H12C-01
Basin-Scale Hydrologic Impacts of CO2 Sequestration within the Mt Simon Formation, Illinois Basin; Scaling Calculations using Sharp-Interface Theory
The Illinois Basin hosts dozens of coal fired power plants generating more than 80 million metric tons of CO2 annually. Here we present a suite of basin-scale, hydrologic models of the Mt Simon formation, Illinois Basin using sharp interface theory. The goal of these models is to determine what are the basin-scale hydrologic consequences of CO2 injection and whether some regions of the Illinois Basin would represent a better venue for carbon sequestration than others. While this approach makes some restrictive simplifying assumptions, it allows us to assess the problem at the sedimentary basin scale. Our solution domain spans the northern two thirds of the Illinois Basin (about 230,000 km2). We allowed porosity and permeability to decrease with depth from 0.2 to 0.05 and 400 to 2 mD, respectively. We injected CO2 using 727, 10 inch diameter injection wells delivering about 210 kg/minute/well. The wells were positioned about 2 km apart in a radial pattern around known power plant locations. We ran the injection wells for 100 years. The wells were then shut in for an additional 900 years. Results indicate that after 100 years of continuous injection, deviatoric fluid pressures varied between 9.2 to 0.5 MPa between the deepest and shallowest injection wells. For the deepest portion of the basin (~ 3.1 km), deviatoric pressures reach about 22 percent of lithostatic levels. Owing to the rather subtle regional hydraulic gradient (200m/500km), long-range separate-phase CO2-migration is driven by buoyancy at a rate of only 2 m/year. If CO2 remained as a separate phase on time scales of 100,000 years, the injected CO2 would migrate about 200 km to the north before charging gentle structural traps. Owing to the radial, bowl-shaped geometry of the Illinois Basin, net brine displacement to the north would be small, probably less than 100 m. Our analysis suggest that the Mt. Simon formation represents a good venue for CO2 sequestration although shallower regions ( ~ 2 km depth) would pose less risk of catastrophic breaching due to high deviatoric fluid pressures. Fluid pressures do not return to hydrostatic conditions after 1000 years due to buoyant forces resulting from the presence of a separate CO2 phase.
H12C-02
A Hypothetical Scenario for Full-Scale Deployment of Geological Carbon Sequestration: Investigating the Interaction Between Multiple CO2 Storage Sites in a Sedimentary Basin
Most ongoing projects of geological carbon sequestration (GCS) are relatively small in size, with annual injection rates from a few thousand to less than a million tonnes. These projects help build the GCS technology with respect to modeling, monitoring, risk assessment, and mitigation, and have been successful so far in terms of CO2 containment and caprock geomechanical integrity. In the future, GCS will be implemented at full-scale, multiple industrial-size CO2 storage sites in large sedimentary basins to make full use of the potential storage capacity. Simultaneous injection into multiple not-too-distant storage sites will lead to interference between the individual regions of pressure build-up and possible interference between the individual CO2 plumes. The Illinois Basin is used to model the future impact of multiple injection sites in the thick, extensive Mount Simon Formation. The basin-scale model domain of 241,000 km2 covers a core injection area of 24,000 km2, a larger near-field area where significant pressure buildup is expected, and an even larger far-field area for investigating environmental impacts on groundwater resources. The model assumes that there are twenty sequestration sites (spaced 30 km apart) within the core injection area. Three injection scenarios are considered, featuring annual injection rates of 5, 10, and 15 million tonnes of CO2 at each site, respectively. These scenarios correspond to 33%, 67% and 100% of the current single-point large CO2 sources in the relevant states (Illinois, Indiana and Kentucky). The model adequately captures the characteristics of the Mount Simon Formation in the core injection area, which include (1) an overall thickness of 300 to 680 m, (2) an upper unit of sandstone and shale tidally influenced and deposited, (3) a thick middle unit of clean sandstone of relatively high permeability, and (4) a lower arkosic unit of higher permeability (one Darcy) with an average thickness of 90 m. At each site, CO2 is injected into the lower arkosic unit to ensure sufficient permeability to accommodate high injection rates. A three-dimensional unstructured mesh is used for the model, with progressive refinement horizontally from the far-field area to the core injection area and radial refinement toward each injection center within the injection area, as well as progressive vertical refinement from four model layers in the far-field area to 50 model layers for each CO2 plume. The overlying Eau Claire seal and the underlying Pre-Cambrian granite unit are also included in the model. Both the two-phase CO2-brine flow within the twenty CO2 plumes and the single-phase brine flow away from the plumes are simulated using the parallel TOUGH2/ECO2N simulator. Preliminary simulation results are discussed with respect to (1) the dynamic evolution and migration of individual CO2 plumes, (2) the possible interference between different plumes, (3) the interference between individual regions of pressure buildup, (4) the possible impacts of GCS on the groundwater resources at the basin's boundary, and (5) the possibility of caprock damage.
H12C-03
Analytical solution for pressure buildup and plume evolution during injection of CO2 into saline aquifers
If geo-sequestration of CO2 is to be employed as a key greenhouse gas reduction method in the global effort to mitigate climate change, simple yet robust methods must be available to help design and monitor injection into saline aquifers. There has been significant development of simple analytical and semi-analytical techniques to support screening analysis and performance assessment for potential carbon sequestration sites. These techniques have generally been used to estimate the size of CO2 plumes for the purpose of leakage rate estimation. A common assumption of previous has been that both the fluids and the geological formation are incompressible. Consequently, calculation of pressure distribution requires the specification of an arbitrary radius of influence. In the present work, we relax this restriction by incorporating fluid and formation compressibility into our governing equations. These equations are transformed into ordinary differential equations using a similarity transformation, and are then solved using the method of matched asymptotic expansions. By allowing for compressibility in the fluids and formation, the solutions improve on previous work by not requiring the specification of an arbitrary radius of influence. Our solution is also capable of accounting for non-Darcy inertial effects modeled by the Forchheimer equation. These analytical solutions are validated by comparison with finite difference solutions. Our analysis leads to a simple yet highly accurate algebraic equation for estimating the evolution of a CO2 plume, and the associated pressure buildup, as a function of time.
H12C-04
Analysis of Heterogeneity Length-scales on Residual Gas trapping and Buoyancy-driven CO2 Migration
The primary purpose of this study is to elucidate how variations in the length-scale of permeability (k) heterogeneity affect CO2 sequestration processes, especially buoyancy-driven flow and residual gas trapping. We systematically implemented 24 scenarios corresponding to 141 simulations representing a systematic variation in k: homogeneous and isotropic (four scenarios), homogeneous and anisotropic (five scenarios), random (five scenarios), homogenous with a low k inclusion (two scenarios), correlated k field with k isotropy (four scenarios), and k anisotropy (four scenarios). Sequential Gaussian simulation was used to generate an equally probable 10 realizations of each scenario except for the homogeneous cases. Effective permeabilities were calculated to evaluate the ambient velocity field in each realization. In addition, the first and second moments of CO2 plume distribution were examined to explore both the lateral and vertical CO2 displacement behavior according to geologic complexity. With quantified velocity information and plume distribution, we investigated the systematic variation of CO2 trapping mechanisms corresponding to different heterogeneity length-scales. Simulation results reveal that residual CO2 trapping increases with effective vertical k in both homogeneous and uncorrelated random fields. Increasing the effective vertical k increases CO2 velocities, resulting in farther CO2 migration. Consequently, the injected CO2 plume sweeps a larger area thus the amount of residual-trapped CO2 increases. Interestingly, horizontal connectivity also increases residual trapping by increasing the lateral CO2 plume extension. For example, a longer correlation length enhances the lateral extension of a CO2 plume, also increasing the amount of residual gas trapping. In sum, residual trapping is enhanced when CO2 plume migrates farther vertically (vertical k control) or laterally (horizontal k control or correlation lengths control). In practice, the goal is to store more CO2 as residually-trapped gas, and to minimize buoyancy-driven CO2 migration. These simulations suggest that heterogeneous k fields with longer correlation lengths are more promising target formation for geologic CO2 sequestration. Finally, these findings imply that horizontal injection wells may enhance residual CO2 trapping significantly, because such horizontal wells will likely increase the early lateral extent of an injected CO2 plume.
H12C-05
Relative Permeability Properties of CO2 and Brine in Reservoir Rocks.
This paper presents the results of laboratory experiments of relative permeability to brine and CO2 on core samples of reservoir rocks. A new experimental facility in the Department of Energy Resources Engineering at Stanford University has been developed to replicate reservoir conditions (T > 40°C, P > 80 bars) during CO2 injection. We are able to co-inject brine and CO2 continuously at flow rates anticipated in the storage reservoir near and distant from the injection well. Saturation distributions of each phase within the core are determined using X-ray CT scanning. Using this apparatus, experiments in which CO2 and brine are co-injected at different proportions have been carried out over a range of flow rates. The results are analyzed in conjunction with sub-core scale capillary pressure measurements, analysis of the corresponding thin sections and numerical simulations.
H12C-06
Simulating Coupled Fluid Mechanical Processes During CO2 Injection
The geologic sequestration of CO2 is one of the technologies being considered for mitigating impact of anthropogenic emissions of CO2. Because of vast quantities of fluid needed to be injected in the subsurface and the relative lack of pore space, geo-mechanical effects and their impacts will be an important consideration in the evaluation of sequestration sites. Numerical models to predict the geo-mechanical effects must be capable of accurately representing the coupled thermal-hydrologic-mechanical (THM) processes and solving the resulting nonlinear system of equations in a very efficient manner. We present application of our approach to characterize the geo-mechanical impact of large-scale CO2 injection. The approach is based on the coupled solution of THM processes presented by Bower and Zyvoloski (1997). Accurate representation of permeability-displacement behavior in faults presents significant challenges. We have developed a general permeability-displacement approach that is applicable not only to general rock types but also to accurately represent faults in large grid blocks. The approach allows use of a complex model near injection wells and a relatively simple model in the far field to accurately capture the geo- mechanical effects. Our numerical studies are focused on understanding how faults/fault gouges behave during large-scale CO2 injection including coupled fault displacements and CO2 migration. The results will show why a coupled approach is needed for accurate representation of geo-mechanical effects during large- scale CO2 injection. Reference: Bower, K. M., and G. Zyvoloski, 1997, "A Numerical Model for Thermo-Hydro-mechanical Coupling in Fractured Rock," Int. J. Rock Mech. Min. Sci. Vol. 34, No. 8, pp. 1201-1211.
H12C-07
Pore-Scale Analysis of Microtomography Images of the Rock in Geosequestration Research
Accumulation of carbon dioxide and other green-house gases in the atmosphere impacts the Earth energy balance and leads to global warming. Injection of gas in deep geologic formations is one of possible ways to mitigate the unwanted climate changes. Success of such program is determined by the capability of trapping the injected gas under the surface for a geologic time. This process is very complex: it includes interaction of multiphase flow and geochemistry processes across multiple scales. In particular, it is very important to clearly understand the consequences of injection at the pore scale and how these processes upscale to entire aquifer. Synchrotron-based microtomography at the Advanced Light Source line 8.3.2 at Lawrence Berkeley National Laboratory produces high-resolution three-dimensional images of the pore space of the rock of interest. A suite of methods of analysis of petrophysical properties of the rock provide a glimpse into the multiphase flow properties of the rock and the impact of injection and geochemical processes their modification. We present some results obtained by the method of Maximal Inscribed Spheres developed at Lawrence Berkeley National Laboratory. This work follows up presentation Eos Trans. AGU, 86(52), 2005 Fall Meet. Suppl., Abstract H33A-1381
H12C-08
Non-modal analysis of the onset of density-driven convection in porous media: Effect of medium heterogeneity
In the context of geological sequestration of carbon dioxide (CO2), trapping of the injected CO2 due to dissolution is expected to play a dominant role in the short term. Due to it's importance, a lot of work has recently been done to understand the length and time scales associated with the convective motions leading to the dissolution of injected CO2. Recently, Rapaka et. al. (J. Fluid Mech., vol 609, p285-303, 2008) have used non-modal stability theory to obtain rigorous estimates of the growth rates of perturbations in homogeneous porous media. Non-modal stability theory is a mathematically rigorous extension of the traditional normal-mode (eigenvalue) approach to time-dependent systems. We present an extension of this method to account for heterogeneity of the permeability field. In particular, we study the two simplified problems of vertical heterogeneity (layering) and horizontal heterogeneity. We present results for the distribution functions of the critical time as a function of the mean, variance and correlation length of the permeability field.