This project is a research into the effect of gas condensate damage in hydraulically fractured wells. It is the result of a problem encountered in producing a low permeability formation from a well in South Texas owned by the El Paso Production Company. The well was producing from a gas condensate reservoir. Questions were raised about whether flowing bottomhole pressure below dewpoint would be appropriate. Condensate damage in the hydraulic fracture was expected to be of significant effect. In the most recent work done by Adedeji Ayoola Adeyeye, this subject was studied when the effects of reservoir depletion were minimized by introduction of an injector well with fluid composition the same as the original reservoir fluid. He also used an infinite conductivity hydraulic fracture along with a linear model as an adequate analogy. He concluded that the skin due to liquid build-up is not enough to prevent lower flowing bottomhole pressures from producing more gas. This current study investigated the condensate damage at the face of the hydraulic fracture in transient and boundary dominated periods when the effects of reservoir depletion are taken into account. As a first step, simulation of liquid flow into the fracture was performed using a 2D 1-phase simulator in order to help us to better understand the results of gas condensate simulation. Then during the research, gas condensate models with various gas compositions were simulated using a commercial simulator (CMG). The results of this research are a step forward in helping to improve the management of gas condensate reservoirs by understanding the mechanics of liquid build-up. It also provides methodology for quantifying the condensate damage that impairs linear flow of gas into the hydraulic fracture.

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

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

Not available / text

A new test facility, with a vertical reflux condenser of 1500mm overall length and 45mm internal diameter, has been commissioned and tested and methods developed for measuring key process parameters. An experimental study of reflux condensation in a single tube using n-pentane and iso-octane and binary mixtures of these single component hydrocarbons has been undertaken. Using water as the cooling medium, a correlation was developed for determining the coolant-side heat transfer coefficient in the reflux condenser based on the Wilson plot method. The composition of binary liquid mixture samples from the test facility was determined using an empirical correlation developed using density measurements from a vibrating u-tube densitometer. The single components were condensed in the range 32.0-48.4°C and 0.106-1.515bara by adjusting the test condenser heat load for fixed conditions on the coolant side to investigate how the condensate-film heat transfer coefficient varied with the condensate film Reynolds number. The results show good agreement with the method recommended by HTFS for correcting the Nusselt theory for the effects of waves. A further small correction was made to improve the fit to the data. The binary hydrocarbon mixtures were condensed across the range 65.9-90.1°C and 0.729-1.531bara by conducting similar experiments where the feed vapour contained 50% and 70% n-pentane. Composition measurements of the condensate and vapour leaving the test condenser were made to examine the separation of components during partial reflux condensation. The results suggest that this separation is influenced by heat flux and that it would be improved if the test condenser were operated at a lower heat flux. Further experimental work is needed to verify this, and to investigate how this influences the number of thermodynamic stages, which was found to be less than one with the conditions reported here. Analysis of the heat transfer resistances on the vapour side showed that the standard procedure of using a dry-gas heat transfer coefficient, with or without a mass transfer correction term based on the film theory, poorly predicted the experimental values. These predictions were improved by the use of an enhancement factor, which may be more relevant in counter-current than co-current condensing situations. The results indicate that use of a dry-gas heat transfer coefficient with the film theory correction factor, over-predicts the mass transfer resistance. Comparison was made between the data and predictions based on the integral condensation curve, as might be used in Silver's method for condenser thermal design. It was shown that this method poorly predicted the surface area and the separation achieved in the test condenser. The results indicate that the heat and mass transfer coefficients obtained in a plain tube are significantly higher than those based on using a dry-gas heat transfer coefficient corrected by film theory. Implications for the design of reflux condensers have been presented.

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).

Many gas wells suffer a loss in productivity due to liquid accumulation in the near wellbore region. This problem starts as the flowing bottom hole pressure drops below the dew point in wells producing from gas condensate reservoirs. Chemical stimulation may be used as a remedy, by altering the wettability to non-liquid wetting. Successful treatments decrease liquid trapping, increase fluids mobility, and improve the well’s deliverability. The main focus in this research was to develop an effective chemical treatment to mitigate liquid blocking in gas wells producing from carbonate reservoirs. In the initial stages, screening tests were developed to quickly and effectively identify suitable chemicals from a large pool of compounds. X-ray Photoelectron Spectroscopy (XPS) measurements, drop imbibition tests, and contact angle measurements with water and n-decane were found to be necessary but not sufficient indicators of the effectiveness of the chemicals and were used as screening tools. An integral part of the development of the treatment solution was the selection of a solvent mixture capable of delivering the fluorinated chemical to the rock surface. The treatment solution, mixture of chemical dissolved in solvent, must be stable in the presence of both brine and condensate so that it will not precipitate and will not reduce permeability of the rock. Through phase behavior studies the compatibility of the treatment solution and in-situ brines were investigated to reduce the risk of failure in the coreflood experiments. The measured relative permeability values in Texas Cream Limestone and Silurian Dolomite cores are demonstrate from high-pressure, high-temperature coreflood experiments before and after treatment. Measurements were made using a pseudo-steady-state method with synthetic gas-condensate mixtures. To enhance the durability of the treatment a special amine primer is introduced. / text

When the reservoir pressure is decreased below dew point pressure of the gas near the wellbore, gas-condensate wells start to decrease production because condensate is separated from the gas around the wellbore causing a decrease in gas relative permeability. This effect is more dramatic if the permeability of the reservoir is low. The idea proposed for reducing this problem is to eliminate the irreducible water saturation near the wellbore to leave more space for the gas to flow and therefore increase the productivity of the well. In this research a simulation study was performed to determine the range of permeabilities where the cylinder of condensate will seriously affect the well’s productivity, and the distance the removal of water around the wellbore has to be extended in order to have acceleration of production and an increase in the final reserves. A compositional-radial reservoir was simulated with one well in the center of 109 grids. Three gas-condensate fluids with different heptanes plus compositions ( 4, 8 and 11 mole %), and two irreducible water saturations were used. The fitting of the Equation of State (EOS) was performed using the method proposed by Aguilar and McCain. Several simulations were performed with several permeabilities to determine the permeabilities for which the productivity is not affected by the presence of the cylinder of condensate. At constant permeability, various radii of a region of zero initial water saturation around the wellbore were simulated and comparisons of the effects of removal of irreducible water on productivity were made. Reservoirs with permeabilities lower than 100 mD showed a reduction in the ultimate reserves due to the cylinder of condensate. The optimal radius of water removal depends on the fluid composition and the irreducible water saturation of the reservoir. The expected increase in reserves due to water removal varies from 10 to 80 % for gas production and from 4 to 30% for condensate production.

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.