Simulation of Multi-Component Gas Flow and Condensation in Marcellus Shale Reservoir

The Marcellus shale formation, with more than 463 trillion cubic feet (Tcf) of recoverable gas in Pennsylvania and West Virginia, will play a critical role in providing clean energy, environmental sustainability, and increased security for our nation. However, due to recent low gas prices, most of the operating companies have slowed down their activities in dry gas areas and refocused their attention in oil and condensate production from liquid-rich regions. This change in production plans requires detailed investigation of gas condensate bank developments and saturation dynamics in shale gas reservoirs that change greatly with reservoir conditions. An advanced level of understanding of the parameters affecting gas condensate phase behavior is necessary in order to make accurate predictions of these changes.

One of these parameters is the phase behavior of gas condensate in shale gas reservoirs that is significantly different than that of gas condensate as bulk in the PVT cell. It is highly affected by shale pore size distribution, gas adsorption, and water vapor saturation. Critical properties of gas condensate are also significantly influenced by shale pore size distribution, leading to changes in viscosity and formation volume calculations. In addition to that fluid composition, natural and hydraulic fractures, reservoir anisotropy, rock compressibility and number of horizontal wells and their operating conditions could also significantly impact the condensate bank development and dynamics. To quantify the importance of each one of these parameters and their interactions on dynamics of condensate bank development, an experimental design technique, Plackett-Burman design, will be practiced for two different cases (single well cylindrical model and actual Marcellus shale gas reservoir with heterogeneous porosity and permeability field). Detailed uncertainty analysis of different parameters has a significant impact on implementing the best production strategies such as bottom-hole pressures and hydraulic fracture spacing. Commercial simulators are unable to provide reliable predictions of condensate production rates and saturation dynamics due to lack of correct physics controlling production mechanisms in shale gas reservoirs.

In this study we will introduce a new equation of state, including the cohesive and adhesive forces due to fluid-fluid and fluid-solid interactions, and use that to develop a compositional model for gas condensate fluids in Marcellus shale gas reservoirs. A new correlation to adjust critical properties of gas condensate will also be developed based on shale pore size distribution to incorporate into the compositional simulator, CMG (GEM), to investigate the dynamics of gas condensation, and to perform sensitivity analysis on saturation profiles for different gas compositions of Marcellus from “super-rich” to liquid-rich areas.

Based on our study, critical properties and phase behavior of gas condensate are distinctively different under the influence of wall effects and adsorption in organic nanopores, and also have significant effect on production strategies and stimulation design for Marcellus shale gas reservoirs. This study takes a unique approach that can be applied to commercial simulators as a modification to currently applied models without requiring rewriting or development of a new generation of simulators.