Ronald M. Drake

Underpressure in Mesozoic and Paleozoic rock units in the Midcontinent of the United States

Potentiometric surfaces for Paleozoic strata, based on water well levels and selected drill-stem tests, reveal the control on hydraulic head exerted by outcrops in eastern Kansas and Oklahoma. From outcrop in the east, the westward climb of hydraulic head is much less than that of the land surface, with heads falling so far below land surface that the pressure:depth ratio in eastern Colorado is less than 5.7 kPa/m (0.25 psi/ft). Permian evaporites separate the Paleozoic hydrogeologic units from a Lower Cretaceous (Dakota Group) aquifer, and a highly saline brine plume pervading Paleozoic units in central Kansas and Oklahoma is attributed to dissolution of Permian halite. Underpressure also exists in the Lower Cretaceous hydrogeologic unit in the Denver Basin, which is hydrologically separate from the Paleozoic units. The data used to construct the seven potentiometric surfaces were also used to construct seven maps of pressure:depth ratio. These latter maps are a function of the differences among hydraulic head, land-surface elevation, and formation elevation. As a consequence, maps of pressure:depth ratio reflect the interplay of three topologies that evolved independently with time. As underpressure developed, gas migrated in response to the changing pressure regime, most notably filling the Hugoton gas field in southwestern Kansas. The timing of underpressure development was determined by the timing of outcrop exposure and tilting of the Great Plains. Explorationists in western Kansas and eastern Colorado should not be surprised if a reservoir is underpressured; rather, they should be surprised if it is not.

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 Permian tight oil and gas resources in the Junggar basin of China, 2016

Introduction The U.S. Geological Survey (USGS) quantitatively assessed the potential for continuous (unconventional) oil and gas resources within organic-rich shale and associated tight reservoirs in lacustrine deposits of the Junggar basin of China (fig. 1). The assessed stratigraphic interval was laminated, organic-rich shale of the Lower Permian Lucaogou Formation (Yang and others, 2010; superseding an Upper Permian age assigned by previous researchers, such as Carroll and others, 1992). The Permian lacustrine formations of the Junggar basin were likely deposited in a foreland basin north of a north-directed thrust belt in the Tian Shan at the basin’s southern margin (fig. 1) (Wartes and others, 2002). The Junggar was an intracratonic sag basin in the Mesozoic and Paleogene and is again in a foreland setting in Neogene to present time (Bian and others, 2010). The focus of this assessment is the potential for oil and gas retained in tight reservoirs interbedded within the Permian Lucaogou lacustrine shales. Tight reservoirs are generally considered to be nonshale reservoirs that require artificial stimulation such as hydraulic fracturing to produce hydrocarbons because of low permeability of the reservoir (generally near 0.1 millidarcies or lower, criteria met by the Lucaogou reservoirs according to Cao and others, 2016). Current exploration and production of tight oil from the Lucaogou Formation are focused on the Jimusar sag, a relatively shallow part of the basin (fig. 1). At present, there are 16 wells producing “industrial tight-oil flows” from the Lucaogou in the Jimusar sag (Hu and others, 2016). Within the Permian Lucaogou Total Petroleum System, we defined two assessment units (AUs): the Permian Lucaogou Continuous Oil AU and the Permian Lucaogou Continuous Gas AU (fig. 1). The thickness, organic matter content and type, and thermal maturity of the Lucaogou all suggest the potential to produce continuous oil and gas. The Permian Lucaogou Continuous Oil AU corresponds to areas where the Lucaogou Formation is currently at depths shallower than 5 kilometers on shelves around the margins of the basin (for example, Jimusar sag; fig. 1). Gradual burial of the basin’s shelves and shallow marginal sags led to oil being generated in the Permian Lucaogou Formation in the Late Jurassic to middle Cretaceous (Kuang and others, 2012). The Permian Lucaogou Continuous Gas AU corresponds to the areas where organic-rich shale lies at depths greater than 5 kilometers. This part of the basin experienced voluminous nonmarine sedimentation nearly continuously from the Permian to the Neogene. Oil was generated in latest Permian and earliest Triassic (Kuang and others, 2012) and cracked to gas later in the Mesozoic. Continuous oil and gas accumulations in the United States were used as analogs in this assessment. Table 1 lists principal input data for the assessment.

Geologic framework for the national assessment of carbon dioxide storage resources—Southern Rocky Mountain Basins: Chapter M in Geologic framework for the national assessment of carbon dioxide storage resources

The U.S. Geological Survey has completed an assessment of the potential geologic carbon dioxide storage resources in the onshore areas of the United States. To provide geological context and input data sources for the resources numbers, framework documents are being prepared for all areas that were investigated as part of the national assessment. This report is the geologic framework document for the Uinta and Piceance, San Juan, Paradox, Raton, Eastern Great, and Black Mesa Basins, and subbasins therein of Arizona, Colorado, Idaho, Nevada, New Mexico, and Utah. In addition to a summary of the geology and petroleum resources of studied basins, the individual storage assessment units (SAUs) within the basins are described and explanations for their selection are presented. Although appendixes in the national assessment publications include the input values used to calculate the available storage resource, this framework document provides only the context and source of the input values selected by the assessment geologists. Spatial-data files of the boundaries for the SAUs, and the well-penetration density of known well bores that penetrate the SAU seal, are available for download with the release of this report.

Geologic framework for the national assessment of carbon dioxide storage resources: U.S. Gulf Coast: Chapter H in Geologic framework for the national assessment of carbon dioxide storage resources

This report presents 27 storage assessment units (SAUs) within the United States (U.S.) Gulf Coast. The U.S. Gulf Coast contains a regionally extensive, thick succession of clastics, carbonates, salts, and other evaporites that were deposited in a highly cyclic depositional environment that was subjected to a fluctuating siliciclastic sediment supply and transgressive and regressive sea levels. At least nine major depositional packages contain porous strata that are potentially suitable for geologic carbon dioxide (CO2) sequestration within the region. For each SAU identified within these packages, the areal distribution of porous rock that is suitable for geologic CO2 sequestration is discussed, along with a description of the geologic characteristics that influence the potential CO2 storage volume and reservoir performance. These characteristics include reservoir depth, gross thickness, net-porous thickness, porosity, permeability, and groundwater salinity. Additionally, a characterization of the overlying regional seal for each SAU is presented. On a case-by-case basis, strategies for estimating the pore volume existing within structurally and (or) stratigraphically closed traps are also presented. Geologic information presented in this report has been employed to calculate potential storage capacities for CO2 sequestration in the SAUs that are assessed herein, although complete assessment results are not contained in this report.

Geologic framework for the national assessment of carbon dioxide storage resources: Denver Basin, Colorado, Wyoming, and Nebraska: Chapter G in Geologic framework for the national assessment of carbon dioxide storage resources

This is a report about the geologic characteristics of five storage assessment units (SAUs) within the Denver Basin of Colorado, Wyoming, and Nebraska. These SAUs are Cretaceous in age and include (1) the Plainview and Lytle Formations, (2) the Muddy Sandstone, (3) the Greenhorn Limestone, (4) the Niobrara Formation and Codell Sandstone, and (5) the Terry and Hygiene Sandstone Members. The described characteristics, as specified in the methodology, affect the potential carbon dioxide storage resource in the SAUs. The specific geologic and petrophysical properties of interest include depth to the top of the storage formation, average thickness, net-porous thickness, porosity, permeability, groundwater quality, and the area of structural reservoir traps. Descriptions of the SAU boundaries and the overlying sealing units are also included. Assessment results are not contained in this report; however, the geologic information included here will be used to calculate a statistical Monte Carlo-based distribution of potential storage volume in the SAUs.

Geologic framework for the national assessment of carbon dioxide storage resources: Greater Green River Basin, Wyoming, Colorado, and Utah, and Wyoming-Idaho-Utah Thrust Belt

The 2007 Energy Independence and Security Act (Public Law 110–140) directs the U.S. Geological Survey (USGS) to conduct a national assessment of potential geologic storage resources for carbon dioxide (CO2). The methodology used by the USGS for the national CO2 assessment follows up on previous USGS work. The methodology is non-economic and intended to be used at regional to subbasinal scales. This report identifies and contains geologic descriptions of 14 storage assessment units (SAUs) in Ordovician to Upper Cretaceous sedimentary rocks within the Greater Green River Basin (GGRB) of Wyoming, Colorado, and Utah, and eight SAUs in Ordovician to Upper Cretaceous sedimentary rocks within the Wyoming-Idaho-Utah Thrust Belt (WIUTB). The GGRB and WIUTB are contiguous with nearly identical geologic units; however, the GGRB is larger in size, whereas the WIUTB is more structurally complex. This report focuses on the characteristics, specified in the methodology, that influence the potential CO2 storage resource in the SAUs. Specific descriptions of the SAU boundaries, as well as their sealing and reservoir units, are included. Properties for each SAU, such as depth to top, gross