Sensitivity Study of Simulation Parameters Controlling CO2 Trapping Mechanisms in Saline Formations

Abstract

The primary purpose of this study is to understand quantitative characteristics of mobile, residual, and dissolved CO 2 trapping mechanisms within ranges of systematic variations in different geologic and hydrologic parameters. For this purpose, we conducted an extensive suite of numerical simulations to evaluate the sensitivities included in these parameters. We generated two-dimensional numerical models representing subsurface porous media with various permutations of vertical and horizontal permeability (k v and k h ), porosity (φ), maximum residual CO 2 saturation (S max gr ), and brine density (ρ br ). Simulation results indicate that residual CO 2 trapping increases proportionally to k v , k h , S max gr and ρ br but is inversely proportional to φ. In addition, the amount of dissolution-trapped CO 2 increases with k v and k h , but does not vary with φ, and decreases with S max gr and ρ br . Additionally, the distance of buoyancy-driven CO 2 migration increases proportionally to k v and ρ br only and is inversely proportional to k h , φ, and S max gr . These complex behaviors occur because the chosen sensitivity parameters perturb the distances of vertical and horizontal CO 2 plume migration, pore volume size, and fraction of trapped CO 2 in both pores and formation fluids. Finally, in an effort to characterize complex relationships among residual CO 2 trapping and buoyancy-driven CO 2 migration, we quantified three characteristic zones. Zone I, expressing 123 808 W. S. Han et al.the variations of S max gr and k h , represents the optimized conditions for geologic CO 2 sequestration. Zone II, showing the variation of φ, would be preferred for secure CO 2 sequestration since CO 2 has less potential to escape from the target formation. In zone III, both residual CO 2 trapping and buoyancy-driven migration distance increase with k v and ρ br .

Laboratory Measurements of CO2-H2O Interfacial Tension at HP/HT Conditions: Implications for CO2 Sequestration in Deep Aquifers

“…Potential subsurface CO 2 disposal and storage candidates include depleted oil and gas reservoirs (Krumhansl, et al, 2002;Le Gallo et al, 2002;Oldenburg and Benson, 2002;House, et al 2003;Seo and Mamora, 2003;Pawar, et al 2004;Sobers et al, 2004;Barrufet et al, 2010;and Oldenburg and Doughty, 2010 ); coalbed methane and shale gas reservoirs (Plug, et al, 2008;Jikich, et al, 2009;Koperna and Riestenberg, 2009;and Schepers, et al, 2009); and deep saline or brackish aquifers (Pruess et al, 2001;Kumar et al, 2005;Ozah et al, 2005;Izgec et al, 2008;Nghiem et al, 2009;Fang et al;and Han et al, 2011).…”

Sensitivity of injection costs to input petrophysical parameters in numerical geologic carbon sequestration models

“…Since this study was focused on unfractured conditions, these low intrinsic permeability simulations were not included in the final results. The range of porosity values tested was based on the simulation studies conducted by Doughty (2010) and Han et al (2011). The van Genuchten m values came from the study by Cropper et al (2011) and represent both different porous media and measurement methods.…”

“…Multiphase flow models focus on the phase transition behavior of CO 2 , buoyancy contrasts between CO 2 and brine, solubility of CO 2 in brine, leakage through abandoned wells or faults, precipitation of salt in brine, and three-phase relative permeability relationships. Heat transport is an important process in CO 2 sequestration modeling because many transport mechanisms are temperature dependent, relating mainly to cooling due to decompression of supercritical CO 2 (Gupta, 2008;Doughty, 2010;Han et al, 2011;Heath et al, 2012). Reactive transport models can simulate mineral dissolution and precipitation and their associated changes to petrophysical parameters as well as aquifer acidification.…”

“…Injection of CO 2 on site and the monitoring of its migration have provided additional information for fine-tuning numerical simulations of subsurface CO 2 sequestration (Doughty et al, 2008;Sakurai et al, 2005). Not all GCS simulation studies are site-specific, and a number of published studies have used similar generic parameters combined with a simple geologic model (e.g., Burton et al, 2009;Esposito and Benson, 2010;Han et al, 2011;Mathias et al, 2011Mathias et al, , 2013Nordbotten et al, 2005;Nordbotten and Celia, 2006). Simulations of geochemical reactions, multiphase flow, and heat transport in model saline aquifers using have been run by Pruess et al (2003) to determine the amounts of CO 2 that can be stored given certain conditions.…”

“…Simulations of geochemical reactions, multiphase flow, and heat transport in model saline aquifers using have been run by Pruess et al (2003) to determine the amounts of CO 2 that can be stored given certain conditions. Some researchers have looked at the sensitivity of numerical multiphase flow models to variations in selected petrophysical parameters due to heterogeneity when modeling geologic storage of CO 2 (Han et al, 2011;Doughty, 2010;Sifuentes et al, 2009;Juanes et al, 2006;Mo and Akervoll, 2005). Variations in the costs of carbon capture, transport, and storage have also been investigated (Heath et al, 2012;Middleton et al, 2012;Poiencot et al, 2012;Cinar et al, 2008;McCoy and Rubin, 2009).…”