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James W. Schmoker

Publications and source records attributed to James W. Schmoker.

At least 19 recordsLinked to original sources
USGS2007

U.S. Geological Survey assessment concepts for conventional petroleum accumulations: Chapter 24 in Petroleum systems and geologic assessment of oil and gas in the San Joaquin Basin Province, California

Conventional petroleum accumulations are discrete fields or pools localized in structural or stratigraphic traps by the buoyancy of oil or gas in water; they float, bubble-like, in water. This report describes the fundamental concepts supporting the U.S. Geological Survey “Seventh Approximation” model for resource assessments of conventional accumulations. The Seventh Approximation provides a strategy for estimating volumes of undiscovered petroleum (oil, gas, and coproducts) having the potential to be added to reserves in a 30-year forecast span. The assessment of an area requires (1) choice of a minimum accumulation size, (2) assignment of geologic and access risk, and (3) estimation of the number and sizes of undiscovered accumulations in the assessment area. The combination of these variables yields probability distributions for potential additions to reserves. Assessment results are controlled by geology-based input parameters supplied by knowledgeable geologists, as opposed to projections of historical trends.

Professional Paper↗
USGS2007

U.S. Geological Survey input-data form and operational procedure for the assessment of conventional petroleum accumulations: Chapter 25 in Petroleum systems and geologic assessment of oil and gas in the San Joaquin Basin Province, California

The U.S. Geological Survey model for undiscovered conventional accumulations is designed to aid in the assessment of crude oil, natural gas, and natural gas liquids (collectively called petroleum) resources. Conventional accumulations may be described in terms of discrete fields or pools localized in structural and stratigraphic traps by the buoyancy of oil or natural gas in water. Conventional accumulations are commonly bounded by a down-dip water contact. The assessment model requires estimates of the number and sizes of undiscovered conventional accumulations. Technically recoverable petroleum resources from undiscovered conventional accumulations are calculated by statistically combining probability distributions of the estimated number and sizes of undiscovered accumulations, along with associated risks and coproduct ratios. Probabilistic estimates of petroleum resources are given for oil in oil accumulations, gas (associated/dissolved) in oil accumulations, natural gas liquids in oil accumulations, gas (nonassociated) in gas accumulations, and total liquids (oil and natural gas liquids) in gas accumulations.

Professional Paper↗
USGS2007

Data sources and compilation: Chapter 27 in Petroleum systems and geologic assessment of oil and gas in the San Joaquin Basin Province, California

Geologic, production, and exploration/discovery-history data are used by the U.S. Geological Survey to aid in the assessment of petroleum resources. These data, as well as the broad knowledge and experience of the assessing geologists, are synthesized to provide, for each assessment unit, geologic and exploration models upon which estimates are made of the number and sizes of undiscovered accumulations for conventional assessment units or number and total recoverable volumes of untested cells for continuous assessment units (input data for resource calculations). Quantified geologic information and trends in production and exploration/discovery-history data with respect to time and exploration effort provide guides for the estimating parameters of variables recorded on the input-data forms (input data) used to calculate petroleum resources. An Assessment Review Team reviews proposed geologic and exploration models and input data for each assessment unit in formal assessment meetings. The Assessment Review Team maintains the accuracy and consistency of the assessment procedure during the formal assessment meetings.

Professional Paper↗
USGS2001

Changing perceptions of United States natural-gas resources as shown by successive U. S. Department of the Interior assessments

Trends in four successive estimates of United States technically recoverable natural gas resources are examined in this report. The effective dates of these assessments were January 1 of 1975, 1980, 1987, and 1994. The 1994 estimate of the U.S. total gas endowment increased significantly over the previous three estimates, indicating that the technically recoverable endowment of gas is not an absolute volume, but rather is a quantity that can increase through time in response to advances in technology and in geologic understanding. Much of this increase was in the category of reserve growth. Reserve growth refers to additions to the estimated ultimate recovery of fields that typically occur as discovered fields are developed and produced. The potential for U.S. reserve growth, rather than being rapidly used up, appears to be sustainable for many years by intensive engineering efforts coupled with improving technology. Potential additions to reserves in continuous (unconventional) accumulations also represent a type of reserve growth, and were estimated (for the first time) in the 1994 assessment at 358 trillion cubic feet of gas. This resource category provides a significant new contribution to the estimated U.S. total gas endowment.

Bulletin↗
USGS2000

Reserve growth effects on estimates of oil and natural gas resources

Many scientists think that the supply of economically recoverable oil and natural gas is geologically limited. However, as recently as early 1999, we experienced a glut of oil on the world market and the lowest inflation-adjusted price of gasoline in history. What is going on? While we cannot provide a comprehensive answer to that question here, we can describe one process that significantly affects the domestic oil and gas industry, a process that also will affect the global industry at some point—reserve growth (also known as field growth).

Fact Sheet↗
USGS1997

Reserve growth important to U.S. gas supply

Reserve growth is a major component of the remaining U.S. natural gas resources. Historical data support this premise, as do estimates of technically recoverable and of economically recoverable gas resources remaining in the U.S. However, reserve growth is still poorly understood. Hence, much work remains to be done on the phenomenon of reserve growth.

Oil & Gas Journal↗
USGS1990

Woodford shale in the Anadarko basin: Could it be another 'Bakken type' horizontal target?

The Woodford shale is one of several organic rich "black" shales of late Devonian and early Mississippian age present in basins of the North American craton. Where thermally mature, these black shales are economically important as hydrocarbon source rocks. The Woodford shale is widely regarded as a major source rock in the Anadarko basin. This report describes regional depositional trends and organic carbon content of the Woodford shale as evidenced by wire line logs in the Oklahoma portion of the Anadarko basin.

Oil & Gas Journal↗
USGS1989

Thermal maturity of the Anadarko Basin

Levels of thermal maturity are estimated for Paleozoic strata in five areas of the central Anadarko basin for times between the Paleozoic and the present, and depths of the oil window are plotted as a function of geologic time. Mean surface temperature assumed here for calculating Lopatin's time-temperature index of thermal maturity (TTl) in the central Anadarko basin declines from 80°F (27°C) to 60°F (16°C) from early Paleozoic time to the present. Shallow-water carbonates and lower paleolatitudes suggest warmer climates in the Paleozoic for this area. The geothermal gradient is assumed to equal 4.0°F/100 ft (7.3°C/100 m) in the Late Cambrian and to decay over a 100-m.y. period to the present regional gradient of 1.3°F/100 ft (2.4°C/100 m). Initial basin formation was caused by crustal thinning. Accumulation of thick Pennsylvanian sediments in a foreland-style basin dominated by vertical lithospheric flexure represents a second major period of subsidence. An elevated geothermal gradient during this time is not assumed for TTl calculations, because mathematical models suggest time-invariant heat flows in such basins. TTl computations based on these assumptions indicate that oil could have been generated in the ancestral Anadarko basin >350 m.y. ago. By the end of the Pennsylvanian, significant volumes of kerogen were in the oil window (and perhaps beyond), and significant volumes have remained in the oil window up to the present day. These circumstances may partially explain the unusual richness of the Anadarko basin as a Paleozoic hydrocarbon province.

Oklahoma↗
USGS1989

Relationship of clay-mineral diagenesis to temperature, age, and hydrocarbon generation–an example from the Anadarko Basin, Oklahoma

Randomly interstratified illite/smectite (I/S) is present in Springeran and Morrowan rocks (Late Mississippian and Early Pennsylvanian) of the Anadarko basin, Oklahoma, at present-day depths <2,750 m, but disappears at depths of 2,750-3,050 m. Only ordered I/S is found in samples below 3,050 m. The work reported here relates the diagenesis of I/S to burial history and oil generation in the Anadarko basin and tests the dependence of the smectite-to-illite reaction on temperature and time. Published temperature models of clay diagenesis suggest that, for Tertiary and Cretaceous rocks, the transition from randomly interstratified I/S to ordered I/S occurs at 100-110°C. Burial reconstructions for the Anadarko basin indicate that maximum temperatures of 100-110°C correspond to present-day burial depths between 2,700 and 3,100 m. These independently calculated depths for the 100-110°C isotherm match the depths at which randomly interstratified I/S is observed to disappear in Morrowan-Springeran rocks. Thus, random I/S disappears at the same temperature in rocks that differ in age by some 300 m.y. Although the extent of the smectite-to-illite reaction is controlled by kinetics, and effects of time are apparent in laboratory experiments and short-lived geologic systems, the results of this study suggest that time plays a secondary role in long-term diagenetic settings.

Oklahoma↗
USGS1985

Selected characteristics of limestone and dolomite reservoirs in the United States

Data from the United States Oil and Gas File (TOTL) developed by the University of Oklahoma, Norman, Oklahoma, are used to characterize the lithology, location (state and basin), geologic age, year of discovery, depth to top of pay, porosity, permeability, water saturation, volume of crude oil and nonassociated gas originally in place, and net-pay thickness of limestone and dolomite reservoirs in the United States. Distributions of these parameters, representing thousands of reservoirs, establish a framework to which individual carbonate reservoirs can be compared, and provide insights into geologic processes affecting reservoir characteristics. Limestone reservoirs are more numerous in the United States than dolomite reservoirs (by a ratio of about 3 to 1) because limestones are more abundant than dolomites. However, in the eight states that account for over 90% of United States carbonate reservoirs, there is a statistical tendency for carbonate reservoirs to occur preferentially in dolomites. Dolomite reservoirs, on the average, are larger and deeper than those of limestone, yet they often have lower matrix porosities and permeabilities. This line of investigation offers supplemental evidence that dolomitization tends to improve the reservoir properties of a given formation, and that effective fracture systems at reservoir depths are more likely to occur in dolomites than in limestones.

American Association of Petroleum Geologists Bulle↗
USGS1984

Empirical relation between carbonate porosity and thermal maturity: An approach to regional porosity prediction

Data indicate that porosity loss in subsurface carbonate rocks can be empirically represented by the power function, ^Thgr = a (TTI) b , where ^Thgr is regional porosity, TTI is Lopatin's time-temperature index of thermal maturity, the exponent, b, equals approximately -0.372, and the multiplier, a, is constant for a given data population but varies by an order of magnitude overall. Implications include the following. 1. The decrease of carbonate porosity by burial diagenesis is a maturation process depending exponentially on temperature and linearly on time. 2. The exponent, b, is essentially independent of the rock matrix, and may reflect rate-limiting processes of diffusive transport. 3. The multiplying coefficient, a, incorporates the net effect on porosity of all depositional and diagenetic parameters. Within constraints, carbonate-porosity prediction appears possible on a regional measurement scale as a function of thermal maturity. Estimation of carbonate porosity at the time of hydrocarbon generation, migration, or trapping also appears possible.

American Association of Petroleum Geologists Bulle↗