Experimental Investigation on the Effects of Flow Resistance on the Fracturing Fluids Imbibition into Gas Shale

Abstract

Less than half of the injected fracturing fluid in gas shale is often recovered and in many cases the flowback efficiency is <20%, which relates to potential productivity hindrance. Some have suggested that the water migration in the neighborhood of fractures induced by spontaneous imbibition contributes to auto-removal mechanism of water damage. However, water imbibition into fractured shale reservoirs is a physic-chemical and multiscale flow process, which is significantly different from conventional reservoirs. Therefore, we systematically characterize the samples by measuring the porosity, permeability, wetting angle and mineral composition. Comparative imbibition experiments are performed on 18 binary core plugs from typical formations of China's basin (i.e., Ordos Basin, Songliao Basin and Sichuan Basin). The preliminary result shows that Handy imbibition model has an evident deviation in predicting the shale imbibition experiment result, which is significantly overestimated. This disagreement can be explained by strong fluid-wall interactions in micron-nano pores. In addition to the widely believed capillary driving forces and viscous forces, the overall resistance of fluid-wall interactions have an important impact on water migration, which could reduce the imbibition rate in gas shale. A critical aperture Dc of about 36~100nm exits, which can be used to address the effects of fluid-wall interactions. The matrix blocks with average pore size of > Dc tend to produce minor resistance effects of fluid-wall interaction on imbibition rate. Handy model can provide a good match with experimental imbibition in micro-fractures or macropores; in the contrary, the matrix blocks with average pore size of <Dc tend to exert significant resistance effects of fluid-wall interaction on imbibition rate. Handy model reproduce the global trend of variation, which has been inadequate. The results of our study are more valuable for the comprehension of auto-removal water damage process and optimization of flowback time after fracturing operations in gas shale.

Pore- and Core-Scale Mechanisms Controlling Supercritical Cyclic Gas Utilization for Enhanced Recovery under Immiscible and Miscible Conditions in the Three Forks Formation

“…Increasing the soaking time enhances the interaction between CO 2 and oil phases in the matrix–fracture system and assists the diffusion mechanism process. As a result, the diffusion of CO 2 into oil increases, affecting CO 2 solubility, oil swelling factor, interfacial tension and capillary pressure reduction, oil transport from the matrix to fractures, and extraction of hydrocarbons. − In contrast, under miscible conditions, the phase of CO 2 is favorable, and the soaking time has a negligible influence on RF in both formations. As opposed to the diffusion mechanisms under immiscible conditions, the mass transfer process operates much more speedily with high injection pressure.…”

Zero Flowback Rate of Hydraulic Fracturing Fluid in Shale Gas Reservoirs: Concept, Feasibility, and Significance

“…Figure b shows the optimum state of a shale gas reservoir that most of the HFF flows back to the ground after flowback operation, recovering the permeability of both the fracture and the shale matrix. However, the seepage channels (fractures and beddings) cannot be cleaned up thoroughly as shown in Figure b because of the low flowback rate of HFF in shale gas reservoirs. − Figure c shows the shale reservoir conditions treated with the ZFR strategy. To increase the imbibition volume, the formulation of HFF can be adjusted to be acidic, alkaline, or oxidative as discussed in the Imbibition Potentials of Shale Gas Formation section. − , As we know, gas shales contain a large amount of chemically unstable compositions (e.g., clay minerals, carbonate, pyrite, and organic matter (OM)) which are sensitive to the adjusted HFF .…”

“…In short, the existing methods for increasing the flowback rate of HFF are either ineffective or costly. Commonly, only 10–20% of the injected fluid is recovered during production for shale gas reservoirs. − …”

A pore-scale study on the dynamics of spontaneous imbibition for heterogeneous sandstone gas reservoirs

“…Therefore, it is important to clarify the water distribution and spontaneous imbibition mechanism in lowpermeability sandstone gas reservoirs. Numerous studies have been performed to investigate the spontaneous imbibition in the gas-water system from different perspectives, including the boundary conditions (Yang et al, 2016), permeability differences (Meng et al, 2015), initial water saturations (Li and Horne, 2001), and water block damages (Zhou et al, 2016;Zhang et al, 2019). Additionally, computed tomography (CT) scans, nuclear magnetic resonance (NMR) scans, and microfluidic models are selected as new methods to monitor the spontaneous imbibition (Bao et al, 2017;Liang et al, 2017;Liu et al, 2017;Shen et al, 2017;Liang et al, 2018;Yuan S. et al, 2019;Liang et al, 2020).…”