Troy A. Cook

A Framework for Quantitative Assessment of Impacts Related to Energy and Mineral Resource Development

Natural resource planning at all scales demands methods for assessing the impacts of resource development and use, and in particular it requires standardized methods that yield robust and unbiased results. Building from existing probabilistic methods for assessing the volumes of energy and mineral resources, we provide an algorithm for consistent, reproducible, quantitative assessment of resource development impacts. The approach combines probabilistic input data with Monte Carlo statistical methods to determine probabilistic outputs that convey the uncertainties inherent in the data. For example, one can utilize our algorithm to combine data from a natural gas resource assessment with maps of sage grouse leks and piñon-juniper woodlands in the same area to estimate possible future habitat impacts due to possible future gas development. As another example: one could combine geochemical data and maps of lynx habitat with data from a mineral deposit assessment in the same area to determine possible future mining impacts on water resources and lynx habitat. The approach can be applied to a broad range of positive and negative resource development impacts, such as water quantity or quality, economic benefits, or air quality, limited only by the availability of necessary input data and quantified relationships among geologic resources, development alternatives, and impacts. The framework enables quantitative evaluation of the trade-offs inherent in resource management decision-making, including cumulative impacts, to address societal concerns and policy aspects of resource development.

Geologic Model for the Assessment of Technically Recoverable Oil in the Devonian–Mississippian Bakken Formation, Williston Basin

The Upper Devonian and Lower Mississippian Bakken Formation in the United States part of the Williston Basin is a giant continuous (unconventional) oil resource. A recent U.S. Geological Survey (USGS) assessment estimated a mean volume of undiscovered technically recoverable oil for the Bakken Formation of about 3.65 billion bbl of oil. The estimate is based on a geologic model and a methodology that defines different assessment units by accumulation type (conventional or continuous), structural control, fracture occurrence and prediction, lithology and petrophysical properties, formation thickness, underlying salt movement or dissolution, and level of thermal maturity and oil-generation capacity of Bakken source rocks. The Bakken Formation consists of three informal members: (1) lower shale member; (2) middle sandstone member; and (3) upper shale member. Shale members are rich in marine organic matter (as much as 35% by weight) and are the petroleum source rocks, whereas the middle sandstone member varies in depositional facies and lithology and locally exhibits good matrix porosity (as much as 14%) but with low permeability, a characteristic of tight reservoirs. Additional commingled production occurs locally from matrix porosity in the immediately underlying, informally named, Sanish sand unit of the Upper Devonian Three Forks Formation. Combined, the Bakken Formation and Sanish sand define the Bakken composite continuous reservoir. On a larger scale, thermally mature organic-rich Bakken shale members are also the source for oils produced from locally occurring Waulsortian mounds or porous strata immediately above the upper shale member in the overlying Lower Mississippian Lodgepole Limestone. As a whole, elements of petroleum source, reservoir, seal, migration, and trap define the stratigraphic and geographic character of a Bakken-Lodgepole Total Petroleum System. The geographic extent of the continuous oil accumulation within the United States part of the Bakken Formation is defined as the area in which organic-rich shale members of the Bakken Formation are thermally mature with respect to oil generation. The area of the oil-generation window for the Bakken Formation continuous reservoir was determined using a combination of the following: (1) contour mapping of both the hydrogen index (HI) and log-resistivity well data of the upper shale member, (2) calibration of HI to the transformation ratio (TR) from one-dimensional burial history models, and (3) calibration of HI to total organic content. The geologic model used to further define continuous assessment units (AUs) within the Bakken Formation continuous oil accumulation was, in general, based on assumed levels of thermal maturity and generation capacity of the Bakken shale members as determined from HI and TR, relation of HI and TR to potential fracturing and structural complexity of the Williston Basin, and lithofacies distribution and petrophysical character of the middle sandstone member. The area of the oil-generation window was divided into five continuous AUs: (1) Elm Coulee-Billings Nose AU, (2) Central Basin-Poplar Dome AU, (3) Nesson-Little Knife Structural AU, (4) Eastern Expulsion Threshold AU, and (5) Northwest Expulsion Threshold AU. One hypothetical conventional AU, a Middle Sandstone Member AU, was defined external to the area of oil generation. Using the established U.S. Geological Survey methodology, assessment of each Bakken continuous AU was performed after estimation of effective well drainage areas, estimated ultimate recovery (EUR) from productive wells, and production success defined by a minimum EUR of 2000 bbl of oil. The AUs with the greatest resource potential are the Eastern Expulsion Threshold AU (mean volume, 0.973 billion bbl of oil), which is best represented by the Parshall and Sanish fields of Mountrail County, North Dakota, and the Nesson-Little Knife Structural AU (mean volume, 0.908 billion bbl of oil), where structural reservoir development exists, the middle sandstone member is thick and porous, the underlying Sanish sand reservoir unit is commonly present, and shale members have high oil-generation potential and the probability of abundant natural fracturing.

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.

Assessment of undiscovered biogenic gas resources, North-central Montana Province

In 2000 the U.S. Geological Survey (USGS) assessed the undiscovered biogenic (also known as microbial) continuous gas resource potential of the North-Central Montana Province in eastern Montana (fig. 1) as part of a national oil and gas assessment project. The assessment was based on the general geologic elements used to define a total petroleum system (TPS), including hydrocarbon source rocks (hydrocarbon generation and migra tion), reservoir rocks (sequence stratigraphy and petrophysical properties), and hydrocarbon traps (trap formation and timing). Using this geologic framework, the USGS defined the Cretaceous Judith River through Belle Fourche Biogenic Gas TPS and seven assessment units (AUs) within it, and quantitatively estimated the undiscovered continuous gas resources within each AU. Resource Summary