Abstract
Water uptake induced by fluid–rock interaction plays a significant role in the recovery of flowback water during hydraulic fracturing. However, the existing accounts fail to fully acknowledge the significance of shale anisotropy on water uptake typically under in situ reservoir temperature. Thus we investigated the shale-hydration anisotropy using two sets of shale samples from the Longmaxi Formation in Sichuan Basin, China, which are designated to imbibe water parallel and perpendicular to shale bedding planes. All the samples were immersed in distilled water for one to five days at 80 °C or 120 °C. Furthermore, samples’ topographical and elemental variations before and after hydration were quantified using energy-dispersive spectroscopy–field-emission scanning electron microscopy. Our results show that shale anisotropy and imbibition time strongly affect the width of pre-existing micro-fracture in hydrated samples. For imbibition parallel to lamination, the width of pre-existing micro-fracture initially decreases and leads to crack-healing. Subsequently, the crack surfaces slightly collapse and the micro-fracture width is enlarged. In contrast, imbibition perpendicular to lamination does not generate new micro-fracture. Our results imply that during the flowback process of hydraulic fracturing fluid, the shale permeability parallel to bedding planes likely decreases first then increases, thereby promoting the water uptake.
Highlights
With an increasing demand for geo-energy, unconventional resources, such as shale gas, play a significant role in meeting demand, and are expected to continue to do so for the foreseeable future [1]
Fakcharoenphol et al [18] simulated the effect of osmotic pressure on water and oil flow into and out of the shale plugs with consideration of capillary pressure. Their results indicate that high osmotic pressure likely takes place in shales due to the considerable salinity difference between in situ brine and slick water, which would promote water imbibition and oil counter-current flow. All these mechanisms imply that spontaneous imbibition associated with fluid–shale interaction and capillary forces governs hydraulic fracturing fluids loss [9,13,15,16,19,20,21]
We investigated shale hydration anisotropy experimentally using two sets of shale samples extracted from the Longmaxi Formation in Sichuan Basin, China
Summary
With an increasing demand for geo-energy, unconventional resources, such as shale gas, play a significant role in meeting demand, and are expected to continue to do so for the foreseeable future [1]. Their results indicate that high osmotic pressure likely takes place in shales due to the considerable salinity difference between in situ brine and slick water, which would promote water imbibition and oil counter-current flow All these mechanisms imply that spontaneous imbibition associated with fluid–shale interaction and capillary forces governs hydraulic fracturing fluids loss [9,13,15,16,19,20,21]. They found that compared to the imbibition perpendicular to lamination, parallel imbibition to bedding planes can accelerate water uptake due to the shale layered structure. Few existing studies investigate the effect of shale anisotropy on water uptake with consideration of in situ reservoir temperature and pressure. To better characterize the samples’ topographical and elemental variations, energy-dispersive spectroscopy–field-emission scanning electron microscopy (EDS–FE-SEM) was used before and after hydration for quantitative analysis
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