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At least 181 records · Page 10Linked to original sources

Geology and mineral resources of central Antioquia Department (Zone IIA), Colombia

This report summarizes the geology of an area of some 6000 square kilometers in the northern part of the Central Cordillera of the Colombian Andes. The area, in north-central Department of Antioquia, was mapped between 1964 and 1968 as part of the Inventario Minero Nacional (IMN) project. Mineral resources are summarized within a larger area, designated as subzone ILK of IMN Zone If, which comprises almost 22,000 sq. kin, including the area mapped geologically by IMN and additional areas mapped by other agencies. The oldest formation is a micaceous paragneiss of early Paleozoic or possibly late Precambrian age. A thick geosynclinal sedimentary series accumulated during the Paleozoic Era and became regionally metamorphosed to greenschist (locally amphibolite) facies during the Permian or early Triassic; these schists and gneisses are designated collectively as the Valdivia Group. The Permian(?) orogenic episode included intrusion of concordant syntectonic plutons, mostly of tonalitic composition. Rocks of unequivocal Triassic or Jurassic age are not recognized. The Cretaceous is well represented by both igneous and sedimentary assemblages. Eugeosynclinal alpine ophiolites comprising submarine basalt flows and numerous intrusions of gabbro and serpentinite are prominent in the Lower Cretaceous, together with flysch composed of marine shale and lesser sandstone and conglomerate. The Upper Cretaceous is represented along the west border of the mapped area by submarine basalt flows and pyroclastic rocks, locally Interbedded with fine-grained clastic sedimentary beds, and lenses of dark laminated chert, at least part of which is radiolarian. The Late Cretaceous was marked by an orogenic event that profoundly folded and faulted all rocks and in the Central Cordillera caused low-grade metamorphism, the overprint of which is hardly observable in pre-Cretaceous rocks elsewhere. The Late Cretaceous orogeny culminated with discordant intrusion of the epizonal tonalitic Antioquian batholith. Displacement along the great Romeral wrench fault may have begun in the Cretaceous. Plutonism continued into the Cenozoic, exemplified by the hornblende-diorite Sabanalarga pluton. Intermontane basins were filled with molasse derived from the erosion of adjacent highlands; Tertiary sedimentation in marshy areas included organic carboniferous matter subsequently converted to lignite or subbituminous coal. The Sabanalarga fault system originated in the Late Tertiary; intermittent displacement continued on the older wrench faults such as the Romeral. Epeirogenic uplift, which probably began in the Pliocene and continued through the Pleistocene and Holocene, brought on renewed erosion which has sculptured the mountains into their present form. Mineral resources in subzone IIA are varied but not of outstanding importance. Gold and silver mining, significant in past centuries, is minor today. Ferruginous laterite on serpentinite once considered as a potential source of iron ore is not economically exploitable. IMN has explored nickeliferous laterite at the extreme northwest corner of subzone IIA; this is a potential resource, exploitable only after exhaustion of the larger and richer nickel laterite deposit at Cerro Matoso, farther to the north and outside the boundaries of Zone If. Known deposits of mercury, chromium, manganese, and copper are small, with limited economic potential. Nonmetallic resources include raw materials for cement, including portland cement. Saprolite clay is widely used in making common red brick and tile, still a dominant construction material in all but the most modern multistory buildings. Aggregate materials are varied and abundant. Kaolin of good quality near La Union is important as a ceramic raw mineral filler. Tertiary subbituminous coal beds are an important energy resource in western subzone IIA, and have a good potential for greater development. Deposits of sodic feldspar, talc, decorative stone, and silica a

Open-File Report

Assessment of continuous (unconventional) oil and gas resources in the Late Cretaceous Mancos Shale of the Piceance Basin, Uinta-Piceance Province, Colorado and Utah, 2016

The U.S. Geological Survey (USGS) completed a geology-based assessment of the continuous (unconventional) oil and gas resources in the Late Cretaceous Mancos Shale within the Piceance Basin of the Uinta-Piceance Province (fig. 1). The previous USGS assessment of the Mancos Shale in the Piceance Basin was completed in 2003 as part of a comprehensive assessment of the greater UintaPiceance Province (U.S. Geological Survey Uinta-Piceance Assessment Team, 2003). Since the last assessment, more than 2,000 wells have been drilled and completed in one or more intervals within the Mancos Shale of the Piceance Basin (IHS Energy Group, 2015). In addition, the USGS Energy Resources Program drilled a research core in the southern Piceance Basin that provided significant new geologic and geochemical data that were used to refine the 2003 assessment of undiscovered, technically recoverable oil and gas in the Mancos Shale.

Colorado, Utah

Mineral resources of the Sagebrush Focal Areas of Idaho, Montana, Nevada, Oregon, Utah, and Wyoming

Scientific Investigations Report 2016–5089 and accompanying data releases are the products of the U.S. Geological Survey (USGS) Sagebrush Mineral-Resource Assessment (SaMiRA). The assessment was done at the request of the Bureau of Land Management (BLM) to evaluate the mineral-resource potential of some 10 million acres of Federal and adjacent lands in Idaho, Montana, Nevada, Oregon, Utah, and Wyoming. The need for this assessment arose from the decision by the Secretary of the Interior to pursue the protection of large tracts of contiguous habitat for the greater sage-grouse ( Centrocercus urophasianus ) in the Western United States. One component of the Department of the Interior plan to protect the habitat areas includes withdrawing selected lands from future exploration and development of mineral and energy resources, including copper, gold, silver, rare earth elements, and other commodities used in the U.S. economy. The assessment evaluates the potential for locatable minerals such as gold, copper, and lithium and describes the nature and occurrence of leaseable and salable minerals for seven Sagebrush Focal Areas and additional lands in Nevada (“Nevada additions”) delineated by BLM. Supporting data are available in a series of USGS data releases describing mineral occurrences (the USGS Mineral Deposit Database or “USMIN”), oil and gas production and well status, previous mineral-resource assessments that covered parts of the areas studied, and a compilation of mineral-use cases based on data provided by BLM, as well as results of the locatable mineral-resource assessment in a geographic information system. The present assessment of mineral-resource potential will contribute to a better understanding of the economic and environmental trade-offs that would result from closing approximately 1 0 million acres of Federal lands to mineral entry.

Idaho, Montana, Nevada, Oregon, Utah, Wyoming

India National Gas Hydrate Program Expedition 02 Summary of Scientific Results: Gas hydrate systems along the eastern continental margin of India

The primary objectives of the India National Gas Hydrate Program Expedition 02 (NGHP-02) were to obtain new data on the occurrence of gas hydrate systems and to advance the understanding of the controls on the formation of gas hydrate accumulations in the offshore of India. In accordance with the ultimate overall goal of the NGHP effort to assess the energy resource potential of marine gas hydrates in India, particular focus was placed on the exploration and evaluation of gas hydrate occurrences at high saturations in sand-rich systems. NGHP-02 operations were conducted from 3-March-2015 to 28-July-2015 off the eastern coast of India and included logging while drilling (LWD) operations at 25 locations, and coring and wireline logging operations at 10 locations, in the Krishna-Godavari and Mahanadi Basins. The formation of highly concentrated gas hydrate accumulations, which are more suitable for energy extraction, requires the presence of relatively coarse-grained sediments with porosity needed to support the migration and accumulation of gas, and the nucleation of gas hydrate. The results of downhole logging, coring and formation pressure testing operations during NGHP-02 have confirmed the presence of extensive sand-rich depositional systems throughout the deepwater portions of the Krishna-Godavari and Mahanadi Basins. Two areas of Krishna-Godavari Basin, referred to as Areas B and C, contain substantial gas hydrate accumulations in sand-rich systems and therefore represent ideal candidate sites for future gas hydrate production testing. This summary and technical report includes a comprehensive synthesis of the geologic, geophysical, geochemical, and physical property data acquired during NGHP-02 as it relates to the controls on gas hydrate occurrence, particularly with regards to sand-hosted accumulations. In the Mahanadi Basin, despite the confirmation of extensive reservoir capacity, gas supply at the NGHP-02 sites was insufficient to charge the reservoirs with gas hydrates. In the Krishna-Godavari Basin, extensive reservoir systems were confirmed with sediment grain-sizes ranging from coarse-silts to gravels. These reservoirs range from fully- to partially filled with gas hydrate. The gas is determined to be from only microbial sources, and in part migrated into the reservoirs from deeper systems. The controls on gas hydrate occurrence are complex and varied; and include substantial reservoir heterogeneity and sufficient permeability throughout the reservoirs and seals that allowed pervasive fluid flow into and through the hydrate-bearing systems. These discoveries are the most significant confirmation of the exploration approach that focuses on direct detection of hydrate reservoirs supported by comprehensive petroleum systems analyses.

Journal of Marine and Petroleum Geology

United States Geological Survey Yearbook, fiscal year 1977

Fiscal 1977 marked the 98th year the U.S. Geological Survey has endeavored in the unceasing task of providing information about the Earth and its physical resources, and regulating the activities of lessees engaged in extracting petroleum and other minerals from the public domain. The past year also marked the beginning of a third and challenging mission, drawing upon the Survey's scientific talents, to explore and assess the petroleum potential of a vast 37,000 square miles expanse of Alaska's North Slope known as the National Petroleum Reserve in Alaska. The first two missions require detailed and continuing investigations of the location, character, and extent of the Nation's land, water, mineral, and energy resources; a continuing National Topographic Mapping Program; the classification of Federal lands for mineral and waterpower potential; and a continuing program of technical review, safety inspection and royalty auditing of the operations of private parties engaged in mineral development on Federal lands to assure standards of safety, environmental protection, resource conservation, and a fair market return to the public for the development of their resources.

Yearbook

Evaluation of long-term gas hydrate production testing locations on the Alaska North Slope

The results of short duration formation tests in northern Alaska and Canada have further documented the energy resource potential of gas hydrates and justified the need for long-term gas hydrate production testing. Additional data acquisition and long-term production testing could improve the understanding of the response of naturally-occurring gas hydrate to depressurization-induced or thermal-, chemical-, and/or mechanical-stimulated dissociation of gas hydrate into producible gas. The Eileen gas hydrate accumulation located in the Greater Prudhoe Bay area in northern Alaska has become a focal point for gas hydrate geologic and production studies. BP Exploration (Alaska) Incorporated and ConocoPhillips have each established research partnerships with U.S. Department of Energy to assess the production potential of gas hydrates in northern Alaska. A critical goal of these efforts is to identify the most suitable site for production testing. A total of seven potential locations in the Prudhoe Bay, Kuparuk, and Milne Point production units were identified and assessed relative to their suitability as a long-term gas hydrate production test site. The test site assessment criteria included the analysis of the geologic risk associated with encountering reservoirs for gas hydrate testing. The site selection process also dealt with the assessment of the operational/logistical risk associated with each of the potential test sites. From this review, a site in the Prudhoe Bay production unit was determined to be the best location for extended gas hydrate production testing. The work presented in this report identifies the key features of the potential test site in the Greater Prudhoe Bay area, and provides new information on the nature of gas hydrate occurrence and potential impact of production testing on existing infrastructure at the most favorable sites. These data were obtained from well log analysis, geological correlation and mapping, and numerical simulation.

Conference Paper

Evaluation of long-term gas hydrate production testing locations on the Alaska North Slope

The results of short-duration formation tests in northern Alaska and Canada have further documented the energy-resource potential of gas hydrates and have justified the need for long-term gas-hydrate-production testing. Additional data acquisition and long-term production testing could improve the understanding of the response of naturally occurring gas hydrate to depressurization-induced or thermal-, chemical-, or mechanical-stimulated dissociation of gas hydrate into producible gas. The Eileen gashydrate accumulation located in the Greater Prudhoe Bay area in northern Alaska has become a focal point for gas-hydrate geologic and production studies. BP Exploration (Alaska) Incorporated and ConocoPhillips have each established research partnerships with the US Department of Energy to assess the production potential of gas hydrates in northern Alaska. A critical goal of these efforts is to identify the most suitable site for production testing. A total of seven potential locations in the Prudhoe Bay, Kuparuk River, and Milne Point production units were identified and assessed relative to their suitability as a long-term gas-hydrate-production test sites. The test-site-assessment criteria included the analysis of the geologic risk associated with encountering reservoirs for gas-hydrate testing. The site-selection process also dealt with the assessment of the operational/logistical risk associated with each of the potential test sites. From this review, a site in the Prudhoe Bay production unit was determined to be the best location for extended gas-hydrate-production testing. The work presented in this report identifies the key features of the potential test site in the Greater Prudhoe Bay area and provides new information on the nature of gas-hydrate occurrence and the potential impact of production testing on existing infrastructure at the most favorable sites. These data were obtained from well-log analysis, geological correlation and mapping, and numerical simulation.

Alaska

GHASTLI — Determining physical properties of sediment containing natural and laboratory-formed gas hydrate

Gas-hydrate samples have been recovered at about 16 areas worldwide (Booth et al., 1996). However, gas hydrate is known to occur at about 50 locations on continental margins (Kvenvolden, 1993) and is certainly far more widespread so it may represent a potentially enormous energy resource (Kvenvolden, 1988). But adverse effects related to the presence of hydrate do occur. Gas hydrate appears to have caused slope instabilities along continental margins (Booth et al., 1994; Dillon et al., 1998; Mienert et al., 1998; Paull & Dillon, (Chapter 12; Twichell & Cooper, 2000) and it has also been responsible for drilling accidents (Yakushev and Collett, 1992). Uncontrolled release of methane could affect global climate (Chapter 11), because methane is 15–20 times more effective as a “greenhouse gas” than an equivalent concentration of carbon dioxide. Clearly, a knowledge of gas-hydrate properties is necessary to safely explore the possibility of energy recovery and to understand its past and future impact on the geosphere.

Book chapter

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

Petroleum system and production characteristics of the Muddy (J) Sandstone (Lower Cretaceous) Wattenberg continuous gas field, Denver basin, Colorado

Wattenberg field is a continuous-type gas accumulation. Estimated ultimate recovery from current wells is 1.27 tcf of gas from the Lower Cretaceous Muddy (J) Sandstone. Mean gas resources that have the potential to be added to these reserves in the next 30 yr are 1.09 tcf; this will be primarily through infill drilling to recover a greater percentage of gas in place and to drain areas that are isolated because of geologic compartmentalization. Greatest gas production from the Muddy (J) Sandstone in Wattenberg field occurs (1) from within the most permeable and thickest intervals of Fort Collins Member delta-front and nearshore-marine sandstones, (2) to a lesser extent from the Horsetooth Member valley-fill channel sandstones, (3) in association with a large thermal anomaly that is delineated by measured temperatures in wells and by vitrinite reflectance contours of 0.9% and greater, (4) in proximity to the bounding Mowry, Graneros, and Skull Creek shales that are the hydrocarbon source rocks and reservoir seals, and (5) between the Lafayette and Longmont right-lateral wrench fault zones (WFZs) with secondary faults that act as conduits in areas of the field. The axis of greatest gas production is north 25 to 35 degrees northeast, which parallels the basin axis. Recurrent movement along five right-lateral WFZs that crosscut Wattenberg field shifted the Denver basin axis to the northeast and influenced depositional and erosional patterns of the reservoir and seal intervals. Levels of thermal maturity within the Wattenberg field are anomalously high compared to other areas of the Denver basin. The Wattenberg field thermal anomaly may be due to upward movement of fluids along faults associated with probable igneous intrusions. Areas of anomalous high heat flow within the field correlate with an increased and variable gas-oil ratio. Debra Higley has 5 years experience in uranium exploration and 20 years as a petroleum geologist with the U.S. Geological Survey. Her research interests include and integrate reservoir characterization, thermal maturation studies, and petroleum resource assessment in basins in North and South America. She received a B.S. degree in geology from Mesa State College (Colorado) and an M.S. degree in geochemistry and Ph.D. in geology from the Colorado School of Mines.Dave Cox is vice president of Reservoir Engineering for Questa Engineering in Golden, Colorado. He has 25 years experience in the oil and gas industry, primarily in reservoir engineering and property evaluations, and has analyzed reservoirs in 31 states of the United States and 19 other countries. He is an expert in coalbed methane, tight gas reservoirs, and enhanced oil recovery. He has B.S. and M.S. degrees in petroleum engineering from the Colorado School of Mines. Robert Weimer has taught courses in stratigraphy, regional and field geology, and energy resource exploration and development for 43 years. He earned B.A. and M.A. degrees from the University of Wyoming and his Ph.D. from Stanford University. He has been a visiting professor at universities in Calgary, Canada; Adelaide, Australia; and Bandung, Indonesia. He is currently professor emeritus, Colorado School of Mines. Weimer has been honored for teaching excellence, blending basic and applied research, national and international continuing education, and service to scientific societies and to state and national boards.

Colorado

The key to commercial-scale geological CO2 sequestration: Displaced fluid management

The Wyoming State Geological Survey has completed a thorough inventory and prioritization of all Wyoming stratigraphic units and geologic sites capable of sequestering commercial quantities of CO 2 (5–15 Mt CO 2 /year). This multi-year study identified the Paleozoic Tensleep/Weber Sandstone and Madison Limestone (and stratigraphic equivalent units) as the leading clastic and carbonate reservoir candidates for commercial-scale geological CO 2 sequestration in Wyoming. This conclusion was based on unit thickness, overlying low permeability lithofacies, reservoir storage and continuity properties, regional distribution patterns, formation fluid chemistry characteristics, and preliminary fluid-flow modeling. This study also identified the Rock Springs Uplift in southwestern Wyoming as the most promising geological CO 2 sequestration site in Wyoming and probably in any Rocky Mountain basin. The results of the WSGS CO 2 geological sequestration inventory led the agency and colleagues at the UW School of Energy Resources Carbon Management Institute (CMI) to collect available geologic, petrophysical, geochemical, and geophysical data on the Rock Springs Uplift, and to build a regional 3-D geologic framework model of the Uplift. From the results of these tasks and using the FutureGen protocol, the WSGS showed that on the Rock Springs Uplift, the Weber Sandstone has sufficient pore space to sequester 18 billion tons (Gt) of CO 2 , and the Madison Limestone has sufficient pore space to sequester 8 Gt of CO 2 .

Energy Procedia

Geospatial data for coal beds in the Powder River Basin, Wyoming and Montana

The purpose of this report is to provide geospatial data for various layers and themes in a Geographic Information System (GIS) format for the Powder River Basin, Wyoming and Montana. In 2015, as part of the U.S. Coal Resources and Reserves Assessment Project, the U.S. Geological Survey (USGS) completed an assessment of coal resources and reserves within the Powder River Basin, Wyoming and Montana. This report is supplemental to USGS Professional Paper 1809 and contains GIS data that can be used to view digital layers or themes, including the Tertiary limit of the Powder River Basin boundary, locations of drill holes, clinker, mined coal, land use and technical restrictions, geology, mineral estate ownership, coal thickness, depth to the top of the coal bed (overburden), and coal reliability categories. Larger scale maps may be viewed using the GIS data provided in this report supplemental to the page-size maps provided in USGS Professional Paper 1809. Additionally, these GIS data can be exported to other digital applications as needed by the user. The database used for this report contains a total of 29,928 drill holes, of which 21,393 are in the public domain. The public domain database is linked to the geodatabase in this report so that the user can access the drill-hole data through GIS applications. Results of this report are available at the USGS Energy Resources Program Web site, http://energy.usgs.gov/RegionalStudies/PowderRiverBasin.aspx .

Montana, Wyoming

Archie’s saturation exponent for natural gas hydrate in coarse-grained reservoirs

Accurately quantifying the amount of naturally occurring gas hydrate in marine and permafrost environments is important for assessing its resource potential and understanding the role of gas hydrate in the global carbon cycle. Electrical resistivity well logs are often used to calculate gas hydrate saturations, S h , using Archie's equation. Archie's equation, in turn, relies on an empirical saturation parameter, n . Though n = 1.9 has been measured for ice‐bearing sands and is widely used within the hydrate community, it is highly questionable if this n value is appropriate for hydrate‐bearing sands. In this work, we calibrate n for hydrate‐bearing sands from the Canadian permafrost gas hydrate research well, Mallik 5L‐38, by establishing an independent downhole S h profile based on compressional‐wave velocity log data. Using the independently determined S h profile and colocated electrical resistivity and bulk density logs, Archie's saturation equation is solved for n, and uncertainty is tracked throughout the iterative process. In addition to the Mallik 5L‐38 well, we also apply this method to two marine, coarse‐grained reservoirs from the northern Gulf of Mexico Gas Hydrate Joint Industry Project: Walker Ridge 313‐H and Green Canyon 955‐H. All locations yield similar results, each suggesting n ≈ 2.5 ± 0.5. Thus, for the coarse‐grained hydrate bearing ( S h > 0.4) of greatest interest as potential energy resources, we suggest that n = 2.5 ± 0.5 should be applied in Archie's equation for either marine or permafrost gas hydrate settings if independent estimates of n are not available.

Journal of Geophysical Research B: Solid Earth

Hydraulic properties of sediments from the GC955 gas hydrate reservoir in the Gulf of Mexico

The economic feasibility of gas production from hydrate deposits is critical for hydrate to become an energy resource. Permeability in hydrate-bearing sediments dictates gas and water flow rates and needs to be accurately evaluated. Published permeability studies of hydrate-bearing sediments mostly quantify vertical permeability; however, the flow is mainly horizontal during gas production in layered reservoirs. Additionally, ASTM standards require a hydraulic gradient of 10–30 to be used during laboratory permeability measurements, but the gradient is much higher in the field, particularly near a production well. To address these issues, this study focuses on the hydraulic properties of a sandy silt subsample of the hydrate reservoir and a clayey silt subsample of the fine-grained, hydrate-free interbed recovered from a GC955 deep-water Gulf of Mexico gas hydrate reservoir. We characterize the sediment pore space with water retention curves for both hydrate-free and hydrate-bearing samples (hydrate saturation, S h =80 %). Vertical deformation with increasing stress is also quantified while consolidating the samples to the 4 MPa in situ vertical effective stress. The customized permeameter measures both the horizontal and vertical permeability with increasing stress. Results show that high hydraulic gradients lower permeability in the flow direction, possibly due to increased flow tortuosity and local sediment compaction from the high seepage force. Assuming a single permeability value, even though hydraulic gradients decrease with distance from the well, is not realistic for field estimations. The results highlight that permeability anisotropy, hydrate saturation, stress conditions, and hydraulic gradient all substantially impact reservoir permeability during production.

Geomechanics for Energy and the Environment

Consolidation and permeability of the B1 and D1 gas hydrate bearing sands and associated seal sediments of the extended-duration gas production test site on the Alaska North Slope

Gas hydrate, a solid combination of gas (mostly methane in nature) and water molecules stable at low temperatures and elevated pressures, occurs naturally in marine and permafrost-associated environments. Gas hydrate reservoirs, such as those in the Alaska North Slope, have been considered potential energy resources for gas production. To understand the petrophysical and geo-mechanical characteristics of the reservoir, core samples retrieved from the site of the JOGMEC-DOE-USGS collaborative gas hydrate R&D project have been analyzed in the laboratory for their hydraulic and mechanical properties. This paper focuses on both seal and reservoir samples associated with the B1 and D1 sands, which are evaluated for index properties (including porosity, grain size distribution, liquid and plastic limits, specific surface area, and specific gravity), consolidation, permeability, and water retention. Furthermore, the reservoir core samples were tested with pore-filling, laboratory-grown tetrahydrofuran hydrate, in order to assess reservoir behavior during gas production from hydrates. Under simulated in situ stress conditions, the seal and hydrate-free reservoir cores had a permeability anisotropy ratio of k h / k v = 3.0–5.0, and k h / k v = 2.4–3.0 for the reservoir tetrahydrofuran hydrate-bearing cores. The data suggest that depressurizing the reservoir to induce hydrate dissociation alters the reservoir effective permeability in three ways: permeabilities decrease due to porosity lost (e.g., the initial reservoir thickness can decrease by up to 5% upon 7 MPa depressurization), permeability increases due to the loss of solid hydrate in the pore space, and permeability anisotropy k h / k v decreases in response to the evolving pore-space geometry. We show that given the simulated in situ gas hydrate saturations (i.e., S h = 32% in core 7P-2E and S h = 21% in core 20P-4), gas production from the dissociation of tetrahydrofuran hydrate in the two tested cores results in a net increase in effective permeability and a decrease in k h / k v . This study highlights the importance of investigating seal and reservoir sediments and the impacts of depressurization on the porosity and permeability responses during production.

Alaska

Evaluating greater sage-grouse seasonal space use relative to leks: Implications for surface use designations in sagebrush ecosystems

The development of anthropogenic structures, especially those related to energy resources, in sagebrush ecosystems is an important concern among developers, conservationists, and land managers in relation to greater sage-grouse (Centrocercus urophasianus; hereafter, sage-grouse) populations. Sage-grouse are dependent on sagebrush ecosystems to meet their seasonal life-phase requirements, and research indicates that anthropogenic structures can adversely affect sage-grouse populations. Land management agencies have attempted to reduce the negative effects of anthropogenic development by assigning surface use (SU) designations, such as no surface occupancy, to areas around leks (breeding grounds). However, rationale for the size of these areas is often challenged. To help inform this issue, we used a spatial analysis of sage-grouse utilization distributions (UDs) to quantify seasonal (spring, summer and fall, winter) sage-grouse space use in relation to leks. We sampled UDs from 193 sage-grouse (11,878 telemetry locations) across 4 subpopulations within the Bi-State Distinct Population Segment (DPS, bordering California and Nevada) during 2003–2009. We quantified the volume of each UD (vUD) within a range of areas that varied in size and were centered on leks, up to a distance of 30 km from leks. We also quantified the percentage of nests within those areas. We then estimated the diminishing gains of vUD as area increased and produced continuous response curves that allow for flexibility in land management decisions. We found nearly 90% of the total vUD (all seasons combined) was contained within 5 km of leks, and we identified variation in vUD for a given distance related to season and migratory status. Five kilometers also represented the 95th percentile of the distribution of nesting distances. Because diminishing gains of vUD was not substantial until distances exceeded 8 km, managers should consider the theoretical optimal distances for SU designation between 5.0 km and 7.5 km, depending on migratory status. Although these results represent space use for sage-grouse within the Bi-State DPS, our results likely have broad relevance to other areas with similar landscape characteristics and patterns of space use.

Journal of Wildlife Management

Laboratory simulation of hydrothermal petroleum formation from sediment in Escanaba Trough, offshore from northern California

Petroleum associated with sulfide-rich sediment is present in Escanaba Trough at the southern end of the Gorda Ridge spreading axis offshore from northern California within the Exclusive Economic Zone (EEZ) of the U.S. This location and occurrence are important for evaluation of the mineral and energy resource potential of the seafloor under U.S. jurisdiction. In Escanaba Trough, petroleum is believed to be formed by hydrothermal processes acting on mainly terrigenous organic material in Quaternary, river-derived sediment. To attempt to simulate these processes in the laboratory, portions of a Pleistocene gray-green mud, obtained from ∼ 1.5 m below the seafloor at a water depth of ∼ 3250 m in Escanaba Trough, were heated in the presence of water in four hydrous-pyrolysis experiments conducted at temperatures ranging from 250 to 350°C and at a pressure of 350 bar for 1.0–4.5 days. Distributions of n -alkanes, isoprenoid hydrocarbons, triterpanes, and steranes in the heated samples were compared with those in a sample of hydrothermal petroleum from the same area. Mud samples heated for less than 4.5 days at less than 350°C show changes in some, but not all, molecular marker ratios of organic compounds that are consistent with those expected during hydrothermal petroleum formation. Our results suggest that the organic matter in this type of sediment serves as one possible source for some of the compounds found in the hydrothermal petroleum.

California

Gas hydrates in the ocean environment

A GAS HYDRATE, also known as a gas clathrate, is a gas-bearing, icelike material. It occurs in abundance in marine sediments and stores immense amounts of methane, with major implications for future energy resources and global climate change. Furthermore, gas hydrate controls some of the physical properties of sedimentary deposits and thereby influences seafloor stability.

Book chapter