Managing Shut-in Time to Enhance Gas Flow Rate in Hydraulic Fractured Shale Reservoirs: a Simulation Study

Some shale gas and oil wells undergo month-long shut-in times after multi-stage hydraulic fracturing well stimulation. Field data indicate that in some wells, such shut-in episodes surprisingly increase the gas and oil flow rate. In this paper, we report a numerical simulation study that supports such observations and provides a potentially viable underlying imbibition and drainage mechanism. In the simulation, the shale reservoir is represented by a triple-porosity fracture-matrix model, where the fracture forms a continuum of interconnected network created during the well simulation while the organic and non-organic matrices are embedded in the fracture continuum. The effect of matrix wettability, capillary pressure, relative permeability, and osmotic pressure, that is, chemical potential characteristics are included in the model. The simulation results indicate that the early lower flow rates are the result of obstructed fracture network due to high water saturation. This means that the injected fracturing fluid fills such fractures and blocks early gas or oil flow. Allowing time for the gravity drainage and imbibition of injected fluid in the fracture-matrix network is the key to improving the hydrocarbon flow rate during the shut-in period. Introduction Some shale gas and oil wells undergo month-long shut-in times after multi-stage hydraulic fracture stimulation. Field data indicate that in some wells, such shut-in episodes surprisingly increase the gas and oil flow rate. For example, Fig. 1 shows the effect of an extended shut-in on production of a multi-stage hydraulically fractured well in Marcellus shale (Cheng, 2012). The well was flowed back, after hydraulic fracture stimulation, for a short period before it underwent a six-month shut-in period. When the well was reopened after six months of shut in, gas production rate increased and water production rate decreased significantly. The question is what caused this apparent anomaly? Water load recovery and flowback behavior Field experience indicates that water load recovery could be as low as 5% of the total injection volume in Haynesville shale to as high as 50% of that in Barnett and Marcellus shales (King, 2012). Number of mechanisms could contribute to the lowrecovery, including extra-trapped water due to changing in natural fractures width that increasing during injection and decreasing during production periods (Economides et al., 2012), water imbibition into shale matrix by capillary pressure (Cheng, 2012). Flow back water analyzed by Haluszczak et al. (2013) indicates that formation brine in shale basin could be higher than 150,000 ppm, Fig. 2b. As the typical fracturing fluid comprises low-salinity water, in many cases it is in the range of 1,000 ppm, significant salinity contrast would be expected. This major salinity difference could lead to substantial chemical potential differences creating large osmotic pressure and driving filtrate from natural fractures into shale matrix block.