Thesis (M.Sc.)--University of Alberta, 2010. / Title from PDF file main screen (viewed on Apr. 13, 2010). A thesis submitted to the Faculty of Graduate Studies and Research in partial fulfillment of the requirements for the degree of Master of Science, Department of Earth and Atmospheric Sciences, University of Alberta. Includes bibliographical references.

Carbonate reservoirs contain approximately two-thirds of the world's oil and gas reserves (Al-Anzi et al., 2003). Carbonates often pose a significant problem when it comes to understanding their reservoir quality because of their heterogeneous nature, which is caused by both the variety of processes occurring depositionally and their high susceptibility to diagenetic alterations. In order to fully characterise the behaviour of carbonate rocks in the subsurface is it important to understand their textural heterogeneity and also how faulting can modify their textures. Deformation in fault zones causes the petrophysical properties (e.g. porosity, permeability and velocity) to alter from the background values. For example, fracturing in damage zones surrounding faults increase the permeability, creating conduits to fluids, conversely, fault cores often act as barriers, created by pore occluding processes. However, faulting in carbonate rocks is often complicated by their textural variations, leading to a variety of deformation microstructures, and each will create different petrophysical properties. This thesis aims to understand how faulting effects different carbonate rocks and analyse the controls on any alterations to the petrophysical properties (porosity, permeability and velocity) into the fault zones. Alterations to the permeability are important to unravel in order to assess the fluid flow potential and hydraulic properties of a rock. Understanding the alterations to the velocity can help to better image faults at depth and to provide information on their microstructures.

Thesis (Ph. D.)--University of Alberta, 2010. / Title from pdf file main screen (viewed on Mar. 18, 2010). A thesis submitted to the Faculty of Graduate Studies and Research in partial fulfillment of the requirements for the degree of Doctor of Philosophy in Geophysics, Department of Physics, University of Alberta. Includes bibliographical references.

Fractures can profoundly affect the capacity of carbonate reservoirs to store and permeate fluids, depending on the properties and abundance of fractures. Fractures exist abundantly in carbonate outcrops; however, their abundance in subsurface carbonates is obscure because of the data shortages and uncertainties about the factors that drive fracturing in sedimentary basins. The objective of this research is twofold. The first is to study abundance of fractures in gently deformed carbonates, which were generally overlooked. The second is to address measuring fracture abundance using electrical borehole imaging, which is the mostly used method to describe reservoir fractures. Fractures were studied from areas in the gently folded and shallowly (less than 2 km depth) buried interiors of the Arabian Platform. The study areas include outcrops and reservoirs of the Late Jurassic Arab carbonates in the sprawling homocline of Central Arabia and a low-relief dome in Eastern Arabia. The Cenozoic Rus carbonates in the dome outcrops were also studied. Fracture abundance was measured from the outcrops using scanlines and from the reservoirs using core and borehole images of extended-reach drilling. Many systematic properties were drawn on mineralization, orientation, and abundance of fractures. The fractures were found to be opening mode, mostly barren, and exist with subvertical dips, and some regional trends. The fractures display significantly differing ranges of abundance that were controlled by the subtle structural bending of the dome and homocline, carbonate lithofacies, and paucity of fracture mineralization. The borehole imaging was found to significantly lower fracture abundance. The detection of fractures was subject to several factors including size of fracture widths, nature of fracture roughness, and present-day stress field. The results have implications for modeling of fracture systems and tectonic regimes. For example, finding that fracture abundance varies drastically in such gently deformed regions indicates that carbonates are very sensitive to fracturing processes. Moreover, the borehole imaging limitations influence the models of fracture abundance and orientations, which are often used to deduce paleo tectonic regimes and present-day geodynamics in carbonate reservoirs.

Thesis (Ph. D.)--University of Wyoming, 2006. / Title from PDF title page (viewed on Dec. 21, 2007). Includes bibliographical references (p. 199-216).

Many gas wells suffer a loss in productivity due to liquid accumulation in the near wellbore region. This problem starts as the flowing bottom hole pressure drops below the dew point in wells producing from gas condensate reservoirs. Chemical stimulation may be used as a remedy, by altering the wettability to non-liquid wetting. Successful treatments decrease liquid trapping, increase fluids mobility, and improve the well’s deliverability. The main focus in this research was to develop an effective chemical treatment to mitigate liquid blocking in gas wells producing from carbonate reservoirs. In the initial stages, screening tests were developed to quickly and effectively identify suitable chemicals from a large pool of compounds. X-ray Photoelectron Spectroscopy (XPS) measurements, drop imbibition tests, and contact angle measurements with water and n-decane were found to be necessary but not sufficient indicators of the effectiveness of the chemicals and were used as screening tools. An integral part of the development of the treatment solution was the selection of a solvent mixture capable of delivering the fluorinated chemical to the rock surface. The treatment solution, mixture of chemical dissolved in solvent, must be stable in the presence of both brine and condensate so that it will not precipitate and will not reduce permeability of the rock. Through phase behavior studies the compatibility of the treatment solution and in-situ brines were investigated to reduce the risk of failure in the coreflood experiments. The measured relative permeability values in Texas Cream Limestone and Silurian Dolomite cores are demonstrate from high-pressure, high-temperature coreflood experiments before and after treatment. Measurements were made using a pseudo-steady-state method with synthetic gas-condensate mixtures. To enhance the durability of the treatment a special amine primer is introduced. / text

Thesis (Ph. D.)--University of Wyoming, 2006. / Title from PDF title page (viewed on April 16, 2008). Includes bibliographical references (p. 157-174).

Petrophysical properties are fundamental to understanding fluid flow processes in hydrocarbon reservoirs. Special Core Analysis (SCAL) routinely used in industry are time-consuming, expensive, and often destructive. Alternatively, easily available thin section data is lacking the representation of pore space in 3D, which is a requisite for generating pore network models (PNM) and computing petrophysical properties. In this study, these challenges were addressed using a numerical SCAL workflow that employs pore volume reconstruction from thin section images obtained from confocal laser scanning microscopy (CLSM). A key objective is to investigate methods capable of 2D to 3D reconstruction, to obtain PNM used for the estimation of transport properties. Representative thin sections from a well-known Middle-Eastern carbonate formation were used to obtain CLSM images. The thin-sections were specially prepared by spiking the resin with UV dye, enabling high-resolution imaging. The grayscale images obtained from CLSM were preprocessed and segmented into binary images. Generative Adversarial Networks (GAN) and Two-Point Statistics (TPS) were applied, and PNM were extracted from these binary datasets. Porosity, Permeability, and Mercury Injection Porosimetry (MIP) on the corresponding core plugs were conducted and an assessment of the properties computed from the PNM obtained from the reconstructed 3D pore volume is presented. Moreover, the results from the artificial pore networks were corroborated using 3D confocal images of etched pore casts (PCE). The results showed that based on visual inspection only, GAN outperformed TPS in mimicking the 3D distribution of pore scale heterogeneity, additionally, GAN and PCE outperformed the results of MIP obtained by TPS on the Skeletal-Oolitic facies, without providing a major improvement on more heterogeneous samples. All methods captured successfully the porosity while absolute permeability was not captured. Formation resistivity factor and thermal conductivity showcased their strong correlation with porosity. The study thus provides valuable insights into the application of 2D to 3D reconstruction to obtain pore network models of heterogeneous carbonate rocks for petrophysical characterization for quick decision. The study addresses the following important questions: 1) how legacy thin sections can be leveraged to petrophysically characterize reservoir rocks 2) how reliable are 2D to 3D reconstruction methods when predicting petrophysical properties of carbonates.

The purpose of this study was first to develop a method by which a detailed porosity classification system could be utilized to understand the relationship between pore/pore-throat geometry, genetic porosity type, and facies. Additionally, this study investigated the relationships between pore/pore-throat geometry, petrophysical parameters, and reservoir performance characteristics. This study focused on the Jurassic Smackover reservoir rocks of Grayson field, Columbia County, Arkansas. This three part study developed an adapted genetic carbonate pore type classification system, through which the Grayson reservoir rocks were uniquely categorized by a percent-factor, describing the effect of diagenetic events on the preservation of original depositional texture, and a second factor describing if the most significant diagenetic event resulted in porosity enhancement or reduction. The second part used petrographic image analysis and mercury-injection capillary pressure tests to calculate pore/pore-throat sizes. From these data sets pore/pore-throat sizes were compared to facies, pore type, and each other showing that pore-throat size is controlled by pore type and that pore size is controlled primarily by facies. When compared with each other, a pore size range can be estimated if the pore type and the median pore-throat aperture are known. Capillary pressure data was also used to understand the behavior of the dependent rock properties (porosity, permeability, and wettability), and it was determined that size-reduced samples, regardless of facies, tend to show similar dependent rock property behavior, but size-enhanced samples show dispersion. Finally, capillary pressure data was used to understand fluid flow behavior of pore types and facies. Oncolitic grainstone samples show unpredictable fluid flow behavior compared to oolitic grainstone samples, yet oncolitic grainstone samples will move a higher percentage of fluid. Size-enhanced samples showed heterogeneous fluid flow behavior while the size-reduced samples could be grouped by the number of modes of pore-throat sizes. Finally, this study utilized petrographic image analysis to determine if 2- dimensional porosity values could be calculated and compared to porosity values from 3-dimensional porosity techniques. The complex, heterogeneous pore network found in the Grayson reservoir rocks prevents the use of petrographic image analysis as a porosity calculation technique.

The application of carbon-dioxide injection for enhanced oil recovery and/or sequestration purposes has gained impetus in the last decade. It is known that well test analysis plays a crucial role on getting information about reservoir properties, boundary conditions, etc. Although there are some studies related to the well test analysis in the fractured reservoirs, most of them are not focused on the carbon dioxide injection into the reservoir. Naturally fractured reservoirs (NFR) represent an important percentage of the worldwide hydrocarbon reserves and current production. Reservoir simulation is a fundamental technique in characterizing this type of reservoirs. Fracture properties are often not clear due to difficulty to characterize the fracture systems. On the other hand, well test analysis is a well known and widely applied reservoir characterization technique. Well testing in NFR provides two significant characteristic parameters, storativity ratio (&omega / ) and interporosity flow coefficient (&lambda / ). The storativity ratio is related to fracture porosity. The interporosity flow coefficient can be linked to the shape factor which is a function of fracture spacing. In this study, the effects of fracture and fluid flow factors (geometry, orientation and flow properties) on pressure and pressure derivative behavior are studied by applying a reservoir simulation model. Model is utilized mainly for the observation of multiphase flow effects in CO2 flooded fractured reservoirs. Several runs are conducted for various ranges of the aforementioned properties in the CO2 flooded reservoir. Results of well test analysis are compared to the input data of simulation models on a parameter basis.