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Spontaneous imbibition is a pervasive part of many natural and industrial processes. As an inherent feature of fluid transport in porous media, it is a driver for oil recovery. Understanding spontaneous imbibition and leveraging surface science is fundamental for fluid recovery; specifically, the role of the surfactant in the imbibition processes and the potential to alter capillarity and wettability of reservoir rock. Surfactant success relies on the understanding of the factors governing the interfacial phenomena among crude oil, and formation properties under reservoir conditions. Developing a methodology coupling chemical performance with analytical techniques, and statistical interpretation of core/surfactant/oil interactions, can help establish workflows to advance new chemistries and enhance oil recovery. This article discusses a study of flowback aids formulated as microemulsions corresponding to the thermodynamically stable Winsor Type IV solutions. Neat formulated microemulsions, when dosed at field treatment concentrations, provide either oil‐in‐water droplet microemulsions or nanoemulsions. The solvency potential was measured, and the Kauri‐butanol (Kb) value was determined. Parameters such as critical micelle concentration (CMC) and interfacial tension (IFT) were determined to characterize microemulsion solutions. These systems were tested using either in the column flow test with formation material sieved to match mineral grain size, or sandstone cores of various permeabilities. The results indicate that surfactant‐based flow‐enhancing aids are desirable for improved oil recovery when compared to the control fluid. The statistical analysis of core‐fluid interaction includes an ANOVA followed by assumption evaluations and model interpretation, which demonstrates that the core permeability term, followed by the surfactant term, has the highest contribution whereas oil has no statistical significance to the model.

The water-sensitive nature of shale is traditionally thought to be a factor of the clay content of the rock. Because current practices to mitigate formation damage entail the use of brines to control the osmotic potential of stimulation fluids, we posited that not all brines will induce the same response from Bentonite, Illite, and more importantly shale. Current industrial practices to mitigate permeability damage in source rock shale reservoirs typically entail the use of sodium-, potassium-, calcium-, tetramethyl ammonium-, and/or choline chloride salt brines to control the rate of cation exchange between formation clays and stimulation fluids. Industrial and literature precedent suggests that below a critical salt concentration (CSC) osmostically-driven cation-exchange between injected fluid and the formation is the primary damage mechanisms for both swelling and migrating clays; however, above the CSC, the potential still exists for crystalline swelling and mechanical destabilization. Examining various clays and clay laden formation materials revealed that certain cations, even above their CSC, will induce formation damage. To accurately assess the effect and permanency of various brines when introduced to pure clay as well as shales, a statistically relevant laboratory protocol has been developed to evaluate the role differing cations play in shale preservation. The clay and formation cuttings were evaluated for swelling and mechanical stability, then subjected to dynamic experiments using sandpack, coreflow, and API conductivity testing methods. The evaluated formation materials were diagnosed with computed tomography (CT), scanning electron microscopy (SEM), and energy-dispersive X-ray spectroscopy to diagnose permeability damage mechanisms for given treatment fluids and formation material composition. This paper seeks to advance the existing understanding of the damage mechanisms involved when brine containing stimulation fluids are introduced to shale reservoirs. Currently, there is a lack of consensus on the significance of the identity of the ideal salt-cation treatment to preserve permeability in shale reservoirs. The authors have probed the effect various brines have on clay and unconventional material, which compliments the current body of literature related to shale inhibition.

This paper describes the development of a highly automated apparatus and customized software package to rapidly evaluate the performance of surfactant additives in dry gas shale reservoirs. A major challenge throughout the industry is the ability to reduce water saturation resulting from fluid leakoff into the formation matrix during stimulation operations. The new method presented in this paper to help identify the optimum surfactant for reducing post-treatment water saturation based on well-specific parameters. Conventional laboratory evaluation of stimulation fluid additives typically involves coreflow studies, which are excessively time consuming and have poor reproducibility as a result of core-to-core inconsistencies. The focus of this endeavor was to develop a statistically relevant method that can use drill cuttings samples and measures surfactant additive performance data with high confidence and reproducibility for the tested formation material. Data analysis included analysis of variance (ANOVA) followed by post-hoc Tukey honest significant difference (HSD) range testing. Test apparatus results were also corroborated with coreflow studies. Eight surfactant additives were evaluated in the presence of four different fracture fluid formulations and formation samples. For each surfactant/fracturing fluid/formation test matrix, the software was able to rank surfactants performance based on the volume of fracturing fluid displaced from a column pack normalized to the pressure gradient. No individual surfactant performed best more than 40% of the time within this test series, and the surfactant-laden formulations always statistically outperformed the nonsurfactant control. The results imply that the addition of surfactants results in increased treatment fluid load recovery. Reservoir simulations were performed to investigate the effects of increased load recovery and depth of invasion of fracturing fluids on hydrocarbon production. The simulation results confirmed the assumption that minimal invasion of treatment fluid into the matrix of the formation resulting from increased load recovery does improve hydrocarbon production. The simulation data also suggest this observed hydrocarbon production improvement is particularly prevalent in the early time/cleanup period of the life of the well. A key feature and novelty of the apparatus is the ability to evaluate numerous surfactants in series and the potential to perform up to 24 individual tests in an 8-hour shift. The results presented in this paper showcase the utility of the newly developed apparatus, which offers a new method for rapid customization of stimulation fluids.