Impact of Hydraulic Fracturing Fluid Damage on Shale Gas Well Production Performance

Abstract Much work has been done to accurately simulate shale gas production using horizontal well with hydraulic fractures. In general, these numerical studies have considered single-phase gas transport. However, following the fracturing, fluid-wall interactions can form a damaged zone nearby the fracture characterized by strong capillarity and osmosis effects. To understand the impact of fracturing fluid damage to well production performance, we present a new reservoir multi-phase flow model which includes these mechanisms of formation damage. In the simulation model, the shale matrix by the fracture is treated as a multi-scale porosity medium including interconnected organic, inorganic slit-shaped, and interlayer clay porosity fields. Prior to fracturing, the matrix holds the gas in the organic and the inorganic pore network, the water in the inorganic and the clay. Imbibition and osmosis mechanisms are included into an existing multi-scale advective-diffusive flow model to describe water-shale interactions following the fracturing. The reservoir flow simulator is fully implicit and based on the integral finite difference method. The simulation results show that, although fracturing is a rapid process, fluid-wall interactions continuing after fracturing could lead to important imbibition effect during the flowback and production, which allows water to penetrate into the inorganic pore network and displace the gas in-place near the fracture. Osmosis, on the other hand, takes part in the clay interlayer pores due to salt concentration difference between the fracturing fluid and the clay water, because clay in shale matrix acts as a semi-permeable membrane. This leads to pressure build-up in the clay interlayer pores. The pressure build-up, known as clay swelling pressure, exerts additional pressure into the shale matrix which can lead to significant permeability damage during the flowback and production. We measured the propagation speeds of the pressure waves associated with the capillarity and the osmosis. The new model is used to demonstrate the damage zone formation characteristics and its effect on the flowback dynamics. We also investigated effects of varying salinity contrast between the fracturing fluid and structural water, of varying clay content/type on the shale gas well production performance. Finally, the stress-dependence of the inorganic matrix permeability in the damaged zone is investigated. The new shale gas reservoir flow simulation model includes additional mechanisms that will allow the practicing engineer to gain insight into a particular case of production in the presence of water-shale interactions. The model can also be implemented into a simulation-based optimization process to design hydraulic-fracturing and flowback procedures for optimal gas production.