Marilyn E. Tennyson

Assessment of undiscovered oil and gas in the Arctic.

Arctic Energy Reserves The Arctic consists of approximately equal fractions of terrain above sea level, continental shelves with depths less than 500 meters, and deep ocean basins that have been mostly covered in ice. While the deep ocean regions probably have limited petroleum reserves, the shelf areas are likely to contain abundant ones. Based on the limited amount of exploration data available, Gautier et al. (p. 1175) have constructed a probabilistic, geology-based estimate of how much oil and gas may be found. Approximately 30% of the worlds undiscovered gas, and 13% of its undiscovered oil, may be found north of the Arctic Circle. Advances in the technology of hydrocarbon recovery, as well as vanishing ice cover around the North Pole, make the Arctic an increasingly attractive region for energy source development, although the existing reserves are probably not large enough to shift current production patterns significantly. About 30 percent of the world’s undiscovered gas and 13 percent of the world’s undiscovered oil probably exist north of the Arctic Circle. 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.

Chapter 43 Assessment of NE Greenland: prototype for development of Circum-Arctic Resource Appraisal methodology

Abstract Geological features of NE Greenland suggest large petroleum potential, as well as high uncertainty and risk. The area was the prototype for development of methodology used in the US Geological Survey (USGS) Circum-Arctic Resource Appraisal (CARA), and was the first area evaluated. In collaboration with the Geological Survey of Denmark and Greenland (GEUS), eight ‘assessment units’ (AU) were defined, six of which were probabilistically assessed. The most prospective areas are offshore in the Danmarkshavn Basin. This study supersedes a previous USGS assessment, from which it differs in several important respects: oil estimates are reduced and natural gas estimates are increased to reflect revised understanding of offshore geology. Despite the reduced estimates, the CARA indicates that NE Greenland may be an important future petroleum province.

Chapter 9: Oil and gas resource potential north of the Arctic Circle

Abstract The US Geological Survey recently assessed the potential for undiscovered conventional petroleum in the Arctic. Using a new map compilation of sedimentary elements, the area north of the Arctic Circle was subdivided into 70 assessment units, 48 of which were quantitatively assessed. The Circum-Arctic Resource Appraisal (CARA) was a geologically based, probabilistic study that relied mainly on burial history analysis and analogue modelling to estimate sizes and numbers of undiscovered oil and gas accumulations. The results of the CARA suggest the Arctic is gas-prone with an estimated 770–2990 trillion cubic feet of undiscovered conventional natural gas, most of which is in Russian territory. On an energy-equivalent basis, the quantity of natural gas is more than three times the quantity of oil and the largest undiscovered gas field is expected to be about 10 times the size of the largest undiscovered oil field. In addition to gas, the gas accumulations may contain an estimated 39 billion barrels of liquids. The South Kara Sea is the most prospective gas assessment unit, but giant gas fields containing more than 6 trillion cubic feet of recoverable gas are possible at a 50% chance in 10 assessment units. Sixty per cent of the estimated undiscovered oil resource is in just six assessment units, of which the Alaska Platform, with 31% of the resource, is the most prospective. Overall, the Arctic is estimated to contain between 44 and 157 billion barrels of recoverable oil. Billion barrel oil fields are possible at a 50% chance in seven assessment units. Undiscovered oil resources could be significant to the Arctic nations, but are probably not sufficient to shift the world oil balance away from the Middle East.

Assessment of undiscovered conventional oil and gas resources in the Wyoming Thrust Belt Province, Wyoming, Idaho, and Utah, 2017

The U.S. Geological Survey (USGS) quantitatively assessed the potential for undiscovered, technically recoverable conventional oil and gas resources in the Wyoming Thrust Belt Province, which is located west of the Southwestern Wyoming Province, east of the Eastern Great Basin Province, south of the Idaho-Snake River Downwarp Province, and north of the Uinta-Piceance Basin Province (fig. 1). The Wyoming Thrust Belt developed by east-directed compression associated with steeply dipping subduction during the Late Jurassic to Late Cretaceous Sevier Orogeny (Lamerson, 1982; Webel, 1987). Compression resulted in a series of stacked thrust sheets that are progressively younger in age to the east. The major thrusts in the Wyoming Thrust Belt Province are the Paris-Willard, Meade, Crawford, Absaroka, Hogsback-Darby, and Prospect (fig. 1). Exploration in the mid-1970s resulted in the discovery of more than 30 oil and gas fields, most of which are associated with the Absaroka thrust sheet. Compared to the Absaroka, exploration along the other thrust sheets has been largely unsuccessful. The temporal sequence of thrust loading and structural deformation has resulted in a complex evolution of petroleum systems in the Wyoming Thrust Belt Province (Warner, 1982; Edman and Surdam, 1984; Burtner and Nigrini, 1994).

Assessment of undiscovered oil and gas resources in the North-Central Montana Province, 2017

The U.S. Geological Survey (USGS) quantitatively assessed the potential for undiscovered, technically recoverable conventional and continuous (unconventional) oil and gas resources in the North-Central Montana Province (fig. 1). The geologic evolution of the province is the result of a series of tectonic events that affected the western margin of North America (Petersen, 1986; Anna and others, 2011). These events include (1) the development of Neoproterozoic rifts and a regional lineament system; (2) an early to middle lower Paleozoic passive margin (Cambrian–Silurian); (3) the east–west trending central Montana trough coeval with the development of the Williston Basin (Petersen, 1986; Maughan, 1989); (4) Late Devonian through Mississippian subduction and compression during the Antler orogenic event; (5) Pennsylvanian uplift and erosion related to the Ouachita event; (6) Jurassic to Early Cretaceous high-angle subduction and compression during the

Assessment of undiscovered oil and gas resources in the Akita Basin Province, Japan, 2018

The U.S. Geological Survey (USGS) quantitatively assessed the potential for undiscovered, technically recoverable conventional and continuous (unconventional) oil and gas resources in the Akita Basin Province of Japan (fig. 1). The tectonic evolution of the Japan arc and the Sea of Japan is well known and forms the basis for the development of the Miocene petroleum system assessed here (Okamura and others, 1995; Wakita, 2013; Van Horne and others, 2017). The Akita Basin is part of a back-arc basin along the western margin of the volcanic Japan arc. Prior to about 30 mega-annum (Ma), the Japan arc was located on the eastern margin of the Eurasian terrane. Regional extension in the Oligocene began about 30 Ma, perhaps driven by trench roll-back forces, creating a series of grabens and horsts in the back arc, effectively separating the Japan arc from Eurasia. Following a regional transgression in the Miocene, deep-water conditions prevailed, and many of the grabens were filled with siliceous, organic-rich shales; tuffaceous sandstones; and volcanic rocks. Extension ceased by about 15 Ma, and post-rift thermal sag led to further deposition and thermal maturation of source rocks. Beginning in the Pliocene, a major phase of compression resulted in the inversion of many grabens, and petroleum generated from siliceous shales migrated into these structures. As inversion may have caused loss of seal integrity, some of the oil may have been lost or degraded (Okui and others, 2008). The model underlying the assessment is for some oil to have been retained within conventional reservoirs and for some oil to have been retained within the shales as a self-sourced, continuous (unconventional) shale-oil reservoir.

Assessment of continuous oil and gas resources of the Timan-Pechora Basin Province, Russia, 2018

The U.S. Geological Survey (USGS) quantitatively assessed the potential for undiscovered, technically recoverable continuous (unconventional) oil and gas resources in the Timan-Pechora Basin Province of Russia (fig. 1). The development of three petroleum systems in the province is related to the tectonic history (Otto and Bailey, 1995; IsmailZadeh and others, 1997; Martirosyan and others, 1998; Lindquist, 1999; Fossum and others, 2001; O’Leary and others, 2004; Sliaupa and others, 2006). The progressive closure of the Uralian Ocean in the Late Permian to Early Jurassic led to the formation of the Ural fold and thrust belt and a west-facing foredeep along the fold belt. As much as 8 kilometers of sediment in the foredeep resulted in the thermal maturation of petroleum source rocks into the gas-generation window and into the oil-maturation window west of the foredeep. Compressional deformation in the Cretaceous effectively ended the maturation process and resulted in erosion of as much as 800 meters. Mild compression in the Oligocene was likely related to the far-field effect of the India-Eurasia plate collision. Uncertainty in this assessment relates to the retention of oil or gas in the reservoirs following compressive deformation and migration.

Assessment of continuous gas resources of the North Caspian Basin Province, Kazakhstan and Russia, 2018

The U.S. Geological Survey (USGS) quantitatively assessed the potential for undiscovered, technically recoverable continuous (unconventional) gas resources in the North Caspian Basin Province of Kazakhstan and Russia (fig. 1). The North Caspian Basin Province contains 20 kilometers of mainly Paleozoic sediment, making it one of the deepest basins in the world. The tectonic evolution of the basin is not well constrained given the extreme depth and the sparseness of data from the deep central part of the basin (Nevolin and Fedorov, 1995; Brunet and others, 1999; Ulmishek, 2001; Volozh and others, 2003; Okere and Toothill, 2012). Initiation of rifting and subsidence in the North Caspian Basin may have been as early as the Neoproterozoic (Brunet and others, 1999), but most likely began in the Ordovician, and rifting and subsidence were related to the opening of the Uralian Ocean (Ulmishek, 2001). Renewed and continuous subsidence from the Late Devonian to Early Permian may have been because of back-arc extension (Brunet and others, 1999), which resulted in the deposition of hundreds of meters of organic-rich source rocks in basinal areas; shallowwater platform carbonates that rimmed the basin are of similar age (Cook and others, 1999). Collision of terranes along the southern margin of the North Caspian Basin during the Early Permian partially isolated the basin and resulted in the deposition of as much as 5 kilometers of evaporites that partially seal the underlying Late Devonian–Early Permian source rocks. The progressive closure of the Uralian Ocean from late Carboniferous to the Triassic formed the Ural fold belt and the adjacent foreland, which filled with several kilometers of orogenic clastic sediments. This pulse of deposition resulted in the maturation of Late Devonian–Early Permian subsalt source rocks by burying them into the oil-generation window and into the gas window in the deep central part of the basin.

Assessment of undiscovered continuous oil and gas resources of Upper Cretaceous Shales in the Songliao Basin of China, 2017

The U.S. Geological Survey (USGS) quantitatively assessed the potential for continuous (unconventional) oil resources within organic-rich lacustrine shale of the Upper Cretaceous Qingshankou and Nenjiang Formations of the Songliao Basin. The Songliao Basin is the most productive oil-bearing nonmarine basin in China, mainly from the super-giant, conventional Daqing Oil Field (fig. 1). This field, discovered in 1959, produces oil from high-quality sandstone reservoirs in large anticlinal traps, sourced by adjacent lacustrine shale of the Qingshankou Formation (Lee, 1986; Li, 1995). Daqing Oil Field has produced over 12 billion barrels of oil, but production has declined in recent years. In light of this decline in conventional oil production, Cao and others (2017) and Liu and others (2017) analyzed the shale-oil potential of the Qingshankou. These authors noted that operators have completed preliminary exploration and tests, but there has been no reported shale-oil production in the Songliao Basin.

Assessment of undiscovered oil and gas resources in the Midlands area, England, 2018

The U.S. Geological Survey (USGS) completed an assessment of undiscovered, technically recoverable continuous (unconventional) and conventional oil and gas resources in the Midlands area of England (figs. 1 and 2). The Midlands is a structurally complex area as a result of several regional tectonic events (Fraser and Gawthorpe, 1990; Corfield and others, 1996). Extension in the Late Devonian to Carboniferous led to deposition of synrift organic-rich shales of the lower part of the Bowland Shale Formation and Hodder Mudstone Formation within several grabens. Postrift regional thermal subsidence led to the deposition of organic-rich shales in the upper part of the Bowland Formation and fluvial-deltaic sandstones of the Millstone Grit Group. Shales in the upper and lower parts of the Bowland and in the Hodder represent the most viable petroleum source rocks in the Midlands (Gross and others, 2015; Raji and others, 2015; Yang and others, 2016; Fauchille and others, 2017; Hennissen and others, 2017; Whitelaw and others, 2017). Regional, northdirected compression in the late Carboniferous and Early Permian caused many of the extensional structures to be uplifted and inverted. Extension and subsidence in the Late Permian through Jurassic resulted in the deposition of several kilometers of sediment, which led to thermally mature organic matter in shales of the Bowland and Hodder Formations and to the generation and migration of oil and gas. Up to 4 kilometers of uplift and erosion in the Paleogene (Anell and others, 2009) may have resulted in the breaching of conventional traps and the loss of oil and gas resources from conventional and continuous reservoirs. This uplift and possible loss of oil and gas is the major source of geologic uncertainty in the assessment of conventional and continuous oil and gas resources in the Midlands area.