The Effect of Different Fracturing Fluids on the Productivity of Multi-Staged Fractured Marcellus Shale Horizontal Wells

While hydraulic fracturing has undeniably improved the production from oil and gas reservoirs, this technology is not without limitations. The primary hurdles lie in the areas of proppant transport, fluid rheology, and stress management. Despite the extensive research conducted in this domain, there remains a considerable amount of work to be done for comprehensive solutions that account for the complex interactions among fracturing fluid, proppant distribution, and geomechanical conditions. Achieving this will then make room for a holistic and efficient hydraulic fracturing strategy. This study addresses the above-mentioned problem by examining the impact of fluid type on proppant transport and distribution leading to productivity improvement for a multi-staged fractured Marcellus Shale horizontal well. In addition, stress shadow impact and the extent to which various fracture properties contribute to production are evaluated. The findings can be used to enhance fracture treatment design in the Marcellus shale through optimum fluid selection and stage spacing to reduce the impact of the stress shadow. Available core plug measurements, well logs, and image logs were analyzed to determine the shale petrophysical and geomechanical properties, including natural fracture (fissure) distribution, to develop a horizontal Marcellus Shale well model. Available laboratory measurements and published data were analyzed to determine the gas adsorption characteristics and the shale compressibility. The impact of the shale compressibility as a function of net stress was then incorporated into the model by developing multipliers for fissure and matrix permeability as well as the hydraulic fracture conductivity. The hydraulic fracture properties estimated using the GOHFER 3D software were incorporated into the developed reservoir model and ultimately, the impact of fluid type and stress shadow on proppant transport and the gas production were investigated. The reservoir model’s credibility was confirmed by a close match between the actual and predicted production. The fracture heights induced by all the fluids remained within the pay zone and the entire fracture height contributed to the production. High Viscosity Friction Reducer (HVFR) resulted in relatively larger fracture volume (with increased fracture height) in comparison to Slickwater, Crosslinked Gel, and Hybrid fluids thus resulting in improved productivity. The cross-linked gel also improved productivity but was found to be inferior to HVFR. High Percentage Reduction indicated the adverse impact of stress shadow on hydraulic fracture properties and gas production. The impact of the stress shadow on the production is, however, more pronounced during early production due to higher production rates.