Simulation of Multicomponent Gas Flow and Condensation in Marcellus Shale Reservoir

Abstract

AbstractThe 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 depending on reservoir rock and fluid properties and also operating 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.Phase behavior and critical properties of gas condensate in shale gas reservoirs is significantly different than that of gas condensate as bulk in the PVT cell. It is highly affected by shale pore size distribution leading to changes in gas compressibility, viscosity, formation volume and original gas in place calculations. In addition to pore size effect, 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 developments and saturation dynamics. To quantify the importance of these parameters experimental design model, i.e., Plackett-Burman, implemented following a systematic approach for two different cases (single well cylindrical model and actual Marcellus shale gas reservoir). Detailed uncertainty analysis of different parameters using Marcellus shale gas reservoir model show the significance of reservoir fluid composition, matrix anisotropy, rock compressibility and hydraulic fracture spacing on condensate bank developments where the pore size confinement effects has been ignored. They also show that gas condensation is not only a near wellbore phenomenon but it can happen deep into the reservoir causing severe formation damage. However, considering the nano-pore size characteristics of Marcellus shale gas reservoir by assuming average 2 nm pore size distribution the modified critical properties and fluid behavior, results in significant reduction in condensate saturations around the wellbore and inside the reservoir. This significantly alleviates the formation damage that has been seen in the absence of nano-pore wall confinement effects. Based on our study, critical properties and phase behavior of reservoir fluid under pore wall confinements have the most significant impact on production strategies and stimulation design for Marcellus shale gas reservoirs.