Analysis of Capillary Pressure and Relative Permeability Effects on the Productivity of Naturally Fractured Gas-Condensate Reservoirs Using Compositional Simulation

Open Access
Al Ghamdi, Bander Nasser
Graduate Program:
Petroleum and Natural Gas Engineering
Master of Science
Document Type:
Master Thesis
Date of Defense:
November 13, 2009
Committee Members:
  • Luis F Ayala H, Thesis Advisor
  • compositional simulaiton
  • capillary pressure
  • relative permeability
  • naturally fractured
  • gas-condensate reservoirs
The developments of gas-condensate reservoirs are highly dependent on the thermodynamic behavior of the fluids in place. During the depletion of gas-condensate reservoirs, the gas condenses as the pressure of the reservoir reduces below the hydrocarbon dew point pressure, which introduces a liquid phase called retrograde condensate. In such conditions, the productivity experience a reduction in recovery due to the appearance of condensate near the production channels, which in turn reduces the overall flow of hydrocarbons to the surface. The phase behavior of the fluids in place impacts the production scheme of gas-condensate reservoirs, since the recovery of condensate is highly dependent on the changes in composition. In this study, the productivity of naturally fractured gas-condensate reservoirs is addressed using a compositional simulation model to examine the effects of capillary pressure and relative permeability on the recovery of gas-condensate fluids. Capillary pressure is a function of saturation and it controls the distribution of fluids in the pore spaces of a reservoir. The role of capillary pressure in the distribution of fluids in the reservoir can become more relevant in naturally fractured reservoirs, where the transport of fluids between the matrix and the fractures depends on the capillary pressure. In addition, the deliverability of gas-condensate reservoirs in such conditions is controlled by the transport properties, which are the relative permeabilities between the fluids in a pore-scale. Therefore, this study is devoted to evaluate the growth of condensate coating by examining different compositions (light/heavy) with the activation of the capillary pressure forces, while keeping the depletion rate constant, and deactivating the diffusion effect in the system. A compositional simulation model was utilized for the evaluation of the influence of fluid characteristics on the severity of condensate coating while assigning tight matrix permeability of 0.001 md, 1 psi/day for depletion rate, and zero capillary pressures. The analysis of the condensate coating on the edges of the matrix blocks lead to the conclusion that the saturation pressure point is controlled by the concentration of heavy components. The sooner the saturation pressure is reached, the sooner condensate appears and hinders the overall recovery of fluids. Using the same conditions applied to the different composition concentration while activating the capillary pressure effect at different pore size distribution indexes (1.5 to 7); the fluid distribution, movement, and recovery, had a similar behavior indicating that the capillary pressure had insignificant influence on the reservoir fluids behavior. On the other hand, the effect of relative permeabilities showed dependency on the amount of condensate content in the reservoir. The more condensation that takes place, the more influence is applied by the relative permeability curves. The major variable that enhanced the oil-gas relative permeability curve was the fracture parameter (ë) obtained by van Genuchten’s (1980) to calculate the oil and gas relative permeabilities. Several values were used to address the fracture parameter to influence the position of the oil-gas relative permeability curve. As a result, it appeared that the influence depends on the amount of condensate content in the reservoir. The more condensation that takes place, the more influence is applied by the relative permeability curves.