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Several surfactant formulations that had been tested successfully in oil-wet unconventional reservoirs were tested in mixed-wet to oil-wet unconventional reservoir cores and did not generate the expected results. To study the mechanisms of oil recovery and understand the uniqueness of these shale reservoirs, a series of studies were performed utilizing Eagle Ford (EF) and Canadian Bakken shale rocks and fluids. In this study customized chemical formulations for improving production from the EF and the Canadian Bakken were developed. Previously related formulation development for the Bakken and Permian basins relied upon wettability alteration as the oil recovery mechanism; however, no significant oil recovery compared to brine was seen from wettability-altering formulations using EF and Canadian Bakken shale rock and fluids. Several imbibition tests showed that baseline oil recovery by brine was 20-30% of original oil in place (OOIP) for both formations. High oil recovery by brine was attributed to the mixed to water-wet nature of the pore surface. A well-connected fracture system may have also contributed. Further, there was no correlation between oil recovery and contact angle measurements. Failure of wettability alteration as an oil recovery mechanism led to investigation of interfacial tension (IFT) reduction as an alternative mechanism. Testing this hypothesis, a change in the EF formulation reduced IFT to 0.03 dyne/cm and had oil recoveries above 60% OOIP. However, these formulations were not stable at 320 °F. Formulation KPIs were set as lowering IFT and being stable up to 320 °F. Out of many formulations tested, two containing multiple actives in a specific mixture of solvents passed the KPIs and were tested for imbibition oil recovery. A synergistic mixture had a final oil recovery above 56% OOIP as compared to 20-25% OOIP for brine alone. The imbibition oil recovery results indicate that although the ultimate oil recovery by brine alone is significant, the early oil production is significantly slower than by surfactant solutions. Upscaling the laboratory time to the field time emphasizes the value of implementing customized surfactant formulation in both early and late oil production. Similarly, there was no correlation between wettability contact angle measurements and oil recovery for the Canadian Bakken shale. Surfactant formulations which exhibited low IFT (~0.01 dyne/cm) significantly accelerated the oil production and recovered an additional 30-45% OOIP in the tertiary mode from the imbibition tests. Further laboratory studies via the Washburn method, imbibition tests, and zeta potential measurements validated lowering IFT, not altering the wettability, as a primary oil recovery mechanism in the mixed-wet EF and Canadian Bakken. Optimal formulations for EF and Canadian Bakken will be tested in the field by mid-2018.

Significant work is ongoing within the industry to determine a best practice for maximizing oil recovery from fractured oil-wet shale reservoirs. Rapid decline curves are often observed and water flooding can be largely ineffective because of negative capillary pressure. The goal of this work is to identify a chemical solution that can maximize oil and gas recovery in unconventional reservoirs by reduction of hydrocarbon adhesion to shale rocks. In order to evaluate an optimal solution, numerous formulations were developed and tested for their impact on adsorption and adhesion on rock and/or sand, changes in interfacial tension, and how the formulation affects the wettability of the formation. Shale rocks were characterized for their surface energy, as this governs the adsorption and adhesion tension of crude oil, water, and chemicals to the solid surface. Formulations were selected that minimized the adsorption on rock and sand surfaces since such adsorption may lead to an increase in the surface tension of fluid pumped into the well and the interfacial tension between the crude oil and fluid. Contact angle measurements were used to determine the Van der Waals and Lewis acid-base components of surface energies for Barnett, Eagle Ford, Niobrara, and Bakken shales. In addition, contact angle measurements and interfacial tension were used to determine the adhesion of crude oil to the rock. Numerous chemical formulations were evaluated to identify products that can decrease the work of adhesion, making oil recovery more efficient (i.e. less work is required to remove oil drops from the rock surface and mobilize them). Competitive adsorption of formulations at the oil-water and rock-water interface was evaluated. The amount of natural surfactants in the oil and their adsorption on the rocks (reversible vs. irreversible) affect whether the rock is oil-wet or water-wet. If the adsorption is reversible, the rock would be more water-wet, resulting in higher oil recovery. Formulations which altered the wettability to water wet rapidly, but reduced the interfacial tension slightly, exhibited the highest oil recoveries. Based on wettability alteration, interfacial tension, and work of adhesion, a novel product was developed that is salt tolerant (in 30% TDS), thermally stable (115°C), and produces high oil recovery (i.e., 60% OOIP). Kinetics were also improved compared to conventional treatments and brine alone. In addition, this product showed a low static adsorption on the Bakken shale (0.20 mg product active/gram rock) and no emulsion tendency.

Reservoirs containing very high total dissolved solids and high hardness make the design of a surfactant polymer (SP) flood extremely difficult because surfactant tends to precipitate and separate under these conditions. Beside divalent ions, Ca2+, Mg2+, presence of iron in the brine can be a challenging issue. Different surfactant formulations are evaluated and incorporate cosurfactants and co-solvents which minimize viscous macroemulsions, promote rapid coalescence under Winsor Type III conditions, and stabilize the chemical solution by reducing precipitation and phase separation. The optimal surfactant formulations were further evaluated in one-dimensional sand packs and coreflood tests using Berea sandstone, reservoir oils, and brines at reservoir temperatures. Using similar injection protocols, 3 pore volumes of surfactant-only system, experimental results show the oil recovery ranging from 45 % to 70% of the residual oil (Sor) after water flooding. The level of surfactant loading is less than 0.5 wt%. A single-well test was conducted to confirm laboratory results in situ in the presence of high-salinity formation water containing 102,300 mg/L total dissolved solids (TDS). The aim of ongoing test is to confirm the effectiveness of the high-salinity surfactant-only formulation (0.46 wt% of surfactant). In this effort, we plan to conduct multiple single-well tests at different wells to minimize the design risks involved for the surfactant pilot test. A pilot test at a sandstone reservoir is scheduled to be performed in July of 2013 to further evaluate the effectiveness of surfactant formulation and address technical issues related to scale-up.