Ronald R. Charpentier

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 8: US geological survey Circum-Arctic Resource Appraisal (CARA): Introduction and summary of organization and methods

Abstract The USGS has assessed undiscovered petroleum resources in the Arctic through geological mapping, basin analysis and quantitative assessment. The new map compilation provided the base from which geologists subdivided the Arctic for burial history modelling and quantitative assessment. The CARA was a probabilistic, geologically based study that used existing USGS methodology, modified somewhat for the circumstances of the Arctic. The assessment relied heavily on analogue modelling, with numerical input as lognormal distributions of sizes and numbers of undiscovered accumulations. Probabilistic results for individual assessment units were statistically aggregated taking geological dependencies into account. Fourteen papers in this Geological Society volume present summaries of various aspects of the CARA.

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.

Undiscovered Recoverable Oil and Gas Resources

An assessment was made of the undiscovered recoverable oil and gas resources of the Bekes basin. The resulting mean estimates were 5.22 million metric tons* of undiscovered oil and 18.05×109 m3 of undiscovered natural gas (recoverable). This compares with discovered amounts (through 1985) of 3.81 million metric tons of oil and 25.40×109 m of natural gas. Among the twelve plays assessed, the delta front play has the highest mean potential for oil, 1.90 million metric tons, and the basal turbidite drape structure play has the highest mean potential for undiscovered gas, 5.22×109 m3.

Assessment of undiscovered continuous gas resources of the Ordos Basin Province, China, 2015

The U.S. Geological Survey quantitatively assessed the potential for technically recoverable resources of continuous (unconventional) natural gas in the Ordos Basin Province of China as part of the assessment of priority basins worldwide. Large volumes of tight gas and coalbed gas have been discovered and produced from upper Paleozoic rocks of the Ordos Basin Province. Data on the number of wells and well productivity are, however, publicly unavailable. Limited access to data contributed to the large uncertainty in the resource estimates. The assessments were completed using a methodology developed by the U.S. Geological Survey. This methodology uses Monte Carlo simulation to calculate resource volumes based on probabilistic estimates of assessment unit (AU) area, average well drainage area, percent of AU area that is untested, well success ratio, average estimated ultimate recovery per well, and average coproduct ratios (Charpentier and Cook, 2010). Inadequate data pertaining to the numbers of wells and well productivity in the Ordos Basin Province required that these input distributions be based on the range of behavior in the complete set of analog tight gas and coalbed gas plays that have been assessed in the United States. Two AUs were defined using published geologic studies and the IHS Energy (2014) database. The Upper Paleozoic Tight Gas AU covers 147,409 square kilometers of the central part of the Ordos Basin Province that gently dips (less than 1 degree) to the west (fig. 1). The western and southern boundaries of the AU are defined by fault zones. The northern boundary is defined as the transition between the gas-water zone and the updip water zone (Xiao and others, 2005). The eastern boundary, which separates the tight gas AU from the Upper Paleozoic Coalbed Gas AU, is the −1,200 meter subsurface depth contour. The sources of the gas are the coal beds in the Taiyuan and Shanxi Formations. Reservoirs are mainly low-permeability sandstones, especially in the Shanxi and lower Shihezi Formations. The accumulation is a basin-center, gas-charged zone with an updip water leg. Future potential is envisioned as extending into facies with poorer porosity and permeability than what is being currently developed. Figure 1. Map showing the extent of the Ordos Basin Province, China, and the two assessments units defined in this study. 42°

Assessment of unconventional tight-gas resources of the Magallanes Basin Province, Chile, 2015

The U.S. Geological Survey assesses the potential for technically recoverable unconventional shale-oil, shale-gas, tight-oil, tight-gas, and coalbed-gas resources in priority geologic provinces worldwide. This report summarizes the geologic model and assessment of unconventional tight-gas resources within the informally defined Zona Glauconitica of the Magallanes Basin Province, Chile (fig. 1). The Zona Glauconitica is a 50to 150-meter thick transgressive unit consisting of low-permeability sandstone and siltstone with significant percentages of glauconite (Zurita and others, 2013). Sediments were sourced from the Andean orogen to the west (Biddle and others, 1986). The Magallanes Basin Province contains a Lower Cretaceous Total Petroleum System made up of several source rock intervals containing marine Type II organics with as much as 6 weight percent total organic matter (Pittion and Arbe, 1997). Parts of the oil and gas, generated from Lower Cretaceous source rocks, (1) migrated vertically into the Zona Glauconitica; (2) remained in the Lower Cretaceous source rocks; and (3) migrated into the underlying Springhill Sandstone, which forms the major conventional reservoir for more than 200 oil and gas fields in the eastern part of the Magallanes Basin Province. This study focuses on estimating the potential for technically recoverable resources of tight gas in the Zona Glauconitica.

Assessment of undiscovered oil and gas resources of the Paris Basin, France, 2015

The U.S. Geological Survey (USGS) quantitatively assessed the potential for undiscovered, technically recoverable oil and gas resources in the Paris Basin of France (fig. 1) as part of an effort to assess priority European basins. The Paris Basin composes part of the USGS Anglo-Paris Basin Province, but for this study, only the Paris Basin was evaluated for undiscovered conventional and unconventional (shale oil, shale gas, tight gas) oil and gas resources. More than 35 conventional oil and gas fields have been discovered in the Paris Basin since the 1950s, with the largest oil field, Chaunoy, discovered in 1983. The assessment of undiscovered conventional resources in these oil and gas fields is straightforward, due to the fields’ geology, along with their discovery and exploration history, and what is known of the Lower Jurassic source rocks. This study focuses on the geologic evaluation of unconventional (continuous) oil and gas source-reservoir rock systems and potential resources. For conventional resources, the USGS defined a Mesozoic Reservoirs Assessment Unit (AU) to encompass petroleum that was generated from Lower Jurassic organic-rich shales, then migrated and was trapped in Triassic, Jurassic, and Lower Cretaceous reservoirs. Migration of petroleum across tens of kilometers occurred from the areas of thermally mature Lower Jurassic source rocks. In contrast to the conventional petroleum system, Lower Jurassic source rocks were evaluated for potential source-reservoir rock systems that retained moveable oil. For this assessment, an unconventional (continuous) source-reservoir rock system must: (1) contain greater than 2 weight percent total organic carbon (TOC), (2) be within the proper thermal maturity window for oil or gas generation, (3) have greater than 15 meters of organic-rich shale, and (4) contain Type I or Type II organic matter (Charpentier and Cook, 2011). After potential areas for assessment were defined, the tectonic history, thermal history, and timing of maturation and generation were used to evaluate the risk of retention of hydrocarbons within the source rock. The USGS defined a Toarcian-Domerian Continuous Oil AU (including the “schistes carton”) and a Lotharingian-Sinemurian Continuous Oil AU. The USGS also defined a Permo-Carboniferous Tight Gas AU, which involves coal-sourced gas that migrated locally into low-permeability, or “tight” fluvial sandstones within Permo-Carboniferous rift systems, similar to the Lower Saxony Basin of Germany (Wuestefeld and others, 2014). The presence of rifts, “tight” fluvial reservoirs, and coal-sourced gas are all highly uncertain in the Paris Basin, and the uncertainty is reflected in the F95 fractile of zero resource. The assessment input data for three unconventional (continuous) AUs are shown in table 1.

Assessment of potential unconventional Carboniferous-Permian gas resources of the Liaohe Basin eastern uplift, Liaoning Province, China, 2011

The U.S. Geological Survey (USGS), in cooperation with the U.S. Department of State, is assessing the potential for unconventional oil and gas resources (shale gas, shale oil, tight gas, and coalbed gas) in priority geologic provinces worldwide. In 2010, the USGS, in cooperation with the Chinese National Energy Agency, PetroChina, and PetroChina’s Liaohe Oil Field Company, was requested to evaluate and assess the unconventional resource potential of Carboniferous and Permian coal-bearing strata within the eastern uplift area of the Liaohe Basin, Liaoning Province of the People’s Republic of China (figs. 1, 2). The basin is considered the third most important hydrocarbon-producing basin in China and contains reserves estimated at about 15 billion barrels of oil (Gu and others, 2002; Hu and others, 2005). Much of the geological information used in this study was obtained through a proprietary data agreement with PetroChina. The Liaohe Basin, which is located adjacent to the northeast end of the Bohai Sea, is a wedge-shaped Tertiary rift developed on a paleohigh and can be subdivided into several southwestto-northeast-trending structural units consisting of a series of uplifts and depressions (inset map, fig. 2; Chen and others, 1999). The depressions developed on a basement comprised of Precambrian, Paleozoic, and Mesozoic rocks. Sagging of the eastern depression adjacent to and west of the eastern uplift commenced at about 65 million years ago (Sun, 1999). The eastern uplift is the easternmost structural element of the basin complex and is located within the USGS Luxi Jiaoliao Uplift Province (fig.1). Exploration of oil and gas in the adjacent eastern depression to the west has been ongoing since 1970; the first oil-field discovery occurred in 1975. However, little exploration has occurred in the adjacent eastern uplift to the east (inset map, fig. 2). The U.S. Geological Survey estimated a mean of 448 billion cubic feet of potential technically recoverable unconventional natural gas in Carboniferous and Permian coal-bearing strata in the eastern uplift of the Liaohe Basin, Liaoning Province, China.

Assessment of undiscovered oil and gas resources of Papua-New Guinea, Eastern Indonesia, and East Timor, 2011

The U.S. Geological Survey (USGS) assessed the potential for undiscovered conventional oil and gas fields within five geologic provinces of eastern Asia as part of the USGS World Petroleum Resources Assessment Project. This study follows the USGS assessment of 23 provinces in Southeast Asia (Schenk and others, 2010). The five geologic provinces assessed in this study are the Banda Arc, Bintuni−Sulawati, Arafura Basin−Irian Jaya, New Guinea Foreland Basin-Fold Belt, and the Papuan Basin-Shelf Platform (fig. 1). Assessment units (AU) defined within these provinces are (1) Banda Arc Province—Timor Thrust Structures AU and Seram Thrust Structures AU; (2) Bintuni− Sulawati Province—Sulawati Basin AU, Bintuni Basin AU, and Lengguru Fold Belt AU; (3) Arafura Basin−Irian Jaya Province—Arafura Platform AU and Irian Jaya Fold Belt AU; (4) New Guinea Foreland Basin-Fold Belt Province—Papua New Guinea Fold Belt AU; and (5) Papuan Basin-Shelf Platform Province—Papua Platform AU (table 1). The methodology for the assessment included a complete geologic framework description for each AU based mainly on published literature. Exploration and discovery history was a critical part of the methodology used to estimate sizes and numbers of undiscovered accumulations. Where the discovery history of an AU was immature, geologic analogs were used in the assessment as a guide to sizes and numbers of undiscovered oil and gas accumulations. Each AU was assessed for undiscovered oil and nonassociated gas accumulations, and co-product ratios were used to calculate the volumes of associated gas (gas in oil fields) and volumes of natural gas liquids.