Thesis (M.S.)--West Virginia University, 2007. / Title from document title page. Document formatted into pages; contains xi, 79 p. : ill. (some col.). Includes abstract. Includes bibliographical references (p. 42-47).

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

Thesis (Ph.D.)--University of Tulsa, 1975. / Bibliography: l. 45-48.

Thesis (M.S.)--West Virginia University, 2009. / Title from document title page. Document formatted into pages; contains xi, 68 p. : ill. (some col.), col. maps. Includes abstract. Includes bibliographical references (p. 66-68).

Predicting the performance of wells in compartmentalized reservoirs can be quite challenging to most conventional reservoir engineering tools. The purpose of this research is to develop a Compartmentalized Gas Depletion Model that applies not only to conventional consolidated reservoirs (with constant formation compressibility) but also to unconsolidated reservoirs (with variable formation compressibility) by including geomechanics, permeability deterioration and compartmentalization to estimate the OGIP and performance characteristics of each compartment in such reservoirs given production data. A geomechanics model was developed using available correlation in the industry to estimate variable pore volume compressibility, reservoir compaction and permeability reduction. The geomechanics calculations were combined with gas material balance equation and pseudo-steady state equation and the model was used to predict well performance. Simulated production data from a conventional gas Simulator was used for consolidated reservoir cases while synthetic data (generated by the model using known parameters) was used for unconsolidated reservoir cases. In both cases, the Compartmentalized Depletion Model was used to analyze data, and estimate the OGIP and Jg of each compartment in a compartmentalized gas reservoir and predict the subsequent reservoir performance. The analysis was done by history-matching gas rate with the model using an optimization technique. The model gave satisfactory results with both consolidated and unconsolidated reservoirs for single and multiple reservoir layers. It was demonstrated that for unconsolidated reservoirs, reduction in permeability and reservoir compaction could be very significant especially for unconsolidated gas reservoirs with large pay thickness and large depletion pressure.

In the oil and gas industry today, continuous wellbore data can be obtained with high precision. This accurate and reliable downhole data acquisition is made possible by advancements in permanent monitoring systems such as downhole pressure and temperature gauges and fiber optic sensors. The monitoring instruments are increasingly incorporated as part of the intelligent completion in oil wells where they provide bottomhole temperature, pressure and sometimes volumetric flow rate along the wellbore - offering the promise of revolutionary changes in the way these wells are operated. However, to fully realize the value of these intelligent completions, there is a need for a systematic data analysis process to interpret accurately and efficiently the raw data being acquired. This process will improve our understanding of the reservoir and production conditions and enable us make decisions for well control and well performance optimization. In this study, we evaluated the practical application of an interpretation model, developed in a previous research work, to field data. To achieve the objectives, we developed a simple and detailed analysis procedure and built Excel user interface for data entry, data update and data output, including diagnostic charts and graphs. By applying our interpretation procedure to the acquired field data we predicted temperature and pressure along the wellbore. Based on the predicted data, we used an inversion method to infer the flow profile - demonstrating how the monitored raw downhole temperature and pressure can be converted into useful knowledge of the phase flow profiles and fluid entry along the wellbore. Finally, we illustrated the sensitivity of reservoir parameters on accuracy of interpretation, and generated practical guidelines on how to initialize the inverse process. Field production logging data were used for validation and application purposes. From the analysis, we obtained the production profile along the wellbore; the fluid entry location i.e. the productive and non-productive locations along the wellbore; and identified the fluid type i.e. gas or water being produced along the wellbore. These results show that temperature and pressure profiles could provide sufficient information for fluid identity and inflow distribution in gas wells.

Predicting the performance of wells in compartmentalized reservoirs can be quite challenging to most conventional reservoir engineering tools. The purpose of this research is to develop a Compartmentalized Gas Depletion Model that applies not only to conventional consolidated reservoirs (with constant formation compressibility) but also to unconsolidated reservoirs (with variable formation compressibility) by including geomechanics, permeability deterioration and compartmentalization to estimate the OGIP and performance characteristics of each compartment in such reservoirs given production data. A geomechanics model was developed using available correlation in the industry to estimate variable pore volume compressibility, reservoir compaction and permeability reduction. The geomechanics calculations were combined with gas material balance equation and pseudo-steady state equation and the model was used to predict well performance. Simulated production data from a conventional gas Simulator was used for consolidated reservoir cases while synthetic data (generated by the model using known parameters) was used for unconsolidated reservoir cases. In both cases, the Compartmentalized Depletion Model was used to analyze data, and estimate the OGIP and Jg of each compartment in a compartmentalized gas reservoir and predict the subsequent reservoir performance. The analysis was done by history-matching gas rate with the model using an optimization technique. The model gave satisfactory results with both consolidated and unconsolidated reservoirs for single and multiple reservoir layers. It was demonstrated that for unconsolidated reservoirs, reduction in permeability and reservoir compaction could be very significant especially for unconsolidated gas reservoirs with large pay thickness and large depletion pressure.

During production from gas condensate reservoirs, significant productivity loss occurs after the pressure near the production wells drops below the dew point of the hydrocarbon fluid. Several methods such as gas recycling, hydraulic fracturing and solvent injection have been tried to restore gas production rates after a decline in well productivity owing to condensate and/or water blocking. These methods of well stimulation offer only temporary productivity restoration and cannot always be used for a variety of reasons. Significant advances have been made during this study to develop and extend a chemical treatment to reduce the damage caused by liquid (condensate + water) blocking in gas condensate reservoirs. The chemical treatment alters the wettability of water-wet sandstone rocks to neutral wet, and thus reduces the residual liquid saturations and increases gas relative permeability. The treatment also increases the mobility and recovery of condensate from the reservoir. A nonionic polymeric fluoro-surfactant in a glycol-alcohol solvent mixture improved the gas and condensate relative permeabilities by a factor of about 2 on various outcrop and reservoir sandstone rocks. The improvement in relative permeability after chemical treatment was quantified by performing high pressure and high temperature coreflood experiments on outcrop and reservoir cores using synthetic gas mixtures at reservoir conditions. The durability of the chemical treatment has been tested by flowing a large volume of gas-condensate fluids for a long period of time. Solvents used to dissolve and deliver the surfactant play an important part in the treatment, especially in the presence of high water saturation or high salinity brine. A screening test based on phase behavior studies of treatment solutions and brines has been used to select appropriate mixtures of solvents based on reservoir conditions. The adsorption of the surfactant on the rock surface has been measured by measuring the concentration of the surfactant in the effluent. Wettability of treated and untreated reservoir rocks has been analyzed by measuring the USBM and Amott-Harvey wettability indices to evaluate the effect of chemical treatment on wettability. For the first time, chemical treatments have also been shown to remove the damage caused by water blocking in gas wells and for increasing the fracture conductivity and thus productivity of fractured gas-condensate wells. Core flood experiments done on propped fractures show significant improvement in gas and condensate relative permeability due to surface modification of proppants by chemical reatment. Relative permeability measurements have been done on sandstone and limestone cores over a wide range of conditions including high velocities typical of high rate gas wells and corresponding to both high capillary numbers and non-Darcy flow. A new approach has been presented to express relative permeability as a function three non-dimensionless terms; capillary number, modified Reynolds Number and PVT ratio. Numerical simulations using a compositional simulator have been done to better understand and design well treatments as a function of treatment volume and other parameters. Injection of treatment solution and chase gas and the flow back of solvents were simulated. These simulations show that chemical treatments have the potential to greatly increase production with relatively small treatment volumes since only the near-well region blocked by condensate and/or water needs to be treated.

Thesis (M.S.)--West Virginia University, 2009. / Title from document title page. Document formatted into pages; contains ix, 100 p. : ill. (some col.), col. maps. Includes abstract. Includes bibliographical references (p. 72-73).

Thesis (M.S.)--West Virginia University, 1999. / Title from document title page. Document formatted into pages; contains x, 82 p. : ill. (some col.) Vita. Includes abstract. Includes bibliographical references (p. 42).