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At least 91 records · Page 5Linked to original sources
USGS1995

Beyond the petroleum system: GEOHORIZONS

The first joint AAPG/AMGP (Association of Mexican Petroleum Geologists) Hedberg Conference on “Geologic Aspects of Petroleum Systems” was held October 2–6, 1994, in Mexico City, Mexico. This research conference attracted nearly 150 geoscientists from 15 countries; 41 papers and 27 posters were presented. The opposite response occurred when the petroleum-system concept was presented more than 20 yr ago; it was largely overlooked. In the past decade, however, interest in this concept as an exploration tool has been growing rapidly. The research conference addressed the concept itself, its elements and processes, the tools and methods used to identify a petroleum system, and many case studies. We summarize responses by the participants to the following three questions. First, what is gained from using the petroleum-system concept? Second, in what new directions will the petroleum-system concept take us in the future? Third, has anything new come out of this research conference?

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↗
USGS2014

Upper Devonian–Mississippian stratigraphic framework of the Arkoma Basin and distribution of potential source-rock facies in the Woodford–Chattanooga and Fayetteville–Caney shale-gas systems

Wireline logs were used to document the stratigraphic framework of Upper Devonian–Mississippian strata in the Arkoma Basin, and maps of high-gamma ray (HGR) log response were used to analyze the spatial distribution of potential source rocks in the Woodford–Chattanooga and Fayetteville–Caney shale-gas systems. The Woodford–Chattanooga shale is a transgressive deposit that accumulated on an arid continental margin influenced by marine upwelling and minimal sediment influx. A broad HGR depocenter along the southwestern margin of the basin includes two areas of higher accommodation containing the thickest HGR concentrations. Basin-wide patterns of HGR likely reflect broad tectonic influence on accommodation. The proportion of chert in the formation increases eastward and southward, likely reflecting latitudinal and bathymetric influence on the accumulation of siliceous ooze. The Lower Mississippian Burlington sequence, which lies between the two shale-gas systems, comprises carbonate ramp and distal shale deposits. Proximal ramp facies form an apron around the southern flank of the Ozark uplift and grade radially basinward into distal facies. An Upper Mississippian succession in the east includes lowstand deposits of the Batesville delta, which onlap the relict Burlington ramp. Basinwide, the succession includes the transgressive Fayetteville–Caney shale overlain by regressive deposits of the proximal Pitkin Limestone and distal upper Fayetteville (Arkansas) and “false” Caney (Oklahoma) shale. The HGR shale is concentrated in an area of intermediate accommodation on the western margin of the Mississippi Embayment and just basinward of the Pitkin Limestone pinchout in Arkansas, and in an area of relatively high accommodation in Oklahoma.

Arkansas, Oklahoma↗
USGS1981

Petroleum geology of Cook Inlet basin: An exploration model

Oil exploration commenced onshore adjacent to lower Cook Inlet on the Iniskin Peninsula in 1900, shifted with considerable success to upper Cook Inlet from 1957 through 1965, then returned to lower Cook Inlet in 1977 with the COST well and Federal OCS sale. Lower Cook Inlet COST No. 1 well, drilled to a total depth of 3,775.6 m, penetrated basinwide unconformities at the tops of Upper Cretaceous, Lower Cretaceous, and Upper Jurassic strata at 797.1, 1,540.8, and 2,112.3 m, respectively. Sandstone of potential reservoir quality is present in the Cretaceous and lower Tertiary rocks. All siltstones and shales analyzed are low (0 to 0.5 wt. %) in oil-prone organic matter, and only coals are high in humic organic matter. At total depth, vitrinite readings reached a maximum ave age reflectance of 0.65. Several indications of hydrocarbons were present. Oil analyses suggest that oils from the major fields of the Cook Inlet region, most of which produce from the Tertiary Hemlock Conglomerate, have a common source. More detailed work on stable carbon isotope ratios and the distribution of gasoline-range and heavy (C 12 + ) hydrocarbons confirms this genetic relation among the major fields. In addition, oils from Jurassic rocks under the Iniskin Peninsula and from the Hemlock Conglomerate at the southwestern tip of the Kenai lowland are members of the same or a very similar oil family. The Middle Jurassic strata of the Iniskin Peninsula are moderately rich in organic carbon (0.5 to 1.5 wt. %) and yield shows of oil and of gas in wells and in surface seeps. Extractable hydrocarbons from this strata are similar in chemi al and isotopic composition to the Cook Inlet oils. Organic matter in Cretaceous and Tertiary rocks is thermally immature in all wells analyzed. Oil reservoirs in the major producing fields are of Tertiary age and unconformably overlie Jurassic rocks; the pre-Tertiary unconformity may be significant in exploration for new oil reserves. The unconformable relation between reservoir rocks and likely Middle Jurassic source rocks also implies a delay in the generation and expulsion of oil from Jurassic until late Tertiary when localized basin subsidence and thick sedimentary fill brought older, deeper rocks to the temperature required for petroleum generation. Reservoir porosities, crude oil properties, the type of oil field traps, and the tectonic framework of the oil fields on the west flank of the basin provide evidence used to reconstruct an oil migration route. The route is inferred to commence deep in the truncated Middle Jur ssic rocks and pass through the porous West Foreland Formation in the McArthur River field area to a stratigraphic trap in the Oligocene Hemlock Conglomerate and the Oligocene part of the Tyonek Formation at the end of Miocene time. Pliocene deformation shut off this route and created localized structural traps, into which the oil moved by secondary migration to form the Middle Ground Shoal, McArthur River, and Trading Bay oil fields. Oil generation continued into the Pliocene, but this higher API gravity oil migrated along a different route to the Granite Point field.

Alaska↗
USGS1981

Lithology, reservoir properties, and burial history of portion of Gammon Shale (Cretaceous), southwestern North Dakota

In the northern Great Plains, large quantities of biogenic methane are contained at shallow depths in Cretaceous marine mudstones. The Gammon Shale and equivalents of the Milk River Formation in Canada, which comprise most sediments deposited offshore during the Eagle-Telegraph Creek regression, are typical of such gas-bearing rocks. At Little Missouri field, southwestern North Dakota, Gammon reservoirs consist of discontinuous lenses and laminae of siltstone, less than 10 mm thick, enclosed by silty clay shale. Large amounts of allogenic clay, including highly expansible mixed-layer illite-smectite cause great water sensitivity and high measured and calculated water-saturation values. Reconstructed burial depths, clay mineralogy, and organic matter maturation studies show that the Gammon has not undergone thermal conditions sufficient for oil or thermal gas generation. Scarce authigenic minerals such as pyrite, siderite, and calcite probably formed as a result of bacterial metabolism early in the burial history. The scarcity of authigenic silicates suggests that diagenesis has been inhibited during much of the burial history by the presence of free methane. Shale layers are practically impermeable whereas siltstone microlenses are porous (30 to 40%) and have permeabilities on the order of 3 to 30 md. Reservoir continuity between siltstone layers is poor and, overall, reservoir permeability is probably less than 0.4 md. Connecting passageways between siltstone lenses are 0.1 µm or less in diameter. Organic matter in the low-permeability reservoirs served as the source of biogenic methane, and capillary forces acted as the trapping mechanism for gas accumulation. At Little Missouri field, reservoirs and non-reservoirs cannot be distinguished on the basis of lithology, and much of the Gammon interval is potentially economic. Future research should be directed toward determining the physical basis of log response in the low-permeability reservoirs and toward the development or application of water-free recovery technology.

North Dakota↗
USGS1981

Determination of organic-matter content of Appalachian Devonian shales from gamma-ray logs

The organic-matter content of the Devonian shale of the Appalachian basin is important for assessing natural-gas resources. In most of the western part of the Appalachian basin the organic-matter content of the Devonian shale can be estimated from gamma-ray wire-line logs. Organic-matter contents estimated using these logs are compared with determinations from direct laboratory analyses of organic carbon for 74 intervals of varying thickness from 12 widely separated wells. The cumulative pool of gamma-ray logs for the Devonian shale forms a large and geographically broad data base. The approach may also be applicable to other formations.-from Author

Appalachian Basin↗
USGS1981

Lithostratigraphy of Shell 272-1 and 273-1 Wells: Implications as to depositional history of the Baltimore Canyon Trough, Mid- Atlantic OCS

Upper Jurassic gray and red-brown shale, sandstone, and coal are the oldest strata penetrated by the Shell 272-1 and 273-1 wells, located approximately 66 mi (106 km) southeast of Atlantic City, New Jersey, in the northwest part of the Baltimore Canyon Trough. The Lower Cretaceous section consists of gray shale that is overlain by a sequence of thick-bedded sandstones interbedded with thin-bedded shales. The Upper Cretaceous section is dominated by slightly calcareous mudstone, but also contains a Coniacian to Campanian sandstone. The Cenozoic section is mainly mudstone and overlying unconsolidated sand. Seven major lithologic units were established and correlated to the COST B-2 and B-3 wells. The depositional environments of the Upper Jurassic rocks range from an upper delta plain facies penetrated in the two Shell wells and the B-2 well to a back-reef facies penetrated in the B-3 well. The Lower Cretaceous strata, in a vertical sequence, consist of upper delta plain, lower delta plain, interdistributary bay and/or marginal marine, and distributary-mouth-bar deposits. A Cenomanian sandstone penetrated in the B-3 well is the youngest indicator of deltaic deposition; marine strata dominate the remainder of the Upper Cretaceous and Cenozoic.

Baltimore Canyon Trough↗
USGS1981

Geology of central Lake Michigan

The geology beneath Lake Michigan between 43°00' and 44°00' N and between 86°30' and 87°40' W is interpreted from a synthesis of 1,700 km of continuous seismic reflection profile data, bathymetry, grab samples, and onshore surface and subsurface information. The continuous seismic reflection profiles and bathymetry provided information for maps of unconsolidated sediment thickness and Paleozoic bedrock topography. The map of unconsolidated sediment (primarily Pleistocene) shows thicknesses ranging from 180 m in a steep-walled, northeast-trending valley to less than 10 m over a mid-lake topographic high. This valley and the mid-lake high are the dominant topographic features developed on the gently eastward-dipping Paleozoic rocks along this part of the western flank of the Michigan basin. Two structural-stratigraphic cross sections of the study area were constructed by utilizing a composite subsurface-surface section for eastern Wisconsin and two control wells in western Michigan. The cross sections, grab samples previously described in the literature, the bedrock topographic map, and published maps were used to construct a Paleozoic geologic map for central Lake Michigan. Rocks from Middle Silurian through Early Mississippian age form subcrops beneath the study area, whereas rocks of Early Silurian, Ordovician, and Late Cambrian age are present at greater depth. The Upper Cambrian rocks unconformably overlie Precambrian igneous and metamorphic rocks. The structural-stratigraphic cross sections also allow us to speculate about the petroleum potential beneath Lake Michigan. The possibility of oil occurrences within the Silurian is enhanced by major east-west facies changes, and other horizons with promise are present in Devonian and Ordovician rocks. Although Michigan and Wisconsin laws currently prohibit petroleum exploration in Lake Michigan, it is an area with future potential.

Michigan, Wisconsin↗
USGS1982

Volume of organic-rich Devonian shale in the Appalachian Basin: relating "black" to organic-matter content: Geologic notes

Some estimates of natural-gas resources in the Devonian shale of the Appalachian basin depend on the volume of organic-rich shale in the basin. A map by L. G. Wallace and W. de Witt showing the thickness and extent of Devonian "black" shale facies in the Appalachian basin is widely used as an indicator of organic-rich shale, but the map is derived from subjective evaluations of shale color. Wallace and de Witt's definition of "black" is shown here to correspond to an organic-matter content of approximately 4% or more by volume and a Munsell color value for dry pressed-powder samples of about N5 (medium gray) or darker. The volume of Devonian shale with an organic-matter content greater than 2.0% by volume (a definition of "organic-rich" that is preferred by the writers) a erages 1.44 times that of the "black" shale of Wallace and de Witt, and totals about 2,574 × 10 12 cu ft (72.9 × 10 12 cu m) in the Appalachian basin.

Appalachian Basin↗
USGS1982

Stratigraphic reference section for Georges Bank Basin - Depositional model for New England passive margin.

A multichannel seismic reflection profile (U.S. Geological Survey line 19), calibrated with the COST G-1, COST G-2, and Shell Mohican I-100 wells, and seismic-sequence analysis shows that the chronostratigraphic and lithostratigraphic units and depositional history of the Georges Bank basin are similar to those of the Scotian basin. Carbonate rocks of the Iroquois and Abenaki Formations, as much as 16,000 ft (4,800 m) thick, dominated the eastern half of the Georges Bank basin during the Jurassic. As much as 7,500 ft (2,300 m) of the coeval terrigenous clastic deposits of the Mohican, Mohawk, and Mic Mac Formations accumulated updip (westward) in sublittoral, paralic, and nonmarine environments. Siliciclastic deposition, as much as 6,000 ft (1,800 m), dominated the entire basin throughout the Cretaceous and Cenozoic, and it was punctuated briefly by carbonate deposition during the Hauterivian and Paleogene. Tentative correlation between the Georges Bank basin sequences and those of the adjacent, deep North American basin suggests that the deep-sea facies were strongly influenced by depositional events on the shelf. Deposition in both areas has been sensitive to changes in sea level and to paleoclimatic cycles.

Atlantic Ocean, Georges Bank↗
USGS1982

Applications of Landsat imagery to problems of petroleum exploration in Qaidam Basin, China

Tertiary and Quaternary nonmarine, petroleum-bearing sedimentary rocks in the Qaidam basin of remote western China have been extensively deformed by compressive forces. These forces created many folds which are current targets of Chinese exploration programs. Manual techniques of image analysis and interpretation were applied to computer-enhanced Landsat images of the western part of the Qaidam basin in an effort to evaluate the contributions of Landsat imagery in defining the geologic conditions of the basin and to determine its usefulness as an exploration tool in the region. Most success was realized in defining the structural geologic setting of the region. Image-derived interpretations of folds, strike-slip faults, thrust faults, normal or reverse faults, and fractures compared very favorably, in terms of locations and numbers mapped, with Chinese data compiled from years of extensive field mapping. The image studies resulted in the identification of at least one subsurface fold that had not been detected by field mapping. The results of this study have direct exploration significance. Many potential hydrocarbon trapping structures were precisely located and information was obtained that may have significant implications with respect to fluid migration or attempts to locate offset reservoirs and buried folds. In addition, the orientations of major structural trends defined from Landsat imagery correlate well with those predicted for the area based on global tectonic theory. These correlations suggest that similar orientations exist in the eastern half of the basin where folded rocks are mostly obscured by unconsolidated surface sediments and where limited exploration has occurred.

Qaidam Basin↗
USGS1983

Structure, burial history, and petroleum potential of frontal thrust belt and adjacent foreland, southwest Montana

The frontal thrust belt in the Lima area of southwestern Montana consists of blind (nonsurfacing) thrusts of the Lima thrust system beneath the Lima anticline and the Tendoy thrust sheet to the west. The Tendoy sheet involves Mississippian through Cretaceous rocks of the southwest-plunging nose of the Mesozoic Blacktail-Snowcrest uplift that are thrust higher (northeast) onto the uplift. The front of the Tendoy sheet west of Lima locally has been warped by later compressive deformation which also involved synorogenic conglomerates of the structurally underlying Beaverhead Formation. To the north, recent extension faulting locally has dropped the front of the Tendoy sheet beneath Quaternary gravels. Rocks of the exposed Tendoy sheet have never been deeply buried, based on itrinite reflectance of <= 0.6%, conodont CAI (color alteration index) values that are uniformly 1, and on supporting organic geochemical data from Paleozoic rocks from the Tendoy thrust sheet. Directly above and west of the Tendoy sheet lie formerly more deeply buried rocks of the Medicine Lodge thrust system. Their greater burial depth is indicated by higher conodont CAI values. West-dipping post-Paleocene extension faults truncate much of the rear part of the Tendoy sheet and also separate the Medicine Lodge sheet from thrust sheets of the Beaverhead Range still farther west. The Laramide Blacktail-Snowcrest uplift east of the frontal thrust belt is asymmetric. Its southeast, steeper limb is exposed along the Snowcrest Range. This limb extends southwestward in the complexly deformed Snowcrest structural terrane. Northwest-dipping thrusts on this limb involve basement rocks and probably merge with depth into a major sub-Snowcrest Range thrust. This major thrust borders and is chiefly responsible for the Blacktail-Snowcrest uplift and adjacent Ruby synclinorium to the southeast. Uniform conodont CAI values of 1 from both the southeast and northwest flanks of the Blacktail-Snowcrest uplift indicate that no thick cover of Upper Cretaceous or younger rocks extended over the flanks of the uplift. During Mississippian through Permian time, the area of later Laram de uplift underwent more rapid subsidence than the area of the Laramide Ruby syncline and the Centennial basin to the southeast. The inferred sub-Snowcrest Range thrust fault apparently represents a reactivated zone of basement weakness. The intersection of thrust-belt and foreland trends, similar to the Uinta uplift area to the south, probably formed a number of structural traps for hydrocarbons which have not yet been tested. Potential petroleum source beds and reservoir rocks are both present in southwest Montana. However, remnants of Tertiary lava flows through much of the area, Tertiary to recent basin-and-range faulting, and supermaturity with respect to oil of Permian and older rocks in the western Centennial uplift area are additional factors which must be considered in any estimate of hydrocarbon potential of the Cordilleran overthrust belt and adjacent foreland in extreme southwestern Montana.

Montana↗
USGS2010

Assessment of undiscovered conventional oil and gas resources, onshore Claiborne Group, United Statespart of the northern Gulf of Mexico Basin

The middle Eocene Claiborne Group was assessed for undiscovered conventional hydrocarbon resources using established U.S. Geological Survey assessment methodology. This work was conducted as part of a 2007 assessment of Paleogene-Neogene strata of the northern Gulf of Mexico Basin, including the United States onshore and state waters (Dubiel et al., 2007). The assessed area is within the Upper Jurassic-CretaceousTertiary composite total petroleum system, which was defined for the assessment. Source rocks for Claiborne oil accumulations are interpreted to be organic-rich, downdip, shaley facies of the Wilcox Group and the Sparta Sand of the Claiborne Group; gas accumulations may have originated from multiple sources, including the Jurassic Smackover Formation and the Haynesville and Bossier shales, the Cretaceous Eagle Ford and Pearsall (?) formations, and the Paleogene Wilcox Group and Sparta Sand. Hydrocarbon generation in the basin started prior to deposition of Claiborne sediments and is currently ongoing. Primary reservoir sandstones in the Claiborne Group include, from oldest to youngest, the Queen City Sand, Cook Mountain Formation, Sparta Sand, Yegua Formation, and the laterally equivalent Cockfield Formation. A geologic model, supported by spatial analysis of petroleum geology data, including discovered reservoir depths, thicknesses, temperatures, porosities, permeabilities, and pressures, was used to divide the Claiborne Group into seven assessment units (AUs) with three distinctive structural and depositional settings. The three structural and depositional settings are (1) stable shelf, (2) expanded fault zone, and (3) slope and basin floor; the seven AUs are (1) lower Claiborne stable-shelf gas and oil, (2) lower Claiborne expanded fault-zone gas, (3) lower Claiborne slope and basin-floor gas, (4) lower Claiborne Cane River, (5) upper Claiborne stable-shelf gas and oil, (6) upper Claiborne expanded fault-zone gas, and (7) upper Claiborne slope and basin-floor gas. Based on Monte Carlo simulation of justified input parameters, the total estimated mean undiscovered conventional hydrocarbon resources in the seven AUs combined are 52 million bbl of oil, 19.145 tcf of natural gas, and 1.205 billion bbl of natural gas liquids. This article describes the conceptual geologic model used to define the seven Claiborne AUs, the characteristics of each AU, and the justification behind the input parameters used to estimate undiscovered resources for each AU. The great bulk of undiscovered hydrocarbon resources are predicted to be nonassociated gas and natural gas liquids contained in deep (mostiy >12,000-ft [3658 m], present-day drilling depths), overpressured, structurally complex outer shelf or slope and basin-floor Claiborne reservoirs. The continuing development of these downdip objectives is expected to be the primary focus of exploration activity for the onshore middle Eocene Gulf Coast in the coming decades. ?? 2010 U.S. Geological Survey. 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↗
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↗