Thesis (Ph. D.)--University of Texas at Austin, 2000. / Vita. Includes bibliographical references (leaves 181-194). Available also in a digital version from Dissertation Abstracts.

Thesis (M.S.)--West Virginia University, 2002. / Title from document title page. Document formatted into pages; contains xii, 94 p. : ill. (some col.), maps. Includes abstract. Includes bibliographical references (p. 51-53).

Thesis (Ph. D.)--University of Texas at Austin, 2000. / Vita. Includes bibliographical references (leaves 99-101). Available also in a digital version from Dissertation Abstracts.

Thesis (Ph. D.)--University of Texas at Austin, 2001. / Vita. Includes bibliographical references. Available also from UMI/Dissertation Abstracts International.

Thesis (Ph. D.)--University of Texas at Austin, 2000. / Vita. Includes bibliographical references (leaves 180-187). Available also in a digital version from Dissertation Abstracts.

Thesis (Ph. D.)--University of Texas at Austin, 2000. / Vita. Includes bibliographical references (leaves 299-304). Available also in a digital version from Dissertation Abstracts.

During waterflooding, or chemical EOR processes with polymers, fractures are frequently generated in injectors. This can have a profound impact on the process performance and reservoir management. A fracture growth model was developed and linked to a reservoir simulator that incorporates the effect of (i) particle plugging due to filtration of solids and oil droplets in the injected fluids; (ii) non-Newtonian polymer rheology (shear-thinning and -thickening) for polymer injection; and (iii) thermal stresses induced by cold water injection. Dynamic fracture growth, which results from the pore pressure increase due to particle plugging or complex polymer rheology, affects the well injectivity and reservoir sweep significantly. With the fracture growth model, simulations can be made not only to make more accurate reservoir sweep and oil recovery predictions, but also to help identify well patterns that may improve reservoir performance. In homogeneous reservoirs, the injectivity is significantly affected by the propagation of an injection induced fracture; but the ultimate oil recovery and reservoir sweep are relatively unaffected. In multi-layered reservoirs, however, reservoir sweep and oil recovery are impacted significantly by the fracture growth. The oil recovery results from our fracture growth model differ substantially from those obtained based on the assumption of no fracture generation or a static fracture. For polymer injection processes, the shear rate dependence of the polymer viscosity is critical in determining the injectivity, fracture growth, and oil recovery. In addition to vertical injection well fractures, horizontal injection well fractures have been simulated by using the fracture growth model. The reservoir stress distribution determines the fracture orientation near a horizontal well. When the minimum horizontal stress orientation is perpendicular to the horizontal injector, a longitudinal fracture is generated, while with the minimum horizontal stress orientation parallel to the injector, a transverse fracture is developed. The impact of static and dynamic transverse/longitudinal fractures on well injectivity and reservoir sweep has been investigated. The impacts of (i) lengths of horizontal injector and producer; (ii) location of water oil contact; (iii) sizes of transverse and longitudinal fractures; (iv) particle concentration in the water, were further investigated. The well injectivity model was validated successfully by history matching injection of water (with particles) and shear rate dependent polymer injection. The history match was performed by adjusting the effective particle concentration in the injected water or the shear rate dependent polymer rheology. Based on history matching the long-term injection rates and pressures, estimates of the fracture length were made. These fracture dimensions could not be independently measured and verified. Based on the simulation results recommendations were made for strategies for drilling well patterns, water quality and injection rates that will lead to better oil recovery. / text

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<p> Capturing carbon dioxide (CO₂) from stationary sources and injecting it into deep underground geologic formations has been identified as a viable method for reducing carbon emissions to the atmosphere. Sedimentary rocks, such as sandstones overlain by shales or evaporites, are the preferred formations because their morphology and structure provide pore space, and containment for the long term storage of CO₂. Sandstone formations have also served as repositories to migrating hydrocarbons, and are the sites of many oil recovery operations. For many depleted oil reservoirs, secondary waterflooding recovery methods are no longer efficient or economically viable, hence the application of tertiary CO₂ enhanced oil recovery (CO₂-EOR) followed by CO₂ storage is an attractive and cost effective business plan. </p><p> Citronelle Oil Field, located in southwest Alabama, is the largest and longest producing sandstone oil reservoir in the state, having produced more than 170 million barrels of oil from its estimated 500 million barrels of original oil in place, since its discovery in 1955. The field is in the later stages of secondary recovery by waterflooding and daily oil production has declined considerably. The field is comprised of the Upper and Lower Donovan hydrocarbon bearing sandstones, which are separated by the saline-water-bearing sandstones of the Middle Donovan. The Ferry Lake Anhydrite, which overlies the three sections, serves as their caprock. </p><p> The present work is focused on an investigation of the feasibility of a CO₂-EOR project for the Citronelle Oil Field and the use of the Middle Donovan for long term CO₂ storage. A set of static calculations, based on estimation methods which were retrieved from publications in the field, was followed by computer simulations using MASTER 3.0, TOUGH2-ECO2N, and TOUGHREACT. Results using MASTER 3.0, for simulation of CO₂-EOR, indicated that nearly 50 million barrels of additional oil could be produced by tertiary recovery. Results using TOUGH2-ECO2N and TOUGHREACT, for the simulations of CO₂ storage, indicated that 159 million metric tons (175 short tons) of CO₂ could be stored in the Middle Donovan formation. An investigation into possible CO₂ leakage from the reservoirs indicated that the Ferry Lake Anhydrite serves as a very reliable long term storage seal.</p><p> The present work can serve as a template for preliminary assessment of tertiary oil recovery and CO₂ storage of similar oil reservoirs and saline-water formations.</p>

AbstractInside of the Norne E-segment remains a considerable amount of residual oil even after applying the primary and secondary oil recovery methods (water injection). Recently, several methods have been studied based on simulations to decrease the residual oil trapped by capillary forces and consequently improve the oil recoverability. Additionally, Norne E-segment is severely affected by stratigraphic barriers and faults of nature not sealing, semi sealing and completely sealing. Water Alternating Gas (WAG) and Simultaneously Water Alternating Gas (SWAG) injection techniques are presented as potential candidates to increase oil productivity in the Norne E-Segment by decreasing the gas mobility and capillary forces guarantying effective microscopic displacement due to gas flooding and macroscopic sweep created by water injection.In the first part of this study, based on simulations (Eclipse 100, Black oil simulator), sensitivity analyses of WAG cycles and WAG ratio were investigated combining with low injection rate and high injection rate. However, three WAG cycle were suggested (3 months, 6 months and 1years injection cycles) and different values of WAG ratio were studied based on low and high injection rates of water and gas. According to the results, WAG cycle doesn&#146;t affect the fluids rates productions when low injection rate is used, but a slightly effect is noticed when high injection rate is applied, thus a slightly optimal WAG ratio was found to be 1:3 when high WAG ratio is used.As a sequence, examination of three different injection patters scenarios were simulated to optimize the oil recoverability using both techniques WAG and SWAG, namely: injection studies using the injection wells already existed; injection studies using the injection wells already existed by doing a new completion within Ile and Tofte formations; injection studies placing a new injection well plus new completion of the injection well. As a result, the last scenario using SWAG technique presented oil recovery around 73%, whose was approximately 5% higher than oil recoverability when WAG injection technique (68%), when high injection rate is applied.