Peer Reviewed: Safe Storage of CO2 in Deep Saline Aquifiers

Bruant, Robert G.; Guswa, Andrew J.; Celia, Michael A.; Peters, Catherina A.

doi:10.1021/es0223325

Cited by 238 publications

(169 citation statements)

References 34 publications

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“…CO 2 geological storage is a promising means to mitigate CO 2 emission [1][2][3][4][5] and storage in deep saline aquifers appears to hold the largest potential capacity [4,[6][7][8]. The sequestration capacity, long-term CO 2 behavior in receptor formations, and the quantification of possible CO 2 leaks are the main concerns [2,4,9,10], and there remains a need to study the potential mobility of CO 2 dissolved in brines over a wide range of spatial and temporal scales [4,9,11], the CO 2 concentration distribution in saline aquifers, as well as the density distribution in geological media [8].…”

Section: Introductionmentioning

confidence: 99%

“…The sequestration capacity, long-term CO 2 behavior in receptor formations, and the quantification of possible CO 2 leaks are the main concerns [2,4,9,10], and there remains a need to study the potential mobility of CO 2 dissolved in brines over a wide range of spatial and temporal scales [4,9,11], the CO 2 concentration distribution in saline aquifers, as well as the density distribution in geological media [8]. This highlights the significance of research on CO 2 dissolution and the mass transfer of CO 2 dissolved in brines.…”

Section: Introductionmentioning

confidence: 99%

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Modeling mass transfer of CO2 in brine at high pressures by chemical potential gradient

Lü

et al. 2013

Sci. China Chem.

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To investigate long-term CO 2 behavior in geological formations and quantification of possible CO 2 leaks, it is crucial to investigate the potential mobility of CO 2 dissolved in brines over a wide range of spatial and temporal scales and density distributions in geological media. In this work, the mass transfer of aqueous CO 2 in brines has been investigated by means of a chemical potential gradient model based on non-equilibrium thermodynamics in which the statistical associating fluid theory equation of state was used to calculate the fugacity coefficient of CO 2 in brine. The investigation shows that the interfacial concentration of aqueous CO 2 and the corresponding density both increase with increasing pressure and decreasing temperature; the effective diffusion coefficients decrease initially and then increase with increasing pressure; and the density of the CO 2 -disolved brines increases with decreasing CO 2 pressure in the CO 2 dissolution process. The aqueous CO 2 concentration profiles obtained by the chemical potential gradient model are considerably different from those obtained by the concentration gradient model, which shows the importance of considering non-ideality, especially when the pressure is high.

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Section: Introductionmentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

Modeling mass transfer of CO2 in brine at high pressures by chemical potential gradient

Lü

et al. 2013

Sci. China Chem.

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“…Technologies that can capture CO2 from fossil fuels, either before or after combustion, are being considered as a strategy to limit the rising atmospheric concentration (1)(2)(3). Rather than being released into the atmosphere, CO2 could be injected into deep geological formations or dissolved in the deep ocean (4).…”

Section: Introductionmentioning

confidence: 99%

Initial Public Perceptions of Deep Geological and Oceanic Disposal of Carbon Dioxide

Palmgren

Morgan

Bruin

et al. 2004

Environ. Sci. Technol.

149

117

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Two studies were conducted to gauge likely public perceptions of proposals to avoid releasing carbon dioxide from power plants to the atmosphere by injecting it into deep geological formations or the deep ocean. Following a modified version of the mental model interview method, Study 1 involved face-to-face interviews with 18 nontechnical respondents. Respondents shared their beliefs after receiving basic information about the technologies and again after getting specific details. Many interviewees wanted to frame the issue in the broader context of alternative strategies for carbon management, but public understanding of mitigation strategies is limited. The second study, administered to a sample of 126 individuals, involved a closedform survey that measured the prevalence of general beliefs revealed in study 1 and also assessed the respondent's views of these technologies. Study results suggest that the public may develop misgivings about deep injection of carbon dioxide because it can be seen as temporizing and perhaps creating future problems. Ocean injection was seen as more problematic than geological injection. An approach to public communication and regulation that is open and respectful of public concerns is likely to be a prerequisite to the successful adoption of this technology.

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“…(Bruant et al, 2002). Sealing efficiency of the trapping barrier and of the wellbore cement plays a major role in determining the overall effectiveness of geological CO 2 storage projects.…”

Section: Carbon Capture and Storage (Ccs)mentioning

confidence: 99%

“…When successfully sealed and stored, some supercritical CO 2 will dissolve into the formation brine or precipitate as carbonate minerals as shown in Figure 1.2. These processes are known to further enhance the security of geological CO 2 storage (Bruant et al, 2002). Figure 1.2: CO 2 is injected as a supercritical fluid, some of which dissolves in the brine and some of which is trapped in precipitated mineral phases (Bruant et al, 2002).…”

Section: Carbon Capture and Storage (Ccs)mentioning

confidence: 99%

The Use of a pH-Triggered Polymer Gelant to Seal Cement Fractures in Wells

Tavassoli

Patterson

et al. 2016

SPE Drilling &Amp; Completion

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Summary The potential leakage of hydrocarbon fluids or carbon dioxide (CO2) out of subsurface formations through wells with fractured cement or debonded microannuli is a primary concern in oil-and-gas production and CO2 storage. The presence of fractures in a cement annulus with apertures on the order of 10–300 µm can pose a significant leakage danger with effective permeability in the range of 0.1–1.0 md. Leakage pathways with small apertures are often difficult for conventional oilfield cement to repair; thus, a low-viscosity sealant that can be placed into these fractures easily while providing a long-term robust seal is desired. The development of a novel application with pH-triggered polymeric sealants could potentially be the solution to plugging these fractures. The application is based on the transport and reaction of a low-pH poly(acrylic acid) polymer through fractures in strongly alkaline cement. The pH-sensitive microgels viscosify after neutralization with cement to become highly swollen gels with substantial yield stress that can block fluid flow. Experiments in a cement fracture determined the effects of the viscosification and gel deposition with real-time visual observation and measurements of pressure gradient and effluent pH. Although the pH-triggered gelling mechanism and rheology measurements of the polymer gel show promising results, the polymer solution undergoes a reaction caused by the release of calcium cations from cement that collapses the polymer network (syneresis). It produces an undesirable calcium-precipitation byproduct that is detrimental to the strength and stability of the gel in place. As a result, gel-sealed leakage pathways that were subjected to various degrees of syneresis often failed to hold backpressures. Multiple chemicals were tested for pretreatment of cement cores to remove calcium from the cement surface zone to inhibit syneresis during polymer placement. A chelating agent, sodium triphosphate (Na5P3O10), was found to successfully eliminate syneresis without compromising the injectivity of polymer solution during placement. Polymer-gel strength is determined by recording the maximum-holdback pressure gradients during liquid-breakthrough tests after various periods of pretreatment and polymer shut-in time. Cores pretreated with Na5P3O10 successfully held up to an average of 70 psi/ft, which is significantly greater than the range of pressure gradients expected in CO2-storage applications. The use of such inexpensive, pH-triggered polyacrylic acid polymer allows the sealing of leakage pathways effectively under high-pH conditions.

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Peer Reviewed: Safe Storage of CO2 in Deep Saline Aquifiers

Cited by 238 publications

References 34 publications

Modeling mass transfer of CO2 in brine at high pressures by chemical potential gradient

Modeling mass transfer of CO2 in brine at high pressures by chemical potential gradient

Initial Public Perceptions of Deep Geological and Oceanic Disposal of Carbon Dioxide

The Use of a pH-Triggered Polymer Gelant to Seal Cement Fractures in Wells

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