The objective of this paper is to present a new innovative methodology that can be used to develop and evaluate the efficacy of enhanced flowback chemistries such as a novel oil-based surface modifier. This unique chemistry has been optimized to penetrate into the nanonetwork of formations, such as the Wolfcamp, with pore throat sizes as low as 110 nm at pressure differentials of only 225 psi, thereby demonstrating the ability to increase the volume of oil recovered during flowback by 250% and increasing the average producing flowrate by 194% during testing.

Although it is generally accepted that a water wet formation will lend itself to enhanced oil flowback, in unconventional formations there is a fine line between a water wet surface and the potential for increased capillary pressure, which can impact production potential. Resistance to flow in unconventional formations is created when droplets of brine form hydrogen bonded networks with the surface of the silicate formation rock creating additional capillary pressure. If the resistance is large enough it can restrict hydrocarbon flow rates out of the fractured rock formation. Nanoscale surface modification of unconventional formation rocks with the novel chemistry, SM1, can impact the wetting properties of oil and water in the nanopores and channels, disrupting the water-surface hydrogen bonding interactions, thereby decreasing the resistance to hydrocarbon flow.

The methodology used for product optimization and performance evaluation of the novel chemistries presented in this paper incorporates the use of reservoir analogues, in place of cores, in an experiment similar to core flow. The reservoir analogue replicates the inherent nanoconfined geometries of the shale reservoir rock using available geological information (e.g. pore/grain size distribution, porosity and permeability, and SEM images) and the connectivity between the induced fractures (frac zone). The reservoir oil and water samples are used to establish initial saturations. The surface wettability is also modified to capture the surface properties of the reservoir. The test methodology includes the flow of fluids in one direction into an oil saturated porous media (i.e., from frac zone into the nano network) followed by oil and water flowback in the opposite direction (i.e., from nanonetwork into the frac zone). Testing is conducted at specified reservoir representative conditions.

The nanotechnology platform offers several advantages in the product optimization and evaluation of fluid performance in unconventional rock formations. First, the specialized equipment, proprietary machine vision software, and refined testing protocols enable tests to be run efficiently in days at relevant reservoir conditions. Moreover, the platforms’ optical access enables first-of-its-kind, visual validation of performance mechanisms including surface wettability modification, emulsion characterization, and solid-precipitation if present. Additionally, this technology provides a platform that allows for repeatable results due to the high level of system control. Unlike testing with cores, analogues can be fabricated with ideal replication, eliminating the variance that cores introduce, which becomes complex, when evaluating the chemistry of fluids.

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