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Leigh C. Price

Publications and source records attributed to Leigh C. Price.

12 recordsLinked to original sources
USGS2001

Diagenesis and fracture development in the Bakken Formation, Williston Basin: Implications for reservoir quality in the middle member

The middle member of the Bakken Formation is an attractive petroleum exploration target in the deeper part of the Williston Basin because it is favorably positioned with respect to source and seal units. Progressive rates of burial and minor uplift and erosion of this member led to a stable thermal regime and, consequently, minor variations in diagenesis across much of the basin. The simple diagenetic history recorded in sandstones and siltstones in the middle member can, in part, be attributed to the closed, low-permeability nature of the Bakken petroleum system during most of its burial history. Most diagenesis ceased in the middle member when oil entered the sandstones and siltstones in the Late Cretaceous. Most oil in the Bakken Formation resides in open, horizontal fractures in the middle member. Core analysis reveals that sandstones and siltstones associated with thick mature shales typically have a greater density of fractures than sandstones and siltstones associated with thin mature shales. Fractures were caused by superlithostatic pressures that formed in response to increased fluid volumes in the source rocks during hydrocarbon generation

North Dakota↗
USGS2000

Organic metamorphism in the California petroleum basins; Chapter B, Insights from extractable bitumen and saturated hydrocarbons

Seventy-five shales from the Los Angeles, Ventura, and Southern San Joaquin Valley Basins were extracted and analyzed. Samples were chosen on the basis of ROCK-EVAL analyses of a much larger sample base. The samples ranged in burial temperatures from 40 ? to 220 ? C, and contained hydrogen-poor to hydrogen-rich organic matter (OM), based on OM visual typing and a correlation of elemental kerogen hydrogen to carbon ratios with ROCK-EVAL hydrogen indices. By extractable bitumen measurements, rocks with hydrogen- poor OM in the Los Angeles Basin began mainstage hydrocarbon (HC) generation by 90 ? C. The HC concentrations maximized by 165 ? C, and beyond 165 ? C, HC and bitumen concentrations and ROCK-EVAL hydrogen indices all began decreasing to low values reached by 220 ? C, where HC generation was largely complete. Rocks with hydrogen-poor OM in the Southern San Joaquin Valley Basin commenced mainstage HC generation at 135 ? C and HC concentrations maximized by 180 ? C. Above 180 ? C, HC and bitumen concentrations and ROCK-EVAL hydrogen indices all decreased to low values reached by 214 ? C, again the process of HC generation being largely complete. In both cases, bell-shaped HC-generation curves were present versus depth (burial temperature). Mainstage HC generation had not yet begun in Ventura Basin rocks with hydrogen-poor OM by 140 ? C. The apparent lower temperature for initiation of mainstage generation in the Los Angeles Basin is attributed to very recent cooling in that basin from meteoric-water flow. Thus, HC generation there most probably occurred at higher burial temperatures. In contrast, mainstage HC generation, and all aspects of organic metamorphism, were strongly suppressed in rocks with hydrogen-rich OM at temperatures as high as 198 ? C. For example, shales from the Wilmington field (Los Angeles Basin) from 180 ? to 198 ? C retained ROCK-EVAL hydrogen indices of 550- 700 and had saturated-HC coefficients of only 4-15 mg/g organic carbon. The rocks with hydrogen-rich OM were subjected to the same burial conditions as the rocks with hydrogenpoor OM. We attribute this suppression of organic metamorphism in this study primarily to much stronger bonds in the hydrogen-rich OM compared to the bonds in hydrogen-poor OM. Trends in bitumen compositions (qualitative characteristics) versus burial temperature were also very different for rocks with hydrogen-poor OM compared to that in rocks with hydrogen- rich OM. This observation demonstrated that the two OM types also had significantly different reaction pathways, in addition to different reaction kinetics. Strong exploration implications arise from these observations. Above 40?C, but before mainstage HC generation, a lowtemperature (pre-mainstage) HC generation occurred in all rocks, and all OM types, studied. This low-temperature generation resulted in significant qualitative changes in the bitumen and HCS (hydrocarbons) from rocks of all OM types, especially in rocks with hydrogen-rich OM, from 40 ? to 70 ? C. This, and previous studies, document that very high carbon-normalized concentrations of indigenous bitumen and HCS occur in late Neogene immature rocks of any OM type in all southern California basins. This characteristic is attributed to the low-temperature generation occurring in both sulfur-poor and sulfur-rich kerogens, which originally had unusually high concentrations of weak (15-40 Kcal/mole) bonds. These observations and considerations have marked relevance to exploration regarding the possible formation of commercial oil deposits at immature ranks in these basins. Other significant geochemical observations also result from this study.

Bulletin↗
USGS1999

Organic metamorphism in the California petroleum basins; Chapter A, Rock-Eval and vitrinite reflectance

The results of ROCK-EVAL and vitrinite reflectance analyses of a large sample base from more than 70 wells located in three oil-rich California petroleum basins are reported. The cores from these wells have a wide range of present-day burial temperatures (40 ? to 220 ? C). The rocks in these basins were deposited under highly variable conditions, sometimes resulting in substantially different organic matter (OM) types in rocks tens of meters vertically apart from each other in one well. The kinetic response of these different OM types to equivalent wellknown burial histories is a pivotal point of this study. In the Los Angeles and Ventura Basins, rock organic-richness significantly increased with depth, as did kerogen hydrogen content, and the percentage of fine-grained versus coarsegrained rocks. The shales in these basins are perceived as containing primarily hydrogen-rich amorphous OM. In actuality, the shallowest 2,000 to 3,000 m of rocks in the basins, and at least the upper 6,000 m of rocks in parts of the Los Angeles Basin central syncline, are dominated by type III/IV OM. In the Los Angeles Basin, mainstage hydrocarbon (HC) generation commences in the type III/IV OM at present-day burial temperatures of 85 ? to 110 ? C, most likely around 100 ? C, and is largely complete by 220 ? C. In the Southern San Joaquin Valley Basin, mainstage HC generation commences in type III/IV OM at 150 ? C and is also largely complete by 220 ? C. In the Ventura Basin, mainstage HC generation commences above 140 ? C in type III/IV OM. The apparent lower temperatures for commencement of HC generation in the Los Angeles Basin are attributed to the fact that parts of the basin were cooled from maximal burial temperatures by increased meteoric water flows during the last glaciations. All aspects of organic metamorphism, including mainstage HC generation, are strongly suppressed in rocks with hydrogenrich OM in these basins. For example, ROCK-EVAL data suggest that mainstage HC generation has not commenced in rocks with hydrogen-rich OM at present-day temperatures of 198?C. This observation is attributed to much stronger bonds in hydrogen- rich OM compared to types III and IV OM and, therefore, significantly higher burial temperatures are required to break these bonds. This difference in OM kinetics has profound ramifications for petroleum-geochemical exploration models. Organic-matter characteristics inherited from original depositional conditions were overlaid on, and at times confused interpretation of, characteristics from organic metamorphism in all study areas. In all the basins examined in this study, immature fine-grained rocks occasionally had high to very high carbon-normalized concentrations of pre-generation indigenous bitumen. This unusual characteristic may be due to unique depositional conditions in these basins.

Bulletin↗
USGS1983

Solubility of crude oil in methane as a function of pressure and temperature

The solubility of a 44° API (0.806 sp. gr.) whole crude oil has been measured in methane with water present at temperatures of 50 to 250°C and pressures of 740 to 14,852 psi, as have the solubilities of two high molecular weight petroleum distillation fractions at temperatures of 50 to 250°C and pressures of 4482 to 25,266 psi. Both increases in pressure and temperature increase the solubility of crude oil and petroleum distillation fractions in methane, the effect of pressure being greater than that of temperature. Unexpectedly high solubility levels (0.5–1.5 grams of oil per liter of methane—at laboratory temperature and pressure) were measured at moderate conditions (50–200°C and 5076–14504 psi). Similar results were found for the petroleum distillation fractions, one of which was the highest molecular weight material of petroleum (material boiling above 266°C at 6 microns pressure). Unexpectedly mild conditions (100°C and 15,200 psi; 200°C and 7513 psi) resulted in cosolubility of crude oil and methane. Under these conditions, samples of the gas-rich phase gave solubility values of 4 to 5 g/l, or greater. Qualitative analyses of the crude-oil solute samples showed that at low pressure and temperature equilibration conditions, the solute condensate would be enriched in C 5 –C 15 range hydrocarbons and in saturated hydrocarbons in the C 15+ fraction. With increases in temperature and especially pressure, these tendencies were reversed, and the solute condensate became identical to the starting crude oil. The data of this study, compared to that of previous studies, shows that methane, with water present, has a much greater carrying capacity for crude oil than in dry systems. The presence of water also drastically lowers the temperature and pressure conditions required for cosolubility. The data of this and/or previous studies demonstrate that the addition of carbon dioxide, ethane, propane, or butane to methane also has a strong positive effect on crude oil solubility, as does the presence of fine grained rocks. The n -paraffin distributions (as well as the overall composition) of the solute condensates are controlled by the temperature and pressure of solution and exsolution, as well as by the composition of the original starting material. It appears quite possible that primary migration by gaseous solution could ‘strip’ a source rock of crude-oil like components leaving behind a bitumen totally unlike the migrated crude oil. The data of this study demonstrate previous criticisms of primary petroleum migration by gas solution are invalid; that primary migration by gaseous solution cannot occur because methane cannot dissolve sufficient volumes of crude oil or cannot dissolve the highest molecular weight components of petroleum (tars and asphaltenes).

Colorado, Nebraska, Oklahoma↗
USGS1982

Organic geochemistry of core samples from an ultradeep hot well (300°C, 7 km)

South Texas cores of Lower Cretaceous rocks from a depth of 6400.8 to 7544.6 m at present-day temperatures of 262–296°C have high concentrations of C 15+ hydrocarbons. Bitumen coefficients range from 105 to 367 mg/g and C 15+ extractable bitumen ranges from 500 to 2200 ppm. Some generation potential remains associated with the kerogen of these rocks. In addition to exhibiting the above organic-geochemical properties, characteristic of the zone of intense hydrocarbon generation, these rocks also have organic-geochemical properties, attributed to the zone of hydrocarbon extinction or greenschist metamorphism. These characteristics are: high vitrinite reflectance ( R 0 ) values, 4.4–4.8; low H/C ratios, 0.30–0.58; high saturate/aromatic hydrocarbon ratios, 7.05–20.6; high hydrocarbon/NSO ratios, 2.65–4.66; and high transformation index ratios [ ], 0.61–0.87. The data from this (and other wells we have studied) show that high concentrations of C 15+ hydrocarbons are thermally stable to high temperatures (at least 300°C) in abnormally-pressured semi-closed systems over geologic time. Concepts prevelant among petroleum organic geochemists concerning the thermal fate of hydrocarbons, with subsequent graphite formation, and greenschist metamorphism, are in sharp contradiction to these data. Conventional concepts of the distribution of heavy hydrocarbons with increasing temperature and depth apparently require further review and revision.

Chemical Geology↗
USGS1981

Organic geochemistry of the 9.6 km Bertha Rogers No. 1. well, Oklahoma

Organic geochemical analyses of fine-grained rocks from the 9.590 km Bertha Rogers No. 1 well have been carried out: total organic carbon, Soxhlet extraction and silica gel chromatography, C 15+ saturated and aromatic hydrocarbon gas chromatography and mass spectrometry, pyrolysis, kerogen analysis, X-ray diffraction and visual kerogen analysis. Rocks ranged in age from Permian to Ordovician; the well has an estimated bottom hole temperature of 225°C. Some data from this study are inconsistent with conventional theories concerning the generation and thermal destruction of hydrocarbons. For example, appreciable amounts of C 15+ gas-condensate-like hydrocarbons are present in very old rocks currently at temperatures where current theory predicts that only methane and graphite should remain. Also, substantial amounts of pyrolyzable C 15+ hydrocarbons remain on the kerogen in these deeply buried Paleozoic rocks. This suggests, at least in somes cases, that temperatures much higher than those predicted by current theory are required for generation and thermal destruction of hydrocarbons. The data from this well also suggest that original composition of organic matter and environment of deposition may have a much stronger influence on the organic geochemical characteristics of fine-grained sediments than has previously been ascribed to them. The results from this well, from other deep hot wells in which temperatures exceed 200°C, and from laboratory experiments, suggest that some of the basic concepts of the generation and maturation of petroleum hydrocarbons may be in error and perhaps should be reexamined.

Oklahoma↗
USGS1978

Hot, deep origin of petroleum: deep basin evidence and application

Use of the model of a hot deep origin of oil places rigid constraints on the migration and entrapment of crude oil. Specifically, oil originating from depth migrates vertically up faults and is emplaced in traps at shallower depths. Review of petroleum-producing basins worldwide shows oil occurrence in these basins conforms to the restraints of and therefore supports the hypothesis. Most of the world's oil is found in the very deepest sedimentary basins, and production over or adjacent to the deep basin is cut by or directly updip from faults dipping into the basin deep. Generally the greater the fault throw the greater the reserves. Fault-block highs next to deep sedimentary troughs are the best target areas by the present concept. Traps along major basin-forming faults are quite prospective. The structural style of a basin governs the distribution, types, and amounts of hydrocarbons expected and hence the exploration strategy. Production in delta depocenters (Niger) is in structures cut by or updip from major growth faults, and structures not associated with such faults are barren. Production in block fault basins is on horsts next to deep sedimentary troughs (Sirte, North Sea). In basins whose sediment thickness, structure and geologic history are known to a moderate degree, the main oil occurrences can be specifically predicted by analysis of fault systems and possible hydrocarbon migration routes. Use of the concept permits the identification of significant targets which have either been downgraded or ignored in the past, such as production in or just updip from thrust belts, stratigraphic traps over the deep basin associated with major faulting, production over the basin deep, and regional stratigraphic trapping updip from established production along major fault zones.

Open-File Report↗
USGS1978

Hot, deep origin of petroleum: shelf and shallow basin evidence and application

Oil and gas pools in shallow basins or on the shallow, stable shelves of deeper sedimentary basins may not be exceptions to the model of a hot deep origin of petroleum. 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 or 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 shelves of deep basins may have 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 have been sandstones in delta-distributary systems (eastern Oklahoma and Kansas), reef trends (Alberta, Canada), or regional porosity and permeability in sheet carbonates (Anadarko basin, western Oklahoma and Kansas).

Open-File Report↗