Investigation of uncertainty in CO2 reservoir models: A sensitivity analysis of relative permeability parameter values

Abstract

Numerical reservoir models of CO 2 injection in saline formations rely on parameterization of laboratorymeasured pore-scale processes. We performed a parameter sensitivity study and Monte Carlo simulations to determine the normalized change in total CO 2 injected using the finite element heat and mass-transfer code (FEHM) numerical reservoir simulator. Experimentally measured relative permeability parameter values were used to generate distribution functions for parameter sampling. The parameter sensitivity study analyzed five different levels for each of the relative permeability model parameters. All but one of the parameters changed the CO 2 injectivity by <10%, less than the geostatistical uncertainty that applies to all large subsurface systems due to natural geophysical variability and inherently small sample sizes. The exception was the end-point CO 2 relative permeability, 2 , the maximum attainable effective CO 2 permeability during CO 2 invasion, which changed CO 2 injectivity by as much as 80%. Similarly, Monte Carlo simulation using 1000 realizations of relative permeability parameters showed no relationship between CO 2 injectivity and any of the parameters but 2 , which had a very strong (R 2 =0.9685) power law relationship with total CO 2 injected. Model sensitivity to 2 points to the importance of accurate core flood and wettability measurements.

Using Heat as a Predictor of CO2 Breakthrough in Highly Heterogeneous Reservoirs

“…Interestingly, phase interference between CO 2 and water can also drive pressure gradients at the leading edge of the CO 2 plume (Pollyea, ). Recent numerical studies show that relative permeability effects may cause variability in CO 2 injection pressure (Pollyea, ; Yoshida et al, ). For example, Pollyea () utilizes numerical simulations to study how the uncertainty associated with relative permeability can affect a CO 2 injection.…”

Two risk metrics for CO2storage reservoirs with varying domain size, heterogeneity, and injection rate

“…In this study, the sensitivity of relative permeability was not investigated. Other studies have shown that the maximum impact of relative permeability is found near the well, at least during the injection phase, and this study is focused on impacts far from the well bore. For similar reasons, capillary pressure between the supercritical CO 2 and brine was considered to be negligible in the simulations, given the relatively large pore sizes in typical storage reservoirs, the varying wettability of such systems (, and the fact that the interfacial tension between CO 2 and brine initially decreases with pressure and then levels off to some pseudo‐plateau value in the range of 20–30 mN/m .…”

“…29,30 Many of these studies have been helpful in increasing our fundamental knowledge of the processes at small to regional scale. At the reservoir scale, there have been many simulation and sensitivity studies of CO 2 injection useful in defining the effect of boundary conditions, 31 relative permeability, [32][33][34] and other parameters 35 on the behavior of pressure and saturation. A recent report 36 showed that the temporal evolution of the areal extent of the differential pressure plume and the saturation plume are key metrics for carbon storage risk.…”

Development of quantitative metrics of plume migration at geologic CO2 storage sites

“…We used linear relative permeability and capillary pressure models in these simulations. It has long been recognized that relative permeability and capillary pressure models influence plume migration . While the metrics presented here can help investigate this issue, this is beyond the scope of the current paper.…”