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

Not available / text

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.

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

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, 2010. / Title from document title page. Document formatted into pages; contains ix, 52 p. : ill. (some col.). Includes abstract. Includes bibliographical references (p. 49-51).

A critical issue in the development of gas condensate reservoirs is accurate prediction of well deliverability. In this investigation a procedure has been developed for accurate prediction of well production rates using semi-empirical approach. The use of state of the art fine grid numerical simulation is time consuming and computationally demanding, therefore not suitable for real time rapid production management decisions required on site. Development of accurate fit-for-purpose correlations for fluid property prediction below the saturation pressure was a major consideration to properly allow for retrograde condensation, complications of multiphase flow and mobility issues. Previous works are limited to use of experimentally measured pressure, volume, temperature (PVT) property data, together with static relative permeability correlations for simulation of well deliverability. To overcome the above limitations appropriate fluid property correlations required for prediction of well deliverability and dynamic three phase relative permeability correlation have been developed to enable forecasting of these properties at all the desired reservoir conditions The developed correlations include; condensate hybrid compressibility factor, viscosity, density, compositional pseudo-pressure, and dynamic three phase relative permeability. The study made use of published data bases of experimentally measured gas condensate PVT properties and three phase relative permeability data. The developed correlations have been implemented in both vertical and horizontal well models and parametric studies have been performed to determine the critical parameters that control productivity in gas condensate reservoirs, using specific case studies. The improved correlations showed superior performance over existing correlations on validation. The investigation has built on relevant literature to present an approach that modifies the black oil model for accurate well deliverability prediction for condensate reservoirs at conditions normally ignored by the conventional approach. The original contribution to knowledge and practice includes (i) the improved property correlations equations, (4.44, 4.47, 4.66, 4.69, 4.75, 5.21) and (ii) extension of gas rate equations, for condensate rate prediction in both vertical and horizontal wells. Standard industry software, the Eclipse compositional model, E-300 has been used to validate the procedure. The results show higher well performance compared with the industry standard. The new procedure is able to model well deliverability with limited PVT and rock property data which is not possible with most available methods. It also makes possible evaluation of various enhanced hydrocarbon recovery techniques and optimisation of gas condensate recovery.

In gas-condensate reservoirs, gas productivity declines due to the increasing accumulation of liquids in the near wellbore region as the bottom-hole pressure declines below the dew point pressure. This phenomenon occurs even in reservoirs containing lean gas-condensate fluid. Various methods were addressed to remediate the productivity decline, for example, fracturing, gas injection, solvent injection and chemical treatment. Among them, gas injection techniques have been used as options to prevent retrograde condensation by vaporizing condensate and/or by enhancing condensate recovery in gas-condensate reservoirs. It is of utmost importance that the behavior of liquid accumulation near the wellbore should be described properly as that provides a better understanding of the productivity decline due to the originated from impaired relative mobility of gas. In this research, several gas injection techniques were assessed by using compositional simulators. The feasibility of different methods such as periodic hot gas injection and gas reinjection using horizontal wells were assessed using different reservoir fluid and injection conditions. It is shown that both the temperature and composition of the injection fluids play a key role in the remediation of productivity and condensate recovery. The combined effect of these parameters were investigated and the resulting impact on gas and condensate production was calculated by numerical simulations in this study. Design parameters pertaining to field development and operations including well configuration and injection/production scheme were also investigated in this study along with the above parameters. Based on the results, guidelines on design issues relating gas injection parameters were suggested. The various simulation cases with different parameters helped with gaining insight into the strategy of gas injection techniques to remediate the gas productivity and condensate recovery. / text

In the last decade, shale reservoirs emerged as one of the fast growing hydrocarbon resources in the world unlocking vast reserves and reshaping the landscape of the oil and gas global market. Gas-condensate reservoirs represent an important part of these resources. The key feature of these reservoirs is the condensate banking which reduces significantly the well deliverability when the condensate forms in the reservoir below the dew point pressure. Although the condensate banking is a well-known problem in conventional reservoirs, the very low permeability of shale matrix and unavailability of proven pressure maintenance techniques make it more challenging in shale reservoirs. The nanoscale range of the pore size in the shale matrix affects the gas flow which deviates from laminar Darcy flow to Knudsen flow resulting in enhanced gas permeability. Furthermore, the phase behaviour of gas-condensate fluids is affected by the high capillary pressure in the matrix causing higher condensate saturation than in bulk conditions. A good understanding and an accurate evaluation of how the condensate builds up in the reservoir and how it affects the gas flow is very important to manage successfully the development of these high-cost hydrocarbon resources. This work investigates the gas Knudsen flow under condensate saturation effect and phase behaviour deviation under capillary pressure of gas-condensate fluids in shale matrix with pore size distribution; and evaluates their effect on well productivity. Supplementary MATLAB codes are provided elsewhere on OpenAIR: http://hdl.handle.net/10059/2145.