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At least 19 recordsLinked to original sources
USGS1997

U.S. Geological Survey Studies of Energy Resources in Sub-Saharan Africa

The U.S. Government and the American public need access to information on energy resources in sub-Saharan Africa. Sub-Saharan Africa (mostly Nigeria) produces 5 percent of the world's oil, while supplying the United States with 15 percent of our imports (Energy Information Administration). In the next 10 years, sub-Saharan oil and gas will become increasingly more important to the export market. New discoveries in offshore provinces of West Africa ensure a bright future for the region. Projections indicate that increased oil production in sub-Saharan Africa will far outpace the growth of intraregional consumption, providing greater quantities of oil for export (Forman, 1996). Also, West Africa, although a marginal supplier of liquefied natural gas (LNG) today, will become an important LNG source to the international market by the year 2000 (Oil & Gas Journal, 1996). The United States needs up-to-date information about petroleum resources and the energy balance within the region to predict the future role of sub-Saharan Africa as a major oil and gas exporter. The data required to generate the needed information are often disseminated in archives of oil companies and African geologic surveys, or in obscure publications. For these reasons, the U.S. Geological Survey is collecting data on sub-Saharan energy and constructing a regional energy bibliography. The team of geoscientists will assure that this information is available quickly and from a scientifically based, objective view point.

Fact Sheet↗
USGS2017

Using CO 2 Prophet to estimate recovery factors for carbon dioxide enhanced oil recovery

Introduction The Oil and Gas Journal’s enhanced oil recovery (EOR) survey for 2014 (Koottungal, 2014) showed that gas injection is the most frequently applied method of EOR in the United States and that carbon dioxide (CO 2 ) is the most commonly used injection fluid for miscible operations. The CO 2 -EOR process typically follows primary and secondary (waterflood) phases of oil reservoir development. The common objective of implementing a CO 2 -EOR program is to produce oil that remains after the economic limit of waterflood recovery is reached. Under conditions of miscibility or multicontact miscibility, the injected CO 2 partitions between the gas and liquid CO2 phases, swells the oil, and reduces the viscosity of the residual oil so that the lighter fractions of the oil vaporize and mix with the CO 2 gas phase (Teletzke and others, 2005). Miscibility occurs when the reservoir pressure is at least at the minimum miscibility pressure (MMP). The MMP depends, in turn, on oil composition, impurities of the CO 2 injection stream, and reservoir temperature. At pressures below the MMP, component partitioning, oil swelling, and viscosity reduction occur, but the efficiency is increasingly reduced as the pressure falls farther below the MMP. CO 2 -EOR processes are applied at the reservoir level, where a reservoir is defined as an underground formation containing an individual and separate pool of producible hydrocarbons that is confined by impermeable rock or water barriers and is characterized by a single natural pressure system. A field may consist of a single reservoir or multiple reservoirs that are not in communication but which may be associated with or related to a single structural or stratigraphic feature (U.S. Energy Information Administration [EIA], 2000). The purpose of modeling the CO 2 -EOR process is discussed along with the potential CO 2 -EOR predictive models. The data demands of models and the scope of the assessments require tradeoffs between reservoir-specific data that can be assembled and simplifying assumptions that allow assignment of default values for some reservoir parameters. These issues are discussed in the context of the CO 2 Prophet EOR model, and their resolution is demonstrated with the computation of recovery-factor estimates for CO 2 -EOR of 143 reservoirs in the Powder River Basin Province in southeastern Montana and northeastern Wyoming.

Scientific Investigations Report↗
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↗
USGS1919

The oil fields of Allen County, Kentucky, with notes on the oil geology of adjoining counties

This report is based on a reconnaissance investigation of the oil field of Allen County, Ky., which was part of a broader study of the oil and gas fields of Kentucky, Tennessee, and Alabama, on which a general report is planned. Most of the field work was done by Mr. Mather, who spent three and a half weeks in and around the county. Mr. Shaw visited Scottsville, the county seat of Allen County, a few years ago and spent a few days in that vicinity at the beginning of the recent field work, which extended from the middle of April to the middle of May, 1917 He prepared also the first draft of the report and reviewed the literature, including reports in oil and gas journals. The purpose of the field work was to investigate the geology of the county, particularly the structure or lay of the oil-bearing strata and the results of drilling to date. Structural conditions in the producing fields were determined by running level lines to the wells and correlating the data recorded in the well logs generously furnished by the operators. Traverses were made of outcrops, and observations of the dip and strike were made in different parts of the county. Lack of a topographic base map and of time and funds for making an accurate topographic survey render the results of the work somewhat incomplete, but it is hoped they will form a valuable contribution to the knowledge of the geology of this relatively little known region, for little detailed geologic work has been done heretofore within 50 miles of Scottsville. The dips are generally too low to be read by the clinometer, but in some localities unmistakable dips can be observed in extensive outcrops along creek banks and can be measured with a level or hand transit. Few of the beds of this region can be followed any considerable distance, though by means of fossils the stratigraphic position of beds outcropping many miles apart can be determined within a few feet. The black shale is the best horizon marker, but it outcrops in only a few places and is reached in only a few wells outside the oil fields. The field work thus consisted largely in observations on out- , cropping beds in different localities and in estimating the altitude of those identified, in collecting fossils for use in future detailed work, and in obtaining from oil operators data concerning the wells and their output. It included the determination of the general lay of the rocks in the county and surrounding territory and details of structure in certain areas. The rocks lie so nearly flat that without topographic data only the general dip could be made out for a large part of the area examined. A complete set of logs of wildcat wells in the region would have thrown much light on the structure and oil possibilities, but little is known of many of the earlier wells drilled in the region, especially of those altogether unsuccessful. An unsuccessful test is soon forgotten, though the data thus obtained concerning the depth at which different beds were found and the yield of porous strata, whether water, oil, or gas, is of great value to the geologist and oil prospector.

Kentucky↗
USGS2017

Carbon dioxide enhanced oil recovery performance according to the literature

Introduction The need to increase the efficiency of oil recovery and environmental concerns are bringing to prominence the use of carbon dioxide (CO 2 ) as a tertiary recovery agent. Assessment of the impact of flooding with CO 2 all eligible reservoirs in the United States not yet undergoing enhanced oil recovery (EOR) requires making the best possible use of the experience gained in 40 years of applications. Review of the publicly available literature has located relevant CO 2 -EOR information for 53 units (fields, reservoirs, pilot areas) in the United States and 17 abroad. As the world simultaneously faces an increasing concentration of CO 2 in the atmosphere and a higher demand for fossil fuels, the CO 2 -EOR process continues to gain popularity for its efficiency as a tertiary recovery agent and for the potential for having some CO 2 trapped in the subsurface as an unintended consequence of the enhanced production (Advanced Resources International and Melzer Consulting, 2009). More extensive application of CO 2 -EOR worldwide, however, is not making it significantly easier to predict the exact outcome of the CO 2 flooding in new reservoirs. The standard approach to examine and manage risks is to analyze the intended target by conducting laboratory work, running simulation models, and, finally, gaining field experience with a pilot test. This approach, though, is not always possible. For example, assessment of the potential of CO 2 -EOR at the national level in a vast country such as the United States requires making forecasts based on information already available. Although many studies are proprietary, the published literature has provided reviews of CO 2 -EOR projects. Yet, there is always interest in updating reports and analyzing the information under new perspectives. Brock and Bryan (1989) described results obtained during the earlier days of CO 2 -EOR from 1972 to 1987. Most of the recovery predictions, however, were based on intended injections of 30 percent the size of the reservoir’s hydrocarbon pore volume (HCPV), and the predictions in most cases badly missed the actual recoveries because of the embryonic state of tertiary recovery in general and CO 2 flooding in particular at the time. Brock and Bryan (1989), for example, reported for the Weber Sandstone in the Rangely oil field in Colorado, an expected recovery of 7.5 percent of the original oil in place (OOIP) after injecting a volume of CO 2 equivalent to 30 percent of the HCPV, but Clark (2012) reported that after injecting a volume of CO 2 equivalent to 46 percent of the HCPV, the actual recovery was 4.8 percent of the OOIP. Decades later, the numbers by Brock and Bryan (1989) continue to be cited as part of expanded reviews, such as the one by Kuuskraa and Koperna (2006). Other comprehensive reviews including recovery factors are those of Christensen and others (2001) and Lake and Walsh (2008). The Oil and Gas Journal (O&GJ) periodically reports on active CO 2 -EOR operations worldwide, but those releases do not include recovery factors. The monograph by Jarrell and others (2002) remains the most technically comprehensive publication on CO 2 flooding, but it does not cover recovery factors either. This chapter is a review of the literature found in a search for information about CO 2 -EOR. It has been prepared as part of a project by the U.S. Geological Survey (USGS) to assess the incremental oil production that would be technically feasible by CO 2 flooding of all suitable oil reservoirs in the country not yet undergoing tertiary recovery.

Scientific Investigations Report↗
USGS1988

Liquid hydrocarbons probable under Ross Sea

Thick glacial strata, which have no source-rock potential, cover the Ross Sea. If these strata persist to great depths, then hydrocarbon-generation prospects will be poor. Deeply buried strata within Ross Sea rift-grabens, if like other Gondwana rift-deposits, could have good potential for hydrocarbon generation. Current hydrocarbon assessments of the Ross Sea and adjacent areas must be considered highly speculative because the deeply buried rift(?) strata have not been sampled in situ. The assessment of the Ross Sea relies on geophysical/geologic data, two-stage rift models, and data from formerly nearby Gondwana rift-basins. We conclude that conditions favorable for hydrocarbon generation and entrapment are likely throughout the Ross Sea, and especially in the Victoria Land basin, if adequate source beds exist. -Authors

Oil & Gas Journal↗
USGS1989

Overview of Devonian Duperow formation production, Billings anticline, North Dakota

Oil exploration on the Billings anticline began in earnest in 1978, which is a north-plunging structure in the north central part of southwestern North Dakota. Forty-two fields are included in the Billings anticline area. This paper discusses the following features of the Billings anticline: structure, lithology, Duperow production, and some conservative economic scenarios.

North Dakota↗
USGS1990

Patrick Draw field, Wyoming - 1 seismic expression of subtle strat trap in Upper Cretaceous Almond

The east flank of the Rock Springs uplift and the adjacent Wamsutter arch contain several large hydrocarbon accumulations. Among these accumulations are Patrick Draw field, which produces oil and gas from a stratigraphic trap in the Upper Cretaceous Almond formation, and Table Rock field, a faulted anticlinal trap that produces gas from multiple Tertiary, Mesozoic, and Paleozoic reservoirs. The principal petroleum reservoir in Patrick Draw field is a sandstone at the top of the Almond formation. This sandstone attains a maximum thickness of 35ft and piches out westward into relatively impervious silt-stone and shale that constitute the trapping facies. The objective of this investigation is to determine whether or not the stratigraphic trap at Patrick Draw can be detected on a 12 fold, common depth point seismic profile acquired by Forest Oil Corp. and its partners. The seismic line is 18.5 miles long and crosses Patrick Draw and Table Rock fields.

Wyoming↗
USGS1990

Ouachitas need more exploratory drilling

The Ouachita Mountains in southeastern Oklahoma and western Arkansas are part of a mostly buried late Paleozoic fold and thrust belt that extends from Alabama to northern Mexico. The principal hydrocarbon reservoirs in the Ouachita tectonic province can be subdivided into those that produce natural gas from shallow-water units and those that produce oil and/or natural gas from deep-water units. They can also be divided into those that are fractured and those that produce from primary pore spaces or vugs. The first successful oil well in the Ouachita Mountains was drilled in 1913 or 1914. Since the discovery of the Redden field, over 800 oil and gas wells have been drilled in the Ouachita tectonic province in Oklahoma. Yet, most of the region remains little explored.

Arkansas, Oklahoma↗
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↗
USGS1996

Raton basin coalbed methane production picking up in Colorado

Coalbed methane production in the Raton basin of south-central Colorado and northeast New Mexico has gone over pilot testing and entered the development stage which is expected to last several years. The development work is restricted to roughly a 25 mile by 15 mile wide `fairway' centered about 20 miles west of Trinidad, Colorado. At last count, 85 wells were producing nearly 17.5 MMcfd of coalbed methane from the basin's Raton and Vermejo formation coals.

Colorado↗
USGS1996

Cambrian potential indicated in Kentucky Rome trough

A recent gas discovery in the Rome trough has Appalachian basin operators re-evaluating the deep Cambrian potential of eastern Kentucky. The Rome trough has seen sporadic exploration since the late 1940s, with very limited commercial success. A new exploration phase began in mid-1994 with completion of the Carson Associates 1 Kazee well in Elliott County, Ky. (Fig. 1). This well blew out and initially flowed 11 MMcfd of gas from a zone in the upper Conasauga Group/Rome formation at 6,258-70 ft.

Kentucky↗
USGS1997

Central-northern Appalachian coalbed methane flow grows

Coalbed methane (CBM) has become an increasingly important source of unconventional natural gas in the US within a span of a decade. In 1995, nearly 144 bcf of CBM was produced in the Appalachian basin at a value of about $260 million. From 1992 to 1995, CBM production in the central northern Appalachian basin quadrupled to nearly 31.3 bcf/year at a value of over $55 million, which represents only about 0.2% of the estimated technically recoverable CBM resource. Legal aspects of CBM ownership and environmental problems such as water disposal will become important issues to resolve in the various Appalachian states.

Oil & Gas Journal↗
USGS1998

Method determines vuggy carbonate permeability

An improved method determines vuggy carbonate permeability on the basis of specific surface area per unit pore volume and a flow zone indicator (FZI). Comparisons of fit standard error estimates show that this approach is superior to the multivariable empirical correlations of Chilingarian, et al., and to the ANN-estimated permeabilities.

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↗
USGS1998

Hydrates contain vast store of world gas resources

The discovery of large gas hydrate accumulations on the North Slope of Alaska and off the U.S. southeast coast has heightened interest in gas hydrates as a possible energy resource of the future. However, significant geological uncertainties and possibly insurmountable technical issues need to be resolved before gas hydrates can be counted as a viable option for future, affordable supplies of natural gas.

Oil & Gas Journal↗
USGS1999

Oil, gas field growth projections: Wishful thinking or reality?

The observed `field growth' for the period from 1992 through 1996 with the US Geological Survey's (USGS) predicted field growth for the same period are compared. Known field recovery of field size is defined as the sum of past cumulative field production and the field's proved reserves. Proved reserves are estimated quantities of hydrocarbons which geologic and engineering data demonstrate with reasonable certainty to recoverable from known fields under existing economic and operating conditions. Proved reserve estimates calculated with this definition are typically conservative. The modeling approach used by the USGS to characterize `field growth phenomena' is statistical rather that geologic in nature.

Oil & Gas Journal↗