechanical properties of hydrate-bearing sediments recovered during India's National Gas Hydrate Program Expedition (NGHP) 02

A solid understanding of the mechanical properties of hydrate-bearing sediments is essential for the safe and economic development of methane hydrate as an energy resource. In 2015, 104 pressure cores were collected, recovering sediments from above and within concentrated hydrate reservoirs in the Krishna-Godavari Basin, as part of India’s National Gas Hydrate Program Expedition 02 (NGHP-02). These cores provided minimally-disturbed sediment, retained at pressures and temperatures within the hydrate stability field, for the first-ever systematic triaxial test of dozens of subsections of hydrate-bearing pressure core sediments. Post-cruise testing in Japan, evaluated multiple physical and hydro-mechanical properties. Consolidated drained and undrained triaxial compression tests, uniaxial (unconfined in effective stress) compression tests, multistage consolidation and compression tests, and alternating strain-rate compression tests were also performed. Triaxial compression test results showed an increase in the strength and stiffness, as well as the positive dilatancy, with increasing hydrate saturation, supporting previous research on laboratory-formed and natural hydrate-bearing sediments. However, some strength results in this study were low compared to prior analyses of hydrate-bearing sediments. This low strength was likely caused by the host sediment’s small particle size and loose packing, and the relatively slow applied compression strain rate. Results from uniaxial compression and multi-step compression tests confirmed that pore-space hydrates produce an apparent cohesion in hydrate-bearing sediment. More severe strength loss in sediments during the initial loading for multistage compression was also attributable to the presence of hydrates. The applicability of this multistage compression test for determining in situ properties was not confirmed, but results do provide bounds on the in situ values. Finally, from the variable strain-rate tests, it was revealed that strength in hydrate-bearing sediment has a large strain-rate dependence.

Marine and Petroleum Geology↗

USGS2019

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

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

Journal of Marine and Petroleum Geology↗

USGS2015

Hydro-bio-geomechanical properties of hydrate-bearing sediments from Nankai Trough

Natural hydrate-bearing sediments from the Nankai Trough, offshore Japan, were studied using the Pressure Core Characterization Tools (PCCTs) to obtain geomechanical, hydrological, electrical, and biological properties under in situ pressure, temperature, and restored effective stress conditions. Measurement results, combined with index-property data and analytical physics-based models, provide unique insight into hydrate-bearing sediments in situ. Tested cores contain some silty-sands, but are predominantly sandy- and clayey-silts. Hydrate saturations S h range from 0.15 to 0.74, with significant concentrations in the silty-sands. Wave velocity and flexible-wall permeameter measurements on never-depressurized pressure-core sediments suggest hydrates in the coarser-grained zones, the silty-sands where S h exceeds 0.4, contribute to soil-skeletal stability and are load-bearing. In the sandy- and clayey-silts, where S h < 0.4, the state of effective stress and stress history are significant factors determining sediment stiffness. Controlled depressurization tests show that hydrate dissociation occurs too quickly to maintain thermodynamic equilibrium, and pressure–temperature conditions track the hydrate stability boundary in pure-water, rather than that in seawater, in spite of both the in situ pore water and the water used to maintain specimen pore pressure prior to dissociation being saline. Hydrate dissociation accompanied with fines migration caused up to 2.4% vertical strain contraction. The first-ever direct shear measurements on never-depressurized pressure-core specimens show hydrate-bearing sediments have higher sediment strength and peak friction angle than post-dissociation sediments, but the residual friction angle remains the same in both cases. Permeability measurements made before and after hydrate dissociation demonstrate that water permeability increases after dissociation, but the gain is limited by the transition from hydrate saturation before dissociation to gas saturation after dissociation. In a proof-of-concept study, sediment microbial communities were successfully extracted and stored under high-pressure, anoxic conditions. Depressurized samples of these extractions were incubated in air, where microbes exhibited temperature-dependent growth rates.

Journal of Marine and Petroleum Geology↗