Abstract
Liquid-rich shale (LRS) reservoirs, particularly lean and rich gas-condensates, are economically attractive but pose unique production challenges. These include productivity losses caused by condensate banking, saturation pressure changes due to pore confinement, and the associated rock-fluid interactions. In recent years, development of these types of reservoirs has advanced with optimal lateral well placement and innovative completion designs. It has been well recognized that initial production rates, their decline during depletion, and the ultimate liquid recoveries are severely impacted by the fluid, rock, rock-fluid properties, and the completions design. Thus, it is critical to have an in-depth understanding of the controlling factors related to fluids, rock and rock-fluid parameters that affect the long-term production performance of these reservoirs.
We have conducted detailed reservoir simulation studies based on a sector model to investigate the sensitivity of rock, fluid, and rock-fluid parameters, and modeling fracture properties on reservoir performance. The reservoir model consists of a horizontal well and a network of hydraulic, induced. and natural fractures embedded in the rock matrix. The model also includes the effects of changes in fluid saturation pressures due to pore confinement and altered fluid phase behavior in nano-pore environments, interfacial tension (IFT)-dependent gas-condensate relative permeability curves and end-points, and the matrix and fracture properties. Sensitivity runs allow comparisons of reservoir performance predictions of rates, condensate dropout and the resulting condensate blocking, and ultimate liquid recovery potential.
We developed a number of gas-condensate fluid models covering a range of Condensate to Gas Ratios (CGRs) (50 to 250 stb/MMscf) and implementing dewpoint suppression/elevation in nano-pore matrix and its impact on liquid dropout and condensate banking. In this article, we illustrate the results of the simulation study using a relatively rich condensate with a CGR ~100 stb/mmscf. We also used interfacial-tension dependent relative permeability curves and critical condensate saturations (Scc) for the matrix and for fractures. The compaction effects of matrix and the fractures during depletion were also accounted for.
We conducted a number of sensitivity runs, including elevation/suppression of fluid saturation pressures, IFT- dependent relative permeability, critical condensate saturations, and condensate blocking. Based on the results of this study, the following conclusions can be drawn:
Well rate and its decline with time (pressure) are highly sensitive to the fluid, rock, and the rock-fluid parameters, such as the dewpoint pressure, the relative permeability Corey exponents and ends point saturations.
Ultimate liquid recovery is impacted by the condensate dropout characteristics, IFT, and saturation pressure changes.
The liquid recovery is impacted by the leaning of produced fluids with pressure decline, mobilization of dropped-out condensates, and IFT effects on the relative permeability.
Condensate blocking severely affects gas rates and hence the well productivity.
The results served as a basis for and guided reservoir development strategies and production planning.
