Well productivity impairment due to two-phase flow in the near well region is a major concern in gas condensate reservoirs. There usually exhibit complex flow behaviours due to the condensate banking around the well caused by the bottom-hole pressure drops below the dew point (for most gas-condensate reservoirs). This leads to a drop in gas relative permeability, a decrease in gas production and a significant economic condensate remains in the reservoir.
In this study, we use a methodology to evaluate the productivity of gas condensate wells. Starting from the analysis of six available well tests, we have identified one test that most suitable for the aim of this project. Then we have used a well-developed workflow in the Institute of Petroleum Engineering at Heriot-Watt University to carry out the study. The workflow is to first characterize the formation for reservoir heterogeneity, the fluid properties and well productivity to evaluate the well dynamic performance (transient pressure and inflow). The formation evaluation of the well is performed to determine key parameters of the reservoir. Then fluid PVT test results are studied in details for reservoir fluid property in contrast to the phase diagrams for the whole gas column. The nature of the test, i.e. a gas-condensate reservoir with respect to the testing depth, interval and pressure regimes (on the phase diagram) have been re-ensured.
A radial homogeneous model was built to tune the well test simulation local grid refinement cell sizes and time steps, and a 3D geological model was built using the latest techniques to honour the reservoir heterogeneity. The model was then up-scaled into a fully compositional flow model for well test simulation. Numerical well test has been conducted with the same testing schedule and parameters (rock and fluids) as the existing well test. Finally, sensitivity studies on key parameters have been performed through the numerical well test simulation leading to the construction of families of reservoir system type curves. By the matching of these type curves to the existing well test, a numerical model is derived by tuning and matching to the real testing data. The derived model then can be used for future productivity forecast, as well as for new testing design.
A well test interpretation completed in this way has greatly reduced the analysis uncertainty and enhanced the understanding of the testing and the reservoir providing much more value from a well test.
Introduction
Gas condensate reservoir
Gas condensate reservoir produces a large amount of liquid called condensate. If the pressure experienced by a gas condensate fluid is decreased, particularly when it is below the dew point, then the liquid saturation will increase. However, further pressure reduction will finally lead to part of the liquid segregated fron the gas revaporizes.[11] This is the typical phase behaviour of gas condensate fluids as illustrated in Figure 1.
In gas condensate reservoir, when the reservoir pressure some distance away from the well, falls below the dew point, a two-phase region will be produced due to liquid segregated from the gas. This region has significant lower permeability that that in the rest of the reservoir. Engineers call this "condensate banking". In this situation, four saturation zones[1] away from the well can be observed as shown in Figure 2.Far away from the well, there is an initial saturation in liquid.Moving closer to the well, there is a rapid increase in liquid saturation and decrease in gas mobility. In this region, the liquid is immobile, only gas flows.Further close to the wellbore, the liquid saturation is higher that critical saturation and both gas and condensate are mobile, which will result in reduction of the effective permeability to gas and therefore the productivity of the well.[5] This is the liquid-drop-out region.
