Thesis (M.S.)--University of Missouri, School of Mines and Metallurgy, 1949. / Vita. The entire thesis text is included in file. Typescript. Title from title screen of thesis/dissertation PDF file (viewed June 30, 2010) Includes bibliographical references (p. 40).

<p> Hydrocarbon recovery rates within the Niobrara Shale are estimated as low as 2&ndash;8%. These recovery rates are controlled by the ability to effectively hydraulic fracture stimulate the reservoir using multistage horizontal wells. Subsequent to any mechanical issues that affect production from lateral wells, the variability in production performance and reserve recovery along multistage lateral shale wells is controlled by the reservoir heterogeneity and its consequent effect on hydraulic fracture stimulation efficiency. Using identical stimulation designs on a number of wells that are as close as 600ft apart can yield variable production and recovery rates due to inefficiencies in hydraulic fracture stimulation that result from the variability in elastic rock properties and in-situ stress conditions. </p><p> As a means for examining the effect of the geological heterogeneity on hydraulic fracturing and production within the Niobrara Formation, a 3D geomechanical model is derived using geostatistical methods and volumetric calculations as an input to hydraulic fracture stimulation. The 3D geomechanical model incorporates the faults, lithological facies changes and lateral variation in reservoir properties and elastic rock properties that best represent the static reservoir conditions pre-hydraulic fracturing. Using a 3D numerical reservoir simulator, a hydraulic fracture predictive model is generated and calibrated to field diagnostic measurements (DFIT) and observations (microseismic and 4D/9C multicomponent time-lapse seismic). By incorporating the geological heterogeneity into the 3D hydraulic fracture simulation, a more representative response is generated that demonstrate the variability in hydraulic fracturing efficiency along the lateral wells that will inevitability influence production performance. </p><p> Based on the 3D hydraulic fracture simulation results, integrated with microseismic observations and 4D/9C time-lapse seismic analysis (post-hydraulic fracturing &amp; post production), the variability in production performance within the Niobrara Shale wells is shown to significantly be affected by the lateral variability in reservoir quality, well and stage positioning relative to the target interval, and the relative completion efficiency. The variation in reservoir properties, faults, rock strength parameters, and in-situ stress conditions are shown to influence and control the hydraulic fracturing geometry and stimulation efficiency resulting in complex and isolated induced fracture geometries to form within the reservoir. This consequently impacts the effective drainage areas, production performance and recovery rates from inefficiently stimulated horizontal wells. </p><p> The 3D simulation results coupled with the 4D seismic interpretations illustrate that there is still room for improvement to be made in optimizing well spacing and hydraulic fracturing efficiency within the Niobrara Formation. Integrated analysis show that the Niobrara reservoir is not uniformly stimulated. The vertical and lateral variability in rock properties control the hydraulic fracturing efficiency and geometry. Better production is also correlated to higher fracture conductivity. 4D seismic interpretation is also shown to be essential for the validation and calibration hydraulic fracture simulation models. The hydraulic fracture modeling also demonstrations that there is bypassed pay in the Niobrara B chalk resulting from initial Niobrara C chalk stimulation treatments. Forward modeling also shows that low pressure intervals within the Niobrara reservoir influence hydraulic fracturing and infill drilling during field development.</p><p>

<p> In this study, several efficient and accurate mathematical models and numerical solutions to unconventional reservoir development problems are developed. The first is the three-dimensional embedded discrete fracture method (3D-EDFM), which is able to simulate fluid flow with multiple 3D hydraulic fractures with arbitrary strike and dip angles, shapes, curvatures, conductivities and connections. The second is a multi-porosity and multi-physics fluid flow model, which can capture gas flow behaviors in shales, which is complicated by highly heterogeneous and hierarchical rock structures (ranging from organic nanopores, inorganic nanopores, less permeable micro-fractures, more permeable macro-fractures to hydraulic fractures). The third is an iterative numerical approach combining the extended finite element method (X-FEM) and the embedded discrete fracture method (EDFM), which is developed for simulating the fluid-driven fracture propagation process in porous media. </p><p> Physical explanations and mathematical equations behind these mathematical models and numerical approaches are described in detail. Their advantages over alternative numerical methods are discussed. These numerical methods are incorporated into an in-house program. A series of synthetic but realistic cases are simulated. Simulated results reveal physical understandings qualitatively and match with available analytical solutions quantitatively. These novel mathematical models and computational solutions provide numerical approaches to understand complicated physical phenomena in developing unconventional reservoirs, thus they help in the better management of unconventional reservoirs. </p><p>

<p> The Pine Prairie Field is situated on a salt dome in northern Evangeline Parish, located in south-central Louisiana. Pine Prairie contains the only known Cook Mountain Formation hydrocarbon reservoir in Louisiana. Operators have targeted and produced hydrocarbons from the Cook Mountain reservoir in eight wells at the Pine Prairie Field. The source and origin of the Cook Mountain&rsquo;s reservoir properties are unknown. The objective of this study is to determine the origin of the Cook Mountain Formation&rsquo;s reservoir properties by identifying the processes associated with the formation of a Cook Mountain Reservoir. There are two carbonate outcrops at the surface expression of the Pine Prairie Dome. Samples were taken and thin sections made to determine the relationship, if any, to the Cook Mountain Formation. Thin section analysis of the carbonate outcrop was used to gain a better understanding of the depositional setting present at Pine Prairie Field. Well log, seismic, and production data were integrated to determine that, in all instances, commercial Cook Mountain production is associated with fault zones. The passage of acidic, diagenetic fluids through Cook Mountain fault zones generated areas of vuggy porosity proximal to Cook Mountain faulting. Further, fluctuations in short-term pressure gradients associated with salt diapirism resulted in the vertical migration of hydrocarbons via fault zones. In the Pine Prairie Field, fault seal breakdown occurs in Sparta and Wilcox Reservoirs, subsequently charging the Cook Mountain fault zone. Early hydrocarbon charge from the underlying Wilcox and Sparta Reservoirs prevented additional diagenesis, preserving secondary porosity in areas of Cook Mountain faulting.</p><p>

<p> CO₂ flooding has proven to be an effective technique for enhanced oil recovery. However, the application of CO₂ flooding in the recovery process of asphaltenic crude systems is often avoided, as high asphaltene precipitation rates may occur. While the effects of asphaltene concetration and CO₂ injection pressure on asphaltene precipitation rate have been the focus of many studies, asphaltene precipitation rate is not a reliable factor to predict the magnitude of asphaltene-induced formation damage. Wettability alteration is only caused by the immobile asphaltene deposits on the rock surface. The enternmaint of flocs may occur at high fluid velocity. Morover, the effective permeability reduction is only caused by the flocs, which have become large enough to block the pore throats. The dissociation of the flocs may occur under certain flow conditions. In this study, a compositional reservoir simulation was conducted using Eclipse 300 to investigate the injection practice, which avoids asphaltene-induced formation damage during both immiscible and miscible CO₂ flooding in asphaltenic crude system. Without injection, at pressure above bubble point, slight precipitation occurred in the zone of the lowest pressure near the producing well. As pressure approached the bubble point, precipitation increased due to the change in the hydrocarbon composition, which suggested that the potential of asphaltene-induced formation damage is determined by the overall fluid composition. At very low pressure, precipitation decreased due to the increase in the density. </p><p> As CO₂ was injected below the minimum miscibility pressure, a slight precipitation occurred in the transition zone at the gas-oil interface due to the microscopic diffusion of the volatile hydrocarbon components caused by the local concentration gradients. The increase in CO₂ injection rate did not significantly increase the precipitation rate. </p><p> As CO₂ was injected at pressure above the minimum miscibility pressure, precipitation occurred throughout the entire reservoir due to the vaporizing drive miscibility process. While precipitation increased with the injection rate, further increase in the injection rate slightly decreased the deposition due to shear. The pressure drop in the water phase caused by the pore throat increased the local water velocity, resulting in a more effective removal of the clogging asphaltene material.</p><p>

Both an external surface constraint and a thin film constraint were found to strongly influence the microdomain morphology and macromolecular conformations in linear and star poly(styrene-b-butadiene) (SB) and poly(styrene-b-isoprene) (SI), and linear poly(styrene-b-isoprene-b-2-vinylpyridine) (P2VP) block copolymers. Transmission electron microscopy (TEM) of cryo-ultramicrotomed cross-sections of the external surface and of thin films was employed to determine the interfacial microdomain morphology. Assuming sharp interfaces of constant mean curvature between phases, the mean curvature (H) of, the area per junction ($\sigma\sb{\rm j}$) along, and the respective block chain extensions away from the intermaterial dividing surface (IMDS) were determined. Under near-equilibrium processing conditions, segregation of the lowest critical surface tension ($\gamma\sb{\rm c}$) polydiene blocks to the external surface and to the interface with the substrate was observed for all of the block copolymer architectures and compositions investigated. In diblock copolymers, the thickness (t) of the external surface layer was noted to depend upon the molecular weight of the lower $\gamma\sb{\rm c}$ block, the composition of the diblock, and in star diblocks the position of the lower $\gamma\sb{\rm c}$ block in the arm. TEM measurements indicated that t can decrease by up to 800% for certain microdomain types and surface orientations. Both decreases by up to 50%, and increases by up to 200% in $\sigma\sb{\rm j}$ were found. These large variations in t and $\sigma\sb{\rm j}$ indicated that the chain conformations of block copolymers are highly adaptable in the presence of an external surface constraint. Preferred surface orientations of the microdomains were observed. For body-centered cubic packed spherical microdomains, the closest-packed $\{$110$\}$ planes and occasionally the $\{$100$\}$ planes were parallel to the external surface. For cylindrical microdomains, the $\{$100$\}$ planes were parallel to the external surface. The ordered bicontinuous double-diamond (obdd) structure was found to undergo a surface-induced morphological transition to cylindrical microdomains, except when the surface orientation was with the $\{$110$\}$ planes of the obdd morphology parallel to the external surface. At equilibrium, parallel surface orientations of lamellar microdomains are preferred. In all cases, the preferred orientations facilitate the formation of interfacial layers of the lower $\gamma\sb{\rm c}$ block. The results of this work provide new insight for the basic understanding of the physics which govern the microdomain morphology of block copolymers.

Thesis (M.S.)--King Fahd University of Petroleum and Minerals, 1989. / Title from document title page. Includes bibliographical references. Available in PDF format via the World Wide Web.

<p> Carbon sequestration is a promising solution to mitigate the accumulation of greenhouse gases. Depleted oil and gas reservoirs are desirable vessels for carbon sequestration. It is crucial to maintain the sealing ability of carbon sequestration fields with high concentrations of CO₂.</p><p> A systematic well integrity evaluation system has been developed and validated for carbon sequestration fields. The system constitutes 1) a newly developed analytical model for assessing cement sheath integrity under various operating conditions, 2) quantifications of well parameters contributing to the probability of well leakage, and 3) genetic-neural network algorithm for data analysis and well-leakage probability assessment.</p><p> A wellbore system consists of well casing, cement sheath, and formation rock. A new analytical stress model was developed. The new analytical model solves for the stresses in the casing-cement sheath formation system loaded by the isotropic and anisotropic horizontal in-situ stresses. Further analyses with the analytical model reveal that Young&rsquo;s modulus of cement sheath is a major factor that contributes to the sealing ability of the cement sheath, while Poisson&rsquo;s ratio and cohesion play less important roles in the cement sheath sealing ability. The cement sheath in the shale formation exhibits higher sealing ability than that in the sandstone formation. The sealing ability of weak cement is higher than that of strong cement.</p><p> Descriptive quantifications of well parameters were made in this study for analyzing their effect on the probability of well leakage. These parameters include well cement placement relative to aquifers and fluid reservoir zones, cement type, cement sheath integrity in operating conditions, well aging, and well plugging conditions. It is the combination of these parameters that controls the probability of well leakage. A significant proportion of wells were identified as risky wells in these two fields. It is concluded that the well trained neural network model can be used to predict the well leakage risk over the CO₂ sequestration lifespan, which can promote prevention activities and mitigations to the CO₂ leakage risky wells.</p>

This dissertation is a contribution to two fields of study: applied social epistemology and the philosophy of technology. That is, it is a philosophical study, based on empirical fieldwork research, of social and technical knowledge. Social knowledge here is defined as knowledge acquired through the interactions between epistemic agents and social institutions. Technical knowledge is here defined as knowledge about technical artefacts (including how to design, produce, and operate them). I argue that the two must be considered collectively both in the sense that they are best considered in the light of collectivist approaches to knowledge and in the sense that they must be considered together as part of the same analysis. An analysis solely of the interactions between human epistemic agents operating within social institutions does not give adequate credit to the technological artefacts that help to produce knowledge; an analysis of technical knowledge which does not include an analysis of how that technical knowledge is generated within a rich and complex social network would be similarly incomplete. I argue that it is often inappropriate to separate analyses of technical knowledge from social knowledge and that although not all social knowledge is technical knowledge, all technical knowledge is, by definition, social. Further, the influence of technology on epistemic cultures is so pervasive that it also forms or 'envelops' what we consider to be an epistemic agent.

To continue running our civilization on fossil fuels while avoiding global warming and ocean acidification, anthropogenic carbon dioxide must be diverted from atmospheric release. For geologic carbon sequestration, the injection of CO 2 into the lithosphere, to operate at the necessary large scale requires an understanding of the multiphase flow properties of high-pressure CO 2 displacing brine in porous media. A laboratory-scale core flooding reactor has been built to measure flow properties at in situ pressures, salinities, and temperatures. The reported set of experiments was designed to measure CO 2 relative permeability for CO 2 displacing brine at residual brine saturation. Endpoint drainage CO 2 relative permeability was found to be tightly clustered around 0.35-0.4. These values indicate that CO 2 is not strongly nonwetting, and are characteristic of weakly water-wetting or intermediate wetting flow. Based on these results, CO 2 injectivity will be reduced, pressure-limited reservoirs will have reduced capacity, and inclined area-limited reservoirs will have increased capacity. Future reservoir-scale modeling efforts should incorporate sensitivity to relative permeability. Assuming the majority of reservoirs are pressure limited and if the experimental results reported here are found to apply to other lithologies as well, geologic carbon sequestration at scale will require approximately twice the number of storage sites, wells, reservoirs, and the related infrastructure, personnel, and cost.