Primary oil recovery from fractured unconventional formations, such as shale or tight sands, is typically less than 10%. The development of an economically viable enhanced oil recovery (EOR) technique applicable to unconventional liquid reservoirs (ULRs) would lead to tremendous increases in domestic oil production. Although injection techniques such as waterflooding and CO2 EOR have proven profitable in conventional formations for decades, EOR in ULRs presents a far more difficult challenge. The extremely low permeability and mixed wettability of unconventional formations are the foremost obstacles to success. Because of the challenges associated with water-based EOR techniques (a.k.a., chemical EOR) in shale, several nonaqueous injection fluids have been considered, including CO2, natural gas, and (to a lesser degree) nitrogen. All these fluids have significantly lower viscosities than water, allowing them to more easily penetrate shale nanopores. Unlike water, they also each possess some degree of miscibility with oil, which enables the gas to extract oil through a combination of mechanisms. Based on laboratory-scale experimentation, CO2 and rich natural gas (methane-rich natural gas containing high concentrations of ethane, propane, and butane) are the most promising EOR fluids. The interpretation of results from field tests in the Bakken and Eagle Ford formations have been complicated by interference of frac-hits or well-bashing caused by hydraulic fracturing at nearby wells. In this review we cover mechanisms, laboratory experiments, numerical simulations, and field tests involving high-pressure CO2, natural gas, ethane, nitrogen, and water.

In this study, contact angles were measured for CO2 bubbles on six different sandstones (Navajo, Nugget, Bentheimer, Bandera Brown, Berea, and Mt. Simon) that could potentially represent properties of CO2 storage depositional environments. The impacts of pressure and temperature were studied by focusing on the CO2 phase behavior in three different scenarios: gaseous, liquid, and supercritical conditions. Despite controlling the sample preparation and cleanliness, CO2–brine equilibration conditions, and pressure and temperature, there were inconsistencies in contact angle trends that could largely be attributed to natural sample heterogeneity resulting from localized variations in topography, surface roughness, and mineral composition across the surface. Despite these variations, the analysis of 298 measurements from this study showed that 81% of the contact angles were <40°, representing strongly water-wet to (moderately) water-wet behaviors. Also, 17.3% of the measurements were between 40° and 60° (weakly water-wet) and primarily belonged to small CO2 bubbles (<500 μm) that were heavily impacted by localized surface heterogeneity in natural sandstone samples. In addition, only 1.7% of the measurements had angles greater than 60° and could be classified as no longer water-wet, but these measurements occurred on extremely small bubbles (100–200 μm) that were very dependent on localized surface heterogeneity. While some of the detailed physics of the CO2/brine/sandstone interface is still poorly understood, from an application standpoint, the sandstones of this study were best characterized as strongly water-wet to (moderately) water-wet.

CO2 injection is a promising method for enhanced oil recovery (EOR) in unconventional shale reservoirs. In this work, we postulate that CO2 EOR may be improved by the dissolution of surfactants into CO2. Although CO2 is a relatively good solvent for oil, we show that CO2 and Eagle Ford oil are immiscible at compositions above 70 wt % CO2, even at pressures as high as 62 MPa. The presence of a CO2–oil interface at reservoir conditions indicates that the addition of a surfactant has the potential to improve oil recoveryvia wettability alteration from oil-wet to CO2-wet, CO2–oil interfacial tension (IFT) reduction, or both. Three nonionic surfactants (branched tridecyl ethoxylate Indorama SURFONIC TDA-9, branched nonylphenol ethoxylate Indorama SURFONIC N-100, and linear dodecyl ethoxylate Indorama SURFONIC L12-6) were evaluated for CO2-solubility, shale wettability alteration, effect on CO2–oil IFT, ability to generate CO2–oil foams, and ability to increase oil extraction from Eagle Ford, Mancos, and Bakken shale cores. Each surfactant dissolved in CO2 up to 1 wt % at pressures and temperatures commensurate with CO2 EOR. CO2-dissolved surfactants did not significantly affect CO2–oil IFT or generate CO2–oil foams, but they did induce a dramatic change in the contact angle of an oil droplet on an oil-aged shale chip in CO2 from strongly oil-wet (11°) toward intermediate CO2–oil wettability (82°) (at 80 °C, 27.6 MPa). The branched tridecyl ethoxylated surfactant, SURFONIC TDA-9, afforded the highest oil recovery in core soaking experiments75%, compared to 71% by pure CO2. Analysis of oil extracts by gas chromatography revealed that heavier oil components were produced when the surfactant was added to CO2. These results indicate that CO2-dissolved surfactants may increase oil recovery from shale by wettability alteration from oil-wet toward CO2-wet.

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Free energy of nanoparticles can increase the surface activity at the solid/oil/liquid contact line and remove oil through the disjoining pressure gradient mechanism. Surfactants can also remove oil mainly by reducing interfacial tension, although raising economic concerns as a result of their adsorption on the rock surface. Introduction of nanoparticles to surfactant solutions seemed to be more prominent in improving the wettability than reducing the interfacial tension, which could offer an opportunity to develop cost-effective chemical flooding agents to enhance oil recovery in carbonate reservoirs. However, characterization of wettability alteration using contact angles typically fails in providing consistent results. In this study, the dual-drop–dual-crystal technique was employed to measure precise and reproducible dynamic contact angles and was supported by relative permeability curves generated by coreflood experiments to evaluate the wettability alteration performance of silica nanoparticles combined with both effective and ineffective anionic surfactants at both ambient and high-pressure, high-temperature conditions. Adding nanoparticles to surfactants was seen to change the wettability of the carbonate rocks from strongly oil-wet to weakly oil-wet and intermediate-wet conditions (e.g., change in the advancing contact angle from 167° to 98°), which improved the oil recovery (up to 93% of the original oil in place) and reduced the residual oil saturation, without having to significantly reduce the interfacial tension (only 1 or 2 orders of magnitude). Reduction of the surfactant concentration in the combination did not significantly hinder the wettability alteration performance, showing the ability of nanoparticles to compensate for surfactants. Therefore, the combination of nanoparticles and low-cost dilute surfactants can be tuned to provide economically appealing chemical flooding agents to enhance oil recovery.

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