Subterranean containment and long-term storage of carbon dioxide in unused aquifers and in depleted natural gas reservoirs

Koide, Hitoshi; Tazaki, Yoshiyuki; Noguchi, Yasuhisa; Nakayama, Sumie; Iijima, Masaki; Ito, Kazuitsu; Shindo, Yuji

doi:10.1016/0196-8904(92)90064-4

Cited by 172 publications

(58 citation statements)

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“…How much CO 2 can actually be sequestered in saline aquifers has been the subject of a number of studies, as well as a focus of major U.S. and international collaborative research programs (e.g., the U.S. Department of Energy (DOE) National Carbon Sequestration Database and Geographic Information System (NATCARB) and the International Energy Agency Greenhouse Gas R&D Programme (IEAGHG)). The capacity estimates produced by these and other studies vary considerably (Bachu et al, 2007), but first-order assessments at the global scale (Koide et al 1992) through more detailed assessments at the continental to national level (e.g., the Indian sub-continent by Holloway et al (2009) and the USDOE Sequestration Atlas for North America (Department of Energy (DOE), 2010)) repeatedly demonstrate that deep-saline aquifers could store up to centuries worth of current anthropogenic CO 2 emissions.…”

Section: Introductionmentioning

confidence: 99%

The impact of geologic variability on capacity and cost estimates for storing CO2 in deep-saline aquifers

et al. 2012

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While numerous studies find that deep-saline sandstone aquifers in the United States could store many decades worth of the nation's current annual CO 2 emissions, the likely cost of this storage (i.e. the cost of storage only and not capture and transport costs) has been harder to constrain. We use publicly available data of key reservoir properties to produce geo-referenced rasters of estimated storage capacity and cost for regions within 15 deep-saline sandstone aquifers in the United States. The rasters reveal the reservoir quality of these aquifers to be so variable that the cost estimates for storage span three orders of magnitude and average > $100/tonne CO 2 . However, when the cost and corresponding capacity estimates in the rasters are assembled into a marginal abatement cost curve (MACC), we find that~75% of the estimated storage capacity could be available for b $2/tonne. Furthermore,~80% of the total estimated storage capacity in the rasters is concentrated within just two of the aquifers-the Frio Formation along the Texas Gulf Coast, and the Mt. Simon Formation in the Michigan Basin, which together make up only~20% of the areas analyzed. While our assessment is not comprehensive, the results suggest there should be an abundance of low-cost storage for CO 2 in deep-saline aquifers, but a majority of this storage is likely to be concentrated within specific regions of a smaller number of these aquifers.

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Section: Introductionmentioning

confidence: 99%

The impact of geologic variability on capacity and cost estimates for storing CO2 in deep-saline aquifers

et al. 2012

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“…There are numerous papers on the concept and evaluation of general feasibility of CO 2 injection into natural gas reservoirs for GCS and for enhanced gas recovery (Blok et al 1997;Koide et al 1992;van der Burgt et al 1992;Oldenburg et al 2001Oldenburg et al , 2004a. In addition, studies of thermal effects of injecting high-pressure CO 2 into low-pressure depleted reservoirs have been made (Oldenburg 2007;Maloney and Briceno 2009;Mathias et al 2010).…”

Section: Prior Workmentioning

confidence: 99%

Injection, Flow, and Mixing of CO2 in Porous Media with Residual Gas

Oldenburg

Doughty

2010

Transp Porous Med

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Geologic structures associated with depleted natural gas reservoirs are desirable targets for geologic carbon sequestration (GCS) as evidenced by numerous pilot and industrial-scale GCS projects in these environments world-wide. One feature of these GCS targets that may affect injection is the presence of residual CH 4 . It is well known that CH 4 drastically alters supercritical CO 2 density and viscosity. Furthermore, residual gas of any kind affects the relative permeability of the liquid and gas phases, with relative permeability of the gas phase strongly dependent on the time-history of imbibition or drainage, i.e., dependent on hysteretic relative permeability. In this study, the effects of residual CH 4 on supercritical CO 2 injection were investigated by numerical simulation in an idealized one-dimensional system under three scenarios: (1) with no residual gas; (2) with residual supercritical CO 2 ; and (3) with residual CH 4 . We further compare results of simulations that use non-hysteretic and hysteretic relative permeability functions. The primary effect of residual gas is to decrease injectivity by decreasing liquid-phase relative permeability. Secondary effects arise from injected gas effectively incorporating residual gas and thereby extending the mobilegas plume relative to cases with no residual gas. Third-order effects arise from gas mixing and associated compositional effects on density that effectively create a larger plume per unit mass. Non-hysteretic models of relative permeability can be used to approximate some parts of the behavior of the system, but fully hysteretic formulations are needed to accurately model the entire system.

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“…The authors of the first publications speak of injecting anthropogenic carbon dioxide to geological structures, mainly unused aquifers, oil and gas fields and non-produced coal seams [3,14,15,16,19].…”

Section: Introductionmentioning

confidence: 99%

Analysis of reservoir properties and parameters of oil fields suitable for the application of CO2-EOR method

Uliasz-Misiak¹,

Kosowski²,

Lewandowska-Śmierzchalska³

2015

drill

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Subterranean containment and long-term storage of carbon dioxide in unused aquifers and in depleted natural gas reservoirs

Cited by 172 publications

References 1 publication

The impact of geologic variability on capacity and cost estimates for storing CO2 in deep-saline aquifers

The impact of geologic variability on capacity and cost estimates for storing CO2 in deep-saline aquifers

Injection, Flow, and Mixing of CO2 in Porous Media with Residual Gas

Analysis of reservoir properties and parameters of oil fields suitable for the application of CO2-EOR method

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