Geology topics
Publications and source records attributed to Laura N.R. Roberts.
Using a geology-based assessment methodology, the U.S. Geological Survey estimated mean undiscovered volumes of 3.65 billion barrels of oil, 1.85 trillion cubic feet of associated/dissolved natural gas, and 148 million barrels of natural gas liquids in the Bakken Formation of the Williston Basin Province, Montana and North Dakota.
Using a geology-based assessment methodology, the U.S. Geological Survey estimated a mean of 989 billion cubic feet of undiscovered natural gas, a mean of 72 million barrels of undiscovered oil, and a mean of 13 million barrels of undiscovered natural gas liquids in the Bighorn Basin Providence of Wyoming and Montana.
Using a geology-based assessment method, the U.S. Geological Survey estimated mean undiscovered volumes of 3.8 billion barrels of undiscovered oil, 3.7 trillion cubic feet of associated/dissolved natural gas, and 0.2 billion barrels of undiscovered natural gas liquids in the Williston Basin Province, North Dakota, Montana, and South Dakota. (See “Introduction” in Fact Sheet for additional information.)
Burial history, thermal maturity, and timing of oil and gas generation were modeled for seven key source-rock units at eight well locations throughout the Bighorn Basin in Wyoming and Montana. Also modeled was the timing of cracking to gas of Phosphoria Formation-sourced oil in the Permian Park City Formation reservoirs at two well locations. Within the basin boundary, the Phosphoria is thin and only locally rich in organic carbon; it is thought that the Phosphoria oil produced from Park City and other reservoirs migrated from the Idaho-Wyoming thrust belt. Other petroleum source rocks include the Cretaceous Thermopolis Shale, Mowry Shale, Frontier Formation, Cody Shale, Mesaverde and Meeteetse Formations, and the Tertiary (Paleocene) Fort Union Formation. Locations (wells) selected for burial history reconstructions include three in the deepest parts of the Bighorn Basin (Emblem Bench, Red Point/Husky, and Sellers Draw), three at intermediate depths (Amoco BN 1, Santa Fe Tatman, and McCulloch Peak), and two at relatively shallow locations (Dobie Creek and Doctor Ditch). The thermal maturity of source rocks is greatest in the deep central part of the basin and decreases to the south, east, and north toward the basin margins. The Thermopolis and Mowry Shales are predominantly gas-prone source rocks, containing a mix of Type-III and Type-II kerogens. The Frontier, Cody, Mesaverde, Meeteetse, and Fort Union Formations are gas-prone source rocks containing Type-III kerogen. Modeling results indicate that in the deepest areas, (1) the onset of petroleum generation from Cretaceous rocks occurred from early Paleocene through early Eocene time, (2) peak petroleum generation from Cretaceous rocks occurred during Eocene time, and (3) onset of gas generation from the Fort Union Formation occurred during early Eocene time and peak generation occurred from late Eocene to early Miocene time. Only in the deepest part of the basin did the oil generated from the Thermopolis and Mowry Shales start generating gas from secondary cracking, which occurred in the late Eocene to Miocene. Also, based on modeling results, gas generation from the cracking of Phosphoria oil reservoired in the Park City Formation began in the late Eocene in the deep part of the basin but did not anywhere reach peak generation.
The Cretaceous-Lower Tertiary Composite Total Petroleum System (TPS) of the Wind River Basin Province includes all strata from the base of the Lower Cretaceous Cloverly Formation to the base of the Waltman Shale Member of the Paleocene age Fort Union Formation and, where the Waltman is absent, includes strata as young as the Eocene Wind River Formation. Locally, Cretaceous-sourced gas migrated into strata as old as the Mississippian Madison Limestone, and in these areas the TPS extends stratigraphically downward to include these reservoirs. The extensive vertical migration of gases in highly fractured areas of the Wind River Basin led to the commingling of gases from several Upper Cretaceous and lower Tertiary sources, thus only two petroleum systems are recognized in these rocks, the Cretaceous-Lower Tertiary Composite TPS, the subject of this report, and the Waltman Shale TPS described by Roberts and others (Chapter 5, this CD-ROM). The Cretaceous-lower Tertiary Composite TPS was subdivided into (1) seven continuous gas assessment units (AU): (a) Frontier-Muddy Continuous Gas AU, (b) Cody Sandstone Continuous Gas AU, (c) Mesaverde--Meeteetse Sandstone Gas AU, (d) Lance-Fort Union Sandstone Gas AU, (e) Mesaverde Coalbed Gas AU, (f) Meeteetse Coalbed Gas AU, and (g) Fort Union Coalbed Gas AU; (2) one continuous oil assessement unit--- Cody Fractured Shale Continuous Oil AU; and (3) one conventional assessment Unit--- Cretaceous-Tertiary Conventional Oil and Gas AU. Estimates of undiscovered resources having the potential for additions to reserves were made for all but the Cody Fractured Shale Continuous Oil AU, which is considered hypothetical and was not quantitively assessed. The mean estimate of the total oil is 41.99 million barrels, mean estimate of gas is 2.39 trillion cubic feet, and mean estimate of natural gas liquids is 20.55 million barrels. For gas, 480.66 billion cubic feet (BCFG) is estimated for the Frontier-Muddy Continuous Gas AU, 115.34 BCFG for the Cody Sandstone Continuous Gas AU, 383.16 BCFG for the Mesaverde-Meeteetse Sandstone Continuous Gas AU, 711.30 BCFG for the Lance-Fort Union Sandstone Gas AU, 107.18 BCFG for the Mesaverde Coalbed Gas AU, 21.29 BCFG for the Meeteetse Coalbed Gas AU, and 118.08 BCFG for the Fort Union Coalbed Gas AU. All the undiscovered oil and 98.94 BCFG of undiscovered gas is in the Cretaceous-Tertiary Conventional Oil and Gas AU.
The Waltman Shale Total Petroleum System encompasses about 3,400 square miles in the Wind River Basin Province, Wyoming, and includes accumulations of oil and associated gas that were generated and expelled from oil-prone, lacustrine shale source rocks in the Waltman Shale Member of the Paleocene Fort Union Formation. Much of the petroleum migrated and accumulated in marginal lacustrine (deltaic) and fluvial sandstone reservoirs in the Shotgun Member of the Fort Union, which overlies and intertongues with the Waltman Shale Member. Additional petroleum accumulations derived from Waltman source rocks are present in fluvial deposits in the Eocene Wind River Formation overlying the Shotgun Member, and also might be present within fan-delta deposits included in the Waltman Shale Member, and in fluvial sandstone reservoirs in the uppermost part of the lower member of the Fort Union Formation immediately underlying the Waltman. To date, cumulative production from 53 wells producing Waltman-sourced petroleum exceeds 2.8 million barrels of oil and 5.8 billion cubic feet of gas. Productive horizons range from about 1,770 feet to 5,800 feet in depth, and average about 3,400 to 3,500 feet in depth. Formations in the Waltman Shale Total Petroleum System (Fort Union and Wind River Formations) reflect synorogenic deposition closely related to Laramide structural development of the Wind River Basin. In much of the basin, the Fort Union Formation is divided into three members (ascending order): the lower unnamed member, the Waltman Shale Member, and the Shotgun Member. These members record the transition from deposition in dominantly fluvial, floodplain, and mire environments in the early Paleocene (lower member) to a depositional setting characterized by substantial lacustrine development (Waltman Shale Member) and contemporaneous fluvial, and marginal lacustrine (deltaic) deposition (Shotgun Member) during the middle and late Paleocene. Waltman Shale Member source rocks have total organic carbon values ranging from 0.93 to 6.21 weight percent, averaging about 2.71 weight percent. The hydrocarbon generative potential of the source rocks typically exceeds 2.5 milligrams of hydrocarbon per gram of rock and numerous samples had generative potentials exceeding 6.0 milligrams of hydrocarbon per gram of rock. Waltman source rocks are oil prone, and contain a mix of Type-II and Type-III kerogen, indicating organic input from a mix of algal and terrestrial plant matter, or a mix of algal and reworked or recycled material. Thermal maturity at the base of the Waltman Shale Member ranges from a vitrinite reflectance value of less than 0.60 percent along the south basin margin to projected values exceeding 1.10 percent in the deep basin west of Madden anticline. Burial history reconstructions for three wells in the northern part of the Wind River Basin indicate that the Waltman Shale Member was well within the oil window (Ro equal to or greater than 0.65 percent) by the time of maximum burial about 15 million years ago; maximum burial depths exceeded 10,000 feet. Onset of oil generation calculated for the base of the Waltman Shale member took place from about 49 million years ago to about 20 million years ago. Peak oil generation occurred from about 31 million years ago to 26 million years ago in the deep basin west of Madden anticline. Two assessment units were defined in the Waltman Shale Total Petroleum System: the Upper Fort Union Sandstones Conventional Oil and Gas Assessment Unit (50350301) and the Waltman Fractured Shale Continuous Oil Assessment Unit (50350361). The conventional assessment unit primarily relates to the potential for undiscovered petroleum accumulations that are derived from source rocks in the Waltman Shale Member and trapped within sandstone reservoirs in the Shotgun Member (Fort Union Formation) and in the lower part of the overlying Wind River Formation. The potential for Waltman-sourced oil accumulations in fan-delta depos
Burial history, thermal maturity, and timing of oil and gas generation were modeled for eight key source rock units at nine well locations throughout the Wind River Basin Province. Petroleum source rocks include the Permian Phosphoria Formation, the Cretaceous Mowry Shale, Cody Shale, and Mesaverde, Meeteetse, and Lance Formations, and the Tertiary (Paleocene) Fort Union Formation, including the Waltman Shale Member. Within the province boundary, the Phosphoria is thin and only locally rich in organic carbon. Phosphoria oil produced from reservoirs in the province is thought to have migrated from the Wyoming and Idaho thrust belt. Locations (wells) selected for burial history reconstructions include three in the deepest parts of the province (Adams OAB-17, Bighorn 1-5, and Coastal Owl Creek); three at intermediate depths (Hells Half Acre, Shell 33X-10, and West Poison Spider); and three at relatively shallow locations (Young Ranch, Amoco Unit 100, and Conoco-Coal Bank). The thermal maturity of source rocks is greatest in the deep northern and central parts of the province and decreases to the south and east toward the basin margins. The results of the modeling indicate that, in the deepest areas, (1) peak petroleum generation from Cretaceous rocks occurred from Late Cretaceous through middle Eocene time, and (2) onset of oil generation from the Waltman Shale Member occurred from late Eocene to early Miocene time. Based on modeling results, gas generation from the cracking of Phosphoria oil reservoired in the Park City Formation reached a peak in the late Paleocene/early Eocene (58 to 55 Ma) only in the deepest parts of the province. The Mowry Shale and Cody Shale (in the eastern half of the basin) contain a mix of Type-II and Type-III kerogens. Oil generation from predominantly Type-II source rocks of these units in the deepest parts of the province reached peak rates during the latest Cretaceous to early Eocene (65 to 55 Ma). Only in these areas of the basin did these units reach peak gas generation from the cracking of oil, which occurred in the early to middle Eocene (55 to 42 Ma). Gas-prone source rocks of the Mowry and Cody Shales (predominantly Type-III kerogen), and the Mesaverde, Meeteetse, Lance, and Fort Union Formations (Type –III kerogen) reached peak gas generation in the latest Cretaceous to late Eocene (67 to 38 Ma) in the deepest parts of the province. Gas generation from the Mesaverde source rocks started at all of the modeled locations but reached peak generation at only the deepest locations and at the Hells Half Acre location in the middle Paleocene to early Eocene (59 to 48 Ma). Also at the deepest locations, peak gas generation occurred from the late Paleocene to the early Eocene (57 to 49 Ma) for the Meeteetse Formation, and during the Eocene for the Lance Formation (55 to 48 Ma) and the Fort Union Formation (44 to 38 Ma). The Waltman Shale Member of the Fort Union Formation contains Type-II kerogen. The base of the Waltman reached a level of thermal maturity to generate oil only at the deep-basin locations (Adams OAB-17 and Bighorn 1-5 locations) in the middle Eocene to early Miocene (36 to 20 Ma).
Introduction: The Wind River Basin is a large Laramide (Late Cretaceous through Eocene) structural and sedimentary basin that encompasses about 7,400 mi2 in central Wyoming. The basin boundaries are defined by fault-bounded Laramide uplifts that surround it, including the Owl Creek and Bighorn Mountains to the north, Wind River Range to the west, Granite Mountains to the south, and Casper Arch to the east. The purpose of this report is to present new vitrinite reflectance data to be used in support of the U.S Geological Survey assessment of undiscovered oil and gas resources of the Wind River Basin. One hundred and nineteen samples were collected from Jurassic through Tertiary rocks, mostly coal-bearing strata, in an effort to better understand and characterize the thermal maturation and burial history of potential source rocks.
Summary: Petroleum resource assessments are among the most highly visible and frequently cited scientific products of the U.S. Geological Survey. The assessments integrate diverse and extensive information on the geologic, geochemical, and petroleum production histories of provinces and regions of the United States and the World. Petroleum systems modeling incorporates these geoscience data in ways that strengthen the assessment process and results are presented visually and numerically. The purpose of this report is to outline the requirements, advantages, and limitations of one-dimensional (1-D), two-dimensional (2-D), and three-dimensional (3-D) petroleum systems modeling that can be applied to the assessment of oil and gas resources. Primary focus is on the application of the Integrated Exploration Systems (IES) PetroMod? software because of familiarity with that program as well as the emphasis by the USGS Energy Program on standardizing to one modeling application. The Western Canada Sedimentary Basin (WCSB) is used to demonstrate the use of the PetroMod? software. Petroleum systems modeling quantitatively extends the 'total petroleum systems' (TPS) concept (Magoon and Dow, 1994; Magoon and Schmoker, 2000) that is employed in USGS resource assessments. Modeling allows integration of state-of-the-art analysis techniques, and provides the means to test and refine understanding of oil and gas generation, migration, and accumulation. Results of modeling are presented visually, numerically, and statistically, which enhances interpretation of the processes that affect TPSs through time. Modeling also provides a framework for the input and processing of many kinds of data essential in resource assessment, including (1) petroleum system elements such as reservoir, seal, and source rock intervals; (2) timing of depositional, hiatus, and erosional events and their influences on petroleum systems; (3) incorporation of vertical and lateral distribution and lithologies of strata that compose the petroleum systems; and (4) calculations of pressure-volume-temperature (PVT) histories. As digital data on petroleum systems continue to expand, the models can integrate these data into USGS resource assessments by building and displaying, through time, areas of petroleum generation, migration pathways, accumulations, and relative contributions of source rocks to the hydrocarbon components. IES PetroMod? 1-D, 2-D, and 3-D models are integrated such that each uses the same variables for petroleum systems modeling. 1-D burial history models are point locations, mainly wells. Maps and cross-sections model geologic information in two dimensions and can incorporate direct input of 2-D seismic data and interpretations using various formats. Both 1-D and 2-D models use data essential for assessments and, following data compilation, they can be completed in hours and retested in minutes. Such models should be built early in the geologic assessment process, inasmuch as they incorporate the petroleum system elements of reservoir, source, and seal rock intervals with associated lithologies and depositional and erosional ages. The models can be used to delineate the petroleum systems. A number of 1-D and 2-D models can be constructed across a geologic province and used by the assessment geologists as a 3-D framework of processes that control petroleum generation, migration, and accumulation. The primary limitation of these models is that they only represent generation, migration, and accumulation in two dimensions. 3-D models are generally built at reservoir to basin scales. They provide a much more detailed and realistic representation of petroleum systems than 1-D or 2-D models because they portray more fully the temporal and physical relations among (1) burial history; (2) lithologies and associated changes through burial in porosity, permeability, and compaction; (3) hydrodynamic effects; and (4) other parameters that influence petroleum gen
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This publication contains zmap-format grid files of isopach intervals that represent strata associated with Devonian to Holocene petroleum systems of the Western Canada Sedimentary Basin (WCSB) of Alberta, British Columbia, and Saskatchewan, Canada. Also included is one grid file that represents elevations relative to sea level of the top of the Lower Cretaceous Mannville Group. Vertical and lateral scales are in meters. The age range represented by the stratigraphic intervals comprising the grid files is 373 million years ago (Ma) to present day. File names, age ranges, formation intervals, and primary petroleum system elements are listed in table 1. Metadata associated with this publication includes information on the study area and the zmap-format files. The digital files listed in table 1 were compiled as part of the Petroleum Processes Research Project being conducted by the Central Energy Resources Team of the U.S. Geological Survey, which focuses on modeling petroleum generation, 3 migration, and accumulation through time for petroleum systems of the WCSB. Primary purposes of the WCSB study are to Construct the 1-D/2-D/3-D petroleum system models of the WCSB. Actual boundaries of the study area are documented within the metadata; excluded are northern Alberta and eastern Saskatchewan, but fringing areas of the United States are included. Publish results of the research and the grid files generated for use in the 3-D model of the WCSB. Evaluate the use of petroleum system modeling in assessing undiscovered oil and gas resources for geologic provinces across the World.
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No abstract available.