Geology topics

Steven M. Cahan

Publications and source records attributed to Steven M. Cahan.

At least 19 recordsLinked to original sources

USGS2025

Estimated ultimate recovery (EUR) Prediction for Eagle Ford Shale using integrated datasets and artificial neural networks

The estimated ultimate recovery (EUR) is an important parameter for forecasting oil and gas production and informing decisions regarding field development strategies. In this study, we combined site-specific geologic, completion, and operational parameters with the predictive capabilities of machine learning (ML) models to predict EURs of the wells for the Eagle Ford Marl Continuous Oil Assessment Unit. We developed an extensive dataset of wells that have produced from the lower and upper Eagle Ford Shale intervals and reduced the model complexity using principal component analysis. We tested the ML models and estimated the sensitivities of ML-predicted EURs to changes in the values of different input variables. The results of applying the optimized ML model to the Eagle Ford suggest that the approach developed in this study could be promising. The ML estimates of the EURs fit the DCA-based values with an R 2 ~ 0.9 and a mean absolute error of ~36 × 10 3 bbl. In the lower Eagle Ford Shale, the EUR estimates were found to be most sensitive to changes in porosity, net thickness of the interval, clay volume, and the API gravity of the oil; and that in the upper Eagle Ford Shale they were most sensitive to changes in the total organic carbon and water saturation, which suggests that it could be important to consider these parameters in assessing these intervals or close analogs.

Louisiana, Mississippi, Texas↗

USGS2024

Spatial distribution of API gravity and gas/oil ratios for petroleum accumulations in Upper Cretaceous strata of the San Miguel, Olmos, and Escondido Formations of the south Texas Maverick Basin—Implications for petroleum migration and charge history

The Maverick Basin of south Texas is currently undergoing active exploration and production of gas and oil from tight sandstone reservoirs. The most productive tight sandstones in the basin are in the Upper Cretaceous San Miguel, Olmos, and Escondido Formations. These units are second only to the Eagle Ford Shale in terms of cumulative production volumes. The structural history of the Maverick Basin, from rifting to subsidence to exhumation, has had a profound effect on the characteristics of these reservoirs and the petroleum resources contained therein. This U.S. Geological Survey review of the production history of these strata reflects a recent shift from conventional production to horizontal drilling (unconventional) that exploits low permeability reservoirs in previously overlooked areas of existing oil and gas fields in southern Texas, typically outside of established field boundaries. To investigate the physical properties of the Maverick Basin hydrocarbon accumulations, this case study compiled American Petroleum Institute (API) gravity measurements and calculated cumulative gas/oil ratios (GOR) for thousands of producing wells from the San Miguel, Olmos, and Escondido Formations. Maps were generated from the compiled well production data to show the spatial heterogeneity of API gravity and GOR values for the three formations within the Maverick Basin and immediately outside the basin to the northeast. Within the Maverick Basin, the spatial patterns of API gravity values indicate lighter oils downdip towards the southern basin edge. GOR values indicative of wet and dry gases within the basin are seen interspersed, with values that correspond to black and heavy oils. Differences in the spatial patterns of the petroleum properties within the Maverick Basin are interpreted as effects of Eocene basin inversion caused by Laramide orogenic deformation, and the resulting reservoir exhumation of basin strata. East of the Maverick Basin, spatial distributions of API gravity and GOR values show progressively heavier oils updip to the northwest, grading to dry gases downdip to the southeast, which correlates to the oil and gas windows of the underlying Eagle Ford Shale. Correlation of API gravity and GOR values from the San Miguel, Olmos, and Escondido Formations with thermal maturity data from the Eagle Ford Shale suggests that the Eagle Ford Shale is the petroleum source, and that petroleum migration was approximately vertical for areas to the east of the Maverick Basin. The discontinuity of API gravity and GOR properties within the Maverick Basin implies a complex petroleum charge history, possibly involving the remigration of petroleum and the addition of petroleum from other source intervals in Mexico, to the southwest. Depressurization of exhumed, overpressured reservoirs of the San Miguel, Olmos, and Escondido Formations can explain the intermittent occurrence of gas production throughout the southern Maverick Basin by exsolution of gas from formation brines and the resulting dry gas flushing of hydrocarbon-charged reservoirs. The introduction of dry gas through flushing can, in turn, explain why the patterns of API gravity and GOR values are so dissimilar in the Maverick Basin. This process has implications for possible future production of unconventional resources from undiscovered tight-gas reservoirs in strata of the San Miguel, Olmos, and Escondido Formations, and a different approach to petroleum exploration may be needed in the Maverick Basin relative to exploration techniques applied in other basins within the northern Gulf of Mexico.

Texas↗

USGS2023

Geologic carbon management options for the North Atlantic-Appalachian Region

Introduction The U.S. Geological Survey (USGS) North Atlantic-Appalachian Region is developing the regionwide capacity to provide timely science support for decision-makers attempting to enhance carbon removal, sequestration, and emissions mitigation to meet national atmospheric carbon reduction goals. The U.S. Environmental Protection Agency (EPA) reported that in 2021, the fourteen States and the District of Columbia in the northeastern region account about for approximately 18 percent of the total national greenhouse gas (GHG) emissions. This Fact Sheet provides a summary of USGS science information and ongoing and new investigations or data-collection programs that may help the northeastern region decrease the release of carbon-containing GHG to the atmosphere.

Connecticut, Delaware, Maine, Maryland, Massachuse↗

USGS2022

Dynamic estimates of geologic CO2 storage resources in the Illinois Basin constrained by reinjectivity of brine extracted for pressure management

Geologic carbon storage (GCS) is likely to be an important part of global efforts to decarbonize the energy industry. Widespread deployment of GCS relies on strategies to maximize CO 2 injection rates while minimizing reservoir pressurization that could induce seismicity and/or fluid leakage into groundwater resources. Brine extraction from CO 2 storage formations with subsurface reinjection elsewhere could mitigate pressure buildup associated with GCS. Therefore, evaluation of CO 2 storage resources should consider the injectivity of produced brine in geologic layers above or below the CO 2 storage formation. For this study, a methodology was developed to estimate brine injectivity from formation depth and thickness using flow modeling and optimization techniques. The methodology was demonstrated in the Illinois Basin, where GCS in the Mt. Simon Sandstone is ongoing. Based on pressure constraints and considering only regions of the shallower units where salinity and sealing conditions were met, maximum brine injection rates were estimated within the Mt. Simon and three overlying hydrostratigraphic layers. Results indicate that a large area exists where CO 2 injectivity could be optimized by brine extraction and reinjection.

Illinois, Indiana↗

USGS2022

A novel method for conducting a geoenvironmental assessment of undiscovered ISR-amenable uranium Resources: Proof-of-concept in the Texas Coastal Plain

A geoenvironmental assessment methodology was developed to estimate waste quantities and disturbances that could be associated with the extraction of undiscovered uranium resources and identify areas on the landscape where uranium and other constituents of potential concern (COPCs) that may co-occur with uranium deposits in this region are likely to persist, if introduced into the environment. Prior to this work, a method was lacking to quantitively assess the environmental aspects associated with potential development of undiscovered uranium resources at a scale of a uranium resource assessment. The mining method of in situ recovery (ISR) was historically used to extract uranium from deposits in the Goliad Sand of the Texas Coastal Plain. For this reason, the study’s methodology projected the following types of wastes and disturbances commonly associated with ISR based on historical ISR mining records: the mine area, affected aquifer volume, mine pore volume, water pumped and disposed during uranium extraction and restoration, and radon emissions. Within the tract permissive for the occurrence of undiscovered uranium resources, maps and statistics of factors were derived that indicate the potential contaminant pathways. The percentage of days meeting the criteria for air stagnation indicate the potential for radon accumulation; the geochemical mobility of COPCs in groundwater in combination with effective recharge indicates the potential for infiltration of surface-derived COPCs; the geochemical mobility of COPCs in groundwater combined with hydraulic conductivity indicates the propensity for transmitting fluids away from contaminated or mined aquifers; and finally, geochemical mobility of COPCs in surface water combined with the factor for climatic erosivity (R factor) indicates the potential for COPCs to persist in surface waters due to runoff. This work resulted in a new methodology that can be applied to any undiscovered mineral resource to better understand possible wastes and disturbances associated with extraction and identify areas on the landscape where COPCs are likely to persist.

Texas↗

USGS2022

Database of the "North America Tapestry of Time and Terrain" map

In 2000, the U.S. Geological Survey published a distinctive map, entitled “A Tapestry of Time and Terrain,” which showed a generalized depiction of the geology in the conterminous United States, draped over shaded-relief topography. In 2003, that map concept was extended geographically, and the resulting new map was published at 1:8,000,000 scale as “The North America Tapestry of Time and Terrain” (NATTT). The NATTT map showed the wide range of ages of the bedrock that underlies North America, as well as the distribution of the principal rock types— sedimentary, igneous (as two subtypes, volcanic and plutonic), and metamorphic. Regional processes active at the land surface, as well as continental-scale tectonic events, are exposed on the maps, in the three dimensions of space and in the fourth dimension, geologic time. This new publication contains the geographic information system (GIS) data from the NATTT map, which, in turn, includes map data from the earlier Tapestry map. The GIS files contain over 20,000 polygons that represent geologic age and rock class. In addition, layer files are provided to facilitate a symbolized display of the map that is similar to that of the original NATTT map publication. The data are intended to be used at the scale of the published source map (1:8,000,000).

Data Series↗

USGS2022

National assessment of carbon dioxide enhanced oil recovery and associated carbon dioxide retention resources — Results

In 2020, the U.S. Geological Survey (USGS) completed a probabilistic assessment of the volume of technically recoverable oil resources available if current carbon dioxide enhanced oil recovery (CO 2 -EOR) technologies were applied to amenable oil reservoirs underlying the onshore and State waters areas of the conterminous United States. The assessment also includes estimates of the mass of CO 2 that could be stored (retained) as a result of CO 2 -EOR activities. The USGS assessment team evaluated more than 3,500 oil reservoirs that were miscible to injected CO 2 . The assessed reservoirs are in 185 previously defined USGS plays in 33 petroleum provinces of 7 national regions. The assessment team estimated that the technically recoverable oil associated with CO 2 -EOR ranges from approximately 25,000 million barrels (MMbbl) at the P 5 percentile to as much as 32,000 MMbbl at the P 95 percentile, with a mean of 29,000 MMbbl. The associated CO 2 retention ranges from approximately 7,400 million metric tons (Mt) at the P 5 percentile to as much as 9,500 Mt at the P 95 percentile, with a mean of 8,400 Mt. The West Texas and Eastern New Mexico region and the Gulf Coast region together contain 60 percent of the mean assessed CO 2 -EOR oil potential and 61 percent of the mean assessed CO 2 retention. Other regions with significant resource potential include the Midcontinent region and Rocky Mountains and Northern Great Plains region.

Continental United States↗

USGS2022

National assessment of carbon dioxide enhanced oil recovery and associated carbon dioxide retention resources — Summary

Introduction In 2020, the U.S. Geological Survey (USGS) completed a probabilistic assessment of the volume of technically recoverable oil resources that might be produced by using current carbon dioxide enhanced oil recovery (CO 2 -EOR) technologies in amenable conventional oil reservoirs underlying the onshore and State waters areas of the conterminous United States. The assessment also includes estimates of the mass of CO 2 that could be stored (retained) in the assessed oil reservoirs following the application of the CO 2 -EOR process. The USGS assessment team evaluated more than 3,500 oil reservoirs that were miscible to injected CO 2 . The assessed reservoirs are in 185 previously defined USGS plays in 33 petroleum provinces of 7 national regions. The team estimated that the total technically recoverable oil resulting from the application of the CO 2 -EOR process ranges from approximately 25,000 million barrels (MMbbl) at the P 5 percentile to as much as 32,000 MMbbl at the P 95 percentile, with a mean of 29,000 MMbbl. The associated CO 2 retention ranges from approximately 7,400 million metric tons (Mt) at the P 5 percentile to as much as 9,500 Mt at the P 95 percentile, with a mean of 8,400 Mt. The results are summarized in this fact sheet and are provided in more detail in the companion data release and circular. The West Texas and Eastern New Mexico region (primarily its Permian Basin) and the Gulf Coast region together contain 60 percent of the mean assessed CO 2 -EOR oil potential and 61 percent of the mean assessed CO 2 retention. Other regions with significant resource potential include the Midcontinent region and the Rocky Mountains and Northern Great Plains region.

Continental United States↗

USGS2022

Assessment of carbon dioxide enhanced oil recovery and associated carbon dioxide retention resources of the United States

In 2020, the U.S. Geological Survey (USGS) completed a probabilistic assessment of the volume of technically recoverable oil resources that could be produced using current carbon dioxide enhanced oil recovery (CO2-EOR) technologies in amenable conventional oil reservoirs underlying onshore and State-owned offshore waters (herein after, onshore and State waters areas) of the conterminous United States. Our assessment also includes estimates of the mass of CO2 that could be stored (retained) in the assessed oil reservoirs following the application of the CO2-EOR process. The USGS assessment team evaluated more than 3,500 oil reservoirs that were amenable to miscible CO2 injection. The assessed reservoirs are located in 185 plays previously defined by a USGS National Oil and Gas Assessment in 33 petroleum provinces of seven national regions. The team estimated that the total technically recoverable oil resulting from the application of the CO2-EOR process ranges from approximately 25,000 million barrels (MMbbl) at the P5 probability percentile to as much as 32,000 MMbbl at the P95 probability percentile, with a mean of 29,000 MMbbl. The associated CO2 retention ranges from approximately 7,400 million metric tons (Mt) at the P5 percentile to as much as 9,500 Mt at the P95 percentile, with a mean of 8,400 Mt.

conterminous United States↗

USGS2019

Estimating market conditions for potential entry of new sources of anthropogenic CO2 for EOR in the Permian Basin

This study attempts to determine feasible carbon dioxide (CO2) price thresholds for entry of new sources of anthropogenic (man-made) CO2 for utilization in enhanced oil recovery (EOR) in the Permian Basin. Much of the discussion about carbon capture, utilization, and storage (CCUS) has focused on the high costs of carbon capture as the major barrier to entry of new anthropogenic sources of CO2 for EOR. In addition, a recent study by Edwards and Celia (2018) suggests that the lack of a CO2 transportation network to efficiently transport CO2 from ethanol plants in the Midwest to EOR sites in the Permian Basin could be a prohibitive barrier to commercial-scale entry (without some Government assistance to help finance the construction of new CO2 pipelines), despite the costs of carbon capture from ethanol plants being relatively low. Thus, entry of additional sources of anthropogenic CO2 for use in EOR in the Permian Basin could be primarily by major carbon emitters that are located closest to the existing CO2 pipeline network that currently transports mostly natural CO2 (extracted from geologic reservoirs) to EOR sites. Data from the U.S. Environmental Protection Agency (EPA)’s Greenhouse Gas Reporting Program (GHGRP) (U.S. Environmental Protection Agency, 2019) suggest that numerous major CO2 emitters are located within 50 km of the existing pipeline network that provides CO2 for EOR in the Permian Basin. The costs for connecting these potential sources of CO2 to the existing transportation infrastructure could be very low. Of these potential sources of anthropogenic CO2, the leading emitters are coal-fired electricity generation plants, and the sources with next-largest emissions are natural gas-fired power plants. However, the CO2 concentrations in the emission streams of these types of power plants is typically far lower than that for ethanol plants and some other industrial facilities (including natural gas processing plants), which causes the estimated capture costs (using currently available technologies) to be far higher, in general. In addition, the potential cost (per metric ton of CO2 supplied) of adding these new sources of anthropogenic CO2 for EOR in the Permian basin could be greater than expanding production of existing suppliers and developing new sources of natural CO2. On the other hand, their proximity to the existing pipeline network could allow them to be viable sources of anthropogenic CO2 for EOR in the Permian Basin, and the relative competitiveness of these sources with the existing use of natural CO2 could be further enhanced if they qualify for the recently revised 45Q tax credit (Heitkamp, 2017). The results of this study provide some estimates of the potential gaps in the costs of CO2 supply from these distinct sources, and the potential implications of the results for the market conditions that could be necessary to overcome those gaps are discussed.

Conference Paper↗

USGS2018

Geologic framework for the national assessment of carbon dioxide storage resources—Atlantic Coastal Plain and Eastern Mesozoic Rift Basins

This chapter presents information pertinent to the geologic carbon dioxide (CO 2 ) sequestration potential within saline aquifers located in the Atlantic Coastal Plain and Eastern Mesozoic Rift Basins of the Eastern United States. The Atlantic Coastal Plain is underlain by a Jurassic to Quaternary succession of sedimentary strata that onlap westward onto strata of the Appalachian Piedmont physiographic province and generally thicken eastward toward the present-day Atlantic coastline and onto the present-day continental shelf. Although no significant petroleum discoveries have been made on the coastal plain, the deep saline aquifers of the region appear to contain porous strata (potential reservoirs, or “storage formations”) that are overlain by fine-grained, laterally continuous strata (potential seals), which are prospective CO 2 sequestration targets. For the Atlantic Coastal Plain, we identify two storage assessment units (SAUs), both of which consist of Cretaceous strata. The two SAUs are the Lower Cretaceous Composite SAU C50700101 and the Upper Cretaceous Composite SAU C50700102. The Eastern Mesozoic Rift Basins are a chain of generally southwest- to northeast-trending, elongate sedimentary basins that either underlie the Atlantic Coastal Plain or crop out within adjacent geologic provinces to the west. Similar to the Atlantic Coastal Plain, there has been no significant oil and gas production from any of the basins, although there is a proven petroleum system in several of them. At least three of these basins appear to contain potential storage formations overlain by potential seal units. Most of the other basins were not assessed because a storage and (or) seal formation could not be established in the timeframe of the assessment, often because of the paucity of subsurface data for these basins in comparison to other petroliferous basins of the United States. Thus, we present information supporting one quantitative assessment in the Newark basin, as well as information supporting two nonquantitative assessments, one for strata in the Gettysburg basin and the other for strata in the Culpeper basin. We briefly discuss six other basins within the Eastern Mesozoic Rift Basins that were not assessed. For all SAUs, we discuss the areal distribution of suitable CO 2 reservoir rock. We also describe the overlying sealing unit and the geologic characteristics that influence the potential CO 2 storage volume and reservoir characteristics. These characteristics include storage formation depth, gross thickness, net thickness, porosity, permeability, and groundwater salinity. Case-by-case strategies for estimating the pore volume existing within structurally and (or) stratigraphically closed traps are presented. Although assessment results are not contained in this chapter, the geologic information included herein was used to calculate the potential storage space in the SAUs.

Atlantic Coastal Plain and Eastern Mesozoic Rift B↗

USGS2017

Geologic assessment of undiscovered oil and gas resources—Lower Cretaceous Albian to Upper Cretaceous Cenomanian carbonate rocks of the Fredericksburg and Washita Groups, United States Gulf of Mexico Coastal Plain and State Waters

In 2010, the U.S. Geological Survey (USGS) assessed Lower Cretaceous Albian to Upper Cretaceous Cenomanian carbonate rocks of the Fredericksburg and Washita Groups and their equivalent units for technically recoverable, undiscovered hydrocarbon resources underlying onshore lands and State Waters of the Gulf Coast region of the United States. This assessment was based on a geologic model that incorporates the Upper Jurassic-Cretaceous-Tertiary Composite Total Petroleum System (TPS) of the Gulf of Mexico basin; the TPS was defined previously by the USGS assessment team in the assessment of undiscovered hydrocarbon resources in Tertiary strata of the Gulf Coast region in 2007. One conventional assessment unit (AU), which extends from south Texas to the Florida panhandle, was defined: the Fredericksburg-Buda Carbonate Platform-Reef Gas and Oil AU. The assessed stratigraphic interval includes the Edwards Limestone of the Fredericksburg Group and the Georgetown and Buda Limestones of the Washita Group. The following factors were evaluated to define the AU and estimate oil and gas resources: potential source rocks, hydrocarbon migration, reservoir porosity and permeability, traps and seals, structural features, paleoenvironments (back-reef lagoon, reef, and fore-reef environments), and the potential for water washing of hydrocarbons near outcrop areas. In Texas and Louisiana, the downdip boundary of the AU was defined as a line that extends 10 miles downdip of the Lower Cretaceous shelf margin to include potential reef-talus hydrocarbon reservoirs. In Mississippi, Alabama, and the panhandle area of Florida, where the Lower Cretaceous shelf margin extends offshore, the downdip boundary was defined by the offshore boundary of State Waters. Updip boundaries of the AU were drawn based on the updip extent of carbonate rocks within the assessed interval, the presence of basin-margin fault zones, and the presence of producing wells. Other factors evaluated were the middle Cenomanian sea-level fall and erosion that removed large portions of platform and platform-margin carbonate sediments in the Washita Group of central Louisiana. The production history of discovered reservoirs and well data within the AU were examined to estimate the number and size of undiscovered oil and gas reservoirs within the AU. Using the USGS National Oil and Gas Assessment resource assessment methodology, mean volumes of 40 million barrels of oil, 622 billion cubic feet of gas, and 14 million barrels of natural gas liquids are the estimated technically recoverable undiscovered resources for the Fredericksburg-Buda Carbonate Platform-Reef Gas and Oil AU.

Alabama, Arkansas, Florida, Louisiana, Mississippi↗

USGS2016

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, chapter M, 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.

Arizona, Colorado, Idaho, Nevada, New Mexico, Utah↗

USGS2015

Geologic framework for the national assessment of carbon dioxide storage resources─South Florida Basin: Chapter L in Geologic framework for the national assessment of carbon dioxide storage resources

This report presents five storage assessment units (SAUs) that have been identified as potentially suitable for geologic carbon dioxide sequestration within a 35,075-square-mile area that includes the entire onshore and State-water portions of the South Florida Basin. Platform-wide, thick successions of laterally extensive carbonates and evaporites deposited in highly cyclic depositional environments in the South Florida Basin provide several massive, porous carbonate reservoirs that are separated by evaporite seals. For each storage assessment unit identified within the basin, the areal distribution of the reservoir-seal couplet identified as suitable for geologic Carbon dioxide sequestration is presented, along with a description of the geologic characteristics that influence the potential carbon dioxide storage volume and reservoir performance. On a case-by-case basis, strategies for estimating the pore volume existing within structurally and (or) stratigraphically closed traps are also discussed. Geologic information presented in this report has been employed to calculate potential storage capacities for carbon dioxide sequestration in the storage assessment units assessed herein, although complete assessment results are not contained in this report.

Florida↗

USGS2015

Geologic framework for the national assessment of carbon dioxide storage resources: Permian and Palo Duro Basins and Bend Arch-Fort Worth Basin: Chapter K 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 resource 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 Permian and Palo Duro Basins, the combined Bend arch-Fort Worth Basin area, and subbasins therein of Texas, New Mexico, and Oklahoma. In addition to a summarization 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. Though 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 inputs selected by the assessment geologists. Spatial files of boundaries for the SAUs herein, as well as maps of the density of known well bores that penetrate the SAU seal, are available for download with the release of this report.

New Mexico, Oklahoma Texas↗

USGS2015

National assessment of geologic carbon dioxide storage resources: allocations of assessed areas to Federal lands

Following the geologic basin-scale assessment of technically accessible carbon dioxide storage resources in onshore areas and State waters of the United States, the U.S. Geological Survey estimated that an area of about 130 million acres (or about 200,000 square miles) of Federal lands overlies these storage resources. Consequently, about 18 percent of the assessed area associated with storage resources is allocated to Federal land management. Assessed areas are allocated to four other general land-ownership categories as follows: State lands about 4.5 percent, Tribal lands about 2.4 percent, private and other lands about 72 percent, and offshore areas about 2.6 percent.

Scientific Investigations Report↗

USGS2014

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 thickness, porosity, permeability, groundwater quality, and structural reservoir traps, are typically provided to illustrate geologic factors critical to the assessment. This geologic information was employed, as specified in the USGS methodology, to calculate a probabilistic distribution of potential storage resources in each SAU. Figures in this report show SAU boundaries and cell maps of well penetrations through sealing units into the top of the storage formations. The cell maps show the number of penetrating wells within one square mile and are derived from interpretations of variably attributed well data and a digital compilation that is known not to include all drilling.

Colorado, Idaho, Utah, Wyoming↗

USGS2014

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

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.

Colorado, Nebraska, Wyoming↗