This study presents the development of a cell-based routing model. The model developed is a two parameter hydrological routing model that uses a coarse resolution stream network to route runoff from each cell in the watershed to the outlet. The watershed is divided into a number of equal cells, which are approximated as cascade of linear reservoirs or tanks. Water is routed from a cell downstream, depending on the flow direction of the cell, using the cascade of tanks. The routing model consists of two phases, first is the overland flow routing, which is followed by the channel flow routing. In this study, the cell-to-cell stream flow routing model is applied to the Brazos River Basin to demonstrate the impact of the cascade of tanks on the flow over a simple linear reservoir method. This watershed was tested with a uniform runoff depth in absence of observed runoff data. A case study on Waller Creek in Austin, Texas with observed runoff depths and stream flow is used to demonstrate the calibration and validation of model parameters.

This research utilizes the imbibition experiments and X-ray tomography results for modeling fluid flow in naturally fractured reservoirs. Conventional dual porosity simulation requires large number of runs to quantify transfer function parameters for history matching purposes. In this study empirical transfer functions (ETF) are derived from imbibition experiments and this allows reduction in the uncertainness in modeling of transfer of fluids from the matrix to the fracture. The application of the ETF approach is applied in two phases. In the first phase, imbibition experiments are numerically solved using the diffusivity equation with different boundary conditions. Usually only the oil recovery in imbibition experiments is matched. But with the advent of X-ray CT, the spatial variation of the saturation can also be computed. The matching of this variation can lead to accurate reservoir characterization. In the second phase, the imbibition derived empirical transfer functions are used in developing a dual porosity reservoir simulator. The results from this study are compared with published results. The study reveals the impact of uncertainty in the transfer function parameters on the flow performance and reduces the computations to obtain transfer function required for dual porosity simulation.

We propose a rigorous approach for well drainage volume calculations in gas reservoirs based on the flux field derived from dual porosity finite-difference simulation and demonstrate its application to optimize well placement. Our approach relies on a high frequency asymptotic solution of the diffusivity equation and emulates the propagation of a 'pressure front' in the reservoir along gas streamlines. The proposed approach is a generalization of the radius of drainage concept in well test analysis (Lee 1982), which allows us not only to compute rigorously the well drainage volumes as a function of time but also to examine the potential impact of infill wells on the drainage volumes of existing producers. Using these results, we present a systematic approach to optimize well placement to maximize the Estimated Ultimate Recovery. A history matching algorithm is proposed that sequentially calibrates reservoir parameters from the global-to-local scale considering parameter uncertainty and the resolution of the data. Parameter updates are constrained to the prior geologic heterogeneity and performed parsimoniously to the smallest spatial scales at which they can be resolved by the available data. In the first step of the workflow, Genetic Algorithm is used to assess the uncertainty in global parameters that influence field-scale flow behavior, specifically reservoir energy. To identify the reservoir volume over which each regional multiplier is applied, we have developed a novel approach to heterogeneity segmentation from spectral clustering theory. The proposed clustering can capture main feature of prior model by using second eigenvector of graph affinity matrix. In the second stage of the workflow, we parameterize the high-resolution heterogeneity in the spectral domain using the Grid Connectivity based Transform to severely compress the dimension of the calibration parameter set. The GCT implicitly imposes geological continuity and promotes minimal changes to each prior model in the ensemble during the calibration process. The field scale utility of the workflow is then demonstrated with the calibration of a model characterizing a structurally complex and highly fractured reservoir.

This study presents the development of a cell-based routing model. The model developed is a two parameter hydrological routing model that uses a coarse resolution stream network to route runoff from each cell in the watershed to the outlet. The watershed is divided into a number of equal cells, which are approximated as cascade of linear reservoirs or tanks. Water is routed from a cell downstream, depending on the flow direction of the cell, using the cascade of tanks. The routing model consists of two phases, first is the overland flow routing, which is followed by the channel flow routing. In this study, the cell-to-cell stream flow routing model is applied to the Brazos River Basin to demonstrate the impact of the cascade of tanks on the flow over a simple linear reservoir method. This watershed was tested with a uniform runoff depth in absence of observed runoff data. A case study on Waller Creek in Austin, Texas with observed runoff depths and stream flow is used to demonstrate the calibration and validation of model parameters.

Naturally fractured reservoirs (NFR) represent an important percentage of the worldwide hydrocarbon reserves and production. Reservoir simulation is a fundamental technique in characterizing this type of reservoir. Fracture properties are often not available due to difficulty to characterize the fracture system. On the other hand, well test analysis is a well known and widely applied reservoir characterization technique. Well testing in NFR provides two characteristic parameters, storativity ratio and interporosity flow coefficient. The storativity ratio is related to fracture porosity. The interporosity flow coefficient can be linked to shape factor, which is a function of fracture spacing. The purpose of this work is to investigate the feasibility of estimating fracture porosity and fracture spacing from single well test analysis and to evaluate the use of these two parameters in dual porosity simulation models. The following assumptions were considered for this research: 1) fracture compressibility is equal to matrix compressibility; 2) no wellbore storage and skin effects are present; 3) pressure response is in pseudo-steady state; and 4) there is single phase flow. Various simulation models were run and build up pressure data from a producer well was extracted. Well test analysis was performed and the result was compared to the simulation input data. The results indicate that the storativity ratio provides a good estimation of the magnitude of fracture porosity. The interporosity flow coefficient also provides a reasonable estimate of the magnitude of the shape factor, assuming that matrix permeability is a known parameter. In addition, pressure tests must exhibit all three flow regimes that characterizes pressure response in NFR in order to obtain reliable estimations of fracture porosity and shape factor.

To continue increasing the energy supply to meet global demand in the coming decades, the energy industry needs creative thinking that leads to the development of new energy sources. Unconventional gas resources, especially those in frontier basins, will play an important role in fulfilling future world energy needs. We must identify and quantify potential unconventional gas resources in basins around the world to plan for their development. Basin analog assessment is one technique that can be used to identify and quantify unconventional gas resources that is less expensive and less time consuming. We have developed a basin analog methodology that is useful for rapidly and consistently evaluating the unconventional hydrocarbon resource potential in exploratory basins. We developed software, Basin Analog System (BAS), to perform and accelerate the process of identifying analog basins. Also, we built a database that includes geologic and petroleum systems information of intensely studied North America basins that contain well characterized conventional and unconventional hydrocarbon resources. We have selected 25 basins in North America that have a history of producing unconventional gas resources. These are “reference” basins that are used to predict resources in frontier or exploratory basins. The software assists us in ranking reference basins that are most analogous to the target basin for the primary purpose of evaluating the potential unconventional resources in the target basin. The methodology allows us to numerically rank all the reference basins relative to the target basin. The accuracy of the results depends on the descriptions of geologic and petroleum systems. We validated the software to make sure it is functioning correctly and to test the validity of the process and the database. Finding a reference basin that is analogous to a frontier basin can provide insights into potential unconventional gas resources of the frontier basin. Our method will help industry predict the unconventional hydrocarbon resource potential of frontier basins, guide exploration strategy, infer reservoir characteristics, and make preliminary decisions concerning the best engineering practices as wells are drilled, completed, stimulated and produced.

Thesis (M.S.)--West Virginia University, 2009. / Title from document title page. Document formatted into pages; contains ix, 44 p. : ill. (some col.). Includes abstract. Includes bibliographical references (p. 34-35).

Thesis (M.S.)--West Virginia University, 2003. / Title from document title page. Document formatted into pages; contains xvii, 103 p. : ill. (some col.), maps. Includes abstract. Includes bibliographical references (p. 52-55).

"A thesis submitted to Oregon State University." / Includes appendices. Photocopy of original. Includes bibliographical references (leaves 126-132). Also available on the World Wide Web.

Large volumes of natural gas exist in tight fissured reservoirs. Hydraulic fracturing is one of the main stimulating techniques to enhance recovery from these fractured reservoirs. Although hydraulic fracturing has been used for decades for the stimulation of tight gas reservoirs, a thorough understanding of the interaction between induced hydraulic fractures and natural fractures is still lacking. Recent examples of hydraulic fracture diagnostic data suggest complex, multi-stranded hydraulic fracture geometry is a common occurrence. The interaction between pre-existing natural fractures and the advancing hydraulic fracture is a key condition leading to complex fracture patterns. Large populations of natural fractures that exist in formations such as the Barnett shale are sealed by precipitated cements which could be quartz, calcite, etc. Even though there is no porosity in the sealed fractures, they may still serve as weak paths for fracture initiation and/or for diverting the path of the growing hydraulic fractures. Performing hydraulic fracture design calculations under these complex conditions requires modeling of fracture intersections and tracking fluid fronts in the network of reactivated fissures. In this dissertation, the effect of the cohesiveness of the sealed natural fractures and the intact rock toughness in hydraulic fracturing are studied. Accordingly, the role of the pre-existing fracture geometry is also investigated. The results provide some explanations for significant differences in hydraulic fracturing in naturally fractured reservoirs from non-fractured reservoirs. For the purpose of this research, an extended finite element method (XFEM) code is developed to simulate fracture propagation, initiation and intersection. The motivation behind applying XFEM are the desire to avoid remeshing in each step of the fracture propagation, being able to consider arbitrary varying geometry of natural fractures and the insensitivity of fracture propagation to mesh geometry. New modifications are introduced into XFEM to improve stress intensity factor calculations, including fracture intersection criteria into the model and improving accuracy of the solution in near crack tip regions. The presented coupled fluid flow-fracture mechanics simulations extend available modeling efforts and provide a unified framework for evaluating fracture design parameters and their consequences. Results demonstrate that fracture pattern complexity is strongly controlled by the magnitude of in situ stress anisotropy, the rock toughness, the natural fracture cement strength, and the approach angle of the hydraulic fracture to the natural fracture. Previous studies (mostly based on frictional fault stability analysis) have concentrated on predicting the onset of natural fracture failure. However, the use of fracture mechanics and XFEM makes it possible to evaluate the progression of fracture growth over time as fluid is diverted into the natural fractures. Analysis shows that the growing hydraulic fracture may exert enough tensile and/or shear stresses on cemented natural fractures that they may be opened or slip in advance of hydraulic fracture tip arrival, while under some conditions, natural fractures will be unaffected by the hydraulic fracture. A threshold is defined for the fracture energy of cements where, for cases below this threshold, hydraulic fractures divert into the natural fractures. The value of this threshold is calculated for different fracture set orientations. Finally, detailed pressure profile and aperture distributions at the intersection between fracture segments show the potential for difficulty in proppant transport under complex fracture propagation conditions. Whether a hydraulic fracture crosses or is arrested by a pre-existing natural fracture is controlled by shear strength and potential slippage at the fracture intersections, as well as potential debonding of sealed cracks in the near-tip region of a propagating hydraulic fracture. We introduce a new more general criterion for fracture propagation at the intersections. We present a complex hydraulic fracture pattern propagation model based on the Extended Finite Element Method as a design tool that can be used to optimize treatment parameters under complex propagation conditions. / text