分子模拟在油田中的应用

页岩气作为一种重要的非常规天然气资源，在全球能源结构中占据越来越重要的地位。在页岩气的开发过程中，气体在页岩中的吸附行为对气藏评估和开发方案的制定至关重要。本文综述了页岩气藏中二氧化碳与甲烷的竞争吸附机理、影响因素、实验研究进展、数值模拟方法及其实际应用，并对未来研究方向进行了展望。

伴随石油开采技术的持续革新，渗吸采油技术因开发低渗油藏的优势渐成研究热点。但纳米乳液在低渗储层的吸附行为及吸附改性效果的主控因素尚不明确，制约其应用。本研究通过渗吸驱油实验，探究了不同条件下纳米乳液在低渗储层的吸附特性及其对驱油效率的影响规律，明确了其影响因素。研究结果表明：影响纳米乳液吸附性能的因素包括温度、纳米乳液浓度、岩心长度、边界开放程度等因素，温度增大10℃，渗吸驱油效率增加幅度达到3%；相同实验条件下，0.3%浓度的纳米乳液要比0.1%浓度的纳米乳液渗吸驱油效率高4%；岩心长度越短，渗吸速率反而最快，最终采出程度最高；边界开放程度越高，渗吸速率越快，其最终采出程度按大小排序为：全开放 > 两端封闭 > 两端开放。

研究微尺度条件下的液体流动规律对于高效开发低渗透油气资源有着重要意义。本文实验研究了低速条件下去离子水和正十六烷在内径分别为18.5 μm、9.6 μm和4.1 μm的石英微圆管内的流动特性。实验结果显示当流速范围在0.01 mm/s~1 mm/s时，微管道内的液体压降与平均流速呈线性关系，微圆管内的实际流动阻力与经典流体力学的层流流动理论基本吻合，该结果说明对于直径大于4 μm的微管道内的牛顿流体流动，固壁不动边界层的影响可以忽略，并没有出现流动阻力随着流速降低而减小的达西非线性现象以及明显的启动压力现象。

针对稠油油田蒸汽吞吐开发中稠油乳化现象严重影响开采效果的问题以及油包水型乳状液形成规律及影响因素不明确的问题，本文运用文献分析的方法，基于油层物理、流体力学及渗流理论，通过分析乳状液中乳化活性组分的界面作用机制，结合文献中温度、含水率、原油组成等关键参数的实验观测数据，开展蒸汽吞吐条件下W/O乳状液形成规律及影响因素的研究。调研中明确了W/O乳状液的形成需油水两相、表面活性物质及乳化能量三个必要条件；揭示了原油黏度、含水率、温度、盐浓度及分散相粒径等因素对乳状液稳定性与物性参数的影响规律；明确了W/O乳状液深褐色至黑色、热力学不稳定但动力学稳定的物理性质，及其黏度、凝点、屈服应力随含水率和温度变化的特征。研究还表明，W/O乳状液的高黏度性与低流动性会阻碍原油渗流，需针对性调控其形成。研究成果深化了对蒸汽吞吐中W/O乳状液形成原因的理解，为提高采收率提供了科学依据，对稠油油田高效开发具有重要的指导意义。

近年来，随着页岩气开发与研究的兴起，研究纳米尺度下多孔介质中的渗流问题成为了流体力学界关注的焦点。这是因为在空隙中页岩气的流动规律与页岩的孔隙大小是紧密相关的。在纳米尺度下研究受限空间中水的动力学机制，利用水受限于几何平板这样的模型是十分有必要的。本文利用分子动力学模拟水分子在受限的环境下，构造两块彼此平行的石墨烯平板，改变两平板间的距离，观察水的流量与密度的变化。我们的研究观察到流体的动力学行为与经典微管中的poiseuille流中的是非常不同的。从1 nm到2 nm之间水的密度分布发生了很大的变化；从4 nm到5 nm之间水的速度以及氢键分布都发生了很大的变化。我们认为在受限空间中，几何平板之间距离的大小对水分子动力学行为的影响是比较大的，并且这种变化是非线性的。

吸附气是页岩气赋存在页岩储层中的主要方式之一，而且吸附气是页岩气后期产量的主要来源，页岩储层甲烷高温高压条件下的赋存特征是准确评估页岩气储量的关键。依据四川盆地五峰组——龙一1亚段页岩无机地球化学特征，构建了石英、干酪根和复合孔组成的有机质——石英复合孔隙体系分子模型。通过巨正则蒙特卡洛(GCMC)、分子动力学(MD)和非平衡分子动力学(EFMD)模拟方法，研究了甲烷分子在复合孔隙体系中的微观赋存特征及其流动扩散特征。研究结果显示，随着压力的升高，赋存于孔隙空间中的甲烷分子增多，同时其扩散能力受到限制(压力越大，扩散系数越小)，且赋存的甲烷分子数量随着孔径的增大而增多；孔隙壁面附近存在明显密度峰值，峰值随着压力的升高而增大；采用外力法模拟施加压降，外力的增大会提升甲烷在孔隙中的流速，且赋存空间(孔径)越大，甲烷在孔隙中的流速越大。在开采过程中制造较大的压差，更有利于甲烷从页岩储层中脱离出来。

孔径及孔径分布是多孔材料的重要性质之一，通过介绍包括Barrett-Joyner-Halenda (BJH)法、Horvath-Kawazoe (HK)法、Saito-Foley (SF)法和NLDFT (非定域密度泛函理论)多种孔径分析的理论模型，总结了每种模型的优缺点及适用条件。结果表明，BJH法只能适用于分析柱状的介孔材料(5 nm < 孔径 < 50 nm)；HK法只适用于分析含狭缝孔的微孔活性炭材料；SF法适用于根据氩气吸附等温线分析圆柱型微孔材料；NLDFT法不仅适用于分析微孔材料的孔径分布，还可以分析微介孔复合材料孔径分布，具有更广的应用范围及前景。

微纳米页岩基质孔内气水关系复杂，现有的页岩气表观渗透率模型通常只考虑单相气，且存在作用机理考虑不全面、模型构建方法不准确等问题，导致不能合理地揭示页岩基质传质规律。本文基于基质孔中气–水–固三者之间相互作用，建立了考虑页岩气吸附、应力敏感效应、基质收缩效应和束缚水饱和度等多种因素共同影响下的页岩气表观渗透率模型，进行了基质孔表观渗透率敏感性参数分析。结果表明：基质孔表观渗透率与应力敏感系数和束缚水饱和度呈负相关；表面扩散贡献率与压力和孔径呈负相关关系；黏性流贡献率与压力和孔径呈正相关关系。

我国深层页岩气储量占比大，明确深层页岩气吸附规律对于准确评价深层页岩气储量具有十分重要的意义。然而，深层页岩储层温度压力高，远超实验测试范围，导致深层页岩气吸附规律尚不清楚。因此，采用分子模拟技术构建深层页岩干酪根模型，模拟深层页岩甲烷高温高压吸附行为，揭示深层页岩气储层原位吸附规律，在此基础上，研究了深层页岩气等温吸附数学模型。结果表明：随着温度的增加，深层页岩气吸附量减少；随着压力的增加，深层页岩气吸附量呈现先快后慢的增加，并在高压段趋于平缓；通过采用Langmuir模型、Freundlich模型以及Langmuir-Freundlich模型对模拟数据进行拟合，明确了Langmuir-Freundlich模型能够更好描述深层页岩气吸附规律。

本文首先简要回顾了原油破乳剂的发展历程，然后对影响乳状液稳定的影响因素进行了分析，从而阐述了原油破乳剂的作用机理，接着对原油破乳的主要类型及其应用特点进行了综述，最后对原油破乳剂的发展进行了展望。

随着全球经济与社会的持续发展以及人民生活水平的不断提高，能源消费需求持续增长。目前，全球能源消耗仍主要依赖于石油、天然气和煤炭等化石燃料。然而，随着石油开采年限的延长和开采规模的不断扩大，稠油(重质原油)在能源结构中的重要性日益凸显。由于稠油黏度高、开采难度大，有效降低其黏度成为提升稠油资源利用率的关键环节之一，旨在显著改善其流动性。在多种输送方式中，管道输送占据重要地位，因此稠油乳状液的稳定性成为影响输送效率的核心因素。本研究从多角度探讨蜡组分对乳化体系稳定性的作用机制，相关结论可为乳化降黏技术的进一步深入研究提供参考与支撑。

稠油中的胶质和沥青质易吸附并聚集在岩石中，导致稠油粘度大、流动性弱，给稠油开采、运输造成严重的困难。SiO2纳米材料形成的硅烷醇基对沥青质的亲和力较高，可以分解沥青质聚集体，改变沥青质胶体结构，从而降低稠油粘度。室内通过对比不同粒径的纳米SiO2材料，在不同粒径、不同浓度、不同温度和剪切速率下，评价了纳米SiO2材料对稠油粘度的影响。试验结果表明，浓度为1000 mg/L，粒径为6 nm的SiO2纳米能较大幅度地降低稠油粘度，稠油粘度降低率超过40%，且提高温度及高剪切速率有利于降低稠油粘度。表明了SiO2纳米粒子有效防止沥青质聚集体的形成，起到分散沥青的作用，达到降低稠油粘度的目的。

本研究设计合成了一种具有温敏型开关特性、表面活性的共聚物(THFAA-NIPAM-PEGMA)，是一种可以仅通过改变温度就可以控制其乳化/破乳性质的新型表面活性剂。通过表面张力、界面张力以及乳化性能测试，表明了其具有良好的表面活性及乳化能力。通过表观温敏性、透光率曲线，以及不同温度下界面张力的比较，表明了其具有温度敏感特性，并阐述了温敏机理。通过乳化/破乳测试，表明了其具有温敏开关乳化/破乳特性。

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Interlayer heterogeneity, an inevitable and complex challenge during water flooding, seriously constrains the spread of the sweep region and oil recovery enhancement in multilayered heterogeneous reservoirs. To overcome this challenge, a novel polymeric surfactant, having an excellent performance in the reduction of interfacial tension (IFT) and the increase of viscosity of displacing fluid, is applied for enlarging the sweep resonance and increasing the oil washing efficiency. Through the molecular dynamics (MD) simulation, the molecular distributing mechanisms of the polymeric surfactant at the oil–water interface are analyzed to provide the theoretical basis for explaining the microscopic mechanism of oil extraction. To directly reflect the microscopic behavior of oil extraction, multiple transparent sand-packed models are designed to investigate the flowing behavior of different fluids and the extracted mechanisms of the remaining oil in both pore and macroscales. The multilayered heterogeneous reservoirs consisting of high-, moderate-, and low-permeability layers are fabricated to represent a heterogeneous characteristic. The recognition from the visual experiment and MD simulation can study the performance control, the extracting performance of the remaining oil, and the expression of the displacing front from different perspectives. The results from MD simulation demonstrate that the polymeric surfactant can promote the disintegration of the remaining oil and enhance its mobility. The experimental results indicate that the sweep efficiency is restricted by viscous fingering and tongue advance. Through the analysis of mathematical models, the rising mobility ratio and the location of the displacing front have a strong positive relationship with viscous fingering and tongue advance, which can reasonably explain the plugging performance of the polymeric surfactant, greatly improving the sweeping effect of the whole reservoir. Moreover, the Marangoni effect generated by the IFT gradient can induce the transformation of interfacial energy to displacement kinetic energy by the emulsification of the oil–water interface so that the remaining oil in the blind-end pore can be effectively extracted. However, by comparing data from image quantification techniques and production dynamic performance, the sweep efficiency (484%) was significantly greater than that of oil recovery (300%), demonstrating that the expanded sweep effect still plays a dominant role in the extraction of remaining oil after polymeric surfactant flooding. This study provides a novel plugging and effective washing agent that is expected to be an excellent and comprehensive method for solving the problem of low oil recovery in multilayered heterogeneous reservoirs.

Hydrogen (H2) underground storage has attracted considerable attention as a potentially efficient strategy for the large-scale storage of H2. Nevertheless, successful execution and long-term storage and withdrawal of H2 necessitate a thorough understanding of the physical and chemical properties of H2 in contact with the resident fluids. As capillary forces control H2 migration and trapping in a subsurface environment, quantifying the interfacial tension (IFT) between H2 and the resident fluids in the subsurface is important. In this study, molecular dynamics (MD) simulation was employed to develop a data set for the IFT of H2–brine systems under a wide range of thermodynamic conditions (298–373 K temperatures and 1–30 MPa pressures) and NaCl salinities (0–5.02 mol·kg–1). For the first time to our knowledge, a comprehensive assessment was carried out to introduce the most accurate force field combination for H2–brine systems in predicting interfacial properties with an absolute relative deviation (ARD) of less than 3% compared with the experimental data. In addition, the effect of the cation type was investigated for brines containing NaCl, KCl, CaCl2, and MgCl2. Our results show that H2–brine IFT decreases with increasing temperature under any pressure condition, while higher NaCl salinity increases the IFT. A slight decrease in IFT occurs when the pressure increases. Under the impact of cation type, Ca2+ can increase IFT values more than others, i.e., up to 12% with respect to KCl. In the last step, the predicted IFT data set was used to provide a reliable correlation using machine learning (ML). Three white-box ML approaches of the group method of data handling (GMDH), gene expression programming (GEP), and genetic programming (GP) were applied. GP demonstrates the most accurate correlation with a coefficient of determination (R2) and absolute average relative deviation (AARD) of 0.9783 and 0.9767%, respectively.

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Methane is the main component of shale gas and is adsorbed in shale pores. Methane adsorption not only affects the estimation of shale gas reserves but also reduces extraction efficiency. Therefore, investigating the behavior of methane adsorption in shale reservoirs is important for evaluating shale gas resources, as well as understanding its desorption and displacement from the nanochannels of shale gas reservoirs. In this research, molecular dynamics simulations were used to investigate the adsorption behavior of methane gas in organic shale pores made of graphenylene, followed by its displacement by CO2 and N2 injection gases. The effects of pore size, pressure, and temperature on adsorption were examined. It was observed that increasing the pore size at a constant pressure led to a decrease in the density of adsorbed methane molecules near the pore surface, while a stable free phase with constant density formed in the central region of the nanopore. Moreover, adsorption increased with increasing pressure, and at pressures ranging from 0 to 3 MPa, 15 and 20 Å pores exhibited lower methane adsorption compared to other pores. The amount of adsorption decreased with increasing temperature, and the observed adsorption isotherm followed the Langmuir adsorption isotherm. The mechanism of methane displacement by the two injected gases differed. Carbon dioxide filled both vacant adsorption sites and directly replaced the adsorbed methane. On the other hand, nitrogen only adsorbed onto the vacant sites and, by reducing the partial pressure of methane, facilitated the displacement of methane.

The strong solid-liquid interaction leads to the complicated occurrence characteristics of shale oil. However, the solid-liquid interface interaction and its controls of the occurrence state of shale oil are poorly understood on the molecular scale. In this work, the adsorption behavior and occurrence state of shale oil in pores of organic/inorganic matter under reservoir conditions were investigated by using grand canonical Monte Carlo (GCMC) and molecular dynamics (MD) simulations. The adsorption potential energy and interaction energy were quantitatively evaluated, and the control mechanism of the oil-rock interaction on shale oil occurrence was explained. Results show that the density distribution of shale oil is not uniform under the confined space. Multiple layers of adsorption of n-octane occur in graphene pores. The number of adsorbed layers is mainly affected by pore size. With the increasing temperature and pore size, the adsorption site shifts from the high-energy to low-energy site and the solid-liquid interaction weakens. The effect of pressure on the occurrence state can be ignored due to capillary condensation. Minerals and oil chemical compositions also affect the oil-rock interaction and occurrence state. The adsorption intensity of minerals to n-octane decreases in the order graphene > montmorillonite > quartz. Competitive adsorption occurs among oil components. The adsorption order of oil components in graphene is asphaltenes > resin > nonhydrocarbon compound > aromatic hydrocarbons > saturated hydrocarbons. Asphaltenes preferentially adsorb on the surface of organic matter and occupy most of the adsorption surface, while saturated hydrocarbons mainly adsorb on the surface of heavy components or distribute in the pore center. The molecular structure of hydrocarbons also affects the adsorption characteristics. The long-chain hydrocarbons preferentially adsorb on the surface more than short-chain hydrocarbons. The straight-chain hydrocarbons preferentially adsorb more than the branched-chain hydrocarbons. This study provides the microscopic interaction between shale oil and minerals and explores the effect of the control mechanism of the oil-rock interfacial interaction on the occurrence state at the molecular level.

The interactions among fluid species such as H2O, CO2, and CH4 confined in nano- and meso-pores in shales and other rocks is of central concern to understanding the chemical behavior and transport properties of these species in the earth's subsurface and is of special concern to geological C-sequestration and enhanced production of oil and natural gas. The behavior of CO2, and CH4 is less well understood than that of H2O. This paper presents the results of a computational modeling study of the partitioning of CO2 and CH4 between bulk fluid and nano- and meso-pores bounded by the common clay mineral montmorillonite. The calculations were done at 323 K and a total fluid pressure of 124 bars using a novel approach (constant reservoir composition molecular dynamics, CRC-MD) that uses bias forces to maintain a constant composition in the fluid external to the pore. This purely MD approach overcomes the difficulties in making stochastic particle insertion-deletion moves in dense fluids encountered in grand canonical Monte Carlo and related hybrid approaches. The results show that both the basal siloxane surfaces and protonated broken edge surfaces of montmorillonite both prefer CO2 relative to CH4 suggesting that methods of enhanced oil and gas production using CO2 will readily displace CH4 from such pores. This preference for CO2 is due to its preferred interaction with the surfaces and extends to approximately 20 Å from them.

Nanoscale roughness of reservoir skeleton surfaces inevitably affects the CO2 geo-sequestration, and its exact microscopic mechanism remains elusive. Here, nanosecond molecular dynamics (MD) simulations were performed to investigate this effect with silica nanopore models. We classified the surface into "nano-valleys" and "nano-peaks" by the median z-coordinate of surface atoms and further divided nanovalleys into shallow and deep types. The results demonstrate that the nanovalleys can trap CO2 molecules, resulting in lower CO2 diffusivity and higher local concentration compared to nanopeaks. Generally, the total CO2 quantity on nanovalleys and nanopeaks is increasing as surface roughness increases. A further exploration shows that the CO2 concentration of the deep valley is always higher than that of the shallow valley under the same degree of roughness and exhibits an increasing trend as surface roughness increases. Furthermore, CO2 molecules enter nanovalleys vertically and adsorb parallel to the surface, while water molecules orient randomly. In a high CO2 concentration system, CO2 nanobubbles are observed in nanovalleys. The nanobubbles are smaller but more numerous as the surface roughness increases. In a dual-phase system, the boundary between CO2 and liquid phases connects the nanopeaks of top and bottom layers, embedding the CO2 phase in concaves, which indicates the restrictive effect of nanopores on the CO2 phase. These molecular insights confirm the accumulation and retention of prestored CO2 due to nanoscale roughness on the reservoir surface.

Enhanced oil recovery (EOR) plays a critical role in optimizing oil extraction from existing fields to satisfy global energy demands while mitigating environmental impact. One promising EOR technique involves injecting water with reduced surface tension utilizing deep eutectic solvents (DESs). Despite early experimental support, the efficacy of aqueous-DES EOR varies and depends on factors such as connate water saturation, water salinity, and reservoir wettability. The recovery mechanisms for aqueous DESs are poorly understood due to the intricate nature of oil components and reservoir formation. In this paper, we investigate the role of DESs in the EOR process through molecular dynamics (MD) simulations. Three different types of DES molecules, such as choline chloride : urea (ChCl : U), choline chloride : ethylene glycol (ChCl : EG), and menthol : salicylic acid (M : SA) are used, for the recovery of dodecane (C12H26) oil from silica and calcite confined surfaces. We have demonstrated the structural characteristics of these systems by examining various physical properties, including interaction energies, density profiles, hydrogen bonds, and interfacial tension (IFT). Different concentrations (10 and 25 wt%) of DESs have been considered to unravel the effect of concentration on oil removal. The wettability of the substrate and the IFT between oil and aqueous DESs are critical physical properties that play a crucial role in influencing EOR phenomena. The IFT between water and oil decreases with the addition of DESs for all DES molecules, leading to a shift in surface behavior from oleophilic to oleophobic and ultimately facilitating the removal of oil from the substrate. Additionally, hydrogen bond formation between DESs and water has been calculated to elucidate its influence on the water/oil interface and substrate wettability. The study provides insights into the fundamental aspects of EOR processes for more effective and sustainable oil extraction.

Underground hydrogen (H2) storage has become increasingly popular in recent years; however, H2 leakage is a critical concern. A conventional reservoir is sealed by a dense caprock; the long-chain hydrocarbons cannot escape through the caprock because of the complex molecular structure and large molecular size, but H2 leakage can still occur, particularly through the nanopores of the caprock. In this study, we investigate the H2 leakage problem using the molecular dynamics (MD) and MD–Monte Carlo (MDMC) methods. The results of our MDMC algorithm concur with the MD simulation results, indicating that the MDMC algorithm can feasibly predict the H2 leakage process. Caprock defects are repaired by water (H2O) clusters owing to the hydrogen bonding and adsorption of H2O on the caprock surface. Methane (CH4) forms an absorption layer on the caprock, inhibiting the probability of contact between H2 and the rock surface. We further explain the spatial distribution of different gas components using their potential energies and interaction forces. The molecular sealing mechanism is also proposed accordingly, and the H2O cluster and CH4 adsorption layer form the double barrier for H2 leakage. The evaporation of H2O at high temperatures weakens the stability of the H2O cluster, and smaller pore sizes (<10.0 Å) within the caprock prevent H2 leakage. H2 leakage can be further inhibited by increasing the H2O content in a H2 storage project. Thus, a specific amount of H2O and CH4 gas can alleviate the H2 leakage problem.

Interest in nanomaterials for subsurface applications has grown markedly due to their successful application in a variety of disciplines, such as biotechnology and medicine. Nevertheless, nanotechnology application in the petroleum industry presents greater challenges to implementation because of the harsh conditions (i.e. high temperature, high pressure, and high salinity) that exist in the subsurface that far exceed those present in biological applications. The most common subsurface nanomaterial failures include colloidal instability (aggregation) and sticking to mineral surfaces (irreversible retention). We previously reported an atomic force microscopy (AFM) study on the calcium-mediated adhesion of nanomaterials in reservoir fluids (S. L. Eichmann and N. A. Burnham, Sci. Rep. 7, 11613, 2017), where we discovered that the functionalized and bare AFM tips showed mitigated adhesion forces in calcium ion rich fluids. Herein, molecular dynamics reveal the molecular-level details in the AFM experiments. Special attention was given to the carboxylate-functionalized AFM tips because of their prominent ion-specific effects. The simulation results unambiguously demonstrated that in calcium ion rich fluids, the strong carboxylate-calcium ion complexes prevented direct carboxylate-calcite interactions, thus lowering the AFM adhesion forces. We performed the force measurement simulations on five representative calcite crystallographic surfaces and observed that the adhesion forces were about two to three fold higher in the calcium ion deficient fluids compared to the calcium ion rich fluids for all calcite surfaces. Moreover, in calcium ion deficient fluids, the adhesion forces were significantly stronger on the calcite surfaces with higher calcium ion exposures. This indicated that the interactions between the functionalized AFM tips and the calcite surfaces were mainly through carboxylate interactions with the calcium ions on calcite surfaces. Finally, when analyzing the order parameters of the tethered functional groups, we observed significantly different behavior of the alkanethiols depending on the absence or presence of calcium ions. These observations agreed well with AFM experiments and provided new insights for the competing carboxylate/calcite/calcium ion interactions.

Chemical enhanced oil recovery (EOR) using polymers has been very successful in reservoirs with favorable reservoir environments. However, chemical flooding in high-temperature (HT; 80°C), high-salinity (30,000 ppm) reservoirs faces challenges due to poor polymer/surfactant stability. Despite numerous studies on polymer-based EOR fluids, limited attention has been given to hybrid systems combining surfactants, hydrophobically associated polymers, and nanoparticles. In this work, a combination of experimental and molecular dynamics (MD) simulation methods was used to develop and evaluate a hybrid nanofluid using hydrophobically associative polymer (HAP; AP-P4), surfactant [sodium dodecylsulfate (SDS)], and silica nanoparticles (SiO2). The optimal formulation (0.18% AP-P4, 0.3% SDS, 0.1% SiO2) exhibited strong stability (zeta potential = −32 mV), reduced interfacial tension (IFT; 0.42 mN/m), and wettability alteration (θ = 116−23°). The comparison of Fourier transform infrared spectroscopy (FTIR) spectra of pure SiO2, AP-P4 with hybrid fluid highlighted the physical rather than chemical interaction in the nanofluid. Viscosity loss of only 38.2% under HT conditions was recorded. Furthermore, MD simulation parameters, such as radial distribution function (RDF), mean square displacement (MSD), and binding energy, revealed strong AP-P4 and SiO2 interactions, improving stability and viscoelasticity, while AP-P4 and SDS enhance injectivity. Coreflooding tests showed a 14.1% oil recovery increase post-waterflooding, with good injectivity (resistance factor = 1.54, residual resistance factor = 1.15) and minimal permeability damage. This hybrid nanofluid offers a promising EOR solution for HT and high-salinity reservoirs, combining stability, mobility control, and improved displacement efficiency.

In alkali/surfactant/polymer (ASP) flooding systems, alkalis react with clay minerals such as Illite, montmorillonite, and kaolinite, leading to reservoir damage and impacting oil recovery rates. Therefore, studying the dissolution effects of strong alkalis on clay minerals is crucial for improving oil recovery. This study uses Illite as a representative clay mineral and employs the ReaxFF reactive force field and molecular dynamics simulations to model its dissolution in NaOH solution. We investigated the diffusion coefficients of metal cations in Illite and their interactions with hydroxide ions at various NaOH concentrations. The study also explores the evolution of dissolution products and protonation characteristics during the dissolution of Illite. By calculating the changes in ionic energy throughout the dissolution process, we analyzed variations in ionic reactivity within the system. Simulation results show that as the NaOH concentration increases, metal cations in Illite form stable chemical bonds with hydroxide ions, creating highly aggregated clusters with strong ionic interactions that hinder migration. Consequently, the diffusion coefficients of metal cations gradually decrease. During the reaction, water dissociates to produce hydrogen ions and hydroxide ions. Ion exchange occurs between the solution cations and Illite cations. Illite cations gradually precipitate and form metal hydroxides by combining with hydroxide ions under electrostatic forces. Protonation propagates from the surface to the internal structure during the reaction. Moreover, the degree of protonation increases with higher NaOH concentrations. Changes in the average ionic energy before and after the reaction indicate that K+ exhibits the highest reactivity. Intermediate silicate products are unstable in NaOH solution, with some Si4+ ions showing higher energy and stronger reactivity.

Ion partitioning between different compartments (e.g., a porous material and a bulk solution reservoir), known as Donnan equilibrium, plays a fundamental role in various contexts such as energy, environment, or water treatment. The linearized Poisson-Boltzmann (PB) equation, capturing the thermal motion of the ions with mean-field electrostatic interactions, is practically useful to understand and predict ion partitioning, despite its limited applicability to conditions of low salt concentrations and surface charge densities. Here, we investigate the Donnan equilibrium of coarse-grained dilute electrolytes confined in charged slit-pores in equilibrium with a reservoir of ions and solvent. We introduce and use an extension to confined systems of a recently developed hybrid nonequilibrium molecular dynamics/grand canonical Monte Carlo simulation method ("H4D"), which enhances the efficiency of solvent and ion-pair exchange via a fourth spatial dimension. We show that the validity range of linearized PB theory to predict the Donnan equilibrium of dilute electrolytes can be extended to highly charged pores by simply considering renormalized surface charge densities. We compare with simulations of implicit solvent models of electrolytes and show that in the low salt concentrations and thin electric double layer limit considered here, an explicit solvent has a limited effect on the Donnan equilibrium and that the main limitations of the analytical predictions are not due to the breakdown of the mean-field description but rather to the charge renormalization approximation, because it only focuses on the behavior far from the surfaces.

The structure H (sH) of methane hydrate, which has a distinctive structure with large (LL) cages capable of encapsulating multiple methane molecules, has been suggested as a methane reservoir in large icy bodies such as Titan, making it important in planetary science. This high-pressure phase, which exists in the GPa range, lends itself to the study of methane states and dynamics using powerful experimental techniques such as IR and Raman spectroscopy. However, the interpretation of the vibrational spectra of methane in the sH structure has been challenging because of the spectral complexities. The signals attributed to the methane molecules in the LL cage, as well as those of the other two cage types, overlap in the spectra. In this study, we investigated the microscopic origins of the shape of the C-H stretching vibration spectrum of methane in the LL cage using ab initio molecular dynamics (AIMD) simulations. For a single methane molecule in the LL cage, the ν3 band of the C-H stretching mode was observed at a higher frequency typical of isolated molecules in vacuum due to the large size of the LL cage. As the number of methane molecules in the LL cage increased beyond one, a tendency to blue-shift with increasing methane occupancy was observed, consistent with a loose-cage-tight-cage model. By characterizing the time correlation function of methane stretching vibrations based on the solvation number of methane and water molecules proximal to methane within the LL cage, we showed that the complicated spectral line shape observed in cases of higher methane occupancy in the LL cage resulted from the wider variation of the solvation shell states. Analysis of the solvation structures of the AIMD trajectories provided interpretations of the experimental spectral line shape, demonstrating the complementary nature of AIMD to the experiment and its effectiveness in analysis.

Abstract The high viscosity and poor fluidity of heavy oil challenge its extraction, leading to the widespread use of surfactant emulsification to reduce viscosity and enhance recovery. This study evaluated three surfactants—sodium dodecyl sulfate (SDS), sodium oleate (SO), and APG0810—for their suitability and effectiveness in the X reservoir. The solution properties of these surfactants were analyzed and their micro-mechanisms investigated using MD calculations. The effects of surfactant concentration and additives on emulsification and viscosity reduction were elucidated. Ultimately, a system for emulsification and viscosity reduction was selected for physical simulation research. The experimental findings show that SO reduces interfacial tension from 52.4 mN/m to 0.0027 mN/m, transforming lipophilic surfaces into hydrophilic. MD analyses reveal SO’s optimal interfacial properties, with the lowest interfacial energy of −6423.4 kcal/mol, maximum interfacial thickness of 2.56 nm, and minimal diffusion coefficient of 0.4087 Å2/ps at the oil-water interface. These findings align with experimental results, confirming SO’s superior interfacial properties. Combining 0.3% SO with 0.5% n-pentanol results in a 98% viscosity reduction. The emulsion shows excellent stability, with no water separation in the first 30 min and only 8.3% after 2 h. Physical simulation results show that in high(low) permeability core displacement experiments, system flooding and subsequent water flooding can increase recovery rates by 15.39%(36.91%), indicating the system’s potential for enhancing oil recovery in Reservoir X. The findings suggest that the implementation of this system not only boosts the crude oil recovery rate but also carries economic significance in the industry. GRAPHICAL ABSTRACT

Carbon dioxide (CO2) drive is one of the effective methods to develop old oil fields with high water content for tertiary oil recovery and to improve the recovery rate. However, due to the low viscosity of pure CO2, it is not conducive to expanding the wave volume of the mixed phase, which leads to difficulty utilizing the residual oil in vertical distribution and a low degree of recovery in the reservoir. By introducing viscosity enhancers, it is possible to reduce the two-phase fluidity ratio, expanding the degree of longitudinal rippling and oil recovery efficiency. It has been proven that the acetate scCO2 tackifier PVE can effectively tackify CO2 systems. However, little research has been reported on the microscopic viscosity enhancement mechanism of scCO2 viscosity enhancers. To investigate the influence of a vinyl acetate (VAc) functional unit on the viscosity enhancement effect of the CO2 system, PVE (Polymer–Viscosity–Enhance, P-3) was used as the parent, the proportion of VAc was changed, and the molecules P-1 and P-2 were designed to establish a molecular dynamics simulation model for the P-n-CO2 system. The molecules in the system under the conditions of 70 °C-10 MPa, 80 °C-10 MPa, and 70 °C-20 MPa were simulated; the viscosity of the system was calculated; and the error between the theoretical and simulated values of the viscosity in the CO2 system was relatively small. The difference between P-n molecular structure and system viscosity was analyzed at multiple scales through polymer molecular dynamics simulations and used the molecular radial distribution function, system density, accessible surface area, radius of gyration, minimum intermolecular distance, and minimum number of intermolecular contacts as indicators. This study aimed to elucidate the viscosity enhancement mechanism, and the results showed that the higher the proportion of VAc introduced into the molecules of P-n-scCO2 viscosities, the larger the molecular amplitude, the larger the effective contact area, and the greater the viscosity of the system. Improvement in the contact efficiency between the ester group on the P-n molecule and CO2 promotes the onset of solvation behavior. This study on the microscopic mechanism of scCO2 tackifiers provides a theoretical approach for the design of new CO2 tackifiers.

This study investigates the influence of physical parameters such as porosity, permeability, pore-throat radius, and specific surface area/volume on the adsorption capacity of surfactants in the pore surface of reservoirs. In the meantime, the hydraulic fracturing-assisted oil displacement (HFAD) technique can effectively improve the permeability and porosity of pores in the reservoir, which may affect the adsorption capacity of surfactants in low-permeability reservoirs. This may help to reduce the adsorption loss of surfactants in low-permeability reservoirs. Based on physical simulation methods, dynamic adsorption experiments were conducted to clarify the dynamic saturation adsorption capacity effect of high-pressure and low-pressure displacement agents by the HFAD technique. In addition, the molecular dynamics simulation method was used to study the effect of high-pressure conditions of HFAD on the adsorption capacity of surfactants on weakly lipophilic silica walls. Under the condition of high injection pressure by the HFAD technique, the fluid flow velocity and the initial kinetic energy of molecules increase, while the absolute value of the electrostatic potential energy in the system decreases. In addition, the van der Waals potential energy increases. In other words, the smaller the gravitational attraction experienced by the surfactant molecules during adsorption, the greater the repulsive force. Under the dual action of electrostatic force and van der Waals forces, the absolute values of the adsorption energy and the free energy decrease. The adsorption capacity of the surfactant molecules is weakened. Moreover, the decrease in adsorption capacity has little effect on the improvement of wettability, indicating that the adsorption of the surfactant reduced by HFAD technology is mostly ineffective adsorption.

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The SAGP (steam and gas push) process is an effective enhanced oil recovery (EOR) method for heavy oil reservoirs. Understanding the microscopic interactions among steam, non-condensable gasses (NCGs), and heavy oil under reservoir conditions in SAGP processes is important for their EOR applications. In this study, molecular simulations were performed to investigate the microscopic interactions among steam, NCG, and heavy oil under reservoir conditions in SAGP processes. In addition, the microscopic EOR mechanisms during SAGP processes and the effects of operational parameters (NCG type, NCG–steam mole ratio, temperature, and pressure) were discussed. The results show that the diffusion and dissolution of CH4 molecules and the extraction of steam molecules cause the molecules of saturates with light molecular weights in the oil globules to stretch and gradually detach from one another, resulting in the swelling of heavy oil. Compared with N2, CH4 has a stronger ability to diffuse and dissolve in heavy oil, swell the heavy oil, and reduce the density and viscosity of heavy oil. For this reason, compared with cases where N2 is used, SAGP processes perform better when CH4 is used, indicating that CH4 can be used as the injected NCG in the SAGP process to improve heavy oil recovery. As the NCG–steam mole ratio and injection pressure increase, the diffusion and solubility abilities of CH4 in heavy oil increase, enabling CH4 to perform better in swelling the heavy oil and reducing the density and viscosity of heavy oil. Hence, increasing the NCG–steam mole ratio and injection pressure is helpful in improving the performance of SAGP processes in heavy oil reservoirs. However, the NCG–steam mole ratio and injection pressure should be reasonably determined based on actual field conditions because excessively high NCG–steam mole ratios and injection pressures lead to higher operation costs. Increasing the temperature is favorable for increasing the diffusion coefficient of CH4 in heavy oil, swelling heavy oil, and reducing the oil density and viscosity. However, high temperatures can result in intensified thermal motion of CH4 molecules, reduce the interaction energy between CH4 molecules and heavy oil molecules, and increase the difference in the Hildebrand solubility parameter between heavy oil and CH4–steam mixtures, which is unfavorable for the dissolution of CH4 in heavy oil. This study can help readers deeply understand the microscopic interactions among steam, NCG, and heavy oil under reservoir conditions in SAGP processes and its results can provide valuable information for the actual application of SAGP processes in enhancing heavy oil recovery.

Fluid transport across nanometric channels induced by electric, pressure, and concentration gradients is ubiquitous in biological systems and fosters various applications. In this context, computer simulation setups with well-defined open-boundary equilibrium starting states are essential in understanding and assisting experimental studies. However, open-boundary computational methods are scarce and do not typically satisfy all the equilibrium conditions imposed by reality. Namely, in the absence of external gradients, (1) the system of interest (SoI) must be at thermodynamic and chemical equilibrium with an infinite reservoir of particles; (2) the fluctuations of the SoI in equilibrium should sample the grand canonical ensemble; (3) the local solvation thermodynamics, which is extremely sensitive to finite-size effects due to solvent depletion, should be correctly described. This point is particularly relevant for out-of-equilibrium systems; and (4) finally, the method should be robust enough to deal with phase transitions and coexistence conditions in the SoI. In this study, we demonstrate with prototypical liquid systems embedded into a reservoir of ideal gas particles that the adaptive resolution simulation (AdResS) method, coupled with particle insertion/deletion steps (AdResS+PI), satisfies all these requirements. Therefore, the AdResS+PI setup is suitable for performing grand canonical and stationary non-equilibrium simulations of open systems.

In poorly consolidated carbonate rock reservoirs, solids production risk, which can lead to increased environmental waste, can be mitigated by injecting formation-strengthening chemicals. Classical atomistic molecular dynamics (MD) simulation is employed to model the interaction of polyacrylamide-based polymer additives with a calcite structure, which is the main component of carbonate formations. Amongst the possible calcite crystal planes employed as surrogates of reservoir rocks, the (1 0 4) plane is shown to be the most suitable surrogate for assessing the interactions with chemicals due to its stability and more realistic representation of carbonate structure. The molecular conformation and binding energies of pure polyacrylamide (PAM), hydrolysed polyacrylamide in neutral form (HPAM), hydrolysed polyacrylamide with 33% charge density (HPAM 33%) and sulfonated polyacrylamide with 33% charge density (SPAM 33%) are assessed to determine the adsorption characteristics onto calcite surfaces. An adsorption-free energy analysis, using an enhanced umbrella sampling method, is applied to evaluate the chemical adsorption performance. The interaction energy analysis shows that the polyacrylamide-based polymers display favourable interactions with the calcite structure. This is attributed to the electrostatic attraction between the amide and carboxyl functional groups with the calcite. Simulations confirm that HPAM33% has a lower free energy than other polymers, presumably due to the presence of the acrylate monomer in ionised form. The superior chemical adsorption performance of HPAM33% agrees with Atomic Force Microscopy experiments reported herein.

Methane hydrates are important from a scientific and industrial perspective, and form by nucleation and growth from a supersaturated aqueous solution of methane. Molecular simulation is able to shed light on the process of homogeneous nucleation of hydrates, using straightforward molecular dynamics or rare event enhanced sampling techniques with atomistic and coarse grained force fields. In our previous work [Arjun, T. A. Berendsen, and P. G. Bolhuis, Proc. Natl. Acad. Sci. U. S. A. 116, 19305 (2019)], we performed transition path sampling (TPS) simulations using all atom force fields under moderate driving forces at high pressure, which enabled unbiased atomistic insight into the formation of methane hydrates. The supersaturation in these simulations was influenced by the Laplace pressure induced by the spherical gas reservoir. Here, we investigate the effect of removing this influence. Focusing on the supercooled, supersaturated regime to keep the system size tractable, our TPS simulations indicate that nuclei form amorphous structures below roughly 260 K and crystalline sI structures above 260 K. For these temperatures, the average transition path lengths are significantly longer than in our previous study, pushing the boundaries of what can be achieved with TPS. The temperature to observe a critical nucleus of certain size was roughly 20 K lower compared to a spherical reservoir due to the lower concentration of methane in the solution, yielding a reduced driving force. We analyze the TPS results using a model based on classical nucleation theory. The corresponding free energy barriers are estimated and found to be consistent with previous predictions, thus adding to the overall picture of the hydrate formation process.

The decline in oil production has led to the development of the Enhanced Oil Recovery (EOR) technology to increase oil production. Chemical injection is one of the methods in EOR by injecting surfactants or polymers into reservoir wells. To understand the properties and dynamics of surfactants and polymers at the nanoscale, computational studies using molecular dynamics simulation were carried out. In this study, surfactant Sodium Dodecyl Benzene Sulfonate (SDBS) and polymers such as Polyacrylamide (PAM) were used to investigate their effect on the oil-water interface system at the atomic level. Molecular dynamics simulation was carried out using Large-scale Atomic/Molecular Massively Parallel Simulator (LAMMPS) to calculate the diffusion coefficient and Interface Formation Energy (IFE) value for the addition of the surfactant and polymers. The simulation results show that the addition of the surfactant and polymers affects the water-oil interface system differently. The diffusion coefficient results indicates that there are strong interactions between SDBS and dodecane with D of 0.01358. While for PAM, the interactions with water are more significant with D of 0.059. The results of the IFE calculation value also show that the addition of SDBS and PAM makes the water-oil interface system more stable with the negative IFE value of -197.51 and -13.13 Kcal/mol respectively. The results of this study will be used as a reference and a basis for designing new surfactants or polymers that will led to more oil recovery.

Coalbed methane serves as a vital clean energy resource that plays a notable role in mitigating imbalances in the energy supply and demand and improving energy structure optimization. Methane is predominantly confined within the microporous structure of coal, posing challenges for its desorption process. Comprehending the microscale flow mechanisms of methane is essential for optimizing desorption efficiency. Herein, molecular models of the coal micropore structures were developed by using experimental techniques to investigate their adsorption characteristics and the adsorption/diffusion behavior of methane. The findings reveal that most of the coal micropores are smaller than 10 nm, with the highest concentration observed in the 2–4 nm range. The adsorption capacity of the gas decreases with increasing temperature, while it increases with the pressure and the degree of coal metamorphism. Methane adsorbed in the coal matrix pores has a lower propensity for desorption than methane in the coal body pores. Additionally, gas diffusion in pore-free spaces follows a decreasing trend with pressure and the degree of coal metamorphism.

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Dielectric behavior of electrolyte aqueous solutions with various concentrations in a cylindrical nanopore of MCM 41 silica has been investigated. The effect of confinement is investigated by using isothermal-isosurface-isobaric statistical ensemble, which has proved to be an effective alternative to the Grand Canonical Monte Carlo (GCMC) simulation method. Several single-salt solutions have been considered (e.g., NaCl, NaI, BaCl2, MgCl2) in order to investigate the effect of ion polarizability, ion size, and ion charge. The effect of salt concentration has also been addressed by considering NaCl solutions at different concentrations (i.e., 0.1 mol/L, 0.5 mol/L, and 1 mol/L). The motivation in performing this integrated set of simulations is to provide deep insight into the dielectric exclusion in NF theory that plays a significant role in separation processes. It was shown that the dielectric constant increased when ions were added to water inside the nanopore (with respect to the dielectric constant of confined pure water) unlike what was obtained in the bulk phase and this phenomenon was even more pronounced for electrolytes with divalent ions (MgCl2 and BaCl2). Therefore, our simulations indicate opposite effects of ions on the dielectric constant of free (bulk) and nanoconfined aqueous solutions.

The specific surface area (SSA) is a crucial parameter for estimating the adsorption capacity of shale, significantly influencing its adsorption characteristics. The Brunauer-Emmett-Teller (BET) method was widely used to characterize the surface area of various porous materials. However, research on its applicability for characterizing shale surface areas, particularly concerning the adsorption mechanism of nitrogen in shale nanopores, remains limited. In this study, ultra-low-pressure nitrogen adsorption experiments and molecular simulation methods were employed to characterize the adsorption behavior of nitrogen on shale nanopore surfaces at 77 K. The results indicate that the assumptions of the classic BET isotherm model do not fully align with the state and microscopic mechanisms of nitrogen on shale surfaces. Nitrogen exhibits multilayer adsorption on shale surfaces represented by organic matter and Illite, but the initial pressure for multilayer adsorption varies with the rock phase surface. Calculating the specific surface area of organic matter in shale using the relative pressure range recommended by the classic BET theory results in a certain degree of error. Through analysis of isotherm adsorption curves, density field distributions, and intermolecular interactions, the adsorption mechanisms of nitrogen on shale pore surfaces were elucidated. It was found that for organic matter, a more suitable relative pressure range for BET calculations is 0.002–0.035, whereas for Illite, it is 0.035-0.2. This study provided crucial insights into the adsorption mechanisms of nitrogen on shale pore surfaces and the optimization of BET surface area characterization for shale nanopores, laying a theoretical foundation for predicting shale adsorption capacity and estimating in-situ natural gas in shale.

Boundary layer formed by crude oil on the shale nanopores surface hinders fluidity of crude oil and leads to a decline in oil recovery. CO2 injection has been considered as an effective method to enhance shale oil recovery. However, the impact of CO2 on the disruption of boundary layers within shale nanopores and the extraction mechanisms of crude oil during the recovery process remains unclear. In this work, molecular dynamics simulation was employed to investigate the process of using scCO2 to extract crude oil from shale nanopore surface. During the process of scCO2 extraction, polar molecules have the capability to reduce the diffusion coefficient, prolong the residence time, and decrease flowability of decane, ultimately resulting in a deterioration of its kinetic properties. Phenol, with its hydrophilic hydroxyl group, closely adheres to the shale surface, while the oleophylic benzene ring covers the shale surface, causing a transition in the wettability of this segment from hydrophilic to oleophylic. As a result, a substantial adsorption of decane occurs on phenol. The research findings contribute to the comprehension of the scCO2 extraction mechanism and the advancement of unconventional oil and gas resources. GRAPHICAL ABSTRACT

The molecular models of nanopores for major rock constituents in deep shale were constructed. The microscopic adsorption behavior of methane was simulated by coupling the grand canonical Monte Carlo and Molecular Dynamics methods and the effect of rock constituents was discussed. Based on the illite and kerogen nanopore models, the discrepancies in microscopic water distribution characteristics were elucidated, the effects of water on methane adsorption and its underlying mechanisms were revealed, and the competitive adsorption characteristics between water and methane were elaborated. The results show a similar trend in the microscopic distribution of methane between different shale rock constituents. Illite and kerogen slit pores have no significant difference in methane adsorption capacity. The adsorption capacity per unit mass of kerogen is greater than that of illite due to the smaller molar mass of the kerogen skeleton and its large intermolecular porosity. Illite has a greater affinity for water than methane. With increasing water content, water molecules preferentially occupy the high-energy adsorption sites and then overspread the entire pore walls to form water adsorption layers. Methane molecules are adsorbed on the water layers, and methane adsorption has little effect on water adsorption. Kerogen is characterized as mix-wetting. Water molecules are preferentially adsorbed on polar functional groups and gather around to form water clusters. In kerogen with high water content, methane adsorption can facilitate water cluster fusion and suppress water spreading along pore walls. In addition to adsorption, some water molecules dissolve in the kerogen matrix.

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Currently, the utilization of coalbed methane resources in the Guizhou region faces challenges such as complex reservoir structure, high gas content, and microporous development. Based on these, the pore structure and adsorption capacity of Guizhou tectonic deformed coals (TDCs) were evaluated using a suite of integrated diagnostic techniques including low-temperature nitrogen adsorption (LT-N2A), mercury intrusion porosimetry (MIP), methane isothermal adsorption. Through the above methods, the pore structure and adsorption characteristics of the samples were characterized; The samples were divided into the range of joint pores by combining the results of MIP and LT-N2A; Using the molecular simulation software, the 2 nm, 4 nm, 10 nm pores affecting the methane endowment state were investigated respectively, and from the perspective of the heat of adsorption and energy, the concept of the three-phase transition of methane was proposed, and explore the change of the pore spacing affecting the endowment state of methane from the solid state pore to the gas state pore. The results provide new ideas for the in-depth study of gas storage in tectonic coal reservoirs in Guizhou Province.

In this study, molecular dynamics (MD) simulation is used to investigate the phase behavior and composition distribution of an ethane/heptane binary mixture in heterogeneous oil-wet graphite nanopores with pore size distribution. The pore network system consists of two different setups of connected bulk and a 5-nm pore in the middle; and the bulk connected to 5-nm and 2-nm pores. Our results show that nanopore confinement influences the phase equilibrium of the multicomponent hydrocarbon mixtures and this effect is stronger for smaller pores. We recognized multiple adsorbed layers of hydrocarbon molecules near the pore surface. However, for smaller pores, adsorption is dominant so that, for the 2-nm pore, most of the hydrocarbon molecules are in the adsorbed phase. The MD simulation results revealed that the overall composition of the hydrocarbon mixture is a function of pore size. This has major implications for macro-scale unconventional reservoir simulation, as it suggests that heterogenous shale nanopores would host fluids with different compositions depending on the pore size. The results of this paper suggest that modifications should be made to the calculation of overall composition of reservoir fluids in shale nanopores, as using only one overall composition for the entire heterogenous reservoir can result in significant error in recovery estimations.

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Enhanced oil recovery (EOR) has become a widely applied technique to meet global energy demands, in which surfactants have been recognized as an important type of efficient EOR agent. However, the application of surfactants in EOR has been subjected to many problems, such as unsatisfactory interfacial activity, high adsorption loss, poor salt resistance, low water solubility, and toxic side effects. In this work, natural long-chain fatty acid oleic acid (OA) and a composite surfactant system with high interfacial activity, formed by OA combining green surfactants coconut diethanolamide (CDEA) and cocamidopropylamine oxide (CAO), were encapsulated through microcapsules prepared by solvent evaporation, which is easy for large-scale production, with the use of ethyl cellulose (EC) as the sustainable shell material. Molecular dynamics (MD) simulations were employed to explore the interfacial behaviors of EC and the surfactants, revealing the mechanisms and providing guidance for core material formula design. It was confirmed that EC formed a stable shell by self-assembly, endowing the microcapsules with oil-targeted performance and surfactant protection. The microcapsules remained stable in brine while ruptured upon encountering the oil phase, releasing the surfactants in situ, and the interfacial tension (IFT) could be reduced by 2-3 orders of magnitude quickly. Microencapsulation of green surfactants not only avoids adsorption and precipitation losses during transport but also overcomes the problem of poor water solubility faced by surfactants with long hydrophobic tails. This study proposes a green and novel strategy for the efficient utilization of surfactants, which provides new ideas and methods for the sustainable development of related industrial fields.

Green surfactant (GS) flooding, an environmentally friendly chemical Enhanced Oil Recovery (cEOR) method, is explored in this molecular dynamics (MD) simulation study. This study evaluates the ability of (S)-2-dodecanamido-aminobutanedioic as a GS for cEOR, assessing its performance with hexane (C6), dodecane (C12), and eicosane (C20) as representative oils. In the case of the bulk system, a comprehensive molecular-level investigation provides structural details such as the radial distribution function, solvent-accessible surface area, GS adsorption dynamics, diffusivity, and emulsion stability of the GS, oil, and water systems. Also the impact of the three distinct oils on interfacial tension was examined in the existence of GS molecules. The findings reveal rapid GS molecule aggregation and adsorption on oil droplets, with various impacts on emulsion stability depending on the oil type. Additionally, GS enhances the aggregation of heavy C20 oil molecules in a water medium. The study demonstrates GS’s role as an effective emulsifier, facilitating oil droplet recovery, with electrostatic interactions governing micelle formation and van der Waals interactions influencing oil droplet emulsification. These results align with prior experimental data, affirming GS’s promising application potential in cEOR while prioritizing environmental sustainability.

CO2 injection for enhanced oil recovery (EOR) and geological carbon sequestration (GCS) in shale reservoirs offers a promising win-win strategy. Yet, the mechanisms by which CO2 flooding and huff-and-puff (HNP) mobilize multicomponent shale oil in inorganic nanopores remain unclear, particularly regarding their respective contributions to oil recovery and CO2 storage. Here, we employ molecular dynamics (MD) simulations to compare CO2 flooding and HNP in calcite dead-end nanopores saturated with a multicomponent hydrocarbon mixture. We analyze interfacial and transport behaviors, extract localized molecular clusters to quantify self-diffusion coefficients, and examine the roles of flood and flowback pressures. Results show that flooding promotes greater CO2 penetration into nanopores but suppresses counter-current hydrocarbon migration, limiting swelling-driven recovery. In contrast, HNP enables CO2 diffusion during the huff stage and reverse pressure gradients during the puff stage, which enhance oil swelling and achieve higher recovery at the expense of lower storage efficiency. Elevated CO2 density increases the diffusion coefficients of all components, underscoring the critical roles of pressure gradients and molecular transport. By extracting localized molecular clusters, we further obtained pressure-dependent diffusion bounds for CO2 and hydrocarbons and quantify injection and flowback pressure windows that jointly optimize oil recovery and the CO2 storage efficiency. On this basis, we propose a well-count-agnostic and field translatable hybrid method that achieves 60.44% oil recovery and 47.18% CO2 storage efficiency. These findings provide molecular-scale guidance for full-process CCUS design in unconventional reservoirs.

Divalent ions, which are omnipresent in brine, may be detrimental to surfactant functionalities during chemical flooding in the enhanced oil recovery (EOR) process. Surfactant blending is one potential solution to overcome such an adverse effect. Herein, we report a molecular dynamics (MD) study to investigate the molecular arrangement and possible applications of surfactant blending in hard water-resistant chemical flooding for oil recovery. We chose commonly used anionic surfactants, sodium dodecyl sulfate (SDS), as primary surfactants. The non-ionic (propanol) and cationic [cetrimonium bromide (CTAB)] surfactants with a wide range of concentrations are introduced to the primary system. We demonstrate that CTAB can disaggregate the cation bridging when their concentration is above a certain threshold. This threshold value is related to the surfactant and cosurfactant surface charge in the interface region. The cation bridging density is maintained at a low level when the sum of surfactants and cosurfactant interface charges is neutral or positive. On the other hand, propanol barely disaggregates the cation bridging. When propanol concentration is above a certain value, it even facilitates the cation bridging formation. Both propanol and CTAB can further decrease the oil-brine interfacial tension (IFT) while having different efficacies (IFT decrement rate is different as their interface concentration increases). More rapid IFT decrement is observed when cation bridging is disaggregated (i.e., in systems with high CTAB concentrations). Increasing propanol concentration barely affects hydrogen bond (H-bond) formation between SDS and H2O because of a low propanol distribution around SDS. On the other hand, the first increasing and then decreasing trend in H-bond density between SDS and H2O is observed as CTAB concentration increases. Our work should provide important insights into designing chemical formulas in chemical flooding applications.

Enhanced oil recovery using low-salinity solutions to sweep sandstone reservoirs is a widely-practiced strategy. The mechanisms governing this remain unresolved. Here, we elucidate the role of Ca2+ by combining chemical force microscopy (CFM) and molecular dynamics (MD) simulations. We probe the influence of electrolyte composition and concentration on the adsorption of a representative molecule, positively-charged alkylammonium, at the aqueous electrolyte/silica interface, for four electrolytes: NaCl, KCl, MgCl2, and CaCl2. CFM reveals stronger adhesion on silica in CaCl2 compared with the other electrolytes, and shows a concentration-dependent adhesion not observed for the other electrolytes. Using MD simulations, we model the electrolytes at a negatively-charged amorphous silica substrate and predict the adsorption of methylammonium. Our simulations reveal four classes of surface adsorption site, where the prevalence of these sites depends only on CaCl2 concentration. The sites relevant to strong adhesion feature the O− silica site and Ca2+ in the presence of associated Cl−, which gain prevalence at higher CaCl2 concentration. Our simulations also predict the adhesion force profile to be distinct for CaCl2 compared with the other electrolytes. Together, these analyses explain our experimental data. Our findings indicate in general how silica wettability may be manipulated by electrolyte concentration.

CO2-responsive foam (CRF) is a highly promising candidate for CO2-enhanced oil recovery (CO2-EOR) because it displays higher stability than the surfactant-stabilized foam owing to the formation of robust wormlike micelles (WLMs) upon exposure to CO2. In this work, the nanoparticle-enhanced CO2-responsive foam (NECRF) was properly prepared using lauryl ether sulfate sodium (LES)/diethylenetriamine/nano-SiO2, and its interfacial properties and EOR potential were experimentally and numerically assessed, aiming to explore the feasibility and effectiveness of NECRF as a novel CO2-EOR technique. It was found that the interfacial expansion elastic modulus increased 6-fold after CO2 stimulation. The modulus continued to increase with the introduction of nano-SiO2 owing to the pronounced synergistic effect of WLMs and nanoparticles. In addition to increasing the viscosity of the foaming liquid, WLMs and nano-SiO2 enhanced the shearing resistance of the NECRF as well. Calculations demonstrated that both the coarsening rate and the size distribution uniformity coefficient of NECRF were markedly lower than that of the LES foam, which subsequently inhibited NECRF decay and greatly improved its dynamic stability. Besides, molecular dynamics simulation revealed that adding inorganic salts to NECRF could notably enhance the foaming performance due to the intensified hydration of surfactant head groups and reduced binding energy of neighboring molecules. Nuclear magnetic resonance-assisted core flooding experiments validated the exceptional capacity of NECRF to sweep the low-permeability region and improve the conformance profile. Overall, these findings may provide valuable insights into the development and application of novel materials and strategies for the CO2-EOR.

Enhanced oil recovery (EOR) via CO2 flooding is a promising strategy for improving hydrocarbon recovery and carbon sequestration, yet the influence of pH on solid–liquid interfacial interactions in quartz-dominated reservoirs remains poorly understood. This study employs molecular dynamics (MD) simulations to investigate the pH-dependent adsorption behavior of crude oil components on quartz surfaces and its impact on CO2 displacement mechanisms. Three quartz surface models with varying ionization degrees (0%, 9%, 18%, corresponding to pH 2–4, 5–7, and 7–9) were constructed to simulate different pH environments. The MD results reveal that aromatic hydrocarbons exhibit significantly stronger adsorption on quartz surfaces at high pH, with their maximum adsorption peak increasing from 398 kg/m3 (pH 2–4) to 778 kg/m3 (pH 7–9), while their alkane adsorption peaks decrease from 764 kg/m3 to 460 kg/m3. This pH-dependent behavior is attributed to enhanced cation–π interactions that are facilitated by Na+ ion aggregation on negatively charged quartz surfaces at high pH, which form stable tetrahedral configurations with aromatic molecules and surface oxygen ions. During CO2 displacement, an adsorption–stripping–displacement mechanism was observed: CO2 first forms an adsorption layer on the quartz surface, then penetrates the oil phase to induce the detachment of crude oil components, which are subsequently displaced by pressure. Although high pH enhances the Na+-mediated weakening of oil-surface interactions, which leads to a 37% higher diffusion coefficient (8.5 × 10−5 cm2/s vs. 6.2 × 10−5 cm2/s at low pH), the tighter packing of aromatic molecules at high pH slows down the displacement rate. This study provides molecular-level insights into pH-regulated adsorption and CO2 displacement processes, highlighting the critical role of the surface charge and cation–π interactions in optimizing CO2-EOR strategies for quartz-rich reservoirs.

Carbon capture, utilization, and storage (CCUS) is a critical strategy for climate change mitigation, often involving CO2 injection into subsurface reservoirs for enhanced oil recovery (EOR) and geological storage. Reservoir wettability significantly impacts these processes, yet carbonate formations frequently become oil-wet due to organic acid adsorption from crude oil, hindering recovery. While CO2 injection can alter wettability towards a more favorable water-wet state, the underlying molecular mechanisms involving CO2, adsorbed organic acids, and the calcite surface are not fully understood. This study employs molecular dynamics (MD) simulations to elucidate these mechanisms, using decane as the main oil component and butyric acid as a model acidic component. Results demonstrate that, even though no chemical reaction is considered in this study, CO2 significantly enhances the hydrophilicity of the calcite surface originally rendered partially lipophilic by butyric acid adsorption. Furthermore, the influence of CO2 concentration on the water contact angle was quantitatively evaluated. The water droplet contact angle was 0° for the water-oil-calcite system in the absence of acid molecule but increased to ∼29° by including the butyric acid in the oil phase. The addition of CO2 reduced the contact angle back to ∼8°, restoring hydrophilicity. This wettability shift is attributed to a competitive adsorption mechanism where sufficient concentrations of CO2 displace butyric acid from the calcite surface. This displacement is facilitated by the formation of hydrogen bonds between CO2 molecules and the carboxyl groups of the butyric acid, disrupting the acid's interaction with the calcite surface. By clarifying this interplay among CO2, acidic components, and the calcite surface, this work provides fundamental, molecular-scale insights into interfacial phenomena. These findings can guide the optimization of CO2-EOR efficiency and advance CCUS applications in carbonate reservoirs.

Partially hydrolyzed polyacrylamides (HPAMs) have been gaining attention in enhanced oil recovery, with recent studies showing that adding nanoparticles (NPs) can boost the HPAMs flooding efficiency. Here, molecular dynamics (MD) simulations were utilized to explore the viscosity enhancement mechanism of HPAMs and the silica nanoparticle composite system. The results demonstrated that during the HPAMs self-assembly process, polymer ends formed hydrogen bonds, creating a network structure that increased the viscosity of the system. The simulations identified multiple hydrogen bonding units formed between amide hydrogen atoms and carboxyl carbonyl oxygen atoms, enhancing polymer network stability and improving fluid transport and recovery rates in reservoirs. The introduction of nanoparticles increased the cross-linking points within the polymer network and restricted the movement of the HPAMs molecular chains, thereby reducing the relative slippage between polymer chains. On the other hand, the introduction of silica nanoparticles not only restricted the movement of polymer chains but was also restricted by the surrounding polymer network, greatly reducing their range of movement. The dual restrictive effect of these nanoparticles on polymer chains and of polymer chains on nanoparticles further enhanced the overall viscosity of the system. The findings aim to leverage these findings to enhance oil field recovery, particularly under extreme conditions, by improving the polymer flooding efficiency through nanoparticle integration.

Geochemical reactions are crucial for in situ CO2 mineralization underground associated with CO2‐enhanced oil recovery (CO2‐EOR) in a hydrocarbon reservoir. However, the presence of formation water and adsorbed oil on rocks generates physical barriers to CO2's access to mineral surfaces, which may yield impedance to CO2 mineral trapping that has yet to be accounted for. In this study, we mimic the dynamic oil detachment process using molecular dynamic (MD) simulation and analyze the influence of an adsorbed oil film on supercritical CO2 (scCO2) diffusion toward the mineral surface in the presence and absence of a water phase. Our results demonstrated a negative impact of water on oil film detachment by scCO2, which may weaken mineral reactions and is unfavorable for mineralized CO2 storage underground.

Understanding the mechanisms underlying residual oil displacement by CO2 flooding is essential for CO2-enhanced oil recovery. This study utilizes molecular dynamics (MD) simulations to investigate the displacement of residual oil by CO2 flooding in dead-end nanopores, focusing specifically on the water-blocking effect. The findings reveal that oil displacement does not commence until the water film is breached. The dissolution of CO2 molecules in water and the hydrogen bond interactions between water and rock are the primary factors that disrupt the hydrogen bond network among the water molecules, facilitating the breakthrough of the water film. Additionally, the displacement process can be delineated into four distinct stages – encompassing water film rupture, oil swelling, massive oil displacement, and displacement completion – as evidenced by the oil recovery-displacement time curves. Moreover, a cutting-edge oil recovery-displacement time model precisely quantifies crucial stages in the displacement process. For example, when t < δ, trapped oil is impeded by the water film, while when t > δ + 3τ, displacement culminates successfully. Altogether, this research bolsters comprehension of residual oil displacement in the presence of water blocking and advocates for sustainable oil production strategies in oilfields.

No abstract available

Understanding the adsorption state and molecular behavior of the diverse components of shale oil in shale slits is of critical importance for exploring novel enhanced shale oil recovery techniques, but it is hard to be achieved by experimental measurements. In this paper, molecular dynamics (MD) simulations are performed to quantitatively describe the microbehavior of shale oil mixtures containing different kinds of hydrocarbon components, including asphaltene, in quartz slits. The spatial distributions of all the presenting components are given, the interaction energy between the components and quartz is analyzed, and the diffusion coefficients of all the components are calculated. It was found that asphaltene molecules play a vitally important role in restricting the detachment and diffusion movement of all hydrocarbon components, which is actually a key problem limiting the recovery efficiency of shale oil. The effects of temperature, slit aperture, and the appearance of CO2 on the adsorption behavior of the different shale oil components are examined; the results suggest that the light and medium components are the fractions with the most potential in thermal exploitation, while injection of CO2 is beneficial for the extraction of all the components, especially the medium components. This work gives insights into the effect of asphaltene on shale oil recovery in quartz slits and might provide guidance on the utilization of thermal and CO2-enhanced enhanced oil recovery (EOR) techniques in shale oil production.

HYPOTHESIS Surfactant flooding is the leading approach for reversing the wettability of oil-wet carbonate reservoirs, which is critical for the recovery of the remaining oil. Combination of molecular dynamics (MD) simulations with experiments on simplified model systems can uncover the molecular mechanisms of wettability reversal and identify key molecular properties for systematic design of new, effective chemical formulations for the enhanced oil recovery. EXPERIMENTS/SIMULATIONS Wettability reversal by a series of surfactant solutions was studied experimentally using contact angle measurements on aged calcite chips, and a novel MD simulation methodology with scaled-charges that provides superior description of the ionic interactions in aqueous solutions. FINDINGS The MD simulation results were in excellent agreement with the experiments. Cationic surfactants were the most effective in reversing the calcite wettability, resulting in complete detachment of the oil from the surface. Some nonionic surfactants also altered the wettability, but to a lesser degree, while the amphoteric and anionic surfactants had no effect. From the tested cationic surfactants, the double-tailed one was the least effective, but the experiments were inconclusive due to its poor solubility. Contributions of specific interactions to the wettability reversal process and implications for the design and optimization of surfactants for the enhanced oil recovery are discussed.

The physical chemistry mechanisms behind the oil-brine interface phenomena are not yet fully clarified. The knowledge of the relation between brine composition and concentration for a given oil may lead to the ionic tuning of the injected solution on geochemical and enhanced oil recovery processes. Thus, it is worth examining the parameters influencing the interfacial properties. In this context, we have combined machine learning (ML) techniques with classical molecular dynamics simulations (MD) to predict oil/brine interfacial tensions (IFT) effectively and compared this process to a linear regression (LR) method. To diversify our data set, we have introduced a new atomistic crude oil model (medium) with 36 different types of hydrocarbon molecules. The MD simulations were performed for mono- and multicomponent (toluene, heptane, Heptol, light, and medium) oil systems interfaced with sulfate and chloride brines with varying cations (Na+, K+, Ca2+, and Mg2+) and salinity concentration. Thus, a consistent IFT data set was built for the ML training and LR fitting at room temperature and pressure conditions, over the feature space considering oil density, oil composition, salinity, and ionic concentrations. On the basis of gradient boosted (GB) algorithms, we have observed that the dominant quantities affecting the IFT are related to the oil attributes and the salinity concentration, and no specific ion dominates the IFT changes. When the obtained LR model was validated against MD and experimental data from the literature, the error varied up to 2% and 9%, respectively, showing a robust and consistent transferability. The combination of MD simulations and ML techniques may provide a fast and cost-effective IFT determination over multiple and complex fluid-fluid and fluid-solid interfaces.

Polymer flooding is one of the widely used enhanced oil recovery (EOR) methods. However, tuning polymer properties to achieve improved performance in porous mineral rocks of diverse oil reservoirs remains one of the challenges of EOR processes. Here, we use molecular dynamics (MD) simulations to examine decane/water mixtures with surfactant additives in calcite and kaolinite mineral nanopores and characterize surfactant properties associated with increased fluid mobility and improved wettability in planar and constricted nanopore geometries. Cetyltrimethylammonium chloride (CTAC) and sodium dodecyl sulfate (SDS) surfactants are found to modulate the contact angles of decane droplets and reduce the decane density on mineral surfaces. CTAC can enhance and unblock the flow of decane droplets through narrowing nanopores with constricted geometries while aiding in decane droplet shape deformation, whereas SDS leads to decane droplets stalling in front of constrictions in nanopores. We hypothesize that the inability of the cationic CTAC headgroup to form hydrogen bonds is one of the key factors leading to enhanced CTAC-coated decane flow through constricted nanopores. The obtained molecular view of equilibrium and dynamic properties of complex fluids typical of oil reservoirs can provide a basis for the future design of new molecules for EOR processes.

Investigating the hydration behavior of xanthan gum (XG) under strongly alkaline and salt-containing conditions is essential for its reliable application in water-based drilling fluids and enhanced oil recovery (EOR) systems. In particular, the molecular mechanisms governing its hydration and rheological behavior under the coexistence of high-pH and Ca2+ conditions remain poorly understood. In this work, XG systems with varying pH and Ca2+ concentrations were examined through rheological measurements, structural characterizations, and molecular dynamics (MD) simulations. The results revealed that varying either pH or Ca2+ concentration alone exerted only limited effects on hydration and viscosity, whereas their coexistence above critical thresholds (pH > 12.0 and [Ca2+] ≥ 14 mM) led to a sharp viscosity loss and the formation of insoluble deposits. Remarkably, hydration and viscosity could be restored by chelating Ca2+ or lowering pH, indicating a reversible coordination-driven inhibition process rather than irreversible degradation of the XG backbone. Structural and MD simulation analyses jointly demonstrated that Ca2+ interacts with deprotonated carboxy groups on XG chains via electrostatic bridging and coordination, thereby restricting molecular extension and water accessibility. These findings provide molecular-level insights into the behavior of XG in complex ionic environments and hold important implications for its engineering applications.

In recent years, heavy oil-solid separation has attracted quantities of attention, and ionic liquids (ILs) enhanced solvent extraction has been widely studied. However, the detailed mechanism of ILs effect onto the heavy oil recovery was unclear, especially the interaction role between ILs and heavy oil SARA. In order to solve these problems, this paper used the experiment and molecular dynamics simulation methods to explore the four ILs ([Bmmim][PF6], [C12mim][Ac], [C12mim][BF4], and [Emim][Ac]) effect on enhancing the solvent extraction for oil sands. The experimental results showed that the ILs could enhance the solvent extraction process, improve heavy oil recovery, reduce bitumen viscosity, decrease oil-sand interaction force, alter the sand particles wettability. The extraction efficiency of [Bmmim][PF6] + toluene reached 93.9 %. Additionally, molecular dynamics (MD) simulations were conducted to analyze the interaction mechanisms between heavy oil SARA (saturates, aromatics, resins, asphaltenes) and solvents and ILs. The simulations results indicated that the saturates, aromatics, resins and asphaltenes have different interaction role with the different ILs under varieties of solvents, and the interaction role strength was related to the functional groups and heteroatom. In the end, the detailed mechanism of ILs enhancing solvent extraction for oil sands was put forward.

CO2-enhanced coalbed methane recovery (CO2-ECBM) has been demonstrated as an effective enhanced oil recovery (EOR) technique that enhances the production of coalbed methane (CBM) while achieving the goal of CO2 sequestration. In this paper, the grand canonical Monte Carlo simulation is used to investigate the dynamic mechanism of CO2-ECBM in anthracite pores. First, an anthracite pore containing both organic and inorganic matter was constructed, and the adsorption and diffusion characteristics of CO2 and CH4 in the coal pores under different temperature and pressure conditions were studied by molecular dynamics (MD) simulations. The results indicate that the interaction energy of coal molecules with CO2 and CH4 is positively associated with pressure but negatively associated with temperature. At 307.15 K and 101.35 kPa, the interaction energies of coal adsorption of single-component CO2 and CH4 are −1273.92 kJ·mol−1 and −761.53 kJ·mol−1, respectively. The interaction energy between anthracite molecules and CO2 is significantly higher compared to CH4, indicating that coal has a greater adsorption capacity for CO2 than for CH4. Furthermore, the distribution characteristics of gas in the pores before and after injection indicate that CO2 mainly adsorbs and displaces CH4 by occupying adsorption sites. Under identical conditions, the diffusion coefficient of CH4 surpasses that of CO2. Additionally, the growth rate of the CH4 diffusion coefficient as the temperature increases is higher than that of CO2, which indicates that CO2-ECBM is applicable to high-temperature coal seams. The presence of oxygen functional groups in anthracite molecules greatly influences the distribution of gas molecules within the pores of coal. The hydroxyl group significantly influences the adsorption of both CH4 and CO2, while the ether group has a propensity to impact CH4 adsorption, and the carbonyl group is inclined to influence CO2 adsorption. The research findings are expected to provide technical support for the effective promotion of CO2-ECBM technology.

ABSTRACT A deep understanding of CO2 storage in sandstone reservoirs is significant for Carbon Capture and Storage (CCS) technology and CO2-enhanced oil recovery (CO2-EOR). Based on this, a systematic investigation is conducted to study the CO2 adsorption characteristics in sandstone nanopores using grand canonical Monte Carlo (GCMC), molecular dynamics (MD), and density functional theory (DFT) methods. Specifically, CO2 adsorption capacity, density profiles, and isosteric heat (Qst) are calculated in both dry and water containing sandstone nanopores. The results reveal that the CO2 adsorption capacity increases as pressure rises, but decreases with higher temperatures. CO2 adsorption capacity under water containing decreases by 27.8%, 54.4%, 76.3%, and 92.2% sequentially compared to dry conditions at 323.15 K and 20 MPa. Density profiles show a symmetric distribution of CO2 molecules. Additionally, DFT analyses further reveal the influence of H2O molecules on CO2 adsorption. These analyses show that the adsorption energy of H2O (−59.96 kJ/mol) is significantly more negative than that of CO2 (−17.26 kJ/mol). The charge transfer from H2O to the SiO2(001) (0.027 e) is greater than that from CO2 (0.017 e). These results emphasise the role of H2O molecules in inhibiting the CO2 adsorption, providing theoretical guidance for CCS/CO2-EOR and related geological storage technologies.

No abstract available

Illite mineral is present in shale rocks, and its wettability behavior is significant for the oil and gas industry. In this work, the pH effects on the affinity between the (001) and (010) crystallographic planes of illite K2(Si7Al)(Al3Mg)O20(OH)4 and direct and inverse emulsions were studied using molecular dynamics simulations. To develop the simulations, an atomistic model of illite was constructed following Löwenstein's rule. The oily phase was modeled using heptane, toluene, and mixtures of heptane/heptanoic acid, heptane/heptanoate, heptane/hexylamine and heptane/hexylammonium. For the heptane/heptanoate and heptane/hexylammonium mixtures, Na+ and Cl- ions were used to neutralize the excess electrical charge of the droplets, respectively. The affinity of the mineral surface to the oil models was estimated by the contact angle for systems where it was possible. However, for systems where the droplets did not adhere to the mineral, a methodology based on the height of the droplet on the surface was proposed. The results showed that, in general, for the inverse emulsions, water exhibited a high affinity for both illite surfaces, with its contact angle remaining below 45° regardless of pH. However, the heptane/heptanoic acid inverse emulsions on the edge surface were an exception to this behavior. Specifically, the contact angles calculated for the water droplets revealed mixed wettability due to hydrogen bonds between the carboxylic functional groups (pH ≪ 4.4) and the surface silanols and aluminols. Oil droplets suspended in water, on the other hand, did not adhere to the illite surfaces, and contact angles were not measurable. Nevertheless, the heptane/heptanoic acid droplets (pH ≪ 4.4) showed heights of approximately 2 Å and 4 Å above the basal and edge surfaces, respectively. This behavior was attributed to the hydrogen bonds formed between the carboxylic functional groups and the water molecules located on the mineral surfaces. Finally, the heptane/heptanoate (pH ≫ 4.4) and heptane/hexylammonium (pH ≪ 10.64) droplets were localized at distances greater than 8 Å from the surface, presumably due to a charge repulsion between the mineral surface and the surface of the droplets.

The CO2-enhanced oil recovery (EOR) technology has the dual significance of enhancing oil recovery and realizing carbon storage in onshore and offshore oil and gas exploitation. This study investigates the adsorption of crude oil components on quartz surfaces and the microscopic mechanisms of CO2 stripping from crude oil using molecular dynamics simulations. A four-component model representing C6H14, benzene, resins, and asphaltenes was constructed to simulate the oil phase, while the quartz surface model was created using Materials Studio. Simulations were conducted under different temperature conditions to understand the distribution and adsorption behavior of crude oil components, as well as the impact of CO2 on the oil film at pressures up to 10 MPa. The results indicate that the resin–asphaltene interactions are significantly weakened at elevated temperatures, affecting the adsorption capacity. Furthermore, CO2 stripping primarily extracts light components such as C6H14 and aromatic hydrocarbons, while heavy components remain in the oil phase. The highest extraction efficiency and expansion effect of CO2 were observed at 35 °C, demonstrating optimal conditions for enhanced oil recovery through CO2 flooding. These findings provide insights into the effective use of CO2 for crude oil extraction and its interactions with oil components on a quartz substrate, which is crucial for optimizing CO2-enhanced oil recovery operations.

Oil, gas condensates, oil products present a complex colloidal-dispersed system which often demonstrates the abnormally changing properties when external conditions change. Mixing the petroleum products can be accompanied by a non-linear behavior accompanied by synergistic and antagonistic effects. Understanding of the oil and oil products as oil dispersed systems, the specific features of intermolecular interaction largely clarify their behavior, changes in properties, chemistry and mechanism of reactions occurring in them. Petroleum systems are polydisperse, in which the components can coexist in different aggregate states, and the size of the dispersed phase can vary over a wide range. They consist of diverse compounds that differ in properties, structure, shapes and sizes of molecules. Due to the variety of components that make up oil disperse systems the intermolecular interactions determine such a feature of the behavior of oil systems as the phenomenon of self-organization and structuring, which manifest themselves when external influences change and are sensitive to them. They are characterized by the absence of charge and a minimum of charge-polarization interactions of molecules, and intermolecular interactions are largely determined by the presence of paramagnetic molecules. The uncompensated spin of macromolecular compounds due to the steric obstacles, a homolytic dissociation, and the presence of microelement compounds ensure the paramagnetism of petroleum dispersed systems. This leads to developing the stable associative combinations and the formation of complex structural units capable of redistributing components and layers between phases under the influence of external effects. Comprehensive analysis and unanimity of views on the physical and chemical interactions of the components of oil systems leading to a change in their structure, open up fundamentally new opportunities for intensifying processes in the practice of production, transportation and processing of hydrocarbon raw materials and the use of petroleum products, and also allow predicting the behavior of oil systems in processes which they are participating.

No abstract available

No abstract available

Pressurized gases adsorb on the gas‐liquid (g‐l) interfaces, thus reducing the interfacial tension (IFT). Gas‐saturated liquid–liquid (l‐l) emulsions occur in oil and gas wells, possible IFT changes due to saturation remain unclear. We study if the IFT reduction occurs for the model system of methane, p‐xylene, and water. The neutron imaging (NI) observations of bulk (g‐l‐l) systems at 100 bar provide several quantities simultaneously from each experimental run, e.g., IFT for g‐l and methane diffusivity for the p‐xylene rich phase, but does not sensitively provide IFT for the l‐l interface. The quantities derived for the p‐xylene‐rich phase using NI allows us to calibrate molecular dynamics (MD) simulation, which is used for the predictions of IFT for l‐l, literature data for binary benzene/water (l‐l) system are used as the reference. Overall, no, or very minor effect (±1 mN m−1) on IFT is robustly found up to methane saturation at 100 bar. Variation of partial charges on the p‐xylene model from zero to quantum calculation‐based modulate the fine structure of p‐xylene/water interface and has small, yet qualitative effect on IFT, resulting in a weak adsorption (−1 mN m−1), or weak depletion (+1 mN m−1) of methane from l‐l.

We perform a molecular dynamics simulation of a bulk eight-component hydrocarbon mixture that roughly represents a composition of hydrocarbon fluid in a volatile oil reservoir. For that goal, we have developed a method for building molecular models of hydrocarbon mixtures which can include various branched molecules. We have used self-periodical simulation boxes with different aspect ratios. Our main focus here is the phase behavior of a multicomponent mixture in the presence of gas–liquid interfaces of different shapes: spherical, cylindrical, and slab-like gas bubbles. We have developed a method for calculating properties of coexisting phases in molecular simulations of multicomponent systems. In particular, it allows us to analyze the local composition of the mixture and to calculate the molar densities of components in liquid and gas phases, and inside the interface layer between them. For the values of model parameters that we have used so far, the mixture is homogeneous at a high pressure and undergoes liquid–gas phase separation upon decreasing the pressure. We have kept the same temperature T=375.15 K, the same composition and the same number of molecules in all systems and used several combinations of the simulation box size and shape to control the overall density, and therefore also the pressure, as well as the presence or absence of a liquid–gas interface and its shape. The gas bubble that appears in the system is mainly composed of methane. There is also a small number of ethane and butane molecules, a tiny number of hexane molecules, and no molecules of heavier components at all. In the liquid phase, all components are present. We also show that inside the gas–liquid interface layer, which is actually quite broad, the molar density of methane is also higher than that of other components and even reaches a maximum value in the middle of the interface. Ethane behaves similarly: its molar density also reaches a maximum inside the interface. The molar density of heavier components grows monotonically from the inner part of the interface towards its outer part and shows a very small (almost not visible) maximum at the outer side of the bubble.

The reversible solubilization behavior of pyrene by a CO2/N2 switchable surfactant (named N'-dodecyl- N, N-dimethylacetamidinium bicarbonate (DDAB)) was investigated with molecular dynamics (MD) simulations. We first individually simulated the aggregation of the inactive surfactant N'-dodecyl- N, N-dimethylacetamidines (DDA) and effective surfactant DDAB in water. Detailed structural properties analysis showed that DDAB molecules aggregated into a micelle, while the aggregation of DDA molecules was considered to be an oil droplet that was separated from the water phase. MD simulations revealed that pyrene molecule was solubilized in the interior hydrophobic region of the micelle as expected. Pyrene was adsorbed on the surface of the oil droplet which is due to the dense packing of DDA molecules inside the oil droplet. The simulated release process showed that the solubilized pyrene in the interior was squeezed out when the micelle was changed to an oil droplet. Reduced density gradient (RDG) function was used to study the weak interactions and explore the molecular driving force behind the reversible solubilization. The results demonstrated that repulsion effects of water molecules on the DDA headgroups play an important role on the pyrene release. Because of the persistent molecular motion of DDA molecules into the droplet center, pyrene was finally repelled out of the oil droplet. Our study provided a molecular mechanism into the reversible solubilization of a gas-controlled switchable surfactant. This is expected to be useful for surfactant-enhanced remediation (SER) experiments.

Carbon dioxide flooding offers dual benefits of enhanced oil recovery and greenhouse gas storage, with strong potential in unconventional reservoirs. However, the nanoporous nature of these reservoirs introduces strong wall–fluid interactions and confinement effects that substantially alter fluid thermodynamics. As a result, the conventional Peng–Robinson equation of state shows noticeable deviations when predicting phase behavior at the micro- and nanoscale. This study reviews advances in understanding CO2–crude oil systems in nanopores, highlighting critical property shifts, phase envelope deformation, and the reduction of minimum miscibility pressure (MMP). Most existing approaches apply single-mechanism corrections and lack integrated models that couple multiple confinement effects. To address this gap, we developed a dimensionless correlation linking critical properties to pore size, derived from experimental and molecular simulation data. This correlation was combined with adsorption layer thickness adjustment, capillary pressure, and volume translation to construct a modified EOS. The model was applied to multicomponent flash calculations and the multiple-mixing-cell method to predict MMP under nanoconfinement. Validation demonstrated high accuracy and robustness across pore sizes, compositions, and temperatures. Results indicate that critical temperature and pressure decrease nonlinearly with pore size, with pronounced changes below 10 nm. The phase envelope shifts toward lower pressures and temperatures, while the two-phase region contracts. The MMP decreases significantly with pore size reduction. These findings reveal the coupled mechanisms governing CO2 flooding behavior in unconventional reservoirs and provide theoretical support for optimizing injection strategies and evaluating storage potential.

Injecting industrial high-temperature flue gas into hydrocarbon reservoirs has emerged as a novel approach for carbon sequestration. However, the complex high-temperature phase behavior between flue gas (CO2, N2) and reservoir fluids challenges this technology’s development, as traditional experimental methods and theoretical models often fall short in capturing it accurately. To address this, molecular dynamics simulations were employed in this study to investigate the phase behavior of single-component alkanes, multicomponent alkane mixtures, and multicomponent alkane–flue gas systems under high-temperature conditions. The results reveal that CO2 can become miscible with alkanes, while N2 diffuses into the system, causing volumetric expansion and a reduction in density. The initially distinct phase interface between the multicomponent alkanes and the flue gas becomes progressively blurred and eventually disappears, indicating the formation of a fully miscible phase. Comparative simulations revealed that the diffusion coefficients of N2 and CO2 increased by up to 20% with rising temperature and pressure, while variations in flue gas composition had negligible effects, indicating that high-temperature and high-pressure conditions significantly enhance flue gas–alkane miscibility.

Experimentally determining thermophysical properties for various compositions commonly found in CO2 transportation systems is extremely challenging. To overcome this challenge, we performed Monte Carlo (MC) and Molecular Dynamics (MD) simulations of CO2 rich mixtures to compute thermophysical properties such as densities, thermal expansion coefficients, isothermal compressibilities, heat capacities, Joule–Thomson coefficients, speed of sound, and viscosities at temperatures of (235–313) K and pressures of (20–200) bar. We computed thermophysical properties of pure CO2 and CO2 rich mixtures with N2, Ar, H2, and CH4 as impurities of (1–10) mol % and showed good agreement with available Equations of State (EoS). We showed that impurities decrease the values of thermal expansion coefficients, isothermal compressibilities, heat capacities, and Joule–Thomson coefficients in the gas phase, while these values increase in the liquid and supercritical phases. In contrast, impurities increase the value of speed of sound in the gas phase and decrease it in the liquid and supercritical phases. We present an extensive data set of thermophysical properties for CO2 rich mixtures with various impurities, which will help to design the safe and efficient operation of CO2 transportation systems.

Surfactant-free microemulsions (SFMEs), formed in mixed ternary systems such as water/ethanol/oil, have garnered substantial interest due to their unique properties and broad applications in areas such as enzyme-catalyzed reactions and nanoparticle synthesis. In this work, we conducted an in-depth investigation of the spontaneous nucleation and stabilization mechanisms of SFMEs, employing experimental techniques, molecular dynamics (MD) simulations, and Flory-Huggins (F-H) theory. The formation of multiscale nanostructures (characteristic scales of ∼1 and ∼100 nm) and their interfacial charging characteristics in SFMEs have been revealed experimentally. MD simulations investigated the structure and stability on the microscopic scale, enhancing our understanding of molecular interactions within these microemulsions. Our theoretical analysis revealed that the stability of mesoscopic nanodroplets within SFMEs hinges on a delicate balance between mixing entropy and internal energy. Equilibrium between these energies results in stable nanodroplet solutions, showcasing a delicate balance that can be manipulated by adjusting the volume fractions of the components and their interaction parameters. This research not only advances the theoretical understanding of SFMEs but also highlights their potential in industrial applications, emphasizing the importance of integrating theoretical and experimental approaches to develop functional nanostructured materials.

Retrograde condensation is a critical process in the exploitation of gas condensate fields, leading to significant reductions in hydrocarbon production. This study examines the mechanisms behind this phenomenon, focusing on the BT 6 ¹ reservoir of the North-Chaselsky field. Here, condensation occurs when the reservoir pressure falls to 27,64 MPa, which is only 0.12 MPa above the current pressure of 27,52 MPa. The aim of this study is to identify molecular and thermodynamic factors causing early condensation and to propose measures for maintaining reservoir pressure to reduce hydrocarbon production losses. The paper is relevant as it clarifies the physics of intermolecular interactions during gas-liquid phase filtration in the reservoir. Using the Peng-Robinson equation of state and Lennard-Jones potential, the authors of this paper conducted an analysis of intermolecular interactions in the methane-heavy hydrocarbon (C 5 +) system. Also, the authors found that the formation of complexes with C 5 + when pressure decreases from 25 MPa down to 10–18 MPa results in the blocking of 98,9 % of the reservoir pores. This blockage is 4 to 6 times higher than the percolation threshold (15–25 %). It explains the complete cessation of gas production at the maximum condensation pressure. The results of this work underscore the need for maintaining pressure above the dew point and managing rock wettability. This study is relevant for fields with terrigenous reservoirs, where retrograde condensation presents significant challenges to project profitability.

The mass transfer process of CO2 multiphase systems constitutes a core physical mechanism governing both oil recovery and sequestration performance, involving complex interactions between CO2 and oil under reservoir conditions. However, the mass transfer behavior of CO2 multiphase systems at the nanoscale remains insufficiently elucidated. This study investigates the transport and mass transfer processes of CO2 multiphase systems within nanopores using molecular dynamics simulations, specifically focusing on the underlying CO2–oil interaction mechanisms and the influence of various factors. The results demonstrate that the energy difference between CO2–oil phase and oil phase–pore wall interactions serves as the decisive factor for mass transfer behaviors, with larger energy differences correlating to enhanced miscibility effects. Van der Waals energy dominates the CO2–oil interaction energy and acts as the primary driving force for interphase mass transfer. Elevated temperature and pressure significantly promote the mass transfer process. CO2 exhibits superior mass transfer behaviors with nonpolar oil molecules compared to polar counterparts, and shorter-chain nonpolar molecules achieve better miscibility with CO2. Hydrocarbon gases can promote the mass transfer process between CO2 and C8H18, and impurity gases inhibit mass transfer. The mass transfer degree of CO2 and C8H18 increases with nanopore size and reaches higher levels in hydrophilic pores. These findings provide molecular-level insights into CO2–oil mass transfer behaviors, offering theoretical guidance for optimizing CO2-enhanced oil recovery and geological sequestration strategies.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 218145, “Modeling Phase Behavior of Solvents/Water/Heavy Oil Systems Under Reservoir Conditions With the PC-SAFT Equation of State,” by Yunlong Li, SPE, Desheng Huang, and Xiaomeng Dong, SPE, University of Regina, et al. The paper has not been peer reviewed. In this work, a perturbed-chain (PC) statistical associating fluid theory (SAFT) equation of state (EOS) has been developed to characterize heavy-oil-associated systems containing polar components [e.g., dimethyl ether (DME) and water] and nonpolar components [e.g., carbon dioxide (CO2) and nitrogen (N2)] with respect to their phase behavior and physical properties. The proposed model shows its superior performance over the widely used Peng-Robinson EOS with a root-mean-squared relative error (RMSRE) of 2.93% for the predicted saturation pressure (Psat) of the aforementioned systems. The theoretical model proposed in this study reproduces accurately experimentally measured phase behavior and physical properties under reservoir conditions. The primary objective of this work is to develop a PC-SAFT EOS to accurately quantify the phase behavior and physical properties of heavy-oil-associated systems consisting of diverse components, including polar elements and nonpolar components. Experimentally, constant composition expansion (CCE) tests have been performed to measure Psat, phase volume, and phase compositions within CO2/heavy oil systems, N2/heavy oil systems, and DME/heavy oil systems in the absence and presence of water. Theoretically, the PC-SAFT EOS is integrated to reproduce accurately the measured Psat and physical properties observed in the aforementioned systems by using the single-carbon-number (SCN)-type approach along with temperature-independent binary interaction parameters (BIPs). For the CCE tests, a heavy oil sample with a molecular weight of 482 g/mol was used. Synthetic brine was formulated with 2 ppm of dissolved mineral salt. The purities of CO2, N2, and DME used in the study were 99.998 mol%, 99.998 wt%, and 99.5 wt%, respectively. The six CCE tests included the measured Psat and phase volumes sourced from both the present work and previous investigations. These CCE tests contained two CO2/heavy oil systems, two N2/heavy oil systems, and two DME/heavy oil systems in the absence and presence of water. The CCE experiments were conducted at temperatures of up to 433.15 K and pressures not exceeding 20 MPa. PC-SAFT EOS. The PC-SAFT EOS is articulated as a summation of residual Helmholtz free-energy terms, originating from diverse molecular interactions within a scrutinized system. The truncated version of the PC-SAFT EOS (tPC-PSAFT EOS) stands as a straightforward yet precise engineering model. Like the PC-PSAFT EOS, the tPC-PSAFT EOS uses the formulas introduced in the literature to manage dipolar and quadrupolar interactions, ensuring computational accuracy; however, it further simplifies certain aspects tailored to industrial needs. The application of these models to mixtures involves the use of suitable mixing and combining rules for various parameters. Different mixing rules are available for the same parameters, each of which has its own advantages, disadvantages, and scope of applications. The choice of mixing rules is crucial for a given mixture.