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One attractive aspect of CO2 sequestration in shale formations is the preferential adsorption of CO2 compared to methane, which may provide enhanced methane production as well as sequestration of carbon dioxide. In this work, a comprehensive theoretical model of CO2 migration at the pore scale is developed to study CO2 migration properties in organic-rich shale formations. The proposed model takes into account dynamic competitive adsorption between CO2 and CH4, slip-flow effects due to the nanometer range of pore sizes, and pore-size changes due to adsorption. Because of the high pressure and temperature, the injected CO2 is in supercritical phase. Pore bodies in the shale matrix are irregular in shape, with roughness along pore wall. The structure of pore body affects the amount of surface areas and associated number of adsorption sites, and hence, a shape factor is proposed in this work to consider the irregularity of pore structure in shale matrix. The sorption of CO2 leads to an apparent retardation of the migration of CO2, which is quantified in this work. The developed pore-network model is extended to consider the impacts of different spatial distributions of the organic materials within the shale matrix. [ABSTRACT FROM AUTHOR]

Various modeling approaches, including fully three-dimensional (3D) models and vertical-equilibrium (VE) models, have been used to study the large-scale storage of carbon dioxide (CO2) in deep saline aquifers. 3D models solve the governing flow equations in three spatial dimensions to simulate migration of CO2 and brine in the geological formation. VE models assume rapid and complete buoyant segregation of the two fluid phases, resulting in vertical pressure equilibrium and allowing closed-form integration of the governing equations in the vertical dimension. This reduction in dimensionality makes VE models computationally much more efficient, but the associated assumptions restrict the applicability of VE models to geological formations with moderate to high permeability. In the present work, we extend the VE models to simulate CO2 storage in fractured deep saline aquifers in the context of dual-continuum modeling, where fractures and rock matrix are treated as porous media continua with different permeability and porosity. The high permeability of fractures makes the VE model appropriate for the fracture domain, thereby leading to a VE dual-continuum model for the dual continua. The transfer of fluid mass between fractures and rock matrix is represented by a mass transfer function connecting the two continua, with a modified transfer function for the VE model based on vertical integration. Comparison of the new model with a 3D dual-continuum model shows that the new model provides comparable numerical results while being much more computationally efficient. [ABSTRACT FROM AUTHOR]

We construct a three-dimensional pore-network model with mixed wettability to study the two-phase flow mechanisms in dry gas producing shales. Previous pore-scale modeling studies on shale have been focused on single-phase gas flow through the nano-pores. However, at most field sites, the majority of the injected fracking fluid does not return to the surface during the flow-back period. It is believed that a large portion of the fracking fluid imbibes into the shale matrix during the fracking process, and thus two-phase flow occurs. In addition, while the inorganic shale matrix is generally water-wet, the organic material embedded within the matrix is hydrophobic. As such, the system displays spatial heterogeneity of wettability. Other important physics are also coupled in the model. Pressure-dependent gas sorption effects are included in the organic pores, with pore size reduction accounted for in those pores. Compressibility and slip flow effects of the gas phase are included throughout the pore-network, with the latter underscoring the fact that the sizes of the nano-pores are comparable to the mean free path of the methane molecule. The coupled effects of these various physical processes are studied to determine the importance of each effect. Continuum-scale properties are computed, including relative permeability curves, as a function of fraction and structure of organic regions and type and magnitude of boundary conditions. [ABSTRACT FROM AUTHOR]

Subsurface two-phase flow in porous media often takes place in reservoirs with a high ratio between the associated lateral and vertical extent and the lateral and vertical flow time scales. This allows for a two-scale approach with effective quantities for two-dimensional horizontal flow equations obtained from reconstructed hydrostatic vertical pressure and saturation distributions. Here, we derive explicit expressions for the two dimensional constitutive relationships for a play-type hysteretic Brooks-Corey capillary pressure function with a pore-size distribution index of 2 and quadratic relative permeabilities. We obtain an explicit hysteretic parametrization for the upscaled capillary pressure function and the upscaled relative permeabilities. The size of the hysteresis loop depends on the ratio between buoyancy and the entry pressure, i.e. it scales with the reservoir height and the ratio between drainage and imbibition capillary pressure. We find that the scaling for the relative permeability is non-monotonic and hysteresis vanishes for both small and large reservoirs. [ABSTRACT FROM AUTHOR]

Stabilization of CO atmospheric concentrations requires practical strategies to address the challenges posed by the continued use of coal for baseload-electricity production. Over the next two decades, CO capture and sequestration (CCS) demonstration projects would need to increase several orders of magnitude across the globe in both size and scale. This task has several potential barriers which will have to be accounted for. These barriers include those that have been known for a number of years including safety of subsurface sequestration, pore-space competition with emerging activities like shale gas production, legal and regulatory frameworks, and public acceptance and technical communication. In addition water management is a new challenge that should be actively and carefully considered across all CCS operations. A review of the new insights gained on these previously and newly identified challenges, since the IPCC special report on CCS, is presented in this paper. While somewhat daunting in scope, some of these challenges can be addressed more easily by recognizing the potential advantageous synergies that can be exploited when these challenges are dealt with in combination. For example, active management of water resources, including brine in deep subsurface formations, can provide the additional cooling-water required by the CO capture retrofitting process while simultaneously reducing sequestration leakage risk and furthering efforts toward public acceptance. This comprehensive assessment indicates that water, sequestration, legal, and public acceptance challenges ought to be researched individually, but must also be examined collectively to exploit the promising synergies identified herein. Exploitation of these synergies provides the best possibilities for successful large-scale implementation of CCS. [ABSTRACT FROM AUTHOR]

The Mount Simon and Lower Knox Group Formations within the Illinois Basin, USA, are being considered as targets for carbon dioxide (CO $$_2$$ ) storage. Two main concerns related to the subsurface storage process are potential leakage of CO $$_2$$ from the storage formation to the atmosphere and possible migration of CO $$_2$$ or displaced brine into underground sources of drinking water. In this study we use a numerical model to represent the migration of both CO $$_2$$ and brine in the Mount Simon Sandstone and two overlying aquifers, the shallowest of which is considered a potential source of drinking water. A vertically-integrated approach is used to model the fluid flow, leading to a stack of two-dimensional subdomains which are connected by leakage through the aquitards which separate the aquifers. Each formation is discretized into 12,103 grid cells, each $$5 \times 5\,\mathrm{{km}}$$ , and permeability and porosity vary spatially. Two vertical refinements are used for the Mount Simon Sandstone: the first represents the Mount Simon as a single layer, while the second subdivides the formation into subunits within the formation that have varying petrophysical properties. The locations and injection rates of the hypothetical injection operations are based on existing sources of CO $$_2$$ associated with power generation, ethanol production, and oil and gas refineries. A total of 250.5 million metric tons are injected at 118 sites. The injection operations are assumed to continue for 50 years. Results indicate the maximum radial extent of the CO $$_2$$ plume increased from 40 to 50 km between the single layer and multi-layer representations of the Mount Simon. Maximum average pore pressures reached 8.6 MPa and the pressure envelop extended as much as 100 km from the injection wells with significant well-well pressure interference patterns. The maximum well head pressure exceeded the fracture pressure in some cases suggesting more wells may be needed at some of the lower permeability injection sites. Brine leakage into overlying shallower units was not significant. [ABSTRACT FROM AUTHOR]

We propose a simple pressure test that can be used in the field to determine the effective permeability of existing wellbores. Such tests are motivated by the need to understand and quantify leakage risks associated with geological storage of CO2 in mature sedimentary basins. If CO2 is injected into a deep geological formation, and the resulting CO2 plume encounters a wellbore, leakage may occur through various pathways in the “disturbed zone” surrounding the well casing. The effective permeability of this composite zone, on the outside of the well casing, is an important parameter for models of leakage. However, the data that exist on this key parameter do not exist in the open literature, and therefore specific field tests need to be done in order to reduce the uncertainty inherent in the leakage estimates. The test designed and analyzed herein is designed to measure effective wellbore permeability within a low-permeability caprock, bounded above and below by permeable reservoirs, by pressurizing the reservoir below and measuring the response in the reservoir above. Alternatively, a modified test can be performed within the caprock without directly contacting the reservoirs above and below. We use numerical simulation to relate pressure response to effective well permeability and then evaluate the range of detection of the effective permeability based on instrument measurement error and limits on fracture pressure. These results can guide field experiments associated with site characterization and leakage analysis. [ABSTRACT FROM AUTHOR]

This work was motivated by considerations of potential leakage pathways for CO2 injected into deep geological formations for the purpose of carbon sequestration. Because existing wells represent a potentially important leakage pathway, a spatial analysis of wells that penetrate a deep aquifer in the Alberta Basin was performed and various statistical measures to quantify the spatial distribution of these wells were presented. The data indicate spatial clustering of wells, due to oil and gas production activities. The data also indicate that the number of wells that could be impacted by CO2 injection, as defined by the spread of an injected CO2 plume, varies from several hundred in high well-density areas to about 20 in low-density areas. These results may be applied to other mature continental sedimentary basins in North America and elsewhere, where detailed information on well location and status may not be available. [ABSTRACT FROM AUTHOR]

A dynamic pore scale network model is formulated for two phase immiscible flow. Interfaces are tracked through the pore throats using a modified Poiseuille equation, whereas special displacement rules are used at the pore bodies. The model allows interfaces to move over several pore lengths within a time step. Initial computational results are presented for a drainage experiment to demonstrate some of the features of the model. [ABSTRACT FROM AUTHOR]