Reducing greenhouse gas emissions by injecting unwanted gases into unused deep-brine-bearing aquifers is an attractive option because large-volume sinks underlie many carbon dioxide sources. In this study, funded by DOE/NETL, we inventoried the 16 geologic characteristics of 21 brine-bearing formations in the continental United States to provide basic data needed to assess the feasibility, costs, and risks of this sequestration method. We investigated a diverse spectrum of target formations and compiled a GIS database by digitizing published and unpublished data from each basin.

The Carbon Storage Open Database is a collection of spatial data obtained from publicly available sources published by several NATCARB Partnerships and other organizations.

This map shows the rate at which forests could capture carbon from the atmosphere and store it in aboveground live biomass over the first 30 years of natural forest regrowth. It was created by combining ground-based measurements at thousands of locations around the world with 66 co-located environmental covariate layers in a machine learning model to produce a wall-to-wall map. Forest plot data used to train the model are sourced from published literature, which can be found in the Forest Carbon database (ForC, maintained by the Smithsonian Institute (https://github.com/forc-db)), as well as georeferenced data from publicly available national forest inventories. Although rates were estimated over all forest and savanna biomes globally, they are filtered here by “reforestable” area, as defined in Griscom et al. 2017 (PNAS). Reforestable areas exclude areas of native grasslands and croplands to safeguard the production of food and fiber and habitat for biological diversity.Extent: Global, within reforestation extent of Griscom et al. 2017 (which excludes the boreal, grassy biomes, and croplands) Resolution: 1 km x 1 kmCitation: Cook-Patton, S.C., Leavitt, S.M., Gibbs, D. et al. Mapping carbon accumulation potential from global natural forest regrowth. Nature 585, 545–550 (2020).Credits: Cook-Patton, S.C., S.M. Leavitt, D. Gibbs, N.L. Harris, K. Lister, K.J. Anderson-Teixeira, R.D. Briggs, R.L. Chazdon, T.W. Crowther, P.W. Ellis, H.P. Griscom, V. Herrmann, K.D. Holl, R.A. Houghton, C. Larrosa, G. Lomax, R. Lucas, P. Madsen, Y. Malhi, A. Paquette, J.D. Parker, K. Paul, D. Routh, S. Roxburgh, S. Saatchi, J.van den Hoogen, W.S. Walker, C.E. Wheeler, S.A. Wood, L. Xu, B.W. Griscom. 2020. Mapping carbon accumulation potential from natural forest regrowth. Nature, in press. https://www.nature.com/articles/s41586-020-2686-x. This work resulted from a collaboration between The Nature Conservancy, World Resources Institute, and 18 other institutions.Date: Applicable to the first 30 years of natural forest regrowth. Related layers: Carbon accumulation potential from natural forest regrowth in forest and savanna biomes, Uncertainty in carbon accumulation potential from natural forest regrowth

Numerical simulations have shown that the use of supercritical CO2 instead of water as a heat transfer fluid yields significantly greater heat extraction rates for geothermal energy. If this technology is implemented successfully, it could increase geothermal energy production and offset atmospheric emissions of greenhouse gases. However, the impact of geochemical reactions between acidic waters in equilibrium with supercritical CO2 and the reservoir rock have not been evaluated. At issue are enhanced rock-water interactions that may reduce reservoir porosity and permeability and may exacerbate downstream scaling. The publications included in this submission aim to assess the geochemical impact of CO2 on geothermal energy production by analyzing the geochemistry of existing geothermal fields with elevated natural CO2, to measure realistic rock-water rates for geothermal systems using laboratory and field-based experiments, and to develop reactive transport models using the filed-based rates to simulate production scale impacts.

Under the Federal Technology Transfer Act (FTTA), Federal Agencies can patent inventions developed during the course of research. These technologies can then be licensed to businesses or individuals for further development and sale in the marketplace. These technologies relate to treatment of contaminated sites.

Under the Federal Technology Transfer Act (FTTA), Federal Agencies can patent inventions developed during the course of research. These technologies can then be licensed to businesses or individuals for further development and sale in the marketplace. These technologies relate to methods of managing and remediating waste.

Under the Federal Technology Transfer Act (FTTA), Federal Agencies can patent inventions developed during the course of research. These technologies can then be licensed to businesses or individuals for further development and sale in the marketplace. These technologies relate to water monitoring and treatment technologies.

Midwest Geological Sequestration Consortium, Phase II, Evaluation of CO2 Capture Options from Ethanol Plants.

Injection and observation data from two Frio Brine Pilot experiments conducted near Houston, Texas by the Gulf Coast Carbon Center. The items in the "Frio Documents" folder provide details about the project and the data is provided in two folders Frio I and Frio II.

Online web mapping tool for visualization and simple analysis of Earth-energy data files from public and DOE related sources. Geocube allows users to upload and visualize their own datasets but also comes preloaded with individual spatial datasets as well as spatial data collections that align to topical themes.

A comprehensive monitoring, mitigation and verification (MMV) plan is critical to the success of any geological carbon sequestration project utilized as a method of reducing CO2 emissions to the atmosphere. Beginning in October, 2005 and running through September, 2009 the Zama Oil Field in northwestern Alberta, Canada has been the site of acid gas (approximately 70% CO2 and 30% H2S) injection for the simultaneous purpose of enhanced oil recovery (EOR), H2S disposal, and sequestration of CO2. The Plains CO2 Reduction (PCOR) Partnership has conducted MMV activities at the site throughout this period while Apache Canada Ltd. has undertaken the injection and hydrocarbon recovery processes. This project has been conducted as part of the US Department of Energy (USDOE) and National Energy Technology Laboratory (NETL) Regional Partnership Program and includes the participation of Natural Resources Canada, the Alberta Department of Energy, the Alberta Energy & Utilities Board and the Alberta Geological Survey. In an effort to research caprock integrity and the risk of leakage during these field operations a first order geomechanical characterization has been undertaken of the injection reservoir, comprising the Keg River Formation and its Zama Member, and the overlying Muskeg Formation caprock. This poster will summarize key data obtained from a laboratory and wireline log-based analysis of the petrophysical and mechanical properties, and the in-situ stress state in this setting. Vertical stress estimates were determined by integrating bulk density logs in the area, while accounting for the unlogged portion above the surface casing shoe. Horizontal stress magnitudes in the caprock and reservoir were estimated from regional and local stress data for this part of Alberta. Dedicated stress tests such as a mini-frac, a microfrac profile, or an extended leak-off test have not been conducted in the caprock to date in this field. Minimum and maximum in-situ horizontal principal stress orientations in the Zama field and surrounding area, measured within and above the injection interval, were determined from borehole breakouts. Vertical and horizontal in-situ stress changes have occurred within the reservoir and surrounding caprock due to initial production in the pinnacle reef, subsequent water flooding, and most recently acid gas injection. The prediction of these stress changes is a complex function of the reef geometry, the poro-elastic response of the reservoir, pore pressure changes over time in the reef and reservoir, and possibly temperature changes. For this poster, only the horizontal stress changes due to poro-elastic effects have been considered. 3D geomechanical modelling will be used to simulate the more complex problem once the mechanical properties and in-situ stresses are adequately constrained. Basic porosity and unstressed permeability distributions from two cored intervals through the Zama Member and Keg River Formation in two pinnacle reefs in the setting are summarized. Ultrasonic shear and compressional wave velocity measurements have been made under unconfined and confined stress conditions on anhydrite and dolomite from the Muskeg Formation caprock. Triaxial rock strength and unconfined compressive strength (UCS) tests are summarized using Mohr Coulomb and Hoek Brown failure criteria. Static and dynamic elastic properties measured under anisotropic stress conditions are compared. A Schmidt rebound hammer was used to develop a profile of pseudo-static Young’s moduli and UCS though the Muskeg Formation caprock and portions of the Keg River Formation in two wells. Dynamic log-derived elastic properties and their static equivalents were determined for the Muskeg and Keg River Formations in two wells. In order to do this a synthetic shear velocity relationship was developed using recent data from an offset well in the region. These log-derived properties are compared to the static laboratory and Schmidt hammer derived data. Pore volume compressibility tests were also made on a select number of core plugs of the Keg River Formation under relevant reservoir pore pressure and stress conditions, along with stress-dependent permeability and elastic properties. Statistical relationships describing the petrophysical and mechanical properties of the rocks investigated in this study are presented. Key learnings with regard to the heterogeneity of the vuggy dolomitic reservoir versus the evaporitic caprock are highlighted. The data presented in this poster have a variety of applications to EOR and CO2 sequestration in pinnacle reefs of the type being investigated in the Zama field. In addition to caprock integrity, the data can be used to assess optimal injection strategies, design well drilling, completion and stimulation programs, develop and interpret reservoir monitoring data, and conduct coupled geomechanical-reservoir simulation studies of acid gas injection.

Poster presentation given at GHGT-9.

National Energy Technology Laboratory's Energy Exchange Database for group NATCARB. Includes data on the location and size of stationary CO2 sources in the United states and the size and location that can store carbon. Also includes on sequestration brine composition Internet Archive URL: https://web.archive.org/web/2019*/https://edx.netl.doe.gov/group/natcarb

Vertical Seismic Profile data collected in 2009 and 2010 as part of SECARB Phase III Early Test at Cranfield oilfield in Mississippi to determine CO2 induced change from seismic response. Data divided into 3D VSP and Offset VSP folders. Associated Publications: Daley, T. M., Hendrickson, J., & Queen, J. H. (2014). Monitoring CO2 Storage at Cranfield, Mississippi with Time-Lapse Offset VSP – Using Integration and Modeling to Reduce Uncertainty. Energy Procedia, 63, 4240-4248. doi:10.1016/j.egypro.2014.11.459

Borehole gravity measurements obtained during the SECARB project at the Cranfield oil site in Mississippi from CFU31-F2 and CFU31-F3 wells. Data was used to calculate density changes within the Cranfield reservoir and to test borehole gravity performance compared to a variety of other methods for monitoring the injected CO2 plume. Associated Publications: Dodds, K., Krahenbuhl, R., Reitz, A., Li, Y., Hovorka, S. D., 2013, Evaluation of time lapse borehole gravity for CO2 plume detection SECARB Cranfield: International Journal of Greenhouse Gas Control.

Borehole logs from the SECARB project at the Cranfield oil site in Franklin, Mississippi . Well logs are a part of the geologic characterization phase of SECARB; CFU 31F-1, CFU 31F-2, CFU 31F-3 well logs from Detailed Area of Study (DAS) and other well logs. Associated Publications: Butsch, R., Brown, A. L., Bryans, B., Kolb, C., Hovorka, S. D., 2013, Integration of well-based subsurface monitoring technologies: lessons learned at SECARB study, Cranfield, MS: International Journal of Greenhouse Gas Control https://doi.org/10.1016/j.ijggc.2013.06.010.

Distributed Temperature Sensing data files collected during the SECARB project from Detailed Area of Study wells (CFU F-1, F-2, F-3) at Cranfield oil site in Mississippi. Associated Publications: Nuñez-López, V., Muñoz-Torres, J., and Zeidouni, M., 2014, Temperature monitoring using distributed temperature sensing (DTS) technology: Energy Procedia, v. 63, p. 3984–3991, doi:10.1016/j.egypro.2014.11.428.

Electrical Resistance Tomography Data collected as part of SECARB project at Cranfield oil site in Mississippi. Associated Publications: Carrigan, C.R., Yang, X., LaBrecque, D.J., Larsen, D., Freeman, D., Ramirez, A.L., Daily, W., Aines, R., Newmark, R., Friedmann, S. J., Hovorka, S., 2013. Electrical resistivity tomographic monitoring of CO2 movement in deep geologic reservoirs. Int. J. of Greenhouse Gas Control, 18, 401-408. Yang, X., Chen, X., Carrigan, C.R. & Ramirez, A.L., 2014. Uncertainty quantification of CO2 saturation estimated from electrical resistance tomography data at the Cranfield site, Int J Greenh Gas Con, 27, 59-68.

Hydrotest, gas composition, injection fluid, mass spectrometer, and U-tube gas sample analysis data gathered during SECARB project at Cranfield oil site in Mississippi. Geochemical data collected as part of geologic characterization phase of SECARB. Associated Publications: Lu, J., Cook, P. J., Hosseini, S. A., Yang, C., Romanak, K. D., Zhang, T., Freifeld, B. M., Smyth, R. C., Zeng, H., and Hovorka, S. D., 2012, Complex fluid flow revealed by monitoring CO2 injection in a fluvial formation: Journal of Geophysical Research, v. 117, B03208, doi:10.1029/2011JB008939. Lu, J., Kharaka, Y. K., Thordsen, J. J., Horita, J., Karamalidis, A., Griffith, C., Hakala, J. A., Ambats, G., Cole, D. R., Phelps, T. J., Manning, M. A., Cook, P. J., and Hovorka, S. D., 2012, CO2‒rock‒brine interactions in Lower Tuscaloosa Formation at Cranfield CO2 sequestration site, Mississippi, U.S.A.: Chemical Geology, v. 291, p. 269‒277. Yang, C., Hovorka, S. D., Treviño, R. H., and Delgado-Alonso, J., 2015, Integrated framework for assessing impacts of CO2 leakage on groundwater quality and monitoring-network efficiency: case study at a CO2 enhanced oil recovery site: Environmental Science &Technology, v. 49, p. 8887–8898, doi:10.1021/acs.est.5b01574.

Picture and video records of SECARB field trips, DAS site, DAS instrumentation, and casing installations.

Midwest Geological Sequestration Consortium, Phase II, Sequestration and Enhanced Coal Bed Methane Pilot Project, Tanquary Farms Test Site, Wabash County, Illinois

Estimates the uncertainty in carbon accumulation potential from natural forest regrowth. Specifically, the uncertainty metric is calculated as the modeled sequestration rate (mean of 100 random forest models) divided by the standard error of the 100 random forest models. Uncertainty is presented as a ratio because areas with higher sequestration rates tend to have high standard errors for their sequestration rates; presenting error as a ratio standardizes the model error by the sequestration rate. Higher numbers represent greater uncertainty in the model. For reference, an error ratio of 0.5 means that the standard error of the random forest models is half as large as the mean output of the models for that pixel. The rate uncertainties were estimated over all forest and savanna biomes.Extent: Global, within forest and savanna biomesCitation: Cook-Patton, S.C., Leavitt, S.M., Gibbs, D. et al. Mapping carbon accumulation potential from global natural forest regrowth. Nature 585, 545–550 (2020).Credits: Cook-Patton, S.C., S.M. Leavitt, D. Gibbs, N.L. Harris, K. Lister, K.J. Anderson-Teixeira, R.D. Briggs, R.L. Chazdon, T.W. Crowther, P.W. Ellis, H.P. Griscom, V. Herrmann, K.D. Holl, R.A. Houghton, C. Larrosa, G. Lomax, R. Lucas, P. Madsen, Y. Malhi, A. Paquette, J.D. Parker, K. Paul, D. Routh, S. Roxburgh, S. Saatchi, J.van den Hoogen, W.S. Walker, C.E. Wheeler, S.A. Wood, L. Xu, B.W. Griscom. 2020. Mapping carbon accumulation potential from natural forest regrowth. Nature, in press. https://www.nature.com/articles/s41586-020-2686-x. This work resulted from a collaboration between The Nature Conservancy, World Resources Institute, and 18 other institutions.Resolution: 1 x 1 kmDate: Applicable to the first 30 years of natural forest regrowth. Related layers: Carbon accumulation potential from natural forest regrowth in reforestable areas, Carbon accumulation potential from natural forest regrowth in forest and savanna biomes

Links to papers and reports describing the structure and character of the Illinois Basin geology. Included are descriptions of the two reservoirs that are being modeled for the DDU feasibility project at University of Illinois, the St. Peter and Mt. Simon Sandstones.