Publications

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Pore structure is an important parameter to quantify the reservoir rock adsorption capability and diffusivity, both of which are fundamental reservoir properties to evaluate the gas production and carbon sequestration potential for coalbed methane (CBM) and shale gas reservoirs. In this study, we applied small-angle neutron scattering (SANS) to characterize the total and accessible pore structures for two coal and two shale samples. We carried out in situ SANS measurements to probe the accessible pore structure differences under argon, deuterated methane (CD 4 ), and CO 2 penetrations. The results show that the total porosity ranges between 0.25 and 5.8% for the four samples. Less than 50% of the total pores are accessible to CD 4 for the two coals, while more than 75% of the pores were found to be accessible for the two shales. This result suggests that organic matter pores tend to be disconnected compared to mineral matter pores. Argon pressurization can induce pore contraction because of the mechanical compression of the solid skeleton in both the coal and shale samples. Hydrostatic compression has a higher effect on the nanopores of coal and shale with a higher accessible porosity. Both methane and CO 2 injection can reduce the accessible nanopore volume due to a combination of mechanical compression, sorption-induced matrix swelling, and adsorbed molecule occupation. CO 2 has higher effects on sorption-induced matrix swelling and pore filling compared to methane for both the coal and shale samples. Gas densification and pore filling could occur at higher pressures and smaller pore sizes. In addition, the compression and adsorption could create nanopores in the San Juan coal and Marcellus shale drilled core but could have an opposite effect in the other samples, namely, the processes could damage the nanopores in the Hazleton coal and Marcellus shale outcrop.

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The fluid injection into the subsurface perturbs the states of pore pressure and stress on the pre-existing faults, potentially causing earthquakes. In the multiphase flow system, the contrast of fluid and rock properties between different structures produces the changes in pressure gradients and subsequently stress fields. Assuming two-phase fluid flow (gas-water system) and poroelasticity, we simulate the three-layered formation including a basement fault, in which injection-induced pressure encounters the fault directly given injection scenarios. The single-phase poroelasticity model with the same setting is also conducted to evaluate the multiphase flow effects on poroelastic response of the fault to gas injection. Sensitivity tests are performed by varying the fault permeability. The presence of gaseous phase reduces the pressure buildup within the highly gas-saturated region, causing less Coulomb stress changes, whereas capillarity increases the pore pressure within the gas-water mixed region. Even though the gaseous plume does not approach the fault, the poroelastic stressing can affect the fault stability, potentially the earthquake occurrence.

The fluid injection into the subsurface perturbs the states of pore pressure and stress on the pre-existing faults, potentially causing earthquakes. In the multiphase flow system, the contrast of fluid and rock properties between different structures produces the changes in pressure gradients and subsequently stress fields. Assuming two-phase fluid flow (gas-water system) and poroelasticity, we simulate the three-layered formation including a basement fault, in which injection-induced pressure encounters the fault directly given injection scenarios. The single-phase poroelasticity model with the same setting is also conducted to evaluate the multiphase flow effects on poroelastic response of the fault to gas injection. Sensitivity tests are performed by varying the fault permeability. The presence of gaseous phase reduces the pressure buildup within the highly gas-saturated region, causing less Coulomb stress changes, whereas capillarity increases the pore pressure within the gas-water mixed region. Even though the gaseous plume does not approach the fault, the poroelastic stressing can affect the fault stability, potentially the earthquake occurrence.

Anisotropy in the mechanical properties of rock is often attributed to layering or mineral texture. Here, results from a study on mode I fracturing are presented that examine the effect of layering and mineral orientation fracture toughness and roughness. Additively manufactured gypsum rock was created through 3D printing with bassanite/gypsum. The 3D printing process enabled control of the orientation of the mineral texture within the printed layers. Three-point bending (3PB) experiments were performed on the 3D printed rock with a central notch. Unlike cast gypsum, the 3D-printed gypsum exhibited ductile post-peak behavior in all cases. The experiments also showed that the mode I fracture toughness and surface roughness of the induced fracture depended on both the orientation of the bedding relative to the load and the orientation of the mineral texture relative to the layering. This study found that mineral texture orientation, chemical bond strength and layer orientation play dominant roles in the formation of mode I fractures. The uniqueness of the induced fracture roughness is a potential method for the assessment of bonding strengths in rock.

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Understanding of the potential to injection–induced seismicity along faults requires the response of fault zone system to spatiotemporal perturbations in pore pressure and stress. In this study, three–dimensional (3–D) model system consisting of the caprock, reservoir, and basement is intersected by vertical strike–slip faults. We examine the full poroelastic behavior of the formation and perform the mechanical analysis along each fault zone using the Coulomb stress change. The magnitude, rate, and location of potential earthquakes are predicted using the spatial distribution of stresses and pore pressure over time. Rapid diffusion of pore pressure into conductive faults initiates failure, but the majority of induced seismicity occurs at deep fault zones due to poroelastic stabilization near the injection interval. Less permeable faults can be destabilized by either delayed pore pressure diffusion or poroelastic stressing. A two–dimensional (2–D) horizontal model, representing the interface between the reservoir and the basement, limits diffusion of pore pressure and deformation of the formation in the vertical direction that may overestimate or underestimate the potential of earthquakes along the fault. Lastly, our numerical results suggest that the 3–D modeling of faulting system including poroelastic coupling can reduce the uncertainty in the seismic hazard prediction by considering the hydraulic and mechanical interaction between faults and bounding formations.

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Injection of large amounts of fluid into the subsurface alters the states of pore pressure and stress in the formation, potentially inducing earthquakes. Increase in the seismicity rate after shut-in is often observed at fluid-injection operation sites, but mechanistic study of the rate surge has not been investigated thoroughly. Considering full poroelastic coupling of pore pressure and stress, the earthquake occurrence after shut-in can be driven by two mechanisms: (1) post shut-in diffusion of pore pressure into distant faults and (2) poroelastic stressing caused by fluid injection. Interactions of these mechanisms can depend on fault geometry, hydraulic and mechanical properties of the formation, and injection operation. In this work, a 2D aerial view of the target reservoir intersected by strike-slip basement faults is used to evaluate the impact of injection-induced pressure buildup on seismicity rate surge. A series of sensitivity tests are performed by considering the variation in (1) permeability of the fault zone, (2) locations and the number of faults with respect to the injector, and (3) well operations with time-dependent injection rates. Lower permeability faults have higher seismicity rates than more permeable faults after shut-in due to delayed diffusion and poroelastic stressing. Hydraulic barriers, depending on their relative location to injection, can either stabilize or weaken a conductive fault via poroelastic stresses. Gradual reduction of the injection rate minimizes the coulomb stress change and the least seismicity rates are predicted due to slower relaxation of coupling-induced compression as well as pore-pressure dissipation.

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The fluid injection into deep geological formations altar the states of pore pressure and stress on the faults, potentially causing earthquakes. In the multiphase flow system, the interaction between fluid flow and mechanical deformation in porous media is critical to determine the spatio-temporal distribution of pore pressure and stress. The contrast of fluid and rock properties between different structures produces the changes in pressure gradients and subsequently stress fields. Assuming two-phase fluid flow (gas-water system), we simulate the two-dimensional reservoir including a basement fault, in which injection-induced pressure encounters the fault directly given injection scenarios. The single-phase flow model with the same setting is also conducted to evaluate the multiphase flow effects on mechanical response of the fault to gas injection. A series of sensitivity tests are performed by varying the fault permeability. The presence of gaseous phase reduces the pressure buildup within the gas-saturated region, causing less Coulomb stress change. The low-permeability fault prevent diffusion initially as observed in the single-phase flow system. Once gaseous phase approaches, the fault acts as a capillary barrier that causes increases in pressure within the fault zone, potentially inducing earthquakes even without direct diffusion.

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The purpose of the project was to perform multiscale characterization of low permeability rocks to determine the effect of physical and chemical heterogeneity on the poromechanical and flow responses of shales and carbonate rocks with a broad range of physical and chemical heterogeneity . An integrated multiscale imaging of shale and carbonate rocks from nanometer to centimeter scales include s dual focused ion beam - scanning electron microscopy (FIB - SEM) , micro computed tomography (micro - CT) , optical and confocal microscopy, and 2D and 3D energy dispersive spectroscopy (EDS). In addition, mineralogical mapping and backscattered imaging with nanoindentation testing advanced the quantitative evaluat ion of the relationship between material heterogeneity and mechanical behavior. T he spatial distribution of compositional heterogeneity, anisotropic bedding patterns, and mechanical anisotropy were employed as inputs for brittle fracture simulations using a phase field model . Comparison of experimental and numerical simulations reveal ed that proper incorporation of additional material information, such as bedding layer thickness and other geometrical attributes of the microstructures, can yield improvements on the numerical prediction of the mesoscale fracture patterns and hence the macroscopic effective toughness. Overall, a comprehensive framework to evaluate the relationship between mechanical response and micro-lithofacial features can allow us to make more accurate prediction of reservoir performance by developing a multi - scale understanding of poromechanical response to coupled chemical and mechanical interactions for subsurface energy related activities.

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