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

Transport in Porous Media (Impact Factor: 1.55). 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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    ABSTRACT: During CO2 injection into brine aquifers-containing residual and/or dissolved CH4, three distinct regions develop: (1) a single-phase, dry-out region around the well-bore filled with pure supercritical CO2; (2) a two-phase, two-component system containing CO2 and brine; and (3) a two-phase, two-component system containing CH4, and brine. This article extends an existing analytical solution, for pressure buildup during CO2 injection into brine aquifers, by incorporating dissolved and/or residual CH4. In this way, the solution additionally accounts for partial miscibility of the CO2–CH4–brine system and the relative permeability hysteresis associated with historic imbibition of brine and current drainage due to CO2 injection and CH4 bank development. Comparison of the analytical solution results with commercial simulator, CMG-GEM, shows excellent agreement among a range of different scenarios. The presence of residual CH4 in a brine aquifer summons two competing phenomena, (1) reduction in relative permeability (phase interference), which increases pressure buildup by reducing total mobility, and (2) increase in bulk compressibility which decreases pressure buildup of the system. If initial CH4 is dissolved (no free CH4), these effects are not as important as they are in the residual gas scenario. Relative permeability hysteresis increased the CH4 bank length (compared to non-hysteretic relative permeability), which led to further reduction in pressure buildup. The nature of relative permeability functions controls whether residual CH4 is beneficial or disadvantageous to CO2 storage capacity and injectivity in a candid brine aquifer.
    Transport in Porous Media 94(3). · 1.55 Impact Factor
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    ABSTRACT: A large-scale carbon dioxide (CO2) injection pilot is ongoing at Cranfield, Mississippi, in a saline aquifer with high dissolved methane (CH4) content, employing one injection well and two observation wells. The breakthrough of CH4 and CO2 at the observation wells provides insights to phase partitioning and the multipath nature of flow through the formation. Injected CO2 is cooler than the formation temperature, making temperature another useful observation. Simulations of the first year of CO2 injection were conducted with the numerical simulator TOUGH2 and the equation of state module EOS7C, which includes CO2, CH4, and H2O, using an axisymmetric model with layering based on well logs from the injection well. Although the simplification of an axisymmetric model precludes study of formation dip or lateral heterogeneity, its simple structure enables a focus on physical processes involving the phase partitioning of CH4 and CO2, and temperature effects. Field observations that the model reproduces include the arrival of a bank of free-phase CH4 ahead of the main CO2 plume at each observation well, and non-monotonic changes in CH4 and CO2 mole fraction as a function of time, suggesting that multiple distinct flow paths exist between the injection well and the observation wells, each with its own bank of free-phase CH4 leading the CO2. Model results are compared with temperature observations made in the field with a Distributed Temperature Sensor (DTS) system, suggesting that a well-defined thermal response reached the near observation well within the seven-month monitoring period, but not the more distant observation well. © 2013 Society of Chemical Industry and John Wiley & Sons, Ltd
    Greenhouse Gases: Science and Technology 12/2013; 3(6). · 2.92 Impact Factor
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