Publications

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The Mount Simon Sandstone and Eau Claire Formation represent a potential reservoir-caprock system for wastewater disposal, geologic CO2 storage, and compressed air energy storage (CAES) in the Midwestern United States. A primary concern to site performance is heterogeneity in rock properties that could lead to nonideal injectivity and distribution of injected fluids (e.g., poor sweep efficiency). Using core samples from the Dallas Center domal structure, Iowa, we investigate pore characteristics that govern flow properties of major lithofacies of these formations. Methods include gas porosimetry and permeametry, mercury intrusion porosimetry, thin section petrography, and X-ray diffraction. The lithofacies exhibit highly variable intraformational and interformational distributions of pore throat and body sizes. Based on pore-throat size, there are four distinct sample groups. Micropore-throat-dominated samples are from the Eau Claire Formation, whereas the macropore-dominated, mesopore-dominated, and uniform-dominated samples are from the Mount Simon Sandstone. Complex paragenesis governs the high degree of pore and pore-throat size heterogeneity, due to an interplay of precipitation, nonuniform compaction, and later dissolution of cements. The cement dissolution event probably accounts for much of the current porosity in the unit. Mercury intrusion porosimetry data demonstrate that the heterogeneous nature of the pore networks in the Mount Simon Sandstone results in a greater than normal opportunity for reservoir capillary trapping of nonwetting fluids, as quantified by CO2 and air column heights that vary over three orders of magnitude, which should be taken into account when assessing the potential of the reservoir-caprock system for waste disposal (CO2 or produced water) and resource storage (natural gas and compressed air). Our study quantitatively demonstrates the significant impact of millimeter-scale to micron-scale porosity heterogeneity on flow and transport in reservoir sandstones.

The objective of this research is to produce laboratory-based experimental and numerical analysis that will provide a physics-based understanding of shear stimulation phenomena (hydroshearing) and its evolution during stimulation. Water is flowed along fractures in hot and stressed fractured rock, to promote slip. The controlled laboratory experiments potentially provide a high resolution/high quality data resource for evaluation of many analysis methods developed by to assess EGS "behavior" during this stimulation process. Segments of the experimental program provide data sets for model input parameters, i.e., material properties, and other segments of the experimental program represent small scale physical models of an EGS system, which may be modeled. The project is a study of the response of a fracture in hot, water-saturated fractured rock to shear stress which is experiencing fluid flow. Under this condition, the fracture experiences a combination of potential pore pressure changes and fracture surface cooling, resulting in slip along the fracture. As such, the work provides a means to assess the role of "hydroshearing" on permeability enhancement in reservoir stimulation. Using the laboratory experiments and modeling, including pore pressure, thermal stress, fracture shear deformation, and fluid flow, insight into the role of fracture slip on permeability enhancement-"hydro-shear" is obtained. This paper presents the results of an experimental program along with numerical modeling to study shear stimulation of fractures in response to cool water injection into hot stressed rock with simulated fractures. Laboratory-based experimental and numerical analysis results are used to provide a physics-based understanding of shear stimulation phenomena (hydroshearing) and its evolution during stimulation. In order to study hydroshearing in the laboratory, a test system has been configured to (1) simulate reasonable downhole EGS environmental conditions, (2) flow cool water along fractures in hot and stressed fractured rock, (3) from (2) promote slip, (4) model the experiments in a tractable manner such that insight may be obtained of slip mechanisms. Thermo-poroelastic finite element analysis of a fractured rock injection experiment has been carried out to explore the role of pore pressure, cooling and coupled processes on fracture deformation and slip. Good agreement between numerical modeling and experimental observations is achieved. Simulation results illustrate that pore pressure and cooling cause the fracture system to deform (slip) resulting in permeability modifications. Fracture permeability evolution with stress variations in the sample is also observed in these experiments.

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Seven water-saturated triaxial extension experiments were conducted on four sedimentary rocks. This experimental condition was hypothesized more representative of that existing for downhole hydrofracture and thus it may improve our understanding of the phenomena. In all tests the pore pressure was 10 MPa and confirming pressure was adjusted to achieve tensile and transitional failure mode conditions. Using previous work in this LDRD for comparison, the law of effective stress is demonstrated in extension using this sample geometry. In three of the four lithologies, no apparent chemo-mechanical effect of water is apparent, and in the fourth lithology test results indicate some chemo-mechanical effect of water.

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This report presents efforts to develop the use of in situ naturally-occurring noble gas tracers to evaluate transport mechanisms and deformation in shale hydrocarbon reservoirs. Noble gases are promising as shale reservoir diagnostic tools due to their sensitivity of transport to: shale pore structure; phase partitioning between groundwater, liquid, and gaseous hydrocarbons; and deformation from hydraulic fracturing. Approximately 1.5-year time-series of wellhead fluid samples were collected from two hydraulically-fractured wells. The noble gas compositions and isotopes suggest a strong signature of atmospheric contribution to the noble gases that mix with deep, old reservoir fluids. Complex mixing and transport of fracturing fluid and reservoir fluids occurs during production. Real-time laboratory measurements were performed on triaxially-deforming shale samples to link deformation behavior, transport, and gas tracer signatures. Finally, we present improved methods for production forecasts that borrow statistical strength from production data of nearby wells to reduce uncertainty in the forecasts.

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