Summary Source rocks contain significant volumes of hydrocarbon fluids trapped in kerogen, but effective recovery is challenged because of amplified fluid/wall interactions and the nanopore–confinement effect on the hydrocarbon–fluid composition. Enhanced oil production can be achieved by modifying the existing molecular forces in a kerogen pore network using custom–designed targeted–chemistry technologies. The objective of this paper is to show that the maturation of kerogen during catagenesis relates to the qualities of the kerogen pore network, such as pore size, shape, and connectivity, and plays an important role in the recovery of hydrocarbons. Furthermore, using molecular–dynamics (MD) simulations, we investigated how the transport of hydrocarbons in kerogen and hydrocarbon recovery can be altered with the delivery of microemulsion and surfactant micelles into the pore network. New 3D kerogen models are presented using atomistic modeling and molecular simulations. These models possess important chemical and physical characteristics of the organic matter of the source rock. A replica of Type II kerogen representative of the source rocks in the Permian Basin in the US is used for the subsequent recovery simulations. Oil–saturated kerogen is modeled as consisting of nine different types of molecules: dimethyl naphthalene, toluene, tetradecane, decane, octane, butane, propane, ethane, and methane. The delivered microemulsion is an aqueous dispersion of solvent–swollen surfactant micelles. The solvent and nonionic surfactant present in the microemulsion are modeled as d–limonene and dodecanol heptaethyl ether (C12E7), respectively. MD simulation experiments include two stages: injection of an aqueous–phase microemulsion treatment fluid into the oil–saturated kerogen pore network, and transient flowback of the fluids in the pore network. The used 3D kerogen models were developed using a representative oil–sample composition (hydrogen, carbon, oxygen, sulfur, and nitrogen) from the region. Simulation results show that microemulsions affect the reservoir by means of two different mechanisms. First, during the injection, microemulsion droplets possess elastic properties that allow them to squeeze through inorganic pores smaller than the droplet's own diameter and to adsorb at the kerogen surfaces. The solvent dissolves in the oil phase and alters the physical and transport properties of the phase. Second, the surfactant molecules modify the wettability of the solid kerogen surfaces. Consequently, the recovery effectiveness of heavier oil fractions is improved compared with the recovery effectiveness achieved with surfactant micelles without the solubilized solvent. The results indicate that solubilized solvent and surfactant can be effectively delivered into organic–rich nanoporous formations as part of a microemulsion droplet and aid in the mobilization of the kerogen oil.

The application of acoustic spectroscopy to the characterization of binary C12EO7-water system was studied. It was discovered that the size of micelles in aqueous surfactant solutions could not be determined, but it was possible to determine the size of water nanodomains existing in the surfactant-rich systems. It was suggested that in colloidal systems, the energy of ultrasonic waves is dissipated only by interfaces existing between condensed phases. The characterization of Winsor transitions by acoustic spectroscopy in water/d-limonene system stabilized by a mixture of nonionic surfactant and isopropyl alcohol (cosolvent) was also explored. In one study, systems with a constant d-limonene to water weight ratio obtained in the course of titration of d-limonene-in-water emulsion with increasing amounts of surfactant+alcohol were investigated. In another study, a balanced d-limonene/water microemulsion was sequentially diluted with water and d-limonene. The transition between Winsor I and Winsor IV systems was monitored in both cases. Droplet size distributions were calculated using different models for dispersed and continuous phase composition. It was demonstrated that the magnitude of acoustic scattering played a significant role in the ability to reliably determine droplet size distributions, and in particular to simultaneously observe nanometer-size and micron-size droplets in Winsor I systems. An attempt was made to account for intrinsic attenuation of surfactant and alcohol by associating them with the aqueous phase, but this approach was shown not to be applicable in the case of Winsor IV microemulsions.

Characterization studies of organic-rich shale oil reservoirs have revealed significant volumes of hydrocarbon fluids in kerogen. However, the recovery from kerogen pores is challenging due to amplified fluid-solid interactions. New methods can be developed for improved recovery targeting oil from kerogen pore space by modifying the forces of molecular interactions using chemical injection. A highly-developed kerogen pore-network is required for the penetration and delivery of chemical agents that are expected to function in the confined space, such surface active agents. Using advanced computational chemistry tools, the objective of this paper is to show that the maturation (the exposure to high temperature, high pressure) of kerogen during catagenesis relates to the quality of the kerogen pore network such as pore size and shape, and plays important role in the action of added chemicals in the EOR processes. A new molecular dynamics simulation approach is developed applying dramatic changes to the organic chemicals system temperature to mimic varying degree of maturation. Simulation focuses on Type II kerogen, as it is the most common overall source of presently produced hydrocarbons. Two different chemical structures of type-II kerogen (C175H102N4O9S2, C242H219N5O12S2) are used as the building blocks to simulate the solid kerogen. The molar fractions of the elements are controlled to satisfy the overall H/C and O/C ratio of type-II kerogen in the oil window. The simulated hydrocarbon fluid consists of nine different types of molecules: dimethylnaphthalene, toluene, tetradecane, decane, octane, butane, propane, ethane and methane. The simulation box containing these molecules is subjected to a slow quenching process, which continues down to the reservoir temperature and pressure conditions. The effects of maximum temperature and the rate of quenching on the pore morphology of kerogen and the distribution of oil in the pore-network are discussed. We explain how kerogen pore morphology is controlled by the quenching rates. Next, we simulate the interaction of microemulsion droplets with the digital kerogen. Results show that the microemulsion droplets posess elastic properties which allow them to squeeze through the kerogen pores smaller than the droplet's own diameter and to adsorb at pore wall surfaces. One major benefit associated with the use of microemulsions is the ability of the droplets to transport and deliver solvents and surfactants to different parts of the pore network. Our work shows that solvents and surfactants with particular features can be delivered in the form of a microemulsion droplet into oil saturated kerogen pore network and influence the oil mobility.

The imbibition of solutions of a model nonionic surfactant into packed beds of crushed reservoir rocks was studied using the Washburn technique. A linear dependence between the equivalent height of capillary rise and the square root of imbibition time was observed at different stages of imbibition experiments. It has been shown that, under the conditions when surfactants did not alter the polarity of rocks, the imbibition rate of surfactant solutions correlated well with the nondispersion (polar) component of the surface free energy of the rocks. It was possible to compare data obtained for different rocks by normalizing the slopes of imbibition curves over the corresponding slopes determined for a completely wetting fluid, hexamethyldisiloxane (HMDS). Such a normalization allowed one to account for substantial differences in the morphology of crushed rock powders. Overall, the observed trends in the imbibition behavior were qualitatively similar to the trends reported previously for the rise of surfactant solutions in single capillaries. The largest qualitative impact of nonionic surfactant was observed in the imbibition into hydrophobic oily sandstone, in which case a surfactant-induced shift to hydrophilicity was observed. Overall, high concentrations were needed in order to observe the impact of surfactant on the imbibition rate.

Abstract Resource shales have low permeability matrix with nanoporous features. At nano scale in situ fluids experience strong fluid-wall interactions and confinement effects. The hydrocarbons recovery from the nanopore network is therefore limited. Microemulsions are known to be effective in stimulating oil and gas production from non-conventional reservoirs, however their mechanisms of action, as well as their ability to penetrate into nanosize pores of shale matrix during an operation such as hydraulic fracturing needs to be investigated. In this paper, we investigate the conditions for the microemulsion droplet penetration into model nanopores, identify the penetration mechanisms and, following their penetration, analyze their interactions with model organic and inorganic walls, and study their behavior in confinement. Molecular dynamics simulation is employed to simulate the behavior of a nanodroplet dispersion facing a solid surface. The model nanodroplets comprise swollen micelles of C12E7 nonionic surfactant with the d-limonene solvent solubilized in their cores. An oil-wet solid surface is modeled using graphite to represent hydrophobic kerogen in shale, and a water-wet solid surface is modeled using brucite to represent hydrophilic inorganic materials in shale. These surfaces are considered to have nanocapillaries with varying sizes, available for the microemulsion penetration experiment. Our results indicate that penetration into capillaries with sizes less than 10 nm is strongly influenced by the wettability of the solid surface. In the case of an oil-wet solid surface the droplets adsorb on the surfaces and hence impact the penetration ability. In the case of a water-wet surface, however, microemulsion droplets effectively penetrate into the nanocapillaries. The droplets are capable of penetrating into the capillaries that are smaller than their own size. In both of these two cases, the solubilized solvent and the surfactant are delivered into a tight nanocapillary network and come into contact with the in situ hydrocarbons. This research can be extended to include ionic surfactants, varying salinity, and more complex solid surfaces to develop the next generation microemulsions with superior performance in enhancing oil production from the unconventional reservoirs.

Summary Molecular-dynamics simulation is used to investigate the nature of two-phase (oil/water) flow in organic capillaries. The capillary wall is modeled with graphite to represent kerogen pores in liquid-rich resource shale. We consider that the water carries a nonionic surfactant and a solubilized terpene solvent in the form of a microemulsion, and that it was previously introduced to the capillary during hydraulic-fracturing operation. The water has already displaced a portion of the oil in place mechanically and now occupies the central part of the capillary. The residual oil, on the other hand, stays by the capillary walls as a stagnant film. Equilibrium simulations show that, under the influence of organic walls, the solvent inside the microemulsion droplets enables not only the surfactant but also the complete droplet to adsorb to the interfaces. Hence, delivering the surfactant molecules to the oil/water interface is achieved faster and more effectively in the organic capillaries. After the droplet arrives at the interface, the droplet breaks down and the solvent dissolves into the oil film and diffuses. This process is similar to drug delivery at nanoscale. Using nonequilibrium simulations based on the external force-field approach, we numerically performed steady-state flow measurements to establish that the solvent and the surfactant molecules play separate roles that are both essential in mobilizing the oil film. The surfactant deposited at the oil/water interface reduces the surface tension and acts as a linker that diminishes the slip at the interface. Hence, it effectively enables momentum transfer from the mobile water phase to the stagnant oil film. The solvent penetrating the oil film, on the other hand, modifies flow properties of the oil. In addition, as a result of selective adsorption, the solvent displaces the adsorbed oil molecules and transforms that portion of the oil into the free oil phase. Consequently, the fractional flow of oil is additionally increased in the presence of solvent. The results of this work are important for understanding the effect of microemulsion on flow in organic capillaries and its effect on shale-oil recovery.

In enhanced oil recovery, the production is influenced by the ability of injected surfactants to adsorb and to modify interfacial tension at different interfaces. It has previously been demonstrated that surfactant and microemulsion additives enhance the production to a different extent but the mechanisms behind the differences in their action are not fully understood. Recent molecular dynamics simulation shows that the adsorption at a solid surface differs for these two systems. Furthermore, it shows that the solvent solubilized in a microemulsion is transported to the solid surface together with the surfactant, and hence the surface modification can be controlled by designing the chemistry and composition of the selfassembled structure. Here, we report salient new results on the adsorption from microemulsion at graphite-liquid, and liquid-liquid interfaces. The simulation involves an aqueous solution in the presence of an oil (heptane) phase. The solution consists of nonionic surfactant dodecylhepta(oxy-ethylene)ether or C12E7, and a solubilized terpene solvent. We found that the presence of solvent inside the micelles causes the mechanism of adsorption behavior to deviate from those expected for adsorption from micellar surfactant solutions. In the case of solubilized terpene, the swollen micelles adsorb on the surface as one entity. The delivery of a surfactant to the interface and the associated reduction of the interfacial tension is influenced by the change in interaction potential between the surface and surfactant aggregate, and it is controlled by the solvent concentration. Molecular dynamics simulation also reveals the complex distribution of fluids at the capillary wall. The terpene swollen micelle merges with the thin film of oil on the wall. The surfactant deposits on the interface between the aqueous phase and the oil, thereby reducing its interfacial tension. The solvent originally solubilized in a microemulsion droplet, penetrates the thin film of oil. The resulting mixture of oil and solvent has different properties from the oil alone, indicating a primary difference between the mechanism of action between surfactant and a combination of surfactant and solvent. For comparison, the same simulation conditions were applied to the case of C12E7 micelles without solvent. As expected, the whole micelle did not adsorb at the interface. The results are important for our understanding of microemulsion behavior under confinement and its application to organic rich shale oil recovery.

Abstract The productivity and economics of horizontal wells are governed by the ability of the transverse fractures to communicate efficiently with the wellbore, which is strongly controlled by the conductivity of the proppant bed and the effectiveness of the fluid additives. These impact the relative permeability, the capillary pressure and the effective conductivity in the proppant bed. When time at temperature, stress cycling, embedment, multi-phase flow and non-Darcy effects are considered, the effective conductivity can be reduced 100-fold. Another investigated parameter is the impact of the wellbore location relative to the propagated fracture. If the wellbore is high in the fracture, gravity segregation will cause liquid removal from the lower portion of the fracture to be very difficult. In low conductivity proppant beds, capillary pressure will tend to retain high water saturations, thus lower conductivity even for the portions of the fracture above the wellbore. Laboratory experiments have addressed these issues for proppants with a range of permeabilities from 10 to 100 Darcies; 100 mesh to 20/40 mesh and ceramics. The relative permeability to gas can be as low as 0.01, with as much as a 70-fold improvement when suitable proppants and additives are employed. Evaluation of the production performance of 240 wells, 98 with effective additives and 142 without, and covering a similar range of proppant types and sizes, shows a similar benefit to the wells’ normalized 30 day recovery and gross value. These results clearly demonstrate that economic expediency can be detrimental to a well’s ultimate value and hydrocarbon recovery.

Abstract The primary purpose of using surfactants in stimulating hydrocarbon rich gas reservoirs is to reduce interfacial tension, and/or modify contact angle and reservoir wettability. However, many surfactants either adsorb rapidly within the first few inches of the formation, or negatively impact reservoir wettability, thus reducing their effectiveness in lowering capillary pressure. These phenomena can result in phase trapping of the injected fluid adversely impacting oil and gas production. This study describes experimental and field studies comparing various common surfactants used in oil bearing formations including alcohol ethoxylates, EO-PO block copolymers, ethoxylated amines and a multi-phase complex nano fluid system to determine their impact on oil recovery and adsorption tendencies when injected through 5-foot and 1 ft sand columns. Ammot cell tests were used to evaluate imbibition of oil and water and a core flow apparatus was used to evaluate regained relative permeabilities. The results are correlated with surface energies of actual formation materials, oils and treating fluids. The results are used to select formulations containing surfactant, solvents and co-solvents to apply within the fracturing fluid to decrease adsorption, eliminate post treatment emulsions and improve oil and gas recovery in hydrocarbon rich gas wells.

Abstract A continuing challenge in hydraulic fracturing of tight gas formations is associated with remediation of formation damage caused by fluid invasion into the porous media. Numerous studies documenting the use of complex nanofluids and surfactants to remediate formation damage have been reported. Recent publications have demonstrated that complex nanofluid additives resulted in lower pressures to displace injected frac fluids over conventional surfactants, and led to greater enhancement of gas and water production. These findings were also confirmed by several recent statistical analyses that took into consideration differences in the properties of treated wells. Many field case studies and supplementary laboratory data have illustrated benefits of complex nanofluid treatment over conventional surfactants. While these publications describe the successes of complex nanofluid treatment, the influence that the formulation composition has on its performance has not been fully investigated. In the present study, we prepared complex nanofluids with different chemical compositions and examined their performance in fluid recovery tests using columns packed with sand, ceramic proppant, and shale, as well as their ability to enhance permeability of sandstone cores to gas. We have established that performance of complex nanofluids in these applications was dependent on the amount of microemulsifed solvent in the original formulations and that optimal performance across all applications was achieved with a complex nanofluid formulation with a near-balanced composition.

Abstract The productivity and economics of horizontal wells are governed by the ability of the transverse fractures to communicate efficiently with the wellbore, which is strongly controlled by the conductivity of the proppant bed and the effectiveness of the fluid additives. These impact the relative permeability, the capillary pressure and the effective conductivity in the proppant bed. If the wellbore is high in the fracture, gravity segregation will cause liquid removal from the lower portion of the fracture to be very difficult. In low conductivity proppant beds, capillary pressure will tend to retain high water saturations, thus lower the effective conductivity even for the portions of the fracture above the wellbore. Laboratory and field studies are presented comparing various sizes and types of proppants and the influence of surfactants used in oil bearing formations including commonly used demulsifiers and a multi-phase complex nano fluid system. Ammot cell and centrifuge tests were used to evaluate imbibition of oil and water. Columns packed with proppant and formation cuttings are used to compare the effectiveness of various additives in allowing the displacement of water and establishing oil flow. Results are correlated with interfacial tension, contact angle, capillary pressures and surface energies of actual formation materials, oils and treating fluids from the Niobrara, Bakken, Granite Wash and Eagleford formations. Simulations are presented that show the impact of capillary pressure and oil viscosity on the displacement of fluids. Field results from various fields including the Niobrara, Bakken, and Marcellus formations are presented. The normalized field data shows that wells with higher conductivity proppants and properly selected surfactant packages result in longer effective frac lengths and greater normalized oil and gas production. Correlations are made between the observed relative perms in the lab vs. the observed field results.

Abstract In recent years numerous case studies documenting the use of microemulsions in hydraulic fracturing of tight gas formations have appeared in the literature. Field case studies and supplemental laboratory data have illustrated that microemulsions enhance core permeability to gas and enhance fluid flowback mainly due to lowering capillary pressure and altering wettability in reservoirs and propped fractures. Although proven successful for enhancing gas production, many aspects of the microemulsion behavior in propped fractures are still poorly understood. In the present study we have performed numerous experiments on microemulsion-assisted fluid recovery from columns packed with sand proppant and shale, using microemulsions of different chemical composition. Our results indicate that the extent to which microemulsion additives promote foaming is an important factor in achieving highest possible levels of fluid recovery. By using properly formulated microemulsion compositions one can achieve significant improvement in fluid recovery at commercially viable doses of treatment.

Abstract In recent years a number of laboratory studies on the use of surfactants and microemulsions in hydraulic fracturing of shale formations have been reported. These studies mainly focused on such metrics as improvement in permeability regain and enhancement of fluid recovery from packed columns upon the use of surfactant-containing chemicals. Laboratory studies have also been backed by the documented observations from the field illustrating benefits of using microemulsions for the increase in gas production from shale formations. It is a commonly accepted view that these additives benefit gas production by lowering capillary pressure and altering wetability of shale formation. Although it is recognized that the interaction of surfactants and microemulsions with shale is governed by the energetics of solid/liquid, liquid/gas and solid/gas interfaces, there are practically no studies in which surface energies have been determined for different shales. The surface energy, as well as dispersive, non-dispersive, Lifshitz-van der Waals, and Lewis Acid-Lewis Base components of surface energy of several North American shales have been determined from contact angle measurements. It has been discovered that the surface energy of all shale rocks is rather low, typically in the range of 40-50 mJ/m2 a contribution from non-dispersion ("polar") component of about 8-11 dyn/cm. Consequently, shales are capable of interacting with liquids predominantly via dispersion and Lifshitz-van der Waals molecular interactions, which should substantially influence the orientation of surfactant molecules and microemulsion moieties at the shale surface. Furthermore, there was no significant variation in surface energy of shales from different basins, which suggests that individuality of shale surface chemistry should play only a secondary role in the development of shale-specific chemical treatments, and factors other than surface chemistry should be considered first.