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

Thesis (Ph. D.)--University of Texas at Austin, 2006. / 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.

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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.

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.

Altering the wettability of reservoir rock using fluoro-chemical treatments has proved to be a viable solution to the condensate blocking problem in gas wells. Alteration of rock wettability to neutral-wet is the primary reason for improvement in gas and condensate relative permeabilities. Stability/compatibility test, drop tests and X-ray photoelectron spectroscopy (XPS) analysis along with core flood results were used to characterize wettability changes. XPS tests, drop tests, and relative permeability measurements were conducted and correlated with each other. It is shown that XPS analysis and imbibition tests provide a quantitative measure of chemical adsorption and surface modification, but only a qualitative measure of the possible change in relative permeability. As such these simple analytical tools may be used as a screening tool. A positive but imperfect empirical correlation was obtained with results from core flood experiments. The varying concentration of fluorine observed on the rock surface was found to be directly correlated to the wettability change in the rock, which in turn is responsible for improving the deliverability of wells in gas condensate/volatile oil reservoirs. The method discussed in this thesis can be used to identify chemical treatments to change rock wettability and, therefore, relative permeability. This provides a simple, quick and inexpensive way to screen chemicals as wettability altering agents and relative permeability modifiers which saves time, cost and effort. / text

Gas wells suffer a decrease in productivity because of the formation of a liquid hydrocarbon “condensate” in the near wellbore area. This "condensate" forms near producing wells when the flowing pressure is below the reservoir fluid's dew point. Several methods have been shown to temporarily alleviate this problem, but eventually the condensate bank reforms and the productivity again decreases. The use of surfactants to alter the near wellbore wettability to neutral wetting is a potential longer term solution to liquid blocking in these reservoirs. This alteration increases the gas and liquid relative permeabilities and thereby the productivity by reducing the residual liquid saturation. This enhancement allows the accumulated liquid to flow and is durable as long as the wettability alteration is persistent. This solution has been shown to be successful through core flood experiments and field trials in high permeability sandstones, but no improvements had been observed in low permeability cores. As the global demand for energy increases, the petroleum industry has begun to develop unconventional (low permeability) assets, new techniques are needed to maintain and improve their productivity. Liquid blocking in these wells can have a much larger impact on both the gas and condensate production in such low permeability formations. Applying this technique increases both gas and condensate mobility and should increase the economic producing life of these wells. Core flood experiments were conducted to investigate the ability of a chemical treatment to alter the wettability of low permeability sandstones. Previous experimentation did not find any improvement because the increased capillary forces prevented the treatment solution from being easily displaced. This concealed the benefit achieved when the wettability was altered. These experiments recorded smaller relative permeability increases compared to higher permeability core floods, so super critical carbon dioxide was tested as an alternative solvent. While the new treatment was more injectable, it was not as successful at altering wettability. Progress has been made on a solution to liquid blocking in low permeability sandstones, but additional research needs to be completed to further optimize this method. / text