Experimental Observation of Permeability Changes In Dolomite at CO₂Sequestration Conditions

Abstract

Injection of cool CO2 into geothermally warm carbonate reservoirs for storage or geothermal energy production may lower near-well temperature and lead to mass transfer along flow paths leading away from the well. To investigate this process, a dolomite core was subjected to a 650 h, high pressure, CO2 saturated, flow-through experiment. Permeability increased from 10(-15.9) to 10(-15.2) m(2) over the initial 216 h at 21 °C, decreased to 10(-16.2) m(2) over 289 h at 50 °C, largely due to thermally driven CO2 exsolution, and reached a final value of 10(-16.4) m(2) after 145 h at 100 °C due to continued exsolution and the onset of dolomite precipitation. Theoretical calculations show that CO2 exsolution results in a maximum pore space CO2 saturation of 0.5, and steady state relative permeabilities of CO2 and water on the order of 0.0065 and 0.1, respectively. Post-experiment imagery reveals matrix dissolution at low temperatures, and subsequent filling-in of flow passages at elevated temperature. Geochemical calculations indicate that reservoir fluids subjected to a thermal gradient may exsolve and precipitate up to 200 cm(3) CO2 and 1.5 cm(3) dolomite per kg of water, respectively, resulting in substantial porosity and permeability redistribution.

Numerical Investigation into the Impact of CO2-Water-Rock Interactions on CO2 Injectivity at the Shenhua CCS Demonstration Project, China

“…It can be seen that the dissolution of dolomite increases with increasing salinity, while the dissolution-precipitation of other minerals and major aqueous species does not change except for minor calcite precipitation. This is in accordance with previous studies [22,54] and can be explained by the ionic strength of the solution increasing with salinity and reducing the activity of aqueous species, thereby promoting dolomite dissolution. There was no obvious difference in the porosity changes between salinities of 0.09% (not shown) and 0.9 wt.% dissolved NaCl.…”

“…As dolomite content increases in the near-well region (zone I), it has less effect on porosity change; this is because reactivity is limited by lack of water (due to evaporation of water into the free CO 2 phase) and excessive initial mineral (i.e., dolomite supersaturation). This was also observed in a flow-through experiment performed by Tutolo et al [22].…”

“…Laboratory experiments related to CO 2 injection into sandstone and carbonate rocks have been reported in the previous studies [15,[18][19][20][21][22]. These experiments indicate that CO 2 -water-rock interactions can have a substantial effect on porosity and permeability, depending on fluid composition, rock mineralogy, and subsurface thermodynamic conditions.…”

Anti-correlated Porosity–Permeability Changes During the Dissolution of Carbonate Rocks: Experimental Evidences and Modeling

“…A solid body of experimental evidences illustrates that the porosity increase resulting from carbonate dissolution is usually correlated with the increase of permeability. It is worth noticing that most of these experimental studies addressing the evolution of the pore space caused by carbonate dissolution involve highly reactive fluids, as the main field of application addresses the analysis of acidification techniques for enhancing near-well permeability (Cohen et al 2008) and underground CO 2 storage Noiriel et al 2009;Gouze and Luquot 2011;Hao et al 2013;Smith et al 2013;Wang et al 2013;Tutolo et al 2014). For instance, experiments such as those reported by Luquot and Gouze (2009) for limestones for dolostones aimed at reproducing conditions occurring in the vicinity of a CO 2 injection well, where disequilibrium is maximal.…”

Brine displacement by CO2, energy extraction rates, and lifespan of a CO2-limited CO2-Plume Geothermal (CPG) system with a horizontal production well

“…The model extends horizontally to 100 km (not shown) to minimize numerical boundary effects, with logarithmically increasing horizontal grid spacing away from the injection well but horizontal refinement of grid spacing near the production well. The block diagrams to the right show symmetric (top) and asymmetric or skewed (bottom) CO2 plume formation as described in the main text and Appendix A. been addressed elsewhere by our group (e.g., Kong et al, 2013;Luhmann et al, 2013Luhmann et al, , 2014Tutolo et al, 2014aTutolo et al, ,b, 2015a. While the overall dimensions of the reservoir considered here are kept conservatively small to illustrate the performance of a moderatelyscaled system, larger stratigraphic or sedimentary basin reservoirs -such as in the Williston Basin, North Dakota, or the off-shore Sleipner Field, Norway -exist worldwide and may potentially be used for CPG.…”