Evaluation of anionic and non-ionic surfactant performance for Montney shale gas hydraulic fracturing fluids

Abstract

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.

Nonionic and anionic surfactants as flowback aids in hydraulic fracturing methods of crude oil production

“…However, it is important to recognize that the selection and use of surfactants is quite system dependent and not always straightforward. While it has been demonstrated that the use of surfactants can aid flowback (Chai et al, 2019; Chee et al, 2021; Hussien et al, 2019; Somasundaran & Zhang, 2006), careful selection is required (Tangirala & Sheng, 2018), especially in unconventional shale plays (Yongjun et al, 2018), as poor selection can damage the formation. In some cases, performance can be dependent on factors that are not immediately obvious.…”

Surfactants are Ineffective for Reducing Imbibition of Water-Based Fracturing Fluids in Deep Gas Reservoirs

“…Hydraulic fracturing for stimulating production of low-permeability shale gas reservoirs uses large volumes of water, often exceeding 10 4 m 3 per well, while competing for valuable water resources and incurring high costs for water supply and treatment of flowback water. − In addition to these burdens, loss of water-based fracturing fluids into reservoir matrix rocks during shut-in impedes production through blocking pores and through structural damage within the wetted fracture-matrix interface zone. ,− The adverse effects of water imbibition into shales have motivated investigations on ways to minimize water loss within reservoirs through manipulating interfacial properties and capillary forces. Indeed, a key strategy advanced in stimulating unconventional gas reservoirs is to use surfactants in hydraulic fracturing fluids in order to reduce the capillary pressure driving imbibition and thereby decrease thicknesses of water-blocked zones at the fracture-matrix interface. − Indeed, in enhanced oil recovery (EOR), the applications of surfactants to reduce surface tension, stabilize microemulsions, and alter reservoir wettability to facilitate oil mobilization are well recognized. − It is worth noting that surfactants are also added into hydraulic fracturing fluids for controlling rheological properties. As essential components of foams and gelling agents, surfactants can help enhance viscosity, thereby increase fracture width and improve proppant delivery. − …”