Thesis (Ph. D.)--University of Texas at Austin, 2006. / Vita. Includes bibliographical references.

Not available / text

In this work we propose two new Vogel-type Inflow Performance Relations (or IPR) correlations for gas-condensate reservoir systems. One correlation predicts dry gas production the other predicts condensate (liquid) production. These correlations provide a linkage between reservoir rock and fluid properties (dewpoint, temperature, and endpoint relative permeabilities, composition, etc.) to the flowrate-pressure performance for the reservoir system. The proposed IPR relationships for compositional reservoir systems are based on data from over 3000 compositional reservoir simulation cases developed using various fluid properties and relative perme-ability curves. The resulting IPR curves for gas condensate systems are quadratic in behavior - similar to the Vogel IPR trends (the Vogel (quadratic) rate-pressure profile is generally presumed for the case of a solution gas-drive reservoir system). However, in the case of a gas-condensate reservoir system, the coefficients in the quadratic relationship vary significantly depending on the richness of the gas conden-sate fluid (i.e., the composition) as well as the relative permeability-saturation behavior. Using an alter-nating conditional expectation approach (i.e., non-parametric regression), an approximate model was de-veloped to estimate these coefficients. This work also includes a discussion of the Vogel IPR for solution gas-drive systems. The original work proposed by Vogel is based on an empirical correlation of numerical simulations for a solution-gas-drive system. Our work provides a critical validation and extension of the Vogel work by establishing a simple, yet rigorous formulation for flowrate-pressure performance in terms of effective permeabilities and pres-sure-dependent fluid properties. The direct application of this work is to predict the IPR for a given reservoir system directly from rock-fluid properties and fluid properties. This formulation provides a new mechanism that can be used to couple the flowrate and pressure behavior for solution gas-drive systems and we believe that it may be possible to extend the proposed semi-analytical concept to gas-condensate reservoir systems. However, for this work we have only considered a semi-empirical IPR approach (i.e., a data-derived correlation) for the case of gas-condensate reservoir systems. We recognize that further work should be performed in this area, and we encourage future research on the topic of semi-analytical modeling of IPR behavior for gas-condensate reservoir systems.

Thesis (M.S.)--West Virginia University, 2009. / Title from document title page. Document formatted into pages; contains x, 92 p. : ill. (some col.). Includes abstract. Includes bibliographical references (p. 71-73).

Thesis (Ph.D.)--University of Tulsa, 1989. / Bibliography: leaves 300-306.

The proposed work provides a concept for predicting well performance behavior in a gas condensate reservoir using an empirical model for gas mobility. The proposed model predicts the behavior of the gas permeability (or mobility) function in the reservoir as condensate evolves and the gas permeability is reduced in the near-well region due to the "condensate bank". The proposed model is based on observations of simulated reservoir performance and predicts the behavior of the gas permeability over time and radial distance. This model is given by: The proposed concept has potential applications in the development of a pressure-time-radius solution for gas condensate reservoirs experiencing this type of mobility behavior. We recognize that the proposed concept (i.e., a radially-varying gas permeability) is oversimplified, in particular, it ignores the diffusive effects of the condensate (i.e., the viscosity-compressibility behavior). However, we have effectively validated the proposed model using literature results derived from numerical simulation. This new solution is presented graphically in the form of "type curves." We propose that the "time" form of this solution be used for applications in well test analysis. Previous developments used for the analysis of well test data from gas condensate reservoirs consider the radial composite reservoir model, which utilizes a "step change" in permeability at some radial distance away from the wellbore. Using our proposed solution we can visualize the effect of the varying gas permeability in time and radius (a suite of (dimensionless) radius and time format plots are provided). In short, we can visualize the evolution of the condensate zone as it evolves in time and radial distance. A limitation is the simplified form of the kg profile as a function of radius and time - as well as the dependence/appropriateness of the α-parameter. While we suspect that the α-parameter represents the influence of both fluid and rock properties, we do not examine how such properties can be used to calculate the α-parameter.

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

In gas-condensate reservoirs, production rate starts to decrease when retrograde condensation occurs. As the bottomhole pressure drops below the dewpoint, gascondensate and water buildup impede flow of gas to the surface. To stop the impairment of the well, many publications suggest wettability alteration to gas-wetting as a permanent solution to the problem. Previous simulation work suggests an "optimum wetting state" to exist where maximum gas condensate well productivity is reached. This work has direct application in gas-condensate reservoirs, especially in identifying the most effective stimulation treatment which can be designed to provide the optimum wetting conditions in the near-wellbore region. This thesis presents an extensive experimental study on Berea sandstone rocks treated with a fluorinated polymer. Various concentrations of the polymer are investigated to obtain the optimum alteration in wettability to intermediate gas-wet. This wetting condition is achieved with an 8% polymer solution treatment, which yields maximum gas mobility, ultimately increasing the relative permeability curves and allowing enhanced recovery from gas-condensate wells. The treatments are performed mainly at room conditions, and also under high pressure and high temperature, simulating the natural environment of a reservoir. Several experimental techniques are implemented to examine the effect of treatments on wettability. These include flow displacement tests and oil imbibitions. The experimental work took place in the Wettability Research Lab in Texas A&M University at Qatar in Doha, Qatar. The studies in this area are important to improve the productivity of gas-condensate reservoirs where liquid accumulates, decreasing production of the well. Efficiency in the extraction of natural gas is important for the economic and environmental considerations of the oil and gas industry. Wettability alteration is one of the newest stimulation methods proposed by researchers, and shows great potential for future research and field applications.

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.

In a natural gas field, determining the life of the field and deciding the best production technique, meeting the economical considerations is the most important criterion. In this study, a field in Thrace Basin was chosen. Available reservoir data was compiled to figure out the characteristics of the field. The data, then, formatted to be used in the commercial simulator, IMEX, a subprogram of CMG (Computer Modeling Group). The data derived from the reservoir data, used to perform a history match between the field production data and the results of the simulator for a 3 year period between May 2002 and January 2005. After obtaining satisfactory history matching, it was used as a base for future scenarios. Four new scenarios were designed and run to predict future production of the field. Two new wells were defined for the scenarios after determining the best region in history matching. Scenario 1 continues production with existing wells, Scenario 2 includes a new well called W6, Scenario 3 includes another new well, W7 and Scenario 4 includes both new defined wells, W6 and W7. All the scenarios were allowed to continue until 2010 unless the wellhead pressure drops to 500 psi. None of the existing wells reached 2010 but newly defined wells achieved to be on production in 2010. After comparing all scenarios, Scenario 4, production with two new defined wells, W6 and W7, was found to give best performance until 2010. During the scenario 4, between January 2005 and January 2010, 7,632 MMscf gas was produced. The total gas production is 372 MMscf more than Scenario 2, the second best scenario which has a total production of 7,311MMscf. Scenario 3 had 7,260 MMscf and Scenario 1 had 6,821 MMscf respectively. A nodal system analysis is performed in order to see whether the initial flow rates of the wells are close to the optimum flow rates of the wells, Well 1 is found to have 6.9 MMscf/d optimum production rate. W2 has 3.2 MMscf/d, W3 has 8.3 MMscf/d, W4 has 4.8 MMscf/d and W5 has 0.95 MMscf/d optimum production rates respectively.