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At least 37 records · Page 2Linked to original sources
USGS2019

Formation pressure and fluid flow measurements in marine gas hydrate reservoirs, NGHP-02 expedition, offshore India

Open Hole Modular Dynamic Testing (MDT) measurements were conducted in a gas hydrate-bearing sand-rich reservoir offshore India during the National Gas Hydrate Program 02 (NGHP-02) Expedition. The primary goal of this test was to obtain effective reservoir petrophysical properties in the presence of gas hydrates. The test plan included a series of pre-hydrate dissociation flow and build-up (shut-in) tests, and an attempt to dissociate gas hydrate in a sand-rich reservoir by depressurization to collect formation fluid samples and to further characterize in situ gas hydrate stability conditions. Schlumberger’s wireline MDT tool was used in a dual-packer configuration to isolate the formation being tested. This paper presents the results of the open hole MDT measurements that were conducted in Hole NGHP-02-23-C in Krishna-Godavari Basin at a water depth of 2553.5 m. The MDT dual packer test was conducted in 27 cm (10.63 in) diameter open hole section of the borehole within a 1-m interval isolated between two inflatable packers with the midpoint of the test interval at 2853.0 meter below rig floor (mbrf) (271.0 meter below sea floor (mbsf)). This was the first gas hydrate MDT test ever conducted in ultradeep water to characterize a gas hydrate reservoir system. Pre-hydrate dissociation testing was performed with a drawdown period (depressurization) of 20 minutes followed by a build-up (shut-in) of 20 minutes. The measured formation pressure was 4090.7 psia and the formation fluid (i.e., water) mobility was calculated at 1.98 mD/cP. During the second dissociation phase of the same test a maximum pressure drawdown of 840 psia was achieved; however, falling short of the 1120 psia drawdown required for dissociation. During the dissociation test the flow line pressure stabilized at a flowing pressure of 3250 psia which can be attributed to the relatively high mobility of the free water phase in the hydrate-bearing reservoir. Good quality formation pressure and near well bore mobility data was acquired that yielded a “high confidence” reservoir effective radial permeability-thickness product of 0.2 mD.m (or a horizontal effective permeability of 0.1 mD assuming a reservoir thicknees of 1.8 m) using pressure transient analysis (radial flow regime was achieved) despite unstable borehole conditions and complex operations in these shallow unconsolidated sedimentary sections.

Journal of Marine and Petroleum Geology↗
USGS2021

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

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

Alaska↗
USGS2022

Diatom influence on the production characteristics of hydrate-bearing sediments: Examples from Ulleung Basin, offshore South Korea

The Ulleung Basin Gas Hydrate field expeditions in 2007 (UBGH1) and 2010 (UBGH2) sought to assess the Basin's gas hydrate resource potential. Coring operations in both expeditions recovered evidence of gas hydrate, primarily as fracture-filling (or vein type) morphologies in mainly silt-sized, fine-grained sediment, but also as pore-occupying hydrate in the coarser-grained layers of interbedded sand and fine-grained systems. A commonality across many of these occurrences is the presence of diatoms in the fine-grained sediment. Here we tested fine-grained sediment (median grain size <12.5 μm) associated with hydrate occurrences at four UBGH2 sites (UBGH2-2-2, UBGH2-3, UBGH2-6 and UBGH2-11) to investigate potential impacts of diatoms on efforts to extract methane from hydrate, or to tap hydrocarbon reservoirs beneath hydrate-bearing sediment. Two key considerations are: the extent to which diatoms control sediment mechanical properties, and the extent to which pore-water freshening, which occurs as gas hydrate breaks down during resource extraction, alters the diatom control on sediment mechanical properties. We conducted experiments to measure sediment index properties, sedimentation behavior and compressibility to address these considerations. We relied on scanning electron microscope (SEM) imagery and X-ray powder diffraction (XRD) to characterize the sediment mineralogy. Our high-level findings are that at the ∼20–45% (by volume) diatom concentrations observed at these UBGH2 sites, sediment compressibility increases with diatom content, but diatoms only appear to increase porosity and permeability at the highest diatom concentration (∼45%). Our measurements suggest in situ compression indices of 0.35–0.55 and permeabilities on the order of 0.01milliDarcies (1 × 10 −17 m 2 ) can be anticipated at these sites. Importantly, these properties are not expected to vary significantly upon pore water freshening that accompanies gas hydrate dissociation during production.

East Sea, Ulleung Basin↗
USGS2023

Characterization of a complex sand-rich gas hydrate reservoir system in the Indian marine continental margin with downhole log and seismic data

Logging-while-drilling (LWD) and coring data were acquired in Areas A, B, C and E during the National Gas Hydrate Program Expedition 02 (NGHP-02). At Sites NGHP-02-16, −17, −20, −23 and −24 of Area B in the Indian Krishna-Godavari Basin, the gas hydrate-bearing sand-rich reservoirs directly in contact with an underlying water-saturated sediment were revealed near the seismic-inferred bottom simulating reflector (BSR) along a large anticlinal structure. Lithofacies analysis of cores show that the lower gas hydrate-bearing reservoir section at these sites is an interbedded unit with thin fine-sand layers alternating with clay-rich layers. We reanalyzed the LWD data including resistivity, compressional-wave and shear-wave acoustic velocities to assess and compare the spatial variation of sand-hosted gas hydrate and possible related free-gas accumulations. The presence of free gas-bearing sediments in direct contact with gas hydrate-bearing sediments was confirmed at Sites NGHP-02-20 and −24 along the northeastern flank of the anticline. The sand-rich reservoirs associated with the Area B anticlinal feature reveal different pore-filling constituents and variable boundary conditions, including gas hydrate/water contacts and gas hydrate/free gas contacts. We infer that the sedimentary depositional history at Sites NGHP-02-20 and −24, may have resulted in an upward shift of the base of gas hydrate stability zone, that could have led to in situ gas hydrate dissociation and the accumulation of free gas and coexistence interval below the log-inferred gas hydrate-bearing reservoir sections. This study demonstrates that reservoir heterogeneity and fluid migration were major factors affecting the distribution of gas hydrate and free gas in the identified sand-rich reservoirs.

Journal of Marine and Petroleum Geology↗
USGS2014

Coal and petroleum resources in the Appalachian basin: distribution, geologic framework, and geochemical character

Fossil fuels from the Appalachian basin region have been major contributors to the Nation&rsquo;s energy supplies over much of the last three centuries. Appalachian coal and petroleum resources are still available in sufficient quantities to contribute significantly to fulfilling the Nation&rsquo;s energy needs. Although both conventional 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. 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. This publication supplements and updates older USGS regional studies of Appalachian basin coal and petroleum resources. Some chapters are new, and several 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 pertain to large segments of the basin and a wide range of stratigraphic intervals. This volume discusses 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 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 from chapter I.1 as downloadable geographic information system (GIS) data files about the characteristics of selected coal beds and 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 are included in other chapters. 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 topics, papers, and digital images valuable for land-use and policy planning. 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↗
USGS1976

Sedimentary depositional environments of uranium and petroleum host rocks of the Jackson Group, south Texas

Determination of depositional environments in rocks of the Jackson Group of late Eocene age aids in the exploration for uranium and petroleum in south Texas. During deposition of the Jackson Group, conditions were similar to those existing along the modern Gulf Coast of Texas except for a less arid climate and a greater supply of volcanic sediment. Sedimentary depositional environments recognized in both the modern coast and the Jackson rocks, in order from sea toward land, are: shoreface, beach, lagoon and bay, and paludal. Sediment deposited in these environments in places is interbedded with or transected by fluvial sediment. Both uranium and petroleum are found in the shoreface, beach, and fluvial facies. These facies are characterized by permeable well-sorted sandstone, which is commonly overlain and underlain by less permeable mudstone. A typical vertical sequence in ascending order through a unit containing a beach sandstone facies is (1) lagoonal or paludal clay stone and siltstone, (2) crossbedded fine-grained beach sandstone which contains Ophiomorpha burrows and, which, in places, is locally interbedded with lacustrine or lagoonal mudstone, (3) weakly laminated beach sandstone which contains root impressions at the top and Ophiomorpha , and (4) lagoonal or paludal claystone and siltstone. Gulfward, the beach sandstone apparently grades into highly burrowed, generally finer grained, more poorly sorted, less porous shoreface rocks. The beach facies may include barrier island beaches and mainland beaches, some of which were probably cheniers. Beach facies sandstone units extend many miles along the depositional strike, which nearly parallels the present outcrop strike, but extend only a mile or two (2-3 km) normal to the depositional strike into the subsurface. Recognition of the various facies in outcrops and drill holes is necessary for determination of true stratigraphic relations and for aid in exploration for beach and fluvial sandstone favorable for uranium and petroleum accumulations.

Texas↗
USGS1994

Crude-oil spill research project near Bemidji, Minnesota - Bibliography, 1984-1994

The U.S. Geological Survey began a research project at the site of a crude-oil spill near Bemidji, Minnesota in 1983. The project is part of the U.S. Geological Survey's Toxic Substances Hydrology Program. The objectives of research at the site are to obtain an understanding of the mobilization, transport, and fate of petroleum derivatives in the shallow subsurface and to use this understanding to develop predictive models of contaminant behavior. This report presents a bibliography of scientific papers that have been published from 1984 to early 1994. Research results have been published in scientific journals, conference proceedings, U.S. Geological Survey Reports, and academic theses.

Open-File Report↗
USGS2003

Probabilistic assessment methodology for continuous-type petroleum accumulations

The analytic resource assessment method, called ACCESS (Analytic Cell-based Continuous Energy Spreadsheet System), was developed to calculate estimates of petroleum resources for the geologic assessment model, called FORSPAN, in continuous-type petroleum accumulations. The ACCESS method is based upon mathematical equations derived from probability theory in the form of a computer spreadsheet system. ?? 2003 Elsevier B.V. All rights reserved.

International Journal of Coal Geology↗
USGS1973

Problems of underground storage of wastes

Problems of underground storage of waste involve geology in its broadest sense, including hydrology, geochemistry, and geophysics. Wastes may be solid, liquid, or gaseous, and they may be chemically toxic or noxious, esthetically offensive, or radioactive. Some wastes require only temporary containment, whereas others must be isolated for indefinitely long periods. The means and locale for emplacement underground depend upon many governing geological factors, including the physical, chemical, hydrological, and hydraulic properties of the host formation. These must be studied relative to the physical, chemical, and thermal properties of the waste and of potential interactions between the waste and the host formation. Thorough knowledge is essential because lack of it may lead to undesirable or disastrous environmental consequences. Escape of waste may contaminate the surface or near-surface environment; it may destroy the usefulness or accessibility of resources such as ground water, petroleum, and minerals. Effective management of underground waste requires adaptation of current technology and development of new technology.

Journal of Research of the U.S. Geological Survey↗
USGS2020

Fluorescence spectroscopy of ancient sedimentary organic matter via confocal laser scanning microscopy (CLSM)

Fluorescence spectroscopy via confocal laser scanning microscopy (CLSM) was used to analyze ancient sedimentary organic matter, including Tasmanites microfossils in Devonian shale and Gloecapsomorpha prisca ( G. prisca ) in Ordovician kukersite from North American basins. We examined fluorescence emission as a function of excitation laser wavelength, sample orientation, and with respect to location within individual organic entities and in transects across bedded organic matter. Results from spectral scans of the same field of view in Tasmanites with different laser lines showed progressive red-shift in emission maxima with longer excitation wavelengths. This result indicates steady-state Tasmanites fluorescence emission is an overlapping combination of emission from multiple fluorophore functions. Stokes shift decreased with increasing excitation wavelength, further suggesting the presence of multiple fluorophore functions with different S 1 → S 0 transition energies. This observation also indicates that at longer excitation wavelengths, less absorbed light energy is dissipated via collisional transfer than at shorter excitation wavelengths and may suggest fewer polar functions are preferentially absorbing. Confirming earlier results, emission spectra observed from high fluorescence intensity regions (fold apices) in individual Tasmanites are blue-shifted relative to emission from other locations in the same microfossil. We suggest high intensity emission is from photoselective alignment of polarized excitation with the fluorophore absorption and emission transition moment. The blue shift observed in regions of high intensity emission may be due to relative absence or realignment of polar species, e.g., bridging ether or ester functions, although variations in O abundance could not be confirmed with preliminary time-of-flight secondary ion mass spectrometry (TOF-SIMS) analysis. Tasmanites occurring in consolidated sediments are flattened from original spherical morphology and, in optical microscopy, this burial deformation results in generally parallel extinction (strain-influenced) and positive elongation. The deformation also induces fluorescence anisotropy observed as variations in emission wavelength when individual Tasmanites are measured from their long axis parallel to bedding, whereas this effect is absent in bedding-normal view. Transects from G. prisca -rich source layers into adjacent reservoir layers show decrease in fluorescence intensity and spectral red-shift (increase in full-width half-maximum with increasing red portion of the half-width). These results may suggest an increase in fluorescence quenching across the source-to-reservoir transition zone, consistent with an increase in aromaticity following petroleum expulsion and migration. These observations are supported by increasing reflectance values measured across similar micro-scale transects. Our results highlight the applicability of CLSM as a broad and under-utilized approach for the characterization of sedimentary organic matter and are discussed with perspective toward petroleum processes and thermal indices research.

International Journal of Coal Geology↗
USGS1997

U.S. Geological Survey Studies of Energy Resources in Sub-Saharan Africa

The U.S. Government and the American public need access to information on energy resources in sub-Saharan Africa. Sub-Saharan Africa (mostly Nigeria) produces 5 percent of the world's oil, while supplying the United States with 15 percent of our imports (Energy Information Administration). In the next 10 years, sub-Saharan oil and gas will become increasingly more important to the export market. New discoveries in offshore provinces of West Africa ensure a bright future for the region. Projections indicate that increased oil production in sub-Saharan Africa will far outpace the growth of intraregional consumption, providing greater quantities of oil for export (Forman, 1996). Also, West Africa, although a marginal supplier of liquefied natural gas (LNG) today, will become an important LNG source to the international market by the year 2000 (Oil & Gas Journal, 1996). The United States needs up-to-date information about petroleum resources and the energy balance within the region to predict the future role of sub-Saharan Africa as a major oil and gas exporter. The data required to generate the needed information are often disseminated in archives of oil companies and African geologic surveys, or in obscure publications. For these reasons, the U.S. Geological Survey is collecting data on sub-Saharan energy and constructing a regional energy bibliography. The team of geoscientists will assure that this information is available quickly and from a scientifically based, objective view point.

Fact Sheet↗
USGS2001

Report list Arizona's oil, gas potential

This article is a summary of Arizona geological survey circular 29, which addresses the petroleum geology of Arizona, USA. Eight areas have been identified with fair to excellent oil and gas potential, and some Tertiary basins have evidence of source or reservoir rocks. The following are considered here: production history, lands status and services, regulation and permitting, petroleum geology, hydrocarbon indications, and areas with hydrocarbon potential and their petroleum geology and characteristics. The full report contains detailed figures of each of these basin areas, a descriptive tabulation of seeps and petroliferous rocks and extensive references.

Arizona↗
USGS2014

Executive summary

Fossil fuels from the Appalachian basin region have been major contributors to the Nation&rsquo;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&rsquo;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&minus;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↗
USGS2024

Novel insights about petroleum systems from source and reservoir rock characterization, Cretaceous Deposits, Babouri-Figuil Basin, Northern Cameroon

The Babouri-Figuil Basin (BFB) is a frontier basin for petroleum in Cameroon. It belongs to the series of Cretaceous rift basins of the West and Central Rift System (WCARS), the origin of which is related to the opening of the South Atlantic. Within the same rift system, commercial hydrocarbon accumulations have been discovered in Chad, Sudan, Niger and, more recently, in Nigeria (Gongola Basin). The study of the geology of the BFB just recently received considerable attention, mainly because of its presumed hydrocarbon potential. In the pursuit of researching possible petroleum systems in the BFB, the current study provides a first look into the characterization of source and reservoir rock and its integration into a 2D lithostratigraphic model. The study was solely based on outcrop samples. Black shale and massive claystone are good to excellent hydrocarbon source rocks [e.g., up to 38 wt% total organic carbon (TOC), up to 943 mg/g hydrogen index, up to 85 m thickness, up to 20–30 km lateral extension], with moderate to high values of extractable organic matter (e.g., >10,000 ppm). Calcareous claystone, on the other hand, are poor source rocks [e.g., <0.20 wt% TOC]. The samples are thermally immature, except for those located close to volcanic intrusion at Golombe that have reached the threshold for oil generation (Tmax >435 °C, production index >0.1). The petrographic analysis of sandstone revealed that they are fine-grained to coarse-grained, poorly to moderately sorted, texturally and compositionally immature to submature, subarkosic to arkosic arenites. The main diagenetic processes that affected sandstones are as follows: moderate to intense compaction characterized by the development of long, concavo-convex, and sutured contacts between grains; cementation through calcite, iron oxide, and quartz cements; alteration of mica and feldspar grains; partial to complete dissolution of feldspar, mica, amphibole grains, and calcite cement; and the replacement of feldspar and mica grains by clay minerals. Alteration and dissolution increase the porosity of sandstone through the creation of secondary pores. However, mechanical compaction through the development of a pseudomatrix and cementation as pore-filling materials have significantly reduced the quality of sandstone beds as conventional petroleum reservoirs. Hence, the best reservoir-quality sandstones in the basin are generally located in the upper portion of the basin in terms of its lithostratigraphic model. They are the cleanest sandstones with the smallest amount of cement and the lowest ductile grain content (pseudomatrix), with a thickness that varies from 3 m to 120 m and a lateral extension of 20 km. The lithostratigraphic model of the basin is characterized by an extensive lacustrine environment that provided a thick sequence of organic-rich formations; sand deposited as extensive reservoirs sandwiched between shale/claystone beds; the development of stratigraphic traps through lateral facies change; and the widespread deposition of lacustrine and floodplain claystone that provide regional seals. The similarities between the Babouri-Figuil Basin and proven petroleum systems in other WCARS rift basins suggest that the basin may host at least one petroleum system where actively generating source rocks are present.

Babouri-Figuil Basin↗
USGS2024

Characterization of the structural–stratigraphic and reservoir controls on the occurrence of gas hydrates in the Eileen Gas Hydrate Trend, Alaska North Slope

One of the most studied permafrost-associated gas hydrate accumulations in Arctic Alaska is the Eileen Gas Hydrate Trend. This study provides a detailed re-examination of the Eileen Gas Hydrate Trend with a focus on the gas hydrate accumulation in the western part of the Prudhoe Bay Unit. This integrated analysis of downhole well log data and published geophysical data has provided new insight on structural, stratigraphic, and reservoir controls on the occurrence of gas hydrates in the Eileen Gas Hydrate Trend. This study revealed the relatively complex nature of the gas hydrate occurrences in the Eileen Gas Hydrate Trend, with gas hydrates present in a series of coarsening upward, laterally pervasive, mostly fine-grained sand beds exhibiting high gas hydrate saturations. Most of the gas hydrate-bearing reservoirs in the Eileen Gas Hydrate Trend are laterally segmented into distinct northwest- to southeast-trending fault blocks, occur in a combination of structural–stratigraphic traps, and are only partially hydrate filled with distinct down-dip water contacts. These findings suggest that the traditional parts of a petroleum system (i.e., reservoir, gas source, gas migration, and geologic timing of the system formation) also control the occurrence of gas hydrates in the Eileen Gas Hydrate Trend.

Alaska↗
USGS2000

Diagenesis of the Purington Shale in the Illinois Basin and implications for the diagenetic state of sedimentary rocks of shallow Paleozoic basins

The clay minerals, micas, and feldspars of the Pennsylvanian-age Purington Shale have been more diagenetically active than generally recognized. They have undergone diagenetic changes comparable to those of Cenozoic and Mesozoic sedimentary rocks buried three to four times as deeply and heated to approximately twice the temperature. The Purington Shale on the Western Shelf of the Illinois Basin has experienced maximum burial of ???1.0 km and was never heated to more than 60??C, except for a very brief time at about 80??C. The illite/smectite (I/S) of the Purington Shale has ???90% illite. The chemical compositions of the feldspar assemblage in the 0.09-0.063-mm fraction differ from most modern detrital suites of feldspars but are similar to diagenetic sequences described by others from much greater burial depths and are extensively, but not completely, albitized. The simplest interpretation of the apparently advanced stage of diagenesis is that the diagenetic processes have been operating at less pressure and lower temperature but for a longer time; an example of low-temperature, time-dependent diagenesis. By similar reasoning, the apparently anomalously advanced maturity of all of the sedimentary rocks in the relatively shallow Illinois Basin is explained. This generalization should be considered for all shallow Paleozoic basins and should influence (1) exploration for petroleum, (2) use of modal and chemical analyses for determining provenance, and (3) use of chemical composition of shales as proxy for crustal evolution.

Journal of Geology↗
USGS2012

Modeling the mesozoic-cenozoic structural evolution of east texas

The U.S. Geological Survey (USGS) recently assessed the undiscovered technically recoverable oil and gas resources within Jurassic and Cretaceous strata of the onshore coastal plain and State waters of the U.S. Gulf Coast. Regional 2D seismic lines for key parts of the Gulf Coast basin were interpreted in order to examine the evolution of structural traps and the burial history of petroleum source rocks. Interpretation and structural modeling of seismic lines from eastern Texas provide insights into the structural evolution of this part of the Gulf of Mexico basin. Since completing the assessment, the USGS has acquired additional regional seismic lines in east Texas; interpretation of these new lines, which extend from the Texas-Oklahoma state line to the Gulf Coast shoreline, show how some of the region's prominent structural elements (e.g., the Talco and Mount Enterprise fault zones, the East Texas salt basin, and the Houston diapir province) vary along strike. The interpretations also indicate that unexplored structures may lie beneath the current drilling floor. Structural restorations based upon interpretation of these lines illustrate the evolution of key structures and show the genetic relation between structural growth and movement of the Jurassic Louann Salt. 1D thermal models that integrate kinetics and burial histories were also created for the region's two primary petroleum source rocks, the Oxfordian Smackover Formation and the Cenomanian-Turonian Eagle Ford Shale. Integrating results from the thermal models with the structural restorations provides insights into the distribution and timing of petroleum expulsion from the Smackover Formation and Eagle Ford Shale in eastern Texas.

Texas↗