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At least 55 records · Page 3Linked to original sources
USGS2011

Gas shale/oil shale

The production of natural gas from shales continues to increase in North America, and shale gas exploration is on the rise in other parts of the world since the previous report by this committee was published by American Association of Petroleum Geologists, Energy Minerals Division (2009). For the United States, the volume of proved reserves of natural gas increased 11% from 2008 to 2009, the increase driven largely by shale gas development (Energy Information Administration 2010c). Furthermore, shales have increasingly become targets of exploration for oil and condensate as well as gas, which has served to greatly expand their significance as ‘‘unconventional’’ petroleum reservoirs. This report provides information about specific shales across North America and Europe from which gas (biogenic or thermogenic), oil, or natural gas liquids are produced or is actively being explored. The intent is to reflect the recently expanded mission of the Energy Minerals Division (EMD) Gas Shales Committee to serve as a single point of access to technical information on shales regardless of the type of hydrocarbon produced from them. The contents of this report were drawn largely from contributions by numerous members of the EMD Gas Shales Advisory Committee, with much of the data being available from public websites such as state or provincial geological surveys or other public institutions. Shales from which gas or oil is being produced in the United States are listed in alphabetical order by shale name. Information for Canada is presented by province, whereas for Europe, it is presented by country.

Natural Resources Research↗
USGS1975

Linkage effects between deposit discovery and postdiscovery exploratory drilling

For the 1950-71 period of petroleum exploration in the Powder River Basin, northeastern Wyoming and southeastern Montana, three specific topics were investigated. First, the wildcat wells drilled during the ambient phases of exploration are estimated to have discovered 2.80 times as much petroleum per well as the wildcat wells drilled during the cyclical phases of exploration, periods when exploration plays were active. Second, the hypothesis was tested and verified that during ambient phases of exploration the discovery of deposits could be anticipated by a small but statistically significant rise in the ambient drilling rate during the year prior to the year of discovery. Closer examination of the data suggests that this anticipation effect decreases through time. Third, a regression model utilizing the two independent variables of (1) the volume of petroleum contained in each deposit discovered in a cell and the directly adjacent cells and (2) the respective depths of these deposits was constructed to predict the expected yearly cyclical wildcat drilling rate in four 30 by 30 min (approximately 860 mi 2 ) sized cells. In two of these cells relatively large volumes of petroleum were discovered, whereas in the other two cells smaller volumes were discovered. The predicted and actual rates of wildcat drilling which occurred in each cell agreed rather closely.

Montana, Wyoming↗
USGS2012

Regional map of the 0.70 psi/ft pressure gradient and development of the regional geopressure-gradient model for the onshore and offshore Gulf of Mexico basin, USA

Characterization of the regional pressure system in the Gulf of Mexico basin is critical for assessing the occurrence of undiscovered petroleum resources, evaluating areas with potential pressure-related production, identifying potential pressure-related geohazard issues, evaluating hydrocarbon reservoir-seal integrity, and determining the feasibility of geological sequestration and long-term containment of fluids.

Gulf of Mexico↗
USGS2000

A paleolatitude approach to assessing surface temperature history for use in burial heating models

Calculations using heat flow theory as well as case histories show that over geologic time scales (10 6 years), changes in mean annual surface temperature (T s ) on the order of 10°C penetrate kilometers deep into the crust. Thus, burial heating models of sedimentary basins, which typically span kilometers in depth and persist over geological time frames, should consider T s history to increase their accuracy. In any case, T s history becomes important when it changes enough to be detected by a thermal maturation index like vitrinite reflectance, a parameter widely used to constrain burial heating models. Assessment of the general temperature conditions leading to petroleum generation indicates that changes in T s as small as 6°C can be detected by vitrinite reflectance measurements. This low temperature threshold indicates that oil and gas windows can be significantly influenced by T s history. A review of paleoclimatic factors suggests the significant and geologically resolvable factors affecting T s history are paleolatitude, long-term changes between cool and warm geological periods (climate mode), the degree to which a basin is removed from the sea (geographic isolation), and elevation or depth relative to sea level. Case studies using geologically realistic data ranges or different methods of estimating T s in a burial heating model indicate a significant impact of Ts when: (1) continental drift, subduction, tectonism and erosion significantly change paleolatitude, paleoaltitude, or paleogeography; (2) strata are at, or near, maximum burial, and changes in T s directly influence maximum burial temperature; and (3), when a significant change in T s occurs near the opening or closing of the oil or gas windows causing petroleum generation to begin or cease. Case studies show that during the burial heating and petroleum generation phase of basin development changes in climate mode alone can influence T s by about 15°C. At present, T s changes from the poles to the equator by about 50°C. Thus, in extreme cases, continental drift alone can seemingly produce T s changes on the order of 50°C over a time frame of 107 years.

International Journal of Coal Geology↗
USGS1985

Lognormal field size distributions as a consequence of economic truncation

The assumption of lognormal (parent) field size distributions has for a long time been applied to resource appraisal and evaluation of exploration strategy by the petroleum industry. However, frequency distributions estimated with observed data and used to justify this hypotheses are conditional. Examination of various observed field size distributions across basins and over time shows that such distributions should be regarded as the end result of an economic filtering process. Commercial discoveries depend on oil and gas prices and field development costs. Some new fields are eliminated due to location, depths, or water depths. This filtering process is called economic truncation. Economic truncation may occur when predictions of a discovery process are passed through an economic appraisal model. We demonstrate that (1) economic resource appraisals, (2) forecasts of levels of petroleum industry activity, and (3) expected benefits of developing and implementing cost reducing technology are sensitive to assumptions made about the nature of that portion of (parent) field size distribution subject to economic truncation. ?? 1985 Plenum Publishing Corporation.

Journal of the International Association for Mathe↗
USGS2005

Mudstone sedimentation at high latitudes: Ice as a transport medium for mud and supplier of nutrients

Controls on mudstone deposition at high latitudes are poorly known relative to low latitudes. In recent sediments deposited in these environments, ice significantly influences sediment transport and primary productivity. The products of ice transport are relatively well known in glacimarine settings, but are less well known from below melting sea ice. This latter setting is significant as today it is associated with high primary organic productivity. The aim of this study is to assess how sea ice might have controlled lithofacies variability and organic-matter distribution and preservation in an ancient marine, siliciclastic mudstone-dominated succession deposited at high latitudes. Combined sedimentary logging, optical and electron optical (back-scatte red electron imagery), geochemical, and isotopic methods were used to determine sample variability in forty-five samples collected from the Lower Cretaceous succession in the Mikkelsen Bay State #1 borehole (North Slope, Alaska). The succession overall fines upward and contains muddy sandstones and sand- and silt-bearing, clay-rich mudstones towards its base in contrast to clay-rich and clay-dominated mudstones towards its top. Some of the mudstone units exhibit thin (< 5 mm), relic-beds that fine upward weakly. In some units small (0.5 mm), bed-parallel silt-filled microburrows disrupt depositional laminae whereas in others pervasive burrowing completely obliterates original depositional textures. Many of the units are pelleted. These mudstones are unusual in that they contain minor but very striking outsize grains, composed of subrounded to rounded sand and granule-size material. In addition, they are good petroleum source rocks, with between 2.8 and 5.9 wt % total organic carbon, of predominantly Type II kerogen. The organic matter has an isotopic signature ranging from -25.4??? ??13C to -28.1??? ??13C. Thin tuffs (< 20 mm) and carbonate-cemented units are also present. Given the absence of significant polar ice in the Early Cretaceous the outsized grains are interpreted to have been deposited from a combination of melting, dirty anchor, and fast ice. The mud fraction, which forms the bulk of the sediment, is interpreted to have been deposited from melting, sediment-laden frazil ice, and fast ice. After deposition sediments were partially reworked by bottom currents generated by brine rejection during sea ice formation. Sympagic organisms, grazing on algae and bacteria both within and below the ice, pelleted the sediment. Bioturbation, which varies through the succession, indicates that sedimentation probably occurred beneath a predominantly oxic or dysoxic water column. In this setting productivity was fueled by nutrients released from melting sea ice in the marginal ice zone. The good petroleum source potential of these mudstones is attributed to high organic productivity coupled to episodic and rapid sedimentation rather than existence of bottom-water anoxia linked to upwelling. Because sea-ice rafting was probably the dominant sediment transport mechanism it is not appropriate to use sequence stratigraphic methodology to predict lithofacies variability in this environment. Copyright ?? 2005, SEPM (Society for Sedimentary Geology).

Journal of Sedimentary Research↗
USGS1977

The quantitative determination of chlorophylls A and B from freshwater algae without interference from degradation products

Chlorophyll was efficiently extracted from freshwater algae with dimethyl sulfoxide. The extract was chromatographed on commercially available thin-layer cellulose sheets, 2 percent methanol and 98 percent petroleum ether being used as the solvent. Chlorophylls a and b , and phaeophytins a and b were cleanly separated from each other and other degradation products. No artifacts were formed. Recoveries of chlorophylls a and b were 98 and 96 percent as measured by spectrophotometry or fluorometry.

Journal of Research of the U.S. Geological Survey↗
USGS2006

Afghan resource assessment fed positive outlook for exploration

Crude oil, natural gas and natural gas liquids/condensate resources are important for the redevelopment of Afghanistan's infrastructure. Improved living and economic conditions in Afghanistan require increasing the availability of energy particularly by exploitation of Afghanistan's petroleum resources. The four total petroleum systems are subdivided into units with homogeneous geologic traits and exploration efforts that include sufficiently homogeneous field-size populations for resource assessment. The greatest volume of undiscovered crude oil is estimated to be in the Afghanistan Eastern Suprasalt Thrusts and Folds Assessment Unit. The greatest volume of undiscovered natural gas is estimated to be in the Afghanistan Jurassic Evaporite Basin Subsalt Carbonates Assessment Unit.

Oil & Gas Journal↗
USGS2010

Coalbed methane resources of the Appalachian Basin, eastern USA

In 2002, the U.S. Geological Survey (USGS) assessed the technically recoverable, undiscovered coalbed-gas resources in the Appalachian basin and Black Warrior basin Assessment Provinces as about 15.5 trillion cubic feet. Although these resources are almost equally divided between the two areas, most of the production occurs within relatively small areas within these Provinces, where local geological and geochemical attributes have resulted in the generation and retention of large amounts of methane within the coal beds and have enhanced the producibility of the gas from the coal. In the Appalachian basin, coalbed methane (CBM) tests are commonly commercial where the cumulative coal thickness completed in wells is greater than three meters (10 ft), the depth of burial of the coal beds is greater than 100 m (350 ft), and the coal is in the thermogenic gas window. In addition to the ubiquitous cleating within the coal beds, commercial production may be enhanced by secondary fracture porosity related to supplemental fracture systems within the coal beds. In order to release the methane from microporus coal matrix, most wells are dewatered prior to commercial production of gas. Two Total Petroleum Systems (TPS) were defined by the USGS during the assessment: the Pottsville Coal-bed gas TPS in Alabama, and the Carboniferous Coal-bed Gas TPS in Pennsylvania, Ohio, West Virginia, eastern Kentucky, Virginia, Tennessee, and Alabama. These were divided into seven assessment units, of which three had sufficient data to be assessed. Production rates are higher in most horizontal wells drilled into relatively thick coal beds, than in vertical wells; recovery per unit area is greater, and potential adverse environmental impact is decreased.

Alabama, Georgia, Kentucky, Maryland, North Caroli↗
USGS2010

Mineral facilities of Asia and the Pacific

This map displays over 1,500 records of mineral facilities throughout the continent of Asia and the countries of the Pacific Ocean. Each record represents one commodity and one facility type at a single geographic location. Facility types include mines, oil and gas fields, and plants, such as refineries, smelters, and mills. Common commodities of interest include aluminum, cement, coal, copper, gold, iron and steel, lead, nickel, petroleum, salt, silver, and zinc. Records include attributes, such as commodity, country, location, company name, facility type and capacity (if applicable), and latitude and longitude geographical coordinates (in both degrees-minutes-seconds and decimal degrees). The data shown on this map and in table 1 were compiled from multiple sources, including (1) the 2008 U.S. Geological Survey Minerals Yearbook (Asia and the Pacific volume), (2) minerals statistics and information from the U.S. Geological Survey Minerals Information Web site (http://minerals.usgs.gov/minerals/), and (3) data collected by U.S. Geological Survey minerals information country specialists. Other sources include statistical publications of individual countries, annual reports and press releases of operating companies, and trade journals. Due to the sensitivity of some energy commodity data, the quality of these data should be evaluated on a country-by-country basis. Additional information is available from the country specialists listed in table 2.

Open-File Report↗
USGS2010

Mineral facilities of Northern and Central Eurasia

This map displays almost 900 records of mineral facilities within the countries that formerly constituted the Union of Soviet Socialist Republics (USSR). Each record represents one commodity and one facility type at a single geographic location. Facility types include mines, oil and gas fields, and plants, such as refineries, smelters, and mills. Common commodities of interest include aluminum, cement, coal, copper, gold, iron and steel, lead, nickel, petroleum, salt, silver, and zinc. Records include attributes, such as commodity, country, location, company name, facility type and capacity (if applicable), and latitude and longitude geographical coordinates (in both degrees-minutes-seconds and decimal degrees). The data shown on this map and in table 1 were compiled from multiple sources, including (1) the most recently available data from the U.S. Geological Survey (USGS) Minerals Yearbook (Europe and Central Eurasia volume), (2) mineral statistics and information from the USGS Minerals Information Web site (http://minerals.usgs.gov/minerals/pubs/country/europe.html), and (3) data collected by the USGS minerals information country specialists from sources, such as statistical publications of individual countries, annual reports and press releases of operating companies, and trade journals. Data reflect the most recent published table of industry structure for each country at the time of this publication. Additional information is available from the country specialists listed in table 2

Open-File Report↗
USGS2010

Mineral facilities of Europe

This map displays over 1,700 records of mineral facilities within the countries of Europe and western Eurasia. Each record represents one commodity and one facility type at a single geographic location. Facility types include mines, oil and gas fields, and plants, such as refineries, smelters, and mills. Common commodities of interest include aluminum, cement, coal, copper, gold, iron and steel, lead, nickel, petroleum, salt, silver, and zinc. Records include attributes, such as commodity, country, location, company name, facility type and capacity (if applicable), and latitude and longitude geographical coordinates (in both degrees-minutes-seconds and decimal degrees). The data shown on this map and in table 1 were compiled from multiple sources, including (1) the most recently available data from the U.S. Geological Survey (USGS) Minerals Yearbook (Europe and Central Eurasia volume), (2) mineral statistics and information from the USGS Minerals Information Web site (http://minerals.usgs.gov/minerals/pubs/country/europe.html), and (3) data collected by the USGS minerals information country specialists from sources, such as statistical publications of individual countries, annual reports and press releases of operating companies, and trade journals. Data reflect the most recently published table of industry structure for each country at the time of this publication. Additional information is available from the country specialists listed in table 2.

Open-File Report↗
USGS1985

GEOLOGIC ASPECTS OF TIGHT GAS RESERVOIRS IN THE ROCKY MOUNTAIN REGION.

The authors describe some geologic characteristics of tight gas reservoirs in the Rocky Mountain region. These reservoirs usually have an in-situ permeability to gas of 0. 1 md or less and can be classified into four general geologic and engineering categories: (1) marginal marine blanket, (2) lenticular, (3) chalk, and (4) marine blanket shallow. Microscopic study of pore/permeability relationships indicates the existence of two varieties of tight reservoirs. One variety is tight because of the fine grain size of the rock. The second variety is tight because the rock is relatively tightly cemented and the pores are poorly connected by small pore throats and capillaries.

JPT, Journal of Petroleum Technology↗
USGS1975

Analysis of the rate of wildcat drilling and deposit discovery

The rate at which petroleum deposits were discovered during a 16-yr period (1957–72) was examined in relation to changes in a suite of economic and physical variables. The study area encompasses 11,000 mi 2 and is located on the eastern flank of the Powder River Basin. A two-stage multiple-regression model was used as a basis for this analysis. The variables employed in this model were: (1) the yearly wildcat drilling rate, (2) a measure of the extent of the physical exhaustion of the resource base of the region, (3) a proxy for the discovery expectation of the exploration operators active in the region, (4) an exploration price/cost ratio, and (5) the expected depths of the exploration targets sought. The rate at which wildcat wells were drilled was strongly correlated with the discovery expectation of the exploration operators. Small additional variations in the wildcat drilling rate were explained by the price/cost ratio and target-depth variables. The number of deposits discovered each year was highly dependent on the wildcat drilling rate, but the aggregate quantity of petroleum discovered each year was independent of the wildcat drilling rate. The independence between these last two variables is a consequence of the cyclical behavior of the exploration play mechanism. Although the discovery success ratio declined sharply during the initial phases of the two exploration plays which developed in the study area, a learning effect occurred whereby the discovery success ratio improved steadily with the passage of time during both exploration plays.

Journal of the International Association for Mathe↗
USGS2016

Application of organic petrography in North American shale petroleum systems: A review

Organic petrography via incident light microscopy has broad application to shale petroleum systems, including delineation of thermal maturity windows and determination of organo-facies. Incident light microscopy allows practitioners the ability to identify various types of organic components and demonstrates that solid bitumen is the dominant organic matter occurring in shale plays of peak oil and gas window thermal maturity, whereas oil-prone Type I/II kerogens have converted to hydrocarbons and are not present. High magnification SEM observation of an interconnected organic porosity occurring in the solid bitumen of thermally mature shale reservoirs has enabled major advances in our understanding of hydrocarbon migration and storage in shale, but suffers from inability to confirm the type of organic matter present. Herein we review organic petrography applications in the North American shale plays through discussion of incident light photographic examples. In the first part of the manuscript we provide basic practical information on the measurement of organic reflectance and outline fluorescence microscopy and other petrographic approaches to the determination of thermal maturity. In the second half of the paper we discuss applications of organic petrography and SEM in all of the major shale petroleum systems in North America including tight oil plays such as the Bakken, Eagle Ford and Niobrara, and shale gas and condensate plays including the Barnett, Duvernay, Haynesville-Bossier, Marcellus, Utica, and Woodford, among others. Our review suggests systematic research employing correlative high resolution imaging techniques and in situ geochemical probing is needed to better document hydrocarbon storage, migration and wettability properties of solid bitumen at the pressure and temperature conditions of shale reservoirs.

International Journal of Coal Geology↗
USGS1996

Fracture patterns and their origin in the upper Devonian Antrim Shale gas reservoir of the Michigan basin: A review

INTRODUCTION: Black shale members of the Upper Devonian Antrim Shale are both the source and reservoir for a regional gas accumulation that presently extends across parts of six counties in the northern part of the Michigan basin (fig. 1). Natural fractures are considered by most petroleum geologists and oil and gas operators who work the Michigan basin to be a necessary condition for commercial gas production in the Antrim Shale. Fractures provide the conduits for free gas and associated water to flow to the borehole through the black shale which, otherwise, has a low matrix permeability. Moreover, the fractures assist in the release of gas adsorbed on mineral and(or) organic matter in the shale (Curtis, 1992). Depths to the gas-producing intervals (Norwood and Lachine Members) generally range from 1,200 to 1,800 ft (Oil and Gas Journal, 1994). Locally, wells that produce gas from the accumulation are as deep as 2,200 (Oil and Gas Journal, 1994). Even though natural fractures are an important control on Antrim Shale gas production, most wells require stimulation by hydraulic fracturing to attain commercial production rates (Kelly, 1992). In the U.S. Geological Survey's National Assessment of United States oil and gas, Dolton (1995) estimates that, at a mean value, 4.45 trillion cubic feet (TCF) of gas are recoverable as additions to already discovered quantities from the Antrim Shale in the productive area of the northern Michigan trend. Dolton (1995) also suggests that undiscovered Antrim Shale gas accumulations exist in other parts of the Michigan basin. The character, distribution, and origin of natural fractures in the Antrim Shale gas accumulation have been studied recently by academia and industry. The intent of these investigations is to: 1) predict 'sweet spots', prior to drilling, in the existing gas-producing trend, 2) improve production practices in the existing trend, 3) predict analogous fracture-controlled gas accumulations in other parts of the Michigan basin, and 4) improve estimates of the recoverable gas in the Antrim Shale gas plays (Dolton, 1995). This review of published literature on the characteristics of Antrim Shale fractures, their origin, and their controls on gas production will help to define objectives and goals in future U.S. Geological Survey studies of Antrim Shale gas resources.

Michigan↗
USGS1976

A geochemical study of oil in metalliferous veins, Idarado Mine, San Juan Mountains, Colorado

A tarry, benzene-soluble material is present in metal-rich veins in the Idarado mine, Ouray County, Colo., in an area not known to have petroleum resources. The material was compared chemically, spectometrically, and chromatographically with oils from four fields in the nearby Paradox basin. Each of these oil fields contains reservoir rocks equivalent to rock units known to extend beneath volcanic rocks near the mine. Carbon and sulfur isotope data and gas chromatographic data indicate a similarity between the oil from the nearby Sierra field and the oil from the mine. Thus, it seems both geologically and chemically possible that oil in the mine originated in Cretaceous sediments. Variations in the composition of oil from the mine and differences between the mine oil and Sierra oil, notably in the distributions of hydrocarbons, are attributed to bacterial degradation.

Colorado↗
USGS2004

Petroleum systems succeed play basis in Appalachian basin resource estimate

The US Geological Survey (USGS) periodically conducts subjective probabilistic assessments of the technically recoverable undiscovered hydrocarbon resources of the US and of the world. In addition, the USGS prepares forecasts of that portion of the technically recoverable resources that may be economic under specified conditions of supply, demand, and price. Depending on priorities, regional hydrocarbon assessments of the US are revised every 5 to 10 years. These assessments of undiscovered hydrocarbons supplement the data on hydrocarbon reserves that are reported annually by the US Department of Energy, Energy Information Administration. In between assessments, USGS assessment geologists conduct research and compile geologic and production data that may be used to improve future assessments. This new information commonly effects changes in the way the USGS defines "plays" or "assessment units" from assessment to assessment. Furthermore, USGS assessment methodology is in a constant state of evolution and changes to some degree from assessment to assessment.

Oil & Gas Journal↗