Gas condensate reservoirs usually exhibit complex flow behaviors due to the build-up of condensate banks around the wells when the bottomhole pressure drops below the dew point. The formation of this liquid saturation can lead to a severe loss of well productivity and therefore lower gas recovery. Several studies have examined various ways to minimize the pressure drop in order to reduce liquid drop-out and related problems. One solution implemented over the past decade is the use of horizontal wells.
There is a lack of published knowledge on the flow behavior of horizontal wells in gas condensate reservoirs. The limited studies in this area1–3 focused on well performance rather than on well test behavior. There has been no evidence of condensate drop out effects in published horizontal well tests data.
This paper presents preliminary results from a study aimed at establishing an understanding of the near-wellbore well test behavior in horizontal wells in gas condensate reservoirs, with a focus on the existence of different mobility zones due to condensate dropout.
We used a 3D fully compositional model to develop derivative shapes to be expected from horizontal well test data in gas condensate reservoirs below the dew point under various conditions. We then analyzed actual well test data that exhibit such derivative characteristics. Finally, we used a compositional model to verify the results obtained from conventional well test analysis.
It was found that condensate deposit near the wellbore yields a well test composite behavior, similar to what is found in vertical wells, but superimposed on a horizontal well behavior, which makes it much more complex.
Many studies4–6 have reported significant losses of well deliverability in gas condensate reservoirs due to condensate blockage. The level of productivity decline depends on several factors, including critical condensate saturation, relative permeabilities, non-Darcy flow and high capillary number effects.
Retrograde condensation occurs when the flowing bottomhole pressure declines below the dew point pressure7,8, creating three regions in the reservoir with different liquid saturations. Away from the well, an outer region has the initial liquid saturation; next, nearer the well, there is a rapid increase in liquid saturation and a decrease in the gas mobility. Liquid in that region is immobile. Closer to the well, an inner region is formed where liquid saturation is higher than a critical condensate saturation and both oil and gas phases are mobile. Finally, in the immediate vicinity of the well, there is a region with lower liquid saturation due to capillary number effects, which represents the ratio of viscous to capillary forces. Such a region has been inferred from a number of experimental core studies at low interfacial tension and high flow rates9,10. The existence of the fourth region is important because it counters the reduction in productivity caused by liquid drop-out.
The various mobility zones described above can be identified by well test analysis, using a variety of analytical and numerical models. Well test analysis is now commonly used to identify and quantify near-wellbore effects, reservoir behavior (i.e. zones of different mobilities and storativities) and reservoir boundaries. Finding all these information from well tests in gas condensate reservoirs, however, is challenging. This is due to changes in the composition of the original reservoir fluid and the impact of wellbore dynamics. Nonetheless, gas condensate flow behavior is now reasonably well understood for vertical wells, where the fluid flow toward the well can be modeled with a simple radial flow geometry. A number of publications6,11–13 discuss vertical well tests in gas condensate reservoirs which exhibit regions of decreasing gas mobility near the wellbore, including the increased gas mobility region in the immediate vicinity of the wellbore (the fourth region mentioned above)8,11.