Geology Reports⌕ Search

SEARCH · Geology Reports

Results for “American Association of Petroleum Geologists Bulletin”

Search indexed USGS publications on groundwater, aquifers, geologic maps, mineral resources and earthquakes. Explore source records by subject and place.

Quote a phrase for an exact phrase match. Source license links do not imply unrestricted reuse.

At least 73 records · Page 4Linked to original sources
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↗
USGS1991

Implications for organic maturation studies of evidence of a geologically rapid increase and stabilization of vitrinite reflectance at peak temperature: Cerro Prieto geothermal system, Mexico

A short-term rapid heating and cooling of the rock in well M-94 below 1300 m was caused by a pulse of hot water passing through the edge of the Cerro Prieto, Mexico, geothermal system. Below 1300 m, the peak paleotemperatures were about 225-250 degrees C, but equilibrium well log temperatures indicate a decrease to 150-210 degrees C at present. This hot water pulse sharply increased vitrinite reflectance to levels comparable to those measured in the central part of the system, even though studies of apatite fission-track annealing indicate that the duration of heating was only 10{0}-10{1} yr in M-94, in contrast to 10{3}-10{4} yr in the central part of the system. These data indicate that sedimentary organic matter chemically reacts quickly to temperature increases of about 125 degrees C above ambient, even when the higher temperature existed for only 10{0}-10{1} yr. The quick change of the vitrinite reflectance geothermometer indicates that thermal maturation reactions can stabilize, after a geologically short period of heating, to a level consistent with peak temperature under moderate to high-temperature diagenesis in open, fluid-rich, geothermal systems. Cerro Prieto is one of the most intensively studied and well-known geothermal systems in the world. Thus, data from Cerro Prieto are a benchmark to compare with the predictions of published thermal maturation models such as those formulated by J. Karweil, N. V. Lopatin, and A. K. Burnham and J. J. Sweeney. These thermal maturation models inaccurately predict duration of heating at Cerro Prieto. The kinetic equations used in these models explicitly allow thermal maturation to continue indefinitely at peak temperature, which does not seem to be the case at Cerro Prieto.

Cerro Prieto fault↗
USGS2009

Stratigraphic framework and estuarine depositional environments of the Miocene Bear Lake Formation, Bristol Bay Basin, Alaska: Onshore equivalents to potential reservoir strata in a frontier gas-rich basin

The Miocene Bear Lake Formation is exposed along the coast and mountains of the central Alaska Peninsula and extends offshore as part of the Bristol Bay Basin. The Bear Lake Formation is up to 2360 m (7743 ft) thick in an offshore well and is considered to have the highest reservoir potential in this gasrich frontier basin. Our new macrofossil and palynological data, collected in the context of measured stratigraphic sections, allow us to construct the first chronostratigraphic framework for this formation. Biostratigraphic age assignments for the numerous, commonly isolated, onshore exposures of the Bear Lake Formation show that deposition initiated sometime before the middle Miocene (15 Ma) and extended to possibly the earliest Pliocene. The bulk of the Bear Lake Formation, however, was deposited during the middle and late Miocene based on our new findings. We interpret the Bear Lake Formation as the product of a regional transgressive estuarine depositional system based on lithofacies analysis. The lower part of the formation is characterized by trough cross-stratified sandstone interbedded with coal and pedogenic mudstone deposited in fluvial and swamp environments of the uppermost parts of the estuarine system. The lower-middle part of the formation is dominated by nonbioturbated, wavy- and flaser-bedded sandstone and siltstone that were deposited in supratidal flat environments. The uppermiddle part of the Bear Lake Formation is characterized by inclined heterolithic strata and coquinoid mussel beds that represent tidal channel environments in the middle and lower tracts of the estuarine system. The uppermost part of the formation consists of tabular, bioturbated sandstone with diverse marine invertebrate macrofossil faunas. We interpret this part of the section as representing the subtidal tract of the lower estuarine system and possibly the adjacent shallow inner shelf. A comparison of our depositional framework for the Bear Lake Formation with core and well-log data from onshore and offshore wells indicates that similar Miocene depositional systems existed throughout much of the Bristol Bay Basin. The documented changes in depositional environments within the Bear Lake Formation are also important for understanding upsection changes in the geometries of potential reservoirs. Copyright ??2009. The American Association of Petroleum Geologists. All rights reserved.

American Association of Petroleum Geologists Bulle↗
USGS2006

Evaluation of kinetic uncertainty in numerical models of petroleum generation

Oil-prone marine petroleum source rocks contain type I or type II kerogen having Rock-Eval pyrolysis hydrogen indices greater than 600 or 300-600 mg hydrocarbon/g total organic carbon (HI, mg HC/g TOC), respectively. Samples from 29 marine source rocks worldwide that contain mainly type II kerogen (HI = 230-786 mg HC/g TOC) were subjected to open-system programmed pyrolysis to determine the activation energy distributions for petroleum generation. Assuming a burial heating rate of 1??C/m.y. for each measured activation energy distribution, the calculated average temperature for 50% fractional conversion of the kerogen in the samples to petroleum is approximately 136 ?? 7??C, but the range spans about 30??C (???121-151??C). Fifty-two outcrop samples of thermally immature Jurassic Oxford Clay Formation were collected from five locations in the United Kingdom to determine the variations of kinetic response for one source rock unit. The samples contain mainly type I or type II kerogens (HI = 230-774 mg HC/g TOC). At a heating rate of 1??C/m.y., the calculated temperatures for 50% fractional conversion of the Oxford Clay kerogens to petroleum differ by as much as 23??C (127-150??C). The data indicate that kerogen type, as defined by hydrogen index, is not systematically linked to kinetic response, and that default kinetics for the thermal decomposition of type I or type II kerogen can introduce unacceptable errors into numerical simulations. Furthermore, custom kinetics based on one or a few samples may be inadequate to account for variations in organofacies within a source rock. We propose three methods to evaluate the uncertainty contributed by kerogen kinetics to numerical simulations: (1) use the average kinetic distribution for multiple samples of source rock and the standard deviation for each activation energy in that distribution; (2) use source rock kinetics determined at several locations to describe different parts of the study area; and (3) use a weighted-average method that combines kinetics for samples from different locations in the source rock unit by giving the activation energy distribution for each sample a weight proportional to its Rock-Eval pyrolysis S2 yield (hydrocarbons generated by pyrolytic degradation of organic matter). Copyright ?? 2006. The American Association of Petroleum Geologists. All rights reserved.

American Association of Petroleum Geologists Bulle↗
USGS2021

Molecular and isotopic gas composition of the Devonian Berea Sandstone and implications for gas evolution, eastern Kentucky

Since 2011, the Devonian Berea Sandstone in northeastern Kentucky has produced oil where thermal maturity studies indicate that likely source rocks, namely, the Devonian Ohio Shale and Mississippian Sunbury Shale, are thermally immature. Downdip, where source rocks are mature for oil, the Berea Sandstone and Ohio Shale primarily produce gas. To investigate this thermal maturity discordancy, the molecular and isotopic composition of gases from the Berea Sandstone (oil associated) and Ohio Shale (nonassociated) were analyzed to understand the gas generation and migration history. Collected along a northwest-southeast transect in eastern Kentucky, samples range from 1079 to 4602 ft, respectively. All are wet gases with a thermogenic origin (δ 13 C-CH 4 = −53.5‰ to −46.1‰). This is mostly consistent with a reevaluation of thermal maturity in a companion study that expands the area mature for oil. Gas migration is required, however, in updip parts of the Berea play where vitrinite reflectance ( VR o ) values are less than 0.6%. Southeast regional dip exerts a first-order influence on thermal maturity as gases become drier and isotopically heavier downdip. Correlation of δ 13 C values for heavier hydrocarbon gases in a natural gas plot with VR o contour spacing demonstrates the influence of nearby source rock thermal maturity on gas composition. Downdip, migration of oil and the attendant increase in permeability relative to gas may account for the dominance of gas production in the Ohio Shale. Migration along with basin uplift after the Alleghany orogeny may have contributed to development of a gas phase that exsolved from oil.

Kentucky↗
USGS2009

Pore-throat sizes in sandstones, tight sandstones, and shales

Pore-throat sizes in silidclastic rocks form a continuum from the submillimeter to the nanometer scale. That continuum is documented in this article using previously published data on the pore and pore-throat sizes of conventional reservoir rocks, tight-gas sandstones, and shales. For measures of central tendency (mean, mode, median), pore-throat sizes (diameters) are generally greater than 2 μm in conventional reservoir rocks, range from about 2 to 0.03 μm in tight-gas sandstones, and range from 0.1 to 0.005 μm in shales. Hydrocarbon molecules, asphaltenes, ring structures, paraffins, and methane, form another continuum, ranging from 100 Å (0.01 μm for asphaltenes to 3.8 A (0.00038 μm) for methane. The pore-throat size continuum provides a useful perspective for considering (1) the emplacement of petroleum in consolidated siliciclastics and (2) fluid flow through fine-grained source rocks now being exploited as reservoirs.

American Association of Petroleum Geologists Bulle↗
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

Paleovalley fills: Trunk vs. tributary

A late Mississippian-early Pennsylvanian eustatic sea level drop resulted in a complex lowstand drainage network being eroded across the Illinois Basin in the eastern United States. This drainage system was filled during the early part of the Pennsylvanian. Distinct differences can be recognized between the trunk and tributary paleovalley fills. Fills preserved within the trunk systems tend to be fluvially dominated and consist of bed-load deposits of coarse- to medium-grained sandstone and conglomerate. Conversely, the incised valleys of tributary systems tend to be filled with dark mudstone, thinly interbedded sandstones, and mudstones and siltstones. These finer grained facies exhibit marine influences manifested by tidal rhythmites, certain traces fossils, and macro- and microfauna. Examples of tributary and trunk systems, separated by no more than 7 km (4.3 mi) along strike, exhibit these styles of highly contrasting fills. Useful analogs for understanding this Pennsylvanian system include the Quaternary glacial sluiceways present in the lower Ohio, White, and Wabash river valleys of Indiana (United States) and the modern Amazon River (Brazil). Both the Amazon River and the Quaternary rivers of Indiana have (or had) trunk rivers that are (were) dominated by large quantities of bed load relative to their tributaries. The trunk valley systems of these analogs aggraded much more rapidly than their tributary valleys, which evolved into lakes because depositional rates along the trunk are (were) so high that the mouths of the tributaries have been dammed by bed-load deposits. These Holocene systems illustrate that sediment yields can significantly influence the nature of fill successions within incised valleys independent of rates of sea level changes or proximity to highstand coastlines. Copyright ?? 2007. The American Association of Petroleum Geologists. All rights reserved.

American Association of Petroleum Geologists Bulle↗
USGS2008

Mesozoic (Upper Jurassic-Lower Cretaceous) deep gas reservoir play, central and eastern Gulf coastal plain

The Mesozoic (Upper Jurassic-Lower Cretaceous) deeply buried gas reservoir play in the central and eastern Gulf coastal plain of the United States has high potential for significant gas resources. Sequence-stratigraphic study, petroleum system analysis, and resource assessment were used to characterize this developing play and to identify areas in the North Louisiana and Mississippi Interior salt basins with potential for deeply buried gas reservoirs. These reservoir facies accumulated in Upper Jurassic to Lower Cretaceous Norphlet, Haynesville, Cotton Valley, and Hosston continental, coastal, and marine siliciclastic environments and Smackover and Sligo nearshore marine shelf, ramp, and reef carbonate environments. These Mesozoic strata are associated with transgressive and regressive systems tracts. In the North Louisiana salt basin, the estimate of secondary, nonassociated thermogenic gas generated from thermal cracking of oil to gas in the Upper Jurassic Smackover source rocks from depths below 3658 m (12,000 ft) is 4800 tcf of gas as determined using software applications. Assuming a gas expulsion, migration, and trapping efficiency of 2-3%, 96-144 tcf of gas is potentially available in this basin. With some 29 tcf of gas being produced from the North Louisiana salt basin, 67-115 tcf of in-place gas remains. Assuming a gas recovery factor of 65%, 44-75 tcf of gas is potentially recoverable. The expelled thermogenic gas migrated laterally and vertically from the southern part of this basin to the updip northern part into shallower reservoirs to depths of up to 610 m (2000 ft). Copyright ?? 2008. The American Association of Petroleum Geologists. All rights reserved.

American Association of Petroleum Geologists Bulle↗
USGS2012

Source rock contributions to the Lower Cretaceous heavy oil accumulations in Alberta: a basin modeling study

The origin of the immense oil sand deposits in Lower Cretaceous reservoirs of the Western Canada sedimentary basin is still a matter of debate, specifically with respect to the original in-place volumes and contributing source rocks. In this study, the contributions from the main source rocks were addressed using a three-dimensional petroleum system model calibrated to well data. A sensitivity analysis of source rock definition was performed in the case of the two main contributors, which are the Lower Jurassic Gordondale Member of the Fernie Group and the Upper Devonian–Lower Mississippian Exshaw Formation. This sensitivity analysis included variations of assigned total organic carbon and hydrogen index for both source intervals, and in the case of the Exshaw Formation, variations of thickness in areas beneath the Rocky Mountains were also considered. All of the modeled source rocks reached the early or main oil generation stages by 60 Ma, before the onset of the Laramide orogeny. Reconstructed oil accumulations were initially modest because of limited trapping efficiency. This was improved by defining lateral stratigraphic seals within the carrier system. An additional sealing effect by biodegraded oil may have hindered the migration of petroleum in the northern areas, but not to the east of Athabasca. In the latter case, the main trapping controls are dominantly stratigraphic and structural. Our model, based on available data, identifies the Gordondale source rock as the contributor of more than 54% of the oil in the Athabasca and Peace River accumulations, followed by minor amounts from Exshaw (15%) and other Devonian to Lower Jurassic source rocks. The proposed strong contribution of petroleum from the Exshaw Formation source rock to the Athabasca oil sands is only reproduced by assuming 25 m (82 ft) of mature Exshaw in the kitchen areas, with original total organic carbon of 9% or more.

Alberta↗
USGS2013

Petroleum system analysis of the Hunton Group in West Edmond field, Oklahoma

West Edmond field, located in central Oklahoma, is one of the largest oil accumulations in the Silurian–Devonian Hunton Group in this part of the Anadarko Basin. Production from all stratigraphic units in the field exceeds 170 million barrels of oil (MMBO) and 400 billion cubic feet of gas (BCFG), of which approximately 60 MMBO and 100 BCFG have been produced from the Hunton Group. Oil and gas are stratigraphically trapped to the east against the Nemaha uplift, to the north by a regional wedge-out of Hunton strata, and by intraformational diagenetic traps. Hunton Group reservoirs are the Bois d'Arc and Frisco Limestones, with lesser production from the Chimneyhill subgroup, Haragan Shale, and Henryhouse Formation. Hunton Group cores from three wells that were examined petrographically indicate that complex diagenetic relations influence permeability and reservoir quality. Greatest porosity and permeability are associated with secondary dissolution in packstones and grainstones, forming hydrocarbon reservoirs. The overlying Devonian–Mississippian Woodford Shale is the major petroleum source rock for the Hunton Group in the field, based on one-dimensional and four-dimensional petroleum system models that were calibrated to well temperature and Woodford Shale vitrinite reflectance data. The source rock is marginally mature to mature for oil generation in the area of the West Edmond field, and migration of Woodford oil and gas from deeper parts of the basin also contributed to hydrocarbon accumulation.

Oklahoma↗
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↗
USGS2011

Pore-throat sizes in sandstones, siltstones, and shales: Reply

In his discussion of my article (Nelson, 2009), W. K. Camp takes issue with the concept that buoyancy is not the dominant force in forming and maintaining the distribution of gas in tight-gas accumulations (Camp, 2011). I will restrict my response to the issues he raised regarding buoyant versus nonbuoyant drive and to a few comments regarding water saturation and production. I claim that the pressure generated in petroleum source rocks (P g ), instead of the buoyancy pressure (P b ), provides the energy to charge most tight sandstones with gas. The arguments are fourfold: (1) buoyant columns of sufficient height seldom exist in low-permeability sand-shale sequences, (2) tight-gas systems display a pressure profile that declines instead of increases upward, (3) gas is pervasive in overpressured systems, and (4) source rocks can generate pore pressures sufficiently high to charge tight sandstones.

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↗
USGS2007

Circum-Arctic petroleum systems identified using decision-tree chemometrics

Source- and age-related biomarker and isotopic data were measured for more than 1000 crude oil samples from wells and seeps collected above approximately 55??N latitude. A unique, multitiered chemometric (multivariate statistical) decision tree was created that allowed automated classification of 31 genetically distinct circumArctic oil families based on a training set of 622 oil samples. The method, which we call decision-tree chemometrics, uses principal components analysis and multiple tiers of K-nearest neighbor and SIMCA (soft independent modeling of class analogy) models to classify and assign confidence limits for newly acquired oil samples and source rock extracts. Geochemical data for each oil sample were also used to infer the age, lithology, organic matter input, depositional environment, and identity of its source rock. These results demonstrate the value of large petroleum databases where all samples were analyzed using the same procedures and instrumentation. Copyright ?? 2007. The American Association of Petroleum Geologists. All rights reserved.

American Association of Petroleum Geologists Bulle↗