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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

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.

California↗
USGS2007

U.S. Geological Survey input-data form and operational procedure for the assessment of conventional petroleum accumulations

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

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↗
USGS2007

Glossary

Selected terms of particular importance to the U.S. Geological Survey assessment of undiscovered resources in total petroleum systems are defined here. The definitions are intended to be generally explanatory rather than strictly technical. No attempt has been made to include a detailed listing of common industry definitions.

Professional Paper↗
USGS2003

Well-Production Data and Gas-Reservoir Heterogeneity -- Reserve Growth Applications

Oil and gas well production parameters, including peakmonthly production (PMP), peak-consecutive-twelve month production (PYP), and cumulative production (CP), are tested as tools to quantify and understand the heterogeneity of reservoirs in fields where current monthly production is 10 percent or less of PMP. Variation coefficients, defined as VC= (F5-F95)/F50, where F5, F95, and F50 are the 5th, 95th, and 50th (median) fractiles of a probability distribution, are calculated for peak and cumulative production and examined with respect to internal consistency, type of production parameter, conventional versus unconventional accumulations, and reservoir depth. Well-production data for this study were compiled for 69 oil and gas fields in the Lower Pennsylvanian Morrow Formation of the Anadarko Basin, Oklahoma. Of these, 47 fields represent production from marine clastic facies. The Morrow data were supplemented by data from the Upper Cambrian and Lower Ordovician Arbuckle Group, Middle Ordovician Simpson Group, Middle Pennsylvanian Atoka Formation, and Silurian and Lower Devonian Hunton Group of the Anadarko Basin, one large gas field in Upper Cretaceous reservoirs of north-central Montana (Bowdoin field), and three areas of the Upper Devonian and Lower Mississippian Bakken Formation continuous-type (unconventional) oil accumulation in the Williston Basin, North Dakota and Montana. Production parameters (PMP, PYP, and CP) measure the net result of complex geologic, engineering, and economic processes. Our fundamental hypothesis is that well-production data provide information about subsurface heterogeneity in older fields that would be impossible to obtain using geologic techniques with smaller measurement scales such as petrographic, core, and well-log analysis. Results such as these indicate that quantitative measures of production rates and production volumes of wells, expressed as dimensionless variation coefficients, are potentially valuable tools for documenting reservoir heterogeneity in older fields for field redevelopment and risk analysis.

Bulletin↗
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↗
USGS2001

Basin-centered gas systems of the U.S.

Basin-center accumulations, a type of continuous accumulation, have spatial dimensions equal to or exceeding those of conventional oil and gas accumulations, but unlike conventional fields, cannot be represented in terms of discrete, countable units delineated by downdip hydrocarbon-water contacts. Common geologic and production characteristics of continuous accumulations include their occurrence downdip from water-saturated rocks, lack of traditional trap or seal, relatively low matrix permeability, abnormal pressures (high or low), local interbedded source rocks, large in-place hydrocarbon volumes, and low recovery factors. The U.S. Geological Survey, in cooperation with the U.S. Department of Energy, National Energy Technology Laboratory, Morgantown, West Virginia, is currently re-evaluating the resource potential of basin-center gas accumulations in the U.S. in light of changing geologic perceptions about these accumulations (such as the role of subtle structures to produce sweet spots), and the availability of new data. Better geologic understanding of basin-center gas accumulations could result in new plays or revised plays relative to those of the U.S. Geological Survey 1995 National Assessment (Gautier and others, 1995). For this study, 33 potential basin-center gas accumulations throughout the U.S. were identified and characterized based on data from the published literature and from well and reservoir databases (Figure 1). However, well-known or established basin-center accumulations such as the Green River Basin, the Uinta Basin, and the Piceance Basin are not addressed in this study.

Open-File Report↗
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↗
USGS1998

How perceptions have changed of world oil, gas resources

In this article, some of the trends in the estimates of the oil and gas resources are examined, with a view toward better understanding world oil and gas resources in the context of the next few decades. Quantitative assessments facilitate recognition of the big picture, which is necessary for purposes of planning and investment, and also form the foundation for periodic adjustments to the big picture made necessary by changes in technology and scientific understanding.

Oil & Gas Journal↗
USGS1998

Diverse gas plays lurk in gas resource pyramid

This final article on the outlook for U.S. future natural gas supplies expands on the concept of the natural gas resource pyramid. A series of poorly understood but potentially significant emerging gas plays is introduced. These plays reside at various levels within the resource pyramid. These emerging resources include sub-volcanic gas, shale gas, deep coalbed methane, and unrecognized tight gas sands.

Oil & Gas Journal↗
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↗
USGS1994

Regional porosity trends of the Upper Jurassic Norphlet Formation in southwestern Alabama and vicinity, with comparisons to formations of other basins

Sandstone porosity of the Upper Jurassic Norphlet Formation in southwestern Alabama and vicinity decreases systematically as depth and thermal maturity increase over a wide range. Median porosity is about 25% where equivalent vitrinite reflectance (R o ) is slightly over 0.7% in the northern part of the study area (Clarke County, Mississippi). Median porosity is reduced to 8% where R o approaches 2.7% in the southern part of the study area (state waters of Mobile Bay). Porosity of the cemented, tight zone at the top of the Norphlet in downdip locations is roughly 10% lower than porosities of facies underlying the tight zone, but nevertheless is slightly above the norm for other sandstones at similar R o levels. Porosity of dune facies is consistently 2-5% higher than that of interdune facies, other factors being equal. Our data show 3-6% higher porosity in chlorite-dominated intervals relative to intervals where illite is the dominant clay mineral. Norphlet porosity has little or no correlation with position relative to the present-day hydrocarbon-water contact. Based on comparisons at similar R o levels, median (50th-percentile) Norphlet porosity exceeds porosities of "typical" sandstones in other basins by more than a factor of two throughout the study area. Even the lower (10th-percentile) Norphlet porosities are higher than median porosities of sandstones in general.

Alabama, Mississippi, Florida↗