Thesis (M.S.)--West Virginia University, 2004. / Title from document title page. Document formatted into pages; contains xiii, 118 p. : ill. (some col.), maps (some col.). Includes abstract. Includes bibliographical references (p. 71-80).

A thesis Submitted to the School of Chemical and Metallurgical Engineering, Faculty of Engineering and the Built Environment, University of the Witwatersrand, Johannesburg, in fulfillment of the requirements for the degree of Doctor of Philosophy Johannesburg, 2016 / Wettability of a porous reservoir rock is an important factor that affects oil recovery during waterflooding. It is recognized as being important for multiphase properties. Understanding the variation of these properties in the field, due to wettability trends and different pore structures, is very critical for designing efficient and reliable processes and projects for enhanced hydrocarbon recovery. After primary drainage the reservoir wettability changes: if it was oil-wet initially, it gradually changes to water-wet during waterflooding. This change in reservoir wettability towards water-wet will reduce the residual oil saturation and improve the oil displacement efficiency. However, knowledge of the constitutive relationship between the pore scale descriptors of transport in the porous system is required to adequately describe wettability trend and its impact on oil recovery, particularly during waterflooding. In this work, the petrophysical properties that define fluid flow in the Agbada, Nigeria sandstone reservoir were determined using conventional experimental and x-ray CT scanning methods. Experimentally measured average porosity is 0.28, average permeability is 1699 mD, while the initial and irreducible water saturation is 0.22. Permeability in the x, y and z directions, ranging from 50 to 200 mD, were calculated from the pore network extracted from the Agbada sandstone rock. Results obtained from the Amott-Harvey wettability measurement method indicate that the reservoir is strongly water-wet, with Amott-Harvey index of about 0.9. The cross-over between the water and oil relative permeabilities occurred at saturations of the samples above 0.5, giving an indication of strong water-wetness. The work summarizes the mechanism of wettability alteration and characterizes the performance of the reservoir during waterflooding from injecting water, and relates the residual oil saturation, relative permeability and volumes of water injected to wettability and its effects on oil recovery. Waterflood oil recovery is computed using the Buckley-Leverett method based on the reservoir rock and fluid properties. Computed waterflood oil recovery using this method was about 60% of the oil initially in place. Plots of spontaneous imbibition rate show that the injection rate for optimal oil recovery is 40 bbls of injected water per day. At this rate, both the mobility and shock front mobility ratios are less than 1, leading to a stable flood front and absence of viscous fingering. Waterflooding is by far the most widely applied method of improved oil recovery over the years with good results in conventional and unconventional (tight oil) reservoirs It is relatively simple and cost effective: abundance and availability of water. Waterflood oil recovery factor is affected by internal and external factors. The placement of the injection and production wells, for example, impacts on the effectiveness of the waterflooding process. I considered the placement of the wells in a five-spot pattern as elements of an unbounded double periodic array of wells and assumed the reservoir to be homogeneous, infinite and isotropic, with constant porosity and permeability. Both fluids are treated as having slight but constant compressibility and their flow governed by Darcy’s law. The average pressure in the reservoir satisfies quasi-static flow or diffusion equation. I then assumed piston-like displacement of oil by injected water that takes account of viscosity diffence between both fluids and proposed a model based on the theory of elliptic functions, in particular Weierstrass p-functions functions. Oil-water contact movement, dimensionless time for water breakthrough at the production well, areal sweep and average reservoir pressures were modeled. The model was tested using Wolfram Mathematica 10 software and the results are promising. The thesis has therefore established that the Agbada sandstone reservoir is strongly water-wet and that waterflooding is a viable option for enhanced oil recovery from the reservoir. / MT2016

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

Quick evaluation of reservoir performance is a main concern in decision making. Time-consuming input data preparation and computing, along with data uncertainty tend to inhibit the use of numerical reservoir simulators. New analytical solutions are developed for capacitance-resistive models (CRMs) as fast predictive techniques, and their application in history-matching, optimization, and evaluating reservoir uncertainty for water/CO₂ floods are demonstrated. Because the CRM circumvents reservoir geologic modeling and saturation-matching issues, and only uses injection/production rate and bottomhole pressure data, it lends itself to rapid and frequent reservoir performance evaluation. This study presents analytical solutions for the continuity equation using superposition in time and space for three different reservoir-control volumes: 1) entire field volume, 2) volume drained by each producer, and 3) drainage volume between an injector/producer pair. These analytical solutions allow rapid estimation of the CRM unknown parameters: the interwell connectivity and production response time constant. The calibrated model is then combined with oil fractional-flow models for water/CO₂ floods to match the oil production history. Thereafter, the CRM is used for prediction, optimization, flood performance evaluation, and reservoir uncertainty quantification. Reservoir uncertainty quantification is directly obtained from several equiprobable history-matched solutions (EPHMS) of the CRM. We validated CRM's capabilities with numerical flow-simulation results and tested its applicability in several field case studies involving water/CO₂ floods. Development and application of fast, simple and yet powerful analytic tools, like CRMs that only rely on injection and production data, enable rapid reservoir performance evaluation with an acceptable accuracy. Field engineers can quickly obtain significant insights about flood efficiency by estimating interwell connectivities and use the CRM to manage and optimize real time reservoir performance. Frequent usage of the CRM enables evaluation of numerous sets of the EPHMS and consequently quantification of reservoir uncertainty. The EPHMS sets provide good sampling domains and reasonable guidelines for selecting appropriate input data for full-field numerical modeling by evaluating the range and proper combination of uncertain reservoir parameters. Significant engineering and computing time can be saved by limiting numerical simulation input data to the EPHMS sets obtained from the CRMs. / text

Thesis (M.S.)--West Virginia University, 2002. / Title from document title page. Document formatted into pages; contains viii, 122 p. : ill. (some col.), maps. Includes abstract. Includes bibliographical references (p. 76-78).

Thesis (M.S.)--West Virginia University, 2000. / Title from document title page. Document formatted into pages; contains xi, 94 p. : ill. (some col.), maps. Includes abstract. Includes bibliographical references (p. 63-64).

Thesis (Ph.D.)--University of Wyoming, 2009. / Title from PDF title page (viewed on June 10, 2010). Includes bibliographical references.

Thesis (Ph. D.)--University of Texas at Austin, 1999. / Vita. Includes bibliographical references (leaves 248-254). Available also in a digital version from Dissertation Abstracts.

Two-phase flow, ubiquitous to waterflood oil recovery, geological CO2 storage, and groundwater remediation, is strongly influenced by wettability, and made more complex under mixed-wet conditions. Optimum wettability for such operations is not well established due to limited experimental data and difficulties in their interpretation. This thesis investigates the impact of mixed-wettability, characterised by advancing contact angle θa on capillary pressure, relative permeability, and waterflood displacement. Using a Darcy scale simulator, relative permeability kr, capillary pressure Pc, and residual oil saturation Sor were extracted by history matching production and pressure drop data from centrifuge brine invasion and waterflood displacements completed for a range of θa. As θa increased, a larger |Pc| was required to displace oil from mixed-wet cores at high initial oil saturation. End point oil and brine permeability decreased with increasing θa. A permeability enhancement, such that kr > 1, was measured both when the flowing phase was wetting and non-wetting and was attributed to a slippage at the oil/brine interface directly correlated to θa. Residual oil saturation decreased monotonically with increasing θa while core-averaged remaining oil saturation at the end of the waterflood exhibited a non-monotonic dependence on θa. Simulations of the waterfloods revealed that both significant capillary end effects and premature termination of the waterflood in the laboratory contribute to the deviation between remaining and residual saturations. This work demonstrates that the former is not representative of the latter, as it has been assumed in a number of studies in the literature. Both corefloods and microfluidic waterfloods show the importance of combining experimental studies with simulation for correct interpretation of the measurements especially under capillary dominated flow.

Thesis (Ph. D.)--University of Wyoming, 2006. / Title from PDF title page (viewed on Dec. 17, 2007). Includes bibliographical references (p. 187-197).