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We present a reservoir geophysics study, including rock physics modeling and seismic inversion, of a carbon dioxide sequestration site in Southwestern Wyoming, namely the Rock Springs Uplift, and build a petrophysical model for the potential injection reservoirs for carbon dioxide sequestration. Our objectives include the facies classification and the estimation of the spatial model of porosity and permeability for two sequestration targets of interest, the Madison Limestone and the Weber Sandstone. The available dataset includes a complete set of well logs at the location of the borehole available in the area, a set of 110 core samples, and a seismic survey acquired in the area around the well. The proposed study includes a formation evaluation analysis and facies classification at the well location, the calibration of a rock physics model to link petrophysical properties and elastic attributes using well log data and core samples, the elastic inversion of the pre-stack seismic data, and the estimation of the reservoir model of facies, porosity and permeability conditioned by seismic inverted elastic attributes and well log data. In particular, the rock physics relations are facies-dependent and include granular media equations for clean and shaley sandstone, and inclusion models for the dolomitized limestone. The permeability model has been computed by applying a facies-dependent porosity-permeability relation calibrated using core sample measurements. The study shows that both formations show good storage capabilities. The Madison Limestone includes a homogeneous layer of high-porosity high-permeability dolomite; the Weber Sandstone is characterized by a lower average porosity but the layer is thicker than the Madison Limestone. [ABSTRACT FROM AUTHOR]

Laboratory experiments evaluated two shale caprock formations, the Gothic Shale and Marine Tuscaloosa Formation, at conditions relevant to carbon dioxide (CO2) sequestration. Both rocks were exposed to CO2-saturated brines at 160°C and 15 MPa for ∼45 days. Baseline experiments for both rocks were pressurized with argon to 15 MPa for ∼35 days. Varying concentrations of iron, aqueous silica, sulfate, and initial pH decreases coincide with enhanced carbonate and silicate dissolution due to reaction between CO2-saturated brine and shale. Saturation indices were calculated and activity diagrams were constructed to gain insights into sulfate, silicate, and carbonate mineral stabilities. Upon exposure to CO2-saturated brines, the Marine Tuscaloosa Formation appeared to be more reactive than the Gothic Shale. Evolution of aqueous geochemistry in the experiments is consistent with mineral precipitation and dissolution reactions that affect porosity. This study highlights the importance of tracking fluid chemistry to clarify downhole physicochemical responses to CO2 injection and subsequent changes in sealing capacity in CO2 storage and utilization projects. [ABSTRACT FROM AUTHOR]

Carbon capture, utilization, and storage, one proposed method of reducing anthropogenic emissions of CO2, relies on low permeability formations, such as shales, above injection formations to prevent upward migration of the injected CO2. Porosity in caprocks evaluated for sealing capacity before injection can be altered by geochemical reactions induced by dissolution of injected CO2 into pore fluids, impacting long-term sealing capacity. Therefore, long-term performance of CO2 sequestration sites may be dependent on both initial distribution and connectivity of pores in caprocks, and on changes induced by geochemical reaction after injection of CO2, which are currently poorly understood. This article presents results from an experimental study of changes to caprock porosity and pore network geometry in two caprock formations under conditions relevant to CO2 sequestration. Pore connectivity and total porosity increased in the Gothic Shale; while total porosity increased but pore connectivity decreased in the Marine Tuscaloosa. Gothic Shale is a carbonate mudstone that contains volumetrically more carbonate minerals than Marine Tuscaloosa. Carbonate minerals dissolved to a greater extent than silicate minerals in Gothic Shale under high CO2 conditions, leading to increased porosity at length scales <∼200 nm that contributed to increased pore connectivity. In contrast, silicate minerals dissolved to a greater extent than carbonate minerals in Marine Tuscaloosa leading to increased porosity at all length scales, and specifically an increase in the number of pores >∼1 μm. Mineral reactions also contributed to a decrease in pore connectivity, possibly as a result of precipitation in pore throats or hydration of the high percentage of clays. This study highlights the role that mineralogy of the caprock can play in geochemical response to CO2 injection and resulting changes in sealing capacity in long-term CO2 storage projects. [ABSTRACT FROM AUTHOR]

Hydrothermal experiments were conducted and geochemical models constructed to evaluate the geochemical and mineralogical response of fractured granite and granite + epidote in contact with thermal water, with and without supercritical CO 2 , at 250 °C and 25–45 MPa. Illite ± smectite ± zeolite(?) precipitate as secondary minerals at the expense of K-feldspar, oligoclase, and epidote. Illite precipitates in experiments reacting granite and granite + epidote with water; metastable smectite forms in the experiments injected with supercritical CO 2 . Waters are supersaturated with respect to quartz and saturated with respect to chalcedony in CO 2 -charged experiments, but neither mineral formed. Carbonate formation is predicted for experiments injected with supercritical CO 2 , but carbonate only formed during cooling and degassing of the granite + epidote + CO 2 experiment. Experimental results provide insight into the buffering capacity of granites as well as the drivers of clay formation. Metastable smectite in the experiments is attributed to high water–rock ratios, high silica activities, and high CO 2 and magnesium–iron concentrations. Smectite precipitation in supercritical CO 2 -bearing geothermal systems may affect reservoir permeability. Silicate formation may create or thicken caps within or on the edges of geothermal reservoirs. Carbonate formation, as desired for carbon sequestration projects coinciding with geothermal systems, may require extended periods of time; cooling and degassing of CO 2 -saturated waters leads to carbonate precipitation, potentially plugging near-surface production pathways. [ABSTRACT FROM AUTHOR]

Abstract: The Madison Limestone on the Moxa Arch, southwest Wyoming, USA is a sulfur-rich natural CO2 reservoir. A series of hydrothermal experiments was performed to evaluate multi-phase (CO2–H2O)–brine–rock reactions and processes in this reservoir and to test the hypothesis that this reservoir is a natural analog for geologic carbon–sulfur co-sequestration. Idealized Madison Limestone (dolomite–calcite–anhydrite–pyrite) and Na–Cl–SO4 2− brine (I=0.5molal) reacted at 110°C and 25MPa for approximately 81days (1940h). Supercritical CO2 was then injected and the experiment continued for approximately 46days (1100h). A parallel experiment was performed without supercritical CO2 to provide a basis of understanding for the interaction of supercritical CO2 with the brine–rock system. Two additional experiments were conducted in the same manner, but without anhydrite in the starting mineral assemblage, to examine supercritical CO2–sulfur reactivity. Injection of supercritical CO2 decreases pH by 2.5 to 3.3units, increases Eh by 0.19 to 0.23V, and drives reaction pathways along the pyrite–anhydrite saturation boundary of an Eh–pH diagram. The dolomite–calcite–anhydrite mineral assemblage and reaction textures that are produced are consistent with those observed in the natural CO2 reservoir. The mineral assemblage does not change following emplacement of supercritical CO2; instead, minerals dissolve, mobilize and re-precipitate. Anhydrite precipitates in the dolomite–calcite–pyrite experiment following injection of supercritical CO2 and provides a mineral trap for sulfur. Anhydrite precipitation decreases SO4 2− activity, ultimately leading to mineralization of CO2. Experimental results support the hypothesis that the Madison Limestone on the Moxa Arch is a natural analog for geologic carbon-sulfur co-sequestration. [Copyright &y& Elsevier]

Abstract: The Madison Limestone on the Moxa Arch, southwest Wyoming, USA contains large volumes (65–95%) of supercritical CO2 that it has stored naturally for 50millionyears. This reservoir also contains supercritical H2S, aqueous sulfur complexes (SO4 2− and HS−), and sulfur-bearing minerals (anhydrite and pyrite). Although SO2 is not present, these sulfur-bearing phases are known products of SO2 disproportionation in other water–rock systems. The natural co-occurrence of SO4 2−, S2−, supercritical CO2 and brine affords the opportunity to evaluate the fate of a carbon–sulfur co-sequestration scenario. Mineralogic data was obtained from drill core and aqueous geochemical data from wells outside and within the current supercritical CO2–sulfur–brine–rock system. In addition to dolomite, calcite, and accessory sulfur-bearing minerals, the Madison Limestone contains accessory quartz and the aluminum-bearing minerals feldspar, illite, and analcime. Dawsonite (NaAlCO3(OH)2), predicted as an important carbon sink in sequestration modeling studies, is not present. After confirming equilibrium conditions for the Madison Limestone system, reaction path models were constructed with initial conditions based on data from outside the reservoir. Addition of supercritical CO2 to the Madison Limestone was simulated and the results compared to data from inside the reservoir. The model accurately predicts the observed mineralogy and captures the fundamental changes expected in a Madison Limestone-brine system into which CO2 is added. pH decreases from 5.7 to 4.5 at 90°C and to 4.0 at 110°C, as expected from dissolution of supercritical CO2, creation of carbonic acid, and buffering by the carbonate rock. The calculated redox potential increases by 0.1V at 90°C and 0.15V at 110°C due to equilibrium among CO2, anhydrite, and pyrite. Final calculated Eh and pH match conditions for the co-existing sulfur phases present in produced waters and core from within the reservoir. Total dissolved solids increase with reaction progress, mostly due to dissolution of calcite with an accompanying increase in dissolved bicarbonate. The Madison Limestone is a natural example of the thermodynamic end point that similar fluid–rock systems will develop following emplacement of a supercritical CO2–sulfur mixture and is a natural analog for geologic carbon–sulfur co-sequestration. [Copyright &y& Elsevier]

Abstract: The potential impact to the integrity of wellbore cements as a result of exposure to supercritical carbon dioxide (SCCO2) has been raised as an area of some concern with respect to long-term effectiveness of CO2 storage in geological formations. In flow-through experiments we simulated diffusion of brine and SCCO2 from the interface between wellbore cement and caprock into a fracture-bearing Portland cement. The experiments were performed at in-situ reservoir pressure (pore pressure: 19.9 MPa) and temperature (54 °C) conditions for 113 days. For this purpose we saturated illite-rich shale and the Portland cement core (2.02 cm×5.35 cm) with 1.65 M brine for 14 days. After this period of time we injected SCCO2 into the system for 99 days and simulated a diffusion process by using a pressure gradient of 0.7 MPa. Calcite precipitation occurred within the fracture and the induced pressure of crystal growth may explain an increase in the relative permeability along the fracture with time. SCCO2-induced reactions extended ~5 mm into the Portland cement core from the fracture and formed an orange-colored zone. The orange-colored zone is nearly completely carbonated with crystalline phases consisting mainly of calcite, aragonite, and vaterite. The only crystalline cement component that persisted in the orange-colored zone was brownmillerite. Interior portions of the hydrated cement were partially carbonated, modified in texture and contained newly formed calcite, hydrogarnet and hydrocalumite (Friedel''s salt). Cement porosity decreased from 37.8% to 23.8% during carbonation and was associated with a 19.6% increase in mass. [Copyright &y& Elsevier]

Abstract: Carbon dioxide injection in porous reservoirs is the basis for carbon capture and storage, enhanced oil and gas recovery. Injected carbon dioxide is stored at multiple scales in porous media, from the pore-level as a residual phase to large scales as macroscopic accumulations by the injection site, under the caprock and at reservoir internal capillary pressure barriers. These carbon dioxide saturation zones create regions across which the full spectrum of mutual CO2–H2O solubility may occur. Most studies assume that geochemical reaction is restricted to rocks and carbon dioxide-saturated formation waters, but this paradigm ignores injection of anhydrous carbon dioxide against brine and water-alternating-gas flooding for enhanced oil recovery. A series of laboratory experiments was performed to evaluate the reactivity of the common reservoir mineral dolomite with water-saturated supercritical carbon dioxide. Experiments were conducted at reservoir conditions (55 and 110°C, 25MPa) and elevated temperature (220°C, 25MPa) for approximately 96 and 164h (4 and 7days). Dolomite dissolves and new carbonate mineral precipitates by reaction with water-saturated supercritical carbon dioxide. Dolomite does not react with anhydrous supercritical carbon dioxide. Temperature and reaction time control the composition, morphology, and extent of formation of new carbonate minerals. Mineral dissolution and re-precipitation due to reaction with water-saturated carbon dioxide may affect the contact line between phases, the carbon dioxide contact angle, and the relative permeability and permeability distribution of the reservoir. These changes influence fundamental properties of hysteresis of drainage and imbibition cycles, rock wettability, and capillary pressure. The efficacy of physical carbon dioxide trapping mechanisms, integrity of caprock, and injectivity of a carbon dioxide storage reservoir as well as the injectivity and production rate of an enhanced oil recovery operation may be affected. [Copyright &y& Elsevier]

Abstract: Supercritical CO2 has been shown to act as a disinfectant against microorganisms. These organisms have most often been tested in vegetative or spore form. Since biofilm organisms are typically more resilient to physical, chemical, and biological stresses than the same organisms in planktonic form, they are often considered more difficult to eradicate. It is therefore hypothesized that supercritical CO2 (SC–CO2) induced inactivation of biofilm organisms would be less effective than against planktonic (suspended) growth cultures of the same organism. Six-day old biofilm cultures as well as suspended planktonic cultures of Bacillus mojavensis were exposed to flowing SC–CO2 at 136atm and 35°C for 19min and slowly depressurized after treatment. After SC–CO2 exposure, B. mojavensis samples were analyzed for total and viable cells. Suspended cultures revealed a 3log10 reduction while biofilm cultures showed a 1log10 reduction in viable cell numbers. These data demonstrate that biofilm cultures of B. mojavensis are more resilient to SC–CO2 than suspended planktonic communities. It is hypothesized that the small reduction in the viability of biofilm microorganisms reflects the protective effects of extracellular polymeric substances (EPS) which make up the biofilm matrix, which offer mass transport resistance, a large surface area, and a number of functional groups for interaction with and immobilization of CO2. The resistance of biofilm suggests that higher pressures, longer durations of SC–CO2 exposure, and a quicker depressurization rate may be required to eradicate biofilms during the sterilization of heat-sensitive materials in medical and industrial applications. However, the observed resilience of biofilms to SC–CO2 is particularly promising for the prospective application of subsurface biofilms in the subsurface geologic sequestration of CO2. [Copyright &y& Elsevier]