Recent studies suggest that continental flood basalts may be suitable for geologic carbon sequestration due to fluid-rock reactions that mineralize injected CO₂ on relatively short time-scales. Flood basalts also possess a permeability structure favorable for injection, with alternating high-permeability (flow margin) and low-permeability (flow interior) layers. However, little information exists on the behavior of CO₂ as it leaks through fractures characteristic of the flow interior, particularly at conditions near the critical point for CO₂. In this study, a two-dimensional 5 × 5 m model of a fracture network is built based on high-resolution LiDAR scans of a Columbia River Basalt flow interior taken near Starbuck, WA. Three-phase CO₂ flow is simulated using TOUGH3 (beta) with equation of state ECO2M for 10 years simulation time. Initial conditions comprise a hydrostatic pressure profile corresponding to 750-755 m below ground surface and a constant temperature of 32° C. Under these conditions, the critical point for CO₂ occurs 1.5 meters above the bottom of the domain. Matrix permeability is assumed to be constant, based on literature values for the Columbia River Basalt. Fracture permeability is assigned based on a lognormal distribution of random values with mean and standard deviation based on measured fracture aperture values and in situ permeability values from literature. In order to account for fracture permeability uncertainty, CO₂ leakage is simulated in 50 equally probable realizations of the same fracture network with spatially random permeability constrained by the lognormal permeability distribution. Results suggest that fracture permeability uncertainty has some effect on the distribution of CO₂ within the fractures, but network geometry is the primary control in determining flow paths. Fracture permeability uncertainty has a larger influence on fluid pressure, and can affect the location of the critical point within ~1.5 m. Uncertainty in fluid pressure was found to be highest along major flow paths below channel constrictions, indicating permeability at a few key points can have a large influence on fluid pressure distribution. / Master of Science / Geologic carbon sequestration (GCS) is a means of reducing greenhouse gas emissions using currently available technology. It consists of trapping carbon dioxide (CO<i>2</i>) released by the burning of fossil fuels at a large emitter, such as a coal fired power plant, and injecting it deep beneath the earth’s surface for permanent storage. This research builds on an increasing body of evidence that suggests that the Columbia River Basalt Group (GRBG), a large lava formation located in the northwestern United States, may be a suitable target for GCS. This is largely because CO<i>2</i> reacts with basalt rocks within a few years of injection to form stable minerals, after which it is permanently immobilized. This basalt province also contains alternating layers of rock, some of which have high permeability, meaning that they can accept CO<i>2</i> injections, and some of which have low permeability, meaning that they would block CO<i>2</i> rising from the injection layers. Layers with low permeability are called confining layers, and in the CRBG, they contain fractures that formed when the lava initially cooled. While some information about these fractures is known, it is impossible to know how easily fluid might flow through them at any given point (permeability) at the depths of interest for GCS. This study seeks to quantify the effects of that uncertainty, by building a model of CO<i>2</i> flow through a CRBG fracture set, and running that same model 50 times with all variables held constant, except the exact location of permeability values within the fracture network. Chemical reactions are not considered, so this model represents behavior in the network very soon after CO<i>2</i> is injected, before minerals start to form. The results of this model suggest that uncertainty in permeability values within fractures influences predictions of fluid pressure within the confining layer. This is important, because fluid pressure has a large influence on whether or not CO<i>2</i> will leak through the confining layer. This research will be useful in informing the model design of future researchers attempting to simulate GCS efforts in the CRBG and similar geologic formations.

Fractures are the main flow channels in naturally fractured reservoirs. Therefore the fracture permeability is a critical parameter to production optimization and reservoir management. Fluid pressure reduction caused by production induces an increase in effective stress in naturally fractured reservoirs. The change of effective stress induces fracture deformation and changes fracture aperture and permeability, which in turn influences the production. Coupled interactions exist in the fractured reservoir: (i) fluid pressure change induces matrix deformation and stress change; (ii) matrix deformation induces fluid volume change and fluid pressure change; (iii) fracture deformation induces the change of pore pressure and stress in the whole field (the influence disappears at infinity); (iv) the change of pore pressure and stress at any point has an influence on the fracture and induces fracture deformation. To model accurately the influence of pressure reduction on the fracture permeability change in naturally fractured reservoirs, all of these coupled processes need to be considered. Therefore, in this dissertation a fully coupled approach is developed to model the influence of production on fracture aperture and permeability by combining a finite difference method to solve the fluid flow in fractures, a fully coupled displacement discontinuity method to build the global relation of fracture deformation, and the Barton-Bandis model of fracture deformation to build the local relation of fracture deformation. The fully coupled approach is applied to simulate the fracture permeability change in naturally fracture reservoir under isotropic in situ stress conditions and high anisotropic in situ stress conditions, respectively. Under isotropic stress conditions, the fracture aperture and permeability decrease with pressure reduction caused by production, and the magnitude of the decrease is dependent on the initial effective in situ stress. Under highly anisotropic stress, the fracture permeability can be enhanced by production because of shear dilation. The enhancement of fracture permeability will benefit to the production of oil and gas.

Serpentinization is a complex set of hydration reactions, where olivine and pyroxene are replaced by serpentine, magnetite, brucite, talc and carbonate minerals. Serpentinization reactions alter chemical, mechanical, magnetic, seismic, and hydraulic properties of the crust. To understand the complicated nature of serpentinization and the linkages between physical and chemical changes during the reactions, I performed flow-through laboratory experiments on cylindrically cored samples of ultramafic rocks. Each core had a well-mated through-going tensile fracture, to investigate evolution of fracture permeability during serpentinization. The samples were tested in a triaxial loading machine at an effective pressure of 30 MPa, and temperature of 260°C, simulating a depth of 2 km under hydrostatic conditions. Fracture permeability decreased by one to two orders of magnitude during the 200 to 340 hour experiments. Electron microprobe and SEM data indicated the formation of needle-shaped crystals of serpentine composition along the walls of the fracture, and chemical analyses of sampled pore fluids were consistent with dissolution of ferro-magnesian minerals. The rate of transformation of olivine to serpentine in a tensile fracture is calculated using the data on evolution of fracture permeability assuming the fracture permeability could be represented by parallel plates. Assuming the dissolution and precipitation reactions occur simultaneously; the rate of transformation at the beginning of the experiments was ~ 10-8-10-9 (mol/m2s) and decreased monotonically by about an order of magnitude towards the end of the experiment. Results show that dissolution and precipitation is the main mechanism contributing to the reduction in fracture aperture. The experimental results suggest that the fracture network in long-lived hydrothermal circulation systems may be sealed rapidly as a result of mineral precipitation, and generation of new permeability resulting from a combination of tectonic and crystallization-induced stresses may be required to maintain fluid circulation. Another set of flow through experiments were performed on intact samples of ultramafic rocks at room temperature and effective pressures of 10, 20 and 30 MPa to estimate the pressure dependency of intact permeability. Porosity and density measurements were also performed with the purpose of characterizing these properties of ultramafic rocks. The pressure dependency of the coefficient of matrix permeability of the ultramafic rock samples fell in the range of 0.05-0.14 MPa-1. Using porosity and permeability measurements, the ratio of interconnected porosity to total porosity was estimated to be small and the permeability of the samples was dominantly controlled by microcracks. Using the density and porosity measurements, the degree of alteration of samples was estimated. Samples with high density and pressure dependent permeability had a smaller degree of alteration than those with lower density and pressure dependency. / Ph. D.

The vast majority of oil and gas reserves are trapped in fractured carbonate reservoirs. Most carbonate reservoirs are naturally fractured, with fractures ranging from millimeter- to kilometer-scale. These fractures create complex flow behaviors which impact reservoir characterization, production performance, and, eventually, total recovery. As we know, bridging the gas from plug to near-wellbore, eventually to field scales, is a persisting challenge in modeling Naturally Fractured Reservoirs (NFRs). This dissertation will focus on assessing the fundamental flow mechanisms in fractured rocks at the plug scale, understanding the governing upscaling parameters, and ultimately, developing fit-for-purpose upscaling tools for field-scale implementation. In this dissertation, we first focus on the upscaling of rock fractures under the laminar flow regime. A novel analytical model is presented by incorporating the effects of normal aperture, roughness, and tortuosity. We then investigate the stress-dependent hydraulic behaviors of rock fractures. A new and generalized theoretical model is derived and verified by a dataset collected from public experimental resources. In addition, an efficient coupled flow-geomechanics algorithm is developed to further validate the proposed analytical model. The physics of matrix-fracture interaction and fluid leakage is modeled by a high-resolution, micro-continuum approach, called extended Darcy-Brinkman-Stokes (DBS) equations. We observe the back-flow phenomena for the first time. Machine learning is then implemented into our traditional upscaling work under complex physics (e.g., initial and Klinkenberg effects). We finally consolidate the lab-scale upscaling tools and scale them up to the field scale. We develop a fully coupled hydro-mechanical model based on the Discrete-Fracture Model (DFM) in fractured reservoirs, in which we incorporate localized effects of fracture roughness at the field-scale.

A large percentage of oil and gas reservoirs in the most productive regions such as the Middle East, South America, and Southeast Asia are naturally fractured reservoirs (NFR). The major difference between conventional reservoirs and naturally fractured reservoirs is the discontinuity in media in fractured reservoir due to tectonic activities. These discontinuities cause remarkable difficulties in describing the petrophysical structures and the flow of fluids in the fractured reservoirs. Predicting fluid flow behavior in naturally fractured reservoirs is a challenging area in petroleum engineering. Two classes of models used to describe flow and transport phenomena in fracture reservoirs are discrete and continuum (i.e. dual porosity) models. The discrete model is appealing from a modeling point of view, but the huge computational demand and burden of porting the fractures into the computational grid are its shortcomings. The affect of natural fractures on the permeability anisotropy can be determined by considering distribution and orientation of fractures. Representative fracture permeability, which is a crucial step in the reservoir simulation study, must be calculated based on fracture characteristics. The diagonal representation of permeability, which is customarily used in a dual porosity model, is valid only for the cases where fractures are parallel to one of the principal axes. This assumption cannot adequately describe flow characteristics where there is variation in fracture spacing, length, and orientation. To overcome this shortcoming, the principle of the full permeability tensor in the discrete fracture network can be incorporated into the dual porosity model. Hence, the dual porosity model can retain the real fracture system characteristics. This study was designed to develop a novel approach to integrate dual porosity model and full permeability tensor representation in fractures. A fully implicit, parallel, compositional chemical dual porosity simulator for modeling naturally fractured reservoirs has been developed. The model is capable of simulating large-scale chemical flooding processes. Accurate representation of the fluid exchange between the matrix and fracture and precise representation of the fracture system as an equivalent porous media are the key parameters in utilizing of dual porosity models. The matrix blocks are discretized into both rectangular rings and vertical layers to offer a better resolution of transient flow. The developed model was successfully verified against a chemical flooding simulator called UTCHEM. Results show excellent agreements for a variety of flooding processes. The developed dual porosity model has further been improved by implementing a full permeability tensor representation of fractures. The full permeability feature in the fracture system of a dual porosity model adequately captures the system directionality and heterogeneity. At the same time, the powerful dual porosity concept is inherited. The implementation has been verified by studying water and chemical flooding in cylindrical and spherical reservoirs. It has also been verified against ECLIPSE and FracMan commercial simulators. This study leads to a conclusion that the full permeability tensor representation is essential to accurately simulate fluid flow in heterogeneous and anisotropic fracture systems. / text

This thesis is dedicated to the study of the turbulent fluid flow in rough-walled rock fractures. Fracture models were generated from 3D scans of fractured rock samples, while fluid flow was simulated numerically by means of FVM-based open-source CFD toolbox OpenFOAM, employing the high-performance computing cluster for the more demanding 3D models. First part of the thesis addresses the issue of fracture geometry. Realistic 2D and 3D fracture models were constructed from 3D scans of upper and lower halves of a fractured rock sample, taking both shear displacement and contact spots into account. Furthermore, we discuss the shortcomings of the available fracture aperture metrics and propose a new aperture metric based on the Hausdorff distance; imaging performance of the new metric is shown to be superior to the conventional vertical aperture, especially for rough fracture surfaces with abundant ridges and troughs. In the second part of the thesis we focus on the fluid flow through the rock fracture for both 2D and 3D cases. While previous studies were largely limited to the fully viscous Darcy or inertial Forchheimer laminar flow regimes, we chose to investigate across the widest possible range of Reynolds numbers from 0.1 to 10^6, covering both laminar and turbulent regimes, which called for a thorough investigation of suitable turbulence modeling techniques. Due to narrow mean aperture and high aspect ratio of the typical fracture geometry, meshing posed a particularly challenging problem. Taking into account limited computational resources and a sheer number of model geometries, we developed a highly-optimised workflow, employing the steady-state RANS simulation approach to obtain time-averaged flow fields. Our findings show that while flow fields remain mostly stationary and undisturbed for simpler contactless geometries, emergence of contact spots immediately triggers a transition to non-stationary flow starting from Re ∼ 10^2, which is reflected by the streamline tortuosity data. This transition disrupts the flow pattern across the fracture plane, causing strong channeling and large separation bubbles, with area of the latter being much larger than the generating contact spots. Adverse influence of the contact spots on the overall permeability is strong enough to override any benefits of aperture increase during shear and dilation. Contactless 3D models can to a certain degree be approximated by their 2D counterparts. Lastly, we investigate the influence of both shearing and contact spots on the overall permeability and friction factor of the fracture, drawing a parallel to the well-studied area of turbulent flow in rough-walled pipes and ducts. Unlike the latter, 3D curvilinear fracture geometries exhibit a gapless laminar–turbulent transition, behaving as a hydraulically rough channel in the turbulent range as the shear displacement increases.