بابک شعبانی

Formation of condensates around the wellbore in gas condensate reservoirs reduces the efficiency of well performance, and it can be intensified depending on the fluid type, reservoir and well properties. Adequate and appropriate information can be helpful for accurate modelling of gas condensate reservoirs. Disregarding the dependence of gas-oil relative permeability on capillary number and high the velocity flow (non-Darcy flow) may cause miscalculations and poor estimations in gas condensate reservoirs. In this paper, a sector model of South-Pars gas condensate field located in the Persian Gulf was simulated using ECLIPSE-300, and the effect of the capillary number and non-Darcy flow on cumulative condensate production and condensate formation near the wellbore and in the reservoir were investigated. Obtained results reveal that production increases as the bottom-hole pressure decreases and/or the production flow rate increases; however, more pressure drop and condensate blockage were occurred. Thus, bottom-hole pressure and the production flow rate should be optimized for efficient production. In addition, taking into account the effect of the capillary number on relative permeability decreases condensate formation near the wellbore and in the reservoir. Non-Darcy flow increases pressure drop, resulting in more condensate blockage near the wellbore. Ignoring the effect of the capillary number and non-Darcy flow in simulation process will strongly affect the accurate prediction of well performance in gas condensate reservoirs.

Relative permeability can be measured directly from cores, but due to problems such as unavailability of experimental results of direct relative permeability measurement, indirect techniques also have been used to calculate relative permeability. One of these methods is estimating relative permeability curves from capillary pressure data that the reliability of this method for approximation of liquid-gas relative permeability curves had thoroughly investigated. However, there is not enough information to conclude which method is the standard one for calculating oil-water relative permeability curves. Various capillary pressure techniques such as the Corey, Brooks-Corey, Li-Purcell and Li-Burdine methods were utilized to calculate oil-water relative permeabilities using the measured oil-water capillary pressure data in drainage process in an oil-wet Carbonate reservoir. Despite wide popularity of Purcell and Burdine methods for calculating relative permeability, new Li-Purcell and Li-Burdine methods were used. The calculated results were compared to the experimental data of oil-water relative permeabilities measured in a Carbonate reservoir. The Corey and Brooks-Corey models are shown an acceptable and nearly exact match with the measured oil relative permeability values. However, the Li-Purcell and Li-Burdine models underestimate the values for wetting phase in most cases. It is also worth mentioning that, except Li-Purcell method, the results of all other methods for calculating non-wetting phase relative permeability are almost the same and overestimate the values. Then, rock typing on the basis of pore throat radius at 35% mercury saturation were done and the accuracy of each model were examined for all rock types. Results of this work revealed that calculation of oil-water relative permeability using the capillary pressure data is also a reliable technique in oil-wet carbonate reservoirs.