Fracturing Fluid Distribution in Shale Gas Reservoirs Due to Fracture Closure, Proppant Distribution and Gravity Segregation

Abstract

Many stimulated shale gas wells experience surprisingly low fracturing fluid recoveries. Fracture closure, gravity segregation, fracture tortuosity, proppant distribution, and shut-in (soaking) time have been widely postulated to be the contributing factors. This study examines the impacts of these factors on fracturing fluid distribution using flow and geomechanical simulations. The results are analyzed to understand the circumstances under which fluid recovery might be beneficial or detrimental to well performance. A series of 3D numerical models are constructed based on petrophysical parameters, fluid properties and operational constraints representative of Horn River shale gas reservoir. Hydraulic fracture is modeled explicitly in the computational domain. Complex partially-propped fracture geometry is computed using numerical constitutive models. The physical process of fracture closure during shut-in and production periods is modeled by adjusting the fracture volume and fracture conductivity dynamically. Non-Darcy behavior due to high gas velocity in fracture and matrix desorption are considered. The coupled effect of multi-phase flow, gravity and geomechanics is simulated to examine the mechanisms responsible for the low fracturing fluid recovery and the ensuing fluid distribution away from the wellbore. Water uptake into the matrix is influenced by forced and spontaneous imbibition due to the large pressure differential across the matrix-fracture interface and matrix capillarity. Additional water is displaced into the matrix as pressure depletes and fracture closes. Gravity segregation may lead to water accumulating near the bottom of a vertical planar fracture, but fracture tortuosity could limit the segregation and promote a more uniform fluid distribution. The influence of proppant distribution is far more complex: results of the geomechanical simulation confirm the formation of a residual opening above of the proppant pack in a partially-propped fracture. Despite gas production is often hampered by non-uniform proppant distribution, the residual opening offers a highly conductive flow path for gas, which is much more mobile than the water-based fracturing fluid; this further aggravates the phenomenon of gravity segregation. Extended shut-in time may enhance the initial gas rate, but lower late-time production is observed. Analysis of the residual opening of a partially-propped fracture and its implications on production performance is novel. The results highlight the interactions between different mechanisms on fracturing fluid distribution in 3D. A few practical insights pertinent to the optimal operation strategy are explained.

Water Saturation Relations and Their Diffusion‐Limited Equilibration in Gas Shale: Implications for Gas Flow in Unconventional Reservoirs

“…Indeed, large fracture apertures (> 10 −4 m) supported with proppant (Liang et al, ) and bounded by very low permeability (< 10 −20 m 2 ) matrix surfaces possess a wide range of near‐zero P c where unsaturated drainage of water is efficient (Tokunaga & Wan, ). More recently, gravity drainage has been incorporated in conceptual models for unconventional gas reservoirs (Taylor et al, ), and is rapidly gaining recognition (Agrawal & Sharma, ; Liu et al, ; Parmar et al, ; Sarkar et al, ). Importantly, time scales for gravity drainage of water from larger fractures are short, thus limiting the volume of water imbibition in regions above horizontal wells to that of the shut‐in period.…”

A Novel model for simulating the integration process of hydraulic fracturing, shut-in period, and well production

“…Current researches show that capillary pressure guides fracturing fluid invade into the matrix during shut-in period, which changes the distributions of pore pressure and water saturation in the matrix (Ghanbari and Dehghanpour, 2016;Shen et al, 2016;Liu et al, 2017;Liang et al, 2021;Liu et al, 2021) and may enhance the viscosity of shale (Peng et al, 2020a). The pressure gradient caused by hydraulic fracturing also guides the fluid flow between fractures and matrix during shut-in period (Zhao et al, 2019;Wang et al, 2020b).…”

Potential for Prediction of Water Saturation Distribution in Reservoirs Utilizing Machine Learning Methods

“…Reservoir simulation plays a dominant role in formulating the reservoir development plan and improving oil recovery at the current stage [10]. In this background, many researchers studied water saturation distribution utilizing numerical simulation for different type of problem, such as water imbibition [11][12][13], performance of EOR (enhance oil recovery) methods [14,15], unconventional reservoir exploitation [16,17], etc. However, it will take a long time for history matching and forecast calculation, and the prediction cost is relatively higher.…”