National assessment of geologic carbon dioxide storage resources: methodology implementation

Blondes, Madalyn S.; Brennan, Sean T.; Merrill, Matthew D.; Buursink, Marc L.; Warwick, Peter D.; Cahan, Steven M.; Corum, Margo D.; Cook, Troy A.; Craddock, William H.; DeVera, Christina A.; Drake, Ronald M.; Drew, Lawrence J.; Freeman, Philip A.; Lohr, Celeste D.; Olea, Ricardo A.; Roberts-Ashby, Tina L.; Slucher, Ernie R.; Varela, Brian A.

doi:10.3133/ofr20131055

Cited by 33 publications

(27 citation statements)

References 13 publications

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“…Furthermore, oil reservoirs have been trapping oil inside them for millions of years and would thus form good CO 2 "traps", as well as having extensive operating histories, which is highly important in terms of safety [41]. Although CO 2 storage in reservoirs has less uncertainty than CO 2 storage in aquifers [42], there are still significant knowledge gaps in terms of the assessment of the risk of the underground storage of CO 2 [43].…”

Section: Environmental Impacts Of Co 2 -Eormentioning

confidence: 99%

A Review of CO2-Enhanced Oil Recovery with a Simulated Sensitivity Analysis

et al. 2016

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This paper reports on a comprehensive study of the CO 2 -EOR (Enhanced oil recovery) process, a detailed literature review and a numerical modelling study. According to past studies, CO 2 injection can recover additional oil from reservoirs by reservoir pressure increment, oil swelling, the reduction of oil viscosity and density and the vaporization of oil hydrocarbons. Therefore, CO 2 -EOR can be used to enhance the two major oil recovery mechanisms in the field: miscible and immiscible oil recovery, which can be further increased by increasing the amount of CO 2 injected, applying innovative flood design and well placement, improving the mobility ratio, extending miscibility, and controlling reservoir depth and temperature. A 3-D numerical model was developed using the CO 2 -Prophet simulator to examine the effective factors in the CO 2 -EOR process. According to that, in pure CO 2 injection, oil production generally exhibits increasing trends with increasing CO 2 injection rate and volume (in HCPV (Hydrocarbon pore volume)) and reservoir temperature. In the WAG (Water alternating gas) process, oil production generally increases with increasing CO 2 and water injection rates, the total amount of flood injected in HCPV and the distance between the injection wells, and reduces with WAG flood ratio and initial reservoir pressure. Compared to other factors, the water injection rate creates the minimum influence on oil production, and the CO 2 injection rate, flood volume and distance between the flood wells have almost equally important influence on oil production.

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Section: Environmental Impacts Of Co 2 -Eormentioning

confidence: 99%

A Review of CO2-Enhanced Oil Recovery with a Simulated Sensitivity Analysis

et al. 2016

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“…Because geologic uncertainty is inherent in CO 2 storage estimates and data are sparse, Heidug (2013) and others (e.g., USGS 2013; Causebrook 2014) have argued that probabilistic methods are the best approach to consider the limitations and characterize the uncertainty in CO 2 storage resource assessments. In Table 1, only the methodology for the USGS (2013) estimates of volumetric storage capacity is fully probabilistic (Brennan et al 2010;Blondes et al 2013;Brennan 2014).…”

Section: Potentially Critical Assumptionsmentioning

confidence: 99%

“…Similarly, the other cost estimates in Table 2 are based on availability of volumetric storage capacity in the potential storage formations that were included in these cost studies. Volumetric capacities for these cost studies were estimated based on storage coefficients (e.g., IEAGHG 2009) or efficiencies (e.g., Brennan et al 2010;Blondes et al 2013), and were not dynamic or pressure-limited CO 2 storage capacity estimates. Without considering active pressure management (brine extraction) Eccles et al (2012) demonstrated an inverse relationship between storage capacity and cost.…”

Section: Cost Estimates For Geologic Storage Of Comentioning

confidence: 99%

Cost Implications of Uncertainty in CO2 Storage Resource Estimates: A Review

Anderson

2016

Nat Resour Res

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Carbon capture from stationary sources and geologic storage of carbon dioxide (CO 2 ) is an important option to include in strategies to mitigate greenhouse gas emissions. However, the potential costs of commercial-scale CO 2 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 access those resources. Storage resource estimates are highly dependent on storage efficiency values or storage coefficients, which are calculated based on ranges of uncertain geological and physical reservoir parameters. If dynamic factors (such as variability in storage efficiencies, pressure interference, and acceptable injection rates over time), reservoir pressure limitations, boundaries on migration of CO 2 , consideration of closed or semi-closed saline reservoir systems, and other possible constraints on the technically accessible CO 2 storage resource (TASR) are accounted for, it is likely that only a fraction of the TASR could be available without incurring significant additional costs. Although storage resource estimates typically assume that any issues with pressure buildup due to CO 2 injection will be mitigated by reservoir pressure management, estimates of the costs of CO 2 storage generally do not include the costs of active pressure management. Production of saline waters (brines) could be essential to increasing the dynamic storage capacity of most reservoirs, but including the costs of this critical method of reservoir pressure management could increase current estimates of the costs of CO 2 storage by two times, or more. Even without considering the implications for reservoir pressure management, geologic uncertainty can significantly impact CO 2 storage capacities and costs, and contribute to uncertainty in carbon capture and storage (CCS) systems. Given the current state of available information and the scarcity of (data from) long-term commercial-scale CO 2 storage projects, decision makers may experience considerable difficulty in ascertaining the realistic potential, the likely costs, and the most beneficial pattern of deployment of CCS as an option to reduce CO 2 concentrations in the atmosphere.

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“…Descriptive summaries of these SAUs are presented herein. Geologic elements of each SAU are discussed, as is data employed in the methodology as defined in the Editors' Preface and others (2009), Brennan andothers (2010), and Blondes and others (2013). Also, factors and petrophysical properties related to geologic CO 2 storage and other geologic attributes that influence the potential CO 2 storage volumes are discussed in addition to the inputs for the calculations.…”

Section: Co2 Storagementioning

confidence: 99%

“…Excluding such areas from our assessment, the minimum, maximum, and most likely area of the SAU available for storage is 80, 95, and 90 percent, respectively. The methodology of Brennan and others (2010) and implementation guide of Blondes and others (2013) were used to determine the minimum and central tendency buoyant-trapping pore volumes and the maximum buoyant-trapping pore volume available for CO 2 storage. …”

Section: By Ernie R Sluchermentioning

confidence: 99%

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 <i>Geologic framework for the national assessment of carbon dioxide storage resources</i>

National assessment of geologic carbon dioxide storage resources: methodology implementation

Cited by 33 publications

References 13 publications

A Review of CO2-Enhanced Oil Recovery with a Simulated Sensitivity Analysis

A Review of CO2-Enhanced Oil Recovery with a Simulated Sensitivity Analysis

Cost Implications of Uncertainty in CO2 Storage Resource Estimates: A Review

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 <i>Geologic framework for the national assessment of carbon dioxide storage resources</i>

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