Geology topics

R.J. Hill

Publications and source records attributed to R.J. Hill.

6 recordsLinked to original sources

USGS2007

Geologic framework of the Mississippian Barnett Shale, Barnett-Paleozoic total petroleum system, Bend arch-Fort Worth Basin, Texas

This article describes the primary geologic characteristics and criteria of the Barnett Shale and Barnett-Paleozoic total petroleum system (TPS) of the Fort Worth Basin used to define two geographic areas of the Barnett Shale for petroleum resource assessment. From these two areas, referred to as "assessment units," the U.S. Geological Survey estimated a mean volume of about 26 tcf of undiscovered, technically recoverable hydrocarbon gas in the Barnett Shale. The Mississippian Barnett Shale is the primary source rock for oil and gas produced from Paleozoic reservoir rocks in the Bend arch-Fort Worth Basin area and is also one of the most significant gas-producing formations in Texas. Subsurface mapping from well logs and commercial databases and petroleum geochemistry demonstrate that the Barnett Shale is organic rich and thermally mature for hydrocarbon generation over most of the Bend arch-Fort Worth Basin area. In the northeastern and structurally deepest part of the Fort Worth Basin adjacent to the Muenster arch, the formation is more than 1000 ft (305 m) thick and interbedded with thick limestone units; westward, it thins rapidly over the Mississippian Chappel shelf to only a few tens of feet. The Barnett-Paleozoic TPS is identified where thermally mature Barnett Shale has generated large volumes of hydrocarbons and is (1) contained within the Barnett Shale unconventional continuous accumulation and (2) expelled and distributed among numerous conventional clastic- and carbonate-rock reservoirs of Paleozoic age. Vitrinite reflectance (Ro) measurements show little correlation with present-day burial depth. Contours of equal Ro values measured from Barnett Shale and typing of produced hydrocarbons indicate significant uplift and erosion. Furthermore, the thermal history of the formation was enhanced by hydrothermal events along the Ouachita thrust front and Mineral Wells-Newark East fault system. Stratigraphy and thermal maturity define two gas-producing assessment units for the Barnett Shale: (1) a greater Newark East fracture-barrier continuous Barnett Shale gas assessment unit, encompassing an area of optimal gas production where dense impermeable limestones enclose thick (???300 ft; ???91 m) Barnett Shale that is within the gas-generation window (Ro ??? 1.1%); and (2) an extended continuous Barnett Shale gas assessment unit covering an area where the Barnett Shale is within the gas-generation window, but is less than 300 ft (91 m) thick, and either one or both of the overlying and underlying limestone barriers are absent. Copyright ?? 2007. The American Association of Petroleum Geologists. All rights reserved.

American Association of Petroleum Geologists Bulle↗

USGS2007

Oil and gas geochemistry and petroleum systems of the Fort Worth Basin

Detailed biomarker and light hydrocarbon geochemistry confirm that the marine Mississippian Barnett Shale is the primary source rock for petroleum in the Fort Worth Basin, north-central Texas, although contributions from other sources are possible. Biomarker data indicate that the main oil-generating Barnett Shale facies is marine and was deposited under dysoxic, strong upwelling, normal salinity conditions. The analysis of two outcrop samples and cuttings from seven wells indicates variability in the Barnett Shale organic facies and a possibility of other oil subfamilies being present. Light hydrocarbon analyses reveal significant terrigenous-sourced condensate input to some reservoirs, resulting in terrigenous and mixed marine-terrigenous light hydrocarbon signatures for many oils. The light hydrocarbon data suggest a secondary, condensate-generating source facies containing terrigenous or mixed terrigenous-marine organic matter. This indication of a secondary source rock that is not revealed by biomarker analysis emphasizes the importance of integrating biomarker and light hydrocarbon data to define petroleum source rocks. Gases in the Fort Worth Basin are thermogenic in origin and appear to be cogenerated with oil from the Barnett Shale, although some gas may also originate by oil cracking. Isotope data indicate minor contribution of biogenic gas. Except for reservoirs in the Pennsylvanian Bend Group, which contain gases spanning the complete range of observed maturities, the gases appear to be stratigraphically segregated, younger reservoirs contain less mature gas, and older reservoirs contain more mature gas. We cannot rule out the possibility that other source units within the Fort Worth Basin, such as the Smithwick Shale, are locally important petroleum sources. Copyright ?? 2007. The American Association of Petroleum Geologists. All rights reserved.

American Association of Petroleum Geologists Bulle↗

USGS2007

Modeling of gas generation from the Barnett Shale, Fort Worth Basin, Texas

The generative gas potential of the Mississippian Barnett Shale in the Fort Worth Basin, Texas, was quantitatively evaluated by sealed gold-tube pyrolysis. Kinetic parameters for gas generation and vitrinite reflectance (Ro) changes were calculated from pyrolysis data and the results used to estimate the amount of gas generated from the Barnett Shale at geologic heating rates. Using derived kinetics for Ro evolution and gas generation, quantities of hydrocarbon gas generated at Ro ??? 1.1% are about 230 L/t (7.4 scf/t) and increase to more that 5800 L/t (186 scf/t) at Ro ??? 2.0% for a sample with an initial total organic carbon content of 5.5% and Ro = 0.44%. The volume of shale gas generated will depend on the organic richness, thickness, and thermal maturity of the shale and also the amount of petroleum that is retained in the shale during migration. Gas that is reservoired in shales appears to be generated from the cracking of kerogen and petroleum that is retained in shales, and that cracking of the retained petroleum starts by Ro ??? 1.1%. This result suggests that the cracking of petroleum retained in source rocks occurs at rates that are faster than what is predicted for conventional siliciclastic and carbonate reservoirs, and that contact of retained petroleum with kerogen and shale mineralogy may be a critical factor in shale-gas generation. Shale-gas systems, together with overburden, can be considered complete petroleum systems, although the processes of petroleum migration, accumulation, and trap formation are different from what is defined for conventional petroleum systems. Copyright ?? 2007. The American Association of Petroleum Geologists. All rights reserved.

American Association of Petroleum Geologists Bulle↗

USGS2007

Unconventional shale-gas systems: The Mississippian Barnett Shale of north-central Texas as one model for thermogenic shale-gas assessment

Shale-gas resource plays can be distinguished by gas type and system characteristics. The Newark East gas field, located in the Fort Worth Basin, Texas, is defined by thermogenic gas production from low-porosity and low-permeability Barnett Shale. The Barnett Shale gas system, a self-contained source-reservoir system, has generated large amounts of gas in the key productive areas because of various characteristics and processes, including (1) excellent original organic richness and generation potential; (2) primary and secondary cracking of kerogen and retained oil, respectively; (3) retention of oil for cracking to gas by adsorption; (4) porosity resulting from organic matter decomposition; and (5) brittle mineralogical composition. The calculated total gas in place (GIP) based on estimated ultimate recovery that is based on production profiles and operator estimates is about 204 bcf/section (5.78 ?? 109 m3/1.73 ?? 104 m3). We estimate that the Barnett Shale has a total generation potential of about 609 bbl of oil equivalent/ac-ft or the equivalent of 3657 mcf/ac-ft (84.0 m3/m3). Assuming a thickness of 350 ft (107 m) and only sufficient hydrogen for partial cracking of retained oil to gas, a total generation potential of 820 bcf/section is estimated. Of this potential, approximately 60% was expelled, and the balance was retained for secondary cracking of oil to gas, if sufficient thermal maturity was reached. Gas storage capacity of the Barnett Shale at typical reservoir pressure, volume, and temperature conditions and 6% porosity shows a maximum storage capacity of 540 mcf/ac-ft or 159 scf/ton. Copyright ?? 2007. The American Association of Petroleum Geologists. All rights reserved.

American Association of Petroleum Geologists Bulle↗

USGS2005

Petroleum geochemistry of oil and gas from Barbados: Implications for distribution of Cretaceous source rocks and regional petroleum prospectivity

Petroleum produced from the Barbados accretionary prism (at Woodbourne Field on Barbados) is interpreted as generated from Cretaceous marine shale deposited under normal salinity and dysoxic conditions rather than from a Tertiary source rock as previously proposed. Barbados oils correlate with some oils from eastern Venezuela and Trinidad that are positively correlated to extracts from Upper Cretaceous La Luna-like source rocks. Three distinct groups of Barbados oils are recognized based on thermal maturity, suggesting petroleum generation occurred at multiple levels within the Barbados accretionary prism. Biodegradation is the most significant process affecting Barbados oils resulting in increased sulfur content and decreased API gravity. Barbados gases are interpreted as thermogenic, having been co-generated with oil, and show mixing with biogenic gas is limited. Gas biodegradation occurred in two samples collected from shallow reservoirs at the Woodbourne Field. The presence of Cretaceous source rocks within the Barbados accretionary prism suggests that greater petroleum potential exists regionally, and perhaps further southeast along the passive margin of South America. Likewise, confirmation of a Cretaceous source rock indicates petroleum potential exists within the Barbados accretionary prism in reservoirs that are deeper than those from Woodbourne Field.

Marine and Petroleum Geology↗

USGS2003

Insights into oil cracking based on laboratory experiments

The objectives of this pyrolysis investigation were to determine changes in (1) oil composition, (2) gas composition and (3) gas carbon isotope ratios and to compare these results with hydrocarbons in reservoirs. Laboratory cracking of a saturate-rich Devonian oil by confined, dry pyrolysis was performed at T = 350-450??C, P = 650 bars and times ranging from 24 h to 33 days. Increasing thermal stress results in the C15+ hydrocarbon fraction cracking to form C6-14 and C1-5 hydrocarbons and pyrobitumen. The C6-14 fraction continues to crack to C 1-5 gases plus pyrobitumen at higher temperatures and prolonged heating time and the ?? 13Cethane-?? 13Cpropane difference becomes greater as oil cracking progresses. There is considerable overlap in product generation and product cracking. Oil cracking products accumulate either because the rate of generation of any product is greater than the rate of removal by cracking of that product or because the product is a stable end member under the experimental conditions. Oil cracking products decrease when the amount of product generated from a reactant is less than the amount of product cracked. If pyrolysis gas compositions are representative of gases generated from oil cracking in nature, then understanding the processes that alter natural gas composition is critical. ?? 2003 Elsevier Ltd. All rights reserved.

Organic Geochemistry↗