Capillary end effect develops in tight gas and shale formations near hydraulic fractures during flow back of the fracturing treatment water and extends into the natural gas production period. Previous studies showed the potential flow impairment mechanisms in tight gas and shale formations and discussed to a certain extent that they may influence a well’s performance during production. However, these studies did not consider the existence of capillary end effect. This paper presents the impact of the stress change on the micro-fractures permeability and how that compares to the capillary end effect. In addition, we study the interplay of capillarity in micro-fractures and osmosis in clay pores during the flow-back and production periods. The study considered simulation of a triple porosity formation representative of source rocks such as organic-rich shales.
The fully implicit integral finite difference method is used for modelling a multi-phase flow in shale reservoir. The reservoir model has a multi-scale pore structure with secondary pores consisting of micro-fractures and cracks, and small primary pores that belong to the inorganic particles, interlayer clays and kerogen. The primary pore pressure changes due to osmosis of the injected fresh water into the clays and the associated clay swelling, and due to natural gas release (desorption and diffusion) from kerogen. The model simulates water-gas flow in the secondary pore network with a capillary discontinuity at the hydraulic fracture-matrix interface in addition to changes in total stress due to changes in the primary pores pressure.
The simulation results show that the capillary end effect cause significant formation damage during the flow back and production periods by holding the water saturation near the fracture at a higher level than that based on spontaneous imbibition of water. The effect makes water less mobile in the formation during the flow-back, and tends to block gas flow. The stress-related effects of the primary pores are relatively less important. We showed that the capillary end effect cannot be removed completely but can be reduced significantly by controlling the wellbore flowing pressure and by altering the formation wettability.
A new multi-phase reservoir flow simulation model which including capillary end effect is developed to understand the capillary end effect on the removal of the water from the formation and gas production. The correct value of interstitial water saturation and end of gas relative permeability is predicted to correct the error in saturation, relative permeability, and capillary pressure calculation because of capillary end effect. This model can be used to optimize the hydraulic fracturing design during shale gas production.
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