Natural gas in Arkoma basin of Oklahoma and Arkansas
Assoc. Petrol. Geol. Mem 01/1968; 9.
The Arkoma Basin is in E.-SE. Oklahoma and in W.-central Arkansas. The deepest part of this arcuate trough is adjacent to the Ouachita Mt. system where the sedimentary column is estimated to be 30,000-ft thick. Rocks in the basin have been highly deformed by a combination of forces. Evidence indicates that some of these faults were growing contemporaneously with deposition of Lower Pennsylvanian beds. Early Permian mountain building on the south compressed Arkoma Basin beds into a series of long, narrow, E.-W. anticlinal and synclinal folds. Overthrusting along anticlinal axes near the mountain front is common. Most of the gas production in the Arkoma Basin is from lenticular, fine-grained sandstone within the Atoka sequence. The entire Atoka sequence is estimated to be 20,000 ft thick along the mountain front in Arkansas. The Arkoma Basin is essentially a dry-gas province with the gas being approx. 95% methane. To date there are about 25 gas-producing zones in the basin, ranging in age from Pennsylvanian to Ordovician. (23 refs.)
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ABSTRACT: The Spiro sand is a laterally extensive thin sandstone of earliest Atokan (Pennsylvanian) age that forms a major natural gas reservoir in the western Arkoma Basin, Oklahoma. Petrographic analysis revelas a variety of diagenetic alterations, the majority of which occurred during moderate to deep burial. Early diagenetic processes include calcite cementation and the formation of Fe-clay mineral peloids and coatings around quartz framework grains. These clays, which underwent transformation to well-crystallized chamosite [polytype lb(β = 90°C)]. These clays, are particularly abundant in medium-grained channel sandstones, whereas illitic clays are predominant in fine-grained interchannel sandstones. Subsequent to mechanical compaction, saddle ankerite precipitated in the reservoir at temperatures in excess of 70°C. Crude oil collected in favourable structural locations during and after ankeritization. Whereas hydrocarbons apparently halted inorganic diagenesis in oil-saturated zones, cementation continued in the underlying water-saturated zones. As reservoir temperatures increased further, hydrocarbons were cracked and a solid pyrobitumen residue remained in the reservoir. At temperatures exceeding ∼140–150°C, non-syntaxial quartz cement, ferroan calcite and traces of dickite(?) locally reduced the reservoir quality. Local secondary porosity was created by carbonate cement dissolution. This alteration post-dated hydrocarbon emplacement and is probably related to late-stage infiltration of freshwater along ‘leaky’ faults. The study shows that the Spiro sandstone locally retained excellent porosites despite deep burial and thermal conditions that correspond to the zone of incipient very low grade metamorphism.Marine and Petroleum Geology 02/1996; 13(1):25–40. DOI:10.1016/0264-8172(95)00037-2 · 2.64 Impact Factor
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ABSTRACT: Oil and gas pools in shallow basins of on the shallow, stable shevles of deeper sedimentary basins appear to be exceptions to the model of a hot-deep origin of petroleum. However, the oil in shallow basins is directly associated with faulting extending out of the deepest parts of the basin. Evidence exists that some of these shallow basins have been much hotter in the past either from igneous activity of from a higher geothermal gradient. Uplift and erosion may also have removed substantial thicknesses of sediments in some of these basins. Oil on the stable, shallow, shelvees of deep basins could originated in the deeper part of the basin and undergone long lateral migration to the traps where it is now found. Conduits for such migration could have been sandstones in delta-distributary systems (E Oklahoma and Kansas), reef trends (Alberta, Canada), or regional porosity and permeability in sheet carbonates (Anadarko basin. W. Oklahoma and Kansas). The model discussed herein allows us to (1) predict which areas of the stable shelves of deep basins should produce hydrocarbons and which areas should not, (2) predict the type of hydrocarbon (gas or oil), (3) set the limit of lateral updip migration, of hydrocarbons within any one formation in a basin, and (4) predict the downdip occurrence of hydrocarbons in the formation. The model should aslo help us determine which shallow cratonic basins should produce oil and which should not.Journal of Petroleum Geology 06/2008; 3(1):91 - 116. DOI:10.1111/j.1747-5457.1980.tb01005.x · 1.47 Impact Factor
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