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Injection of Supercritical CO2 Into Deep Saline Carbonate Formations: Predictions From Geochemical Modeling
- Document Type
- Journal Paper
- Guoxiang Zhang (Shell International E&P) | Conxita Taberner (Shell International E&P) | Linzey Cartwright (Shell International E&P) | Tianfu Xu (Lawrence Berkeley National Laboratory)
- Document ID
- SPE Journal
- 959 - 967
- Publication Date
- Society of Petroleum Engineers
- 2011. Society of Petroleum Engineers
- 6.1.5 Geologic Modeling, 6.11.1 CO2 Sequestration, 6.2.3 Geochemical Characterization, 6.5.3 Scaling Methods, 6.10.1 Carbonate Reservoirs
- CO2 sequestration, TOUGHREACT, reactive transport modeling, carbonate reservoir, Pitzer ion-interaction model
- 11 in the last 30 days
- 555 since 2007
Modeling of supercritical CO2 injection into a deep saline carbonate formation (calcite and dolomite with minor anhydrite) was performed using TOUGHREACT (Xu et al. 2006) with Pitzer ion-interaction-model implementation for handling high-salinity problems (Zhang et al. 2006). The formation-brine salinity is approximately 225,000 ppm (NaCl dominant), the temperature is 102°C, and the pressure is 225 bar. The CO2 is injected through a horizontal well in a 3D model domain at a constant rate for a period of 1 year. The carbonate formation was assumed to have homogeneous porosity and permeability and to be overlain by an impermeable seal. The effect of a high-permeability fault with orientation perpendicular to the horizontal well and bounded by the impermeable overburden was evaluated. The changes in mineralogy and rock property during the injection have been assessed. The simulation results illustrate that (1) the high-permeability fault acts as a CO2 conduit; (2) a dry-out zone is developed within a few meters from the injection well because of displacement by supercritical CO2 and evaporation of water into the CO2 stream; (3) at the front of the dry-out zone, brine is further concentrated because of water evaporation into the supercritical CO2, the pH is lowered from 5.5 to 3.1, halite (NaCl) and anhydrite (CaSO4) precipitate, and the brine becomes CaCl2 dominant; (4) near-wellbore porosity reduces by approximately 5 - 17% (1 - 3 pu) because of halite precipitation in the dry-out zone; (5) HCl gas is generated from the dry-out front; (6) calcite and dolomite dissolve as the CO2 plume advances during injection; (7) anhydrite, however, slightly dissolves along the CO2 front but precipitates in the area corresponding to the CO2 plume, with higher proportions of this mineral precipitated near the wellbore dry-out zone.
These findings are valuable for the assessment of injectivity changes and near-wellbore stability of saline aquifers in carbonate formations during injection of CO2. The overall mineral trapping in hundreds of years is not the focus of this paper. The method of this study is useful for further evaluation of engineering options to enhance immobile trapping of CO2 and mitigation measures for potential injectivity impairment.
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