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D. D. Rice

Publications and source records attributed to D. D. Rice.

9 recordsLinked to original sources
USGS2002

Assessment of hydrocarbon source rock potential of Polish bituminous coals and carbonaceous shales

We analyzed 40 coal samples and 45 carbonaceous shale samples of varying thermal maturity (vitrinite reflectance 0.59% to 4.28%) from the Upper Carboniferous coal-bearing strata of the Upper Silesian, Lower Silesian, and Lublin basins, Poland, to evaluate their potential for generation and expulsion of gaseous and liquid hydrocarbons. We evaluated source rock potential based on Rock-Eval pyrolysis yield, elemental composition (atomic H/C and O/C), and solvent extraction yields of bitumen. An attempt was made to relate maceral composition to these source rock parameters and to composition of the organic matter and likely biological precursors. A few carbonaceous shale samples contain sufficient generation potential (pyrolysis assay and elemental composition) to be considered potential source rocks, although the extractable hydrocarbon and bitumen yields are lower than those reported in previous studies for effective Type III source rocks. Most samples analysed contain insufficient capacity for generation of hydrocarbons to reach thresholds required for expulsion (primary migration) to occur. In view of these findings, it is improbable that any of the coals or carbonaceous shales at the sites sampled in our study would be capable of expelling commercial amounts of oil. Inasmuch as a few samples contained sufficient generation capacity to be considered potential source rocks, it is possible that some locations or stratigraphic zones within the coals and shales could have favourable potential, but could not be clearly delimited with the number of samples analysed in our study. Because of their high heteroatomic content and high amount of asphaltenes, the bitumens contained in the coals are less capable of generating hydrocarbons even under optimal thermal conditions than their counterpart bitumens in the shales which have a lower heteroatomic content. Published by Elsevier Science B.V.

Chemical Geology↗
USGS1994

Cretaceous rocks from southwestern Montana to southwestern Minnesota, northern Rocky Mountains, and Great Plains

In Montana, Wyoming, North and South Dakota, and Minnesota, Cretaceous strata are preserved in the asymmetric Western Interior foreland basin. More than 5,200 m (17,000 ft) of Cretaceous strata are present in southwestern Montana, less than 300 m (1,000 ft) in eastern South Dakota. The asymmetry resulted from varying rates of subsidence due to tectonic and sediment loading. The strata consist primarily of sandstone, siltstone, mudstone, and shale. Conglomerate is locally abundant along the western margin, whereas carbonate is present in most areas of the eastern shelf. Sediment was deposited in both marine and nonmarine environments as the shoreline fluctuated during major tectonic and eustatic cycles. A discussion of Cretaceous strata from southwestern to east-central Montana, the Black Hills, eastern South Dakota, and southwestern Minnesota shows regional stratigraphy and facies relations, sequence, boundaries, and biostratigraphic and radiometric correlations. The thick Cretaceous strata in southwestern Montana typify nonmarine facies of the rapidly subsiding westernmost part of the basin. These strata include more than 3,000 m (10,000 ft) of synorogenic conglomerate of the Upper Cretaceous part of the Beaverhead Group. West of the Madison Range, sequence boundaries bracket the Kootenai (Aptian and Albian), the Blackleaf (Albian and Cenomanian), and the Frontier Formations (Cenomanian and Turonian); sequence boundaries are difficult to recognize because the rocks are dominantly non-marine. Cretaceous strata in east-central Montana (about 1,371 m; 4,500 ft thick) lie at the approximate depositional axis of the basin and are mostly marine terrigenous rocks. Chert-pebble zones in these rocks reflect stratigraphic breaks that may correlate with sequence boundaries to the east and west. Cretaceous rocks of the Black Hills region consist of a predominantly marine clastic sequence averaging approximately 1,524 m (5,000 ft) thick. The Cretaceous System in eastern South Dakota (457 to 610 m; 1,500 to 2,000 ft thick) consists of a marine shelf sequence dominated by shale and limestone. Major sequence boundaries in South Dakota are at the base of the Lower Cretaceous Lakota Formation, Fall River Sandstone, and Muddy Sandstone, and bracket the Upper Cretaceous Niobrara Formation.

Book chapter↗
USGS1991

Oil-generating coals of the San Juan Basin, New Mexico and Colorado, U.S.A.

Coal beds of the Upper Cretaceous Fruitland Formation in the San Juan Basin of northwestern New Mexico and southwestern Colorado have significant liquid hydrocarbon generation potential as indicated by typical Rock-Eval Hydrogen Indexes in the range of 200–400 mg hydrocarbon/g organic carbon (type II and III organic matter). Small, non-commercial quantities of oil have been produced from the coal beds at several locations. The oils are characterized by high pristane/phytane ( ca 4) and pristane/ n -C 17 ratios ( ca 1.2), abundant C 21+ alkanes in the C 10+ fraction with a slight predominance of odd carbon-numbered n -alkanes, abundant branched-chain alkanes in the C 15+ region, and a predominance of methylcyclohexane in the C 4 -C 10 fraction. The oils are indigenous to the Fruitland Formation coals and probably migrated at thermal maturities corresponding to vitrinite reflectance values in the range 0.7–0.8%. Although the oils found to date are not present in commercial amounts, these findings illustrate the potential of some coals to generate and expel oil under conditions of moderate thermal heating.

Colorado, New Mexico↗
USGS1989

Characterization of coal-derived hydrocarbons and source-rock potential of coal beds, San Juan Basin, New Mexico and Colorado, U.S.A.

Coal beds are considered to be a major source of nonassociated gas in the Rocky Mountain basins of the United States. In the San Juan basin of northwestern New Mexico and southwestern Colorado, significant quantities of natural gas are being produced from coal beds of the Upper Cretaceous Fruitland Formation and from adjacent sandstone reservoirs. Analysis of gas samples from the various gas-producing intervals provided a means of determining their origin and of evaluating coal beds as source rocks. The rank of coal beds in the Fruitland Formation in the central part of the San Juan basin, where major gas production occurs, increases to the northeast and ranges from high-volatile B bituminous coal to medium-volatile bituminous coal ( R m values range from 0.70 to 1.45%). On the basis of chemical, isotopic and coal-rank data, the gases are interpreted to be thermogenic. Gases from the coal beds show little isotopic variation ( δ 13 C 1 values range −43.6 to −40.5 ppt), are chemically dry (C 1 /C 1–5 values are > 0.99), and contain significant amounts of CO 2 (as much as 6%). These gases are interpreted to have resulted from devolatilization of the humic-type bituminous coal that is composed mainly of vitrinite. The primary products of this process are CH 4 , CO 2 and H 2 O. The coal-generated, methane-rich gas is usually contained in the coal beds of the Fruitland Formation, and has not been expelled and has not migrated into the adjacent sandstone reservoirs. In addition, the coal-bed reservoirs produce a distinctive bicarbonate-type connate water and have higher reservoir pressures than adjacent sandstones. The combination of these factors indicates that coal beds are a closed reservoir system created by the gases, waters, and associated pressures in the micropore coal structure. In contrast, gases produced from overlying sandstones in the Fruitland Formation and underlying Pictured Cliffs Sandstone have a wider range of isotopic values ( δ 13 C 1 values range from −43.5 to −38.5 ppt), are chemically wetter (C 1 /C 1–5 values range from 0.85 to 0.95), and contain less CO 2 (< 2%). These gases are interpreted to have been derived from type III kerogen dispersed in marine shales of the underlying Lewis Shale and nonmarine shales of the Fruitland Formation. In the underlying Upper Cretaceous Dakota Sandstone and Tocito Sandstone Lentil of the Mancos Shale, another gas type is produced. This gas is associated with oil at intermediate stages of thermal maturity and is isotopically lighter and chemically wetter at the intermediate stage of thermal maturity as compared with gases derived from dispersed type III kerogen and coal; this gas type is interpreted to have been generated from type II kerogen. Organic matter contained in coal beds and carbonaceous shales of the Fruitland Formation has hydrogen indexes from Rock-Eval pyrolysis between 100 and 350, and atomic H:C ratios between 0.8 and 1.2. Oxygen indexes and atomic O:C values are less than 24 and 0.3, respectively. Extractable hydrocarbon yields are as high as 7,000 ppm. These values indicate that the coal beds and carbonaceous shales have good potential for the generation of liquid hydrocarbons. Voids in the coal filled with a fluorescent material that is probably bitumen is evidence that liquid hydrocarbon generation has taken place. Preliminary oil-source rock correlations based on gas chromatography and stable carbon isotope ratios of C 15+ hydrocarbons indicate that the coals and (or) carbonaceous shales in the Fruitland Formation may be the source of minor amounts of condensate produced from the coal beds at relatively low levelsof thermal maturity ( R m =0.7).

International Journal of Coal Geology↗
USGS1988

Character, origin and occurrence of natural gases in the Anadarko basin, southwestern Kansas, western Oklahoma and Texas Panhandle, U.S.A.

Natural gas production in the Anadarko basin comes from three geographically separated areas that can be differentiated by age of reservoir and by inferred nature of organic, thermal origin of the gases. In the central basin, non-associated gases are produced mainly from Upper Mississippian and Pennsylvanian sandstones. Gas samples are from reservoirs as much as 6588 m deep. Gases become isotopically heavier (??13C1-values range from -49.8 to -33.2???) and chemically drier (C2+-values range from 1-33%) with increasing level of thermal maturity. Gases were generated mainly from interbedded shales with type-III kerogen during the mature and post-mature stages of hydrocarbon generation. Deviations from the trend are due to vertical migration and mixing of gases generated at different levels of thermal maturity over the past 250 Myr. In the giant Panhandle-Hugoton field, non-associated gases are generally produced from Permian carbonates at depths of <900 m. Gases display little compositional variation (mean ??13C1-value is -43.2???, mean C2+-value is 14%). Because organic-rich, mature source rocks are not present in the area, gases probably were generated in the central basin from Pennsylvanian or older source rocks during the mature stage of hydrocarbon generation. This interpretation implies migration over distances as much as several hundred kilometers. In the Sooner Trend, associated gases are produced from Silurian, Devonian and Mississippian carbonates at depths as great as 2950 m and were generated from type-II kerogen during the mature stage of hydrocarbon generation. Associated oil usually correlates with extracts of the Upper Devonian and Lower Mississippian Woodford Shale. Gases are isotopically lighter (mean ??13C1-value is -43.9???) and chemically wetter (mean C2+ value is 14%) than those derived from type-III kerogen at an equivalent level of thermal maturity. ?? 1988.

Chemical Geology↗