This thesis is aimed to calculate the effective permeability tensor and to simulate the fluid flow in naturally fractured reservoirs. This requires an understanding of the mechanisms of fluid flow in naturally fractured reservoirs and the detailed properties of individual fractures and matrix porous media. This study has been carried out to address the issues and difficulties faced by previous methods; to establish possible answers to minimise the difficulties; and hence, to improve the efficiency of reservoir simulation through the use of properties of individual fractures. The methodology used in this study combines several mathematical and numerical techniques like the boundary element method, periodic boundary conditions, and the control volume mixed finite element method. This study has contributed to knowledge in the calculation of the effective permeability and simulation of fluid flow in naturally fractured reservoirs through the development of two algorithms. The first algorithm calculates the effective permeability tensor by use of properties of arbitrary oriented fractures (location, size and orientation). It includes all multi-scaled fractures and considers the appropriate method of analysis for each type of fracture (short, medium and long). In this study a characterisation module which provides the detail information for individual fractures is incorporated. The effective permeability algorithm accounts for fluid flows in the matrix, between the matrix and the fracture and disconnected fractures on effective permeability. It also accounts for the properties of individual fractures in calculation of the effective permeability tensor. The second algorithm simulates flow of single-phase fluid in naturally fractured reservoirs by use of the effective permeability tensor. This algorithm takes full advantage of the control volume discretisation technique and the mixed finite element method in calculation of pressure and fluid flow velocity in each grid block. It accounts for the continuity of flux between the neighbouring blocks and has the advantage of calculation of fluid velocity and pressure, directly from a system of first order equations (Darcy???s law and conservation of mass???s law). The application of the effective permeability tensor in the second algorithm allows us the simulation of fluid flow in naturally fractured reservoirs with large number of multi-scale fractures. The fluid pressure and velocity distributions obtained from this study are important and can considered for further studies in hydraulic fracturing and production optimization of NFRs.

The data assimilation process of adjusting variables in a reservoir simulation model to honor observations of field data is known as history matching and has been extensively studied for few decades. However, limited success has been achieved due to the high complexity of the problem and the large computational effort required by the practical applications. An automatic history matching module based on the ensemble Kalman filter is developed and validated in this dissertation. The ensemble Kalman filter has three steps: initial sampling, forecasting through a reservoir simulator, and assimilation. The initial random sampling is improved by the singular value decomposition, which properly selects the ensemble members with less dependence. In this way, the same level of accuracy is achieved through a smaller ensemble size. Four different schemes for the assimilation step are investigated and direct inverse and square root approaches are recommended. A modified ensemble Kalman filter algorithm, which addresses the preference to the ensemble members through a nonequally weighting factor, is proposed. This weighted ensemble Kalman filter generates better production matches and recovery forecasting than those from the conventional ensemble Kalman filter. The proposed method also has faster convergence at the early time period of history matching. Another variant, the singular evolutive interpolated Kalman filter, is also applied. The resampling step in this method appears to improve the filter stability and help the filter to deliver rapid convergence both in model and data domains. This method and the ensemble Kalman filter are effective for history matching and forecasting uncertainty quantification. The independence of the ensemble members during the forecasting step allows the benefit of high-performance computing for the ensemble Kalman filter implementation during automatic history matching. Two-level computation is adopted; distributing ensemble members simultaneously while simulating each member in a parallel style. Such computation yields a significant speedup. The developed module is integrated with reservoir simulators UTCHEM, GEM and ECLIPSE, and has been implemented in the framework Integrated Reservoir Simulation Platform (IRSP). The successful applications to two and three-dimensional cases using blackoil and compositional reservoir cases demonstrate the efficiency of the developed automatic history matching module.

Not available / text

Highly fractured carbonate reservoirs are a class of reservoirs characterized by high conductivity fractures surrounding low permeability matrix blocks. In these reservoirs, wettability alteration is a key method for recovering oil. Water imbibes into the matrix blocks upon water flooding if the reservoir rock is water-wet. However, many carbonate reservoirs are oil-wet. Surfactant solution was used to enhance spontaneous imbibition between the fractures and the matrix by both wettability alteration and ultra-low interfacial tensions. The first part of this study was devoted to determining the wettability of reservoir rocks using Amott-Harvey Index method, and also evaluating the performance of surfactants on wettability alteration, based on the contact angle measurement and spontaneous imbibition rate and ultimate oil recovery on oil-wet reservoir cores. The reservoir rocks have been found to be slightly oil-wet. One cationic surfactant BTC8358, one anionic surfactant and one ultra-low IFT surfactant formulation AKL-207 are all found to alter the wettability towards more water-wet and promote oil recovery through spontaneous imbibition. The second part of the study focused on the parameters that affect wettability alteration by surfactants. Some factors such as core dimension, permeability and heterogeneity of porous medium are evaluated in the spontaneous imbibition tests. Higher permeability leads to higher imbibition rate and higher ultimate oil recovery. Heterogeneity of core samples slows down the imbibition process if other properties are similar. Core dimension is critical in upscaling from laboratory conditions to field matrix blocks. The imbibition rate is slower in larger dimension of core. Further, we investigated the effects of EDTA in surfactant-mediated spontaneous imbibition. Since high concentration of cationic divalent ions in the aqueous solution markedly suppresses the surfactant-mediated wettability alteration, EDTA improved the performance of surfactant in the spontaneous imbibition tests. It is proposed in the thesis that surfactant/EDTA-enhanced imbibition may involve the dissolution mechanism. More experiments should be conducted to verify this mechanism. The benefits of using EDTA in the surfactant solution include but not limited to: altering the surface charge of carbonate to negative, producing the in-situ soap, reducing the brine hardness, decreasing the surfactant adsorption, and creating the water-wet area by dissolving the dolomite mineral. / text

Understanding the stratigraphic architecture of geologically complex reservoirs, such as the heavy oil deposits of Western Canada, is essential to achieve an efficient hydrocarbon recovery. Borehole and 3-D seismic data were integrated to define the stratigraphic architecture and generate 3-dimensional geological models of the Mannville Group in Saskatchewan. The Mannville is a stratigraphically complex unit formed of fluvial to marine deposits. Two areas in west-central and southern Saskatchewan were examined in this study. In west-central Saskatchewan, the area corresponds to a stratigraphically controlled heavy oil reservoir with production from the undifferentiated Dina-Cummings Members of the Lower Cretaceous Mannville Group. The southern area, although non-prospective for hydrocarbons, shares many similarities with time-equivalent strata in areas of heavy oil production. Seismic sequence stratigraphic principles together with log signatures permitted the subdivision of the Mannville into different packages. An initial geological model was generated integrating seismic and well-log data Multiattribute analysis and neural networks were used to generate a pseudo-lithology or gamma-ray volume. The incorporation of borehole core data to the model and the subsequent integration with the lithological prediction were crucial to capture the distribution of reservoir and non-reservoir deposits in the study area. The ability to visualize the 3-D seismic data in a variety of ways, including arbitrary lines and stratal or horizon slicing techniques helped the definition of stratigraphic features such as channels and scroll bars that affect fluid flow in hydrocarbon producing areas. Small-scale heterogeneities in the reservoir were not resolved due to the resolution of the seismic data. Although not undertaken in this study, the resulting stratigraphic framework could be used to help construct a static reservoir model. Because of the small size of the 3-D seismic surveys, horizontal slices through the data volume generally imaged only small portions of the paleogeomorphologic features thought to be present in this area. As such, it was only through the integration of datasets that the geological models were established.

This thesis is aimed to calculate the effective permeability tensor and to simulate the fluid flow in naturally fractured reservoirs. This requires an understanding of the mechanisms of fluid flow in naturally fractured reservoirs and the detailed properties of individual fractures and matrix porous media. This study has been carried out to address the issues and difficulties faced by previous methods; to establish possible answers to minimise the difficulties; and hence, to improve the efficiency of reservoir simulation through the use of properties of individual fractures. The methodology used in this study combines several mathematical and numerical techniques like the boundary element method, periodic boundary conditions, and the control volume mixed finite element method. This study has contributed to knowledge in the calculation of the effective permeability and simulation of fluid flow in naturally fractured reservoirs through the development of two algorithms. The first algorithm calculates the effective permeability tensor by use of properties of arbitrary oriented fractures (location, size and orientation). It includes all multi-scaled fractures and considers the appropriate method of analysis for each type of fracture (short, medium and long). In this study a characterisation module which provides the detail information for individual fractures is incorporated. The effective permeability algorithm accounts for fluid flows in the matrix, between the matrix and the fracture and disconnected fractures on effective permeability. It also accounts for the properties of individual fractures in calculation of the effective permeability tensor. The second algorithm simulates flow of single-phase fluid in naturally fractured reservoirs by use of the effective permeability tensor. This algorithm takes full advantage of the control volume discretisation technique and the mixed finite element method in calculation of pressure and fluid flow velocity in each grid block. It accounts for the continuity of flux between the neighbouring blocks and has the advantage of calculation of fluid velocity and pressure, directly from a system of first order equations (Darcy???s law and conservation of mass???s law). The application of the effective permeability tensor in the second algorithm allows us the simulation of fluid flow in naturally fractured reservoirs with large number of multi-scale fractures. The fluid pressure and velocity distributions obtained from this study are important and can considered for further studies in hydraulic fracturing and production optimization of NFRs.

Thesis (Ph. D.)--University of Texas at Austin, 2007. / Vita. Includes bibliographical references.

Thesis (Ph. D.)--University of Texas at Austin, 2007. / Vita. Includes bibliographical references.

Thesis (Ph. D.)--University of Texas at Austin, 2008. / Vita. Includes bibliographical references.

Thesis (M.S.)--Baylor University, 2009. / Superscript: 6 and 3 in "106m3". Includes bibliographical references (p. 170-175).