Well Test Analysis in Gas Condensate Reservoirs: Theory and Practice

Abstract

Abstract Gas condensate reservoirs exhibit a complex behavior when wells are produced below the dew point, due to the existence of a two-fluid system, reservoir gas and liquid condensate. Different mobility zones develop around the wellbore corresponding respectively to the original gas in place (away from the well), the condensate drop-out, and capillarity number effects (close to the well). Condensate drop-out causes a non-reversible reduction in well productivity, which is compensated in part by capillarity number effects. All these effects can be identified and quantified from well test data. Tests in condensate reservoirs, however, tend to be difficult to interpret. Build-up and/or drawdown data are usually dominated by wellbore phase redistribution effects and the main analysis challenge is to distinguish between reservoir effects, boundary effects, fluid behavior and wellbore phase redistribution perturbations. The paper compares theoretical well test behaviors in vertical and horizontal wells as obtained from compositional simulation with actual behaviors selected from more than twenty different gas condensate reservoirs. An interpretation methodology is described, which uses time-lapse analyses, deconvolution and different analytical and numerical tools to identify the probable causes of the pressure data behavior: two-region and three-region analytical composite models to represent the various mobility zones around the wellbore; a voronoi-grid numerical simulator to represent discontinuous boundaries; a multilayered analytical simulator to account for the geological description and a compositional simulator to verify the fluid behavior. It is shown that, in addition to the usual well test analysis results, it is possible to obtain parameters required for reservoir simulation and well productivity forecasting, such as gas relative permeabilities at the end point, critical oil saturation, and the base capillary number. Introduction Gas condensate reservoirs are becoming more common as deeper depths are being targeted in the exploration for oil and gas. The behaviors of such systems are complex and are still not fully understood, especially in the near-wellbore region. Well tests, in particular, are difficult to interpret. A discussion of the state-of-the-art in gas condensate well test interpretation was published in 2000 by Gringarten et al.[1] with an extensive review of the related literature. To summarize, a characteristic of gas condensate production is the creation of a condensate bank when the bottomhole pressure drops below the dew point[2] pressure. This reduces the gas relative permeability[3] around the well and leads to a loss of well productivity,[4–7] with some wells even ceasing production completely due to condensate loading in the wellbore.[5] This "condensate banking" effect, however, is compensated by "velocity stripping" which increases the gas mobility in the immediate vicinity of the wellbore.[8] "Velocity" or "viscous" stripping (also called "positive coupling")[9–13] occurs at high capillarity number, a dimensionless parameter that represents a ratio of viscous to capillary forces:[14,15]