Near Critical Gas Condensate Relative Permeability of Carbonates

Abstract

Abstract The productivity of most gas condensate wells is reduced significantly due to condensate banking when the bottom-hole pressure falls below the dew point. The liquid drop-out such gas wells leads to reduced gas relative permeability and thus to low recovery problems. An understanding of the characteristics of the high-velocity gas-condensate flow and relative permeabilities is necessary for accurate forecast of well productivity. In order to tackle this goal, a series of relative permeability measurements on a moderate permeability carbonate core, using a binary retrograde condensate fluid sample were conducted near miscible conditions. The experiments used a pseudo-steady-state technique at high pressure and high velocity, measuring relative permeability under conditions similar to the near well region of a carbonate gas-condensate reservoir. Furthermore, the flow of gas and condensate at different force ratios (capillary and bond numbers) are investigated. It was observed that relative permeability depended on fluid composition and flow rate as well as condensate and water saturations. It was observed that as the flow rate of wetting phase (condensate) increased or the interfacial tension decreased, relative permeability curves shifted to left. It was found that a simple three-parameter mathematical model that depends on a new dimensionless number called condensate number successfully models the gas-condensate relative permeability data. The developed model resulted in a good agreement with published gas-condensate relative permeability data as well as end point relative permeabilities and saturations. Introduction In a gas condensate reservoir, there are many important differences between the flow regimes in the regions close to and far from the well. These different flow regimes are reflected in the requirements for relative permeability data for the deep reservoir and near well regions. Far from the well, flow rates are low, and liquid mobility is usually less important, except in reservoirs containing very rich light component fluids. In the near well region, both liquid and gas phases are mobile, flow rates are high, and the liquid mobility is important. At initial reservoir conditions the hydrocarbon fluids are mostly present at near-critical conditions. Consequently, the physical properties of the oil phase are very similar, and the interfacial tension between oil and gas is very low. During the production phase of gas condensate reservoir multi phase fluid problem becomes important below dew point pressure. One of the important multi-phase fluid flow problems at near critical conditions is condensate drop out in the vicinity of wells in gas condensate reservoirs. This drop out causes an apparent skin resistance at the well bore that impairs the production capacity of well. The effect of near-criticality on the relative permeability is still an unsolved issue in reservoir engineering. Experimental studies published in the literature indicate a trend from immiscible to miscible relative permeability curves as the interfacial tension approaches zero. Unfortunately, there is no consensus on how near miscibility changes relative permeability curves and which parameters control this change. Some investigators[1-3] have found that the relative permeability to the non-wetting phase is affected more easily, whereas others observed a greater increase of the relative permeability to the wetting phase compared with the relative permeability to the non-wetting phase[4,5]. More importantly, some studies did not report an effect of interfacial tension at all.[6,7] Equally contradicting are the reports on the effect of flow velocity on near-miscible relative permeability. Some investigators find no effect,[8-9] whereas others do.[2,10] In addition, Henderson et al.[3] have reported that relative permeability is only affected by the flow velocity if the fluids enter the porous medium as a single, homogeneous phase, and subsequently, are allowed to separate into two phases inside the pores. There are two conflicting views on which mechanism controls the change in relative permeability. Many authors argue that a low interfacial tension affects relative permeability through the ratio between viscous forces and capillary forces, as denoted by the capillary number.[1,2,10-14] Most of these authors, however, suggest that there is a threshold interfacial tension below which the capillary-number dependence becomes important.[1-3,11-12] Relative permeability data is usually interpreted in terms of the interfacial tension alone.[4-5,15-18] In two cases, this was done in view of the fact that a transition from partial wetting to complete wetting, as predicted by Cahn,[19] may affect the mobility of both phases.[5,9] The influence of such a transition cannot be described in terms of the capillary number, because it is directly induced by a change in the interfacial tension between the near-miscible phases.