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Numerical simulation was conducted to evaluate supercritical CO 2 (scCO 2 ) storage in the Mt. Simon sandstone at the FutureGen 2.0 site in Morgan County, Illinois. The simulations illustrate the recent modeling effort conducted to successfully obtain a Class VI permit under the Underground Injection Control Program of the U.S. Environmental Protection Agency. The scCO2 was injected into a highly stratified reservoir, distributed among four lateral wells. Results show that each of the multiple reservoir layers with low permeability traps a fraction of the scCO 2 beneath it so that the injected scCO 2 does not reach the top of the reservoir by the end of the simulation period. Hence, all of the injected scCO 2 is considered to be safely trapped by the stratified structure within the reservoir. A local sensitivity analysis (LSA) was conducted for injectivity and plume size at the end of the 20 year injection period. The LSA indicates that the imposed initial conditions and the hydraulic properties of the injection layer contribute the most to the sensitivity. Overall, the simulation outputs are very sensitive to only a small fraction of the inputs. However, the parameters that are important for controlling CO 2 injectivity are not the same as those controlling the plume area. The three most sensitive inputs for injectivity are the horizontal permeability and the residual aqueous saturation of the injection layer, and the initial fracture-pressure gradient. For the plume area, the most sensitive inputs are the horizontal permeability of the injection layer and the residual aqueous saturation of the two adjacent layers above the injection layer. The advantages of requiring just a single set of simulation results, scalability to the proper parameter errors, and straightforward calculation of the composite sensitivities make the proposed analysis attractive for guiding site characterization, injection well design, estimating Area of Review uncertainty and, and monitoring network design. [ABSTRACT FROM AUTHOR]

Constitutive relations between relative permeability ( k r ), fluid saturation ( S ), and capillary pressure ( P c ) determine to a large extent the distribution of brine and supercritical CO 2 (scCO 2 ) during subsurface injection operations. Published numerical multiphase simulations for brine–scCO 2 systems so far have primarily used four k r − S − P c models. For the S − P c relations, either the Brooks–Corey (BC) or Van Genuchten (VG) equations are used. The k r − S relations are based on Mualem, Burdine, or Corey equations without the consideration of experimental data. Recently, two additional models have been proposed where the k r − S relations are obtained by fitting to experimental data using either an endpoint power law or a modified Corey approach. The six models were tested using data from four well-characterized sandstones (Berea, Paaratte, Tuscaloosa, Mt. Simon) for two radial injection test cases. The results show a large variation in plume extent and saturation distribution for each of the sandstones, depending on the used model. The VG–Mualem model predicts plumes that are considerably larger than for the other models due to the overestimation of the gas relative permeability. The predicted plume sizes are the smallest for the VG–Corey model due to the underestimation of the aqueous phase relative permeability. Of the four models that do not use fits to experimental relative permeability data, the hybrid model with Mualem aqueous phase and Corey gas phase relative permeabilities provide the best fits to the experimental data and produce results close to the model with fits to the capillary pressure and relative permeability data. The model with the endpoint power law resulted in very low, uniform gas saturations outside the dry-out zone for the Tuscaloosa sandstone, as the result of a rapidly declining aqueous phase relative permeability. This observed behavior illustrates the need to obtain reliable relative permeability relations for a potential reservoir, beyond permeability and porosity data. [ABSTRACT FROM AUTHOR]

Abstract: A series of flow-cell experiments was conducted to investigate aqueous dissolution and mass-removal behavior for systems wherein immiscible liquid was non-uniformly distributed in physically heterogeneous source zones. The study focused specifically on characterizing the relationship between mass flux reduction and mass removal for systems for which immiscible liquid is poorly accessible to flowing water. Two idealized scenarios were examined, one wherein immiscible liquid at residual saturation exists within a lower-permeability unit residing in a higher-permeability matrix, and one wherein immiscible liquid at higher saturation (a pool) exists within a higher-permeability unit adjacent to a lower-permeability unit. The results showed that significant reductions in mass flux occurred at relatively moderate mass-removal fractions for all systems. Conversely, minimal mass flux reduction occurred until a relatively large fraction of mass (>80%) was removed for the control experiment, which was designed to exhibit ideal mass removal. In general, mass flux reduction was observed to follow an approximately one-to-one relationship with mass removal. Two methods for estimating mass-flux-reduction/mass-removal behavior, one based on system-indicator parameters (ganglia-to-pool ratio) and the other a simple mass-removal function, were used to evaluate the measured data. The results of this study illustrate the impact of poorly accessible immiscible liquid on mass-removal and mass-flux processes, and the difficulties posed for estimating mass-flux-reduction/mass-removal behavior. [Copyright &y& Elsevier]