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USGS1984

Speculations on the petroleum geology of the accretionary body: an example from the central Aleutians

In the 300 km wide Adak-Amlia sector of the central Aleutian Trench ??? 36 000 km3 of offscraped trench fill makes up the wedge-shaped mass of the Aleutian accretionary body. Within this wedge, seismic reflection profiles reveal an abundance of potential hydrocarbon-trapping structures. These structures include antiforms, thrust and normal faults, and stratigraphic pinchouts. Maximum closure on these features is 2 km. In addition, the silt and possibly sand size sediment within the offscraped turbidite deposits, and the porous diatomaceous pelagic deposits interbedded with and at the base of the wedge, may define suitable reservoirs for the entrapment of hydrocarbons. Potential seals for these reservoirs include diagenetically-altered and -produced siliceous and carbonate sediment. The organic carbon input into the central Aleutian Trench, based on carbon analyses of DSDP Legs 18 and 19 core samples, suggests that the average organic carbon content within the accretionary body is approximately 0.3-0.6%. Heat flow across the Aleutian Terrace indicates that at present the oil generation window lies at a depth of 3-6.5 km. At depths of 8 km (which corresponds to the maximum depth the offscraped sediment has been seismically resolved beneath the lower trench slope), the probable high (170-180??C) temperatures prohibit all but gas generation. The dewatering of trench sediment and subducted oceanic crust should produce an abundance of fluids circulating within the accretionary body. These fluids and gases can conduct hydrocarbons to any of the abundant trapping geometries or be lost from the system through sea floor seepage. In the Aleutian accretionary body all the conditions necessary for the formation of oil and gas deposits exist. The size and ultimate preservation of these deposits, however, are dependent on the deformational history of the prism both during accretion and after the accretion process has been superceded by subsequent tectonic regimes. ?? 1984.

Marine and Petroleum Geology↗

USGS2012

Gulf of Mexico Gas Hydrate Joint Industry Project Leg II logging-while-drilling data acquisition and analysis

One of the objectives of the Gulf of Mexico Gas Hydrate Joint Industry Project Leg II (GOM JIP Leg II) was the collection of a comprehensive suite of logging-while-drilling (LWD) data within gas-hydrate-bearing sand reservoirs in order to make accurate estimates of the concentration of gas hydrates under various geologic conditions and to understand the geologic controls on the occurrence of gas hydrate at each of the sites drilled during this expedition. The LWD sensors just above the drill bit provided important information on the nature of the sediments and the occurrence of gas hydrate. There has been significant advancements in the use of downhole well-logging tools to acquire detailed information on the occurrence of gas hydrate in nature: From using electrical resistivity and acoustic logs to identify gas hydrate occurrences in wells to where wireline and advanced logging-while-drilling tools are routinely used to examine the petrophysical nature of gas hydrate reservoirs and the distribution and concentration of gas hydrates within various complex reservoir systems. Recent integrated sediment coring and well-log studies have confirmed that electrical resistivity and acoustic velocity data can yield accurate gas hydrate saturations in sediment grain supported (isotropic) systems such as sand reservoirs, but more advanced log analysis models are required to characterize gas hydrate in fractured (anisotropic) reservoir systems. In support of the GOM JIP Leg II effort, well-log data montages have been compiled and presented in this report which includes downhole logs obtained from all seven wells drilled during this expedition with a focus on identifying and characterizing the potential gas-hydrate-bearing sedimentary section in each of the wells. Also presented and reviewed in this report are the gas-hydrate saturation and sediment porosity logs for each of the wells as calculated from available downhole well logs.

Gulf Of Mexico↗

USGS2011

Pre- and post-drill comparison of the Mount Elbert gas hydrate prospect, Alaska North Slope

In 2006, the United States Geological Survey (USGS) completed a detailed analysis and interpretation of available 2-D and 3-D seismic data, along with seismic modeling and correlation with specially processed downhole well log data for identifying potential gas hydrate accumulations on the North Slope of Alaska. A methodology was developed for identifying sub-permafrost gas hydrate prospects within the gas hydrate stability zone in the Milne Point area. The study revealed a total of 14 gas hydrate prospects in this area. In order to validate the gas hydrate prospecting protocol of the USGS and to acquire critical reservoir data needed to develop a longer-term production testing program, a stratigraphic test well was drilled at the Mount Elbert prospect in the Milne Point area in early 2007. The drilling confirmed the presence of two prominent gas-hydrate-bearing units in the Mount Elbert prospect, and high quality well logs and core data were acquired. The post-drill results indicate pre-drill predictions of the reservoir thickness and the gas-hydrate saturations based on seismic and existing well data were 90% accurate for the upper unit (hydrate unit D) and 70% accurate for the lower unit (hydrate unit C), confirming the validity of the USGS approach to gas hydrate prospecting. The Mount Elbert prospect is the first gas hydrate accumulation on the North Slope of Alaska identified primarily on the basis of seismic attribute analysis and specially processed downhole log data. Post-drill well log data enabled a better constraint of the elastic model and the development of an improved approach to the gas hydrate prospecting using seismic attributes.

Alaska↗

USGS2021

Geochemical advances in Arctic Alaska oil typing - North Slope oil correlation and charge history

The Arctic Alaska petroleum province is geologically and geochemically complex. Mixed hydrocarbon charge from multiple source rocks and/or levels of thermal maturity is common within an individual oil pool. Biomarker and chemometric statistical analyses were used to correlate twenty-nine oils to five oil families derived from: (1) Triassic Shublik Formation (calcareous organofacies), (2) Triassic Shublik Formation (shaly organofacies), (3) Jurassic Kingak Shale, (4) Cretaceous shale (pebble shale unit and Hue Shale), and (5) Paleogene shale (Canning Formation). Age-diagnostic and source-related oil biomarker parameters establish clear genetic relationships between the normal oil-window components and their putative source designations. However, application of diamondoid analyses reveals mixed-oil accumulations with postmature charge contributions (diamondoid-rich and biomarker-poor) in many oils. Most sampled reservoirs contain a predominant charge derived from a single oil-window source plus a minor contribution from one or more higher maturity source(s). Variations in source organofacies also are recognized in the Shublik, Kingak, and Cretaceous oil families. In some cases, oils from multiple pools within a single field display relatively homogeneous geochemical profiles, suggesting a common source and migration pathway. For example, oil from the significant Pikka discovery is inferred to originate mainly from the calcareous Shublik Formation. In other cases, variability among oils from multiple pools within a single field (e.g., Milne Point, Colville River, and Northstar) likely indicates a more complex source, migration, and charge history. Results may be useful for anticipating the composition of oil charge in stratigraphic traps with low-permeability sandstone reservoirs, where oil gravity and other chemical parameters may influence economic viability.

Alaska↗

USGS2010

Detailed seafloor habitat mapping to enhance marine-resource management

Pictures of the seafloor capture important information about the sediments, exposed geologic features, submerged aquatic vegetation, and animals found in a given habitat. With the emergence of marine protected areas (MPAs) as a favored tactic for preserving coral reef resources, knowledge of essential habitat components is paramount to designing effective management strategies. Surprisingly, detailed information on seafloor habitat components is not available in many areas that are being considered for MPA designation or that are already designated as MPAs. A task of the U.S. Geological Survey Coral Reef Ecosystem STudies (USGS CREST) project is addressing this issue.

Fact Sheet↗

USGS2019

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

India’s National Gas Hydrate Program Expedition 02 (NGHP-02), was conducted to better understand geologic controls on gas hydrate occurrence and morphology, targeting potentially coarse-grained sediments near the base of the continental slope offshore eastern India. This study combines seismic, logging-while-drilling data, and a petroleum systems approach to provide a regional geologic context for the core- and grain-scale analyses. This multi-scale approach provides insight on the gas hydrate distribution, morphology and anticipated system response to depressurization-induced methane extraction. The study area, NGHP-02 Area B in the Krishna-Godavari Basin, contains a buried anticline/syncline structure that hosts fracture-filling gas hydrate in fine-grained sediment overlying coarser sediments with pore-occupying gas hydrate. Core- and grain-scale measurements show fine-grained sediment exerts a primary control on the distribution and morphology of gas hydrate in Area B. Diatoms in the fine-grained overburden cause porosity to increase with depth, reaching ~70% at the underlying reservoir contact. High porosity, combined with near-vertical faults, suggests the overlying sediment is an imperfect seal. This allows methane to escape the gas hydrate reservoir sediments and form primarily grain-displacing gas hydrate veins in the fine-grained overburden. Within the reservoir, fine-grained layers are interbedded with coarser-grained gas hydrate reservoir sands. Even in the reservoir sands, however, a soil classification study shows the fines content is high enough to control hydraulic and mechanical properties, such as permeability, compressibility and shear strength. Fluid motion during methane extraction from gas hydrates can mobilize those 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. Accounting for fines content and specific fines mineralogy throughout the gas hydrate petroleum system is important for predicting production efficiency from gas hydrate occurrences along the crest of the anticline in NGHP-02 Area B.

Marine and Petroleum Geology↗

USGS2011

Formation pressure testing at the Mount Elbert Gas Hydrate Stratigraphic Test Well, Alaska North Slope: Operational summary, history matching, and interpretations

In February 2007, the U.S. Department of Energy, BP Exploration (Alaska), and the U.S. Geological Survey, collected open-hole pressure-response data, as well as gas and water sample collection, in a gas hydrate reservoir (the BPXA-DOE-USGS Mount Elbert Gas Hydrate Stratigraphic Test Well) using Schlumberger's Modular Dynamics Formation Tester (MDT) wireline tool. Four such MDT tests, ranging from six to twelve hours duration, and including a series of flow, sampling, and shut-in periods of various durations, were conducted. Locations for the testing were selected based on NMR and other log data to assure sufficient isolation from reservoir boundaries and zones of excess free water. Test stages in which pressure was reduced sufficiently to mobilize free water in the formation (yet not cause gas hydrate dissociation) produced readily interpretable pressure build-up profiles. Build-ups following larger drawdowns consistently showed gas-hydrate dissociation and gas release (as confirmed by optical fluid analyzer data), as well as progressive dampening of reservoir pressure build-up during sequential tests at a given MDT test station. History matches of one multi-stage, 12-h test (the C2 test) were accomplished using five different reservoir simulators: CMG-STARS, HydrateResSim, MH21-HYDRES, STOMP-HYD, and TOUGH + HYDRATE. Simulations utilized detailed information collected across the reservoir either obtained or determined from geophysical well logs, including thickness (11.3 m, 37 ft.), porosity (35%), hydrate saturation (65%), both mobile and immobile water saturations, intrinsic permeability (1000 mD), pore water salinity (5 ppt), and formation temperature (3.3–3.9 °C). This paper will present the approach and preliminary results of the history-matching efforts, including estimates of initial formation permeability and analyses of the various unique features exhibited by the MDT results.

Alaska↗

USGS2011

Alaska North Slope regional gas hydrate production modeling forecasts

A series of gas hydrate development scenarios were created to assess the range of outcomes predicted for the possible development of the “Eileen” gas hydrate accumulation, North Slope, Alaska. Production forecasts for the “reference case” were built using the 2002 Mallik production tests, mechanistic simulation, and geologic studies conducted by the US Geological Survey. Three additional scenarios were considered: A “downside-scenario” which fails to identify viable production, an “upside-scenario” describes results that are better than expected. To capture the full range of possible outcomes and balance the downside case, an “extreme upside scenario” assumes each well is exceptionally productive. Starting with a representative type-well simulation forecasts, field development timing is applied and the sum of individual well forecasts creating the field-wide production forecast. This technique is commonly used to schedule large-scale resource plays where drilling schedules are complex and production forecasts must account for many changing parameters. The complementary forecasts of rig count, capital investment, and cash flow can be used in a pre-appraisal assessment of potential commercial viability. Since no significant gas sales are currently possible on the North Slope of Alaska, typical parameters were used to create downside, reference, and upside case forecasts that predict from 0 to 71 BM 3 (2.5 tcf) of gas may be produced in 20 years and nearly 283 BM 3 (10 tcf) ultimate recovery after 100 years. Outlining a range of possible outcomes enables decision makers to visualize the pace and milestones that will be required to evaluate gas hydrate resource development in the Eileen accumulation. Critical values of peak production rate, time to meaningful production volumes, and investments required to rule out a downside case are provided. Upside cases identify potential if both depressurization and thermal stimulation yield positive results. An “extreme upside” case captures the full potential of unconstrained development with widely spaced wells. The results of this study indicate that recoverable gas hydrate resources may exist in the Eileen accumulation and that it represents a good opportunity for continued research.

Alaska↗

USGS2011

Geologic controls on gas hydrate occurrence in the Mount Elbert prospect, Alaska North Slope

Data acquired at the BPXA-DOE-USGS Mount Elbert Gas Hydrate Stratigraphic Test Well, drilled in the Milne Point area of the Alaska North Slope in February, 2007, indicates two zones of high gas hydrate saturation within the Eocene Sagavanirktok Formation. Gas hydrate is observed in two separate sand reservoirs (the D and C units), in the stratigraphically highest portions of those sands, and is not detected in non-sand lithologies. In the younger D unit, gas hydrate appears to fill much of the available reservoir space at the top of the unit. The degree of vertical fill with the D unit is closely related to the unit reservoir quality. A thick, low-permeability clay-dominated unit serves as an upper seal, whereas a subtle transition to more clay-rich, and interbedded sand, silt, and clay units is associated with the base of gas hydrate occurrence. In the underlying C unit, the reservoir is similarly capped by a clay-dominated section, with gas hydrate filling the relatively lower-quality sands at the top of the unit leaving an underlying thick section of high-reservoir quality sands devoid of gas hydrate. Evaluation of well log, core, and seismic data indicate that the gas hydrate occurs within complex combination stratigraphic/structural traps. Structural trapping is provided by a four-way fold closure augmented by a large western bounding fault. Lithologic variation is also a likely strong control on lateral extent of the reservoirs, particularly in the D unit accumulation, where gas hydrate appears to extend beyond the limits of the structural closure. Porous and permeable zones within the C unit sand are only partially charged due most likely to limited structural trapping in the reservoir lithofacies during the period of primary charging. The occurrence of the gas hydrate within the sands in the upper portions of both the C and D units and along the crest of the fold is consistent with an interpretation that these deposits are converted free gas accumulations formed prior to the imposition of gas hydrate stability conditions.

Alaska↗

USGS2008

Scientific results from Gulf of Mexico Gas Hydrates Joint Industry Project Leg 1 drilling: Introduction and overview

The Gulf of Mexico Gas Hydrates Joint Industry Project (JIP) is a consortium of production and service companies and some government agencies formed to address the challenges that gas hydrates pose for deepwater exploration and production. In partnership with the U.S. Department of Energy and with scientific assistance from the U.S. Geological Survey and academic partners, the JIP has focused on studies to assess hazards associated with drilling the fine-grained, hydrate-bearing sediments that dominate much of the shallow subseafloor in the deepwater (>500 m) Gulf of Mexico. In preparation for an initial drilling, logging, and coring program, the JIP sponsored a multi-year research effort that included: (a) the development of borehole stability models for hydrate-bearing sediments; (b) exhaustive laboratory measurements of the physical properties of hydrate-bearing sediments; (c) refinement of new techniques for processing industry-standard 3-D seismic data to constrain gas hydrate saturations; and (d) construction of instrumentation to measure the physical properties of sediment cores that had never been removed from in situ hydrostatic pressure conditions. Following review of potential drilling sites, the JIP launched a 35-day expedition in Spring 2005 to acquire well logs and sediment cores at sites in Atwater Valley lease blocks 13/14 and Keathley Canyon lease block 151 in the northern Gulf of Mexico minibasin province. The Keathley Canyon site has a bottom simulating reflection at ???392 m below the seafloor, while the Atwater Valley location is characterized by seafloor mounds with an underlying upwarped seismic reflection consistent with upward fluid migration and possible shoaling of the base of the gas hydrate stability (BGHS). No gas hydrate was recovered at the drill sites, but logging data, and to some extent cores, suggest the occurrence of gas hydrate in inferred coarser-grained beds and fractures, particularly between 220 and 330 m below the seafloor at the Keathley Canyon site. This paper provides an overview of the results of the initial phases of the JIP work and introduces the 15 papers that make up this special volume on the scientific results related to the 2005 logging and drilling expedition.

Marine and Petroleum Geology↗

USGS2011

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

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

Alaska↗

USGS2023

Modeling the maturation history of the stacked petroleum systems of the Williston Basin, USA

A three-dimensional petroleum systems model was built to support U.S. Geological Survey assessments of undiscovered oil and gas resources in the Williston Basin of North Dakota, Montana, and South Dakota. Numerous Paleozoic source rocks have been proven or postulated in the basin, of which five were the focus of maturation and migration modeling: the Ordovician Icebox Formation, the kukersite beds of the Ordovician Red River Formation, the shales of the Devonian–Mississippian Bakken Formation, the Mississippian Madison Group, and the Pennsylvanian Tyler Formation. Calibration of the three-dimensional model to present-day temperature data indicates the existence of a north-south trend of high heat flow in western North Dakota, along with a region of high heat flow in eastern Montana. These high heat flow trends strongly control the maturity of all studied source intervals. A Bakken-specific hydrocarbon generation kinetic model was developed to match the calibrated time-temperature history of the basin to spatial trends in hydrogen index from programmed pyrolysis data. Generation of hydrocarbons occurred in the Cretaceous through Paleogene due to increased burial. Subsequent uplift and erosion in the Neogene cooled the basin, ending hydrocarbon generation for all source rocks. The cumulative volume of hydrocarbons generated by each of the source rocks was calculated and used to compare their relative robustness. The shales of the Bakken Formation are estimated to have generated approximately 460 billion barrels of oil equivalent (BBOE), while the Red River Formation generated approximately 130 BBOE, the Tyler Formation 94 BBOE, the Madison Group 44 BBOE, and the Icebox Formation 28 BBOE. Gross migration trends were analyzed with respect to historical oil and gas production in the basin and generally indicate segregation of petroleum systems throughout the stratigraphic column. However, most modeled scenarios indicated significant loss of Bakken oil to the Madison Group, suggesting that mixing of Madison and Bakken oils may be more prevalent than has recently been recognized in the U.S. portion of the Williston Basin and is particularly likely in fractured regions of the basin.

Montana, North Dakota↗

USGS2011

Mount Elbert Gas Hydrate Stratigraphic Test Well, Alaska North Slope: Overview of scientific and technical program

The Mount Elbert Gas Hydrate Stratigraphic Test Well was drilled within the Alaska North Slope (ANS) Milne Point Unit (MPU) from February 3 to 19, 2007. The well was conducted as part of a Cooperative Research Agreement (CRA) project co-sponsored since 2001 by BP Exploration (Alaska), Inc. (BPXA) and the U.S. Department of Energy (DOE) in collaboration with the U.S. Geological Survey (USGS) to help determine whether ANS gas hydrate can become a technically and commercially viable gas resource. Early in the effort, regional reservoir characterization and reservoir simulation modeling studies indicated that up to 0.34 trillion cubic meters (tcm; 12 trillion cubic feet, tcf) gas may be technically recoverable from 0.92 tcm (33 tcf) gas-in-place within the Eileen gas hydrate accumulation near industry infrastructure within ANS MPU, Prudhoe Bay Unit (PBU), and Kuparuk River Unit (KRU) areas. To further constrain these estimates and to enable the selection of a test site for further data acquisition, the USGS reprocessed and interpreted MPU 3D seismic data provided by BPXA to delineate 14 prospects containing significant highly-saturated gas hydrate-bearing sand reservoirs. The “Mount Elbert” site was selected to drill a stratigraphic test well to acquire a full suite of wireline log, core, and formation pressure test data. Drilling results and data interpretation confirmed pre-drill predictions and thus increased confidence in both the prospect interpretation methods and in the wider ANS gas hydrate resource estimates. The interpreted data from the Mount Elbert well provide insight into and reduce uncertainty of key gas hydrate-bearing reservoir properties, enable further refinement and validation of the numerical simulation of the production potential of both MPU and broader ANS gas hydrate resources, and help determine viability of potential field sites for future extended term production testing. Drilling and data acquisition operations demonstrated that gas hydrate scientific research programs can be safely, effectively, and efficiently conducted within ANS infrastructure. The program success resulted in a technical team recommendation to project management to drill and complete a long-term production test within the area of existing ANS infrastructure. If approved by stakeholders, this long-term test would build on prior arctic research efforts to better constrain the potential gas rates and volumes that could be produced from gas hydrate-bearing sand reservoirs.

Alaska↗

USGS2008

Geologic framework of the 2005 Keathley Canyon gas hydrate research well, northern Gulf of Mexico

The Keathley Canyon sites drilled in 2005 by the Chevron Joint Industry Project are located along the southeastern edge of an intraslope minibasin (Casey basin) in the northern Gulf of Mexico at 1335 m water depth. Around the drill sites, a grid of 2D high-resolution multichannel seismic data designed to image depths down to at least 1000 m sub-bottom reveals 7 unconformities and disconformities that, with the seafloor, bound 7 identifiable seismic stratigraphic units. A major disconformity in the middle of the units stands out for its angular baselapping geometry. From these data, three episodes of sedimentary deposition and deformation are inferred. The oldest episode consists of fine-grained muds deposited during a period of relative stability in the basin (units e, f, and g). Both the BSR and inferred gas hydrate occur within these older units. The gas hydrate occurs in near-vertical fractures. A second episode (units c and d) involved large vertical displacements associated with infilling and ponding of sediment. This second interval corresponds to deposition of intercalated fine and coarse-grained material that was recovered in the drill hole that penetrated the thin edges of the regionally much thicker units. The final episode of deposition (units a and b) occurred during more subdued vertical motions. Hemipelagic drape (unit a) characterizes the modern seafloor. The present-day Casey basin is mostly filled. Its sill is part of a subsiding graben structure that is only 10-20 m shallower than the deepest point in the basin, indicating that gravity-driven transport would mostly bypass the basin. Contemporary faulting along the basin margins has selectively reactivated an older group of faults. The intercalated sand and mud deposits of units c and d are tentatively correlated with Late Pleistocene deposition derived from the western shelf-edge delta/depocenter of the Mississippi River, which was probably most active from 320 ka to 70 ka [Winker, C.D., Booth, J., 2000. Sedimentary dynamics of the salt-dominated continental slope, Gulf of Mexico: integration of observations from the seafloor, near-surface, and deep subsurface. In: Proceedings of the GCSSEPM Foundation 20th Annual Research Conference, Deep-water Reservoirs of the World, pp. 1059-1086]. The presence of sand within the gas hydrate stability zone (in units c and d) is not sufficient to concentrate gas hydrate even though dispersed gas hydrate occurs deeper in the fractured mud/clay-rich sections of units e and f.

Gulf of Mexico↗

USGS2014

Geologic implications of gas hydrates in the offshore of India: results of the National Gas Hydrate Program Expedition 01

The Indian National Gas Hydrate Program Expedition 01 (NGHP-01) is designed to study the occurrence of gas hydrate along the passive continental margin of the Indian Peninsula and in the Andaman convergent margin, with special emphasis on understanding the geologic and geochemical controls on the occurrence of gas hydrate in these two diverse settings. The NGHP-01 expedition established the presence of gas hydrates in the Krishna-Godavari and Mahanadi Basins, and the Andaman Sea. The expedition discovered in the Krishna-Godavari Basin one of the thickest gas hydrate accumulations ever documented, in the Andaman Sea one of the thickest and deepest gas hydrate stability zones in the world, and established the existence of a fully developed gas hydrate petroleum system in all three basins. The primary goal of NGHP-01 was to conduct scientific ocean drilling/coring, logging, and analytical activities to assess the geologic occurrence, regional context, and characteristics of gas hydrate deposits along the continental margins of India. This was done in order to meet the long-term goal of exploiting gas hydrate as a potential energy resource in a cost effective and safe manner. During its 113.5-day voyage, the D/V JOIDES Resolution cored and/or drilled 39 holes at 21 sites (1 site in Kerala-Konkan, 15 sites in Krishna-Godavari, 4 sites in Mahanadi, and 1 site in the Andaman deep offshore area), penetrated more than 9250 m of sedimentary section, and recovered nearly 2850 m of core. Twelve holes were logged with logging-while-drilling (LWD) tools and an additional 13 holes were wireline logged. The science team utilized extensive on-board laboratory facilities to examine and prepare preliminary reports on the physical properties, geochemistry, and sedimentology of all the data collected prior to the end of the expedition. Samples were also analyzed in additional post-expedition shore-based studies conducted in leading laboratories around the world. One of the specific objectives of this expedition was to test gas hydrate formation models and constrain model parameters, especially those that account for the formation of concentrated gas hydrate accumulations. The necessary data for characterizing the occurrence of in situ gas hydrate, such as interstitial water chlorinities, core-derived gas chemistry, physical and sedimentological properties, thermal images of the recovered cores, and downhole measured logging data (LWD and/or conventional wireline log data), were obtained from most of the drill sites established during NGHP-01. Almost all of the drill sites yielded evidence for the occurrence of gas hydrate; however, the inferred in situ concentration of gas hydrate varied substantially from site to site. For the most part, the interpretation of downhole logging data, core thermal images, interstitial water analyses, and pressure core images from the sites drilled during NGHP-01 indicate that the occurrence of concentrated gas hydrate is mostly associated with the presence of fractures in the sediments, and in some limited cases, by coarser grained (mostly sand-rich) sediments.

Marine and Petroleum Geology↗

USGS2013

Large-scale depositional characteristics of the Ulleung Basin and its impact on electrical resistivity and Archie-parameters for gas hydrate saturation estimates

Gas hydrate saturation estimates were obtained from an Archie-analysis of the Logging-While-Drilling (LWD) electrical resistivity logs under consideration of the regional geological framework of sediment deposition in the Ulleung Basin, East Sea, of Korea. Porosity was determined from the LWD bulk density log and core-derived values of grain density. In situ measurements of pore-fluid salinity as well as formation temperature define a background trend for pore-fluid resistivity at each drill site. The LWD data were used to define sets of empirical Archie-constants for different depth-intervals of the logged borehole at all sites drilled during the second Ulleung Basin Gas Hydrate Drilling Expedition (UBGH2). A clustering of data with distinctly different trend-lines is evident in the cross-plot of porosity and formation factor for all sites drilled during UBGH2. The reason for the clustering is related to the difference between hemipelagic sediments (mostly covering the top ∼100 mbsf) and mass-transport deposits (MTD) and/or the occurrence of biogenic opal. For sites located in the north-eastern portion of the Ulleung Basin a set of individual Archie-parameters for a shallow depth interval (hemipelagic) and a deeper MTD zone was achieved. The deeper zone shows typically higher resistivities for the same range of porosities seen in the upper zone, reflecting a shift in sediment properties. The presence of large amounts of biogenic opal (up to and often over 50% as defined by XRD data) was especially observed at Sites UBGH2-2_1 and UBGH2-2_2 (as well as UBGH1-9 from a previous drilling expedition in 2007). The boundary between these two zones can also easily be identified in gamma-ray logs, which also show unusually low readings in the opal-rich interval. Only by incorporating different Archie-parameters for the different zones a reasonable estimate of gas hydrate saturation was achieved that also matches results from other techniques such as pore-fluid freshening, velocity-based calculations, and pressure-core degassing experiments. Seismically, individual boundaries between zones were determined using a grid of regional 2D seismic data. Zoning from the Archie-analysis for sites in the south-western portion of the Ulleung Basin was also observed, but at these sites it is linked to individually stacked MTDs only and does not reflect a mineralogical occurrence of biogenic opal or hemipelagic sedimentation. The individual MTD events represent differently compacted material often associated with a strong decrease in porosity (and increase in density), warranting a separate set of empirical Archie-parameters.

East Sea Of Korea;Ulleung Basin↗

USGS2018

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

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 CO 2 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 δ 13 C values ranging from −58.9 to −78.9‰, with small contributions from microbial ethane (−52.1‰) and CO 2 . Gas from the Mahanadi Basin was mainly methane with lower concentrations of C 2 -C 5 hydrocarbons (C 1 /C 2 ratios typically >1000) and CO 2 . 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 CO 2, C 1 /C 2 ratios were mainly >1000 although deeper samples were <1000. Carbon isotopic compositions range from −65.2 to −80.7‰ for methane, −53.1 to −55.2‰ for ethane is consistent with mainly microbial gas sources, although one value recorded of −35.4‰ for propane suggests a thermogenic source. Gas hydrate accumulations in the Krishna-Godavari and Mahanadi Basins are the result of a microbially sourced gas hydrate system. The system is enhanced by the migration of microbial gas from surrounding areas through pathways including high-porosity delta sands, shale diapirism, faulting and folding of sediment due to the local processes associated with rapid sediment deposition, sediment overpressure, and the recycling of methane from a rapidly upward moving gas hydrate stability zone. The gas hydrate system in the Andaman Basin is less well constrained due to lack of exploration and occurs in a forearc basin. Each of these hydrate-bearing systems overlies and is likely supported by the presence and possible migration of gas from deeper gas-prone petroleum systems currently generating thermogenic hydrocarbons at much greater depths.

Marine and Petroleum Geology↗

USGS2008

Evidence of Late Pliocene-Early Pleistocene marine environments in the deep subsurface of the Lihue Basin, Kauai, Hawaii

Cuttings recovered from two deep exploratory wells in the Lihue Basin, Kauai, Hawaii, include fossiliferous marine deposits that offer an uncommon opportunity to study paleoenvironments from the deep subsurface in Hawaii and interpret the paleogeography and geologic history of Kauai. These deposits indicate that two marine incursions gave rise to protected shallow-water, low-energy embayments in the southern part of the Lihue Basin in the late Pliocene-early Pleistocene. During the first marine incursion, the embayment was initially zoned, with a variable-salinity environment nearshore and a normal-marine reef environment offshore. The offshore reef environment eventually evolved to a nearshore, variable-salinity environment as the outer part of the embayment shallowed. During the second marine incursion, the embayment had normal-marine to hypersaline conditions, which constitute a significant departure from the variable-salinity environment present during the first marine incursion. Large streams draining the southern Lihue Basin are a likely source of the freshwater that caused the salinity fluctuations evident in the fossils from the first marine incursion. Subsequent volcanic eruptions produced lava flows that buried the embayment and probably diverted much of the stream flow in the southern Lihue Basin northward, to its present point of discharge north of Kalepa Ridge. As a result, the embayment that formed during the second marine incursion received less freshwater, and a normal-marine to hypersaline environment developed. The shallow-water marine deposits, currently buried between 86 m and 185 m below present sea level, have implications for regional tectonics and global eustasy. Copyright ?? 2008, SEPM (Society for Sedimentary Geology).

Palaios↗