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Hydraulic fracturing of shale reservoirs is one of the important technologies in the oil and gas industry. To ensure the safe operation of oil and gas recovery, it is important to study the shale-fluid interactions on the geomechanical behavior of shale. This study investigated the effect of fracturing fluid treatment on the mechanical and elastic properties of the Mowry Shale formation, Wyoming, USA. Cylindrical Mowry Shale specimens with a diameter of 12.5 mm collected from the United States Geological Survey (USGS) and School of Energy Resources (SER) of the University of Wyoming were treated with brine and brine + stimulation fluid for one month each at pressures of 9 and 11.7 MPa and temperatures of 96 and 66 °C, respectively. Triaxial compression experiments were conducted on the specimens. Results showed that all Mowry Shale specimens experienced an increase in maximum volumetric strain with the increase in effective confining pressure (Pd). Regardless of aging fluids, the maximum deviatoric stress (Δσd) of most Mowry Shale specimens increases with the increase in Pd. At a lower Pd, the USGS specimen aged with brine and stimulation fluid exhibits higher maximum Δσd than those aged with brine only. However, at a higher Pd, the USGS specimen aged with brine exhibits a higher maximum Δσd. SER specimens aged with brine and stimulation fluid exhibit higher maximum Δσd values than those aged with brine for all three Pd values. Regardless of the aging fluids, most USGS specimens experience a brittle failure mode, while SER specimens aged with brine and stimulation fluid experienced a more ductile behavior. [ABSTRACT FROM AUTHOR]

Horizontal drilling and multistage hydraulic fracturing applied in shale formations over the past decade. The operators are trying even closer cluster spacing to increase the initial rate, but it is at the expense of higher operation costs and complexity. This study presents an integrated workflow to investigate the effect of cluster interference on well performance. Analytical rate transient analysis (RTA) was combined with reservoir numerical simulation to calculate the effective fracture surface area (ACe) for hydrocarbon production. A proxy model was built to estimate the effective to actual stimulated fracture area ratio as a function of completion and reservoir parameters. The integrated workflow was applied to actual field data for two shale gas wells. An economic study was conducted to investigate the optimum spacing based on the well profitability. The well with a higher stage number and tighter cluster spacing had high cluster interference with a low ACe/ACa ratio. The well will drain the production area near the wellbore faster with a high initial production rate but with high production declining rate. Increasing the cluster spacing, with the same injected proppant volume, showed an increase in the ACe/ACa ratio, and a decrease in cluster interference. A lower initial rate was observed with a low production declining rate. Economic study showed optimum spacing of 60 ft based on the formation properties, capital cost, and gas price. As the interest rate, gas prices, and increases or low capital costs, the optimum completion tends to be with the tighter spacing to accelerate the production. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing is often used in unconventional shale reservoirs, and 50%–95% of the injected hydraulic fracturing fluid remains in the formation due to the capillary effect. This phenomenon has been observed in the Montney shale formation, Canada, where the flowback water recovery is generally less than 25%. Surfactant is one of the hydraulic fracturing fluid additives for reducing surface tension and capillary forces to facilitate water flowback recovery. Surfactant loss due to adsorption by the reservoir rocks reduces the chemical's efficiency, and this causes water retention in the formation and reduces water flowback recovery. The compatibility of surfactant with reservoir rock is critical to minimize surfactant adsorption on the rock surface because this diminishes the primary function of the surfactant hydraulic fracturing fluid additive and to ensure cost-effectiveness. This study evaluates surfactant efficiency to improve flowback recovery for the Montney shale formation based on IFT, surface tension, and adsorption. This study evaluates surfactant performance and performs a fluid–fluid interaction experiment and fluid-rock compatibility investigation. Several commercial surfactants are screened for low interfacial tension and surface tension. Further analysis is carried out by evaluating the fluid-rock compatibility using the static soaking test at reservoir pressure and temperature. The pre-soaking and post-soaking test fluids were analyzed for water composition, liquid–liquid interfacial tension, surface tension, and pH. Results showed that the selected surfactant is a critical determiner of the hydraulic fracturing fluid performance. SOLOTERRA 938 is an anionic surfactant that has good compatibility with Montney shale formation. Unlike other non-ionic surfactants, SOLOTERRA 938 retains the interfacial tension and surface tension after seven days of interaction with reservoir rock. The interfacial tension remained unchanged at 0.1 mN/m. The surface tension decreased from 28.4 to 27.5 mN/m with air and from 21.7 to 20.8 mN/m with hydrocarbon because surfactant behavior changes with pH change. The surfactant concentration was measured using high-pressure liquid chromatography, and the loss was 12% after seven days of interaction with the reservoir rock (from 0.1 to 0.088wt%). The adsorption calculated based on the concentration volume showed a low value of between 0.43 and 0.97 mg/g rock. [ABSTRACT FROM AUTHOR]