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At least 883 records · Page 49Linked to original sources
USGS2011

Downhole well log and core montages from the Mount Elbert Gas Hydrate Stratigraphic Test Well, Alaska North Slope

The BPXA-DOE-USGS Mount Elbert Gas Hydrate Stratigraphic Test Well was an integral part of an ongoing project to determine the future energy resource potential of gas hydrates on the Alaska North Slope. As part of this effort, the Mount Elbert well included an advanced downhole geophysical logging program. Because gas hydrate is unstable at ground surface pressure and temperature conditions, a major emphasis was placed on the downhole-logging program to determine the occurrence of gas hydrates and the in-situ physical properties of the sediments. In support of this effort, well-log and core data montages have been compiled which include downhole log and core-data obtained from the gas-hydrate-bearing sedimentary section in the Mount Elbert well. Also shown are numerous reservoir parameters, including gas-hydrate saturation and sediment porosity log traces calculated from available downhole well log and core data.

Alaska↗
USGS2010

Seismic imaging of a fractured gas hydrate system in the Krishna-Godavari Basin offshore India

Gas hydrate was discovered in the Krishna-Godavari (KG) Basin during the India National Gas Hydrate Program (NGHP) Expedition 1 at Site NGHP-01-10 within a fractured clay-dominated sedimentary system. Logging-while-drilling (LWD), coring, and wire-line logging confirmed gas hydrate dominantly in fractures at four borehole sites spanning a 500m transect. Three-dimensional (3D) seismic data were subsequently used to image the fractured system and explain the occurrence of gas hydrate associated with the fractures. A system of two fault-sets was identified, part of a typical passive margin tectonic setting. The LWD-derived fracture network at Hole NGHP-01-10A is to some extent seen in the seismic data and was mapped using seismic coherency attributes. The fractured system around Site NGHP-01-10 extends over a triangular-shaped area of ~2.5 km2 defined using seismic attributes of the seafloor reflection, as well as " seismic sweetness" at the base of the gas hydrate occurrence zone. The triangular shaped area is also showing a polygonal (nearly hexagonal) fault pattern, distinct from other more rectangular fault patterns observed in the study area. The occurrence of gas hydrate at Site NGHP-01-10 is the result of a specific combination of tectonic fault orientations and the abundance of free gas migration from a deeper gas source. The triangular-shaped area of enriched gas hydrate occurrence is bound by two faults acting as migration conduits. Additionally, the fault-associated sediment deformation provides a possible migration pathway for the free gas from the deeper gas source into the gas hydrate stability zone. It is proposed that there are additional locations in the KG Basin with possible gas hydrate accumulation of similar tectonic conditions, and one such location was identified from the 3D seismic data ~6 km NW of Site NGHP-01-10. ?? 2010.

Marine and Petroleum Geology↗
USGS2012

Anisotropic models to account for large borehole washouts to estimate gas hydrate saturations in the Gulf of Mexico Gas Hydrate Joint Industry Project Leg II Alaminos 21 B well

Through the use of 3-D seismic amplitude mapping, several gashydrate prospects were identified in the Alaminos Canyon (AC) area of the Gulf of Mexico. Two locations were drilled as part of the Gulf of MexicoGasHydrate Joint Industry Project Leg II (JIP Leg II) in May of 2009 and a comprehensive set of logging-while-drilling (LWD) logs were acquired at each well site. LWD logs indicated that resistivity in the range of ~2 ohm-m and P-wave velocity in the range of ~1.9 km/s were measured in the target sand interval between 515 and 645 feet below sea floor. These values were slightly elevated relative to those measured in the sediment above and below the target sand. However, the initial well log analysis was inconclusive regarding the presence of gashydrate in the logged sand interval, mainly because largewashouts caused by drilling in the target interval degraded confidence in the well log measurements. To assess gashydratesaturations in the sedimentary section drilled in the Alaminos Canyon 21B (AC21-B) well, a method of compensating for the effect of washouts on the resistivity and acoustic velocities was developed. The proposed method models the washed-out portion of the borehole as a vertical layer filled with sea water (drilling fluid) and the apparent anisotropic resistivity and velocities caused by a vertical layer are used to correct the measured log values. By incorporating the conventional marine seismic data into the well log analysis, the average gashydratesaturation in the target sand section in the AC21-Bwell can be constrained to the range of 8–28%, with 20% being our best estimate.

Gulf Of Mexico;Alaminos Canyon↗
USGS2011

Gas hydrate saturation from acoustic impedance and resistivity logs in the Shenhu area, south China Sea

During the China’s first gas hydrate drilling expedition -1 (GMGS-1), gas hydrate was discovered in layers ranging from 10 to 25 m above the base of gas hydrate stability zone in the Shenhu area, South China Sea. Water chemistry, electrical resistivity logs, and acoustic impedance were used to estimate gas hydrate saturations. Gas hydrate saturations estimated from the chloride concentrations range from 0 to 43% of the pore space. The higher gas hydrate saturations were present in the depth from 152 to 177 m at site SH7 and from 190 to 225 m at site SH2, respectively. Gas hydrate saturations estimated from the resistivity using Archie equation have similar trends to those from chloride concentrations. To examine the variability of gas hydrate saturations away from the wells, acoustic impedances calculated from the 3 D seismic data using constrained sparse inversion method were used. Well logs acquired at site SH7 were incorporated into the inversion by establishing a relation between the water-filled porosity, calculated using gas hydrate saturations estimated from the resistivity logs, and the acoustic impedance, calculated from density and velocity logs. Gas hydrate saturations estimated from acoustic impedance of seismic data are ∼10–23% of the pore space and are comparable to those estimated from the well logs. The uncertainties in estimated gas hydrate saturations from seismic acoustic impedances were mainly from uncertainties associated with inverted acoustic impedance, the empirical relation between the water-filled porosities and acoustic impedances, and assumed background resistivity.

Marine and Petroleum Geology↗
USGS2012

Pore- and fracture-filling gas hydrate reservoirs in the Gulf of Mexico Gas Hydrate Joint Industry Project Leg II Green Canyon 955 H well

High-quality logging-while-drilling (LWD) downhole logs were acquired in seven wells drilled during the Gulf of MexicoGasHydrateJointIndustryProjectLegII in the spring of 2009. Well logs obtained in one of the wells, the GreenCanyon Block 955Hwell (GC955-H), indicate that a 27.4-m thick zone at the depth of 428 m below sea floor (mbsf; 1404 feet below sea floor (fbsf)) contains gashydrate within sand with average gashydrate saturations estimated at 60% from the compressional-wave (P-wave) velocity and 65% (locally more than 80%) from resistivity logs if the gashydrate is assumed to be uniformly distributed in this mostly sand-rich section. Similar analysis, however, of log data from a shallow clay-rich interval between 183 and 366 mbsf (600 and 1200 fbsf) yielded average gashydrate saturations of about 20% from the resistivity log (locally 50-60%) and negligible amounts of gashydrate from the P-wave velocity logs. Differences in saturations estimated between resistivity and P-wave velocities within the upper clay-rich interval are caused by the nature of the gashydrate occurrences. In the case of the shallow clay-rich interval, gashydrate fills vertical (or high angle) fractures in rather than fillingpore space in sands. In this study, isotropic and anisotropic resistivity and velocity models are used to analyze the occurrence of gashydrate within both the clay-rich and sand dominated gas-hydrate-bearing reservoirs in the GC955-Hwell.

Gulf Of Mexico↗
USGS2012

Electrical anisotropy of gas hydrate-bearing sand reservoirs in the Gulf of Mexico

We present new results and interpretations of the electricalanisotropy and reservoir architecture in gashydrate-bearingsands using logging data collected during the Gulf of MexicoGasHydrate Joint Industry Project Leg II. We focus specifically on sandreservoirs in Hole Alaminos Canyon 21 A (AC21-A), Hole Green Canyon 955 H (GC955-H) and Hole Walker Ridge 313 H (WR313-H). Using a new logging-while-drilling directional resistivity tool and a one-dimensional inversion developed by Schlumberger, we resolve the resistivity of the current flowing parallel to the bedding, R | and the resistivity of the current flowing perpendicular to the bedding, R | . We find the sandreservoir in Hole AC21-A to be relatively isotropic, with R | and R | values close to 2 Ω m. In contrast, the gashydrate-bearingsandreservoirs in Holes GC955-H and WR313-H are highly anisotropic. In these reservoirs, R | is between 2 and 30 Ω m, and R | is generally an order of magnitude higher. Using Schlumberger's WebMI models, we were able to replicate multiple resistivity measurements and determine the formation resistivity the gashydrate-bearingsandreservoir in Hole WR313-H. The results showed that gashydrate saturations within a single reservoir unit are highly variable. For example, the sand units in Hole WR313-H contain thin layers (on the order of 10-100 cm) with varying gashydrate saturations between 15 and 95%. Our combined modeling results clearly indicate that the gashydrate-bearingsandreservoirs in Holes GC955-H and WR313-H are highly anisotropic due to varying saturations of gashydrate forming in thin layers within larger sand units.

Gulf Of Mexico↗
USGS2011

Petroleum prospectivity of the Canada Basin, Arctic Ocean

Reconnaissance seismic reflection data indicate that Canada Basin is a >700,000 sq. km. remnant of the Amerasia Basin of the Arctic Ocean that lies south of the Alpha-Mendeleev Large Igneous Province, which was constructed across the northern part of the Amerasia Basin between about 127 and 89–83.5 Ma. Canada Basin was filled by Early Jurassic to Holocene detritus from the Beaufort–Mackenzie Deltaic System, which drains the northern third of interior North America, with sizable contributions from Alaska and Northwest Canada. The basin contains roughly 5 or 6 million cubic km of sediment. Three fourths or more of this volume generates low amplitude seismic reflections, interpreted to represent hemipelagic deposits, which contain lenses to extensive interbeds of moderate amplitude reflections interpreted to represent unconfined turbidite and amalgamated channel deposits. Extrapolation from Arctic Alaska and Northwest Canada suggests that three fourths of the section in Canada Basin is correlative with stratigraphic sequences in these areas that contain intervals of hydrocarbon source rocks. In addition, worldwide heat flow averages suggest that about two thirds of Canada Basin lies in the oil or gas windows. Structural, stratigraphic and combined structural and stratigraphic features of local to regional occurrence offer exploration targets in Canada Basin, and at least one of these contains bright spots. However, deep water (to almost 4000 m), remoteness from harbors and markets, and thick accumulations of seasonal to permanent sea ice (until its possible removal by global warming later this century) will require the discovery of very large deposits for commercial success in most parts of Canada Basin.

Conference Paper↗
USGS2012

Resource and hazard implications of gas hydrates in the Northern Gulf of Mexico: Results of the 2009 Joint Industry Project Leg II Drilling Expedition

In the 1970's, Russian scientists were the first to suggest that gas hydrates, a crystalline solid of water and natural gas, and a historical curiosity to physical chemists, should occur in abundance in the natural environment. Since this early start, the scientific foundation has been built for the realization that gas hydrates are a global phenomenon, occurring in permafrost regions of the arctic and in deep water portions of most continental margins worldwide. Recent field testing programs in the Arctic (Dallimore et al., 2008; Yamamoto and Dallimore, 2008) have indicated that natural gas can be produced from gas hydrate accumulations, particularly when housed in sand-rich sediments, with existing conventional oil and gas production technology (Collett et al., 2008) and preparations are now being made for the first marine field production tests (Masuda et al., 2009). Beyond a future energy resource, gas hydrates in some settings may represent a geohazard. Other studies also indicate that methane released to the atmosphere from destabilized gas hydrates may have contributed to global climate change in the past.

Northern Gulf Of Mexico↗
USGS2013

Characteristics and interpretation of fracture-filled gas hydrate: an example from the Ulleung Basin, East Sea of Korea

Through the use of 2-D and 3-D seismic data, a total of thirteen sites were selected and drilled in the East Sea of Korea in 2010. A suite of logging-while-drilling (LWD) logs was acquired at each site. LWD logs from the UBGH2-3A well indicate significant gas hydrate in clay-bearing sediments including several zones with massive gas hydrate with a bulk density less than 1.0 g/m 3 for depths between 5 and 103 m below the sea floor. The UBGH2-3A well was drilled on a seismically identified chimney structure with a mound feature at the sea floor. Average gas hydrate saturations estimated from the isotropic analysis of ring resistivity and P-wave velocity logs are 80 ± 13% and 47 ± 16%, respectively, whereas they are 46 ± 17% and 45 ± 16%, respectively from the anisotropic analysis. Modeling indicates that the upper part of chimney (between 5 and 45 m below sea floor [mbsf]) is characterized by gas hydrate filling near horizontal fractures (7° dip) and the lower part of chimney (between 45 and 103 mbsf) is characterized by gas hydrate filling high angle fractures on the basis of ring resistivity and P-wave velocity. The anisotropic analysis using P40H resistivity (phase shift resistivity at 32 mHz with 40 inch spacing) and the P-wave velocity yields a gas hydrate saturation of 46 ± 15% and 46 ± 15% respectively, similar to those estimated using ring resistivity and P-wave velocity, but with quite different fracture dip angles. Differences in vertical resolution, depth of investigation, and a finite fracture dimension relative to the tool separation appear to contribute to this discrepancy. Forward modeling of anisotropic resistivity and velocity are essential to identify gas hydrate in fractures and to estimate accurate gas hydrate amounts.

East Sea Of Korea;Ulleung Basin↗
USGS2013

Scale-dependent gas hydrate saturation estimates in sand reservoirs in the Ulleung Basin, East Sea of Korea

Through the use of 2-D and 3-D seismic data, several gas hydrate prospects were identified in the Ulleung Basin, East Sea of Korea and thirteen drill sites were established and logging-while-drilling (LWD) data were acquired from each site in 2010. Sites UBGH2–6 and UBGH2–10 were selected to test a series of high amplitude seismic reflections, possibly from sand reservoirs. LWD logs from the UBGH2–6 well indicate that there are three significant sand reservoirs with varying thickness. Two upper sand reservoirs are water saturated and the lower thinly bedded sand reservoir contains gas hydrate with an average saturation of 13%, as estimated from the P-wave velocity. The well logs at the UBGH2–6 well clearly demonstrated the effect of scale-dependency on gas hydrate saturation estimates. Gas hydrate saturations estimated from the high resolution LWD acquired ring resistivity (vertical resolution of about 5–8 cm) reaches about 90% with an average saturation of 28%, whereas gas hydrate saturations estimated from the low resolution A40L resistivity (vertical resolution of about 120 cm) reaches about 25% with an average saturation of 11%. However, in the UBGH2–10 well, gas hydrate occupies a 5-m thick sand reservoir near 135 mbsf with a maximum saturation of about 60%. In the UBGH2–10 well, the average and a maximum saturation estimated from various well logging tools are comparable, because the bed thickness is larger than the vertical resolution of the various logging tools. High resolution wireline log data further document the role of scale-dependency on gas hydrate calculations.

East Sea Of Korea;Ulleung Basin↗
USGS2013

Characterization of gas hydrate reservoirs by integration of core and log data in the Ulleung Basin, East Sea

Examinations of core and well-log data from the Second Ulleung Basin Gas Hydrate Drilling Expedition (UBGH2) drill sites suggest that Sites UBGH2-2_2 and UBGH2-6 have relatively good gas hydrate reservoir quality in terms of individual and total cumulative thicknesses of gas-hydrate-bearing sand (HYBS) beds. In both of the sites, core sediments are generally dominated by hemipelagic muds which are intercalated with turbidite sands. The turbidite sands are usually thin-to-medium bedded and mainly consist of well sorted coarse silt to fine sand. Anomalies in infrared core temperatures and porewater chlorinity data and pressure core measurements indicate that “gas hydrate occurrence zones” (GHOZ) are present about 68–155 mbsf at Site UBGH2-2_2 and 110–155 mbsf at Site UBGH2-6. In both the GHOZ, gas hydrates are preferentially associated with many of the turbidite sands as “pore-filling” type hydrates. The HYBS identified in the cores from Site UBGH2-6 are medium-to-thick bedded particularly in the lower part of the GHOZ and well coincident with significant high excursions in all of the resistivity, density, and velocity logs. Gas-hydrate saturations in the HYBS range from 12% to 79% with an average of 52% based on pore-water chlorinity. In contrast, the HYBS from Site UBGH2-2_2 are usually thin-bedded and show poor correlations with both of the resistivity and velocity logs owing to volume averaging effects of the logging tools on the thin HYBS beds. Gas-hydrate saturations in the HYBS range from 15% to 65% with an average of 37% based on pore-water chlorinity. In both of the sites, large fluctuations in biogenic opal contents have significant effects on the sediment physical properties, resulting in limited usage of gamma ray and density logs in discriminating sand reservoirs.

East Sea Of Korea;Ulleung Basin↗
USGS2014

Gas hydrate identified in sand-rich inferred sedimentary section using downhole logging and seismic data in Shenhu area, South China Sea

Downhole wireline log (DWL) data was acquired from eight drill sites during China's first gas hydrate drilling expedition (GMGS-1) in 2007. Initial analyses of the acquired well log data suggested that there were no significant gas hydrate occurrences at Site SH4. However, the re-examination of the DWL data from Site SH4 indicated that there are two intervals of high resistivity, which could be indicative of gas hydrate. One interval of high resistivity at depth of 171–175 m below seafloor (mbsf) is associated with a high compressional- wave (P-wave) velocities and low gamma ray log values, which suggests the presence of gas hydrate in a potentially sand-rich (low clay content) sedimentary section. The second high resistivity interval at depth of 175–180 mbsf is associated with low P-wave velocities and low gamma values, which suggests the presence of free gas in a potentially sand-rich (low clay content) sedimentary section. Because the occurrence of free gas is much shallower than the expected from the regional depth of the bottom simulating reflector (BSR), the free gas could be from the dissociation of gas hydrate during drilling or there may be a local anomaly in the depth to the base of the gas hydrate stability zone. In order to determine whether the low P-wave velocity with high resistivity is caused by in-situ free gas or dissociated free gas from the gas hydrate, the surface seismic data were also used in this analysis. The log analysis incorporating the surface seismic data through the construction of synthetic seismograms using various models indicated the presence of free gas directly in contact with an overlying gas hydrate-bearing section. The occurrence of the anomalous base of gas hydrate stability at Site SH4 could be caused by a local heat flow conditions. This paper documents the first observation of gas hydrate in what is believed to be a sand-rich sediment in Shenhu area of the South China Sea.

Shenhu↗
USGS2015

Standardization of reflectance measurements in dispersed organic matter: results of an exercise to improve interlaboratory agreement

Vitrinite reflectance generally is considered the most robust thermal maturity parameter available for application to hydrocarbon exploration and petroleum system evaluation. However, until 2011 there was no standardized methodology available to provide guidelines for vitrinite reflectance measurements in shale. Efforts to correct this deficiency resulted in publication of ASTM D7708: Standard test method for microscopical determination of the reflectance of vitrinite dispersed in sedimentary rocks . In 2012-2013, an interlaboratory exercise was conducted to establish precision limits for the D7708 measurement technique. Six samples, representing a wide variety of shale, were tested in duplicate by 28 analysts in 22 laboratories from 14 countries. Samples ranged from immature to overmature (0.31-1.53% R o ), from organic-lean to organic-rich (1-22 wt.% total organic carbon), and contained Type I (lacustrine), Type II (marine), and Type III (terrestrial) kerogens. Repeatability limits (maximum difference between valid repetitive results from same operator, same conditions) ranged from 0.03-0.11% absolute reflectance, whereas reproducibility limits (maximum difference between valid results obtained on same test material by different operators, different laboratories) ranged from 0.12-0.54% absolute reflectance. Repeatability and reproducibility limits degraded consistently with increasing maturity and decreasing organic content. However, samples with terrestrial kerogens (Type III) fell off this trend, showing improved levels of reproducibility due to higher vitrinite content and improved ease of identification. Operators did not consistently meet the reporting requirements of the test method, indicating that a common reporting template is required to improve data quality. The most difficult problem encountered was the petrographic distinction of solid bitumens and low-reflecting inert macerals from vitrinite when vitrinite occurred with reflectance ranges overlapping the other components. Discussion among participants suggested this problem could not be easily corrected via kerogen concentration or solvent extraction and is related to operator training and background. No statistical difference in mean reflectance was identified between participants reporting bitumen reflectance vs. vitrinite reflectance vs. a mixture of bitumen and vitrinite reflectance values, suggesting empirical conversion schemes should be treated with caution. Analysis of reproducibility limits obtained during this exercise in comparison to reproducibility limits from historical interlaboratory exercises suggests use of a common methodology (D7708) improves interlaboratory precision. Future work will investigate opportunities to improve reproducibility in high maturity, organic-lean shale varieties.

Marine and Petroleum Geology↗
USGS2014

Grain-scale imaging and compositional characterization of cryo-preserved India NGHP 01 gas-hydrate-bearing cores

We report on grain-scale characteristics and gas analyses of gas-hydrate-bearing samples retrieved by NGHP Expedition 01 as part of a large-scale effort to study gas hydrate occurrences off the eastern-Indian Peninsula and along the Andaman convergent margin. Using cryogenic scanning electron microscopy, X-ray spectroscopy, and gas chromatography, we investigated gas hydrate grain morphology and distribution within sediments, gas hydrate composition, and methane isotopic composition of samples from Krishna–Godavari (KG) basin and Andaman back-arc basin borehole sites from depths ranging 26 to 525 mbsf. Gas hydrate in KG-basin samples commonly occurs as nodules or coarse veins with typical hydrate grain size of 30–80 μm, as small pods or thin veins 50 to several hundred microns in width, or disseminated in sediment. Nodules contain abundant and commonly isolated macropores, in some places suggesting the original presence of a free gas phase. Gas hydrate also occurs as faceted crystals lining the interiors of cavities. While these vug-like structures constitute a relatively minor mode of gas hydrate occurrence, they were observed in near-seafloor KG-basin samples as well as in those of deeper origin (>100 mbsf) and may be original formation features. Other samples exhibit gas hydrate grains rimmed by NaCl-bearing material, presumably produced by salt exclusion during original hydrate formation. Well-preserved microfossil and other biogenic detritus are also found within several samples, most abundantly in Andaman core material where gas hydrate fills microfossil crevices. The range of gas hydrate modes of occurrence observed in the full suite of samples suggests a range of formation processes were involved, as influenced by local in situ conditions. The hydrate-forming gas is predominantly methane with trace quantities of higher molecular weight hydrocarbons of primarily microbial origin. The composition indicates the gas hydrate is Structure I.

Marine and Petroleum Geology↗
USGS2014

Experimental investigation of changes in methane adsorption of bitumen-free Woodford Shale with thermal maturation induced by hydrous pyrolysis

This study quantifies the effects of organic-matter (OM) thermal maturity on methane (CH 4 ) sorption, on the basis of five samples that were artificially matured through hydrous pyrolysis achieved by heating samples of immature Woodford Shale under five different time–temperature conditions. CH 4 -sorption isotherms at 35 °C, 50 °C, and 65 °C, and pressures up to 14 MPa on dry, solvent-extracted samples of the artificially matured Woodford Shale were measured. The results showed that CH 4 -sorption capacity, normalized to TOC, varied with thermal maturity, following the trend: maximum oil (367 °C) > oil cracking (400 °C) > maximum bitumen/early oil (333 °C) > early bitumen (300 °C) > immature stage (130 °C). The Langmuir constants for the samples at maximum-oil and oil-cracking stages are larger than the values for the bitumen-forming stages. The total pore volume, determined by N 2 physisorption at 77 K, increases with increased maturation: mesopores, 2–50 nm in width, were created during the thermal conversion of organic-matter and a dramatic increase in porosity appeared when maximum-bitumen and maximum-oil generation stages were reached. A linear relationship between thermal maturity and Brunauer–Emmett–Teller (BET) surface area suggests that the observed increase in CH 4 -sorption capacity may be the result of mesopores produced during OM conversion. No obvious difference is observed in pore-size distribution and pore volume for samples with pores <2.0 nm with the increase of thermal maturity based on CO 2 physisorption at 273 K. The isosteric heat of adsorption and the standard entropy for artificially matured samples ranged from 17.9 kJ mol −1 to 21.9 kJ mol −1 and from −85.4 J mol −1 K −1 to −101.8 J mol −1 K −1 , respectively. These values are similar to the values of immature Woodford kerogen concentrate previously observed, but are larger than naturally matured organic-rich shales. High-temperature hydrous pyrolysis might have induced Lewis acid sites on both organic and mineral surfaces, resulting to some extent, in chemical interactions between the adsorption site and the methane C–H bonds. The formation of abundant mesopores (2–50 nm) within organic matter during organic-matter thermal maturation makes a great contribution to the increase in both BET surface area and pore volume, and a significant increase in 2–6 nm pores occurs at maximum-oil-generation and oil-cracking to gas, ultimately controlling the methane-adsorption capacity. Therefore, consideration of pore-size effects and thermal maturity is very important for gas in place (GIP) prediction in organic-rich shales.

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↗
USGS2016

Shallower structure and geomorphology of the southern Puerto Rico offshore margin

Oblique convergence between the North American and Caribbean plates along the eastern Greater Antilles island arc has yielded the compressive Muertos margin in the backarc region. The Muertos margin is characterized by an asymmetric thrust belt with overall opposite vergence to the subduction system in the forearc region. Offshore south of Puerto Rico, this thrust belt disappears and is replaced by a succession of NE─SW- and E─W-trending deep basins and steep ridges that characterize the western Anegada passage, resulting in a complex deformation pattern. Using new high-resolution multibeam bathymetry and a dense data set of mostly new seismic reflection profiles, we studied the along- and across-strike variations of the geomorphology and shallower structure of the southern Puerto Rico offshore margin. We have identified four morphotectonic provinces: the Puerto Rican sub-basin and Muertos trough, the Muertos margin, the insular shelf and the western Anegada passage. The Muertos margin province shows two distinct slope sub-provinces: the active Muertos thrust belt formed by N─S-compression between the island arc and the Caribbean plate’s interior ─which includes lower and upper thrust belts with distinct deformational styles and lateral continuity─ and the shelf slope covered by a thick package of layered sediments highly-incised by a dense canyon network. This network is disrupted by the Investigator fault zone consisting of a 130 km-long E─W-trending band of active extensional deformation. The Investigator fault zone shows differential surface expression caused by along-strike changes in the magnitude and distribution of the deformation, though this deformation is driven by a N─S-oriented extension, and if there is any amount of strike-slip it is insignificant. In the western Anegada passage province, the Whiting basin and Whiting and Grappler ridges are formed by large dipslip normal faults driven by a NW─SE-oriented extensional regime. The western St. Croix rise shows a complex structure as attested by the existence of NE─SW- and E─W-oriented normal faults. The NE─SW-trending NW-dipping normal faults observed at the summit of the rise predate the E─W-bounding faults that could accommodate the extensional deformation at the Present. This study provides detailed observations on the active tectonic and sedimentary processes to help future studies assessing the natural resources and the seismic and tsunamigenic hazard in the Puerto Rico region.

Marine and Petroleum Geology↗
USGS2015

Preface to the special issue on gas hydrate drilling in the Eastern Nankai Trough

Methane hydrate traps enormous amounts of methane in frozen deposits in continental margin sediments, and these deposits have long been targeted for studies investigating their potential as an energy resource. As a concentrated form of methane that occurs at shallower depths than conventional and most unconventional gas reservoirs, methane hydrates could be a readily accessible source of hydrocarbons for countries hosting deposits within their Exclusive Economic Zones. Japan is one such country, and since 2001 the Research Consortium for Methane Hydrate Resources in Japan (referred to as MH21) has conducted laboratory, modeling, and field-based programs to study methane hydrates as an energy resource. The MH21 consortium is funded by the Japanese Ministry of Trade and Industry (METI) and led by the Japan Oil, Gas and Metals National Oil Corporation (JOGMEC) and the National Institute of Advanced Industrial Science and Technology (AIST).

Marine and Petroleum Geology↗