Relative Permeability Experiments of Carbon Dioxide Displacing Brine and Their Implications for Carbon Sequestration

Abstract

To mitigate anthropogenically induced climate change and ocean acidification, net carbon dioxide emissions to the atmosphere must be reduced. One proposed option is underground CO2 disposal. Large-scale injection of CO2 into the Earth's crust requires an understanding of the multiphase flow properties of high-pressure CO2 displacing brine. We present laboratory-scale core flooding experiments designed to measure CO2 endpoint relative permeability for CO2 displacing brine at in situ pressures, salinities, and temperatures. Endpoint drainage CO2 relative permeabilities for liquid and supercritical CO2 were found to be clustered around 0.4 for both the synthetic and natural media studied. These values indicate that relative to CO2, water may not be strongly wetting the solid surface. Based on these results, CO2 injectivity will be reduced and pressure-limited reservoirs will have reduced disposal capacity, though area-limited reservoirs may have increased capacity. Future reservoir-scale modeling efforts should incorporate sensitivity to relative permeability. Assuming applicability of the experimental results to other lithologies and that the majority of reservoirs are pressure limited, geologic carbon sequestration would require approximately twice the number of wells for the same injectivity.

Measurements of CO2‐brine relative permeability in Berea sandstone using pressure taps and a long core

“…1, which shows many recent measured CO 2 relative permeabilities in sandstone cores; 15,18,21,25,26,28,29 included for comparison is the well-referenced measurement of oil relative permeability in Berea sandstone by Oak et al 31 The reported CO 2 relative permeabilities in Berea sandstone (open gray symbols) and non-Berea Original Research Article: Measurements of CO 2 -brine relative permeability in Berea sandstone using pressure taps and a long core X Chen et al Figure 1. 1, which shows many recent measured CO 2 relative permeabilities in sandstone cores; 15,18,21,25,26,28,29 included for comparison is the well-referenced measurement of oil relative permeability in Berea sandstone by Oak et al 31 The reported CO 2 relative permeabilities in Berea sandstone (open gray symbols) and non-Berea Original Research Article: Measurements of CO 2 -brine relative permeability in Berea sandstone using pressure taps and a long core X Chen et al Figure 1.…”

“…1, which shows many recent measured CO 2 relative permeabilities in sandstone cores; 15,18,21,25,26,28,29 included for comparison is the well-referenced measurement of oil relative permeability in Berea sandstone by Oak et al 31 The reported CO 2 relative permeabilities in Berea sandstone (open gray symbols) and non-Berea Original Research Article: Measurements of CO 2 -brine relative permeability in Berea sandstone using pressure taps and a long core X Chen et al Figure 1. 15,18,21,25,26,28,29 sandstones (gray star and cross symbols) show two different trends (the gray dashed lines are guides for the eye), which are both well below the reported oil relative permeability over most of the range. 15,18,21,25,26,28,29 sandstones (gray star and cross symbols) show two different trends (the gray dashed lines are guides for the eye), which are both well below the reported oil relative permeability over most of the range.…”

“…20,25 This is surprising since CO 2 and oil are both non-wetting phases in sandstones, so they are expected to behave similarly. 20,25 This is surprising since CO 2 and oil are both non-wetting phases in sandstones, so they are expected to behave similarly.…”

“…14 It is well known that the low viscosity of CO 2 lowers the viscous forces in core studies; this in turn, makes capillary effects for the CO 2 -brine system relatively stronger when compared with the oil-brine system. 21,25,35,36 Bennion et al proposed to measure endpoint CO 2 relative permeability at different flow rates and fit the two parameters with an exponential function; then they corrected the endpoint CO 2 relative permeability by extrapolating this function to infinite flow rate. 21,25,35,36 Bennion et al proposed to measure endpoint CO 2 relative permeability at different flow rates and fit the two parameters with an exponential function; then they corrected the endpoint CO 2 relative permeability by extrapolating this function to infinite flow rate.…”

“…21,25,35,36 Bennion et al proposed to measure endpoint CO 2 relative permeability at different flow rates and fit the two parameters with an exponential function; then they corrected the endpoint CO 2 relative permeability by extrapolating this function to infinite flow rate. 10,12,21,25,33,35,36 On the other hand, Chen et al 37,38 and Kianinejad et al [39][40][41][42][43] introduced new unsteady-state methods that can locally measure pressure gradient, phase flux and saturation during two-phase and three-phase flows, which experimentally avoid the capillary end effect particularly for gas and supercritical phases and give more accurate CO 2 relative permeability data than conventional unsteady-state methods. They fit the flow rate versus overall pressure drop with a function; and by taking the derivative of this function, CO 2 relative permeability was determined at the inlet of the core.…”