Due to the mixed-wettability phenomenon found in Montney rock fabric, choosing the ideal flowback enhancer/surfactant to Enhance Post Frac Oil Recovery (EPFOR), has not been a straightforward task. Along with the wettability ambiguity, Montney exhibits nano-Darcy permeability making laboratory testing challenging.

Conventionally at the flowback stage, injected treatment water is recovered as soon as possible with the intent to reduce the water saturation in the invasion zone and newly created complex network of fractures. On the contrary, the soakback/slowback concept has been recently adapted as a new practice for flowback management. The well is left shut in for an extended period to promote counter-current imbibition phenomena, where the residual hydraulic fracturing fluid can imbibe deeper in the formation matrix driven by osmotic and capillary forces. The imbibition mechanism into the matrix and dissipation of water saturations beyond the invasion zone help clean up water in the propped fractures and can help to ramp up peak hydrocarbon rates.

Common surfactant chemistry applied in hydraulic fracturing on Montney can be rendered inefficient due to the fast-adsorbing effect in the near-wellbore (hydraulic fracture face) area. Instead, an innovative nano-particle surfactant (NPS) has been developed, that can penetrate through formation rock and oil layers more efficiently, carrying low salinity hydraulic fracturing fluids deeper in the rock matrix, by reducing the in-situ interfacial tension between crude oil and the stimulation fluids and altering the mixed wettability of the formation rock to a more water-wet state. Additionally, the fabric of the Montney formation contains clays, which displays osmotic membrane characteristics in the presence of high salinity gradients (stimulation fluid and connate water). Once stimulation fluid invades the pore space through clay platelets, pore pressure increases and an expulsion of hydrocarbon from pore space is followed.

In this paper, we examine properties of NPS through a rigorous laboratory testing protocol with Montney core and liquid hydrocarbon specimens. Interfacial tension testing shows that when NPS is added at a minimum loading of 0.1 L/m3 in the stimulation fluid, a further interfacial tension reduction of approximately ~41.3% is reached in comparison to other commercially available petroleum surfactants at the same loading. Long-term Amott cell testing performed with Montney core samples in the presences of NPS displays a substantial increase in oil recovery when compared to the blank.

This paper attempts to detail the development of the NPS through laboratory and field testing which includes the characteristics of hydraulic fracturing fluids, produced hydrocarbons, and formation rock interactions.

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