Integrated Well Interference Modeling Reveals Optimized Well Completion and Spacing in the Marcellus Shale

Abstract

Naturally fractured reservoirs such as the Marcellus shale require an integrated reservoir modeling approach to determine well spacing and well-to-well interference. The Marcellus Shale Energy and Environment Laboratory (MSEEL) is a joint project between universities, companies, and government to develop and test new completion technologies and acquire a robust understanding of the Marcellus shale. The study presented in this paper aims to reveal an approach to determine reservoir depletion with time through coupled geological modeling and geomechanical evaluation followed by completion and well performance history matching for a multiwell pad in the Marcellus shale. The geomechanical model was prepared with interpreted vertical log data. A discrete natural fracture (DFN) model was created and used to determine the complexity of hydraulic fracture geometry simulated through complex fracture models on a two well pad. The microseismic data obtained during the hydraulic fracture simulations served as a constraining parameter for the hydraulic fracture footprint in these wells. Sensitivity to the DFN is realized by parametric variations of DFN properties to achieve a calibrated fracture geometry. Reservoir simulation and history matching the well production data confirmed the subsurface production response to the hydraulic fractures. Well spacing sensitivity was done to reveal the optimum distance that the wells need to be spaced to maximize recovery and number of wells per section. Hydraulic fracture geometry was found to be a result of the calibration parameters, such as horizontal stress anisotropy, fracturing fluid leakoff, and the DFN. The availability of microseismic data and production history matching through integrated numerical simulation are therefore critical elements to bring unique representation of the subsurface reaction to the injected fracturing fluid. This approach can therefore be consistently applied to evaluate well spacing and interference in time for the subsequent wells completed in the Marcellus. With the current completion design and pumping treatments, the optimal well spacing of 990 ft was determined between the wells in this study. However, wells to be completed in the future needs to be modeled due to the heterogeneity in the reservoir properties to ensure that wells are not either underspaced to cause well production interference or overspaced to create upswept hydrocarbon reserves in the formation. By adopting the key learnings and approach followed in this paper, operators can maximize subsurface understanding and will be able to place their wellbore in a nongeometric pattern based on reservoir heterogeneity to optimize well spacing and improve recovery.

Scale‐Bridging in Three‐Dimensional Fracture Networks: Characterizing the Effects of Variable Fracture Apertures on Network‐Scale Flow Channelization

“…We incorporate these variable fracture apertures into a set of 3D DFNs whose parameters are loosely based on observed fractured zones in Marcellus shale (Gale et al, 2014;Kavousi et al, 2017;Pankaj et al, 2018;Wang & Carr, 2013) in alignment with the experiments described above, but the networks do not represent a particular site. Flow through such micro-fracture networks are important in shale formations, which occur at these length scales, and are believed to control hydrocarbon production in unconventional reservoirs and changes of permeability in damage zones around faults (Gomila et al, 2021;Hyman, Jiménez-Martínez, et al, 2016;Middleton et al, 2017;Mitchell & Faulkner, 2009;Romano et al, 2020).…”

Automatic History Matching of Parent-Child Wells in Shale Gas Reservoirs with Complex Fracture Hits

“…With the tremendous infill wells drilling in recent years, well interference or fracture hits became the top issue for unconventional reservoir development [2][3][4][5][6][7][8][9][10]. Specifically, the interference mechanism is a complicated issue in terms of matrix permeability and complex fracture network [2].…”