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Peter A. Scholle

Publications and source records attributed to Peter A. Scholle.

15 recordsLinked to original sources
USGS1989

Thermal and cementation histories of Permian shelf-edge carbonate rocks in the Nanpanjiang Basin, South China

As of 1984, the Nanpanjiang Basin of South China has had almost no exploration by drilling although oil seeps exist among its margins and producing wells occur in adjacent basins. however, cooperative studies by petroleum geologists and geochemists of the United States and the People's Republic of China (1982-1984) show that calcite-cemented reef and fore-reef carbonate rocks near Ziyun contain bitumen in Upper Permian shelf-edge sediment. the cementation history consists of three episodes: (1)precipitation of syndepositional marine cement (formerly botryoidal aragonnite and fibrous magnesian calcite); (2)precipitation of post-depositional early cement (radiaxial calcite); and (3)precipitation of late burial cement (white calcite spar). Hydrocarbons were introduced into the rocks between cementation episodes 2 and 3. Fluid inclusion analysis of secondary inclusions in the burial cement indicates that the rocks were heated to nearly 200 C after hydrocarbon migration and cementation episode 3. Bitumen remains in the rocks as evidence of the earlier presence of liquid hydrocarbons. During this study, Ordovician through Permian carbonate rocks and Cambrian through Triassic clastic rocks were analyzed for total organic carbon (TOC) vitrinite reflectance (R 0 ), and extractable hydrocarbon (HC) content and composition. Within the basin, TOC values ranged from 0.02% to 3.91%, total HC ranged from 0.004 to 0.11 mg/g, and R 0 values were mostly greater than 2.0%. Previous studies by several groups of scientists in this region have found low TOC values and evidence of overmaturity. Our studies found higher TOC values, but otherwiese confirm the earlier findings. We conclude that portions of the basin have been heated beyond the level of liquid hydrocarbon generation and retention. Although our observations do not favor the occurrence of liquid hydrocarbons in the Paleozoic strata along the western maring of the basin, the possibility of significant gas accumulations in fractured reservoirs or of other hydrocarbon accumulations in the basin cannot be ruled out.

Nanpanjian Basin↗
USGS1985

Comparative geochemical and mineralogical studies of two cyclic transgressive pelagic limestone units, cretaceous Western Interior Basin, U.S.

Pelagic limestone units were deposited in the North American Western Interior seaway during two major Cretaceous transgressive episodes. The Bridge Creek Limestone Member of the Greenhorn Formation, deposited during the Late Cenomanian-Early Turonian transgression, and the Smoky Hill Member of the Niobrara Formation, deposited during the overall Early Coniacian-Early Campanian transgression, are both enriched in organic-carbon and exhibit smallscale carbonate cycles representing periodicities in the range 20 to 40 ky. The distinct periodicity and overall unusual depositional milieu of both units are reflected in their sedimentary structures, mineralogy, and geochemistry. The Bridge Creek Limestone at Pueblo, Colorado, averages 78% CaCO 3 and 1.75% organic carbon with ranges of 42-96% and 0.06-6.97%, respectively, across small-scale cycles. High concentrations of Al, Fe, Mg, K, Ti, Na, Cr, Ni, V; higher Sr/Ca and lower Si/Al ratios; and lighter δ 18 0 in CaCO 3 in dark-colored clay-rich beds all suggest periodic influx of terrestrial clay minerals during times of peak fresh water runoff from uplifted highlands to the west. Higher Sr/Ca ratios in marlstone beds than in limestone beds suggest that the marlstone beds have undergone less diagenetic removal of Sr. Higher concentrations of organic carbon, hydrogen, and sulfur, and preservation of some lamination in the clay-rich beds also suggest that the times of enhanced runoff may have induced stable salinity stratification in the water column, which led to gradual depletion of dissolved oxygen in the bottom waters and enhanced preservation of organic carbon in sediments. The geochemistry also suggests that a significant change in sedimentation occurred at the Cenomanian-Turonian boundary. The geochemical characteristics of the Niobrara Formation near Fort collins, Colorado, are very similar to those of the Bridge Creek Limestone at Pueblo, suggesting similar depositional conditions and source of clastic materials. However, the small scale cycles are present but more subdued in the Niobrara Formation than in the Bridge Creek Limestone, and the Niobrara Formation in the Fort Collins area has not been as altered by diagenesis.

SEPM Special Publication↗
USGS1980

Geological studies of the COST No. B-3 well, United States mid-Atlantic continental slope area

The COST No. B-3 well is the first deep stratigraphic test to be drilled on the Continental Slope off the Eastern United States. The well was drilled in 2,686 ft (819 m) of water in the Baltimore Canyon trough area to a total depth of 15,820 ft (4,844 m) below the drill platform. It penetrated a section composed of mudstones, calcareous mudstones, and limestones of generally deep water origin to a depth of about 8.200 ft (2,500 m) below the drill floor. Light-colored, medium- to coarse-grained sandstones with intercalated gray and brown shales, micritic limestones, and minor coal and dolomite predominate from about 8,200 to 12,300 ft (2,500 to 3,750 m). From about 12,300 ft (3,750 m) to the bottom, the section consists of limestones (including oolitic and intraclastic grainstones) with interbedded fine-to medium-grained sandstones, dark-colored fissile shales, and numerous coal seams. Biostratigraphic examination has shown that the section down to approximately 6,000 ft (1,830 m) is Tertiary. The boundary between the Lower and Upper Cretaceous sections is placed between 8,600 and 9,200 ft (2,620 and 2,800 m) by various workers. Placement of the Jurassic-Cretaceous boundary shows an even greater range based on different organisms; it is placed variously between 12,250 and 13,450 ft (3,730 and 5,000 m). The oldest unit penetrated in the well is considered to be Upper Jurassic (Kimmeridgian) by some workers and Middle Jurassic (Callovian) by others. The Lower Cretaceous and Jurassic parts of the section represent nonmarine to shallow-marine shelf sedimentation. Upper Cretaceous and Tertiary units reflect generally deeper water conditions at the B-3 well site and show a general transition from deposition at shelf to slope water depths. Examination of cores, well cuttings, and electric logs indicates that potential hydrocarbon-reservoir units are present throughout the Jurassic and Cretaceous section. Porous and moderately permeable limestones and sandstones have been found in the Jurassic section, and significant thicknesses of sandstone with porosities as high as 30 percent and permeabilities in excess of 100 md have been encountered in the Cretaceous interval from about 7,000 to 12,000 ft (2,130 to 3,650 m). Studies of organic geochemistry, vitrinite reflectance, and color alteration of visible organic matter indicate that the Tertiary section, especially in its upper part, contains organic-carbon-rich sediments that are good potential oil source rocks. However, this part of the section is thermally immature and is unlikely to have acted as a source rock anywhere in the area of the B-3 well. The Cretaceous section is generally lean in organic carbon, the organic matter which is present is generally gas-prone, and the interval is thermally immature (although the lowest part of this section is approaching thermal maturity). The deepest part of the well, the Jurassic section, shows the onset of thermal maturity. The lower half of the Jurassic rocks has high organic-carbon contents with generally gas-prone organic matter. This interval is therefore considered to be an excellent possible gas source; it has a very high methane content. The combination of gas-prone source rocks, thermal maturity, significant gas shows in the well at 15,750 ft (4,801 m) and porous reservoir rocks in the deepest parts of the well indicate a considerable potential for gas production from the Jurassic section in the area of the COST No. B-3 well. Wells drilled farther downslope from the B03 site may encounter more fully marine or deeper marine sections that may have a greater potential for oil (rather than gas) generation.

mid-Atlantic continental slope area↗
USGS1979

Geological studies of the COST GE-1 well, United States South Atlantic outer continental shelf area

The COST No. GE-1 well is the first deep stratigraphic test to be drilled in the southern part of the U.S. Atlantic Outer Continental Shelf (AOCS) area. The well was drilled within the Southeast Georgia Embayment to a total depth of 13,254 ft (4,040 m). It penetrated a section composed largely of chalky limestones to a depth of about 3,300 ft (1,000 m) below the drill platform. Limestones and calcareous shales with some dolomite predominate between 3,300 and 7,200 ft (1,000 and 2,200 m), whereas interbedded sandstones and shales are dominant from 7,200 to 11,000 ft (2,200 to 3,350 m). From 11,000 ft (3,350 m) to the bottom, the section consists of highly indurated to weakly metamorphosed pelitic sedimentary rocks and meta-igneous flows or intrusives. Biostratigraphic examination has shown that the section down to approximately 3,500 ft (1,060 m) is Tertiary, the interval from 3,500 to 5,900 ft (1,060 to 1,800 m) is Upper Cretaceous, and the section from 5,900 to 11,000 ft (1,800 to 3,350 m) is apparently Lower Cretaceous. The indurated to weakly metamorphosed section below 11,000 ft (3,350 m) is barren of fauna or flora but is presumed to be Paleozoic based on radiometric age determinations. Rocks deposited at upper-slope water depths were encountered in the Upper Cretaceous, Oligocene, and Miocene parts of the section. All other units were deposited in outer-shelf to terrestrial environments. Examination of cores, well cuttings, and electric logs shows that potential hydrocarbon-reservoir units are present within the chalks in the uppermost part of the section as well as in sandstone beds to a depth of at least 10,000 ft (3,000 m). Sandstones below that depth, and the metamorphic section between 11,000 and 13.250 ft (3,350 and 4,040 m) have extremely low permeabilities and are unlikely to contain potential reservoir rock. Studies of organic geochemistry, vitrinite reflectance, and color alteration of visible organic matter indicate that the chalk section down to approximately 3,600 ft (1,100 m) contains low concentrations of indigenous hydrocarbons, is thermally immature, and has a very poor source-rock potential. The interval from 3,600 to 5,900 ft (1,100 to 1,800 m) has a high content of marine organic matter but appears to be thermally immature. Where buried more deeply, this interval may have significant potential as an oil source. The section from 5,900 to 8,850 ft (1,800 to 2,700 m) has geochemical characteristics indicative of a poor oil source rock and is thermally immature. Rocks below this depth, although they may be marginally to fully mature, are virtually barren of organic matter and thus have little or no source-rock potential. Therefore, despite the thermal immaturity of the overall section, the uppor half of the sedimentary section penetrated in the well shows the greatest petroleum source potential.

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USGS1977

Geological studies on the COST No. B-2 well, U. S. Mid-Atlantic outer continental shelf area

The COST No. B-2 well is the first deep stratigraphic test to be drilled on the United States Atlantic Outer Continental Shelf (AOCS) area. The well was drilled on the eastern flank of the Baltimore Canyon trough to a total depth of 16,043 feet; it penetrated a section composed almost entirely of sand and shale with subordinate amounts of limestone, coal, and lignite. Biostratigraphic studies have shown that the uppermost 5,000 feet is of Tertiary and Quaternary age and was deposited in nonmarine to deep marine environments. The Upper Cretaceous section is about 3,000 feet thick and is of dominantly shallow marine origin. The basal 8,000 feet of sediment has been tentatively determined to be entirely of Early Cretaceous age, the basal sediments being dated as Berriasian. This Lower Cretaceous section is primarily nonmarine to very shallow marine in origin. Examination of cores, well cuttings, and electric logs shows that thick potential reservoir sands are found through much of the section. However, porosity and permeability decrease strikingly in the deeper parts of the Lower Cretaceous section as a result of compaction and cementation. Most of the sands are quite feldspathic, and progressive decomposition of feldspar stimulates authigenic clay and silica formation. Studies of color alteration of visible organic matter, organic geochemistry, and vitrinite reflectance show that although many units have high organic-carbon contents, moderately low geothermal gradients may have retarded thermal maturation. This, in conjunction with the scarcity of marine-derived organic matter in the lower part of the section, suggests a relatively low potential for the generation of liquid hydrocarbons. However, the overall combination of source beds, reservoirs, seals, structures, and thermal gradients may be favorable for the generation and entrapment of natural gas. Furthermore, the presence of reservoir rocks, seals, and trapping structures may indicate a significant potential for entrapment of either natural gas or petroleum that was generated deeper in the basin and then migrated either laterally or vertically.

Circular↗
USGS1977

Current oil and gas production from North American Upper Cretaceous chalks

Production of oil and natural gas from North American chalks has increased significantly during the past five years, spurred by the prolific production from North Sea chalks, as well as by higher prices and improved production technology. Chalk reservoirs have been discovered in the Gulf Coast in the Austin Group, Saratoga and Annona Chalks, Ozan Formation, Selma Group, Monroe gas rock (an informal unit of Navarro age), and other Upper Cretaceous units. In the Western Interior, production has been obtained from the Cretaceous Niobrara and Greenhorn Formations. Significant, though subcommercial, discoveries of natural gas and gas condensate also have been made in the Upper Cretaceous Wyandot Formation on the Scotian Shelf of eastern Canada. All North American chalk units share a similar depositional and diagenetic history. The chalks consist primarily of whole and fragmented coccoliths with subordinate planktonic and benthonic Foraminifera, inoceramid prisms, oysters, and other skeletal grains. Most have between 10 and 35 percent HCl-insoluble residue, predominantly clay. Deposition was principally below wave base in tens to hundreds of meters of water. The diagenetic history of a chalk is critical in determining its reservoir potential. All chalk has a stable composition (low-Mg calcite) and very high primary porosity. With subsequent burial, mechanical and chemical (solution-transfer) compaction can reduce or completely eliminate pore space. The degree of loss of primary porosity in chalk sections is normally a direct function of the maximum depth to which it has been buried. Pore-water chemistry, pore-fluid pressures, and tectonic stresses also influence rates of cementation. Oil or gas reservoirs of North American chalk fall into three main groups: 1. Areas with thin overburden and significant primary porosity retention (for example, Niobrara Formation of Kansas and eastern Colorado). 2. Areas with thicker overburden but considerable fracturing. Here primary porosity has been largely lost but secondary (fracture) porosity provides some storage capacity and greatly improves permeability (for example, Austin Group of the Pearsall field, Texas). 3. Areas with thick overburden in which marine pore fluids have been retained, or where hydrocarbons (including biogenically generated methane) were introduced early in the diagenetic history. In these settings, primary porosity is reduced to a lesser degree than in group two, and adequate reservoir properties can be maintained to depths approaching 2,000 m (6,600 ft) (for example, Scotian Shelf of Canada). Continued small-scale oil and gas discoveries can be expected from these types of reservoirs in North America. The prolific production of oil and gas from North Sea chalk reservoirs will not be matched in North America unless deeply buried, overpressured chalks can be located. It is the early formation of overpressures and (or) early oil input into North Sea chalks that have preserved porosities as high as 40 percent at 3,000- to 3,500-m (9,800- to 11,500-ft) depths and provided the outstanding reservoir capacity of those chalks.

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