2D modeling of salt precipitation during the injection of dry CO2 in a depleted gas reservoir

Giorgis, Thomas; Carpita, Michele; Battistelli, Alfredo

doi:10.1016/j.enconman.2007.01.012

Cited by 140 publications

(108 citation statements)

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“…This effect is caused by displacement of the pore fluid as a result of injection, as well as desiccation caused by water dissolving in the moving CO 2 [Giorgis et al, 2007;Müller et al, 2009]. The near-well volume of rock will therefore usually be in contact with (relatively) dry, supercritical CO 2 .…”

Section: Effects Of Co 2 On Compaction Creep Of Wet Feldsparmentioning

confidence: 99%

Creep of simulated reservoir sands and coupled chemical‐mechanical effects of CO₂ injection

2010

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[1] Geological storage of CO 2 in clastic reservoirs and aquifers is expected to have a variety of coupled chemical-mechanical effects. To investigate the effects of CO 2 injection on creep phenomena, we performed uniaxial compaction experiments on granular aggregates of quartz and feldspar under both wet and dry control conditions. The experiments were performed in constant stress mode. Grain size, temperature, CO 2 partial pressure, and effective stress were varied in order to determine their individual effect. Pore fluid pH was varied by the injection of CO 2 and by addition of acidic and alkaline additives. Pore fluid salinity was increased by the addition of NaCl. Wet samples showed instantaneous compaction upon load application, followed by time-dependent creep. From the mechanical data and microstructures, the main compaction mechanism was inferred to be chemically enhanced microcracking in both quartz and feldspar, with subcritical crack growth, i.e., stress corrosion cracking, controlling deformation in the creep stage. The injection of CO 2 and the concomitant acidification of the pore fluid inhibited microcracking in both the quartz and feldspar samples in line with known effects of pH on stress corrosion cracking. We infer that the injection of CO 2 into quartz-and plagioclase-bearing sandstones will inhibit grain scale microcracking process and that related geomechanical effects, such as reservoir compaction and surface subsidence, will be negligible compared with the poroelastic response.

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Section: Effects Of Co 2 On Compaction Creep Of Wet Feldsparmentioning

confidence: 99%

Creep of simulated reservoir sands and coupled chemical‐mechanical effects of CO₂ injection

2010

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“…Previous work in the CO 2 storage literature related to the changing magnitude of the chemical potential of water and/or adsorptive and capillary water focuses mainly on: 1) near-wellbore saline water evaporation and concomitant salt precipitation that may reduce scCO 2 injection rates due to permeability losses [16,17,[28][29][30]; 2) chemical reactivity under humid scCO 2 including precipation-dissolution and water intercalation in clays as a function of water content in scCO 2 [7,10,[31][32][33][34][35][36]; and 3) laboratory observation or theoretical estimation of thickness of water films in scCO 2 [26,27,37]. Common approaches for assessing near-wellbore dry-out, in calculating water activity in the CO 2 -rich phase, typically neglect any effects of capillary potential or surface adsorption potential on the total chemical potential of water [e.g., see 36,38].…”

Section: Introductionmentioning

confidence: 99%

Fundamental study of CO2-H2O-mineral interactions for carbon sequestration, with emphasis on the nature of the supercritical fluid-mineral interface.

Bryan¹,

Dewers²,

Heath³

et al. 2013

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In the supercritical CO 2 -water-mineral systems relevant to subsurface CO 2 sequestration, interfacial processes at the supercritical fluid-mineral interface will strongly affect core-and reservoir-scale hydrologic properties. Experimental and theoretical studies have shown that water films will form on mineral surfaces in supercritical CO 2 , but will be thinner than those that form in vadose zone environments at any given matric potential. The theoretical model presented here allows assessment of water saturation as a function of matric potential, a critical step for evaluating relative permeabilities the CO 2 sequestration environment. The experimental water adsorption studies, using Quartz Crystal Microbalance and Fourier Transform Infrared Spectroscopy methods, confirm the major conclusions of the adsorption/condensation model. Additional data provided by the FTIR study is that CO 2 intercalation into clays, if it occurs, does not involve carbonate or bicarbonate formation, or significant restriction of CO 2 mobility.We have shown that the water film that forms in supercritical CO 2 is reactive with common rock-forming minerals, including albite, orthoclase, labradorite, and muscovite. The experimental data indicate that reactivity is a function of water film thickness; at an activity of water of 0.9, the greatest extent of reaction in scCO 2 occurred in areas (step edges, surface pits) where capillary condensation thickened the water films. This suggests that dissolution/precipitation reactions may occur preferentially in small pores and pore throats, where it may have a disproportionately large effect on rock hydrologic properties.Finally, a theoretical model is presented here that describes the formation and movement of CO 2 ganglia in porous media, allowing assessment of the effect of pore size and structural heterogeneity on capillary trapping efficiency. The model results also suggest possible engineering approaches for optimizing trapping capacity and for monitoring ganglion formation in the subsurface. 6 ACKNOWLEDGMENTS

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“…The solubility of water into CO 2 is also of importance, because it affects the reactivity of CO 2 with surrounding rocks (e.g., Regnault et al 2005;Rimmelé et al 2008;Lin et al 2008;Suto et al 2007) and determines the capacity of injected CO 2 to dry the rock formations adjacent to injection wells (Giorgis et al 2007;Hurter et al 2007;Pruess and Müller 2009). In the case of a CO 2 -based EGS, the partitioning of water into CO 2 would also determine the time required for the removal of water from the (central portion of the) EGS, and the type of chemical interactions that may take place between the CO 2 plume, reservoir rocks, and engineered systems.…”

Section: Introductionmentioning

confidence: 99%

A Phase-Partitioning Model for CO2–Brine Mixtures at Elevated Temperatures and Pressures: Application to CO2-Enhanced Geothermal Systems

2009

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Correlations are presented to compute the mutual solubilities of CO 2 and chloride brines at temperatures 12-300 • C, pressures 1-600 bar (0.1-60 MPa), and salinities 0-6 m NaCl. The formulation is computationally efficient and primarily intended for numerical simulations of CO 2 -water flow in carbon sequestration and geothermal studies. The phase-partitioning model relies on experimental data from literature for phase partitioning between CO 2 and NaCl brines, and extends the previously published correlations to higher temperatures. The model relies on activity coefficients for the H 2 O-rich (aqueous) phase and fugacity coefficients for the CO 2 -rich phase. Activity coefficients are treated using a Margules expression for CO 2 in pure water, and a Pitzer expression for salting-out effects. Fugacity coefficients are computed using a modified Redlich-Kwong equation of state and mixing rules that incorporate asymmetric binary interaction parameters. Parameters for the calculation of activity and fugacity coefficients were fitted to published solubility data over the P-T range of interest. In doing so, mutual solubilities and gas-phase volumetric data are typically reproduced within the scatter of the available data. An example of multiphase flow simulation implementing the mutual solubility model is presented for the case of a hypothetical, enhanced geothermal system where CO 2 is used as the heat extraction fluid. In this simulation, dry supercritical CO 2 at 20 • C is injected into a 200 • C hot-water reservoir. Results show that the injected CO 2 displaces the formation water relatively quickly, but that the produced CO 2 contains significant water for long periods of time. The amount of water in the CO 2 could have implications for reactivity with reservoir rocks and engineered materials.

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2D modeling of salt precipitation during the injection of dry CO2 in a depleted gas reservoir

Cited by 140 publications

References 10 publications

Creep of simulated reservoir sands and coupled chemical‐mechanical effects of CO₂ injection

Creep of simulated reservoir sands and coupled chemical‐mechanical effects of CO₂ injection

Fundamental study of CO2-H2O-mineral interactions for carbon sequestration, with emphasis on the nature of the supercritical fluid-mineral interface.

A Phase-Partitioning Model for CO2–Brine Mixtures at Elevated Temperatures and Pressures: Application to CO2-Enhanced Geothermal Systems

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2D modeling of salt precipitation during the injection of dry CO2 in a depleted gas reservoir

Cited by 140 publications

References 10 publications

Creep of simulated reservoir sands and coupled chemical‐mechanical effects of CO2 injection

Creep of simulated reservoir sands and coupled chemical‐mechanical effects of CO2 injection

Fundamental study of CO2-H2O-mineral interactions for carbon sequestration, with emphasis on the nature of the supercritical fluid-mineral interface.

A Phase-Partitioning Model for CO2–Brine Mixtures at Elevated Temperatures and Pressures: Application to CO2-Enhanced Geothermal Systems

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Creep of simulated reservoir sands and coupled chemical‐mechanical effects of CO₂ injection

Creep of simulated reservoir sands and coupled chemical‐mechanical effects of CO₂ injection