Application of CO2-Saturated Water Flooding as a Prospective Safe CO2 Storage Strategy

Abstract

In this study, According to the results of CO 2 solubility measurement tests at constant temperatures, an increase in CO 2 solubility values was observed for CO 2 -brine and CO 2 -oil systems when the equilibrium pressure increases. Furthermore, it was revealed that for both aforementioned systems, the solubility of CO 2 reduces when temperature increased. It was found that introducing CO 2 to the oil reservoirs through injection water provides great opportunity to lock large quantity of CO 2 inside the porous medium with high retention factor. Results of this study showed that both secondary and tertiary scenarios of CO 2 -saturated water flooding are favourable with the storage capacity between 34% to 45% of the injected CO 2 in the sand-pack model. In addition, the solubility trapping was shown to be the main CO 2 trapping mechanism during CO 2 -saturated water flooding. According to the results of this study, most of the injected CO 2 was trapped in the porous medium through dissolution in the reservoir fluids, i.e., solubility trapping. As an example, the flooding tests conducted in secondary mode at P = 10.3 MPa and T = 25 °C, showed that about 95% of the injected CO 2 can be trapped by dissolution mechanism into the reservoir oil and brine. In terms of oil recovery, it was found that the ultimate oil recovery factor of CO 2 -saturated water flooding is consistently more than that of conventional water flooding leading this technique to be a more viable option as a means of improved oil recovery technique. In this study, flooding tests conducted at pressure of P = 10.3 MPa and temperature of T = 25 °C, verified that injection of CO 2 -saturated water resulted in improving the conventional water flooding oil recovery factor by about 19.0% and 12.5% of OOIP for secondary and tertiary scenarios, respectively. Based on the results obtained in this work, it was concluded that mixing CO 2 with injected water noticeably provides permanent, safe, and practical CO 2 storage together with considerable oil recovery improvement in light oil systems.

An integrated evaluation of enhanced oil recovery and geochemical processes for carbonated water injection in carbonate rocks

“…Injection of CO2-enriched water for enhanced oil recovery and CO2 storage has received substantial attentions amongst oil industry and CCS stakeholders [ (Blackford, 1987) (Christensen, 1961) (Oelkers, et al, 2008) (Alizadeh, et al, 2014) (Mosavat & Torabi, 2014)].…”

Microscopy and image analysis of the micro-fabric and composition of saline rocks under different phaseCO2-Brine states

“…Shiflett et al, (2008) observed that the solubility of CO2 in ionic rich liquid shows unusual behaviors as CO2 dissolves in ionic liquid with no vapor pressure at low CO2 concentration but at high CO2 concentration there was immiscible layer (vapor-liquid equilibria). Mosavat and Torabi (2014) presented that increase in pressure leads to increase in the solubility of CO2 while increase in temperature leads to decrease in the solubility of CO2 in a CO2-brine system.…”

Permeability Damage and Supercritical Fluid Storage in the Cauvery Basin Neyveli Lignite Bed Containing Kaolinite Deposits during Alternative Injection of Brine and CO2

“…This rise in the CO 2 retention in lignite core is absolutely due to the hysteresis effect during WAG cycle and a maximum of 53% of Sc-C has been retained in the lignite core plug. Soaking and solubility period of CO 2 saturated with the liquid phase, eventually, miscible and trap in the reservoir (Lee et al 2019;Pranesh et al 2018;Mosavat and Torabi 2014). Supercritical CO 2 ooding changes the rock geomechanical property and yield a high amount of storage (Zhang et al 2019b;Zhang et al 2017;Sander et al 2014;Zunsheng et al 2014).…”