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USGS2008

Restoration of Circum-Arctic Upper Jurassic source rock paleolatitude based on crude oil geochemistry

Tectonic geochemical paleolatitude (TGP) models were developed to predict the paleolatitude of petroleum source rock from the geochemical composition of crude oil. The results validate studies designed to reconstruct ancient source rock depositional environments using oil chemistry and tectonic reconstruction of paleogeography from coordinates of the present day collection site. TGP models can also be used to corroborate tectonic paleolatitude in cases where the predicted paleogeography conflicts with the depositional setting predicted by the oil chemistry, or to predict paleolatitude when the present day collection locality is far removed from the source rock, as might occur due to long distance subsurface migration or transport of tarballs by ocean currents. Biomarker and stable carbon isotope ratios were measured for 496 crude oil samples inferred to originate from Upper Jurassic source rock in West Siberia, the North Sea and offshore Labrador. First, a unique, multi-tiered chemometric (multivariate statistics) decision tree was used to classify these samples into seven oil families and infer the type of organic matter, lithology and depositional environment of each organofacies of source rock [Peters, K.E., Ramos, L.S., Zumberge, J.E., Valin, Z.C., Scotese, C.R., Gautier, D.L., 2007. Circum-Arctic petroleum systems identified using decision-tree chemometrics. American Association of Petroleum Geologists Bulletin 91, 877-913]. Second, present day geographic locations for each sample were used to restore the tectonic paleolatitude of the source rock during Late Jurassic time (???150 Ma). Third, partial least squares regression (PLSR) was used to construct linear TGP models that relate tectonic and geochemical paleolatitude, where the latter is based on 19 source-related biomarker and isotope ratios for each oil family. The TGP models were calibrated using 70% of the samples in each family and the remaining 30% of samples were used for model validation. Positive relationships exist between tectonic and geochemical paleolatitude for each family. Standard error of prediction for geochemical paleolatitude ranges from 0.9?? to 2.6?? of tectonic paleolatitude, which translates to a relative standard error of prediction in the range 1.5-4.8%. The results suggest that the observed effect of source rock paleolatitude on crude oil composition is caused by (i) stable carbon isotope fractionation during photosynthetic fixation of carbon and (ii) species diversity at different latitudes during Late Jurassic time. ?? 2008 Elsevier Ltd. All rights reserved.

Organic Geochemistry↗
USGS2014

Activities in tectonics of Research Committee of American Association of Petroleum Geologists

During 1945 and 1946, the Research Committee of the American Association of Petroleum Geologists, under the chairmanship of Shepard W. Lowman, has been engaged in “a reconnaissance survey of research in petroleum geology and allied sciences with explicit reference to exploration” in order “to formulate a comprehensive research program which the American Association of Petroleum Geologists may adopt as its recommendation for that research most needed to improve our ability to find oil” [see “References” at end of report, Lowman, 1945]. In order to make this survey, the field was divided among a number of subcommittees, including a Subcommittee on Tectonics, of which the writer was chairman. Preliminary reports, discussing the research possibilities in the various fields covered by the subcommittees, were submitted in January, 1946, and concrete recommendations were formulated by the Research Committee at the Chicago meeting of the Association in April 1946 [Lowman, 1946]. Final reports of the subcommittees will be published later in 1946 in the Bulletin of the American Association of Petroleum Geologists.

Eos, Transactions, American Geophysical Union↗
USGS2008

Flow unit modeling and fine-scale predicted permeability validation in Atokan sandstones: Norcan East Kansas

Characterizing the reservoir interval into flow units is an effective way to subdivide the net-pay zone into layers for reservoir simulation. Commonly used flow unit identification techniques require a reliable estimate of permeability in the net pay on a foot-by-foot basis. Most of the wells do not have cores, and the literature is replete with different kinds of correlations, transforms, and prediction methods for profiling permeability in pay. However, for robust flow unit determination, predicted permeability at noncored wells requires validation and, if necessary, refinement. This study outlines the use o f a spreadsheet-based permeability validation technique to characterize flow units in wells from the Norcan East field, Clark County, Kansas, that produce from Atokan aged fine- to very fine-grained quartzarenite sandstones interpreted to have been deposited in brackish-water, tidally dominated restricted tidal-flat, tidal-channel, tidal-bar, and estuary bay environments within a small incised-valley-fill system. The methodology outlined enables the identification of fieldwide free-water level and validates and refines predicted permeability at 0.5-ft (0.15-m) intervals by iteratively reconciling differences in water saturation calculated from wire-line log and a capillary-pressure formulation that models fine- to very fine-grained sandstone with diagenetic clay and silt or shale laminae. The effectiveness of this methodology was confirmed by successfully matching primary and secondary production histories using a flow unit-based reservoir model of the Norcan East field without permeability modifications. The methodologies discussed should prove useful for robust flow unit characterization of different kinds of reservoirs. Copyright ?? 2008. The American Association of Petroleum Geologists. All rights reserved.

American Association of Petroleum Geologists Bulle↗
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↗
USGS2004

Climate change: Conflict of observational science, theory, and politics

Debate over whether human activity causes Earth climate change obscures the immensity of the dynamic systems that create and maintain climate on the planet. Anthropocentric debate leads people to believe that they can alter these planetary dynamic systems to prevent that they perceive as negative climate impacts on human civilization. Although politicians offer simplistic remedies, such as the Kyoto Protocol, global climate continues to change naturally. Better planning for the inevitable dislocations that have followed natural global climate changes throughout human history requires us to accept the fact that climate will change, and that human society must adapt to the changes. Over the last decade, the scientific literature reported a shift in emphasis from attempting to build theoretical models of putative human impacts on climate to understanding the planetwide dynamic processes that are the natural climate drivers. The current scientific literature is beginning to report the history of past climate change, the extent of natural climate variability, natural system drivers, and the episodicity of many climate changes. The scientific arguments have broadened from focus upon human effects on climate to include the array of natural phenomena that have driven global climate change for eons. However, significant political issues with long-term social consequences continue their advance. This paper summarizes recent scientific progress in climate science and arguments about human influence on climate. ?? 2004. The American Association of Petroleum Geologists. All rights reserved.

American Association of Petroleum Geologists Bulle↗
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↗
USGS2005

An evaluation of the U.S. Geological Survey World Petroleum Assessment 2000

This study compares the additions to conventional crude oil and natural gas reserves as reported from January 1996 to December 2003 with the estimated undiscovered and reserve-growth volumes assessed in the U.S. Geological Survey World Petroleum Assessment 2000, which used data current through 1995. Approximately 28% of the estimated additions to oil reserves by reserve growth and approximately 11% of the estimated undiscovered oil volumes were realized in the 8 yr since the assessment (27% of the time frame for the assessment). Slightly more than half of the estimated additions to gas reserves by reserve growth and approximately 10% of the estimated undiscovered gas volumes were realized. Between 1995 and 2003, growth of oil reserves in previously discovered fields exceeded new-field discoveries as a source of global additions to reserves of conventional oil by a ratio of 3:1. The greatest amount of reserve growth for crude oil occurred in the Middle East and North Africa, whereas the greatest contribution from new-field discoveries occurred in sub-Saharan Africa. The greatest amount of reserve growth for natural gas occurred in the Middle East and North Africa, whereas the greatest contribution from new-field discoveries occurred in the Asia Pacific region. On an energy-equivalent basis, volumes of new gas-field discoveries exceeded new oil-field discoveries. Copyright ?? 2005. The American Association of Petroleum Geologists. All rights reserved.

American Association of Petroleum Geologists Bulle↗
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↗
USGS2008

Families of miocene monterey crude oil, seep, and tarball samples, coastal California

Biomarker and stable carbon isotope ratios were used to infer the age, lithology, organic matter input, and depositional environment of the source rocks for 388 samples of produced crude oil, seep oil, and tarballs to better assess their origins and distributions in coastal California. These samples were used to construct a chemometric (multivariate statistical) decision tree to classify 288 additional samples. The results identify three tribes of 13C-rich oil samples inferred to originate from thermally mature equivalents of the clayey-siliceous, carbonaceous marl and lower calcareous-siliceous members of the Monterey Formation at Naples Beach near Santa Barbara. An attempt to correlate these families to rock extracts from these members in the nearby COST (continental offshore stratigraphic test) (OCS-Cal 78-164) well failed, at least in part because the rocks are thermally immature. Geochemical similarities among the oil tribes and their widespread distribution support the prograding margin model or the banktop-slope-basin model instead of the ridge-and-basin model for the deposition of the Monterey Formation. Tribe 1 contains four oil families having geochemical traits of clay-rich marine shale source rock deposited under suboxic conditions with substantial higher plant input. Tribe 2 contains four oil families with traits intermediate between tribes 1 and 3, except for abundant 28,30-bisnorhopane, indicating suboxic to anoxic marine marl source rock with hemipelagic input. Tribe 3 contains five oil families with traits of distal marine carbonate source rock deposited under anoxic conditions with pelagic but little or no higher plant input. Tribes 1 and 2 occur mainly south of Point Conception in paleogeographic settings where deep burial of the Monterey source rock favored petroleum generation from all three members or their equivalents. In this area, oil from the clayey-siliceous and carbonaceous marl members (tribes 1 and 2) may overwhelm that from the lower calcareous-siliceous member (tribe 3) because the latter is thinner and less oil-prone than the overlying members. Tribe 3 occurs mainly north of Point Conception where shallow burial caused preferential generation from the underlying lower calcareous-siliceous member or another unit with similar characteristics. In a test of the decision tree, 10 tarball samples collected from beaches in Monterey and San Mateo counties in early 2007 were found to originate from natural seeps representing different organofacies of Monterey Formation source rock instead from one anthropogenic pollution event. The seeps apparently became more active because of increased storm activity. Copyright ?? 2008. The American Association of Petroleum Geologists. All rights reserved.

American Association of Petroleum Geologists Bulle↗
USGS2005

Egret-Hibernia(!), a significant petroleum system, northern Grand Banks area, offshore eastern Canada

Egret-Hibernia(!) is a well-explored petroleum system (3.25 billion barrels oil equivalent [BOE]) located in the Jeanne d'Arc Basin on the Labrador - Newfoundland shelf. Rifting and sediment fill began in the Late Triassic. Egret source rock was deposited in the Late Jurassic at about 153 Ma. After this time, alternating reservoir rock and seal rock were deposited with some syndepositional faulting. By the end of the Early Cretaceous, faults and folds had formed numerous structural traps. For the next 100 m.y., overburden rock thermally matured the source rock when it reached almost 4 km (2.5 mi) burial depth. For 2 km (1.25 mi) below this depth, oil and gas were expelled, until the source was depleted. The expelled petroleum migrated updip to nearby faulted, anticlinal traps, where much of it migrated across faults and upsection to the Hibernia Formation (44% recoverable oil) and Avalon Formation (28%). Accumulation size decreased, and gas content increased from west to east, independent of trap size. These changes correspond to a decrease in source rock richness and quality from west to east. Almost all (96%) of the discovered petroleum resides in the Lower Cretaceous or older reservoir rock units. All accumulations found to date are normally pressured in structural traps. Fifty-two exploration wells found eighteen discoveries. Their size ranges from 1.2 to 0.01 billion BOE. Most discoveries were made between 1979 and 1991. The discovery cycle began with larger accumulations and progressed to smaller accumulations. The estimated sizes of the larger accumulations have grown since 1990. Estimated mean value for undiscovered hydrocarbons is 3.8 billion BOE, thereby raising the ultimate size of Egret-Hibernia(!) to 6.19 billion BOE. Copyright ?? 2005. The American Association of Petroleum Geologists. All rights reserved.

American Association of Petroleum Geologists Bulle↗