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At least 91 records · Page 5Linked to original sources
USGS2016

Geology of tight oil and potential tight oil reservoirs in the lower part of the Green River Formation, Uinta, Piceance, and Greater Green River Basins, Utah, Colorado, and Wyoming

The recent successful development of a tight oil play in the Eocene-age informal Uteland Butte member of the lacustrine Green River Formation in the Uinta Basin, Utah, using modern horizontal drilling and hydraulic fracturing techniques has spurred a renewed interest in the tight oil potential of lacustrine rocks. The Green River Formation was deposited by two large lakes, Lake Uinta in the Uinta and Piceance Basins and Lake Gosiute in the Greater Green River Basin. These three basins contain the world’s largest in-place oil shale resources with recent estimates of 1.53 trillion, 1.33 trillion, and 1.44 trillion barrels of oil in place in the Piceance, Uinta, and Greater Green River Basins, respectively. The Uteland Butte member was deposited during an early freshwater stage of the lake in the Uinta Basin prior to deposition of the assessed oil shale intervals. This report only presents information on the early freshwater interval and overlying brackish-water interval in all three basins because these intervals are most likely to have tight oil potential. Burial histories of the three basins were reconstructed to study (1) variations in subsidence and lake development, and (2) post deposition burial that led to the development of a petroleum system in only the Uinta Basin. The Uteland Butte member is a successful tight oil play because it is thermally mature for hydrocarbon generation and contains organic-rich shale, brittle carbonate, and porous dolomite. Abnormally high pressure in parts of the Uteland Butte is also important to production. Variations in organic richness of the Uteland Butte were studied using Fischer assay analysis from oil shale assessments, and pressures were studied using drill-stem tests. Freshwater lacustrine intervals in the Piceance and Greater Green River Basins are immature for hydrocarbon generation and contain much less carbonate than the Uteland Butte member. The brackish-water interval in the Uinta Basin is thermally mature for hydrocarbon generation but is clay-rich and contains little carbonate, and thus is a poor prospect for tight oil development.

Colorado, Utah, Wyoming↗
USGS1987

Prospects for heavy crude oil development

The problems of utilizing heavy crude oil and natural bitumens centre on their high viscosity which makes them difficult to produce, store, transport, and refine. These factors are reflected in costs. World reserves are substantial, however, perhaps as much as 7 trillion† barrels estimated to represent 0·9 trillion barrels of recoverable oil. Nearly 2·1 trillion barrels of heavy crude oil, more than 50% of the world's total reserve, are located in Venezuela largely in the Orinoco Oil Belt. About 75% of the natural bitumen, 2·6 trillion barrels, is located in Canada in the Athabasca, Cold Lake, and Peace River areas of Alberta. Most of the estimated undiscovered heavy crude oil in the world, approximately 630 billion barrels, is outside the US and Canada. Data required to determine the cost of finding natural bitumen and heavy oil are roughly the same as for other mineral commodities. Similarly for recovery costs. The variables are so extensive that dollar amounts have little meaning without qualification. Recovery depends on depth below surface. Near-surface deposits are recovered by mechanical mining. Deeper deposits must be won by thermal means. Transportation by pipeline is feasible only if the viscosity is lowered by partial upgrading, heating, or by the use of diluents. Part of the high cost of refining results from the major investment required for the large installations that are needed for economic rates of production.

Energy Exploration & Exploitation↗
USGS1999

The Niger Delta petroleum system; Niger Delta Province, Nigeria, Cameroon, and equatorial Guinea, Africa

In the Niger Delta province, we have identified one petroleum system--the Tertiary Niger Delta (Akata-Agbada) petroleum system. The delta formed at the site of a rift triple junction related to the opening of the southern Atlantic starting in the Late Jurassic and continuing into the Cretaceous. The delta proper began developing in the Eocene, accumulating sediments that now are over 10 kilometers thick. The primary source rock is the upper Akata Formation, the marine-shale facies of the delta, with possibly contribution from interbedded marine shale of the lowermost Agbada Formation. Oil is produced from sandstone facies within the Agbada Formation, however, turbidite sand in the upper Akata Formation is a potential target in deep water offshore and possibly beneath currently producing intervals onshore. Known oil and gas resources of the Niger Delta rank the province as the twelfth largest in the world. To date, 34.5 billion barrels of recoverable oil and 93.8 trillion cubic feet of recoverable gas have been discovered. In 1997, Nigeria was the fifth largest crude oil supplier to the United States, supplying 689,000 barrels/day of crude.

Open-File Report↗
USGS2017

Production and disposal of waste materials from gas and oil extraction from the Marcellus Shale Play in Pennsylvania

The increasing world demand for energy has led to an increase in the exploration and extraction of natural gas, condensate, and oil from unconventional organic-rich shale plays. However, little is known about the quantity, transport, and disposal method of wastes produced during the extraction process. We examined the quantity of waste produced by gas extraction activities from the Marcellus Shale play in Pennsylvania for 2011. The main types of wastes included drilling cuttings and fluids from vertical and horizontal drilling and fluids generated from hydraulic fracturing [i.e., flowback and brine (formation) water]. Most reported drill cuttings (98.4%) were disposed of in landfills, and there was a high amount of interstate (49.2%) and interbasin (36.7%) transport. Drilling fluids were largely reused (70.7%), with little interstate (8.5%) and interbasin (5.8%) transport. Reported flowback water was mostly reused (89.8%) or disposed of in brine or industrial waste treatment plants (8.0%) and largely remained within Pennsylvania (interstate transport was 3.1%) with little interbasin transport (2.9%). Brine water was most often reused (55.7%), followed by disposal in injection wells (26.6%), and then disposed of in brine or industrial waste treatment plants (13.8%). Of the major types of fluid waste, brine water was most often transported to other states (28.2%) and to other basins (9.8%). In 2011, 71.5% of the reported brine water, drilling fluids, and flowback was recycled: 73.1% in the first half and 69.7% in the second half of 2011. Disposal of waste to municipal sewage treatment plants decreased nearly 100% from the first half to second half of 2011. When standardized against the total amount of gas produced, all reported wastes, except flowback sands, were less in the second half than the first half of 2011. Disposal of wastes into injection disposal wells increased 129.2% from the first half to the second half of 2011; other disposal methods decreased. Some issues with data were uncovered during the analytical process (e.g., correct geospatial location of disposal sites and the proper reporting of end use of waste) that obfuscated the analyses; correcting these issues will help future analyses.

Pennsylvania↗
USGS1998

Maps showing geology, oil and gas fields and geologic provinces of the Arabian Peninsula

Introduction This digital map compilation, which includes geology, geologic provinces, and oil and gas fields of the Arabian Peninsula, is part of a map series of the world produced by the U.S. Geological Survey World Energy Project. The goal of the project is to produce a worldwide assessment of the undiscovered, technically recoverable oil and gas resources and report these results by the year 2000. To assess the world's petroleum, a sequence of steps is being undertaken proceeding from defining geologic provinces of the world at a comparable scale, allocating oil and gas fields to these provinces, defining petroleum systems within these provinces, and ultimately assessing the undiscovered petroleum potential of selected provinces of the world. A more in-depth discussion of the geologic provinces and their relative ranking in terms of total known petroleum volume is given in USGS Open File Report 97-463 (see Klett and others, 1997).

Open-File Report↗
USGS2007

Statistics of petroleum exploration in the world outside the United States and Canada through 2001

Future oil and gas supplies depend, in part, on the reserves that are expected to be added through exploration and new discoveries. This Circular presents a summary of the statistics and an analysis of petroleum exploration in the world outside the United States and Canada (the study area) through 2001. It updates U.S. Geological Survey Circular 1096 (by E.D. Attanasi and D.H. Root, 1993) and expands coverage of the statistics to areas where drilling and discovery data have recently become available. These new areas include China, the formerly Communist countries of Eastern Europe, and the countries that once were part of the former Soviet Union in Europe and Asia. Data are presented by country but are organized by petroleum provinces delineated by the U.S. Geological Survey World Energy Assessment Team (USGS Digital Data Series DDS?60, published in 2000). The data and analysis are presented in maps and graphs, providing a visual summary of the exploration maturity of an area. The maps show the delineated prospective areas and explored areas through 2001; explored areas have a drilling density that would rule out the occurrence of undetected large petroleum accumulations. Graphs summarize the exploration yields in terms of cumulative recoverable discovered oil and gas by delineated prospective area. From 1992 through 2001 in areas outside the United States and Canada, the delineated prospective area expanded at a rate of about 50,000 square miles per year while the explored area grew at the rate of about 11,000 square miles per year. The delineated prospective area established by 1970 contains about 75 percent of the oil discovered to date in the study area. This area is slightly less than 40 percent of the delineated prospective area established through 2001. Maps and graphs show the extension of the delineated prospective area to deepwater areas offshore of Brazil and West Africa. From 1991 through 2000, offshore discoveries accounted for 59 percent of the oil and 77 percent of the gas discovered in the study area. The petroleum industry's decision to incur the greater costs of moving offshore and into deeper waters appears to be a response to the absence of onshore prospects of comparable quality. Where natural gas can be commercially developed and marketed, data show an expansion of exploration to target gas-prone areas.

Circular↗
USGS1985

Fluorine in Colorado oil shale

Oil shale from the lower part of the Eocene Green River Formation in the Piceance Creek Basin, Colorado, averages 0.13 weight percent fluorine, which is about twice that found in common shales, but is the same as the average amount found in some oil shales from other parts of the world. Some fluorine may reside in fluorapatite; however, limited data suggest that cryolite may be quantitatively more important. Analysis of 913 samples from two core holes that penetrate the lower 375 m of the oil-shale deposits found fluorine to range from 0.001 to 2.2 weight percent; about 90 percent of the samples con tain between 0.001 and 0.20 weight percent fluorine. The analyzed sequence consists of mostly nahcolitebearing dolomitic oil shale, except for the lower 55-75 m, which consists of illitic oil shale. The fluorine content of much of the nahcolitic oil shale is somewhat lower, and much more variable from sample to sample, than that of the underlying illitic oil shale. Vertical profiles of the fluo rine content for the two core holes through the same stratigraphic interval are essentially dissimilar. The abundance of fluorine seems unrelated to shaleoil content, except in the R-5 zone and near the base of nahcolite-bearing oil shale where there is a moderate positive association. Fluorine and phos phorus abundances show mostly little or no assoc iation, and only moderate positive association in some scattered samples.

Colorado↗
USGS2005

An evaluation of the U.S. Geological Survey World Petroleum Assessment 2000

This study compares the additions to conventional crude oil and natural gas reserves as reported from January 1996 to December 2003 with the estimated undiscovered and reserve-growth volumes assessed in the U.S. Geological Survey World Petroleum Assessment 2000, which used data current through 1995. Approximately 28% of the estimated additions to oil reserves by reserve growth and approximately 11% of the estimated undiscovered oil volumes were realized in the 8 yr since the assessment (27% of the time frame for the assessment). Slightly more than half of the estimated additions to gas reserves by reserve growth and approximately 10% of the estimated undiscovered gas volumes were realized. Between 1995 and 2003, growth of oil reserves in previously discovered fields exceeded new-field discoveries as a source of global additions to reserves of conventional oil by a ratio of 3:1. The greatest amount of reserve growth for crude oil occurred in the Middle East and North Africa, whereas the greatest contribution from new-field discoveries occurred in sub-Saharan Africa. The greatest amount of reserve growth for natural gas occurred in the Middle East and North Africa, whereas the greatest contribution from new-field discoveries occurred in the Asia Pacific region. On an energy-equivalent basis, volumes of new gas-field discoveries exceeded new oil-field discoveries. Copyright ?? 2005. The American Association of Petroleum Geologists. All rights reserved.

American Association of Petroleum Geologists Bulle↗
USGS2025

Machine learning provides reconnaissance-type estimates of carbon dioxide storage resources in oil and gas reservoirs

Oil and gas reservoirs represent suitable containers to sequester carbon dioxide (CO 2 ) in a supercritical state because they are accessible, reservoir properties are known, and they previously contained stored buoyant fluids. However, planners must quantify the relative magnitude of the CO 2 storage resource in these reservoirs to formulate a comprehensive strategy for CO 2 mitigation. Even reconnaissance-type estimates of CO 2 storage resources of known oil and gas reservoirs may require complicated calculations involving 1) estimates of recoverable oil and gas, 2) reservoir properties (depth, temperature, pressure, etc.), and 3) the physical qualities of the retained fluids. We demonstrate the application of machine learning (ML) algorithms to bypass these computations to yield more rapid estimates of CO 2 storage resources in reservoirs capable of hosting CO 2 in a supercritical state. ML algorithms are computationally efficient because they do not impose the strong assumptions on the data-generating process that standard statistical or engineering procedures require. Further, ML algorithms can capture highly complex, particularly nonlinear, relationships among predictor variables. We demonstrate the application of four different ML algorithms using data from onshore and offshore oil and gas reservoirs in Europe, and show they perform well when predictions are compared to engineering estimates. The proposed methods and models provide an effective and novel way to more rapidly and directly determine the subsurface CO 2 storage capacity of oil and gas reservoirs around the world, information that operators, researchers, and policymakers alike require to meet energy transition and decarbonization goals.

Frontiers in Enviornmental Science↗
USGS1998

Maps showing geology, oil and gas fields and geological provinces of Africa

The CD-ROM was compiled according to the methodology developed by the U.S. Geological Survey's World Energy Project . The goal of the project was to assess the undiscovered, technically recoverable oil and gas resources of the world and report these results by the year 2000. A worldwide series of geologic maps, published on CD-ROMs, was released by the U.S. Geological Survey's World Energy Project during 1997-2000. Specific details of the data sources and map compilation are given in the metadata files on this CD-ROM. These maps were compiled using Environmental Systems Research Institute Inc. (ESRI) ARC/INFO software. Political boundaries and cartographic representations on this map are shown (with permission) from ESRI's ArcWorld 1:3M digital coverage: they have no political significance and are displayed as general reference only. Portions of this database covering the coastline and country boundaries contain proprietary property of ESRI. (Copyright 1992 and 1996, Environmental Systems Research Institute Inc. All rights reserved.)

Open-File Report↗
USGS2005

Future petroleum supply - exploration or development?

The presentation is titled 'Future Petroleum Supply - Exploration or Development?' and provides a general overview of the magnitude and significance of reserve growth around the world. Reserve growth is defined as the increase in successive estimates of recoverable crude oil, natural gas, and natural-gas liquids and condensates in discovered fields. Analysis of recent exploration and production data shows that petroleum (both crude oil and natural gas) volumes added to reserves by reserve growth in the world are comparable to, if not greater than, the volumes added by new-field discoveries. This presentation describes the examination of recoverable volumes of crude oil in 186 giant oil fields (excluding those of the United States (U.S.) and Canada) reported through time from 1981 to 2003 and describes a comparison of the successive increases in these volumes (reserve growth) with recoverable volumes added from new-field discoveries. Examples from the ongoing USGS study of reserve growth in the North Sea also are shown in this presentation.

Open-File Report↗
USGS1998

Maps showing geology, oil and gas fields and geologic provinces of South Asia

Introduction This digitally compiled map includes petroleum geology, geologic provinces, and oil and gas fields of South Asia. The map is part of a worldwide series released by the U. S. Geological Survey World Energy Project. The goal of the project is to assess the undiscovered, technically recoverable oil and gas resources of the world and report these results by the year 2000. For data management purposes the world was divided into eight energy regions corresponding approximately to the economic regions of the world as defined by the U.S. Department of State. South Asia (Region 8) is represented on this CD-ROM (see Reference Map), and includes Afghanistan, Bangladesh, Bhutan, India, Myanmar, Nepal, Pakistan, and Sri Lanka.

Open-File Report↗
USGS2006

Geology and total petroleum systems of the West-Central Coastal province (7203), West Africa

The West-Central Coastal Province of the Sub-Saharan Africa Region consists of the coastal and offshore areas of Cameroon, Equatorial Guinea, Gabon, Democratic Republic of the Congo, Republic of the Congo, Angola (including the disputed Cabinda Province), and Namibia. The area stretches from the east edge of the Niger Delta south to the Walvis Ridge. The West-Central Coastal Province includes the Douala, Kribi-Campo, Rio Muni, Gabon, Congo, Kwanza, Benguela, and Namibe Basins, which together form the Aptian salt basin of equatorial west Africa. The area has had significant exploration for petroleum; more than 295 oil fields have been discovered since 1954. Since 1995, several giant oil fields have been discovered, especially in the deep-water area of the Congo Basin. Although many total petroleum systems may exist in the West-Central Coastal Province, only four major total petroleum systems have been defined. The area of the province north of the Congo Basin contains two total petroleum systems: the Melania-Gamba Total Petroleum System, consisting of Lower Cretaceous source and reservoir rocks, and the Azile-Senonian Total Petroleum System, consisting of Albian to Turonian source rocks and Cretaceous reservoir rocks. Two assessment units are defined in the West-Central Coastal Province north of the Congo Basin: the Gabon Subsalt and the Gabon Suprasalt Assessment Units. The Congo Basin contains the Congo Delta Composite Total Petroleum System, consisting of Lower Cretaceous to Tertiary source and reservoir rocks. The Central Congo Delta and Carbonate Platform and the Central Congo Turbidites Assessment Units are defined in the Congo Delta Composite Total Petroleum System. The area south of the Congo Basin contains the Cuanza Composite Total Petroleum System, consisting of Lower Cretaceous to Tertiary source and reservoir rocks. The Cuanza-Namibe Assessment Unit is defined in the Cuanza Composite Total Petroleum System. The U.S. Geological Survey (USGS) assessed the potential for undiscovered conventional oil and gas resources in this province as part of its World Petroleum Assessment 2000. The USGS estimated a mean of 29.7 billion barrels of undiscovered conventional oil, 88.0 trillion cubic feet of gas, and 4.2 billion barrels of natural gas liquids. Most of the hydrocarbon potential remains in the offshore waters of the province in the Central Congo Turbidites Assessment Unit. Large areas of the offshore parts of the Kwanza, Douala, Kribi-Campo, and Rio Muni Basins are underexplored, considering their size, and current exploration activity suggests that the basins have hydrocarbon potential. Since about 1995, the offshore part of the Congo Basin has become a major area for new field discoveries and for hydrocarbon exploration, and many deeper water areas in the basin have excellent hydrocarbon potential. Gas resources may be significant and accessible in areas where the zone of oil generation is relatively shallow.

Bulletin↗
USGS1994

The space-time structure of oil and gas field growth in a complex depositional system

Shortly after the discovery of an oil and gas field, an initial estimate is usually made of the ultimate recovery of the field. With the passage of time, this initial estimate is almost always revised upward. The phenomenon of the growth of the expected ultimate recovery of a field, which is known as "field growth," is important to resource assessment analysts for several reasons. First, field growth is the source of a large part of future additions to the inventory of proved reserves of crude oil and natural gas in most petroliferous areas of the world. Second, field growth introduces a large negative bias in the forecast of the future rates of discovery of oil and gas fields made by discovery process models. In this study, the growth in estimated ultimate recovery of oil and gas in fields made up of sandstone reservoirs formed in a complex depositional environment (Frio strand plain exploration play) is examined. The results presented here show how the growth of oil and gas fields is tied directly to the architectural element of the shoreline processes and tectonics that caused the deposition of the individual sand bodies hosting the producible hydrocarbon. ?? 1994 Oxford University Press.

Nonrenewable Resources↗
USGS2018

Geology and assessment of undiscovered oil and gas resources of the Northern West Siberian Mesozoic Composite Total Petroleum System of the West Siberian Basin Province, Russia, 2008

The West Siberian Basin Province is one of the largest sedimentary basins in the world, with an area of 2.6 million square kilometers, and the basin ranks first in the world with more than 400 billion barrels of oil-equivalent discovered petroleum. For the 2008 Circum-Arctic Resource Appraisal, the U.S. Geological Survey defined a Northern West Siberian Mesozoic Composite Total Petroleum System (TPS) and two geologic assessment unit (AUs) within this composite TPS that are north or partially north of the Arctic Circle. The Northern West Siberian Onshore Gas AU was defined to encompass all potential structures, traps, and reservoirs in the onshore part of the Composite TPS. The South Kara Sea Offshore AU was defined to include all potential structures, traps, and reservoirs within the thick sedimentary section that extends offshore from the Northern West Siberian Onshore Gas AU. For the Northern West Siberian Mesozoic Composite TPS, the total mean estimates for undiscovered conventional oil and gas resources are 4.1 billion barrels of oil (BBO), 663 trillion cubic feet of gas (TCFG), and 20.7 billion barrels of natural gas liquids (BBNGL). For areas of the AUs north of the Arctic Circle in the West Siberian Basin Province, the total mean estimates for undiscovered conventional resources are 3.7 BBO, 651 TCFG, and 20.3 BBNGL. The total mean estimates for undiscovered oil and gas north of the Arctic Circle for the Northern West Siberian Onshore Gas AU are 1.2 BBO, 29.3 TCFG, and 0.85 BBNGL. Mean estimates for the South Kara Sea Offshore AU are 2.5 BBO, 622.2 TCFG, and 19.5 BBNGL. The estimate for undiscovered conventional gas resources for the South Kara Sea Offshore AU is the most of any AU in the Circum-Arctic study.

West Siberian Basin Province↗
USGS2006

Map showing geology, oil and gas fields, and geologic provinces of the Gulf of Mexico region

This map was created as part of a worldwide series of geologic maps for the U.S. Geological Survey’s World Energy Project, available on CD-ROM and through the Internet. The goal of the project is to assess the undiscovered, technically recoverable oil and gas resources of the world. Geologic provinces were created for ranking purposes in the World Petroleum Assessment 2000 (U.S. Geological Survey World Energy Assessment Team, 2000). A modified subset of these provinces are shown on the map, based on new bathymetric data and geologic knowledge. Geologic province boundaries are not intended to be taken for country boundaries or exclusive economic zone (EEZ) boundaries. The USGS World Petroleum Assessment 2000 - Description and Results can be found online at: http://pubs.usgs.gov/dds/dds-060 . Oil and gas fields are represented by a single geographic point in the center of the field and displays field type (oil or gas) only. The map includes three surface geology datasets, which were modified for display purposes.

Open-File Report↗
USGS2011

Networks - The assessment of marine reserve networks: Guidelines for ecological evaluation

As marine ecosystems are plagued by an ever-increasing suite of threats including climate change, pollution, habitat degradation, and fisheries impacts (Roessig et al ., 2004; Lotze et al ., 2006; Jackson, 2008), there are now no ocean areas that are exempt from anthropogenic impacts (Halpern et al ., 2008). In order to preserve marine biodiversity, ecosystem function, and the goods and services provided by resistant and/or resilient systems, marine reserves have been increasingly recommended as part of an ecosystem-based approach to management (Browman and Stergiou, 2004; Levin et al ., 2009). Marine reserves are defined as “areas of the ocean completely protected from all extractive and destructive activities” (Lubchenco et al ., 2003) and can be experimental controls for evaluating the impact of these activities on marine ecosystems. Growing scientific information has shown consistent increases in species density, biomass, size, and diversity in response to full protection inside reserves of varying sizes and ages located in diverse regions (Claudet et al ., 2008; Lester et al ., 2009; Molloy et al ., 2009). However, most of these data are from individual marine reserves and therefore have inherently limited transferability to networks of marine reserves, which when properly designed can outperform single marine reserves for a variety of ecological, economic, and social management goals (Roberts et al ., 2003; Almany et al ., 2009; Gaines et al ., 2010). The concept of marine reserve networks grew out of a desire to achieve both conservation and fishery management goals by minimizing the potential negative economic, social, and cultural impacts of a single large reserve while still producing similar or even greater ecological and economic returns (Murray et al ., 1999; Gaines et al ., 2010). In addition, reserves networks can provide insurance by protecting areas across a region and spreading the risk that these sites may be impacted by localized catastrophes such as hurricanes or oil spills (Allison et al ., 2003). The World Conservation Union's Marine Programme defines a network as “a collection of individual marine protected areas (MPAs) or reserves operating co-operatively and synergistically, at various spatial scales and with a range of protection levels that are designed to meet objectives that a single reserve cannot achieve” (IUCN–WCPA, 2008). However, general terms such as “co-operatively” and “synergistically” can have myriad meanings. Without a clear definition of a network, it becomes difficult to identify attainable management goals and design a process for evaluating whether the network achieves those goals. Besides, different management goals may in turn result in the need for different types of networks. The use of MPAs with varying protection levels together with no-take zones in multiple-zoning schemes adds another layer of complexity to network design and evaluation; however, partially protected areas are generally used to manage coastal uses and avoid conflicts (rather than for strict ecological purposes) and are therefore a function of the local social, economic, and cultural context. As we are here interested in the ecological effects of networks, for the purposes of this chapter, we focus on marine reserves because these areas are no-take and therefore offer greater ecological benefits than other types of MPAs that allow some forms of extraction (Lester and Halpern, 2008).

Book chapter↗
USGS2002

Petroleum systems of the Malay Basin Province, Malaysia

The offshore Malay Basin province is a Tertiary oil and gas province composed of a complex of half grabens that were filled by lacustrine shales and continental clastics.These deposits were overlain by clastics of a large delta system that covered the basin.Delta progradation was interupted by transgressions of the South China Sea to the southeast, which finally flooded the basin to form the Gulf of Thailand.Oil and gas from the Oligocene to Miocene lacustrine shales and Miocene deltaic coals is trapped primarily in anticlines formed by inversion of the half grabens during the late Miocene.Hydrocarbon reserves that have been discovered amount to 12 billion barrels of oil equivalent.The U.S. Geological Survey assessment of the estimated quantities of conventional oil, gas and condensate that have the potential to be added to reserves by the year 2025 for this province is 6.3 billion barrels of oil equivalent (BBOE) (U. S. Geological Survey World Energy Assessment Team, 2000).

Basin Province↗