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At least 37 records · Page 2Linked to original sources
USGS2006

Effects of roads and well pads on erosion in the Largo Canyon watershed, New Mexico, 2001-02

Largo Canyon, located in the San Juan Basin of northwestern New Mexico, is one of the longest dry washes in the world. Oil and gas production in the San Juan Basin, which began in the 1940's, required the development of an extensive network of dirt roads to service the oil and gas wells in the Navajo Reservoir area. Presently, there are about eight wells per square mile, and the density of oil and gas wells is expected to increase. Potential environmental effects on landscape stability that may result from the additional roads and well pads have not been documented. In 2001, the U.S. Geological Survey began a study in cooperation with the Bureau of Land Management to evaluate the effects of roads and well pads associated with oil and gas operations on the erosion potential of Bureau of Land Management lands in the Largo Canyon watershed. The effects of roads and well pads on erosion were quantified by installing sediment dams (dams) and by surveying transects across roads and well pads. Data from 26 dams were used in the analysis. Dams were installed at 43 sites: 21 on hillsides upslope from roads or pads to measure erosion from hillslopes, 11 at the downslope edges of roads to measure erosion from roads, and 11 at the downslope edges of well pads to measure erosion from well pads. Pairs of survey transects were established at nine well pads and two road locations. Sediment-accumulation data for 26 dams, recorded at 17 measurement intervals, indicate that average erosion rates at the dams significantly correlate to size of the contributing area. The average erosion rate normalized by drainage area was 0.001 foot per year below roads, 0.003 foot per year on hillslopes, and 0.011 foot per year below well pads. Results of a two-sample t-test indicate that there was no significant difference in average erosion rates for dams located on hillslopes and below roads, whereas average erosion rates were significantly greater for dams below well pads than for dams on hillslopes and dams below roads. The average erosion rates estimated from the data collected during this study most likely represent minimum erosion rates. Sediment-accumulation data for measurement intervals and for dams that were breached during 2002, resulting from the large volume of runoff generated by high-intensity storms, were not used to compute erosion rates. For this reason, the higher range of erosion rates is underrepresented and the results of this study are biased toward the lower end of the range of erosion rates. Measurements along road transects generally indicate that sediment is eroded from the top of road berms and redeposited at the base of the berms and may be transported downslope along the road. Measurements along well-pad transects generally indicate that sediment eroded from hillslopes is transported over the surface of the well pad and down the well-pad edges. Based on field observations, roads aligned parallel to topographic contours facilitate erosional processes in two ways: (1) roads cut across and collect runoff from previously established drainages and (2) roads, where they are cut into hillsides or into the land surface, provide focal points for the initiation of erosion. Roads aligned across topographic contours can serve as conduits to channel runoff but do not constitute a large percentage of the road network.

Scientific Investigations Report↗
USGS2007

Heavy oil and natural bitumen resources in geological basins of the world

Heavy oil and natural bitumen are oils set apart by their high viscosity (resistance to flow) and high density (low API gravity). These attributes reflect the invariable presence of up to 50 weight percent asphaltenes, very high molecular weight hydrocarbon molecules incorporating many heteroatoms in their lattices. Almost all heavy oil and natural bitumen are alteration products of conventional oil. Total resources of heavy oil in known accumulations are 3,396 billion barrels of original oil in place, of which 30 billion barrels are included as prospective additional oil. The total natural bitumen resource in known accumulations amounts to 5,505 billion barrels of oil originally in place, which includes 993 billion barrels as prospective additional oil. This resource is distributed in 192 basins containing heavy oil and 89 basins with natural bitumen. Of the nine basic Klemme basin types, some with subdivisions, the most prolific by far for known heavy oil and natural bitumen volumes are continental multicyclic basins, either basins on the craton margin or closed basins along convergent plate margins. The former includes 47 percent of the natural bitumen, the latter 47 percent of the heavy oil and 46 percent of the natural bitumen. Little if any heavy oil occurs in fore-arc basins, and natural bitumen does not occur in either fore-arc or delta basins.

Open-File Report↗
USGS1985

ESTIMATE OF WORLD HEAVY CRUDE OIL AND NATURAL BITUMEN RESOURCES.

The quantity of heavy hydrocarbons - heavy crude oil and natural bitumens - known or surmised to be present in the earth is large. The total is estimated to fall in the range of 5,879,712-5,942,139 million barrels. The portion of this that may ultimately prove recoverable is small, perhaps on the order of 500,000 million barrels of heavy crude oil and 200,000 million barrels of bitumen.

Conference Paper↗
USGS1985

Comparative study of aggregations under different dependency assumptions for assessment of undiscovered recoverable oil resources in the world

The U.S. Geological Survey assessed all significant sedimentary basins in the world for undiscovered conventionally recoverable crude-oil resources. Probabilistic methodology was applied to each basin assessment to produce estimates in the form of probability distributions. Basin probability distributions were computer aggregated to produce resource estimates for the entire world. Aggregation was approximated by a three-parameter lognormal distribution by combining the first three central moments of basin distributions. For purposes of experiment and study, world aggregation was conducted under four different sets of assumptions. The four cases are (1) dependent assessments of all basins, (2) dependent assessments within continental areas, but independent assessments among continental areas, (3) dependent assessments within countries, but independent assessments among countries, and (4) independent assessments of all basins. Mean estimate remained the same in all four cases, but the width of interval estimate formed using the 95th and 5th fractiles decreased with reduced dependency in going from first to fourth case. ?? 1985 Plenum Publishing Corporation.

Journal of the International Association for Mathe↗
USGS2009

Assessment of undiscovered oil and gas in the Arctic

Among the greatest uncertainties in future energy supply and a subject of considerable environmental concern is the amount of oil and gas yet to be found in the Arctic. By using a probabilistic geology-based methodology, the United States Geological Survey has assessed the area north of the Arctic Circle and concluded that about 30% of the world’s undiscovered gas and 13% of the world’s undiscovered oil may be found there, mostly offshore under less than 500 meters of water. Undiscovered natural gas is three times more abundant than oil in the Arctic and is largely concentrated in Russia. Oil resources, although important to the interests of Arctic countries, are probably not sufficient to substantially shift the current geographic pattern of world oil production.

Science↗
USGS2008

An Approach to the Classification of Potential Reserve Additions of Giant Oil Fields of the World

This report contains slides and notes for slides for a presentation given to the Committee on Sustainable Energy and the Ad Hoc Group of Experts on Harmonization of Fossil Energy and Mineral Resources Terminology on 17 October 2007 in Geneva, Switzerland. The presentation describes the U.S. Geological Survey study to characterize and quantify petroleum-reserve additions, and the application of this study to help classify the quantities.

Open-File Report↗
USGS2011

U.S. Geological Survey circum-arctic resource appraisal

Among the greatest uncertainties in future energy supply is the amount of oil and gas yet to be found in the Arctic. Using a probabilistic geology-based methodology, the U.S. Geological Survey has assessed the area north of the Arctic Circle. The Circum-Arctic Resource Appraisal (CARA) consists of three parts: (1) Mapping the sedimentary sequences of the Arctic (Grantz and others 2009), (2) Geologically based estimation of undiscovered technically recoverable petroleum (Gautier and others 2009, discussed in this presentation) and (3) Economic appraisal of the cost of delivering the undiscovered resources to major markets (also reported at this conference by White and others). We estimate that about 30% of the world's undiscovered gas and about 13% of the world's undiscovered oil may be present in the Arctic, mostly offshore under less than 500m of water. Billion BOE-plus accumulations of gas and oil are predicted at a 50% probability in the Kara Sea, Barents Sea, offshore East and West Greenland, Canada, and Alaska. On a BOE basis, undiscovered natural gas is three times more abundant than oil in the Arctic and is concentrated in Russian territory. Oil resources, while critically important to the interests of Arctic countries, are probably not sufficient to significantly shift the current geographic patterns of world oil production. Copyright 2011, Offshore Technology Conference.

Conference Paper↗
USGS1991

Resource constraints in petroleum production potential

Geologic reasons indicate that the dominant position of the Middle East as a source of conventional petroleum will not be changed by new discoveries elsewhere. The share of world crude oil production coming from the Middle East could increase, within 10 to 20 years, to exceed 50 percent, under even modest increases in world consumption. Nonconventional resources of oil exist in large quantities, but because of their low production rates they can at best only mitigate extant trends. Increased production of natural gas outside the United States, however, offers an opportunity for geographically diversified energy supplies in the near future.

Science↗
USGS2012

Assessment of potential additions to conventional oil and gas resources of the world (outside the United States) from reserve growth, 2012

The U.S. Geological Survey estimated volumes of technically recoverable, conventional petroleum resources resulting from reserve growth for discovered fields outside the United States that have reported in-place oil and gas volumes of 500 million barrels of oil equivalent or greater. The mean volumes were estimated at 665 billion barrels of crude oil, 1,429 trillion cubic feet of natural gas, and 16 billion barrels of natural gas liquids. These volumes constitute a significant portion of the world's oil and gas resources.

Fact Sheet↗
USGS1982

Assessment of the petroleum, coal, and geothermal resources of the Economic Community of West African States (ECOWAS) region

Approximately 85 percent of the land area of the ECOWAS (Economic Community of West African States) region is covered by basement rocks (igneous and highly metamorphosed rocks) or relatively thin layers of Paleozoic, Upper Precambrian, and 'Continental Intercalaire? sedimentary rocks. These areas have little or no petroleum potential. Areas of the ECOWAS region that have potential for petroleum production or potential for increased petroleum production include the narrow belt of sedimentary rocks that stretches along the continental margin from Mauritania to Nigeria and the Niger Delta and the Benue depression. The Senegal Basin, located on the continental margin of Mauritania, Senegal, Gambia, Guinea Bissau, and Guinea, has been intensely explored by the oil industry and most of the larger structures onshore and on the shelf probably have been tested by drilling with little or no resulting commercial production. Unless basic ideas pertaining to the petroleum geology of the Senegal Basin are revised, future discoveries are expected to be limited to small fields overlooked by industry at a time when petroleum prices were low. On the continental shelf of Sierra Leone and the continental shelf of northeast and central Liberia, the sedimentary rocks are relatively thin, and industry has shown little interest in the area. On the continental rise of these countries, however, the sedimentary section, deposited in a complex fault-block system, increases in thickness. A renewal of industry interest in this deep-water area will probably follow further development of deep-water production technology. A recent oil discovery on the continental slope off the Ivory Coast is expected to spur further exploration offshore of southeastern Liberia, Ivory Coast, Ghana, Togo, and Benin. This relatively unexplored area in the Gulf of Guinea has good possibilities .for the discovery of giant oil fields. Nigeria's oil development from the Niger Delta may have peaked, as 13 of 14 giant oil fields were discovered prior to 1969 and the greatest number of fields were discovered in the period 1965 through 1967. Like delta regions in other parts of the world, individual oil fields of the Niger Delta are small to medium by world standards and future discoveries, therefore, are likely to reflect this reality. The natural gas resources of the Niger Delta, unlike its oil resources, are comparatively underdeveloped. Parts of the Benue depression in Nigeria and Niger could contain significant deposits of petroleum. The lower Benue depression, immediately north of the Niger Delta, has been extensively explored by drilling. Except for noncommercial discoveries of oil and gas and traces of oil and gas on the ground surface, the results of exploration in the lower Benue depression were negative. However, in the Lake Chad area of Chad and in southern Chad near the Central African Republic boundary, oil and gas discoveries were made just prior to the cessation of all drilling and exploration activity in early 1979. It is rumored that these discoveries may be large although little information is available. The relation between the two areas in Chad and their overall relation to the Benue depression is poorly understood; however, the possibility of thick sedimentary sections containing Cretaceous marine source rock and Tertiary reservoir beds-all contained within grabens in a highly faulted failed-arm system subjected to high heat flow--is attractive. Of the ECOWAS countries, only Nigeria and Niger produce coal commercially. Nigeria produces subbituminous coal from Paleocene-Maestrichtian and Maestrichtian (Late Cretaceous) age rocks of the Niger Delta region; reserves are estimated, on the basis of extensive drilling, to be 350 million tons (standard coal equivalent). In addition, lignite deposits of the Niger Delta appear to be large but have not been developed. Niger produces small amounts of coal used locally by uranium mine and mill operations from C

Open-File Report↗
USGS2007

Natural bitumen and extra-heavy oil

Since 2005, oil price increases have greatly increased investment in the production of extra- heavy oil and natural bitumen (tar sands or oil sands) to supplement conventional oil supplies. These oils are characterised by their high viscosity, high density (low API gravity), and high concentrations of nitrogen, oxygen, sulphur, and heavy metals. Extra-heavy oil and natural bitumen are the remnants of very large volumes of conventional oils that have been generated and subsequently degraded, principally by bacterial action. Chemically and texturally, they resemble the residuum produced by refinery distillation of light oil. Although these viscous oils are much more costly to extract, transport and refine than conventional oils, production levels have increased to more than 1.6 million barrels per day, or just under 2% of world crude oil production. The resource base of extra-heavy oil and natural bitumen is immense and can easily support a substantial expansion in production. This resource base can make a major contribution to oil supply, if it can be extracted and transformed into useable refinery feedstock at sufficiently high rates and at costs that are competitive with alternative resources. Technology must continue to be developed to address emerging challenges (both environmental and economic) in the market supply chain.

Book chapter↗
USGS1980

Crude oil degradation as an explanation of the depth rule

Previous studies of crude oil degradation by water washing and bacterial attack have documented the operation of these processes in many different petroleum basins of the world. Crude oil degradation substantially alters the chemical and physical makeup of a crude oil, changing a light paraffinic low-S "mature" crude to a heavy naphthenic or asphalt base, "immature appearing" high-S crude. Rough calculations carried out in the present study using experimentally determined solubility data of petroleum in water give insight into the possible magnitude of water washing and suggest that the process may be able to remove large amounts of petroleum in small divisions of geologic time. Plots of crude oil gravity vs. depth fail to show the expected correlation of increasing API gravity (decreasing specific gravity) with depth below 2.44 km (8000 ft.). Previous studies which have been carried out to document in-reservoir maturation have used crude oil gravity data shallower than 2.44 km (8000 ft.). The changes in crude oil composition as a function of depth which have been attributed to in-reservoir maturation over these shallower depths, are better explained by crude oil degradation. This study concludes that changes in crude oil composition that result from in-reservoir maturation are not evident from existing crude oil gravity data over the depth and temperature range previously supposed, and that the significant changes in crude oil gravity which are present over the shallow depth range are due to crude oil degradation. Thus the existence of significant quantities of petroleum should not necessarily be ruled out below an arbitrarily determined depth or temperature limit when the primary evidence for this is the change in crude oil gravity at shallow depths. ?? 1980.

Chemical Geology↗
USGS2015

U.S. Geological Survey assessment of reserve growth outside of the United States

The U.S. Geological Survey estimated volumes of potential additions to oil and gas reserves for the United States by reserve growth in discovered accumulations. These volumes were derived by using a new methodology developed by the U.S. Geological Survey and reviewed by the American Association of Petroleum Geologists Committee on Resource Evaluation. This methodology was used to assess reserve growth in individual accumulations (reservoirs, groups of reservoirs, or fields). Selected, large, well-studied, conventional accumulations in the United States that are estimated to contribute most to reserve growth were assessed using analysis of geology and engineering practices. Potential additions to oil and gas reserves for large, discovered, conventional accumulations outside of the United States due to reserve growth were assessed using the U.S. accumulations as analogs. Potential oil and gas volumes were assumed to be added to proven plus probable reserves. The U.S. Geological Survey estimated volumes of technically recoverable, conventional petroleum resources resulting from reserve growth for discovered fields outside the United States that have reported in-place oil and gas volumes of 500 million barrels of oil equivalent or greater. The mean volumes of reserve growth were estimated at 665 billion barrels of crude oil; 1,429 trillion cubic feet of natural gas; and 16 billion barrels of natural gas liquids. These volumes constitute a significant portion of the world’s oil and gas resources and represent the potential future growth of current global reserves over time based on better assessment methodology, new technologies, and greater understanding of reservoirs.

Scientific Investigations Report↗
USGS2007

Geochemistry of Selected Coal Samples from Sumatra, Kalimantan, Sulawesi, and Papua, Indonesia

Introduction Indonesia is an archipelago of more than 17,000 islands that stretches astride the equator for about 5,200 km in southeast Asia (figure 1) and includes major Cenozoic volcano-plutonic arcs, active volcanoes, and various related onshore and offshore basins. These magmatic arcs have extensive Cu and Au mineralization that has generated much exploration and mining in the last 50 years. Although Au and Ag have been mined in Indonesia for over 1000 years (van Leeuwen, 1994), it was not until the middle of the nineteenth century that the Dutch explored and developed major Sn and minor Au, Ag, Ni, bauxite, and coal resources. The metallogeny of Indonesia includes Au-rich porphyry Cu, porphyry Mo, skarn Cu-Au, sedimentary-rock hosted Au, epithermal Au, laterite Ni, and diamond deposits. For example, the Grasberg deposit in Papua has the world's largest gold reserves and the third-largest copper reserves (Sillitoe, 1994). Coal mining in Indonesia also has had a long history beginning with the initial production in 1849 in the Mahakam coal field near Pengaron, East Kalimantan; in 1891 in the Ombilin area, Sumatra, (van Leeuwen, 1994); and in South Sumatra in 1919 at the Bukit Asam mine (Soehandojo, 1989). Total production from deposits in Sumatra and Kalimantan, from the 19thth century to World War II, amounted to 40 million metric tons (Mt). After World War II, production declined due to various factors including politics and a boom in the world-wide oil economy. Active exploration and increased mining began again in the 1980's mainly through a change in Indonesian government policy of collaboration with foreign companies and the global oil crises (Prijono, 1989). This recent coal revival (van Leeuwen, 1994) has lead Indonesia to become the largest exporter of thermal (steam) coal and the second largest combined thermal and metallurgical (coking) coal exporter in the world market (Fairhead and others, 2006). The exported coal is desirable as it is low sulfur and ash (generally <1 and < 10 wt.%, respectively). Coal mining for both local use and for export has a very strong future in Indonesia although, at present, there are concerns about the strong need for a major revision in mining laws and foreign investment policies (Wahju, 2004; United States Embassy Jakarta, 2004). The World Coal Quality Inventory (WoCQI) program of the U.S. Geological Survey (Tewalt and others, 2005) is a cooperative project with about 50 countries (out of 70 coal-producing countries world-wide). The WoCQI initiative has collected and published extensive coal quality data from the world's largest coal producers and consumers. The important aspects of the WoCQI program are; (1) samples from active mines are collected, (2) the data have a high degree of internal consistency with a broad array of coal quality parameters, and (3) the data are linked to GIS and available through the world-wide-web. The coal quality parameters include proximate and ultimate analysis, sulfur forms, major-, minor-, and trace-element concentrations and various technological tests. This report contains geochemical data from a selected group of Indonesian coal samples from a range of coal types, localities, and ages collected for the WoCQI program.

Open-File Report↗
USGS2000

Growth in conventional fields in high-cost areas: A case study

Exploration managers commonly base future drilling decisions on past experience in an area. To do this well, they should consider both discovered and undiscovered resources to characterize total future potential. Discovery-size estimates should be adjusted to account for future field growth; otherwise, the relative efficiency of recent exploration will be undervalued. This study models and projects field growth for pre-1997 discoveries in the U.S. Federal Gulf of Mexico (GOM) Outer Continental Shelf (OCS). Projected additions to reserves for these fields from field growth through 2020 are 5.2 billion bbl of oil and 46 Tcfg. Projections include growth associated with sizable new oil discoveries in deepwater areas and initial reserve additions from new subsalt plays discovered through 1996. This article focuses on the U.S. GOM because it has produced longer than other worldwide offshore areas. Its field-growth profile may be prototypical of other offshore provinces such as the North Sea, Scotian Shelf and deepwater Angola, as well as high-cost onshore areas.

Gulf Of Mexico↗
USGS2022

Pore systems and organic petrology of cretaceous Mowry and Niobrara source-rock reservoirs, Powder River Basin, Wyoming, USA

The Powder River Basin (PRB) is a world-class oil province, in large part thanks to contributions from premier source rocks, Cretaceous Mowry and Niobrara shales. Both formations are also unconventional reservoirs. A critical aspect of evaluating production potential and finding sweet spots is the nature of the pore systems in these fine-grained source-rock reservoirs. Variation by stratigraphic interval is important for selecting optimum target zones for horizontal wells. Understanding variation in pore type, size, and connectivity and relationships with mineralogy and fabric help in determining prospectivity in different parts of the basin. Deciphering controls on pore-system development helps predict intervals and locations of optimum reservoir quality. Imaging of Niobrara and Mowry samples from a range of thermal maturities provided observations and data on pore systems, organic matter (OM) types and associations with mineralogy and fabric, wettability, and microporosity associated with both diagenetic and detrital clays. Imaging techniques included scanning electron microscopy, organic petrography and correlative scanning electron microscopy, and mapping of mineralogy through energy dispersive spectroscopy. Mean solid bitumen (BR o ) and vitrinite reflectance (VR o ) values indicate all samples are in the oil window with values ranging from 0.52 to 1.15%. Organic fluorescence is prominent in amorphous OM, solid bitumen and some vitrinite in the early oil window. The fluorescence is extinguished at higher thermal maturity. Carbonate pellets (in Niobrara) mainly contain migrated solid bitumen and residual live oil and little or no terrigenous OM (vitrinite and inertinite). However, terrigenous OM is common in siliceous/argillaceous laminae in both formations, where it occurs with amorphous OM, some of which has converted in situ to a solid bitumen petroleum residue. One key finding is the widespread presence of migrated OM at very early oil window maturity. Distribution of such OM and associated wettability alteration is fabric-controlled, at all levels of thermal maturity studied. Clay morphology and abundance and supporting rigid mineral grain framework strongly influence pore development, preservation, and connectivity in both formations. Carbonate content is a good proxy for reservoir quality in Niobrara intervals due to association of porous solid bitumen with calcareous fecal pellets. High recrystallized microquartz content is associated with the best reservoir intervals in the Mowry.

Wyoming↗