Abstract

A steady-state pseudo-pressure method to determine well impairment in gas condensate reservoirs is presented. The method allows rapid and accurate description of the well inflow. Proper compositional simulation of this phenomenon requires a substantial amount of computing time to handle the small time steps required to compensate for the high degree of throughput in the small concentric grid blocks near the wellbore, in addition to the compositional description needed to characterise the reservoir fluid. The model has been used to evaluate effects of the various parameters, which impact on gas condensate well performance. The example calculations show that:

  1. The effect of non-Darcy is much more pronounced in gas condensate reservoirs than in dry gas reservoirs;

  2. The non-Darcy component of the flow equation is significant only in the area within 10 ft from the well;

  3. Velocity stripping of condensate may occur in the area within 5 ft from the well;

  4. The magnitude and hence, the impact of capillary number and non-Darcy flow on condensate and gas relative permeabilities change significantly over a relatively small distance (within 10 ft) from the well;

  5. Near-critical relative permeability and inertial resistance are strongly coupled and a simple supposition of the separate effects may significantly underestimate the well impairment. The results of this work may find application in the development of gas reservoirs and the interpretation of well tests, and may impact on completion design. They can be used, as well, for the calibration and verification of commercial reservoir simulators.

Introduction

The modelling and prediction of well impairment by condensate dropout in the vicinity of the wellbore is still an outstanding issue in gas reservoir engineering. Two major reservoir engineering problems have to be considered during field development studies:

  1. the possibility of a significant drop in gas productivity of the wells below the dew point pressure due to the presence of the condensate, and

  2. the loss of condensate formed throughout the reservoir at the end of exploitation.

(1,2) The answers to these problems depend not only on the phase behaviour of the gas condensate fluid but also on the two-phase flow characteristics in the porous medium near the wellbore. The flow in this region is complicated by near-critical relative permeability functions and by saturation-dependent inertial forces (non-Darcy flow). (3) This problem is made worse due to the fact that the throughput of the gas per unit rock volume progressively increases with decreasing distance from a wellbore with radial drainage. In time, a dynamic equilibrium must be established where the rate of condensation is equal to the rate of liquid phase condensate flow.

The degree to which the gas phase flow will be impaired is governed by the saturation of liquid condensate. The developed saturation is functionally related to the relative permeability characteristics of the reservoir rock, the PVT characteristics of the reservoir fluid and the degree of pressure draw down or, equivalently, the gas rate imposed on the system.

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