Gary A. Cole

Organic Geochemistry and Oil-Source Correlations, Paleozoic of Ohio

Routine analytical methods and new kerogen-kerogen pyrolyzate techniques used for detailed petroleum geochemical studies permit the correlation of oils to their respective source rocks in Ohio. In the Paleozoic section, four good to excellent source units were identified: the Mississippian Sunbury Shale, the Devonian Ohio Shale and Olentangy Shale, and the shales of the Ordovician Point Pleasant Formation. These marine shales are dominantly oil-prone, with maturation levels that span the immature to peak oil-generation range. No source rocks examined exceeded an Ro of 1.0-1.1% (or equivalent). The reservoired oils in Ohio are mostly supermature, based on normal alkanes, pristane/n-C17 to phytane/n-C18 ratios, low asphaltene and sulfur contents, and high paraffin indices. Three basic oil groups were identified using oil characterization procedures: group 1 consists of Cambrian, Ordovician, and some Silurian oils; group 2 consists of some Silurian, Devonian, one Mississippian, and some Pennsylvanian oils; and group 3 consists of oil from the Mississippian Berea sandstone. Oil-source rock correlation techniques permitted the assignment of probable source rocks to each oil group. Group 1 oil was probably derived from the Point Pleasant shales, group 2 oil was derived from the Ohio Shale and Olentangy Shale, and group 3 oil came from the Sunbury Shale. Because the supermature oils in Ohio occur in reservoirs with maturities generally under 0.8% Ro, the oils would have had to migrate from deep within the Appalachian basin. Migration could have followed fracture zones, unconformities, or extensive and permeable units such as the Silurian Clinton sands.

Oligocene to Holocene hydrocarbon migration and salt-dome carbonates, northern Gulf of Mexico

Abstract The geochemistry and geology of Damon Mound salt dome in Brazoria County, Texas provides an insight to the timing of hydrocarbon migration and carbonate caprock development in the Houston salt-dome province. Reservoir rocks flanking the salt dome received a charge of crude oil from deeply buried Eocene source rocks during Early Oligocene-Early Miocene time. The light δ13C of the carbonate caprock at Damon Mound (−24.8 to −31.7‰ PDB) is consistent with an origin from bacterial oxidation of crude oil with similar δ13C (−27.1 to −28.8‰ PDB). A minimum weight estimate of carbonate caprock at Damon Mound is 32.7 × 106 metric tons, suggesting bacterial oxidation of about 34.2 × 106 barrels of crude oil to form the carbonate. Late Oligocene-Early Miocene erosional exposure of the carbonate caprock provided a hard substratum to initiate the development of a coral reef in an otherwise unfavourable mud-dominated environment. Although the bulk of the reef carbonate displays normal marine δ13C, some late carbonate cements show light δ13C values (−22.1 to −29.6‰) from bacterial hydrocarbon oxidation. Buried carbonate caprocks and coral reef facies serve as carbonate reservoir rocks over Gulf of Mexico salt domes, lending support to the hypothesis that intense hydrocarbon oxidation can, in itself, give rise to some carbonate reservoir rocks. Ongoing hydrocarbon migration from deeply buried Cretaceous source rocks and the development of embryonic carbonate caprocks over shallow salt domes on the present Gulf of Mexico continental slope offer analogies and contrasts to the processes that gave rise to carbonates at Damon Mound in the geological past.

Petroleum geochemistry of the Midyan and Jaizan basins of the Red Sea, Saudi Arabia

Abstract During the 1960s, petroleum exploration activities in the offshore Red Sea areas of Saudi Arabia tested gas and condensate reservoired in the Miocene sands immediately below the Mansiyah evaporites in the offshore Midyan basin. Recent onshore exploration activity in the Red Sea has resulted in the discovery of accumulations of oil, gas and condensate in the Lower Miocene Maqna Group in the Midyan and Jaizan basins. As a result of this exploration success, an effort to understand the origin of these hydrocarbons was initiated. The two basins were assessed geochemically by addressing: (1) the potential source rocks; (2) the extent of the hydrocarbon kitchens; and (3) characterization of the hydrocarbons. The potential source rocks for the reservoired hydrocarbons are: (1) the organic-rich, oil-prone shales of the predominantly evaporitic Mansiyah Formation; (2) the variable quality shales and carbonates of the Magna Group; and (3) the moderately organic-rich shales of the Burqan and Tayran Groups. The reservoired hydrocarbons were characterized by carbon isotopes, gas chromatography-mass spectrometry and gas chromatography and compared with the potential source rocks. The results showed an acceptable match to the Maqna and Burqan organic-rich units. Detailed burial history/thermal modelling projects were undertaken to assess the hydrocarbon kitchens of both basins. Results for the Midyan basin indicated that over large areas Tayran and Burqan sediments are oil to gas mature and may be sources for the gas and/or condensate accumulations, whereas the limited area of mature Maqna sediments may be responsible for sourcing the black oil accumulations. In the Jaizan basin, the Maqna and Burqan sediments range from high oil maturity to thermally spent due to high geothermal conditions and excessive burial. The burial of the source rocks increases fairly rapidly from east to west in the Jaizan basin.

Hydrocarbon Seepage and Salt Dome Related Carbonate Reservoir Rocks of the U. S. Gulf Coast

ABSTRACT Although most salt dome-related oil production in the Gulf Coast is from clastic reservoirs, oil has been produced from Tertiary carbonate reservoir facies within (1) carbonate cap rocks over salt domes, and (2) the Heterostegina zone coral reef facies of the Anahuac Formation. The only known surface exposure of both carbonates occurs over the Damon Mound salt dome, near Houston, where oil and thermogenic gas have been produced from early Oligocene to early Miocene reservoirs flanking the dome crest. The origin of carbonate cap rock with extremely light 13C values at Damon Mound is related to long-term microbial oxidation of crude oil and thermogenic gas that commenced during or prior to the early Oligocene. Exposure of the salt-dome cap rock by erosion offered a shallow-water carbonate hardground that favored localized development of the late Oligocene-early Miocene Heterostegina coral reef facies. Carbonate cements with extremely light 13C values in the reef facies suggest that hydrocarbon migration continued during reef development, simultaneous with downward development of the carbonate cap rock by replacement of anhydrite. Processes similar to those that operated at Damon Mound appear to explain the origin of carbonates in cold hydrocarbon seeps of the Gulf continental slope. Generalization of these observations suggests that intense hydrocarbon seepage could result in development of carbonate reservoir facies in other oil basins characterized by siliciclastic sediments and shallow salt.

Origin of the Tertiary reservoired hydrocarbons along the central Texas and Louisiana Gulf Coast rim

Tertiary reservoired hydrocarbons along the central Texas and Louisiana Gulf Coast rim were most likely derived from Paleocene/Eocene Wilcox Group and Sparta Formation marine shales. Sixteen total soluble extracts and >200 oil samples were analyzed using carbon isotopic techniques ({delta}{sup 13}C) and gas chromatography-mass spectometry (GC-MS). Results demonstrated that interpretations must use all types of data because Cretaceous derived and Tertiary derived oils overlap in southern Louisiana. When isotopic, sterane, hopane, and light hydrocarbon data are combined separation of classes become possible. Cretaceous oils and extracts have a full range of extended hopanes, a characteristic peak eluting immediately after C{sub 30} hopane and no oleanane. Paleogene oils and extracts have oleanane and a restricted range of extended hopanes. Regional trends indicate that eastern Louisiana oils were derived from the Sparta or a Sparta/Wilcox mix, the Mississippi delta oils from a Cretaceous clastic source, and western Louisiana and Texas oils from the Wilcox source. Regional variations in GOR/CGR are a function of timing and mechanism of migration.

Ohio Paleozoic Source-Reservoir Combinations: Source Rock Quality and Source-Oil Correlation Studies: ABSTRACT

End_Page 1916------------------------------Although relatively simple structurally, the Interior Lowland area underlying Ohio and adjacent states constitutes a rich and varied hydrocarbon habitat. Structural style included influences of three subsidence episodes, broadly encompassing the Appalachian orogeny to the east and the Michigan and Illinois basins to the northwest and southwest, respectively. A sedimentary sequence covering the whole Paleozoic succession is variously present and becomes generally younger toward the southeast. Hydrocarbons are produced from numerous reservoir intervals within this Paleozoic section. Prominent among these are the Cambrian-Ordovician Knox Group, Ordovician Trenton Limestone, Silurian Medina Group, Devonian Oriskany and Vanango Sandstones, Mississippian Berea Sandstone, and Pennsylvanian c al measure sands. A variety of petroleum types, implying an equal variation in source rock characteristics, has been recognized. Reservoirs have been charged variously from finely textured organic-rich source beds cosedimented within the same succession. Whether the simplistic case of source charging of syndepositional or directly adjacent reservoir beds is normal or whether more complex long distance lateral and/or vertical emplacement processes are involved has yet to be subject to definitive study. Some of the more prominent source candidate rocks include the Conasauga Shale (Cambrian), Reedsville or Utica Shale (Ordovician), Ohio Shale (Devonian), and Bedford or Sunbury Shale (Mississippian), in addition to various Pennsylvanian intervals. Using kerogen pyrolysis-carbon isotopic source-oil correlation technology, it is possible to match petroleums with their precursor sources. End_of_Article - Last_Page 1917------------

Vitrinite Reflectance of Coals from the Heath Formation, Central Montana: ABSTRACT

The Heath Formation (Mississippian) in central Montana is a black calcareous shale containing low to moderate amounts of oil (Fischer assay) and is considered a petroleum source rock for the overlying Tyler Sandstone. Seven core holes were drilled in the summer of 1982 by the Montana Bureau of Mines and Geology in cooperation with the Mineral Management Service. Thin coal seams from the core samples were studied using vitrinite reflectance analysis. Since vitrinite reflectance is a method of determining thermal maturation of organic material in sediments (in this case, a thin coal seam near the base of the Heath Formation), it was possible to construct an iso-reflectance map of the Heath Shale in this area, and estimate the minimum temperature of heating undergone by the organic constituents. Reflectance values show a regional trend caused by burial and the geothermal gradient. Little variation is present in these reflectance values (0.49% to 0.55%). The lowest reflectance values are in the central portion of the study area, and increase to the east and west. However, substantially higher vitrinite reflectances were recorded in the far eastern portion of the area. These high reflectances probably are the result of heating by an igneous intrusion, which was cored during drilling. The sediments heated by the normal geothermal gradient have immature vitrinite which is below the limits of the petroleum generation window. In the small area where the intrusive was discovered, the vitrinite is mature and there is a good possibility of oil generation. End_of_Article - Last_Page 1333------------

Regional Coalification Patterns in Eastern Kentucky, Virginia, West Virginia, Ohio, Maryland, and Southern Pennsylvania: ABSTRACT

An isoreflectance map, based on the average maximum reflectance of the vitrinite macerals, was compiled from 329 coal samples from Kentucky (75 samples), Virginia (14 samples), West Virginia (200 samples), Ohio (10 samples), Maryland (15 samples), and southern Pennsylvania (15 samples). This map shows that coalification increases toward the Allegheny Front (or in west-to-east and northwest-to-southeast directions) in the northern part of the Appalachian coal basin. The dry-ash-free fixed carbon contents of the coals show the same general trends. The isoreflectance map shows that the rank increases to a maximum in two directions: (1) from Ohio eastward to the Allegheny Front in southern Pennsylvania, Maryland, and Mineral County, West Virginia; and (2) from Ohio and northeastern Kentucky to the central part of McDowell County, West Virginia. This increase in rank can be attributed to the eastward thickening of the strata, but the major factor in the coalification was probably the increase of thermal activity and temperatures coupled with the Appalachian orogeny. An attempt to determine the temperatures of coalification by using the level of metamorphism of P. J. Hood showed that the temperatures during the effective times for coalification were approximately 85 to 90°C near the northwestern boundary of the coalfield and approximately 180°C in central McDowell County where the highest reflectance of 1.80% Rmax occurred. End_of_Article - Last_Page 1577------------