Energy Resources Program
Wednesday, October 19, 2016
Wednesday, September 07, 2016
Outside Publication: Natural Resources Research
Carbon capture from stationary sources and geologic storage of carbon dioxide (CO2) is an important option to include in strategies to mitigate greenhouse gas emissions. However, the potential costs of commercial-scale CO2 storage are not well constrained, stemming from the inherent uncertainty in storage resource estimates coupled with a lack of detailed estimates of the infrastructure needed to...
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Thursday, June 02, 2016
Chapter M - 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...
Thursday, March 03, 2016
Geological sequestration (storage) of carbon dioxide (CO2), a greenhouse gas, is an available technology that injects and stores anthropogenic CO2 produced by various industries and electric generation facilities in porous and permeable subsurface rock units, thereby preventing the release of the CO2 into the atmosphere where it may contribute to global warming. Few large-scale CO2 geologic sequestration projects exist today and more research is needed to better understand the geologic controls on subsurface rock storage capacities, the geologic and environmental hazards, and economic feasibility associated with geologic storage of CO2.
The U.S. Geological Survey (USGS) has a long history of assessing national and global ground- and surface-water resources and geologically-based energy and mineral resources. In 2007, the Energy Independence and Security Act (EISA, Public Law 110–140) authorized the USGS to conduct a national assessment of geologic storage resources for CO2. The results of the national assessment were published in 2013 (U.S. Geological Survey Geologic Carbon Dioxide Storage Resources Assessment Team, 2013). The EISA also requested USGS to evaluate the national technically recoverable hydrocarbon resources resulting from CO2 injection and storage (through CO2-enhanced oil recovery). During the next few years, the USGS Carbon Sequestration – Geologic Research and Assessments project plans to develop an assessment methodology and conduct an assessment of recoverable hydrocarbons associated with CO2 injection. An economic analysis of enhanced oil recovery associated with CO2 sequestration will also be undertaken.
The Helium Stewardship Act of 2013 directed the USGS to cooperate with the Bureau of Land Management (BLM) and the State geological surveys, to assess the availability of recoverable natural helium (He) and associated CO2 found in natural gas reservoirs in the United States. The project plans to work with these agencies to build the necessary databases needed to assess natural He and CO2 resources.
The Carbon Sequestration – Geologic Research and Assessments project will also build on geologic models and regional assessment results developed during the national assessment of geologic storage resources. The project will conduct relevant research that focuses on improving the geologic and technical foundation and economic feasibility of CO2 sequestration in various geologic basins, rock types, and regions of the country. Environmental and geologic risks associated with CO2 sequestration will also be investigated and will include those associated with the geochemistry of produced groundwater and induced seismicity related to CO2 injection and storage.
Research conducted by the Carbon Sequestration – Geologic Research and Assessments project will also build the framework needed to improve future assessments of the Nation’s geologic CO2 storage capacities. The project will continue to monitor research to evaluate the storage potential of CO2 in unconventional reservoirs (primarily coal). The project will continue interactions and collaborations established during the previous CO2 storage assessment project, which include State and Federal agencies and international organizations in the area of geologic carbon sequestration. The project work will complement ongoing efforts in these other organizations, and will use their results in the planned research efforts. Project research results will be presented at scientific meetings and published.
During the course of the Carbon Sequestration – Geologic Research and Assessments project, the following six research and assessment topics will be investigated. These topics are discussed in more detail in the research section of this web page.
USGS Frequently Asked Questions (FAQ) Pertaining to "Carbon Sequestration"
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Research conducted by the Carbon Sequestration – Geologic Research and Assessments project will build on geologic models and regional assessment results developed during the national assessment of geologic storage resources (U.S. Geological Survey Geologic Carbon Dioxide Storage Resources Assessment Team, 2013). The project will conduct relevant research that focuses on improving the geologic and technical foundation and economic feasibility of carbon dioxide (CO2) subsurface storage in various geologic basins, rock types, and regions of the country. The project plans to evaluate the national technically recoverable hydrocarbon resources resulting from CO2 injection and storage through CO2-enhanced oil recovery and will study natural CO2 and helium reservoirs as analogues for anthropogenic CO2 storage. Environmental and geologic risks associated with CO2 subsurface storage will also be investigated and will include those associated with the geochemistry of produced groundwater and induced seismicity related to CO2 injection and storage. During the course of the Carbon Sequestration – Geologic Research and Assessments project, the following six research and assessment topics will be investigated.
Geologic CO2 sequestration coupled with enhanced oil recovery (EOR) using CO2 in existing hydrocarbon reservoirs can increase the U.S. hydrocarbon recoverable resource volume and prevent CO2 release to the atmosphere potentially limiting its contribution to global warming as a greenhouse gas. The Energy Independence and Security Act (EISA, Public Law 110–140) of 2007 authorized the U.S. Geological Survey (USGS) to conduct a national assessment of geologic storage resources and to evaluate the national technically recoverable hydrocarbon resources resulting from CO2 injection and storage (CO2-EOR). The USGS recently completed a national CO2 storage assessment (U.S. Geological Survey Geologic Carbon Dioxide Storage Resources Assessment Team, 2013). In addition, the Carbon Sequestration – Geologic Research and Assessments project has developed a comprehensive CO2-EOR database and a preliminary assessment methodology to evaluate the technically recoverable oil related to CO2 sequestration. The goal of the CO2-EOR research task is to finalize the assessment methodology and to conduct a national assessment of technically recoverable oil related to CO2 injection. The amount of CO2 stored during the hydrocarbon recovery process will also be evaluated.
Although enhanced gas recovery by CO2 gas injection into the reservoir is technically feasible, no commercial enhanced gas recovery project exists today in conventional gas reservoirs. There could be some benefits of CO2 gas injection, such as additional natural gas recovery and condensate recovery, but this is not practical because of the high gas recovery factor, the costs of capture and transmission of CO2 to the gas fields, and additional infrastructure for CO2 separation and injection in the gas fields. Therefore, enhanced gas recovery using CO2 injection will not be part of the national CO2-EOR assessment.
The objective of the CO2-EOR research effort is to develop a geologic- and reservoir engineering-based, probabilistic assessment methodology that can be used to estimate the potential volumes of technically recoverable oil using CO2-EOR and associated CO2 sequestration in the onshore and state waters oil fields of the United States. After the methodology has been carefully reviewed by experts from industry, academia, and government, USGS plans to use the assessment methodology to conduct a national assessment of recoverable oil using CO2. The resulting storage of CO2 associated with enhanced oil recovery will also be assessed.
The following USGS factsheet released in 2011 and slide presentations summarize our approach to the development philosophy of assessment methodology and work progress.
USGS Factsheet: Development of an Assessment Methodology for Hydrocarbon Recovery Potential Using Carbon Dioxide and Associated Carbon Sequestration: Workshop Findings
Slideshow: Development Philosophy of an Assessment Methodology for Hydrocarbon Recovery Potential Using CO2–EOR Associated with Carbon Sequestration - By Mahendra Verma and Peter Warwick [Adobe Flash]
Slideshow: Enhanced Oil Recovery and CO2 Resource Studies at the U.S. Geological Survey - By P. D. Warwick and U.S. Geological Survey Geologic Carbon Dioxide Storage Resources Assessment Team [Adobe Flash]
Contact: Mahendra Verma
The recently completed USGS assessment of the national CO2 storage potential (U.S. Geological Survey Geologic Carbon Dioxide Storage Resources Assessment Team, 2013, http://pubs.usgs.gov/circ/1386/) establishes a baseline of storage resources available in various basins of the United States. Because the assessment was completed at a rapid pace in order to meet the completion deadline required by the Energy Independence and Security Act of 2007, more focused geological studies need to be conducted on reservoirs and seals in selected basins and storage assessment units (SAUs) with high potential for CO2 sequestration. Also, reevaluation of smaller basins not assessed during the initial assessment may be needed in some instances to better understand the character and distribution of the storage resources. The purpose of this research task is to reevaluate selected regions of the country and selected SAUs to better understand the distribution of the geologic storage resources for anthropogenic CO2. For example, the following questions represent some of the areas of research that will be addressed:
1) What are the characteristics of the regional sealing units that overlie the SAUs with significant CO2 storage potential?
2) What are the regional pressure variations in each basin and SAU?
3) Are some areas of the SAU in over-pressured or under-pressured conditions?
4) At what time scales did these over- or under-pressures conditions develop – at hundreds, thousands, or millions of years?
5) Which SAUs also have high potential for enhanced hydrocarbon recovery using injected CO2?
Regional maps need to be developed for selected SAUs with high storage potential that show variation in thickness, porosity, permeability, groundwater salinity, and structural complexity. Also, project members will work to complete the CO2 storage basin geology Open-File Reports series (see Warwick and Corum, 2012), which support the results of the USGS national CO2 storage assessment.
The objective of this research effort is to reevaluate selected regions of the country and selected SAUs to better define the distribution of the geologic storage resources for anthropogenic CO2. Since reservoir pressure directly impacts CO2 storage potential, regional models need to be developed to help understand the controls on over- and under-pressure development in basins. Geochemical models are needed to better understand the character of ground water and the subsurface geochemical environments in selected SAUs. These studies are important to assess the feasibility and potential environmental impacts of geologic CO2 storage. As the opportunities develop, project members, in coordination with the USGS Produced Waters project, may also work cooperatively with other organizations to better characterize the local and regional geologic and ground water controls on potential CO2 storage.
Slideshow: CO2 Fluid Flow Modeling to Derive... the Time Scales of Lateral Fluid Migration - By Lauri Burke [Adobe Flash]
Contact: Peter Warwick
The 2007 Energy Independence and Security Act (EISA, Public Law 110–140) authorized the USGS to conduct a national assessment of geologic storage resources for CO2. The results of the national assessment were published in 2013 (U.S. Geological Survey Geologic Carbon Dioxide Storage Resources Assessment Team, 2013). The EISA also directed the USGS to evaluate the unique conditions resulting from long-term storage of CO2 in geologic reservoirs, and to estimate the potential volumes of recoverable hydrocarbons by injection and storage of anthropogenic CO2. In addition, the Helium Stewardship Act of 2013 (HSA, Public Law 113-40) directed the USGS, to work with the Bureau of Land Management (BLM) and State geological surveys, to produce a national assessment of helium (He) resources and associated naturally occurring CO2. Naturally occurring He is used in many industrial and research applications and natural CO2 is primarily used in enhanced oil recovery operations. Although not part of the petroleum system, He and CO2 often occur in natural gas reservoirs. To determine the need for anthropogenic CO2 for enhanced oil recovery operations, a better understanding of the availability and resource distribution of naturally occurring CO2 is needed. Likely, a mix of CO2 from both anthropogenic and natural sources will be used to recover remaining hydrocarbons.
To address these Congressional questions, project members will build upon previous studies of natural CO2/He reservoirs in several regions (see below) and conduct detailed studies of selected reservoirs (primarily those containing greater than 10 percent CO2) to determine the long-term geologic and geochemical effects of natural CO2 storage and to obtain new geochemical isotopic data that can be used to better assess CO2/He resources. Samples of gas and produced water from wells producing from high-CO2 reservoirs will help to define the origin (mantle or crustal), migration history, and ultimate fate of natural CO2 and associated He. Field sampling will be done in coordination with the USGS Produced Waters Project. Field and rock core investigations will help determine the degree and rate of CO2-derived diagenesis (mineralization, recrystallization, dissolution, bleaching) that has occurred in the reservoir rocks. Geologic characterization of the CO2 reservoir rocks will help to determine the long-term effects of natural CO2 storage and the occurrence of CO2 leaks from the reservoir. Reports will be prepared to show the results of these investigations and to development potential analogues for anthropogenic CO2 storage reservoirs. The information obtained from these studies can be used to help predict the geologic and environmental effects of anthropogenic CO2 storage in geologic reservoirs.
Project members will work with BLM and the State Geological Surveys to build a national geochemical database that can be used to assess CO2/He occurrence and resources in U.S. natural gas reservoirs. The BLM and USGS both have geochemical databases that, if merged, would become the most comprehensive publically available natural gas database that provides natural gas composition and isotopic information. The resulting database could be used to evaluate the distribution of discovered natural He resources in the United States. An evaluation of the undisclosed CO2/He resources will follow in later years of the project.
Natural CO2 Study Regions
Contact: Marc Buursink, Email: firstname.lastname@example.org
Northern Rocky Mountains
Contact: Matt Merrill, Email: email@example.com
Southern Rocky Mountains
Contact: Bill Craddock, Email: firstname.lastname@example.org
Southwestern Permian Basin
Contact: Peter Warwick, Email: email@example.com
Jackson Dome, Mississippi
Contact: Tina Roberts-Ashby, Email: firstname.lastname@example.org
Contact: Ernie Slucher, Email: email@example.com
Resource assessments require an economic analysis of the results to help policy makers and other assessment users better understand the potential development of the resource under various economic conditions. Because geologic carbon sequestration is relatively new, few studies have been conducted on the economic viability of wide-spread implementation of the technology. Also, previous economic assessments of enhanced oil recovery (EOR) using CO2 have focused on the economics of the recoverable hydrocarbons and have not included an assessment of the economic viability of CO2 sequestration associated with the EOR processes. Efforts undertaken in this research area will be coordinated with the USGS Energy Resources Program - Economics Dimensions of Energy Resources, Assessments and Future Supply project. The focus of this research will be to 1) develop and apply the economic models to evaluate the results of the 2013 USGS national assessment of geologic carbon dioxide storage resources (U.S. Geological Survey Geologic Carbon Dioxide Storage Resources Assessment Team, 2013); 2) develop economic models to characterize joint CO2-EOR and storage projects; and 3) apply economic models to assess economic potential for incremental oil recovery in oil fields assessed by geologists.
In order to develop the economic implications of the USGS national assessment results for CO2 storage resources, an economic model of representative storage projects must be devised that incorporates geologic data similar to data applied in the national storage assessment. In addition costs must be estimated for various activities, including site evaluation, CO2 injection, storage management, and other economic parameters that may influence the viability of a particular CO2 storage project. Project staff will collect the information required to apply the economic models to estimate costs and economic consequences of risks associated with CO2 storage. In addition, for an economic analysis of CO2-EOR and associated carbon sequestration, project staff will collect the data needed to utilize published and constructed type curves to predict injection and production well performance. Economic models related to the CO2 storage in joint CO2-EOR projects and for sequestration in buoyant structures and saline aquifers will be built in coordination with the Economics Dimensions of Energy Resources, Assessments and Future Supply project. The CO2-EOR economic model developed by USGS ERP Economics project will be used by this project to evaluate potential economic oil for fields assessed by project geologists.
To assess the economic implications of the USGS national assessment results for CO2 storage resources, an economic model of representative CO2 storage projects will be devised that incorporates relevant geologic and engineering data as well as the data applied in the national assessment. In addition to devising an analytical framework to model storage, costs must be estimated for various activities, including site evaluation, CO2 injection, storage management, and other economic parameters that may influence the viability of a particular CO2 storage project. A methodology must also be developed to capture and estimate the risks and the economic consequences of risks associated with CO2 storage. Both the economic model preparation and the characterization of the economic consequences of storage risks will be done in co-operation with the Economics Dimensions of Energy Resources, Assessments and Future Supply project.
Contact: Philip Freeman
The results of USGS National CO2 assessment provide estimates of the potential subsurface storage volumes in existing pore space of sandstones, limestones, or dolostones (U.S. Geological Survey Geologic Carbon Dioxide Storage Resources Assessment Team, 2013). The Energy Independence and Security Act (EISA) of 2007 (Public Law 110-140) also called for the USGS to evaluate the CO2 storage potential in unmineable coal beds. Because there was no clear consensus on what defines an unmineable coal bed, the USGS CO2 storage assessment methodology (Brennan and others, 2010) did not include methods to assess CO2 storage in coal beds. In 2012, the USGS held a workshop where industry, government, and university researchers recommend that CO2 storage in coal beds should be limited to deep coals (>3,000 ft) in order to maintain the injected CO2 in a supercritical state (Jones and others, 2012). However, suitable permeability and porosity needed for CO2 injection in coals with depths greater than 3,000 ft may be difficult to find in many basins. Most CO2 storage demonstration projects that have been conducted thus far have injected CO2 in a non-supercritical state at depths usually between 1,000 and 3,000 ft. Many of these CO2 injections projects are also associated with enhanced coalbed methane (ECBM) production operations. In these projects, the injected CO2 is strongly adsorbed onto organics in the internal pore structure of the coal and physically displaces the methane which can then be produced. Also of concern are the swelling behavior of the coal matrix and loss of permeability in CO2-saturated coal, and the effects of injected CO2 on existing microbial methane producing populations. Many of these coal bed and shale reservoirs (for example in the San Juan Basin, Powder River Basin, Gulf of Mexico Coastal Plain) also contain active microbial communities that naturally convert CO2 and hydrogen (H2) into methane (CH4). What will the fate be of injected CO2 into organic-rich reservoirs? In addition, what effect will CO2 injection have on the release of trace metals and organics from coal beds?
Injection of CO2 into permeable organic-rich shale that has been fractured either by natural or human process, is another option considered for long-term storage of greenhouse gases. More research is needed to better understand the potential for dissolved organics, in CO2-saturated coal or organic-rich shale, to become mobilized and mixed with groundwater. Other lithologies such as basaltic rocks can also trap CO2 through adsorption or mineralogical reaction. Prior to these unconventional reservoirs being included in future national USGS assessments, it is necessary to understand more about their CO2 storage potential, depth, geographic distribution, and the physical and chemical processes that will influence any new assessment methodologies.
The objectives of this research are to compile relevant information summarizing the state of knowledge concerning the use of coal beds and shale as potential reservoirs for the long-term storage of CO2. This task will also follow research and demonstration projects related to CO2 storage in basaltic rocks. Initial products will include national maps showing the location and other available data (thickness for example) for deep (>1,000 ft) coal beds and organic-rich shale that may be available for CO2 storage. Coal beds between 1,000 and 3,000 ft may be available for enhanced gas production using injected CO2 and coal beds deeper than 3,000 ft may be available for super-critical CO2 injection. As required by the EISA, a preliminary methodology will be developed to evaluate the CO2 storage potential in coal beds. Any research initiatives to quantify the potential effect of CO2 injection into organic-rich intervals will be coordinated with the Origin of Microbial Gas (methanogenesis) task in the USGS Energy Program Geochemistry of Solid Fuels project, and relevant State and Federal agencies and international organizations.
Contact: Kevin Jones
In recent years, the United States has expanded the use of technologies that involve injection (and in some cases associated production) of fluid at depth to meet future energy needs, limit emissions of greenhouse gases, and safely dispose of wastewater. To varying degrees, the injection and production practices employed in these technologies have the potential to introduce significant seismic hazards (see the recent report by the National Research Council, 2012; “Induced seismicity potential in energy technologies”). The significance of induced seismicity associated with wastewater disposal from natural gas production is highlighted by the 2008 (magnitude, M, of 3.3) and 2009 earthquake sequence near the Dallas-Fort Worth airport and by moderate-sized earthquakes induced in 2011 by the deep injection of wastewater near Prague, Oklahoma (M5.6), Guy, Arkansas (M4.7) and Youngstown, Ohio (M4.0). Likewise, there is a potential seismic hazard associated with geologic carbon sequestration projects, which could involve the injection of vast quantities of liquid CO2 into sedimentary basins located in or near major urban centers of the eastern and central United States (National Research Council, 2012).
As a national science agency, the USGS is responsible for assessing hazard from earthquakes throughout the United States. The USGS studies induced seismicity across the spectrum of energy issues: carbon sequestration, geothermal energy, and conventional and unconventional oil and gas. In the central and eastern United States, earthquakes induced by fluid injection activities contribute significantly to the total seismic hazard, partly because the modern boom in oil and gas production is taking place in this vast region and also because the background level of seismicity is relatively low in this geologically stable part of the country. This research effort, also supported by the USGS Earthquake Hazards Program ("Induced Earthquakes webpage"), will conduct interdisciplinary research on the potential for induced seismicity related to geologic CO2 storage. The primary focus of the research will be on the installation and operation of an independent USGS seismic monitoring network at the largest operating underground CO2 injection and storage facility in the U.S., located in Decatur, Illinois (see project website). Data collected from the USGS seismic monitoring installation at Decatur will be used to interpret the potential seismic hazard associated with geologic CO2 sequestration in the Illinois Basin and in similar geologic settings (Kaven and others, 2015).
The primary objectives of this research are to develop a better understanding of the physical processes responsible for seismicity induced by deep CO2 injection, develop procedures to quantify the resulting seismic hazards, and help design appropriate mitigation strategies. Achieving these goals will require communication of research results and related information between the USGS and other Federal and non-Federal organizations working on this issue. There are only limited publically available data that can be used to assess the seismic risk associated with CO2 injection; therefore, new seismic monitoring data are needed from areas with active CO2 injection projects.
Some of the key questions that arise in connection with CO2 injection at Decatur are as follows:
1. What magnitude-frequency distribution of induced earthquakes, including the maximum magnitude, is likely to result from the injection of approximately 1 million metric tons of supercritical CO2 into the Mt. Simon Sandstone during the initial 3-year test?
2. What will be the seismic consequences during the second phase of CO2 sequestration at Decatur, proposed to begin in summer 2015, when three times as much carbon dioxide will be injected down a nearby well?
3. What is the likelihood of pore pressure increase due to high-volume injection being transmitted into the pre-Cambrian basement, where there may be hidden faults that might be prone to reactivation?
4. How can knowledge of the in-situ stress field, geologic/hydrologic structure, rock mechanical properties, and injection parameters be used to understand the physical processes controlling induced seismicity at Decatur? Can this knowledge be used to change the operational parameters of CO2 injection (for example, well placement, wellhead injection rates/pressures) to reduce the seismic hazards posed by geologic CO2 sequestration?
To investigate these scientific questions, the USGS conducts seismic monitoring and related studies near the Illinois Basin - Decatur Project (IBDP) CO2 injection site, located in Decatur, Illinois. The IBDP, operated by the Midwest Geological Sequestration Consortium, with funding from the Department of Energy and industry partners, is conducting a five-year test to inject industrial CO2 into a deep saline formation (Mt. Simon Sandstone) in the Illinois Basin. Injection of CO2 started in November 2011 at a rate of approximately 1,000 metric tons per day, and ended in November 2014 after the IBDP injected a total of about 1 million metric tons of CO2. A second injection well operated by a government-industry consortium led by Archer Daniels Midland, the Illinois Industrial Carbon Capture and Storage Project, is scheduled to be completed at Decatur in early-2015, to accommodate an increase in CO2 injection rate of up to 1 million metric tons per year for an additional three years.
There are multiple reasons for concentrating our efforts on the Decatur site. First, Decatur is the first (and, to date, only) site in the U.S. with high-volume CO2 injection into a regionally extensive, undisturbed saline basal aquifer. Such conditions raise the likelihood of fault reactivation by increasing the pore pressure above background levels. Second, the geologic setting at Decatur is a potential candidate for inducing slip along deep hidden faults, due to the Mt. Simon Sandstone resting directly on top of the pre-Cambrian basement. Third, the Decatur Project is intended to test the feasibility of numerous future, larger-scale CO2 injection activities in the Illinois Basin (for example, FutureGen project) and in similar geologic settings elsewhere.
On-going USGS monitoring at Decatur has yielded the following insights into the research questions listed above:
1. The range of microseismic event magnitudes is between -1.2 < Mw < 1.1, which is too small to have been felt at the surface. To date we have detected ~220 seismic events and, so far, have too few microseismic events to constrain the frequency-magnitude distribution for seismicity induced by CO2 sequestration at Decatur.
3. All the detected seismicity so far is located between several hundreds of meters up to 3km from the injection well. All events are located several hundred meters below the Eau Claire Shale, which serves as the primary caprock (seal) for the CO2. Seismicity tends to occur either within the Mt. Simon sandstone, the Pre-Mt. Simon Sandstone (a low-porosity and permeability, highly fractured sandstone), or the underlying pre-Cambrian granitic basement. Some of this seismicity lies along linear trends, which appear to correspond to faults that are favorably oriented for reactivation in the regional tectonic stress field. Focal mechanisms for events in the basement indicate strike-slip motion on these favorably oriented faults. The seismicity within the basement indicates that excess pore pressure from the injection well is communicated into pre-existing faults within the basement that are favorably oriented for slip, causing some of the observed microseismicity.
Contact: Ole Kaven
A list of downloadable Geologic CO2 Sequestration spatial data and associated geologic reports is available here.
Visit our interactive web map that includes investigated basins, assessed areas, stratigraphic columns, and well density information.
Sean T. Brennan1, Joseph A. East1, Kristin O. Dennen1, Hossein Jahediesfanjani2, Brian Varela3
1U.S. Geological Survey, 12201 Sunrise Valley Dr., Reston, VA 20192; 2Lynxnet, 13873 Park Center Rd., Suite 400N, Herndon, VA 20171; 3U.S. Geological Survey, Kipling St & 6th Street, Denver, CO 80226
In 2013, the Helium Stewardship Act (Public Law 113–40; U.S. Congress, 2013) directed the U.S. Geological Survey (USGS) to create an accounting of the geological helium resources of the United States. The initial task in this endeavor has been to collect all known analyses of subsurface helium gas within the contiguous United States and Alaska.
The two main sources of data employed in this assessment process are from the Bureau of Land Management (BLM) and the U.S. Geological Survey (USGS). BLM data come from thousands of gas samples analyzed for the Federal Helium Program, which originally began in 1925 under the U.S. Bureau of Mines (USBM). These analyses were reported in several publications (Moore and Sigler, 1987; Hamak and Gage, 1992; Hamak and Sigler, 1991, 1993; Sigler, 1994; Hamak and Driskill, 1996; Gage and Driskill, 1998, 2003, 2005; Driskill, 2008), and additional unpublished data reside in an internal BLM database. A publically available database that contains much of the data from USBM, BLM, and USGS analyses (U.S. Geological Survey, 2015).
The data include all gas analyses from the BLM and USGS databases with measured values of helium concentrations. Helium values of less than 0.005 mol% are listed as “TRACE”, and those greater than 0.005 mol% were rounded up to 0.01 mol%. We report all helium recognized in gas compositions, even though there is a limit on economically recoverable helium. A minimum helium concentration of 0.3 mole percent (mol%) is needed for the commercial separation of helium from marketable natural gas (National Research Council, 2010). However, helium concentrations as low as 0.04 can be economic if gas is chilled and purified to meet specifications as liquefied natural gas (National Research Council, 2010).
It is important to note that there might be several gas samples from different wells in a given reservoir or formation, hence the concentration values reported for each well sample do not necessarily represent the concentration of helium in the entire reservoir.
The analytical data is supported with identifying information. These include the American Petroleum Institute (API) number, a unique 10 digit identifier for each well, the first two numbers indicate the state, the next three indicate the county, and the last five numbers are a unique code for that well. Each entry also contains the latitude and longitude of the well, and the names of the gas producing formation and field. The sample depth in feet and the date that the sample was collected are listed for each well. The reported date is in mm/dd/yyyy format. Wherever “00” is present in the sample date, this indicates that the sampling day and or month were not listed in the source publications. Where data are absent, or listed as “not given”, “UNK” was entered into the field to indicate that information is unknown.
You must read and agree to the following limitations of the data prior to downloading:
Disclaimer for Provisional Data
The data you have secured are provisional and subject to revision. The data are released on the condition that neither the USGS nor the United States Government may be held liable for any damages resulting from its authorized or unauthorized use.
Although the data have been processed on the computer system at the U.S. Geological Survey, U.S. Department of the Interior, no warranty, expressed or implied, is made by the Geological Survey regarding the utility of the data on any other system, nor shall the act of distribution constitute any such warranty. No responsibility is assumed by the U.S. Geological Survey in the use of these data.
By downloading, you are aware of these limitation to data use and data quality:
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Driskill, D.L, 2008, Analyses of natural gases, 2005–2007: Bureau of Land Management, Technical Note 427, p., accessed May 17, 2016.
Gage, B.D., and Driskill, D.L., 1998, Analyses of Natural Gases, 1996–1997: Bureau of Land Management, Technical Note 404, 71 p., accessed May 17, 2016.
Gage, B.D., and Driskill, D.L., 2003, Analyses of Natural Gases, 1998–2001: Bureau of Land Management, Technical Note 412, 173 p., accessed May 17, 2016.
Gage, B.D., and Driskill, D.L. , 2005, Analyses of Natural Gases, 2002–2004: Bureau of Land Management, Technical Note 418, 243 p., accessed May 17, 2016.
Hamak, J.E., and Driskill, D.L., 1996, Analyses of Natural Gases, 1994–1995: U.S. Bureau of Land Management, Technical Note 399, 70 p., accessed May 17, 2016.
Hamak, J.E., and Gage, B.D., 1992, Analyses of Natural Gases, 1991: U.S. Bureau of Mines, Information Circular 9318, 97 p.
Hamak, J.E., and Sigler, S.M., 1991, Analyses of Natural Gases, 1986–1990: U.S. Bureau of Mines, Information Circular 9301, 315 p.
Hamak, J.E., and Sigler, S.M., 1993, Analyses of Natural Gases, 1992: U.S. Bureau of Mines, Information Circular 9356, 62 p.
Moore, B.J., and Sigler, S.M., 1987, Analyses of Natural Gases, 1917–1985: U.S. Bureau of Mines, Information Circular 9129, 1197 p.
National Research Council. 2010, Selling the Nation's Helium Reserve: Washington, D.C.: The National Academies Press, 156 p.
Sigler, S.M., 1994, Analyses of Natural Gases, 1993: U.S. Bureau of Mines, Information Circular 9400, 58 p.
U.S. Congress, 2013, Helium Stewardship Act of 2013—Public Law 110–40: U.S. Government Printing Office, 15 p., accessed May 17, 2016.
U. S. Geological Survey, 2015, Geochemistry Database: U.S. Geological Survey, Provisional Database, accessed May 17, 2016.
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USGS Public Lecture Series: Watching Nature's Clock: A Citizen-Scientist Effort to Track Seasonal Signs of Climate Change
USGS Public Lecture Series: Baked Alaska--What's Happening to the Glaciers in Alaska?
Can We Move Carbon from the Atmosphere and into Rocks?
USGS Podcast (Episode 89)
See Podcast Transcript
Public Lecture Sneak Peek: Soils, Carbon, and the Global exCHANGE
USGS Podcast (Episode 252)
Sand Dunes on the Loose Due to Climate Change
USGS Podcast (Episode 268)
See Podcast Transcript
New Climate Change Forecasts
USGS Podcast (Episode 283)
USGS Carbon Sequestration Website
National Assessment of Ecosystem Carbon Sequestration and Greenhouse Gas Fluxes
USGS Earthquake Hazards Program - "Induced Earthquakes"
Select Energy Resources Program CO2 Publications
U.S. Department of Energy (DOE) and Related Websites:
U.S. DOE Geologic Sequestration Research
Regional Partnerships Involved in Carbon Sequestration Research:
West Coast Regional Carbon Sequestration Partnership (WestCarb)
Southwest Regional Partnership for Carbon Sequestration
Big Sky Regional Carbon Sequestration Partnership
Plains CO2 Reduction Partnership
Midwest (Illinois Basin) Geologic Sequestration Consortium
Southeast Regional Carbon Sequestration Partnership
Midwest Regional Carbon Sequestration Partnership
State Geologic Survey Websites:
Check on geologic CO2 sequestration activities in your state. Visit the Association of American State Geologists website
International Energy Agency (IEA) Websites:
IEA Greenhouse Gas R&D Programme (IEAGHG)
IEA Carbon Capture and Storage
Other International Websites:
Natural Analogues for the Storage of CO2 in the Geological Environment (NASCENT)
CO2 Capture Project
CO2CRC (Cooperative Research Centre for Greenhouse Gas technologies)
MIT Laboratory for Energy and the Environment Carbon Sequestration Initative
Geologic CO2 Storage, The University of Texas at Austin
Global Climate and Energy Project (GCEP), Stanford University
Carbon Mitigation Initiative (CMI), Princeton University
IRIS Webinar - "Induced/Triggered Earthquakes: Examples from Texas"
Carbon Sequestration Conference
A Strategy for Low Cost Development of Incremental Oil in Legacy Reservoirs (OnePetro)
Page Last Modified: Friday, September 23, 2016