Well Test Analysis in Lean Gas Condensate Reservoirs: Theory and Practice

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]

From Straight Lines to Deconvolution: The Evolution of the State of the Art in Well Test Analysis

“…Numerical simulation, however, can help with the inverse problem (identifying the interpretation model), by modeling the effects of potential geological features, such as discontinuous boundaries of various shapes or layering, and the impact of suspected phase changes as in gas condensate reservoirs below the dewpoint pres-sure or volatile oil reservoirs below the bubblepoint pressure. These forward simulations are mandatory in complex geological or completion situations, to distinguish between potential causes of an observed behavior (Gringarten et al 2006).…”

Single-Well Simulation for Horizontal Wells in Fractured Gas Condensate Reservoirs

“…24 Gringarten incorporated the capillary number effect into numerical simulations and discovered that the saturation of condensate oil near the wellbore was not as high as previously thought, but rather lower than in other regions. 25,26 Thus, a four-zone model was introduced to describe the flow characteristics of condensate oil, which was adopted in this study for fluid flow in porous media. Although the GCR model for vertical wells has been gradually improved, the development of the GCR model for horizontal wells is slow.…”

Semianalytical Modeling for Multiphase Flow in a Fractured Low-Permeability Gas Condensate Reservoir

“…15 Abdolnabi and Gringarten applied composite models to horizontal wells. 16,17 Bozorgzadeh and Kgogo each gave an opinion that the type curves of lean and medium-rich condensate gas fluids have three-zone radial composite behavior. 18,19 However, rich gas fluids exhibit only two-region radial composite behavior.…”