Gas Condensate Reservoir Performance: Part I - Fluid Characterization

Abstract Gas condensate reservoirs exhibit complex coupling between phase behavior and geology. Characterization of the in situ fluid as well as development of phases for quantifying phase interference effects can be subject to considerable error. Techniques for sampling and characterization are reviewed and proposed whereby errors can be minimized. Recommended are multi-rate field sampling along with bottom-hole sampling, detailed analysis of produced liquid-phases and the importance of adhering to the parametric path followed in the field in order to develop representative fluids. Background Engineers sometimes err in the classification of dew point systems simply because they use rules of thumb which do not accurately represent the phase behavior of the reservoir. For example, a certain condensate yield may predispose an engineer to judge the fluid as a wet gas instead of a retrograde condensate fluid. Some wet gas systems may exhibit 20 BBL/MMscf condensate yields whereas some retrograde systems possess liquid yields less than 15 BBL/MMscf; it is not the liquid yield that dictates whether the fluid is condensate or wet gas but where the reservoir temperature is situated in the pressure temperature phase loop. To proceed with the appropriate field development plan and optimization, the reservoir fluid must be understood. Surprisingly, this step is frequently where mistakes are made. The problem of reservoir fluid characterization does not end there however. The common problem of gas productivity decrease with liquid drop out, in the nearwell bore region, provides adequate evidence that capillary pressure plays a significant role in retrograde reservoirs. Understanding the strong coupling between geology and fluid character may provide a competitive advantage for operators who apply the science of phase interference and technologies that address these complex phenomena. References 1 through 5 provide a crosssection of recent interesting topics that show the complexities of gas-condensate reservoir production. All of the relevant parameters, well understood, will lead to more accurate evaluation of the amount of hydrocarbon in place, the rate at which the resource can be produced and optimization strategies as the reservoir matures. It is the focus of this paper to promote understanding of gas-condensate phase behavior that will help the operator make the best of retrograde condensate reservoir opportunities. Sampling and Characterization To conclude whether the character of the fluid is that of retrograde condensate or wet gas should be very straightforward. Figure 1 provides a typical pressuretemperature diagram for a specific composition. If the reservoir temperature is to the right of the critical point, but to the left of the maximum temperature of the phase loop, the system exhibits retrograde behavior; components can condense out of the vapor phase, at reservoir temperature, as the pressure is reduced. This phenomenon differentiates between a wet gas and a gas condensate. Both fluids provide liquid yields at the surface separator, but retrograde condensate fluids create a liquid phase in situ whereas wet gases will only condense a liquid if the temperature is decreased. Since retrograde condensates separate into liquid and vapor in situ, the sampling of such reservoirs can be challenging.