Theoretical Methodology for Prediction of Gas-Condensate Flow Behavior

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Theoretical Methodology for Prediction of Gas-Condensate Flow Behavior Masoud Nikravesh,* SPE, Lawrence Berkeley National Laboratory, Berkeley, CA 94720, Masoud Soroush, Chemical Engineering Department, Drexel University, Philadelphia, PA 19104 Abstract Theoretical and experimental evidence has shown that the flow of condensate in the early stages of condensate formation up to < c is represented by film flow. After a transition state in which the gas saturation reaches critical condensate saturation, the condensate flow is subsequently reduced to bulk flow. The condensate is formed in the smaller pores, fills these pores and will continue into the larger pores. In the presence of interstitial water saturation, the condensate is formed in the water surface in the early stages of condensate formation. In addition, the gravity field has an important effect on Scc. Therefore, ignorance of the gravity effect in the experimental and theoretical calculations leads to an overestimation of the value for Scc. It is also shown that the shape of relative permeability curves are suddenly changed for a given critical IFT value (c). Introduction In a gas-condensate reservoir, as the pressure of the reservoir is reduced to below dewpoint pressure, retrograde condensation will occur and a new liquid phase will be formed. Once the new phase is formed, the condensate accumulates rapidly in the vicinity of the well bore which may lead to a significant drop in gas production. In extreme cases, gas production may stop completely. Recently, interest in gas-condensate flow behavior near critical region and at low Interfacial Tension (IFT) has increased among reservoir engineers and researchers. Some experimental work has recently been done concerning relative permeability which focused on the formation and flow of condensate in reservoir porous media. Saeidi and Handy studied the flow and phase behavior of gas condensate (Methane-Propane) in porous media (Sandstone core). They indicated that interstitial water shifts the oil's relative permeability to an appreciably lower saturation. In addition, no flow of condensate was observed for this system even with an 18% volumetric condensate dropout and in the presence of 30% interstitial water saturation. Asar and Handy investigated the influence of interfacial tension on the relative permeability of gas/oil in a gas-condensate system (Methane-Propane mixture in 0.19- m3 permeability core). They postulated that the irreducible gas and liquid saturation approaches zero as IFT approaches zero. In addition, they observed that condensate could flow at a low condensate saturation (Scc = 10%). Finally, it was concluded that liquid could flow at very low liquid saturation at low IFTs in a condensate reservoir. Gravier et al. used the steady state displacement method with horizontal cores (tight reservoir limestone) with interstitial water saturation from 19.5% to 30%. They determined critical condensate saturation (Scc) by injecting gas condensate into the core. The Scc values ranged from 24.5 to 50.5, with IFT ranging from 0.5 to 1.5 mN/m. Danesh et al. investigated retrograde condensation in water wet pores in their micromodels and a set of sandstone cores. They determined Scc values of 20.5% to 6.8% in the absence and presence of interstitial water, respectively. Morel et al., in their study of vertical dolomite core, reported a very low value for Scc (Scc=1%) for an IFT of 0.05 mN/m. in the presence of water (Swi=20%). Bardon and Longeron studied the effect of IFT (a very wide range of IFT, from 0.001 to 12.6 mN/m). P. 257