Geology topics
Publications and source records attributed to Catherine B. Enomoto.
Using a geology-based assessment methodology, the U.S. Geological Survey estimated undiscovered, technically recoverable mean resources of 14,785 billion cubic feet of gas resources in the Western Gulf Basin Province, U.S. Gulf Coast region.
The U.S. Geological Survey assessed undiscovered unconventional hydrocarbon resources reservoired in the Upper Cretaceous Tuscaloosa marine shale (TMS) of southern Mississippi and adjacent Louisiana in 2018. As part of the assessment, oil-source rock correlations were examined in the TMS play area where operators produce light (38–45° API), sweet oil from horizontal, hydraulically-fractured wells in an overpressured ‘high-resistivity’ (>5 Ω-m) zone at the base of the TMS. Geochemical data from 39 oil samples and 17 source rock solvent extracts collected from the TMS play area indicate close correspondence for Tuscaloosa Group oils [from lower Tuscaloosa, middle Tuscaloosa (the TMS) and upper Tuscaloosa reservoirs] in thermal maturity (computed from MPI), SARA proportions, n- alkane distributions, isoprenoid and DBT/P ratios, monoaromatic steroids, and δ 13 C isotopic compositions (from whole oils, saturate and aromatic fractions). Other parameters (normal steranes, extended homohopanes, C 31 R/C 30 hopane, norhopane/hopane and tricyclic terpane ratios, gammacerane/hopane) show most oil samples have similar values, suggesting all Tuscaloosa Group oils are from a common mixed marine-terrigenous source rock. Tighter distributions for triaromatic steroid (TAS) and δ 13 C isotopic composition for conventional oils in lower and upper Tuscaloosa reservoirs may indicate charge occurred in a single or shorter pulse relative to TMS oils which show broader TAS and δ 13 C properties, possibly from their generation over an extended period of burial maturation. Dissimilarity in geochemical properties between lower Tuscaloosa source rock solvent extracts and Tuscaloosa Group oils indicates lower Tuscaloosa source rocks did not contribute significantly to conventional and unconventional Tuscaloosa Group hydrocarbon accumulations. Whereas, TMS solvent extracts are similar to Tuscaloosa Group oils, suggesting an oil-source rock correlation. Excluding the possibility for long-distance lateral migration from a similar source downdip (which is unnecessary given thermal maturity considerations), the observations indicate 1. the TMS is a self-sourced reservoir, 2. the TMS is the source of oils accumulated in nearby conventional Tuscaloosa Group reservoirs, and 3. thin organic-rich shales in the lower Tuscaloosa did not contribute substantially to any oil accumulations in the Tuscaloosa Group.
Greater than 33 trillion cubic feet of gas, 68 million barrels of natural gas liquids (NGL), and 192 million barrels of water have been produced from the Middle Devonian Marcellus Shale of the Hamilton Group in the Appalachian Basin. These volumes are from more than 11,700 non-commingled wells. Areas of greatest production and future potential for gas and NGL from the Marcellus Shale are within and near the northeast-trending Rome trough in northern West Virginia and Pennsylvania. Southernmost New York, eastern Ohio, western Virginia, and Maryland also contain petroleum potential and (or) reserves. A confluence of factors enhances gas and NGL reserves and resources in the Marcellus Shale. These include (1) brittleness based on lithofacies composition; (2) thickness and distribution of brittle and organic-rich shale; (3) measured thermal maturity of 1% vitrinite reflectance and greater; (4) at least 2 weight percent total organic carbon; (5) dense and complex fracturing and faulting; (6) presence of evaporite beds in the underlying Silurian Salina Group; (7) potential overpressure; (8) current depths of 1,370 m (4,500 ft) and greater; and (9) predominately horizontal wells with laterals that are oriented to the northwest or southeast, or roughly perpendicular to the direction of maximum horizontal stress, and that cross major fault and fracture sets.
Nine 1D burial history models were built across the Appalachian Basin to reconstruct the burial, erosional, and thermal maturation histories of contained petroleum source rocks. Models were calibrated to measured downhole temperature and to vitrinite reflectance (% R o ) data from Devonian through Pennsylvanian petroleum source rocks. The highest levels of thermal maturity in Devonian and Mississippian source rocks are within and proximal to the Rome trough in the deep basin, which is also within the confluence of increased structural complexity and associated faulting, overpressured Devonian shales, and thick intervals of salt in the underlying Silurian Salina Group. Models incorporate minor erosion from 260 to 140 million years ago (Ma) that allows for extended burial and heating of underlying strata and generally results in less eroded thickness, compared to previously published models. Two modeled times of increased erosion, from 140 to 90 Ma and 23 to 5.3 Ma, are followed by less erosion from 5.3 Ma to Present. Absent strata are mainly Permian shales and sandstone; thickness of these removed layers increased from about 6,200 ft (1,890 m) west of the Rome trough to as much as 9,650 ft (2,940 m) within the trough. The onset of oil generation is based on 0.6% R o for Pennsylvanian coal samples; time of onset for the Ordovician Utica Shale ranges from 387 to 306 Ma, and 359 to 282 Ma for Middle Devonian to basal Mississippian shales. The ∼1.2% R o onset of wet gas generation ranges from 360 to 281 Ma in the Utica Shale, and 298 to 150 Ma for Middle Devonian to lowermost Mississippian shales.
Using a geology-based assessment methodology, the U.S. Geological Survey estimated undiscovered, technically recoverable continuous mean resources of 1.8 billion barrels of oil and 117.2 trillion cubic feet of gas in the Upper Ordovician Point Pleasant Formation and Utica Shale of the Appalachian Basin Province.
Using a geology-based assessment methodology, the U.S. Geological Survey estimated undiscovered, technically recoverable continuous mean resources of 96.5 trillion cubic feet of gas in the Middle Devonian Marcellus Shale of the Appalachian Basin Province.
Hydrocarbon reserves and technically recoverable undiscovered resources in continuous accumulations are present in Upper Ordovician strata in the Appalachian Basin Province. The province includes parts of New York, Pennsylvania, Ohio, Maryland, West Virginia, Virginia, Kentucky, Tennessee, Georgia, and Alabama. The Upper Ordovician strata are part of the previously defined Utica-Lower Paleozoic Total Petroleum System (TPS) that extends from New York and southern Canada to Tennessee. This publication presents a revision to the hydrocarbon source rocks in the TPS, a change to the name of the TPS, and changes to the geographic extent of the Utica-Lower Paleozoic TPS. The revision to the TPS recognizes the Upper Ordovician Point Pleasant Formation as a major hydrocarbon source rock in this TPS. Consequently, the name of the TPS is changed to Ordovician Point Pleasant/Utica-Lower Paleozoic TPS. The most significant modification to the boundary of the newly defined Ordovician Point Pleasant/Utica-Lower Paleozoic TPS is a westward extension in the southwesterly portion of the TPS, adding areas in Ohio, Indiana, Kentucky, and Tennessee in order to include Ordovician strata, including potential petroleum source rocks, from the subsurface to their near-surface exposure. Also, portions of the former Utica-Lower Paleozoic TPS are now excluded from the newly defined TPS in a portion of northwestern Ohio and adjacent States to eliminate overlap with the Ordovician to Devonian Composite TPS in the Michigan basin.
Introduction Geologic cross section A–A′ is the fifth in a series of cross sections constructed by the U.S. Geological Survey (USGS) to document and improve understanding of the geologic framework and petroleum systems of the Appalachian basin. Cross section A–A′ provides a regional view of the structural and stratigraphic framework of the Appalachian basin from the southern margin of the Ontario Lowlands province in western New York, across the Allegheny Plateau province of central New York and north-central Pennsylvania, to the Valley and Ridge province in north-central Pennsylvania, a distance of approximately 176 miles. This cross section is a companion to cross sections E–E′, D–D′, C–C′ , and I–I′ that are located approximately 100 to 500 miles to the southwest. Cross section A–A′ complements earlier geologic or stratigraphic cross sections through the central New York and north-central Pennsylvania part of the Appalachian basin. Although some of these other cross sections show more structural and stratigraphic detail, they are of more limited extent geographically and stratigraphically. Cross section A–A′ contains much information that is useful for evaluating energy resources in the Appalachian basin. Although the Appalachian basin petroleum systems are not shown on the cross section, many of their key elements (such as source rocks, reservoir rocks, seals, and traps) can be inferred from lithologic units, unconformities, and geologic structures shown on the cross section. Important oil- and gas-bearing formations like the Oriskany Sandstone, Medina Group sandstones, Tuscarora Sandstone, and the Marcellus and Utica Shales are present on cross-section A–A′ .
Using a geology-based assessment methodology, the U.S. Geological Survey assessed mean undiscovered, technically recoverable continuous resources of 1.5 billion barrels of oil and 4.6 trillion cubic feet of gas in the Upper Cretaceous Tuscaloosa marine shale in onshore and State waters of Louisiana, Mississippi, Alabama, and Florida in the U.S. Gulf Coast region.
Using a geology-based assessment methodology, the U.S. Geological Survey estimated mean undiscovered, technically recoverable conventional resources of 100 million barrels of oil and 16.5 trillion cubic feet of gas in the downdip Paleogene formations in onshore lands and State waters of the U.S. Gulf Coast region.
Using a geology-based assessment methodology, the U.S. Geological Survey estimated mean undiscovered, technically recoverable continuous resources of 10.7 trillion cubic feet of natural gas in Upper Devonian shales of the Appalachian Basin Province.
The U.S. Geological Survey (USGS) completed an assessment of undiscovered, technically recoverable unconventional petroleum resources in the Upper Cretaceous marine shale of the Tuscaloosa Group (Tuscaloosa marine shale; TMS) in 2018. As part of the geologic characterization in preparation for the assessment, a series of wireline log cross sections were constructed to illustrate TMS thickness trends and aid in the delineation of the assessment unit (AU). Lithostratigraphic units were correlated based on gamma ray, spontaneous potential, and resistivity log responses and generally follow the classic stratigraphic nomenclature first proposed in the 1960s. Correlated stratigraphic units include (from youngest to oldest) the Austin Group, Eagle Ford Shale, upper Tuscaloosa, Tuscaloosa marine shale, lower Tuscaloosa, and Lower Cretaceous. A high resistivity zone (HRZ) in the basal Tuscaloosa marine shale was delineated where resistivity was greater than 5 ohm-meters and high resistivity sections were separated by less than 20 feet of low resistivity shale. The HRZ was identified regionally and might indicate petroleum accumulations in the TMS. Third-party biostratigraphic data from wells in Mississippi and Louisiana were integrated into the well control, which aided wireline log correlation. Cross sections depict east-west thinning of the TMS onto the Sabine uplift and north-south thickening of the TMS off of the Lower Cretaceous shelf margin. The western boundary of the USGS-defined Tuscaloosa Marine Shale Continuous Oil AU was drawn in western Louisiana near the Texas-Louisiana state border based on stratigraphic thinning of the Upper Cretaceous section onto the structural high of the Sabine uplift as projected downdip.
In 2010, the U.S. Geological Survey (USGS) assessed Lower Cretaceous Albian to Upper Cretaceous Cenomanian carbonate rocks of the Fredericksburg and Washita Groups and their equivalent units for technically recoverable, undiscovered hydrocarbon resources underlying onshore lands and State Waters of the Gulf Coast region of the United States. This assessment was based on a geologic model that incorporates the Upper Jurassic-Cretaceous-Tertiary Composite Total Petroleum System (TPS) of the Gulf of Mexico basin; the TPS was defined previously by the USGS assessment team in the assessment of undiscovered hydrocarbon resources in Tertiary strata of the Gulf Coast region in 2007. One conventional assessment unit (AU), which extends from south Texas to the Florida panhandle, was defined: the Fredericksburg-Buda Carbonate Platform-Reef Gas and Oil AU. The assessed stratigraphic interval includes the Edwards Limestone of the Fredericksburg Group and the Georgetown and Buda Limestones of the Washita Group. The following factors were evaluated to define the AU and estimate oil and gas resources: potential source rocks, hydrocarbon migration, reservoir porosity and permeability, traps and seals, structural features, paleoenvironments (back-reef lagoon, reef, and fore-reef environments), and the potential for water washing of hydrocarbons near outcrop areas. In Texas and Louisiana, the downdip boundary of the AU was defined as a line that extends 10 miles downdip of the Lower Cretaceous shelf margin to include potential reef-talus hydrocarbon reservoirs. In Mississippi, Alabama, and the panhandle area of Florida, where the Lower Cretaceous shelf margin extends offshore, the downdip boundary was defined by the offshore boundary of State Waters. Updip boundaries of the AU were drawn based on the updip extent of carbonate rocks within the assessed interval, the presence of basin-margin fault zones, and the presence of producing wells. Other factors evaluated were the middle Cenomanian sea-level fall and erosion that removed large portions of platform and platform-margin carbonate sediments in the Washita Group of central Louisiana. The production history of discovered reservoirs and well data within the AU were examined to estimate the number and size of undiscovered oil and gas reservoirs within the AU. Using the USGS National Oil and Gas Assessment resource assessment methodology, mean volumes of 40 million barrels of oil, 622 billion cubic feet of gas, and 14 million barrels of natural gas liquids are the estimated technically recoverable undiscovered resources for the Fredericksburg-Buda Carbonate Platform-Reef Gas and Oil AU.
Recent oil production from the Upper Cretaceous Tuscaloosa marine shale (TMS) has elevated the formation, previously assessed by the USGS in 2011 as part of the Eagle Ford Group, to its own distinct assessment unit for an upcoming assessment. Geologic characterization in preparation for the 2017 assessment has included the analysis of rock samples and produced oils, and the interpretation of well logs and biostratigraphic data. Results include new mapped extents of the reservoir, which reaches a maximum thickness of almost 500 feet in southern Mississippi and central Louisiana, and geochemical interpretations which support a self-sourced origin for high gravity (36-48 API) low sulfur oil. Programmed pyrolysis and petrography indicate the TMS contains dominantly Type III gas-prone kerogen with some Type II oil-prone kerogen present in the most organic-rich samples. TMS samples contain an average of 47 weight percent total clays, had organic carbon content which ranged from 0.14 to 4.0 weight percent, and had a thermal maturity of 0.57 to 0.99 percent vitrinite reflectance in the productive area. These characteristics were the same for the TMS within an area defined as a “high resistivity zone” and outside of it. These results will be integral to the planned USGS assessment of the TMS.
Using a geology-based assessment methodology, the U.S. Geological Survey estimated mean undiscovered, technically recoverable continuous resources that total 464 million barrels of oil and 4.08 trillion cubic feet of gas in the Lower Mississippian Sunbury Shale and Middle Devonian–Lower Mississippian Chattanooga Shale of the Appalachian Basin Province.
Technically recoverable undiscovered hydrocarbon resources in continuous accumulations are present in Upper Devonian and Lower Mississippian strata in the Appalachian Basin Petroleum Province. The province includes parts of New York, Pennsylvania, Ohio, Maryland, West Virginia, Virginia, Kentucky, Tennessee, Georgia, and Alabama. The Upper Devonian and Lower Mississippian strata are part of the previously defined Devonian Shale-Middle and Upper Paleozoic Total Petroleum System (TPS) that extends from New York to Tennessee. This publication presents a revision to the extent of the Devonian Shale-Middle and Upper Paleozoic TPS. The most significant modification to the maximum extent of the Devonian Shale-Middle and Upper Paleozoic TPS is to the south and southwest, adding areas in Tennessee, Georgia, Alabama, and Mississippi where Devonian strata, including potential petroleum source rocks, are present in the subsurface up to the outcrop. The Middle to Upper Devonian Chattanooga Shale extends from southeastern Kentucky to Alabama and eastern Mississippi. Production from Devonian shale has been established in the Appalachian fold and thrust belt of northeastern Alabama. Exploratory drilling has encountered Middle to Upper Devonian strata containing organic-rich shale in west-central Alabama. The areas added to the TPS are located in the Valley and Ridge, Interior Low Plateaus, and Appalachian Plateaus physiographic provinces, including the portion of the Appalachian fold and thrust belt buried beneath Cretaceous and younger sediments that were deposited on the U.S. Gulf Coastal Plain.
This study evaluates regional ‘shale gas’ prospectivity of the Aptian section (primarily Pine Island Shale) in the downdip Mississippi Salt Basin (MSB). Previous work by the U.S. Geological Survey estimated a mean undiscovered gas resource of 8.8 trillion cubic feet (TCF) in the chronostratigraphic-equivalent Pearsall Formation in the Maverick Basin of south Texas, where industry has established a moderately successful horizontal gas and liquids play. Wells penetrating the downdip MSB Aptian section at depths of 12,000-15,000 ft were used to correlate formation tops in a 15-well cross-section extending about 200 miles (mi) east-southeastward from Adams Co. to Jackson Co. Legacy cuttings from these wells were analyzed for thermal maturity and source rock quality. Bitumen reflectance (n=53) increases with increasing present-day burial depth in the east-central study area from 1.0% to 1.7%. As the Aptian section shallows in Adams Co. to the west, bitumen Ro values are higher (1.7-2.0%), either from relatively greater heat flux or greater mid-Cenomanian uplift and erosion in this area. Total organic carbon (TOC) content ranges 0.01-1.21 and averages 0.5 wt.% (n=51); pyrolysis output (S2; n=51) averages 0.40 mg HC/g rock, indicating little present-day hydrocarbon-generative potential. Bitumen reflectance is preferred as a thermal maturity parameter as Tmax values are unreliable. Normalized X-ray diffraction (XRD) mineral analyses (n=26) indicate high average clay abundance (53 wt.%) relative to quartz (29%) and carbonate (18%). Mineral content shows a spatial relationship to an Appalachian orogen clastic sediment source, with proximal high clay and quartz and distal high carbonate content. Clastic influx from the Appalachian orogen is confirmed by detrital zircon U-Pb ages with dominant Grenville and Paleozoic components [105 ages from a Rodessa sandstone and 112 ages from a Paluxy (Albian) sandstone]. Preliminary information from fluid inclusion microthermometry (41 aqueous measurements from calcite cements in one argillaceous James Limestone sample) indicates homogenization temperatures (Th) of 120-135°C, consistent with present-day bottom-hole conditions and measured bitumen Ro values towards the western end of the MSB. Downdip in the central MSB, microthermometry (26 aqueous measurements from quartz dust rims in one Paluxy sandstone sample) and measured bitumen Ro values indicate maximum temperatures may have been significantly higher (~25°C) than present-day conditions. High inclusion salinities (15-25 wt.% salt) at both locations suggest interaction of pore fluids with evaporites. Mercury injection capillary pressure (MICP) analyses (n=3) indicate porosity ranges 1.3-2.1% and permeability 0.006-0.02 µD for Pine Island and Rodessa shales. Overall, results from this work indicate generally poor ‘shale gas’ prospectivity compared to other shale reservoirs based primarily on depth, low organic content, low porosity, and high clay content. However, thickness and thermal maturity are appropriate, moderate reservoir pressures are present, and petroleum systems modelling by others has indicated high undiscovered gas potential for the basin as a whole.
Introduction As the source rocks from which petroleum is generated, organic-rich shales have always been considered an important component of petroleum systems. Over the last few years, it has been realized that in some mudrocks, sufficient hydrocarbons remain in place to allow for commercial development, although advanced drilling and completion technology is typically required to access hydrocarbons from these reservoirs. Tight oil reservoirs (also referred to as continuous oil accumulations) contain hydrocarbons migrated from source rocks that are geologically/stratigraphically interbedded with or occur immediately overlying/underlying them. Migration is minimal in charging these tight oil accumulations (Gaswirth and Marra 2014 ). Companies around the world are now successfully exploiting organic-rich shales and tight rocks for contained hydrocarbons, and the search for these types of unconventional petroleum reservoirs is growing. Unconventional reservoirs range in geologic age from Ordovician to Tertiary (Silverman et al. 2005 ; EIA 2013a ).