Microemulsion Effects on Oil Recovery From Kerogen Using Molecular-Dynamics Simulation Khoa Bui and I. Yucel Akkutlu, Texas A&M University, and Andrei S. Zelenev, W. A. Hill, Christian Griman, Trudy C. Boudreaux, and James A. Silas, Flotek Industries 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 tech- nologies. 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 chemi- cal 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 (C 12 E 7 ), respectively. MD simulation experiments include two stages: injection of an aqueous-phase microemulsion treatment fluid into the oil-saturated kerogen pore network, and tran- sient flowback of the fluids in the pore network. The used 3D kerogen models were developed using a representative oil-sample compo- sition (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 sol- vent 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. Introduction Source-rock reservoirs are characteristically fine-grained, laminated, fissile, and rich in organic matter (Potter et al. 2004; Loucks et al. 2012). During burial and diagenesis processes, organic matter is converted into kerogen. Over a long maturation time accompanied by high pressure and temperature, kerogen is converted into hydrocarbons. Thermal maturation defines the degree to which a source rock has been exposed to a high heat environment needed to convert kerogen into hydrocarbons (Palciauskas and Domenico 1980). More so than time, different degrees of maturity as well as oil migration are responsible for different hydrocarbon properties and composition. During hydrocarbon generation, a complex multiscale pore structure develops. The combination of kerogen pores, inorganic (clay-like) matrix pores, and microfractures permits oil and gas transport within the source rock (Loucks et al. 2012). Several recent studies have focused on establishing an understanding of the organic material and mineral composition of source rocks, as well as the molecular structure of kerogen. The latter has been investigated by several experimental techniques, such as solid- state nuclear magnetic resonance and X-ray photoelectron spectroscopy (Orendt et al. 2013; Ungerer et al. 2015; Bousige et al. 2016). A typical average pore size in kerogen has been estimated at just a few nanometers (Adesida et al. 2011). Scanning-electron- microscopy images indicated the presence of organic and inorganic pores in the shale matrix. In general, kerogen content within the source rocks can be as high as 20 wt%, whereas the kerogen pores can contribute up to 50% of the total pore volume (Akkutlu and Fathi 2012). Hence, kerogen could be important for the production of hydrocarbons (Josh et al. 2012; Kou et al. 2016). The pore network of source rocks has features that cover multiple dimensions and extend over several orders of magnitude. Hydrocarbon-fluid mass transport from microfractures and matrix porosity can be described by using existing theories of multiphase/ multicomponent fluid flow in a porous medium. In contrast, transport within the kerogen porosity cannot be described using the existing theories (Falk et al. 2015). Transport in kerogen pore space can be improved by the targeted use of chemistry during hydraulic fractur- ing (Bui et al. 2016; Kou et al. 2016). During the hydraulic-fracturing and shut-in periods, the adsorption of injected surface-active stimulation chemicals takes place at various interfaces and results in the alteration of interfacial tension and wettability. If the chemical treatment contains a solvent, addi- tional mobilization of oil is possible. There are numerous examples demonstrating a successful use of microemulsion additives for increasing the production of oil and gas (Champagne et al. 2011; Penny et al. 2012). Fig. 1 shows the hydrocarbon production in barrels of oil equivalent (BOE) normalized over the proppant amount per lateral length for a 12-month period (Fig. 1a) and the change in the gas/oil ratio over the same production period (Fig. 1b) for wells in a Type II kerogen source rock. The data in Fig. 1 indicate that using microemulsion increases the amount of produced oil and gas and significantly decreases the gas/oil ratio, which indicates that Copyright V C 2019 Society of Petroleum Engineers This paper (SPE 191719) was accepted for presentation at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, USA, 24–26 September 2018, and revised for publication. Original manuscript received for review 7 August 2018. Revised manuscript received for review 18 February 2019. Paper peer approved 12 March 2019. 2019 SPE Journal 1