Simulation of flow behaviour through fractured unconventional gas reservoirs considering the formation damage caused by water-based fracturing fluids

Highlights

• The flow behaviour of gas with non-linear properties in siltstone has been simulated using Discrete Fracture Model (DFM).

• A field-scale model is built to investigate the effect of fracture aperture variation on shale gas production.

• The effect of formation damage caused by water flooding on shale gas production has been studied.

Abstract

Hydraulic fracturing is essential for commercial-scale gas production from many unconventional gas reservoirs. While the effectiveness of the fractures created is associated with the stress created during the fracturing process, the use of water in the hydraulic fracturing process has been found to significantly reduce fracturing efficiency. In particular, the formation damage caused by water imbibition may have a significant negative impact on the flow capacity through both created fractures and rock matrix. These effects can be minimised by using non-water based fracking fluid such as CO₂. The intention of this study is to investigate the formation damage caused by water invasion and multi-cycle confinement on the gas production of fractured reservoirs. A laboratory-scale discrete fracture model (DFM) was developed based on the experimental results of a series of permeability tests conducted on intact and fractured siltstone samples under steady-state conditions at room temperature using gaseous CO₂ and water as the injection fluids. The developed model shows the ability to simulate the flow behaviour of fractured samples. Based on the laboratory-scale model, an expanded DFM model of an assumed fractured reservoir with a horizontal well was then built to quantitatively investigate the influences of multi-cycle confinement and water invasion damage on gas production from gas reservoir.

Based on the results of the expanded scale simulation, when the effect of water invasion damage on matrix permeability is not considered and only the change of fracture aperture is considered, the ratio of the rate of gas production from fractured formation without any formation damage, fractured formation suffering from the effect of multi-cycle confinement, fractured formation suffering from the combination effect of multi-cycle confinement and water invasion damage, and unfractured formation is around 15.15, 5.14, 2.23, 1 respectively, and the corresponding ratio of total gas production is around 17.62, 4.86, 2.13, 1 respectively, over a 10-year period. If the effects of water invasion damage on matrix permeability and fracture permeability are considered at the same time, the ratio of the rate of gas production rate from fractured formation without any damage on matrix permeability in the damage zone, fractured formation with 30% of initial permeability in the damage zone, fractured formation with 3% of initial permeability in the damage zone, and unfractured formation is around 2.23, 1.69, 0.94, 1 respectively, and the ratio of total gas production is 2.13, 1.54, 0.92, 1 respectively. This indicates that formation damage caused by multi-cycle confinement and fracturing water invasion can greatly impair gas production from unconventional gas reservoirs.

Introduction

Although unconventional gas reservoirs present a great opportunity to overcome the world energy crisis, the ultra-low permeability of these reservoirs is a challenge for commercial gas production from them (Conti et al., 2014). For example, the matrix permeability of a tight gas reservoir is usually less than 0.01mD, and the value can be several orders of magnitude less for shale gas reservoirs (Heller et al., 2014; Ghanizadeh et al., 2015; Bhandari et al., 2015). The ultra-low permeability of unconventional reservoirs greatly obstructs gas transport through the rock matrix to the production well (Lin et al., 2017), which indicates the importance of productivity enhancement techniques. Unconventional gas reservoirs are a kind of dual porosity system, most natural gas is stored in matrix pores and flowed by fractures, and natural gas production greatly depends on the fracture flow capacity and fracture density. Hydraulic fracturing has recently been used to create more fractures to enhance formation permeability by increasing the connections between matrix pores and production well (Daigle and Screaton, 2015; Kumar et al., 2015; Ma et al., 2016; Sun et al., 2016; He et al., 2017). During the fracturing process, the fractures can be kept open by injecting proppants with the fracturing fluid. However, conventionally-used fracturing fluids with low viscosity have very poor proppant-carrying capacity, sometimes resulting in no proppants in some fractures located far from the horizontal well (Warpinski, 2009). However, the shear displacement of fracture walls and the loose particles or debris created during the fracturing process can keep the fractures open, significantly increasing fracture flow capacity (Fredd et al., 2001). The flow capacity of the fracture system without proppants is therefore critical for gas production. However, the fracture system created is quite unstable and sensitive to many factors, especially to formation damage caused by stress and water-softening effects, and the variation of fracture flow capacity can directly determine the success or failure of hydraulic fracturing (Xu et al., 2016b; Zhang et al., 2015a, 2017b).

During the hydraulic fracturing process, a pressurized fluid, generally a water-based fracking fluid, is injected into the gas reservoir to fracture the rock matrix, which may result in a great change in the in-situ stresses and thus potentially creates seismic activities (Skoumal et al., 2015; Yang et al., 2015). Further, the redistribution of surrounding rock stress during gas production also increases the stress instability of the created fractures (Davies et al., 2013; Skoumal et al., 2015). This unstable stress development, which can be much higher than previous stable stress, may crush the contact areas between fracture surfaces and such irreversible deformations result in the reduction of fracture apertures. According to Zhang et al. (2017b), the effect of unstable stress on the fracture apertures was investigated by applying multi-cycle confining pressure varying between 10 MPa and 40 MPa, and the fracture aperture at 10 MPa was decreased by 60% after suffering from 40 MPa confining pressure, leading to a great reduction in fracture flow capacity. The fracture flow capacity during gas production life cycle is therefore greatly dependent on the residual fracture aperture suffered from higher stress in stress-sensitive fractured reservoirs.

The presence of water can induce serious formation damages during well drilling, completion, hydraulic fracturing and production, including physical and chemical damages (Bahrami et al., 2012; Xu et al., 2016a, 2017). In the fractured formation with dual porosity system, the fracture permeability and matrix permeability can be significantly decreased by formation damage caused by the complex physico-mechanical reaction between rock matrix and residual fracturing water (Bahrami et al., 2012; Xu et al., 2016a, 2016b, 2017; Lin et al., 2017). Studies have shown that water saturation can greatly reduce rock strength through the softening effect (Wong, 1998; Das et al., 2014; Zhang et al., 2017c), especially in clay-abundant shale formations, because the swelling of clay minerals induced by clay-water interaction can reduce the bonding between mineral particles and even create micro-fractures (Erguler and Ulusay, 2009; Zhang et al., 2017a). The softening effect decreases the brittleness of fracture surfaces, and the stress concentration between fracture surfaces or between the proppant and surfaces can crush the contact points (Pagels et al., 2013). This process can greatly decrease the fracture apertures and broken fine particles can also occupy the free space for gas flow. For example, according to Zhang et al. (2015a and 2015b), the decreased conductivity of propped fractures due to water invasion damage can cause around 90% reduction of gas flow rate. Moreover, the residual fracturing water can also significantly reduce matrix permeability through the water blocking and phase trapping damage. Studies have shown that the recovery of fracturing water is as low as around 10%–30% during flow-back and most residual water leaks into the rock matrix (Bostrom et al., 2014). This water retention basically happens due to the high capillary pressure and the low relative permeability (Holditch, 1979). With the increase of water content in the water sensitive formations, the damage on matrix permeability can hinder gas flow from matrix pores to fractures through water blockage and phase trapping damage in the tiny pores. Swelling of clay minerals can further reduce the pore porosity and close the pore throat, which greatly aggravate the damage on matrix permeability (Zhang et al., 2017a). The fluid invasion damage of water blocking and phase trapping is not only present in tiny pores, and even in narrow fractures it cannot be ignored (Reitsma and Kueper, 1994).

However, there is little published research focusing on the combined effect of water invasion damage and multi-cycle stress on the gas flow capacity of fractured formation without proppants, and the effects on gas productivity from unconventional gas reservoirs are therefore unclear. Although many simulation studies have been conducted using DFM, which is solved using the finite element analysis software COMSOL Multiphysics, to investigate the effect of fractures on gas production (Mi et al., 2014, 2016; Liang et al., 2016a, 2016b), most have adopted water as a flow fluid with nearly constant density under different pore pressures. This is not applicable for most gases due to their pressure-dependent density. Moreover, most current models are 2-D, which is also inconsistent with the reality that the gas produced in horizontal wells is collected from the whole 3-D gas reservoir volume instead of from a 2-D area (Sun and Schechter, 2014). This kind of limitation of current models has caused many inaccuracies in evaluating the efficiency of fracture systems.

The aim of the study was therefore to investigate the effect of formation damage on gas production from a fractured reservoir by conducting a simulation study. Based on the experimental data in Zhang et al. (2016 and 2017b), who investigated flow behaviour through intact and fractured siltstone samples considering the effects of multi-cycle confining pressure and water invasion damage on the fracture flow capacity of gas, a laboratory-scale 3-D model of cylinder sample was first developed using DFM and then expanded to a greater scale model of a fractured gas reservoir with a horizontal well.