The activation of natural fractures may play a key role in creating complex fracture network during the hydraulic fracturing treatment. The fluid pressure on main hydraulic fracture surface can increase mean confining stress of rock around the main fracture. Natural fracture tends to stabilize when confining stress increasing. Fracturing fluid leaks from main hydraulic fracture into natural fracture causing the elevation of pore pressure in natural fracture. Shear slip may occur when pore pressure of natural fracture elevated. If the fluid pressure within the main fracture suddenly decreases, the mean confining stress of the rock around main fracture decreases quickly, while the pore fluid pressure in the natural fracture do not decrease simultaneously due to the relatively low permeability, which causes the Mohr's stress circle move to the left and natural fractures shear failure easier. In this paper, we present a cyclic treatment to enhance the degree of natural fracture activation. A numerical model is established to investigate the effect of cyclic pressure drop on natural fracture activation. The results show that cyclic treatment can significantly improve the length and permeability of activated natural fracture.


Recent years, multiple-hydraulic-fracturing has been a commonly technology for stimulating tightsand gas and shale gas formations in order to produce commercial quantities of natural gas (Cipolla et al., 2008, Cleveland and Cote, 2014, Daneshy, 2011). Economic production from these reservoirs depends greatly on the effectiveness of hydraulic fracturing stimulation treatment (Dahi Taleghani and Olson, 2014). The classical conceptual model of hydraulic fracturing is that injection forms a symmetrical, bi-wings and planar hydraulic fractures. However, micro-seismic measurements and other in-situ observation suggest that fracturing can creates a complex fracture network in most unconventional reservoirs (Cipolla et al., 2008, Warpinski et al., 2012). This complex fracture networks increases the total contact surface area and plays a key role in the success development of unconventional reservoirs. The created of complex fracture networks strongly influenced by the pre-existing natural fractures (or weak planes) and in-situ stress in the reservoir (McClure and Horne, 2014, Sharma and Manchanda, 2015, Weng et al., 2015).

Core analysis has revealed the presence of abundant natural fractures in different kinds of rocks at different scales (Gale et al., 2014, Olson et al., 2009). As our experience with fracturing large number of well in unconventional formation has grown, it is becoming apparent that one of the most challenges in horizontal-well stimulation is activating natural fractures as many as possible. The matrix permeability is too low to contribute to flow significantly. Flow rates in ultra-low permeability reservoirs mainly depend on the total area of permeable fractures that are hydraulically connected to the well. Much, but not all, activated natural fractures are conducive to the production of the well. These permeable fractures include the main hydraulic fractures and the activated natural fractures which hydraulically connected to the well. Thus, the number of the activated natural fracture is the key to success in tight-sand and shale gas reservoirs stimulation.

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