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Title: Influence of Geochemical Processes on the Geomechanical Responses of Overburden Strata during CO2 Storage in Saline Aquifers



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National Energy Technology Laboratory - Energy Data eXchange; NETL
Sponsoring Org.:
USDOE Office of Fossil Energy (FE)
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DOE Contract Number:
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Country of Publication:
United States

Citation Formats

Robert Dilmore. Influence of Geochemical Processes on the Geomechanical Responses of Overburden Strata during CO2 Storage in Saline Aquifers. United States: N. p., 2017. Web. doi:10.18141/1433156.
Robert Dilmore. Influence of Geochemical Processes on the Geomechanical Responses of Overburden Strata during CO2 Storage in Saline Aquifers. United States. doi:10.18141/1433156.
Robert Dilmore. Thu . "Influence of Geochemical Processes on the Geomechanical Responses of Overburden Strata during CO2 Storage in Saline Aquifers". United States. doi:10.18141/1433156.
title = {Influence of Geochemical Processes on the Geomechanical Responses of Overburden Strata during CO2 Storage in Saline Aquifers},
author = {Robert Dilmore},
abstractNote = {NRAP TRS},
doi = {10.18141/1433156},
journal = {},
number = ,
volume = ,
place = {United States},
year = {Thu Apr 06 00:00:00 EDT 2017},
month = {Thu Apr 06 00:00:00 EDT 2017}


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  • Sedimentary basins in general and deep saline aquifers in particular, are being investigated as possible repositories for large volumes of anthropogenic CO2 that must be sequestered to mitigate global warming and related climate changes. To investigate the potential for the long-term storage of CO2 in such saline aquifers, 1600 t of CO2 were injected at 1500 m depth into a 24-m-thick C sandstone section of the Frio Formation, a regional aquifer in the U.S. Gulf Coast. Fluid samples obtained before CO2 injection from the injection well and an observation well 30 m up dip showed a Na-Ca-Cl type brine withmore » ~93,000 mg/L TDS at saturation with CH4 at reservoir conditions; gas analyses show CH4 comprised ~95% of dissolved gas, but CO2 was low at 0.3%. Following CO2 breakthrough, 51 h after injection, samples showed sharp drops in pH (6.5 to 5.7), pronounced increases in alkalinity (100 to 3000 mg/L as HCO3) and in Fe (30 to 1100 mg/L), a slug of very high DOC values, and significant shifts in the isotopic compositions of H2O, DIC, and CH4. These data coupled with geochemical modeling indicate rapid dissolution of minerals, especially calcite and iron oxyhydroxides caused by lowered pH (initially ~3.0 at subsurface conditions) of the brine in contact with supercritical CO2.« less
  • The ultimate fate of CO{sub 2} injected into saline aquifers for environmental isolation is governed by three interdependent yet conceptually distinct processes: CO{sub 2} migration as a buoyant immiscible fluid phase, direct chemical interaction of this rising plume with ambient saline waters, and its indirect chemical interaction with aquifer and cap-rock minerals through the aqueous wetting phase. Each process is directly linked to a corresponding trapping mechanism: immiscible plume migration to hydrodynamic trapping, plume-water interaction to solubility trapping, and plume-mineral interaction to mineral trapping. In this study, reactive transport modeling of CO{sub 2} storage in a shale-capped sandstone aquifer atmore » Sleipner has elucidated and established key parametric dependencies of these fundamental processes, the associated trapping mechanisms, and sequestration partitioning among them during consecutive 10-year prograde (active-injection) and retrograde (post-injection) regimes. Intra-aquifer permeability structure controls the path of immiscible CO{sub 2} migration, thereby establishing the spatial framework of plume-aquifer interaction and the potential effectiveness of solubility and mineral trapping. Inter-bedded thin shales--which occur at Sleipner--retard vertical and promote lateral plume migration, thereby significantly expanding this framework and enhancing this potential. Actual efficacy of these trapping mechanisms is determined by compositional characteristics of the aquifer and cap rock: the degree of solubility trapping decreases with increasing formation-water salinity, while that of mineral trapping is proportional to the bulk concentration of carbonate-forming elements--principally Fe, Mg, Ca, Na, and Al. In the near-field environment of Sleipner-like settings, 80-85% by mass of injected CO{sub 2} remains and migrates as an immiscible fluid phase, 15-20% dissolves into formation waters, and less than 1% precipitates as carbonate minerals. This partitioning defines the relative effectiveness of hydrodynamic, solubility, and mineral trapping on a mass basis. Seemingly inconsequential, mineral trapping has enormous strategic significance: it maintains injectivity, delineates the storage volume, and improves cap-rock integrity. We have identified four distinct mechanisms: dawsonite [NaAlCO{sub 3}(OH){sub 2}] cementation occurs throughout the intra-aquifer plume, while calcite-group carbonates [principally, (Fe,Mg,Ca)CO{sub 3}] precipitate via disparate processes along lateral and upper plume margins, and by yet another process within inter-bedded and cap-rock shales. The coupled mineral dissolution/precipitation reaction associated with each mechanism reduces local porosity and permeability. For Sleipner-like settings, the magnitude of such reduction for dawsonite cementation is near negligible; hence, this process effectively maintains initial CO{sub 2} injectivity. Of similarly small magnitude is the reduction associated with formation of carbonate rind along upper and lateral plume boundaries; these processes effectively delineate the CO{sub 2} storage volume, and for saline aquifers anomalously rich in Fe-Mg-Ca may partially self-seal the plume. Porosity and permeability reduction is most extreme within shales, because their clay-rich mineralogy defines bulk Fe-Mg concentrations much greater than those of saline aquifers. In the basal cap-rock shale of our models, these reductions amount to 4.5 and 13%, respectively, after the prograde regime. During the retrograde phase, residual saturation of immiscible CO{sub 2} maintains the prograde extent of solubility trapping while continuously enhancing that of mineral trapping. At the close of our 20-year simulations, initial porosity and permeability of the basal cap-rock shale have been reduced by 8 and 22%, respectively. Extrapolating to hypothetical complete consumption of Fe-Mg-bearing shale minerals (here, 10 vol.% Mg-chlorite) yields an ultimate reduction of about 52 and 90%, respectively, after 130 years. Hence, the most crucial strategic impact of mineral trapping in Sleipner-like settings: it continuously improves hydrodynamic seal integrity of the cap rock and, therefore, containment of the immiscible plume and solubility trapped CO{sub 2}.« less
  • A reactive fluid flow and geochemical transport numerical model for evaluating long-term CO{sub 2} disposal in deep aquifers has been developed. Using this model, we performed a number of sensitivity simulations under CO{sub 2} injection conditions for a commonly encountered Gulf Coast sediment to analyze the impact of CO{sub 2} immobilization through carbonate precipitation. Geochemical models are needed because alteration of the predominant host rock aluminosilicate minerals is very slow and is not amenable to laboratory experiment under ambient deep-aquifer conditions. Under conditions considered in our simulations, CO{sub 2} trapping by secondary carbonate minerals such as calcite (CaCO{sub 3}), dolomitemore » (CaMg(CO{sub 3}){sub 2}), siderite (FeCO{sub 3}), and dawsonite (NaAlCO{sub 3}(OH){sub 2}) could occur in the presence of high pressure CO{sub 2}. Variations in precipitation of secondary carbonate minerals strongly depend on rock mineral composition and their kinetic reaction rates. Using the data presented in this paper, CO{sub 2} mineral-trapping capability after 10,000 years is comparable to CO{sub 2} dissolution in pore waters (2-5 kg CO{sub 2} per cubic meter of formation). Under favorable conditions such as increase of the Mg-bearing mineral clinochlore (Mg{sub 5}Al{sub 2}Si{sub 3}O{sub 10}(OH){sub 8}) abundance, the capacity can be larger (10 kg CO{sub 2} per cubic meter of formation) due to increase of dolomite precipitation. Carbon dioxide-induced rock mineral alteration and the addition of CO{sub 2} mass as secondary carbonates to the solid matrix results in decreases in porosity. A maximum 3% porosity decrease is obtained in our simulations. A small decrease in porosity may result in a significant decrease in permeability. The numerical simulations described here provide useful insight into sequestration mechanisms, and their controlling conditions and parameters.« less
  • The overall goal of the project was to bridge the gap between our knowledge of small-scale geochemical reaction rates and reaction rates meaningful for modeling transport at core scales. The working hypothesis was that reaction rates, determined from laboratory measurements based upon reactions typically conducted in well mixed batch reactors using pulverized reactive media may be significantly changed in in situ porous media flow due to rock microstructure heterogeneity. Specifically we hypothesized that, generally, reactive mineral surfaces are not uniformly accessible to reactive fluids due to the random deposition of mineral grains and to the variation in flow rates withinmore » a pore network. Expected bulk reaction rates would therefore have to be correctly up-scaled to reflect such heterogeneity. The specific objective was to develop a computational tool that integrates existing measurement capabilities with pore-scale network models of fluid flow and reactive transport. The existing measurement capabilities to be integrated consisted of (a) pore space morphology, (b) rock mineralogy, and (c) geochemical reaction rates. The objective was accomplished by: (1) characterizing sedimentary sandstone rock morphology using X-ray computed microtomography, (2) mapping rock mineralogy using back-scattered electron microscopy (BSE), X-ray dispersive spectroscopy (EDX) and CMT, (3) characterizing pore-accessible reactive mineral surface area, and (4) creating network models to model acidic CO{sub 2} saturated brine injection into the sandstone rock samples.« less