440529 Impacts of Relative Permeability on Subsurface CO2 Mineralization and Storage

Friday, November 13, 2015: 10:35 AM
250E (Salt Palace Convention Center)
Brian McPherson1, Vivek Patil2, Nathan Moodie2, Adam Olsen2, Daniel Stout3 and Richard Esser2, (1)Civil Engineering, University of Utah, Salt Lake City, UT, (2)Department of Civil and Environmental Engineering, University of Utah, Salt Lake City, UT, (3)Department of Civil and Environmental Engineering, University of Utah, Salt Lake city, UT

One of the greatest sources of uncertainty associated with forecasting subsurface CO2 storage capacity, and associated trapping mechanisms, is permeability heterogeneity.  And, an often-overlooked source of heterogeneity in permeability is the relative permeability function assumed, and its calibration. A seemingly common approach to relative permeability for CO2 storage simulation analyses, due to lack of information, is to assume a “typical” relative permeability function and assign parameters based on similar rock type and geologic setting. We evaluated how such a nearly-arbitrary approach to assigning relative permeability can impact forecasts of storage capacity, and mineralization trapping in particular. We developed and executed the same simulation model of a porous medium but with four different relative permeability curves (functions), and examined the evolution of gas saturation, calcite precipitation, and for a simulated fault, the fault porosity and fault sealing rate, for these different relative permeability formulations. Assigning one permutation as the “base case” for comparison, gas saturation varied considerably among the four models.  But, substantial differences in predictions of calcite precipitation were even more compelling. Accordingly, porosity evolution in the base-case model showed a trend where precipitated minerals formed early on and then dissolved in later stages of the simulations. Specifically, a ‘dissolution front’ moved up depth along flow pathways over time. For simulations of a generic fault zone with a marked contrast in porosity and permeability, using different relative permeability assignments also impacted predictions of fault self-sealing rates. At the top of the fault, each formulation predicted different sealing rates. For example, a van Genuchten formulation forecasted fault-sealing at almost twice the rate as a Corey formulation. The upshot of these results is that relative permeability assignment is a critical variable that must be calibrated with care; otherwise, perhaps a simple linear formulation will be just as meaningful as any other.

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