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.

The Rh(I)-catalyzed allenic Pauson-Khand reaction (APKR) is an efficient, redox-neutral method of synthesizing α-acyloxy cyclopentenones. An enantioselective APKR could provide access to chiral, nonracemic α-acyloxy and α-hydroxy cyclopentenones and their corresponding redox derivatives, such as thapsigargin, a cytotoxic natural product with potent antitumor activity. Rapid scrambling of axial chirality of allenyl acetates in the presence of Rh(I) catalysts enables the conversion of racemic allene to enantiopure cyclopentenone product in a dynamic kinetic asymmetric transformation (DyKAT). A combined experimental and computational approach was taken to develop an effective catalytic system to achieve the asymmetric transformation. The optimization of the denticity, and steric and electronic properties of the ancillary ligand (initially (S)-MonoPhos, 58:42 er), afforded a hemilabile bidentate (S)-MonoPhos-alkene-Rh(I) catalyst that provided α-acyloxy cyclopentenone product in up to 14:86 er. Enantioselectivity of the Rh(I)-(S)-MonoPhos-alkene catalyst was rationalized using ligand-substrate steric interactions and distortion energies in the computed transition states. This asymmetric APKR of allenyl acetates is a rare example of a Type I DyKAT reaction of an allene, the first example of DyKAT in a cyclocarbonylation reaction, and the first catalyst-controlled enantioselective APKR.

In order to reduce greenhouse gas emissions while recovering hydrocarbons from unconventional shale formations, processes that make use of carbon dioxide to enhance oil recovery while storing carbon dioxide (CO2) should be considered. Here, we examine samples from three shale basins across the United States (Utica and Marcellus Shales in the Appalachian Basin, Barnett Shale in the Bend Arch-Ft. Worth Basin, and Eagle Ford in the Western Gulf Basin) to address the following questions: (1) do changes from reaction with CO2 and fluids at the micrometer and nanometer scale alter flow pathways and, in turn, impact hydrocarbon production, CO2 storage, and seal integrity and (2) can CO2 or fluid reactivity be predicted based on physical or chemical properties of shale formations? Experiments were conducted at 40 °C and 10.3 MPa to characterize the interaction between CO2 and shale using X-ray diffraction (XRD), carbon and sulfur analysis, in situ Fourier transform infrared spectroscopy (FT-IR), feature relocation scanning electron microscopy coupled with energy-dispersive spectroscopy (SEM-EDS), mercury (Hg) intrusion porosimetry, and Brunauer–Emmett–Teller (BET) surface area and pore size analysis coupled with density functional theory (DFT) methods. Changes in mechanical, physical, and flow properties of shale cores due to CO2 exposure were addressed using a New England Research Autolab 1500 and Xenon X-ray computed tomography (CT) scanning. Results showed that CO2 did not promote significant reactivity with the shale if water was not present; only shales with swelling clays or residual interstitial pore water reacted with dry CO2 to promote reactivity in shale. When water was added as a reactant, CO2 formed carbonic acid and reacted with the shale to dissolve carbonate pockets, etched and pitted the shale matrix surfaces, and increased the microporosity and decreased nanoporosity. Porosity and permeability increased appreciably in core shale samples after exposure to CO2 saturated fluid due to dissolution of carbonate. Shale mechanical properties were not altered. Trends were not observed that could tie CO2 or fluid reactivity to physical or chemical properties of the shale formations at the basin scale from the samples we examined. However, if the shale contained significant amounts of carbonate and water was available to react with the CO2, pore sizes were altered in the matrix and permeability and porosity increased.

The narrow substrate scope of the asymmetric Pauson–Khand reaction (PKR) presently limits its synthetic utility. We recently reported an example of an enantioselective PKR with a precursor not comprising a 1,6-enyne by using a cationic Rh­(I) catalyst and a chiral monodentate phosphorous ligand. Herein, the mechanisms and ligand effects on the reactivity and selectivity of enyne PKRs using Rh­(I) metal complexes with three different ligands ((R)-BINAP, (S)-MonoPhos, or CO) are examined experimentally and computationally. A correlation between experiments and DFT calculations is demonstrated. The PKR with the bidentate ligand (R)-BINAP is fast and shows a low calculated Gibbs free energy of activation (ΔG ‡) for the oxidative cyclization step; the monodentate ligand, (S)-MonoPhos, affords a much slower reaction with a higher ΔG ‡; and using the CO-only Rh complex, the reaction is very slow with a high ΔG ‡. A linear relationship between the enantiomeric excess of (S)-MonoPhos and the PKR product suggests that the active Rh catalyst involves a single ligand. The absolute configuration of the product afforded by each of these ligand-bound catalysts is determined by DFT calculations and confirmed by vibrational circular dichroism spectroscopy. Transition-state structures for the oxidative cyclization step show that the chiral induction is controlled by steric interactions between the phenyl groups of the (R)-BINAP ligand or the methyl groups of the (S)-MonoPhos ligand and an alkenyl hydrogen of the enyne. DFT calculations revealed two competing oxidative cyclization pathways involving either four- or five-coordinated Rh­(I) species. The preferred mechanism and the enantioselectivity are affected by the ligand, the substrate, and CO concentration. Incorporating experimental temperature and CO concentration into the Gibbs free-energy calculations proved crucial for obtaining agreement with experimental results.

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.

This study attempts to determine if the efficacy of CO2-based enhanced oil recovery (EOR) techniques for unconventional liquid reservoirs (ULRs) can be increased through wettability alteration by adding a dilute non-ionic surfactant to CO2. The use of surfactants to increase the water-wetness of rock surfaces has previously been shown to improve oil recovery during water-based hydraulic fracturing and waterbased EOR in ULRs. In this study, nonionic surfactants are dissolved in CO2 to attain analogous significant shifts in wettability toward CO2-philic and oil-phobic. This could provide another EOR mechanism for the CO2-based recovery of oil from unconventional formations. The solubility of a nonionic, water-soluble, surfactant (Indorama SURFONIC® TDA-9, an ethoxylated alcohol with a branched tridecyl, oil-philic tail and nine ethylene oxide groups in the hydrophilic head group) in CO2 has been measured between 25 – 100 °C. This surfactant exhibits a solubility of roughly 1 wt% at pressures of 2000 – 5000 psia, with lower pressures required for lower temperatures. Eagle Ford outcrop samples were first aged in dead Eagle Ford crude oil at high temperature to attain oilwet characteristics. The oil wetness of shale samples was verified by measuring contact angles of water droplets in air. Then the samples were immersed in CO2 or CO2-surfactant solution for 16 h at 4000 psi and 80 °C. Contact angle measurements were then performed to identify shifts in wettability. No substantial change in wettability were observed for samples exposed to CO2, however the samples exposed to CO2-surfactant solution revealed a significant shift toward water-wet. Two CO2 huff ‘n puff experiments were then conducted for small, oil-saturated shale cores at 80 °C and 4000 psi. Faster oil recovery (i.e. more oil recovery in the first cycle) and cumulative oil recovery of 73% (after 7 huff and puff cycles) were achieved for the core immersed in CO2-surfactant solution (0.7 wt% surfactant) compared to 78% recovery for the core immersed in pure CO2. Continuing tests will examine the effects of rock type, oil properties, temperature, pressure, surfactant type (oil-soluble vs. water-soluble ethoxylated alcohols), surfactant concentration, and the presence of brine. CO2-soluble propoxylated alcohols will also be assessed because the polypropylene oxide oligomer is more CO2-philic than the conventional polyethylene oxide oligomer.

Geologic carbon storage (GCS) is a rapidly evolving technology with the potential to reduce the environmental impact of fossil fuel usage. Saline aquifers, which comprise a sandstone matrix with brine contained in the pores, make up much of the pore space available for CO2 storage in the United States. When CO2 is injected in saline aquifers, however, capillary fingering occurs, and only a small percentage of the pore space is filled with CO2. This fingering effect is due to the low viscosity of CO2, which is roughly ten times less viscous than brine. To address this problem, we tested the ability of inexpensive, commercially available nonionic surfactants to be dissolved in injected CO2 and increase the apparent viscosity of CO2 by generating CO2-in-water foams in situ. We focused our study on nonionic tridecyl ethoxylate surfactants with the number of ethoxylate groups ranging from 11 to 18 (TDA-11, TDA-13, TDA-15, TDA-18). These surfactants exhibited sufficient CO2-solubility and were shown to reduce the CO2-brine interfacial tension (IFT), stabilize bulk CO2-in-brine foams, and reduce the mobility of CO2 during core floods of CO2 in brine-saturated Berea sandstone. The surfactants did not alter the wettability of the Berea sandstone. Modeling results showed that in a reservoir field injection scenario, the presence of TDA-11 (0.1 wt %) increased both the CO2 storage resource and storage efficiency by 17%. Simulations also showed that the lateral extension area of the plume was reduced by 23% and that CO2 saturation within the plume increased by 26%.

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