Improved Recovery in Gas-Condensate Reservoirs Considering Compositional Variations

Abstract

The objective of this work was to develop a methodology to increase the productivity of gas/condensate from gas-condensate reservoirs. Presently, gas-condensate reservoirs experience reductions in productivity by as much as a factor of 10 due to the dropout of liquid close to the wellbore. The liquid dropout blocks the flow of gas to the well and lowers the overall energy output by a very substantial degree. The combination of condensate phase behavior and rock relative permeability results in a composition change of the reservoir fluid, as heavier components separate into the dropped-out liquid while the flowing gas phase becomes lighter in composition. This effect has been sparsely recognized in the literature, although there is clear evidence of it in field observations. This work quantified the effect, developed a scientific understanding of the phenomena, and used the results to investigate ways to enhance the productivity by controlling the liquid composition that drops out close to the well. By optimizing the producing pressure strategy, it should be possible to cause a lighter liquid to be condensed in the reservoir, after which the productivity loss would be more easily remedied.The research made use of experimental measurements of gas-condensate flow, as well as compositional numerical simulations. Different strategies have been compared, and the optimum producing sequences are suggested for maximum condensate recovery. Results show that composition varies significantly as a function of fluid phase behavior and producing sequence; condensate recovery can be improved with proper producing strategy, and productivity loss can be reduced by changing the producing sequence.This study can be used to determine the optimum producing strategy when the well is brought into production and reduce the productivity loss caused by the condensate banking effect.

Disjoining Pressure and Gas Condensate Coupling in Gas Condensate Reservoirs

“…7. This prediction is in agreement with experimental observations in very low IFT gas condensate flow [2], Gas relative permeability reduction after coupling usually ranges between 50% and 95% [22], Figure 1(a) indicates that gas relative permeability reduction after coupling has a strong dependence on disjoining pressure. However, even for large value of NSc= 10 4 the gas relative permeability decreases by 60% (krg ~ 0.40).…”

Reservoir Simulation Analysis of Pressure Depletion Performance in Gas-Condensate Reservoirs: Black-Oil and Compositional Approaches

“…Condensate blockage is one of the major problems that have been addressed in the industry [10,11,12,13]. As reservoir fluid pressure declines below the dew point pressure during the production process, the liquid drops out of the gas phase and forms condensate in the formation.…”

“…The impact of condensate blockage is very sensitive to the gas and oil relative permeabilities in the region around the wellbore. Several laboratory experiments [10,12,15] have demonstrated an increase in mobility for gas-condensate fluids at the high velocities typical of the near-well region, a mechanism that would reduce the negative impact of condensate blockage.…”

Performance Evaluation of CO2 Huff-n-Puff Gas Injection in Shale Gas Condensate Reservoirs

“…This step was used to simulate the primary depletion process, with the CT scanner measuring the condensate saturation in the core. Condensate saturation was calculated by using the following equation [42]:…”