Geology topics
Publications and source records attributed to Timothy R. Klett.
Using a geology-based assessment methodology, the U.S. Geological Survey estimated undiscovered, technically recoverable mean resource of 44.5 trillion cubic feet of shale gas in the Karoo Province of South Africa and Lesotho, Africa.
Using a geology-based assessment methodology, the U.S. Geological Survey assessed mean resources of 5 trillion cubic feet of gas and 187 million barrels of natural gas liquids in tight-gas assessment units in the Canyon sandstones of the Val Verde Basin, Texas.
The U.S. Geological Survey (USGS) completed a geology-based assessment of the continuous (unconventional) oil and gas resources in the Late Cretaceous Mancos Shale within the Piceance Basin of the Uinta-Piceance Province (fig. 1). The previous USGS assessment of the Mancos Shale in the Piceance Basin was completed in 2003 as part of a comprehensive assessment of the greater UintaPiceance Province (U.S. Geological Survey Uinta-Piceance Assessment Team, 2003). Since the last assessment, more than 2,000 wells have been drilled and completed in one or more intervals within the Mancos Shale of the Piceance Basin (IHS Energy Group, 2015). In addition, the USGS Energy Resources Program drilled a research core in the southern Piceance Basin that provided significant new geologic and geochemical data that were used to refine the 2003 assessment of undiscovered, technically recoverable oil and gas in the Mancos Shale.
Using a geology-based assessment methodology, the U.S. Geological Survey estimated mean conventional resources of 68 million barrels of oil and 964 billion cubic feet of gas in the Cooper and Eromanga Basins of Australia.
Using a geology-based assessment methodology, the U.S. Geological Survey estimated undiscovered, technically recoverable mean resources of 160 million barrels of conventional oil, 1,880 billion cubic feet of conventional gas, 602 million barrels of shale oil, and 6,395 billion cubic feet of shale gas in the Taoudeni Basin Province in Mali and Mauritania.
Using a geology-based assessment methodology, the U.S. Geological Survey assessed undiscovered, technically recoverable mean resources of 787 billion cubic feet of conventional gas and 1,630 billion cubic feet of unconventional gas in the Thrace Basin, Turkey.
Using a geology-based assessment methodology, the U.S. Geological Survey estimated mean resources of 28 trillion cubic feet of tight gas and 5.6 trillion cubic feet of coalbed gas in upper Paleozoic rocks in the Ordos Basin Province, China.
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.
Using a geology-based assessment methodology, the U.S. Geological Survey estimated mean volumes of 53 trillion cubic feet of shale gas, 172 million barrels of shale oil, and 176 million barrels of natural gas liquids in the Barnett Shale of the Bend Arch–Fort Worth Basin Province of Texas.
Using a geology-based assessment methodology, the U.S. Geological Survey estimated means of 459 million barrels of shale oil, 275 billion cubic feet of associated gas, and 23 million barrels of natural gas liquids in the Central Sumatra Basin, Indonesia.
Using a geology-based assessment methodology, the U.S. Geological Survey estimated a mean of 23.9 trillion cubic feet of technically recoverable shale gas resources in Paleozoic formations in the Sichuan Basin of China.
Using a geology-based assessment methodology, the U.S. Geological Survey assessed mean volumes of 21 million barrels of oil (MMBO), 27 billion cubic feet of gas, and 1 million barrels of natural gas liquids in two assessment units (AUs) that may contain continuous oil resources. Mean volumes of oil for the individual assessment units are 14 MMBO in the Monterey Buttonwillow AU and 7 MMBO in the Monterey Maricopa AU.
Using a geology-based assessment methodology, the U.S. Geological Survey estimated mean undiscovered resources of 214 million barrels of oil, 329 billion cubic feet of associated/dissolved natural gas, and 14 million barrels of natural gas liquids in the informal Uteland Butte member of the Green River Formation, Uinta Basin, Utah.
Using a geology-based assessment methodology, the U.S. Geological Survey estimated mean volumes of undiscovered, technically recoverable resources of 463 million barrels of oil, 11.2 trillion cubic feet of gas, and 35 million barrels of natural gas liquids in the Cherokee Platform Province area of Kansas, Oklahoma, and Missouri.
Using a geology-based assessment methodology, the U.S. Geological Survey estimated undiscovered mean volumes of 14 million barrels of conventional oil, 430 billion cubic feet of conventional gas, 34,028 billion cubic feet of continuous gas, and a mean total of 391 million barrels of natural gas liquids in sandstone reservoirs of the Upper Jurassic–Lower Cretaceous Cotton Valley Group in onshore lands and State waters of the U.S. Gulf Coast region.
A geologic model was developed for the assessment of potential Mesozoic tight-gas resources in the deep, central part of upper Cook Inlet Basin, south-central Alaska. The basic premise of the geologic model is that organic-bearing marine shales of the Middle Jurassic Tuxedni Group achieved adequate thermal maturity for oil and gas generation in the central part of the basin largely due to several kilometers of Paleogene and Neogene burial. In this model, hydrocarbons generated in Tuxedni source rocks resulted in overpressure, causing fracturing and local migration of oil and possibly gas into low-permeability sandstone and siltstone reservoirs in the Jurassic Tuxedni Group and Chinitna and Naknek Formations. Oil that was generated either remained in the source rock and subsequently was cracked to gas which then migrated into low-permeability reservoirs, or oil initially migrated into adjacent low-permeability reservoirs, where it subsequently cracked to gas as adequate thermal maturation was reached in the central part of the basin. Geologic uncertainty exists on the (1) presence of adequate marine source rocks, (2) degree and timing of thermal maturation, generation, and expulsion, (3) migration of hydrocarbons into low-permeability reservoirs, and (4) preservation of this petroleum system. Given these uncertainties and using known U.S. tight gas reservoirs as geologic and production analogs, a mean volume of 0.64 trillion cubic feet of gas was assessed in the basin-center tight-gas system that is postulated to exist in Mesozoic rocks of the upper Cook Inlet Basin. This assessment of Mesozoic basin-center tight gas does not include potential gas accumulations in Cenozoic low-permeability reservoirs.
In 2004, the U.S. Geological Survey (USGS) completed an assessment of the undiscovered oil and gas potential of the U.S. portion of the Michigan Basin. For this assessment, the Michigan Basin includes most of the State of Michigan, as well as parts of Illinois, Indiana, Minnesota, Ohio, and Wisconsin. The assessment was based on the geologic elements of each of the six total petroleum systems defined in the basin, including (1) hydrocarbon source rocks (source-rock maturation and hydrocarbon generation and migration), (2) reservoir rocks (sequence stratigraphy and petrophysical properties), and (3) hydrocarbon traps (trap formation and timing). Using this geologic framework, the USGS estimated mean technically recoverable undiscovered continuous and conventional resources that total 990 million barrels of oil, 11.4 trillion cubic feet of natural gas, and 219 million barrels of natural gas liquids. Digital Data Series 69-T (DDS-69-T) is cataloged in the Pubs Warehouse as Data Series 69-T (DS-69-T).
The U.S. Geological Survey (USGS) quantitatively assessed the potential for unconventional (continuous) oil and gas resources within the Jurassic Sargelu Formation of Iraq. Organic-rich shales of the Jurassic Sargelu Formation are one of the main petroleum source rocks for conventional fields in the Arabian Peninsula. The Sargelu Formation consists of marine shales, with as much as 10 weight percent sulfur-rich Type IIS organic matter, deposited in a relatively deep, anoxic Jurassic depocenter. The potential for volumes of oil retained in the Sargelu Formation source-reservoir rock system following oil migration, cracking, or degradation is the focus of this assessment. Conventional oil and gas resources of Iraq were assessed by the USGS in 2012. The USGS assessment methodology consists of a well-performance approach that recognizes the geologic variability within assessed reservoirs. For non-U.S. assessments, the USGS assesses shale-gas or shale-oil reservoirs that (1) contain greater than 2 weight percent total organic carbon (TOC), (2) are within the proper thermal maturity window for oil or gas generation, (3) have greater than 15-m thickness of organic-rich shale, and (4) contain Type I or II organic matter. These specific USGS criteria when applied to any given shale-oil or shale-gas reservoir might significantly reduce the potential resource assessment area compared to maps made with greater than 1 weight percent TOC.