As the reservoir deplete, the pore pressure decreases and the effective stress increases. The increase in the effective stress results in the formation compaction which can alter the formation and hydraulic fracture properties. This is particularly significant for a Marcellus shale horizontal well with multi-stage hydraulic fracture due to low Young's modulus and moderate Poisson's ratio of the Marcellus shale. The degree of effective stress increase depends on the initial productivity of the well, which is influenced by the hydraulic fracture properties, stage spacing, as well as the operating conditions. It is therefore necessary to couple the geomechanical and fluid flow simulations to accurately predict the gas production from a horizontal Marcellus Shale well with multi-stage fractures. The objective of this study was to investigate the impact of the formation mechanical properties (Young's modulus and Poisson's ratio), the hydraulic fracture properties (length, initial conductivity, spacing), as well as operating conditions (wellbore pressure) on the productivity of a horizontal Marcellus Shale well with multi-stage fractures.

The advanced technical information available from the Marcellus Shale horizontal wells located at the Marcellus Shale Energy and Environment Laboratory (MSEEL) site provided an opportunity to investigate the impact of the shale compressibility on gas production. The core, well log, well test, completion, stimulation, and production data from the wells at MSEEL site were utilized to estimate the shale mechanical and petrophysical properties as well as the hydraulic fracture characteristics. The results of the data analysis were then utilized to develop a reservoir model for a horizontal well completed in Marcellus Shale with multi-stage hydraulic fractures. A geomechanical (Mohr-Coulomb) module was coupled with reservoir model to determine the effective stress distribution and the formation compaction and its impact on the shale porosity. The impact of the shale compaction on the permeability (for both matrix and fissure) and the conductivity of the hydraulic fractures were determine from the Marcellus shale core plug analysis as well as the published measurements on the propped fracture conductivity in Marcellus shale and were incorporated in the reservoir model.

The inclusion of the compressibility impacts in the reservoir model provided a more realistic simulated production profile. The gas recovery was found to be negatively impacted by the formation compaction due to the increase in the effective stress. The reduction in the conductivity of the hydraulic fractures due to the compressibility impact was found to have the most adverse effect on the gas recovery. The compressibility impacts were found to be more severe during the early production due to higher production rates. Finally, the model was employed to investigate the impact of the formation mechanical properties, hydraulic fracture properties, and the operating conditions on the gas recovery. The higher values of the Young's modulus and Poisson's ratio can mitigate the compressibility impacts and lead to higher recovery. Conversely, the higher values of the fracture half-length as well as the closer fracture spacing will amplify the adverse impacts of the compressibility on the early gas recovery. However, the adverse impacts diminishes with time. The higher values of the initial hydraulic fracture conductivity can also mitigate the compressibility impacts.

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