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NARROW
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all geography including DSDP/ODP Sites and Legs
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Abstract Outcrop and subsurface examples of vertically stacked, multicyclic Pennsylvanian petroleum systems in the Powder River Basin of Wyoming are discussed. In the Rocky Mountain region, different source rock, reservoir quality, oil and gas composition, and seals among cycles reflect increasingly arid conditions from Desmoinesian to Virgilian time as the North American plate migrated from an equatorial position in early Carboniferous time into the arid trade-wind belt (∼ 20° N) in late Carboniferous time with associated eolian-sand-sea deposits. Here, Pennsylvanian rocks contain prolific hydrocarbon-producing, stratigraphically isolated reservoirs (commonly eolianites or phylloid algal mounds) and closely associated organic-rich black shale source beds. The black shales, containing as much as 80% total organic carbon (TOC), are the sources of Paleozoic oils in the Powder River and Paradox basins. The source beds are in a cyclic sequence composed ideally of black shale overlain by carbonate, clastic, and evaporite sediments grading back to carbonate and culminating in the next younger shale. Differences among the black shales, however, reflect in part climatic fluctuations in the marginal-marine settings where these shales were deposited. Kerogen in the black shale and carbonate marlstone of the Leo Formation in the Powder River Basin range from type II to type IV and are predominantly type III. Different proportions of terrestrial organic matter consistently are present in individual shale beds and most likely correlate with climatic variations; i.e., more humid in the early Pennsylvanian and more arid in the late Pennsylvanian. Transported organic matter may reflect cyclic variations in runoff and (or) terrestrial vegetative cover. A model of wetter climate would explain the combination of high TOC, high proportion of type III kerogen, high carbonate content, and carbon isotope composition (i.e., 12 C-depleted kerogen and 12 C-enriched bitumen) in some Desmoinesian shales and the resulting high associated H 2 S gas composition and higher sulfur content of derived oils. Desmoinesian reservoirs have dominantly carbonate cements. Wet/dry cycles are suggested for Missourian cycles where eolian dune sandstones cemented by both anhydrite and carbonate cement intercalate with very organic-rich, oil-prone (sapropelic) lacustrine black shales. Virgilian cycles in the Powder River Basin reflect even more arid conditions dominated by carbonates and evaporites with relatively minor clastics and a predominance of anhydrite cement in eolian reservoirs. The mechanisms controlling the deposition of the cyclothemic black shales are of great interest because source-rock quality is affected. These results suggest that differences among black-shale cycles should be considered as resulting from climatic fluctuations; a eustatic mechanism alone offers little utility in differentiating or understanding oil/rock differences among various Pennsylvanian cycles. Such variable effects are critical, as demonstrated by completion and production concerns relating to production of toxic associated gases and or formation damage, which can be related to specific cycles. Associated gases are highly variable among cycles, ranging from some with very high sulfur content (e.g., 48% in some Desmoinesian cycles) to others with high nitrogen and low sulfur content. Some of these differences are related to different regions with differing depth of burial and thermal maturity; however, where different oils are produced within a single field, as at Red Bird field, the differences are due to differences in source-rock composition that reflect variations in climate. A “sinking reservoir” accommodation model in an uncompensated basin is proposed to explain ancient coastal eolian reservoirs in the Pennsylvanian of eastern Wyoming. This model contrasts significantly with a “buried topography” model, which requires tectonic subsidence or eustatic rise to accommodate and preserve reservoirs. The “sinking reservoir” model may also be applicable to isolated carbonate (e.g., phylloid algal, thrombolitic, or stromatolitic) reservoirs in the Pennsylvanian of the Rocky Mountains, the Cambrian of Russia, and elsewhere. The repeated exposure of sediments to climatic influences in uncompensated basins provides conditions whereby the progressive loading of eolian, fluvial, deltaic, and carbonate sediments (i.e., potential reservoirs) on an unconsolidated substrate may preserve these potential reservoirs via the “sinking reservoir” model. The concept of subsidence moats around such reservoirs preserving a variety of nearby diachronous sediments, together with so called “disjunctive” (growth) faults created during subsidence, has important implications for interpreting sediment sequences.
Geochemistry of Oils from the Junggar Basin, Northwest China
Geology, Thermal Maturation, and Source Rock Geochemistry in a Volcanic Covered Basin: San Juan Sag, South-Central Colorado
Structure, Stratigraphy, and Petroleum Geology of the Little Plain Basin, Northwestern Hungary
Abstract Several petroleum provinces in southeastern Hungary are part of the greater late Miocene-Pliocene Pannonian basin of central Europe. The Pannonian basin formed as a tensional basin in early-middle Miocene time (17-12 Ma) when thick (<1250 m) marine bioclastic carbonates were deposited. Pre-Miocene basement rocks are composed of lithologically and structurally complex rocks of Precambrian to Mesozoic age. Overlying the basement rocks and the marine carbonates are thick (<4500 m) lacustrine Pannonian rocks of late Miocene and Pliocene age. Gas production with some oil and condensate is predominantly from structural and combination traps. Part of one petroleum system present in southeastern Hungary consists of middle-upper Miocene source rocks and reservoir rocks. Fractured Precambrian rocks are the next most important reservoir rocks. Gas and oil generation began less than 6 Ma and is continuing today. Overpressuring is regionally present in rocks at drill depths greater than 2500 m. The overpres-suring is caused by a combination of undercompaction (incomplete sediment dewatering) and active hydrocarbon generation from middle-upper Miocene source rocks. Some overpressuring may be caused by thermally generated CO2 yielded during metamorphism of Paleozoic carbonate basement rocks. Vertical fracturing and sandstone carrier beds cause hydrocarbons from the overpressured source rocks to migrate into basement rocks and Miocene age reservoir rocks. The overpressuring has caused the gas and oil to be forced downward, upward, and laterally. At depths shallower than 2500-1800 m, the hydrocarbons (and CO2) migrated mostly by buoyancy. More than 26 oil and gas fields have been discovered in mostly structurally controlled accumula-tions. These fields have an estimated original in-place oil of 35.3 million t and in-place gas of 66.2 million m3. The amount of undiscovered resources is unknown but only a few deep (>5000 m) exploratory tests have been drilled, and exploration has just begun for stratigraphic traps.
Composition of Crude Oils Generated from Coals and Coaly Organic Matter in Shales
Abstract Coal and coaly organic matter dispersed in shales have long been recognized as sources of hydrocarbon gas and CO 2 but have only recently been shown to be capable of generating and expelling economic quantities of liquid products in a number of basins worldwide (e.g., Brooks and Smith, 1969; Combaz and DeMatharel, 1978; Shibaoka et al., 1978; Durand and Paratte, 1983; Noble et al., 1991; Shanmugan, 1985; Thompson et al., 1985; Khorasani, 1987; Huang Difan et al., 1991). The composition of hydrocarbons that can be extracted with solvents or can be generated by experimental heating varies widely for coals of different ages and from different regions of the world. Factors affecting the hydrocarbon composition include the kerogen composition of the coal and conditions of heating, under either natural or experimental conditions. An understanding of the composition and geochemical characteristics unique (if any) to oils derived from coaly organic matter is important to characterization of oils where the source rock is unknown or uncertain. The ability to characterize an oil as being from a coal source can provide direction in further exploration efforts by helping to elucidate the generation and migration history of the oil accumulation. Moreover, our understanding of the ability of coals and coaly organic matter to generate and expel oil depends not only on assessment of various coals by geochemical means, but also on studies of oil accumulations that have been generated and expelled from coal or coaly organic matter. The purpose of the present paper is to review