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At least 667 records · Page 37Linked to original sources
USGS1974

Spectrophotometric determination of niobium in rocks

After acid decomposition and evaporation to volatilize silica, samples containing 0.5 6 μ g Nb are fused with pyrosulfate and dissolved in hydrochloric acid tartaric acid. Niobium is separated by thiocyanate extraction with amyl alcohol and back-extracting from the organic solvent with dilute hydrofluoric acid. Niobium is reacted with 4-(2-pyridylazo)-resorcinol to obtain a colored species. Analytical error, estimated from replicate analyses of eight U.S. Geological Survey standard rocks, ranges from 2.9 to 6.4 percent at the 1 27 μ g/g Nb level.

Journal of Research of the U.S. Geological Survey↗
USGS2003

Liquefaction potential index: Field assessment

Cone penetration test (CPT) soundings at historic liquefaction sites in California were used to evaluate the predictive capability of the liquefaction potential index (LPI), which was defined by Iwasaki et al. in 1978. LPI combines depth, thickness, and factor of safety of liquefiable material inferred from a CPT sounding into a single parameter. LPI data from the Monterey Bay region indicate that the probability of surface manifestations of liquefaction is 58 and 93%, respectively, when LPI equals or exceeds 5 and 15. LPI values also generally correlate with surface effects of liquefaction: Decreasing from a median of 12 for soundings in lateral spreads to 0 for soundings where no surface effects were reported. The index is particularly promising for probabilistic liquefaction hazard mapping where it may be a useful parameter for characterizing the liquefaction potential of geologic units.

Journal of Geotechnical and Geoenvironmental Engin↗
USGS2010

Viscosity and finite strength of the mantle as determined from water and ice loads

Some recent examples of transient Earth loads (Lake Bonneville, Utah; Glacier Bay, Alaska; northeast Greenland) indicate that both the viscosity and finite strength of the mantle are lower than is commonly presumed. A time constant (1/ e ) of 4000 years is estimated for Lake Bonneville, and of 1000 years for northeast Greenland. A strain rate of 10 −14 is typical. These figures imply viscosities in a homogeneous half space ranging from 10 20 to 10 21 poises. An upper limit of finite strength is set by Lake Bonneville at a few times 10 6 dyn/cm 2 . If mountain ranges like the Sierra Nevada or Himalaya are regarded as dynamically supported rather than static systems, this low value is not incompatible with other geologic observations.

Alaska, Utah↗
USGS1983

Correlation of metal occurrence and terrane attributes in the northwestern conterminous United States

The regional distribution patterns for 20 critical metals derived by an areal-pattern recognition technique leads me to conclude that metals are regularly distributed preferentially in the accreted and cratonic terranes studied in and surrounding the state of Oregon in the northwestern United States. The distribution patterns along distinctively different zones differ in these contrasting crusts across a concealed boundary that is established by strontium isotope data. Copper and gold appear to be abundant in both terranes; nickel, cobalt, chromium, and the platinum-group metals predominate in accreted terranes; lead, zinc, tin, and tungsten are concentrated locally along the boundary zone along the edge and in the interior of the cratonic terrane. The association of metals with accreted terranes and with restricted areas or lineaments in the craton further supports the metallogenetic hypothesis that metal materials are derived mainly from underlying ensialic and ensimatic crusts, and anticipates the possibility for remobilization of these materials along the same broad linear zones over geologic time.

California, Idaho, Montana, Nevada, Oregon, Utah, ↗
USGS1997

New allocyclic dimensions in a prograding carbonate bank: Evidence for eustatic, tectonic, and paleoceanographic control (late Neogene, Bahamas)

The deep-sea record, examined recently for the first time in a shallow-depocenter setting, has unveiled remarkable evidence for new sedimentary components and allocyclic complexity in a large, well-studied carbonate bank, the western Great Bahama Bank. The evidence is a composite foraminiferal signature - Paleocene to early Miocene (allogenic or reworked) and late Miocene to late Pliocene (host) planktic taxa, and redeposited middle Miocene shallow benthic faunas. Ages of the oldest and youngest planktic groups range from ??? 66 to ??? 2 Ma. The reworked and redeposited taxa are a proxy for significant sediment components that otherwise have no lithofacies or seismic resolution. The composite signature, reinforced by a distinctive distribution of the reworked and redeposited faunas, documents a much more complex late Neogene depositional system than previously known. The system is more than progradational. The source sequences that supplied the constituent bank-margin grains formed at different water depths and over hundreds of kilometers and tens of millions of years apart. New evidence from the literature and from data obtained during Ocean Drilling Program (OOP) Leg 166 in the Santaren Channel (Bahamas) support early interpretations based on the composite fossil record and provide valuable new dimensions to regional allocyclicity. The middle Miocene taxa were confined to the lower part of the section by the latest Miocene-earliest Pliocene(?) lowstand of sea level. An orderly occurrence of the allogenic taxa is unique to the global reworked geologic record and appears to have been controlled by a combination of Paleogene-early Neogene tectonics at the source, eustatic changes, and late Neogene current activity at the source and across the bank. The allogenic taxa expand the spatial and temporal range of information in the northern Bahamas by nearly an order of magnitude. In essence, some of the major processes active in the region during ??? 64 m.y. of the Cenozoic can be viewed from within a narrow (??? 6 m.y.) late Neogene window. In this case, the fossil record also serves to demonstrate the potential and significance in evaluating reworked and redeposited assemblages. Copyright ?? 1998, SEPM (Society for Sedimentary Geology).

Journal of Sedimentary Research B: Stratigraphy an↗
USGS1973

Use of machine-processable field notes in a wilderness mapping project (Granite Fiords area), southeastern Alaska

For reconnaissance geologic mapping and mineral resource evaluation of the Granite Fiords wilderness study area, we developed and used a system of machine-processable field notes. Preprinted field forms standardize notes and serve as checklists that insure collection of all available data. The use of this system cut in half the time required to record data at an outcrop. The system consists of three related but different types of preprinted field sheets, a key to abbreviations and codes, and a set of written instructions. The field sheets include a station sheet for basic outcrop data, a specimen sheet for rock samples, and a geochemical sheet for materials to be chemically analyzed. Data on the field sheets are keypunched on standard IBM cards, then arranged in subfiles and retrieved by using a card sorter. Our system is designed specifically for a region of granitic and metamorphic rocks but is easily modified for use in different geologic terranes. We offer four guidelines for developing a system of machine-processable field notes: (1) Time and money spent to develop the system must be worth its anticipated benefits. (2) The system should be as flexible as possible. (3) It is necessary to tailor the system to a particular geologic terrane or project objective. (4) The system should be as simple and self-explanatory as possible.

Alaska↗
USGS1975

An integrated-intensity method for emission spectrographic computer analysis

An integrated-intensity method has been devised to improve the computer analysis of data by emission spectrography. The area of the intensity profile of a spectral line is approximated by a rectangle whose height is related to the intensity difference between the peak and background of the line and whose width is measured at a fixed transmittance below the apex of the line. The method is illustrated by the determination of strontium in the presence of greater than 10 percent calcium. The Sr 3380.711-A line, which is unaffected by calcium and which has a linear analytical curve extending from 100-3,000 ppm, has been used to determine strontium in 18 standard reference rocks covering a wide range of geologic materials. Both the accuracy and the precision of the determinations were well within the accepted range for a semiquantitative procedure.

Journal of Research of the U.S. Geological Survey↗
USGS1975

Early Ordovician gastropod opercula and epicontinental seas

Collections made for some years from Lower Ordovician rocks by many geologists have established that the heavy calcareous operculum of the gastropod Ceratopea is almost never found associated with a shell and that commonly this operculum is secondarily silicified. Ceratopea may have lived in a stressed habitat and may have been essentially the only shelled invertebrate present. Presumably these animals grazed on algal mats and mounds growing in areas of water slightly more saline than open marine water and were killed by an influx of hypersaline water. Subsequent decay of soft parts would permit the operculum to rot off and would also lighten the shell so that it could float away. Pene-contemporaneous silicification of calcareous opercula on the Ordovician sea bottom is postulated. Some Middle Ordovician opercula of the Middle to Late Ordovician genus Maclurites serve to test this speculation. These opercula also occur in geologic settings which may be interpreted in terms of kill of animal, wafting away of shell, and secondary silicification of operculum.

Alabama, Arkansas, Colorado, Georgia, Maryland, Ne↗
USGS2019

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

The India National Gas Hydrate Program Expedition 02 (NGHP-02) discovered gas hydrate at high saturation in sand reservoirs at several sites in the deepwater Bay of Bengal. To assess the potential response of those deposits to scientific depressurization experiments, comprehensive geologic models were constructed to enable numerical simulation for two sites. Both sites (NGHP-02-09 and NGHP-02-16) feature thick sequences of thinly-interbedded reservoir and non-reservoir facies at sub-seafloor depths of less than 300 m and sub-sea depths of 2,400 m or more. These settings pose significant challenges to current modeling capabilities. First, the thinly-bedded reservoir architecture complicates the determination of basic reservoir parameters from both log and core data due to measurement resolution issues. Secondly, the fine-scale variation in sediment properties imparts great contrasts in key parameters over very short distances, creating high gradients at multiple scales and varying orientations that necessitate careful design of high-definition simulation grids. Thirdly, the deposits include internal sources of water, as well as a range of complex boundary conditions, including variable permeability within the overlying mud-rich “seals”, that complicate reservoir depressurization. Lastly, because of the unique combination of great water depth and relatively shallow sub-seafloor depth, models designed to maximize the dissociation rate impose large pressure drawdowns on relatively low-strength sediments. This condition renders the proper evaluation and integration of the geomechanical response to hydrate dissociation critical. In this report, we review the history of gas hydrate reservoir simulation, discuss methods for creating geologic input models, and summarize the key findings and implications of the collaborative NGHP-02 numerical simulation effort. Together, the studies confirm the viability of the modeled accumulations for scientific testing and identify key challenges related to the selection of specific test sites and the design of test wells.

Journal of Marine and Petroleum Geology↗
USGS1977

A reconnaissance investigation of a large meromictic lake in southeastern Alaska

Redoubt Lake is one of the largest documented meromictic lakes in North America. The chemocline extends in depth from 80 to 100 m (meters) and the steepest gradient is between 98 and 100 m. The monimolimnion is anoxic, contains hydrogen sulflde, and has a salinity about two-thirds that of seawater. Turnover appears to introduce additional sodium chloride from the chemocline to the mixolimnion, but diffusion is probably the dominant mixing mechanism. Vertical profiles show a dichothermic temperature curve. A minimum temperature of 3°C in the chemocline is unexplained, but higher temperatures in the monimolimnion may be a result of solar radiation. At the lower limit of the chemocline there is a sharp decrease in pH, which could be due to bacterial action. Redoubt Lake is probably a relict fiord. The data presented herein support the hypothesis that the lake was gradually isolated from the sea by uplift. While seawater was entering the lake, it probably mixed with the freshwater in the mixolimnion and therefore the monimolimnion is less saline than seawater. Geologic and geophysical evidence support the speculation that significant amounts of saltwater inflow probably ceased about 650-800 years before the present.

Alaska↗
USGS2014

Executive summary

Fossil fuels from the Appalachian basin region have been major contributors to the Nation’s energy needs over much of the last three centuries. Early records indicate that Appalachian coal was first mined in the middle 1700s (Virginia and Pennsylvania) and was used sparingly to fuel colonial settlements and, later, a fledgling industrial-based economy along the eastern seaboard of the United States (de Witt and Milici, 1989). In 2011, central Appalachian basin coal production accounted for approximately 77 percent of all U.S. metallurgical (or coking) coal and 29 percent of total U.S. production (U.S. Energy Information Administration, 2013). Following initial discoveries and commercial use in western New York (1821) and Ohio and West Virginia (mid-1830s), the Appalachian petroleum (oil and gas) industry began in earnest in 1859 with the discovery of oil at the Drake well in northwestern Pennsylvania. Between 1860 and 1989, the Appalachian basin produced more than 2.5 billion barrels of oil (BBO) and more than 30 trillion cubic feet of gas (TCFG) from more than 500,000 wells (de Witt and Milici, 1989). Although both oil and gas continue to be produced in the Appalachian basin, most new wells in the region are drilled in shale reservoirs to produce natural gas. Appalachian coal and petroleum resources are still available in sufficient quantities to contribute significantly to the Nation’s energy needs. For example, the U.S. Energy Information Administration (2010) estimated that there are 6,484 million short tons of recoverable coal reserves in the Appalachian basin. Similarly, about 14.7 billion barrels of oil equivalent (BBOE) (1.2 BBO+81 TCFG [or 13.5 BBOE]) of recoverable Appalachian basin oil and gas remain available of an estimated ultimate endowment of approximately 25.5 billion BBOE (cumulative production + reserves + estimated recoverable undiscovered resources) (this volume, chap. C.1). U.S. Geological Survey (USGS) Professional Paper 1708 is a modern, indepth collection of reports, cross sections, and maps that describe the geology of the Appalachian basin and its fossil fuel resources. Several of the chapters have been published in outside journals or as other USGS publications. Although this volume is not a comprehensive regional treatment of all notable geologic and fossil fuel localities in the Appalachian basin, the selected study areas and topics presented in the chapters cover large segments of the basin and a wide range of stratigraphic intervals. As the title implies, this volume addresses topics that refer to the locations of coal and petroleum accumulations, the stratigraphic and structural framework, and the geochemical characteristics of the coal beds and petroleum in the basin, as well as the results and documentation of recent USGS assessments of coal, oil, and gas resources in the basin. Many of the maps and accompanying data supporting the reports in this volume are available as downloadable geographic information system (GIS) data files (such as selected coal beds, selected oil and gas fields, locations of oil and gas wells, coal production, coal chemistry, total petroleum system (TPS) boundaries, and bedrock geology). Log ASCII Standard (LAS) files for geophysical (gamma ray) wireline well logs also are included. This publication supplements and updates older USGS regional studies of Appalachian basin coal and petroleum resources such as those by Arndt and others (1968) and the numerous contributors to USGS Miscellaneous Map Series I−917 (for example, Harris and others, 1978), respectively. USGS Professional Paper 1708 is intended primarily for geoscientists in academia, industry, and government who are interested in Appalachian basin geology and its coal and petroleum resources. Other users, however, may find the wide variety of topics, papers, and digital images of value for landuse and policy planning issues. Among the anticipated benefits of the report are improvements in (1) resource assessment estimates and methodology, (2) exploration strategies, (3) basin models, and (4) energy use policies.

Appalachian Basin↗
USGS1998

Coalbed methane resource potential and current prospects in Pennsylvania

Coalbed methane gas content analyses from exploratory coal cores and existing data indicate that gas content generally increases with increasing depth and rank. The coal beds studied are from the Main Bituminous field of Pennsylvania (which currently contains 24 coalbed methane pools) and the Northern and Southern Anthracite coal fields. They range from the Middle Pennsylvanian Allegheny Group to the Late Pennsylvanian-Early Permian Dunkard Group. Previous US Bureau of Mines studies revealed gas contents from 0.4 to 13.8 cm3/g at depths of 99 to 432 m for the bituminous coal beds of the Allegheny Group. More recent core data from the Allegheny Group yielded gas contents from 2.2 to 8.9 cm3/g at depths from 167 to 387 m. In the Anthracite region of eastern Pennsylvania, the little data that are available show that gas content is anomalously high or low. Gas yields from test holes in eastern Pennsylvania are low with or without artificial stimulation mainly due to the lack of a good cleat system. Overall estimates of coalbed methane resources indicate there may be 1.7 Tm3 (61 Tcf) of gas-in-place contained in the Northern Appalachian coal basin. The amount of technically recoverable coalbed methane resources is projected by the US Geological Survey National Oil and Gas Resource Assessment Team [US Geological Survey National Oil and Gas Resource Assessment Team, 1996. 1995 National assessment of United States oil and gas resources-results, methodology, and supporting data, US Geological Survey Digital Data Series DDS-30, CD-ROM, Denver, CO, 80 pp.] and Lyons [Lyons, P.C., 1997. Central-northern Appalachian coalbed methane flow grows. Oil and Gas Journal 95 (27) 76-79] at 0.3 Tm3 (11.48 Tcf). This includes portions of Pennsylvania, Ohio, West Virginia, and a small part of Maryland. Consequently, a mapping investigation was conducted to evaluate the regional geology of the bituminous coal-bearing intervals in southwestern Pennsylvania and its influence on coalbed methane potential. Phase I of this study involved the entire Pennsylvanian coal-bearing interval of southwestern Pennsylvania. Phase II focused on a stratigraphic delineation and evaluation of Allegheny Group coal beds and associated sandstones. Several prospective coal beds and associated facies relationships with channel-fill sandstones were determined. Possible non-coal scenarios for coalbed methane include erosional contacts between coal beds and overlying channel-fill sandstones and areas of stacked channel-fill sandstones. Repetitive sequences of coal accumulation are stacked, commonly with shale interburden, and are also potential coalbed methane targets. Additional Pennsylvania Geological Survey drilling/coalbed methane sampling occurred in Armstrong, Beaver, Cambria, Greene, Lawrence, Somerset, and Washington Counties. Raw coalbed methane desorption data tables/graphical displays of gas contents versus depth, thickness, and time, and average composition and heating values from coal beds of the Allegheny Group to the Dunkard Group are available at the Pennsylvania Geological Survey. Further information on cross-sections, isopleth maps, isopach maps, raw drillhole data, and ownership issues can also be obtained from the same source.A mapping of the regional geology of the bituminous coal-bearing intervals in southwestern Pennsylvania reveal several prospective coal beds and associated facies relationships with channel-fill sandstones. Possible non-coal scenarios for coalbed methane include erosional contacts between coalbeds and overlying channel-fill sandstones and areas of stacked channel-fill sandstones. Repetitive sequences of coal accumulation are stacked, commonly with shale interburden. and are also potential coalbed methane targets.

International Journal of Coal Geology↗
USGS1975

Flows of impact melt at lunar crater

Lavalike materials that were emplaced in a fluid state occur in and around lunar impact craters whose diameters range from 3 km to more than 200 km and whose ages span a time interval of at least 3.5 b.y. Evidence of fluid emplacement includes flow lobes and leveed channels, a veneer mantling rough crater topography, level-surfaced pools, and complex contraction fissuring. The distribution of the lavalike deposits conforms to asymmetries of other ejecta from the same craters, and the material is concentrated downrange to distances as great as a crater radius. The character and distribution of the lavalike materials support the idea that they formed by impact melting rather than by volcanism. Returned samples indicate that materials with appropriate physical characteristics are generated by partial melting of feldspathic rocks by impact. The geologic evidence at lunar craters suggests that there is more melt rock in and near the craters than is predicted by experiment and theory.

Journal of Research of the U.S. Geological Survey↗
USGS2019

Numerical simulations of depressurization-induced gas production from an interbedded turbidite gas hydrate-bearing sedimentary section in the offshore India: Site NGHP-02-16 (Area-B)

The recent National Gas Hydrate Program Expedition 02 (NGHP-02) identified the existence of gas hydrate-bearing sand reservoirs at a number of sites in the offshore of India including Site NGHP-02-16 in Area-B of the Krishna-Godavari Basin. The architecture of that gas hydrate accumulation is characterized by thin, gas hydrate-bearing, high quality sand layers interbedded with mud layers within a turbidite interval. The lowest gas hydrate-bearing layer contacting a thinly-interbedded saline aquifer designates the base of the gas hydrate stability zone (BGHSZ). The proximity of the BGHSZ and the average temperature around 20oC make the reservoir a favorable target for hydrate destabilization by means of the depressurization method. The results of the reservoir simulations indicate high gas production potential from this marine gas hydrate deposit with manageable concomitant water production using a well completion design that hydraulically isolates layers with water-saturated sands. Using a detailed geological input model, the predicted cumulative gas rates reach 3.1 x 104 m3/day (1.1 mmscf/day) after 90 days of continuous depressurization and demonstrate sustained production rates of 3.0 x 104 m3/day (1.0 mmscf/day) after 5 years of production. The interbedded nature of this gas hydrate occurrence promotes the development of horizontal dissociation interfaces between gas hydrate-bearing sand and mud layers. As a result, non-uniform gas production along the horizontal interfaces becomes a primary determinant of reservoir performance. Simulation cases have been executed to determine the impact of the uncertainty in in situ reservoir permeability and the manner in which intrinsic permeability dynamically changes during dissociation in response to the imposed effective stress increase. The cases where effective permeability is initially low and compaction is highly sensitive to stress result in the least favorable production predictions.

Journal of Marine and Petroleum Geology↗
USGS2020

An international code comparison study on coupled thermal, hydrologic and geomechanical processes of natural gas hydrate-bearing sediments

Geologic reservoirs containing gas hydrate occur beneath permafrost environments and within marine continental slope sediments, representing a potentially vast natural gas source. Numerical simulators provide scientists and engineers with tools for understanding how production efficiency depends on the numerous, interdependent (coupled) processes associated with potential production strategies for these gas hydrate reservoirs. Confidence in the modeling and forecasting abilities of these gas hydrate reservoir simulators (GHRSs) grows with successful comparisons against laboratory and field test results, but such results are rare, particularly in natural settings. The hydrate community recognized another approach to building confidence in the GHRS: comparing simulation results between independently developed and executed computer codes on structured problems specifically tailored to the interdependent processes relevant for gas hydrate-bearing systems. The United States Department of Energy, National Energy Technology Laboratory (DOE/NETL), sponsored the first international gas hydrate code comparison study, IGHCCS1, in the early 2000s. IGHCCS1 focused on coupled thermal and hydrologic processes associated with producing gas hydrates from geologic reservoirs via depressurization and thermal stimulation. Subsequently, GHRSs have advanced to model more complex production technologies and incorporate geomechanical processes into the existing framework of coupled thermal and hydrologic modeling. This paper contributes to the validation of these recent GHRS developments by providing results from a second GHRS code comparison study, IGHCCS2, also sponsored by DOE/NETL. IGHCCS2 includes participants from an international collection of universities, research institutes, industry, national laboratories, and national geologic surveys. Study participants developed a series of five benchmark problems principally involving gas hydrate processes with geomechanical components. The five problems range from simple geometries with analytical solutions to a representation of the world’s first offshore production test of methane hydrates, which was conducted with the depressurization method off the coast of Japan. To identify strengths and limitations in the various GHRSs, study participants submitted solutions for the benchmark problems and discussed differing results via teleconferences. The GHRSs evolved over the course of IGHCCS2 as researchers modified their simulators to reflect new insights, lessons learned, and suggested performance enhancements. The five benchmark problems, final sample solutions, and lessons learned that are presented here document the study outcomes and serve as a reference guide for developing and testing gas hydrate reservoir simulators.

Journal of Marine and Petroleum Geology↗
USGS2014

Comparison of the physical and geotechnical properties of gas-hydrate-bearing sediments from offshore India and other gas-hydrate-reservoir systems

The sediment characteristics of hydrate-bearing reservoirs profoundly affect the formation, distribution, and morphology of gas hydrate. The presence and type of gas, porewater chemistry, fluid migration, and subbottom temperature may govern the hydrate formation process, but it is the host sediment that commonly dictates final hydrate habit, and whether hydrate may be economically developed. In this paper, the physical properties of hydrate-bearing regions offshore eastern India (Krishna-Godavari and Mahanadi Basins) and the Andaman Islands, determined from Expedition NGHP-01 cores, are compared to each other, well logs, and published results of other hydrate reservoirs. Properties from the hydrate-free Kerala-Konkan basin off the west coast of India are also presented. Coarser-grained reservoirs (permafrost-related and marine) may contain high gas-hydrate-pore saturations, while finer-grained reservoirs may contain low-saturation disseminated or more complex gas-hydrates, including nodules, layers, and high-angle planar and rotational veins. However, even in these fine-grained sediments, gas hydrate preferentially forms in coarser sediment or fractures, when present. The presence of hydrate in conjunction with other geologic processes may be responsible for sediment porosity being nearly uniform for almost 500 m off the Andaman Islands. Properties of individual NGHP-01 wells and regional trends are discussed in detail. However, comparison of marine and permafrost-related Arctic reservoirs provides insight into the inter-relationships and common traits between physical properties and the morphology of gas-hydrate reservoirs regardless of location. Extrapolation of properties from one location to another also enhances our understanding of gas-hydrate reservoir systems. Grain size and porosity effects on permeability are critical, both locally to trap gas and regionally to provide fluid flow to hydrate reservoirs. Index properties corroborate more advanced consolidation and triaxial strength test results and can be used for predicting behavior in other NGHP-01 regions. Pseudo-overconsolidation is present near the seafloor and is underlain by underconsolidation at depth at some NGHP-01 locations.

Journal of Marine and Petroleum Geology↗
USGS2019

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↗