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USGS2006

Crustal insights from gravity and aeromagnetic analysis: Central North Slope, Alaska

Aeromagnetic and gravity data are processed and interpreted to reveal deep and shallow information about the crustal structure of the central North Slope, Alaska. Regional aeromagnetic anomalies primarily reflect deep crustal features. Regional gravity anomalies are more complex and require detailed analysis. We constrain our geophysical models with seismic data and interpretations along two transects including the Trans-Alaska Crustal Transect. Combined geophysical analysis reveals a remarkable heterogeneity of the pre-Mississippian basement. In the central North Slope, pre-Mississippian basement consists of two distinct geophysical domains. To the southwest, the basement is dense and highly magnetic; this basement is likely mafic and mechanically strong, possibly acting as a buttress to basement involvement in Brooks Range thrusting. To the northeast, the central North Slope basement consists of lower density, moderately magnetic rocks with several discrete regions (intrusions?) of more magnetic rocks. A conjugate set of geophysical trends, northwest-southeast and southwest-northeast, may be a factor in the crustal response to tectonic compression in this domain. High-resolution gravity and aeromagnetic data, where available, reflect details of shallow fault and fold structure. The maps and profile models in this report should provide useful guidelines and complementary information for regional structural studies, particularly in combination with detailed seismic reflection interpretations. Future challenges include collection of high-resolution gravity and aeromagnetic data for the entire North Slope as well as additional deep crustal information from seismic, drilling, and other complementary methods. Copyrights ?? 2006. The American Association of Petroleum Geologists. All rights reserved.

American Association of Petroleum Geologists Bulle↗
USGS2007

Total petroleum system assessment of undiscovered resources in the giant Barnett Shale continuous (unconventional) gas accumulation, Fort Worth Basin, Texas

Undiscovered natural gas having potential for additions to reserves in the Mississippian Barnett Shale of the Fort Worth Basin, north-central Texas, was assessed using the total petroleum system assessment unit concept and a cell-based methodology for continuous-type (Unconventional) resources. The Barnett-Paleozoic total petroleum system is defined in the Bend arch-Fort Worth Basin as encompassing the area in which the organic-rich Barnett is the primary source rock for oil and gas produced from Paleozoic carbonate and clastic reservoirs. Exploration, technology, and drilling in the Barnett Shale play have rapidly evolved in recent years, with about 3500 vertical and 1000 horizontal wells completed in the Barnett through 2005 and more than 85% of the them completed since 1999. Using framework geology and historical production data, assessment of the Barnett Shale was performed by the U.S. Geological Survey using vertical wells at the peak of vertical well completions and before a transition to completions with horizontal wells. The assessment was performed after (1) mapping critical geological and geochemical parameters to define assessment unit areas with future potential, (2) defining distributions of drainage area (cell size) and estimating ultimate recovery per cell, and (3) estimating future success rates. Two assessment units are defined and assessed for the Barnett Shale continuous gas accumulation, resulting in a total mean undiscovered volume having potential for additions to reserves of 26.2 TCFG. The greater Newark East fracture-barrier continuous Barnett Shale gas assessment unit represents a core-producing area where thick, organic-rich, siliceous Barnett Shale is within the thermal window for gas generation (Ro ??? 1.1%) and is overlain and underlain by impermeable limestone barriers (Pennsylvanian Marble Falls Limestone and Ordovician Viola Limestone, respectively) that serve to confine induced fractures during well completion to maximize gas recovery. The extended continuous Barnett Shale gas assessment unit, which had been less explored, defines a geographic area where Barnett Shale is (1) within the thermal window for gas generation, (2) greater than 100 ft (30 m) thick, and (3) where at least one impermeable limestone barrier is absent. Mean undiscovered gas having potential for additions to reserves in the greater Newark East assessment unit is estimated at 14.6 tcf, and in the less tested extended assessment unit, a mean resource is estimated at 11.6 TCFG. A third hypothetical basin-arch Barnett Shale oil assessment unit was defined but not assessed because of a lack of production data. Copyright ?? 2007. The American Association of Petroleum Geologists. All rights reserved.

American Association of Petroleum Geologists Bulle↗
USGS2010

Geochemical constraints on the origin and volume of gas in the New Albany Shale (Devonian-Mississippian), eastern Illinois Basin

This study involved analyses of kerogen petrography, gas desorption, geochemistry, microporosity, and mesoporosity of the New Albany Shale (Devonian-Mississippian) in the eastern part of the Illinois Basin. Specifically, detailed core analysis from two locations, one in Owen County, Indiana, and one in Pike County, Indiana, has been conducted. The gas content in the locations studied was primarily dependent on total organic carbon content and the micropore volume of the shales. Gas origin was assessed using stable isotope geochemistry. Measured and modeled vitrinite reflectance values were compared. Depth of burial and formation water salinity dictated different dominant origins of the gas in place in the two locations studied in detail. The shallower Owen County location (415-433 m [1362-1421 ft] deep) contained significant additions of microbial methane, whereas the Pike County location (832-860 m [2730-2822 ft] deep) was characterized exclusively by thermogenic gas. Despite differences in the gas origin, the total gas in both locations was similar, reaching up to 2.1 cm3/g (66 scf/ton). Lower thermogenic gas content in the shallower location (lower maturity and higher loss of gas related to uplift and leakage via relaxed fractures) was compensated for by the additional generation of microbial methane, which was stimulated by an influx of glacial melt water, inducing brine dilution and microbial inoculation. The characteristics of the shale of the Maquoketa Group (Ordovician) in the Pike County location are briefly discussed to provide a comparison to the New Albany Shale. Copyright ??2010. The American Association of Petroleum Geologists. All rights reserved.

American Association of Petroleum Geologists Bulle↗
USGS2005

Use of relational databases to evaluate regional petroleum accumulation, groundwater flow, and CO2 sequestration in Kansas

Large-scale relational databases and geographic information system tools are used to integrate temperature, pressure, and water geo-chemistry data from numerous wells to better understand regional-scale geothermal and hydrogeological regimes of the lower Paleozoic aquifer systems in the mid-continent and to evaluate their potential for geologic CO2 sequestration. The lower Paleozoic (Cambrian to Mississippian) aquifer systems in Kansas, Missouri, and Oklahoma comprise one of the largest regional-scale saline aquifer systems in North America. Understanding hydrologic conditions and processes of these regional-scale aquifer systems provides insight to the evolution of the various sedimentary basins, migration of hydrocarbons out of the Anadarko and Arkoma basins, and the distribution of Arbuckle petroleum reservoirs across Kansas and provides a basis to evaluate CO2 sequestration potential. The Cambrian and Ordovician stratigraphic units form a saline aquifer that is in hydrologic continuity with the freshwater recharge from the Ozark plateau and along the Nemaha anticline. The hydrologic continuity with areas of freshwater recharge provides an explanation for the apparent underpressure in the Arbuckle Group. Copyright ?? 2005. The American Association of Petroleum Geologists. All rights reserved.

American Association of Petroleum Geologists Bulle↗
USGS2003

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↗
USGS2005

Origin and development of plains-type folds in the mid-continent (United States) during the late Paleozoic

Plains-type folds are local, subtle anticlines formed in the thin sedimentary package overlying a shallow, crystalline basement on the craton. They are small in areal extent (usually less than 1-3 km 2 [0.4-1.2 mi2]), and their amplitude increases with depth (usually tens of meters), which is mainly the result of differential compaction of sediments (usually clastic units) over tilted, rigid, basement fault blocks. The development of these structural features by continuous but intermittent movement of the basement fault blocks in the late Paleozoic in the United States mid-continent is substantiated by a record of stratigraphic and sedimentological evidence. The recurrent structural movement, which reflects adjustment to external stresses, is expressed by the change in thickness of stratigraphic units over the crest of the fold compared to the flanks. By plotting the change in thickness for different stratigraphic units of anticlines on different fault blocks, it is possible to determine the timing of movement of the blocks that reflect structural adjustment. These readjustments are confirmed by sedimentological evidence, such as convolute, soft-sediment deformation features and small intraformational faults. The stratigraphic interval change in thickness for numerous structures in the Cherokee, Forest City, and Salina basins and on the Nemaha anticline of the mid-continent United States was determined and compared for location and timing of the adjustments. Most of the adjustment occurred during and after time of deposition of the Permian-Pennsylvanian clastic units, which, in turn, reflect tectonic disturbance in adjacent areas, and the largest amount of movement on the plains-type structures occurred on those nearest and semiparallel to major positive features, such as the Nemaha anticline. Depending on the time of origin and development of plains-type folds, they may control the entrapment and occurrence of oil and gas. Copyright ??2005. The American Association of Petroleum Geologists. All rights reserved.

American Association of Petroleum Geologists Bulle↗
USGS2019

Petroleum systems framework of significant new oil discoveries in a giant Cretaceous (Aptian–Cenomanian) clinothem in Arctic Alaska

Recent oil discoveries in an Aptian–Cenomanian clinothem in Arctic Alaska demonstrate the potential for hundred-million- to billion-barrel oil accumulations in Nanushuk Formation topsets and Torok Formation foresets–bottomsets. Oil-prone source rocks and the clinothem are draped across the Barrow arch, a structural hinge between the Colville foreland basin and Beaufort Sea rifted margin. Stratigraphic traps lie in a favorable thermal maturity domain along multiple migration pathways across more than 30,000 km 2 (10,000 mi 2 ). Sediment from the Chukotkan orogen (Russia) filled the western Colville basin and spilled over the Beaufort rift shoulder, forming east- and north-facing shelf margins. Progradational shelf-margin trajectories change abruptly to “sawtooth” trajectories at mid-clinothem, the result of reduction in sediment influx. Two stratigraphic trap types are inferred in Nanushuk basal topsets in the eastern part of the clinothem: (1) lowstand systems tracts, inferred to reflect forced regression, include a narrow, thick progradational stacking pattern perched on a sequence boundary on the upper slope; and (2) highstand-progradational systems tracts include a broad, thin wedge of shingled parasequences above a toplap surface. Both include stratigraphically isolated sandstone sealed by mudstone. Trap geometries in Torok foreset and bottomset facies in the same area include basin-floor fan, slope-apron, and slope-channel deposits that pinch out upslope and are sealed by mudstone. Significant potential exists for the discovery of additional oil accumulations in these stratigraphic trap types in the eastern part of the clinothem. Less potential may exist in the western part because reservoir-seal pairs may not be well developed.

American Association of Petroleum Geologists Bulle↗
USGS2005

Petrophysics of Lower Silurian sandstones and integration with the tectonic-stratigraphic framework, Appalachian basin, United States

Petrophysical properties were determined for six facies in Lower Silurian sandstones of the Appalachian basin: fluvial, estuarine, upper shoreface, lower shoreface, tidal channel, and tidal flat. Fluvial sandstones have the highest permeability for a given porosity and exhibit a wide range of porosity (2-18%) and permeability (0.002-450 md). With a transition-zone thickness of only 1-6 m (3-20 ft), fluvial sandstones with permeability greater than 5 md have irreducible water saturation (Siw) less than 20%, typical of many gas reservoirs. Upper shoreface sandstones exhibit good reservoir properties with high porosity (10-21%), high permeability (3-250 md), and low S iw (<20%). Lower shoreface sandstones, which are finer grained, have lower porosity (4-12%), lower permeability (0.0007-4 md), thicker transition zones (6-180 m [20-600 ft]), and higher S iw. In the tidal-channel, tidal-flat, and estuarine facies, low porosity (average < 6%), low permeability (average < 0.02 md), and small pore throats result in large transition zones (30-200 m; 100-650 ft) and high water saturations. The most favorable reservoir petrophysical properties and the best estimated production from the Lower Silurian sandstones are associated with fluvial and upper shoreface facies of incised-valley fills, which we interpret to have formed predominantly in areas of structural recesses that evolved from promontories along a collisional margin during the Taconic orogeny. Although the total thickness of the sandstone may not be as great in these areas, reservoir quality is better than in adjacent structural salients, which is attributed to higher energy depositional processes and shallower maximum burial depth in the recesses than in the salients. Copyright ??2005. The American Association of Petroleum Geologists. All rights reserved.

American Association of Petroleum Geologists Bulle↗
USGS2021

Organic geochemistry and petrology of Devonian shale in eastern Ohio: Implications for petroleum systems assessment

Recent production of light sweet oil has prompted reevaluation of Devonian petroleum systems in the central Appalachian Basin. Upper Devonian Ohio Shale (lower Huron Member) and Middle Devonian Marcellus Shale organic-rich source rocks from eastern Ohio and nearby areas were examined using organic petrography and geochemical analysis of solvent extracts to test ideas related to organic matter sources, oil–source rock correlation, thermal maturity, and distances of petroleum migration. The data from these analyses indicate organic matter in the Ohio and Marcellus Shales primarily was derived from marine algae and its degradation products, including bacterial biomass. Absence of odd-over-even n - alkane distributions (n - C 13 to n - C 21 range) in gas chromatograms and low gammacerane index values in Devonian source rocks are similar to those of Devonian-reservoired oils in eastern Ohio, suggesting an oil–source rock correlation. Lower Paleozoic oils from eastern Ohio, in contrast, are characterized by the presence of odd-over-even n - alkane distributions (n - C 13 to n - C 21 range) and higher gammacerane values, which discriminate them from Devonian shale-derived oils. Thermal maturity estimates from equilibrium(?) biomarker isomerization ratios suggest that some of the Devonian source rock samples are at middle to peak oil window conditions (i.e., approximate vitrinite reflectance values of 0.8%–0.9%). This observation requires local to short-distance (<50 mi) lateral migration for emplacement of Devonian-sourced oils into Devonian reservoirs of eastern Ohio and may impact exploration and assessment of petroleum resources in the Upper Devonian Berea Sandstone.

Ohio↗
USGS2021

Oil–source correlation studies in the shallow Berea Sandstone petroleum system, eastern Kentucky

Shallow production of sweet high-gravity oil from the Upper Devonian Berea Sandstone in northeastern Kentucky has caused the region to become the leading oil producer in the state. Potential nearby source rocks, namely, the overlying Mississippian Sunbury Shale and underlying Ohio Shale, are immature for commercial oil generation according to vitrinite reflectance and programmed pyrolysis analyses. We used organic geochemical measurements from Berea oils and solvent extracts from potential Upper Devonian–Mississippian source rocks to better understand organic matter sources, oil–oil and oil–source rock correlations, and thermal maturity in the shallow Berea oil play. Multiple geochemical proxies suggest Berea oils are from one family and from similar source rocks. Oils and organic matter in the potential source rocks are from a marine source based on pristane-to-phytane (Pr/Ph) and terrestrial-to-aquatic ratios, carbon preference index values, n - alkane maxima, C-isotopic composition, and tricyclic terpane and hopane ratios. Any or all of the Devonian to Mississippian black shale source rocks could be potential source rocks for Berea oils based on similarities in oil and solvent extract Pr/n - C 17 and Ph/n - C 18 ratios, sterane distributions, C-isotopic values, and sterane/hopane and tricyclic terpane ratios. Multiple biomarker ratios suggest Berea oils formed at thermal maturities of approximately 0.7% –0.9% vitrinite reflectance. These data require significant updip lateral migration of 30–50 mi from a downdip Devonian black shale source kitchen to emplace low-sulfur oils in the shallow updip oil-play area and indicate that immature source rocks nearby to Berea oil production are not contributing to produced hydrocarbons.

Kentucky↗
USGS2013

Characterization of oil shale, isolated kerogen, and post-pyrolysis residues using advanced 13 solid-state nuclear magnetic resonance spectroscopy

Characterization of oil shale kerogen and organic residues remaining in postpyrolysis spent shale is critical to the understanding of the oil generation process and approaches to dealing with issues related to spent shale. The chemical structure of organic matter in raw oil shale and spent shale samples was examined in this study using advanced solid-state 13 C nuclear magnetic resonance (NMR) spectroscopy. Oil shale was collected from Mahogany zone outcrops in the Piceance Basin. Five samples were analyzed: (1) raw oil shale, (2) isolated kerogen, (3) oil shale extracted with chloroform, (4) oil shale retorted in an open system at 500°C to mimic surface retorting, and (5) oil shale retorted in a closed system at 360°C to simulate in-situ retorting. The NMR methods applied included quantitative direct polarization with magic-angle spinning at 13 kHz, cross polarization with total sideband suppression, dipolar dephasing, CH n selection, 13 C chemical shift anisotropy filtering, and 1 H- 13 C long-range recoupled dipolar dephasing. The NMR results showed that, relative to the raw oil shale, (1) bitumen extraction and kerogen isolation by demineralization removed some oxygen-containing and alkyl moieties; (2) unpyrolyzed samples had low aromatic condensation; (3) oil shale pyrolysis removed aliphatic moieties, leaving behind residues enriched in aromatic carbon; and (4) oil shale retorted in an open system at 500°C contained larger aromatic clusters and more protonated aromatic moieties than oil shale retorted in a closed system at 360°C, which contained more total aromatic carbon with a wide range of cluster sizes.

American Association of Petroleum Geologists Bulle↗
USGS2006

North Slope, Alaska: Source rock distribution, richness, thermal maturity, and petroleum charge

Four key marine petroleum source rock units were identified, characterized, and mapped in the subsurface to better understand the origin and distribution of petroleum on the North Slope of Alaska. These marine source rocks, from oldest to youngest, include four intervals: (1) Middle-Upper Triassic Shublik Formation, (2) basal condensed section in the Jurassic-Lower Cretaceous Kingak Shale, (3) Cretaceous pebble shale unit, and (4) Cretaceous Hue Shale. Well logs for more than 60 wells and total organic carbon (TOC) and Rock-Eval pyrolysis analyses for 1183 samples in 125 well penetrations of the source rocks were used to map the present-day thickness of each source rock and the quantity (TOC), quality (hydrogen index), and thermal maturity (Tmax) of the organic matter. Based on assumptions related to carbon mass balance and regional distributions of TOC, the present-day source rock quantity and quality maps were used to determine the extent of fractional conversion of the kerogen to petroleum and to map the original TOC (TOCo) and the original hydrogen index (HIo) prior to thermal maturation. The quantity and quality of oil-prone organic matter in Shublik Formation source rock generally exceeded that of the other units prior to thermal maturation (commonly TOCo > 4 wt.% and HIo > 600 mg hydrocarbon/g TOC), although all are likely sources for at least some petroleum on the North Slope. We used Rock-Eval and hydrous pyrolysis methods to calculate expulsion factors and petroleum charge for each of the four source rocks in the study area. Without attempting to identify the correct methods, we conclude that calculations based on Rock-Eval pyrolysis overestimate expulsion factors and petroleum charge because low pressure and rapid removal of thermally cracked products by the carrier gas retards cross-linking and pyrobitumen formation that is otherwise favored by natural burial maturation. Expulsion factors and petroleum charge based on hydrous pyrolysis may also be high compared to nature for a similar reason. Copyright ?? 2006. The American Association of Petroleum Geologists. All rights reserved.

American Association of Petroleum Geologists Bulle↗
USGS1957

Franciscan group in Coast Ranges and its equivalents in Sacramento Valley, California

The Franciscan group is an assemblage of detrital and chemical sedimentary and volcanic rocks that crops out discontinuously in a structurally complex, northwesterly trending belt along the Coast Ranges of Cahfornia. On the east, along the west side of the Sacramento Valley, a thick section of detrital sedimentary rocks has been subdivided into the Knoxville, Paskenta, and Horsetown forma tions of Late Jurassic and Early Cretaceous age, and several units of early Late Cretaceous age. The Sacramento Valley section represents deposition during most of the time from Late Jurassic to early Late Cretaceous. The Franciscan group is widely held to be restricted to Late Jurassic age, the Knoxville formation to be an upper shaly phase of the Franciscan group, and the two to be overlain unconformably by detrital strata of Cretaceous age. Sparse paleontologic evidence indicates this view to be incorrect. Rather, the Franciscan group seems mainly to have been deposited contemporaneously with the Knoxville, Paskenta, Horsetown, and lower Upper Cretaceous strata, as fossils ranging from Late Jurassic to early Late Cretaceous in age have been found in the Franciscan group. The Franciscan group and strata of the Sacramento Valley section therefore may represent two fades of the same stratigraphic section.

California↗
USGS1959

K-feldspar content of Jurassic and Cretaceous graywackes of northern Coast Ranges and Sacramento Valley, California

Graywackes of Late Jurassic to Late Cretaceous age are the predominant rocks in the northern Coast Ranges and the western Sacramento Valley provinces in California. These graywackes are similar in appearance, but their content of K-feldspar, which can be readily estimated after selective staining, differs widely. Study of several hundred specimens indicates that K-feldspar content is helpful in correlating or distinguishing these rocks, and sheds light on the geologic history of western California. In the Sacramento Valley a conformable sequence of Knoxville (Upper Jurassic), Shasta (Lower Cretaceous), and Upper Cretaceous rocks progressively increases in average K-feldspar content with decreasing age. Graywackes of the Franciscan formation, lying in the Coast Ranges farther west, generally contain no K-feldspar, although some contain a trace, and a few of more uncertain affiliation contain large amounts. Another belt of graywackes, west of the Franciscan formation and paralleling the Pacific shore, contains nearly as much K-feldspar as the Upper Cretaceous rocks of the Sacramento Valley, and most of these rocks are probably of middle Cretaceous age. The writers attribute the increase of K-feldspar with decreasing age of the rocks of the Sacramento Valley to changes in the source area, which is believed to be the Klamath Mountains and the Sierra Nevada. The changes include an increase in proportion of granitic rocks to others as the areas were stripped, and more abundant K-feldspar in the younger granitic rocks. The high K-feldspar content in the middle Cretaceous rocks of the coastal belt suggests that the rocks were deposited in the same basin as the Sacramento Valley rocks.

California↗
USGS1990

Occurrence and geochemistry of natural gases, Piceance Basin, northwest Colorado

The Piceance basin is a hydrocarbon-rich province that has natural gas production from reservoirs ranging in age from Late Jurassic to Eocene and large undeveloped resources of natural gas in coal beds and tight sandstone reservoirs of Cretaceous age. Gases from all producing intervals are of predominantly thermal origin and become isotopically heavier (delta isotope{13}C[1]: -51.3 to -29.1 o/oo) and chemically drier (C[1]/C[1-5]: 0.26 to 1.00) with increasing thermal maturity of reservoirs (R[o]: 0.45 to 2.40%) over a depth range of 1100 to 11,702 ft (335-3567 m). Scatter in trend is attributed to source rock differences and considerable vertical and lateral migration. Based on chemical and isotopic composition, three major types of gases can be distinguished: those generated from mixed type II and III kerogens, those from dispersed type III kerogen, and those from coal. Gases generated from mixed type II and III kerogens are produced from the Upper Jurassic Morrison Formation, the Lower Cretaceous Cedar Mountain Formation, the Upper Cretaceous Dakota Sandstone, the Upper Cretaceous Mancos "B" producing interval, and marginal marine sandstones of the Upper Cretaceous Iles producing interval. These gases are associated with minor amounts of oil and probably were generated from kerogen in the marine Mancos Shale. Gases generated from dispersed type III kerogen are produced from nonmarine sandstones of the Upper Cretaceous Williams Fork producing inter al and from thermally immature reservoirs in the overlying Paleocene and Eocene Fort Union and Wasatch Formations. These nonassociated gases contain large amounts of CO[2] and probably were generated from carbonaceous shales in the Williams Fork producing interval. Their presence in immature Fort Union and Wasatch reservoirs implies considerable vertical migration. The third type of gas is methane rich, is produced by devolatilization of humic coal, and is generally in coal beds of the Cameo-Fairfield zone of the Williams Fork producing interval. These gases are not the major source for adjacent sandstone reservoirs. A fourth, distinct type of isotopically light thermogenic gas occurs in immature reservoirs of the Eocene Green River Formation. This gas is inferred to have migrated from u identified deeper, more mature source rocks.

Colorado↗
USGS1991

Late Laramide thrust-related and evaporite-domed anticlines in the southern Piceance Basin, northeastern Colorado Plateau

New seismic and gravity data across the hydrocarbon-producing Divide Creek and Wolf Creek anticlines in the southern Piceance basin reveal contrasting styles of deformation within two widely separated time frames. Seismic data indicate that prebasin Paleozoic deformation resulted in block faulting of the Precambrian crystalline basement rocks and overlying Cambrian through Middle Pennsylvanian strata. Movement along these block faults throughout much of Pennsylvanian time, during northeast-southwest crustal extension, likely influenced distribution of the Middle Pennsylvanian (Desmoinesian) evaporite-rich facies. Younger rocks, including the thick succession of Cenozoic basin strata, then buried the Paleozoic structures. Tectonic reconfiguration of the basin's eastern margin occurred during late Laramide northeast-southwest compression, when a basement-involved thrust block, whose surface expression is the Grand Hogback monocline, moved into the Piceance basin. A decollement developed in front of the thrust block within the mechanically weak Desmoinesian evaporites and splayed out basinward as small-scale imbricate thrusts in the Upper Cretaceous Mancos Shale. The Divide Creek anticline formed above these splays as thrusting locally overthickened the shale and repeated the sandstone units between it and the evaporites. The Wolf Creek anticline to the east, however, is due to both depositional and tectonic thickening of the evaporite section along the decollement. Gravity data confirm that excess mater al of relatively low density exists beneath the Wolf Creek structure, whereas material of relatively higher density (overthickened shale) is found beneath the Divide Creek anticline. Thrust-related basin margins and intrabasin folds structurally analogous to the Divide Creek and Wolf Creek anticlines may be more common than presently recognized in the Rocky Mountain foreland. One well-documented example is the Pinedale anticline in the northern Green River basin, Wyoming, which, like the Divide Creek anticline, developed above a zone of splay faults from a decollement in front of a large thrust block.

Colorado↗
USGS1991

An analysis of a seismic reflection from the base of a gas hydrate zone, offshore Peru

Seismic reflection data recorded near ODP Site 688, offshore Peru, exhibit a persistent bottom-simulating reflector (BSR) from a depth corresponding to the theoretical base of the gas hydrate stability field. Although gas hydrate has been recovered in cores from scientific drilling in both the Pacific and the Atlantic, drilling in areas exhibiting a BSR has usually been avoided because of the perceived risk of releasing free gas trapped beneath the hydrated sediments. To carry out a quantitative analysis of the BSR, the seismic data were reprocessed using signature deconvolution and true amplitude recovery techniques. Synthetic seismograms that were created using acoustic parameters extracted from the seismic data and physical properties from Site 688 borehole measurement were compared to the observed seismic data to estimate the thickness of the free-gas zone. Results indicate the BSR is discontinuous laterally. Where the BSR is of high amplitude, free gas in a zone 5.5-17 m thick beneath the hydrated sediments provides the observed waveform; where the BSR amplitude is low, the free-gas zone is much thinner than 5.5 m or is entirely absent.

American Association of Petroleum Geologists Bulle↗