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Abstract Measurement of relative permeability in the laboratory and/or its prediction from models has become an increasingly important subject in reservoir modelling, as reservoir simulation has become the standard method for more accurate forecasting of production and ultimate recovery. However, as is often the case, when the history match in a reservoir simulator is unsatisfactory, the parameter which is most likely to be adjusted is the relative permeability. With developments in measurement and interpretation techniques it is now possible to obtain reliable relative permeability curves. This paper examines current developments in relative permeability measurements from laboratory coreflood experiments, including developments in data reduction and the interpretation of results. It is apparent that classical analytical techniques, such as the Johnson, Bossler and Nauman (JBN) method, cannot describe the majority of unsteady-state displacements, yet are often inconsiderately applied. Valid relative permeability data is only possible if the analytical or numerical model allows for capillarity, viscous instability, wettability and permeability heterogeneity, and can be tuned by carefully measured pressure, flow, and saturation data, and, if possible, non-invasive saturation monitoring. The use of upscaling techniques to bridge the gap between reservoir simulation models and geological scale models poses a great challenge on relative permeability measurements and predictions, at small scale (laminar) levels and for different rock facies. Introduction Relative permeability is used to describe multiphase flow in a porous medium. Such data are important input to many reservoir engineering calculations, providing a basic description of the way in which the phases will move in the reservoir. Definition of the flow process can have a significant effect on the predicted hydrocarbon production rate and duration, and is important in calculating the volume of recoverable hydrocarbon reserves. Although ways to determine relative permeability from measurements made in the field have been proposed, they are fraught with problems and have never been regularly used. The most common method for determining relative permeability has been laboratory special core analysis. Laboratory measurement of representative relative permeability data on a reservoir core-fluid system is a complex task. The experiments are costly and time consuming. Accuracy is limited to the specific core samples and is bounded by narrow saturation limits. A fundamental theoretical approach to modelling multiphase fluid flow in porous rocks is prevented by the complex nature of the problem. Major difficulties arise in mathematically describing flow through a porous system where the lengths, diameters and connectivity of channels are largely unquantifiable, and the complex nature of the hydrocarbon fluids which range from heavy oils to gas condensates with complex thermodynamic behaviours. The extension of Darcy's law to multiple phase flow is, in fact, a heuristic procedure suggested by the analogy with single phase flow. It does not provide an understanding of the physics of multiple phase flow. However, as the law has been substantiated by experiments, it must be assumed that it is at least partly correct and a physical understanding of it has to be sought.
- Geology > Rock Type > Sedimentary Rock (0.48)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.35)
Abstract This paper presents the results of an integrated experimental and modelling studies to identify (and quantify) the various flow and phase behaviour phenomena that occur in the near wellbore region, during pressure depletion of a gas condensate reservoir. Laboratory studies were conducted to evaluate the characteristic effects of immobile and mobile condensate saturations on the mobility of gas in the near-wellbore region. The gas flowrates studied span both the Darcy and non-Darcy flow regimes. The experimental data were used in analytical pseudopressures and material balance models to estimate the well productivity changes due to the presence of condensate near the wellbore. Analysis of experimental data and simulation results show that the net effect of the various phenomena occuring in the near wellbore region is a balance between those effects that reduce well productivity (inertial effects, permeability reduction), and those effects that increase well productivity (capillary desaturation, mist flow and viscous stripping). Experiments show that capillary desaturation and viscous stripping of condensate may occur in the near wellbore region and the productivity in gas condensate reservoirs may not be greatly impaired as predicted by theoretical considerations alone. The paper discusses and provides data/models for the following parameters or phenomena:the onset of velocity stripping, critical condensate saturations, gas permeability reduction due to condensate dropout, modifications to relative permeabilities at high velocities and/or low ifts, and non-Darcy flow parameters for gas condensate flow. Introduction Three things are essential in the development of gas condensate fields:That in the original well testing of the field, accurate values of the gas/condensate ratio (GOR) are determined. This is important in the determination of initial in place reserves and fluid composition. That the GOR behaviour of the production wells is understood so that history matching to early data can be accurate. That the general long term behaviour of the reservoir and the liquid recovery factors expected in any planned gas injection process are realistic. An understanding of the dynamic processes involved in the buildup of condensate around the wells is essential for the modelling of gas condensate flow near the wellbore The producing GOR is often used as indication of the efficiency of a producing gas condensate well. Many times the separator GOR's will be too high depending upon whether the well is being produced at too high or too low a flowrate (Fig. 1). At too low a flowrate holdup of the retrograde condensate in the formation results in excessive producing GOR's. At very high flowrate, as the pressure drops below the dewpoint the liquid will drop out and begin to collect in the near wellbore region. In so doing, produced hydrocarbons will contain less liquid than they should and therefore the GOR will be erroneously high. Near Wellbore. The production of gas condensate below the dewpoint will result in the accumulation of liquid phase condensate in the near wellbore area, which in turn will ultimately impair the gas phase permeability. This near well accumulation of liquid is the result of the gas phase dropping out its associated condensate at a more rapid rate in its approach to the wellbore, in response to the pressure sink created by the producing well. This problem is made worse due to the fact that the throughput of the gas phase per unit rock volume progressively increases with decreasing distance from a wellbore with radial drainage. A dynamic equilibrium must be established where the rate of condensation is equal to the rate of liquid phase condensate flow.
- North America > United States (0.28)
- South America > Brazil (0.28)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.85)