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Impact of relative permeability models on fluid flow behavior for gas condensate reservoirs
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Accurate assessments of reserves and evaluation of productivity trends for gas condensate systems depend on a basic understanding of phase and fluid flow behavior. In gas condensate reservoirs, the gas flow depends on liquid drop out at pressures below the dewpoint pressure. The liquid initially accumulates as a continuous film along the porous media because of the low interfacial tension. Then, as the volume of condensate increases, the interfacial tension increases and capillary forces become more important. Modeling fluid flow in these systems must consider the dependence of relative permeability on both viscous and capillary forces. This research focuses on the evaluation of several recently proposed relative permeability models and on the quantification of their impact on reservoir fluid flow and well performance. We selected three relative permeability models to compare the results obtained in the modeling of relative permeabilities for a published North Sea gas condensate reservoir. The models employ weighting factors to account for the interpolation between miscible and immiscible flow behavior. The Pusch model evaluated using Fevang's weighting factor gave the best estimation of relative permeability when compared to the published data. Using a sector model, we evaluated the effects at the field scale of the selected gas condensate relative permeability models on well performance under different geological heterogeneity and permeability anisotropy scenarios. The Bette and Pusch models as well as the Danesh model, as implemented in a commercial reservoir simulator, were used to quantify the impact of the relative permeability models on fluid-flow and well performance. The results showed that, if the transition between miscible and immiscible behavior is not considered, the condensate saturation could be overestimated and the condensate production could be underestimated. After twenty years of production, the heterogeneous model using the selected relative permeability models predicted between 7.5 - 13% more condensate recovery than was estimated using an immiscible relative permeability model. Using the same relative permeability models, the anisotropic model forecast between 3 - 10% more condensate recovery than predicted using an immiscible relative permeability model. Results using the anisotropic model showed that vertical communication could affect the liquid distribution in the reservoir.
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Includes bibliographical references (leaves 109-114).
Issued also on microfiche from Lange Micrographics.
Zapata Arango, Jose︣ Francisco (2002). Impact of relative permeability models on fluid flow behavior for gas condensate reservoirs. Master's thesis, Texas A&M University. Available electronically from
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