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All sourcesNASA NTRSDOE OSTI
DOE OSTI2020

SECARB Semi-Annual Field Review Reports - Early Test

The Southern States Energy Board (SSEB) managed the overall Southeast Regional Carbon Sequestration Partnership (SECARB) Phase III project and The Bureau of Economic Geology (BEG), at the University of Texas at Austin, managed all activities associated with the Early Test field site near Cranfield, Mississippi (the Early Test or Cranfield Project). BEG was assisted in the management of site activities by Sandia Technologies (Sandia). BEG and Sandia implemented reporting procedures that included monthly and quarterly technical progress reports, as well as periodic reporting on key field activities. Subsequent sections of this report catalog the field activities and are organized in a semiannual chronology. The Cranfield Project was located approximately 12 miles east of Natchez, Mississippi. Denbury Onshore, LLC, began operating a commercial CO 2 flood of the field (using the subsurface injection of CO 2 for EOR) in June 2008. Carbon dioxide from the Jackson Dome, a natural source near Jackson, Mississippi, was delivered to the Cranfield oilfield via pipeline. Beginning in October 2008, the SECARB Early Test team characterized the surface and subsurface of the Cranfield site. During the field test CO 2 was injected into the lower Tuscaloosa Formation, a regionally extensive saline formation with the potential to hold millions of tons of CO 2 emissions. By January 2015, the team injected more than 11 million metric tons of CO 2 and monitored a total stored CO 2 mass of 5,326,975 metric tons. SECARB’s study operations occurred in four integrated research program areas within Cranfield field: (1) the High Volume Injection Test area (HiVIT); (2) the Detailed Area of Study (DAS); (3) the Geomechanical area; and (4) the near-surface observatory, also called the “P-site.” Carbon dioxide injection activities were conducted at the HiVIT and the DAS. Figure 1.1-1 provides a depiction of the DAS.

01 COAL, LIGNITE, AND PEAT↗
DOE OSTI2023

CO 2 /Brine/Rock Interactions in the Cedar Keys-Lawson Formation

It has been reported that among the various geologic storage options, deep saline aquifers have the largest estimated capacity for CO 2 storage. Obtaining knowledge of possible artificially geochemically induced changes to the permeability and porosity of host CO 2 storage deposits will enable us to gain insight on long-term reservoir behavior under CO 2 storage conditions. An experimental study of the interaction of CO 2 /brine/rock on saline formations was conducted in a static system under CO 2 storage conditions. Chemical interactions in the Cedar Keys-Lawson Formation carbonate during exposure to CO 2 and brine under sequestration conditions were studied. Samples were exposed to the simulated in-situ reaction conditions for one and six months. The samples were exposed to a model brine at 55 °C and CO 2 pressure of 23.8 MPa (3,500 psig). Computed tomography (CT), x-ray diffraction (XRD), scanning electron microscopy (SEM)-energy dispersive x-ray spectroscopy (EDS), brine composition, core porosity, and core permeability analyses were conducted prior to and after the exposure experiments. Preliminary permeability measurements obtained from the core samples showed changes after they were exposed to CO 2 -saturated brine for one and six months. This observation suggests that mineral dissolution and mineral precipitation could occur in the host deposit altering its characteristics for CO 2 storage over time. The 3D images of the pore space clearly illustrate the degree of dissolution that occurred during exposure. It is noted that the dissolution that occurred during the six-month exposure could have enhanced the connectivity between voids. This may contribute the increase of permeability after the CO 2 /brine exposure. In addition, the primary minerals comprising the core are dolomite and gypsum. Both minerals could dissolve in the CO 2 /brine environment resulting in the increase of permeability after the six-month exposure.

58 GEOSCIENCES↗
DOE OSTI2024

Caprock Remains Water Wet Under Geologic CO 2 Storage Conditions

Abstract Carbon storage technology is primarily targeted in saline formations, which is a porous rock matrix filled with brine, sealed with a low permeability caprock. There are significant variations of CO 2 wetting properties, typically reported in the literature as contact angle of CO 2 and brine interacting with a rock material, suggesting that CO 2 could become wetting under geostorage conditions and negatively impact containment effectiveness. Here, we performed the first controlled laboratory measurements of CO 2 ‐brine contact angles on shale rocks from low permeability sealing formations with distinctive mineralogic properties—calcite‐rich, quartz‐rich, and dolomite‐rich. We targeted temperatures at 40° and 100°C, pressures at 8.3, 34.5, and 62.1 MPa, and salinity at 35,000 and 260,000 ppm. Results show no significant change in contact angle with mineralogy, temperature, pressure, salinity, and CO 2 bubble size. We conclude that caprocks will remain water‐wet at geologic CO 2 storage conditions and will not lose their capillary sealing capacity.

Tapriyal, Deepak↗
DOE OSTI2024

CO2 Saline Storage Talk at the University of Wyoming

These are slides presented virtually to a class on Carbon Capture and Storage (CCS) at the University of Wyoming in Laramie WY. The talk was on the basics of carbon storage in saline formations and reviewed basic geology, important physical properties of CO2 and brine, how fluids flow in the subsurface, environmental risks associated with CO2 storage, the regulations governing CO2 saline storage, and high-level design considerations. The FECM/NETL CO2 Saline Storage Cost Model was used to illustrate how geologic properties vary in different regions of the US (PA, IL and WY) and how the performance of CO2 storage and the cost of CO2 CO2 saline storage depends on geology (October 23, 2024).

Morgan, David↗
DOE OSTI2024

CO 2 Storage prospeCtive Resource Estimation Excel aNalysis (CO 2 -SCREEN) User’s Manual: Python_V5.0

This user’s manual guides the use of the National Energy Technology Laboratory’s (NETL) CO 2 Storage prospeCtive Resource Estimation Excel aNalysis (CO 2 -SCREEN) tool, which was developed to aid users screening geologic formations for prospective CO 2 storage resources. This manual is specific to the CO 2 -SCREEN 5.0 version which is based in Python. The 5.0 version of CO 2 -SCREEN adds in newly updated storage efficiency factors for saline formations for open storage reservoirs and new capability to calculate CO 2 storage in closed and semi-closed storage reservoirs.

58 GEOSCIENCES↗
DOE OSTI2024

GEESS as a Mechanism to Facilitate the Commercialization of Geologic Carbon Sequestration

This is a presentation featuring an overview of the Geoanalytical Economic Evaluation of Saline Storage (GEESS) project and latest results. The GEESS project has worked towards characterizing 57 geologic saline formations targeted for geologic carbon sequestration (GCS) using publicly available datasets. The GEESS system consists of high spatial resolution datasets (up to a 5 km grid spacing) that characterize critical geologic parameters such as depth, thickness, porosity, permeability, fracture pressure, and more. Further, GEESS geologic data were exercised using the FECM/NETL Saline Storage Cost Model (CO2_S_COM) to estimate CO2 plume sizes and the first-year break-even price of CO2 at the grid point level. GEESS is now available on NETL’s Energy Data Exchange (EDX).

Eppink, Jeffrey↗
DOE OSTI2024

Modeling the Cost of Onshore CO2 Pipeline Transport and Onshore CO2 Saline Storage

This paper describes the FECM/NETL CO2 Transport Cost Model (CO2_T_COM), a technoeconomic model of CO2 transport by pipeline, and the FECM/NETL CO2 Saline Storage Cost Model (CO2_S_COM), a technoeconomic model of storage of CO2 in a deep, subsurface saline formation. The results of applying CO2_T_COM to calculate break-even CO2 prices to transport CO2 at different mass flow rates and different distances are presented. Similarly, CO2_S_COM is used to calculate the break-even CO2 price for storing CO2 in 314 potential storage formations across the US. These break-even prices are used to construct cost-supply curves for CO2 storage which are presented on a national and regional basis. CO2_T_COM and CO2_S_COM are the most comprehensive open source technoeconomic models available for analyzing CO2 pipeline transport and CO2 saline storage. To be presented at the SPE?AAPG/SEG Carbon Capture Utilization and Storage Conference in Houston, TX, March 11-13, 2024.

Morgan, David↗
DOE OSTI2023

Developing a roadmap for carbon capture, and storage in Oklahoma by assessing the viability of stacked storage

Abstract The Intergovernmental Panel on Climate Change concludes that CO 2 capture and storage (CCS) is critical for climate‐stabilizing energy transitions. In CCS, captured CO 2 is sequestered in saline aquifers within sedimentary basins. The CO 2 storage capacity and the rate of injection are functions of the geology of the saline aquifer, which is uncertain. To minimize impacts of this uncertainty, CCS projects could include backup plans, such as co‐locating geologic CO 2 storage (GCS) sites with or near existing CO 2 ‐enhanced oil recovery (CO 2 ‐EOR) operations. These “stacked storage” projects could hedge against uncertainty in the saline formation performance because captured CO 2 could be injected into either location in the event of unexpected events (e.g., the injectivity decreases). Here, we investigate the possibility and ramifications of developing CCS networks in Oklahoma that are amendable to stacked storage. We find that stacked storage is possible in Oklahoma but the counties with the lowest‐cost saline storage resources do not have existing CO 2 ‐EOR operations. At the systems level, we find it is slightly more expensive (e.g., $1/tCO 2 to $5/tCO 2 ) to site GCS in counties with CO 2 ‐EOR projects. This increased expense is largely due to increased CO 2 transportation costs because hundreds of km of additional pipeline is required to capture CO 2 from the lowest‐cost sources. Overall, our results suggest that it is optimal to build more pipelines and avoid injecting CO 2 in some of the lowest‐cost saline storage resources, to enable capturing CO 2 from the least‐cost sources. © 2023 Society of Chemical Industry and John Wiley & Sons, Ltd.

42 ENGINEERING↗
DOE OSTI2020

Using Machine Learning to Identify Optimum Prospects for Offshore Geologic CO 2 Storage and Enhanced Oil Recovery in the Gulf of Mexico

The SECARB Offshore Partnership is a government-industry partnership focused on assembling the knowledge base required for secure, long-term, large-scale CO 2 subsea storage in saline formations and mature oil reservoirs. The SECARB Offshore Partnership is evaluating potential storage opportunities in the Central and Eastern planning areas of the outer continental shelf (OCS) of the Gulf of Mexico. The evaluation focuses on active and depleted oil and gas fields and potentially associated CO 2 -enhanced oil recovery (CO 2 -EOR), as well as, deep saline storage resources. As part of Subtask 3.0 (Offshore Storage Resources Characterization) and Subtask 4.0 (Risk Assessment, Simulation, and Modeling), Oklahoma State University (OSU) is developing a machine learning system that employs the SAS Institute’s Viya platform with visual data mining and machine learning to identify and characterize optimum prospects for enhanced oil recovery and stacked storage in saline reservoirs. This report summarizes this effort to date and discusses the many variables that can be used to characterize these storage objectives, as well as, the design vision of the Viya machine learning system.

02 PETROLEUM↗
DOE OSTI2024

FECM/NETL CO 2 Saline Storage Cost Model (2024): User’s Manual

The U.S. Department of Energy's (DOE) Office of Fossil Energy and Carbon Management (FECM), in collaboration with the National Energy Technology Laboratory (NETL), has developed the FECM/NETL CO 2 Saline Storage Cost Model (CO2_S_COM). This Excel-based tool provides a comprehensive framework for estimating the costs and breakeven prices associated with storing carbon dioxide (CO 2 ) in deep saline formations. Designed from the perspective of a CO 2 storage site owner, the CO2_S_COM incorporates four integrated modules—project management, financial analysis, activity cost estimation, and geological evaluation—to deliver fast, robust, and actionable insights for evaluating project finances. This is the user's manual for CO2_S_COM. The model may be accessed at this link: FECM/NETL CO2 Saline Storage Cost Model CO2_S_COM 2024 (v4) - Submissions - EDX

54 ENVIRONMENTAL SCIENCES↗
DOE OSTI2023

NETL’s Perspective on Storage Efficiency and CO2-SCREEN

Carbon capture and storage (CCS) is a process that captures carbon dioxide (CO2) by separating it from anthropogenic emissions sources before atmospheric release and storing that CO2 in deep geologic reservoirs. CCS is a powerful method for reducing anthropogenic CO2 which can ultimately diminish the effects of climate change. Prospective CO2 storage resource is the amount of carbon dioxide that can be stored in a given geologic formation typically given as a mass (e.g., metric tons). Obtaining accurate estimates of CO2 storage resources is necessary for governments and industries to make energy-related policy decisions. Researchers at the National Energy Technology Laboratory (NETL) under the Department of Energy (DOE) developed a methods and a tool [CO2-SCREEN (Storage prospeCtive Resource Estimation Excel aNalysis) to estimate prospective carbon storage resources for saline formations, unconventional shale formations, and residual oil zones. The methods and tool provide CO2 storage and efficiency outputs in the form of probability estimates (i.e. P10 and P90) as well as partitioning storage and efficiency estimates based on storage mechanism (total, free phase, sorbed phase, and dissolution phase). This presentation will focus on how storage efficiency is calculated based on numerical modeling efforts, how it’s applied in the storage methods and tool, and then highlighting needs for future development.

Hanson, Angela Goodman↗
DOE OSTI2021

Permeability evolution of reservoir rocks interacting with CO2/brine under CO2 sequestration conditions

The Mount Simon formation in the Midwest region of the U.S. is considered as a potential candidate host reservoir for carbon storage. Obtaining knowledge of possible geochemically induced changes to the permeability and porosity of host CO2 storage sandstone will enable us to gain a deeper insight of the long-term reservoir behavior under the CO2 storage conditions. An experimental study of the interaction of CO2/brine/rock on saline formations in a static system under CO2 storage conditions was conducted.

Soong, Yee↗
DOE OSTI2025

Overview of the Geoanalytical Economic Evaluation of Saline Storage (GEESS) System

This report provides an overview on the Geoanalytical Economic Evaluation of Saline Storage (GEESS) system which characterized 57 geologic saline formations targeted for geologic carbon storage across the lower-48 U.S. states using publicly available resources. The GEESS system consists of high spatial resolution datasets (up to 5 km grid spacing) that provide key geologic parameters (e.g., depth, thickness, permeability), and estimates of CO 2 plume size and CO 2 first-year break-even price that were determined by exercising GEESS data through the FECM/NETL CO 2 Saline Storage Cost Model (CO2_S_COM). The GEESS geodatabase is available on NETL’s EDX at GEESS Geodatabase.

54 ENVIRONMENTAL SCIENCES↗
DOE OSTI2024

FECM/NETL CO2 Saline Storage Cost Model CO2_S_COM 2024 (v4)

The U.S. Department of Energy's (DOE) Office of Fossil Energy and Carbon Management (FECM), in collaboration with the National Energy Technology Laboratory (NETL), has developed the FECM/NETL CO2 Saline Storage Cost Model (CO2_S_COM). This Excel-based tool provides a comprehensive framework for estimating the costs and breakeven prices associated with storing carbon dioxide (CO2) in deep saline formations. Designed from the perspective of a CO2 storage site owner, the CO2_S_COM incorporates four integrated modules—project management, financial analysis, activity cost estimation, and geological evaluation—to deliver fast, robust and actionable insights for screening project finances.

CO2 storage↗
DOE OSTI2024

Subsurface H 2 Storage: A Williston Basin Commercial-Scale Resource Study

Poster for the 2024 NETL Resource Sustainability Project Review Meeting, Pittsburgh, Pennsylvania, April 2-4, 2024. This poster presents a commercial‑scale assessment of subsurface hydrogen storage potential in the North Dakota portion of the Williston Basin, evaluating saline formations, depleted oil and gas reservoirs, and salt formations. The study integrates laboratory characterization, reservoir simulation, and basinwide analysis to assess storage capacity, injectivity, recovery, and risks related to geochemical, microbial, and wellbore interactions. Results support the feasibility of large‑volume, secure hydrogen storage and provide a framework to guide future hydrogen commercialization and infrastructure development.

08 HYDROGEN↗
DOE OSTI2026

Hydrogeological assessment of CO2 containment assurance and wellbore integrity at a Gulf Coast storage site

Abstract A large-scale carbon capture and storage (CCS) initiative on the Texas Gulf Coast serves as a premier demonstration of the U.S. Department of Energy’s CarbonSAFE program. Targeting deep saline formations, specifically Oligo-Miocene deltaic sequences, the project aims to establish technical and commercial viability for geologic CO2 storage within a major industrial corridor. This study provides a rigorous hydrogeological assessment to support Class VI permitting by quantifying the high degree of containment security. Utilizing a compositional reservoir simulator, we developed a suite of 27 distinct simulation cases to evaluate vertical plume dynamics near both planned injection wells and proximal legacy infrastructure. To ensure numerical accuracy near wellbores, we implemented a refined mesh strategy, determining that a 5.6 ft × 5.6 ft grid refinement offered the optimal balance between computational efficiency and descriptive precision. The modeling framework utilized a systematic sensitivity-based approach to evaluate the mechanical redundancy of the subsurface system by performing a bounding analysis of wellbore interfaces against hypothetical high-permeability microannuli. By systematically isolating competing physical drivers, including permeability, porosity, gas hysteresis, thermal gradients, salinity, and solubility trapping (quantified via Henry’s law with dynamically adjusted coefficients), this work moves beyond binary assessments to establish a nuanced hierarchy of containment factors. The results confirm that primary trapping mechanisms (e.g., gas hysteresis and solubility), combined with the site's unique geomechanical stratigraphy, significantly restrict vertical mobility and reinforce the robust containment security of the reservoir. Baseline results demonstrate substantial vertical separation between the CO2 plume and the upper confining system, ensuring robust containment. Sensitivity analysis reveals that even under highly conservative bounding scenarios—assuming theoretical 10-Darcy pathways at specific wellbore locations—the 2,900-ft thick multi-layered confining zone remains a reliable barrier. In these hypothetical upper-bound cases, peak upward fluxes of CO2 and saltwater after 15 years of injection remain localized and dissipate rapidly within the lower sections of the confining interval, leaving the integrity of the seal uncompromised. Furthermore, the study identifies that while localized wellbore pathways define theoretical upper bounds of vertical migration, the Area of Review (AoR) is primarily sensitive to regional thermal gradients and hysteresis, which can influence the AoR by over 3,000 acres in pessimistic configurations. Also, primary trapping mechanisms, specifically gas hysteresis and solubility, work in tandem with the Gulf Coast’s unique geomechanical stratigraphy to significantly restrict vertical mobility. Ductile, smectite-rich mudstones facilitate natural borehole convergence and the self-healing of potential conduits, creating a natural geomechanical bridge that effectively mitigates migration potential at both current injection points and legacy-well locations. This comprehensive modeling effort demonstrates that the integration of high-resolution wellbore simulations and regional geomechanical observations confirms the long-term storage security of the studied site, providing a physics-based foundation for industrial-scale CCS deployments. This modeling framework establishes a baseline for future research into coupled geomechanical effects, such as time-dependent borehole convergence, to further refine long-term containment projections. Acknowledgements We thank the Gulf Coast Carbon Center (GCCC) at the Bureau of Economic Geology for foundational research support. We appreciate Alex Bump for technical guidance and David Hoffman for model mesh generation. This work used TACC’s Frontera cluster for simulations and CMG Ltd. software licenses provided to UT-Austin. This material is based upon work supported by the Department of Energy under Award Number DE-FE0032338. Disclaimer This material is based upon work supported by the U.S. Department of Energy’s Fossil Energy and Carbon Management Office under the CarbonSAFE program, award Number DE-FE0032338. The views expressed herein do not necessarily represent the views of the U.S. Department of Energy or the United States Government.

58 GEOSCIENCES↗