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

Transport in Porous Media (Impact Factor: 1.43). 10/2010; 90(1):201-218. DOI: 10.1007/s11242-010-9645-1

ABSTRACT 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 CH4. It is well known that CH4 drastically alters supercritical CO2 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 CH4 on supercritical CO2 injection were investigated by numerical simulation in an idealized one-dimensional system under three scenarios: (1) with
no residual gas; (2) with residual supercritical CO2; and (3) with residual CH4. 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 mobile-gas 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.

KeywordsGeologic carbon sequestration–Depleted gas reservoir–Enhanced gas recovery–Residual gas–Hysteretic relative permeability

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Available from: Curtis M. Oldenburg, Dec 19, 2013
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    • "Reference Approach Medium Remarks (Burton et al., 2009) Simulation Aquifer Change in injectivity with the injected volume (Hangx et al., 2013) Experimental No prominent effect on the rock strength due to CO 2 injection (Oldenburg and Doughty, 2011) "
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    ABSTRACT: CO2 injection for storage in subsurface geologic medium is one of the techniques developed in the past years to mitigate anthropological CO2. Prior to CO2 injection, it is essential to predict the feasibility of medium in terms of storage capacity, injectivity, trapping mechanisms, and containment. There have been many studies regarding techniques which can be applied to ensure the safety of CO2 injection. However, there are few studies indicating the importance of capillary trapping during and after CO2 injection. The aim of this study is to review the fundamentals of injectivity and its relationship with capillary trapping for CO2 storage in depleted oil and gas reservoirs. Considering the number of effective parameters which are associated with the injectivity and capillary trapping, it is recommended to perform a comprehensive analysis to determine the optimum injection rate and safe storage medium before operation.
    Journal of Natural Gas Science and Engineering 09/2015; 26:510-517. DOI:10.1016/j.jngse.2015.06.046 · 2.16 Impact Factor
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    • "Blanco et al. (2012) reported CH 4 levels as high as 6% in industrial emissions in Spain (generated by waste management); however, a study conducted by de Visser et al. (2008), in agreement with the European Enhanced Capture (ENCAP) project, suggested a limit of 4% CH 4 in gas injection streams. CH 4 can also be present as a native gas prior to injection (Taggart, 2010; Oldenburg and Doughty, 2011; Hosseini et al., 2012). The production of methane by methane-producing bacteria is also a source of CH 4 within storage reservoirs (Leu et al., 2011). "
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    ABSTRACT: The sequestration of carbon dioxide (CO 2) in deep underground reservoirs has been identified as an important strategy to decrease atmospheric CO 2 levels and mitigate global warming, but potential risks on overlying aquifers currently lack a complete evaluation. In addition to CO 2 , other gasses such as methane (CH 4) may be present in storage reservoirs. This paper explores for the first time the combined effect of leaking CO 2 and CH 4 gasses on the fate of major, minor and trace elements in an aquifer overlying a potential sequestration site. Emphasis is placed on the fate of arsenic (As) and cadmium (Cd) released from the sediments or present as soluble constituents in the leaking brine. Results from macroscopic batch and column experiments show that the presence of CH 4 (at a concentration of 1% in the mixture CO 2 /CH 4) does not have a significant effect on solution pH or the concentrations of most major elements (such as Ca, Ba, and Mg). However, the concentrations of Mn, Mo, Si and Na are inconsistently affected by the presence of CH 4 (i.e., in at least one sediment tested in this study). Cd is not released from the sediments and spiked Cd is mostly removed from the aqueous phase most likely via adsorption. The fate of sediment associated As [mainly sorbed arsenite or As(III) in minerals] and spiked As [i.e., As 5+ ] is complex. Possible mechanisms that control the As behavior in this system are discussed in this paper. Results are significant for CO 2 sequestration risk evaluation and site selection and demonstrate the importance of evaluating reservoir brine and gas stream composition during site selection to ensure the safest site is being chosen.
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    • "Additionally, when buoyancy is ignored, the model results will overestimate injection-induced horizontal migration of CO 2 (i.e., the actual near-field horizontal spreading would be slightly less when buoyancy is included). Even though the viscosity of pure CO 2 can be significantly larger than that of pure CH 4 (Oldenburg and Doughty 2010), for simplicity, we assume that the viscosity of the resident gas phase is equal to that of the injected gas. Figure 1 "
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    ABSTRACT: Injecting CO2 into a subsurface formation causes a buildup of pressure in the vicinity of the injection well. While a large injection rate can reduce the cost associated with injection, an indefinitely large injection rate can result in excessive formation damage. To obtain an optimal injection rate without exceeding the safe pressure limits, one will like to have some knowledge of the transient pressure buildup characteristics resulting from a particular injection rate. While elaborate numerical simulations can provide reliable pressure buildup predictions, they require extensive knowledge about the formation, which is normally not available at the start of an injection process. To alleviate this problem, using some simplifying assumptions, we have developed a solution to predict the transient buildup of pressure resulting from injection of supercritical carbon dioxide from a partially penetrating well into a gas reservoir. The solution in space and time is first obtained in the Fourier–Laplace transform space, and then inverted back into real space (in cylindrical coordinates) and time. We use the solution to study pressure transient characteristics for different formation permeabilities and anisotropy ratios. Results obtained using the solution compared well with those from numerical simulations.
    Transport in Porous Media 02/2011; 91(3). DOI:10.1007/s11242-011-9879-6 · 1.43 Impact Factor
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