Effect of shut-in time on gas flow rate in hydraulic fractured shale reservoirs

Abstract

a b s t r a c tSome 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 stimulation while the organic and inorganic 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.

A critical review of water uptake by shales

“…This hypothesis is supported by an increased oil/gas production rate after the shut-in period, which could have been pushed out by the imbibition of water into the matrix. However, it should be noted that this mechanism would be possible only if the shale matrix has higher affinity for aqueous fluid over hydrocarbon, or in other words the shale matrix is water-wet or mixed-wet rock (Fakcharoenphol et al 2016). Haluszczak et al (2013) analyzed the salinity of the produced water from gas wells in the Marcellus formation and observed that the salinity (concentration of sodium, calcium, and chloride dissolved in water) of produced water increases significantly with time.…”

“…The pressure gradient developed due to the difference in solute concentration can create high pressure anomalies in the geologic formations (Marine and Fritz 1981;Neuzil 2000;Neuzil and Provost 2009). For instance, a fracturing fluid with 1000 ppm of salinity when injected into a shale reservoir containing 150,000 ppm of brine can develop an osmotic pressure as high as 2000 psi (Fakcharoenphol et al 2016). Neuzil and Provost (2009) analyzed data from different clay-rich shale formations and reported that osmotic pressure in some formations with ~0.1 porosities may exceed 30 MPa whereas for formations with ~0.2 porosities the osmotic pressure may exceed 10 MPa.…”

The Effect of Temperature on Flowback Data Analysis in Shale Gas Reservoirs: A Simulation-Based Study

“…Figure 2. Schematics illustrating the model for numerical simulation: (a) the section of reservoir volume between two fracturing stages was selected for this study (modified from [24]); (b) the grid system with dimensions; and (c) the section view of fracture surface wall (in pink). Table 1 lists the key reservoir and fracture parameters for the base model.…”

“…An extended shut-in period of six months has been reported in a gas well completed in Marcellus shale [13]. Recently, several studies [14,[20][21][22][23][24] investigated the effect of shut-in days on the production performance of shale gas wells . Numerical simulations were conducted to investigate the environmental aspects of shut-in on the fate of fracturing water [25][26][27][28].…”

Coupled Thermo-Hydro-Mechanical-Chemical Modeling of Water Leak-Off Process during Hydraulic Fracturing in Shale Gas Reservoirs

“…Chemical osmosis occurs in the leak-off process of hydraulic fracturing (because two conditions are satisfied for the occurrence of chemical osmosis, i.e., clay semipermeable membrane and salinity difference on both sides of the membrane), which results in the transport of water molecules from the low-salinity side to the high-salinity side until the salt concentration reaches an equilibrium on both sides of the shale membrane [26][27][28][29]. That makes chemical osmosis a possible leak-off mechanism for the invasion of water-based fracturing-fluids in fractured shale [30][31][32]. Besides the salinity difference between the fracturing-fluids and shale formation brine, a temperature gradient across the shale-fluid interface exists during the hydraulic fracturing.…”