Shale Oil Recovery Research Articles

‘Supercharged’ Shale EOR: A Liquid-Hydrocarbon-Based Approach Enters the Fray

Around a decade of research and testing has passed by, and the unconventional sector has yet to show that natural gas huff-and-puff can scale effectively across tight-oil fields. This doesn’t mean enhanced oil recovery (EOR) in shale is a lost cause. Though it does suggest that the industry needs alternatives to the first and most well-known method. Proof of this can be found in North Dakota’s Bakken Shale where researchers, operators, and a firm called EOR ETC have tried to show that the water-alternating-gas method is a cheaper, less gas-intensive way of adding incremental barrels. EOR ETC has indicated on its website that ExxonMobil subsidiary XTO Energy is currently testing the technology. Chevron has also recently shared how it has rethought shale EOR methods by designing a program for production-boosting surfactant injections and gas injections that can be done with artificial lift instead of giant compressors. Another emerging shale EOR concept goes a step further, arguing that the unconventional sector should abandon natural gas injections altogether. Denver-based Shale Ingenuity proposes that liquid-hydrocarbon solvents should be used instead. Shale Ingenuity has patented a process called SuperEOR, which it claims delivered a strong showing during its initial field test in the Eagle Ford Shale of south Texas. After nearly a year of cyclic solvent injections, which began in early 2023, a horizontal well with a 4,400-ft lateral and 16 fracture stages produced 44% more oil than its previous total output. This resulted in a 30-fold boost in flow rate, from 13 to 391 B/D. Building on its initial success, Shale Ingenuity informed JPT that two private producers in the Permian Basin and the Eagle Ford have selected its EOR technology for upcoming projects. Both will involve single four-well pads, with EOR operations expected to begin in 2026. The solvents used in the pilot consisted mostly of natural gas liquids (NGL)—ethane, propane, butane, and pentane. Shale Ingenuity said formulations may include other hydrocarbon and nonhydrocarbon liquids. While the bulk of these products flow straight out of thousands of wellheads in the US shale sector, Shale Ingenuity emphasizes that the key to unlocking their potential for EOR lies in its proprietary method of blending, or “tuning,” the solvents based on formation and crude oil properties. This allows the injected solvents to quickly mix with and help mobilize the residual oil droplets that are trapped in tight-rock formations, according to the company. Robert Downey, founder and CEO of Shale Ingenuity, explained the process. “The tuned solvents we are using have a minimum miscibility pressure (MMP) of 700 to 900 psi, which means it doesn’t take much pressure to drive them into solution. When pumped into the well, they instantly become miscible with oil, and as the formation heats up and the well is reopened, the solvents expand back into gas at 100 to 200 times their liquid volume.” The effect of all this is what he describes as a “supercharging” of the solution gas drive mechanism that promotes the strong early well flow shale wells are known for. This is the energy released by dissolved gas in the oil as it expands during the pressure drop brought on by producing the well.

Three-dimensional physical experimental study on mechanisms and influencing factors of CO2 huff-n-puff and flooding process in shale reservoirs after fracturing

Carbon dioxide (CO2) capture and geological storage technology is a promising strategy for enhancing oil and gas production and mitigating climate change in unconventional formations. In shale reservoirs, production decline is rapid under volumetric fracturing development. Currently, CO2 injection and huff-n-puff techniques are cost-effective methods to boost shale oil recovery. However, traditional huff-n-puff techniques are limited in capturing reservoir heterogeneity and intricate fracture conditions. This study employed a three-dimensional physical experimental apparatus to explore CO₂ huff-n-puff dynamics across six distinct fracture patterns. By implementing a real-time monitoring system with multiple pressure points, the study elucidated the impacts of varying fracture penetration levels and spacing on dynamic pressure wave patterns, mobilization extent, and development outcomes during CO2 huff-n-puff. The results demonstrate that fractures substantially improve CO₂ huff-n-puff efficiency in shale reservoirs compared to a seamless model, with Model 6 achieving the highest recovery rate of 42.38%. As fracture penetration increases, CO₂ dynamic coverage expands. However, full penetration leads to preferential flow through fractures, reducing matrix contact and diminishing huff-n-puff efficiency. Reduced fracture spacing enlarges the well's control domain, amplifies CO2 huff-n-puff dynamic coverage area, and increases oil production and recovery rate. Conversely, decreasing fracture spacing accelerates oil and gas displacement rates, leading to higher economic expenses. The study concludes that 2/3 fracture penetration in five fractures offers the most efficient recovery method. For a 500 m horizontal well, optimal fracture spacing is recommended at 125 m, with a fracture length of 145.8 m for a well spacing of 417 m.

Numerical Study on the Enhanced Oil Recovery by CO2 Huff-n-Puff in Shale Volatile Oil Formations

The Sichuan Basin’s Liangshan Formation shale is rich in oil and gas resources, yet the recovery rate of shale oil reservoirs typically falls below 10%. Currently, gas injection huff-n-puff (H-n-P) is considered one of the most promising methods for improving shale oil recovery. This study numerically investigates the application of the CO2 huff-n-puff process in enhancing oil recovery in shale volatile oil reservoirs. Using an actual geological model and fluid properties of shale oil reservoirs in the Sichuan Basin, the CO2 huff-n-puff process was simulated. The model takes into account the molecular diffusion of CO2, adsorption, stress sensitivity effects, and nanopore confinement. After history matching, through sensitivity analysis, the optimal injection rate of 400 tons/day, soaking time of 30 days, and three cycles of huff-n-puff were determined to be the most effective. The simulation results show that, compared with other gases, CO2 has significant potential in improving the recovery rate and overall efficiency of shale oil reservoirs. This study is of great significance and can provide valuable references for the actual work of CO2 huff-n-puff processes in shale volatile oil reservoirs of the Sichuan Basin.

Fluid Flow Behavior in Nanometer-Scale Pores and Its Impact on Shale Oil Recovery Efficiency

Fluid Flow Behavior in Nanometer-Scale Pores and Its Impact on Shale Oil Recovery Efficiency

Molecular dynamics study of shale oil adsorption and diffusion behavior in reservoir nanopores: Impact of hydrocarbon composition and surface type

Understanding shale oil adsorption in reservoir nanopores is essential for efficient extraction. This study used MD simulations to analyze the adsorption and diffusion of two- and multi-component hydrocarbons (Aromatics, Alkanes, Resin) on various shale surfaces (Calcite, Montmorillonite, Quartzite, Organic) at 353 K and 25 MPa. Hydrocarbons formed a bilayer adsorption structure comprising a high-concentration adsorption layer (L1, 0.35–0.90 g/cm3) and a low concentration weak adsorption layer (L2), with adsorption density ranked as Resin > Aromatics > Alkanes. Reservoir surfaces were classified as ionic (e.g., calcite, montmorillonite) and non-ionic (e.g., quartz, graphite), and polar hydrocarbons exhibited higher adsorption densities and energies on ionic surfaces due to combined electrostatic and van der Waals interactions, while non-ionic surfaces showed smaller adsorption differences. For multicomponent hydrocarbons, adsorption layer densities followed the order: graphite > MMT-SiO > quartz > calcite > MMT-Na, with competitive adsorption observed. The polar component exhibited a greater adsorption advantage on the calcite, MMT-SiO side and graphite surfaces due to electrostatic interactions and π-π interactions, and a lesser advantage on the MMT-Na side and quartz surfaces. Hydrocarbon diffusivity was influenced by molecular mass and polarity and ordered as Alkanes > Aromatics ≫ Resin. Polar molecules had a weaker diffusion than nonpolar molecules at similar molecular masses. Among the multicomponent hydrocarbons, the self-diffusion coefficient (Self-D) of Resin increased, while that of lighter components decreased compared to two-component systems. These findings offer strategies for improving shale oil recovery by tailoring injection fluids to reservoir types, anionic surfactants or chelating agents may be used to reduce electrostatic interactions in carbonate and clay reservoirs, while nonionic surfactants may be more effective in quartz reservoirs.

Countercurrent Imbibition in Porous Media with Dense and Parallel Microfractures: Numerical and Analytical Study

Summary Countercurrent imbibition is the process in which the wetting fluid spontaneously displaces the nonwetting fluid, while the nonwetting fluid is recovered at the wetting fluid inlet. It is a major mechanism for the recovery of shale oil, shale gas, and tight oil. In shale and tight formations, microfractures are highly developed. Specifically, some typical formations, such as continental shales, consist of dense and parallel microfractures (DPFs). In DPF systems, microfractures are segregated by low-permeability matrix layers, while the very close distance betwen neighboring microfractures results in strong capillary correlation. The underlying assumptions of the classical dual-porosity (DP) model break down. Despite extensive studies on layered media, there is still no suitable model to describe imbibition in the DPF system at the representative elementary volume (REV) scale. In this study, we first numerically simulate countercurrent imbibition in DPF systems with fine grids, adopting typical continental shale parameters. For imbibition parallel to microfractures, two distinct stages are identified: an early stage where fractures are not correlated and a late stage where neighboring fractures are strongly correlated by capillarity. In both stages, cumulative oil production (Q) is proportional to the square root of imbibition time (t1/2), while the prefactors are very different. The late stage is the dominant stage in oil recovery. We note that the matrix permeability rarely contributes to imbibition parallel to microfractures at the late time, indicating that the matrix’s role here is to store fluid rather than to provide flow resistance. In addition, we rationalize the failure of the classical DP model, as it significantly overestimates fracture-matrix fluid exchange near the displacement front. Similarly, for imbibition perpendicular to microfractures, Q is also proportional to t1/2 in the late stage. After elucidating the mechanisms of fracture-fracture capillary interaction, we successfully derive analytical solutions for uni-directional countercurrent imbibition kinetics in DPF systems at the late stage, for imbibition parrallel and perpendicular to microfractures, respectively. We accordingly propose an equivalent REV scale model and examine it with fine-grid simulations. We highlight the importance of adopting anisotropic relative permeability in this DPF system at REV scale for reservoir simulation rather than simply adopting anisotropic absolute permeability. This presents a new challenge for numerical simulations at reservoir scale.

Shale oil recovery by CO2 injection in Jiyang Depression, Bohai Bay Basin, East China

Laboratory experiments, numerical simulations and fracturing technology were combined to address the problems in shale oil recovery by CO2 injection. The laboratory experiments were conducted to investigate the displacement mechanisms of shale oil extraction by CO2 injection, and the influences of CO2 pre-pad on shale mechanical properties. Numerical simulations were performed about influences of CO2 pre-pad fracturing and puff-n-huff for energy replenishment on the recovery efficiency. The findings obtained were applied to the field tests of CO2 pre-pad fracturing and single well puff-n-huff. The results show that the efficiency of CO2 puff-n-huff is affected by micro- and nano-scale effect, kerogen, adsorbed oil and so on, and a longer soaking time in a reasonable range leads to a higher exploitation degree of shale oil. In the “injection + soaking” stage, the exploitation degree of heavy hydrocarbons is enhanced by CO2 through its effects of solubility-diffusion and mass-transfer. In the “huff” stage, crude oil in large pores is displaced by CO2 to surrounding larger pores or bedding fractures and finally flows to the production well. The injection of CO2 pre-pad is conducive to keeping the rock brittle and reducing the fracture breakdown pressure, and the CO2 is liable to filter along the bedding surface, thereby creating a more complex fracture. Increasing the volume of CO2 pre-pad can improve the energizing effect, and enhance the replenishment of formation energy. Moreover, the oil recovery is more enhanced by CO2 huff-n-puff with the lower shale matrix permeability, the lower formation pressure, and the larger heavy hydrocarbon content. The field tests demonstrate a good performance with the pressure maintained well after CO2 pre-pad fracturing, the formation energy replenished effectively after CO2 huff-n-puff in a single well, and the well productivity improved.

“Component flow” conditions and its effects on enhancing production of continental medium-to-high maturity shale oil

Based on the production curves, changes in hydrocarbon composition and quantities over time, and production systems from key trial production wells in lacustrine shale oil areas in China, fine fraction cutting experiments and molecular dynamics numerical simulations were conducted to investigate the effects of changes in shale oil composition on macroscopic fluidity. The concept of “component flow” for shale oil was proposed, and the formation mechanism and conditions of component flow were discussed. The research reveals findings in four aspects. First, a miscible state of light, medium and heavy hydrocarbons form within micropores/nanopores of underground shale according to similarity and intermiscibility principles, which make components with poor fluidity suspended as molecular aggregates in light and medium hydrocarbon solvents, such as heavy hydrocarbons, thereby decreasing shale oil viscosity and enhancing fluidity and outflows. Second, small-molecule aromatic hydrocarbons act as carriers for component flow, and the higher the content of gaseous and light hydrocarbons, the more conducive it is to inhibit the formation of larger aggregates of heavy components such as resin and asphalt, thus increasing their plastic deformation ability and bringing about better component flow efficiency. Third, higher formation temperatures reduce the viscosity of heavy hydrocarbon components, such as wax, thereby improving their fluidity. Fourth, preservation conditions, formation energy, and production system play important roles in controlling the content of light hydrocarbon components, outflow rate, and forming stable “component flow”, which are crucial factors for the optimal compatibility and maximum flow rate of multi-component hydrocarbons in shale oil. The component flow of underground shale oil is significant for improving single-well production and the cumulative ultimate recovery of shale oil.

Dynamics of oil–CO2–water three-phase under the nanopore confinement effect: Implications for CO2 enhanced shale oil recovery and carbon storage

The widespread nanopores, diverse minerals, and varying water saturation in shale reservoirs complicate the mechanism analysis and performance prediction of CO2 enhanced oil recovery (CO2-EOR) and CO2 storage (CS) in hydrated nanopores. Therefore, molecular dynamics methods were used to simulate the process of CO2 replacing shale oil in hydrated nanopores of inorganic, organic and composite minerals. Importantly, the effects of mineral type, temperature, pressure and water content on CO2-EOR and CS performances in hydrated nanopores were analyzed, and the CO2-EOR mechanisms of dissolution, extraction, viscosity reduction, miscibility and competitive adsorption were revealed. The results show that water in illite, kerogen, and composite nanopores are distributed in the forms of water films, water clusters (films), and water columns, respectively. The replacement efficiency of shale oil in three types of nanopores is improved with increased water content but reduced in kerogen nanopores under high water content. Water is not conducive to the diffusion and viscosity reduction of oil in nanopores, but the miscibility and competitive adsorption of CO2 and oil are improved. The replacement efficiency is positively correlated with temperature and pressure. The increasing temperature promotes diffusion and viscosity reduction of oil and competitive adsorption between CO2 and oil in hydrated nanopores, and increasing pressure promotes miscibility and competitive adsorption. Water columns in kerogen and composite nanopores reduce the CS performance, while thin water films in illite nanopores improve it. Moreover, an excellent CS rate can be achieved at high temperatures and pressures, but the high temperature is not conducive to CS stability. This study provides a theoretical basis for CO2 injection to improve oil production and carbon storage performance in hydrated shale reservoirs and contributes to the optimization of CO2 injection schemes.

An investigation on the pyrolysis of low-maturity organic shale by different high temperature fluids heating

This study evaluates the potential of oil and gas generation from thermal pyrolysis of low-maturity organic rich shales by high temperature fluids injection. This method aims to convert the solid organic matter into hydrocarbons, thereby enhancing the quality of shale oil. The effectiveness of this technique hinges on its ability to convert retained heavy compounds and kerogen into light, moveable hydrocarbons, while also improving the oil recovery factor. Our experimental findings reveal that the decrease of total organic carbon content predominantly occurs between 400–550 °C or even higher. Different heating fluid media were tested for their pyrolysis effectiveness, among the heating media tested, CO2 and steam mixture proved the most productive. A comparison of CO2, steam and CO2-steam pyrolysis experiments were carried out. It is observed that the oil yield is the lowest in a pure CO2 atmosphere, while oil yield from the mixture of CO2-steam pyrolysis is the highest. In addition, the pore structure and mechanical properties of shales during pyrolysis process are examined.This investigation provides a theoretical basis for the large-scale upgrading of organic-rich shale formations, highlighting the critical influencing factors of thermal pyrolysis in optimizing shale oil recovery and quality.

A Comparative Study of Surfactant Solutions Used for Enhanced Oil Recovery in Shale and Tight Formations: Experimental Evaluation and Numerical Analysis.

Applying chemical enhanced oil recovery (EOR) to shale and tight formations is expected to accelerate China's Shale Revolution as it did in conventional reservoirs. However, its screening and modeling are more complex. EOR operations are faced with choices of chemicals including traditional surfactant solutions, surfactant solutions in the form of micro-emulsions (nano-emulsions), and nano-fluids, which have similar effects to surfactant solutions. This study presents a systematic comparative analysis composed of laboratory screening and numerical modeling. It was conducted on three scales: tests of chemical morphology and properties, analysis of micro-oil-displacing performance, and simulation of macro-oil-increasing effect. The results showed that although all surfactant solutions had the effects of reducing interfacial tension, altering wettability, and enhancing imbibition, the nano-emulsion with the lowest hydrodynamic radius is the optimal selection. This is attributed to the fact that the properties of the nano-emulsion match well with the characteristics of these shale and tight reservoirs. The nano-emulsion is capable of integrating into the tight matrix, interacting with the oil and rock, and supplying the energy for oil to flow out. This study provides a comprehensive understanding of the role that surfactant solutions could play in the EOR of unconventional reservoirs.

Pore-scale probing CO2 huff-n-puff in extracting shale oil from different types of pores using online T1–T2 nuclear magnetic resonance spectroscopy

CO2 huff-n-puff shows great potential to promote shale oil recovery after primary depletion. However, the extracting process of shale oil residing in different types of pores induced by the injected CO2 remains unclear. Moreover, how to saturate shale core samples with oil is still an experimental challenge, and needs a recommended procedure. These issues significantly impede probing CO2 huff-n-puff in extracting shale oil as a means of enhanced oil recovery (EOR) processes. In this paper, the oil saturation process of shale core samples and their CO2 extraction response with respect to pore types were investigated using online T1–T2 nuclear magnetic resonance (NMR) spectroscopy. The results indicated that the oil saturation of shale core samples rapidly increased in the first 16 days under the conditions of 60 °C and 30 MPa and then tended to plateau. The maximum oil saturation could reach 46.2% after a vacuum and pressurization duration of 20 days. After saturation, three distinct regions were identified on the T1–T2 NMR spectra of the shale core samples, corresponding to kerogen, organic pores (OPs), and inorganic pores (IPs), respectively. The oil trapped in IPs was the primary target for CO2 huff-n-puff in shale with a maximum cumulative oil recovery (COR) of 70% original oil in place (OOIP) after three cycles, while the oil trapped in OPs and kerogen presented challenges for extraction (COR < 24.2% OOIP in OPs and almost none for kerogen). CO2 preferentially extracted the accessible oil trapped in large IPs, while due to the tiny pores and strong affinity of oil-wet walls, the oil saturated in OPs mainly existed in an adsorbed state, leading to an insignificant COR. Furthermore, COR demonstrated a linear increasing tendency with soaking pressure, even when the pressure noticeably exceeded the minimum miscible pressure, implying that the formation of a miscible phase between CO2 and oil was not the primary drive for CO2 huff-n-puff in shale.

The occurrence of pore fluid in shale-oil reservoirs using nuclear magnetic resonance: The Paleogene Funing Formation, Subei Basin, Eastern China

The occurrence characteristics of pore fluids restrict shale oil recovery. Various approaches have been proposed to analyze the microdistribution of shale oil, but they are limited by the simultaneous characterization of the occurrence of oil and water within shale pore networks. This study conducted a range of nuclear magnetic resonance (NMR) T2 and T1–T2 measurements on the shales at different states, sampled from the Paleogene Funing Formation in the Gaoyou Sag, Subei Basin. A novel water and oil restoration method was introduced to restore pore fluid distributions in shales. The T1–T2 pattern with eight regions was determined for shale oil reservoirs. The pore oil and water in different states were quantitatively calculated using NMR T1–T2 spectra and compared with the results from Rock-Eval. In addition, the occurrence pattern of pore fluids in shales was proposed. The primary results indicated that free oil derived from multistage Rock-Eval is generally lower than that determined using the NMR T1–T2 spectrum. The NMR T1–T2 spectrum specializes in detecting the adsorbed, capillary-bound, and movable oil in pore systems but is limited in quantitatively identifying oil absorbed in organic matter. The occurrences and distributions of pore oil and water in different states can be effectively revealed by the T1–T2 spectrum. Capillary-bound water is predominantly associated with micropores (<100 nm) and, to a lesser extent, with mesopores (100–1000 nm); a similar pattern is observed for adsorbed oil. As a result, adsorbed oil is significantly restricted by pore water. Capillary-bound oil primarily occurs in mesopores, whereas macropores (>1000 nm) are saturated with movable oil. Hence, the distribution of capillary-bound oil is still affected by pore water, whereas movable oil is not. The authors are confident that the results presented in this study offer innovative insights into the occurrence and distribution of pore fluids in shale pore networks.

Influence of glycol ether additive with low molecular weight on the interactions between CO2 and oil: Applications for enhanced shale oil recovery

The high-efficient development of shale oil is one of the urgent problems in the petroleum industry. The technology of CO2 enhanced oil recovery (EOR) has shown significant effects in developing shale oil. The effects of several glycol ether additives with low molecular weight on the interactions between CO2 and oil were investigated here. The solubility of glycol ether additive in CO2 was firstly characterized. Then, the effects of glycol ether additives on the interfacial tension (IFT) between CO2 and hexadecane and the volume expansion and extraction performance between CO2 and hexadecane under different pressures was investigated. The experimental results show that diethylene glycol dimethyl ether (DEG), triethylene glycol dimethyl ether (TEG), and tetraethylene glycol dimethyl ether (TTEG) all have low cloud point pressure and high affinity with CO2. Under the same mass fraction, DGE has the best effect to reduce the IFT between hexadecane and CO2 by more than 30.0%, while an overall reduction of 20.0%–30.0% for TEG and 10.0%–20.0% for TTEG. A new method to measure the extraction and expansion rates has been established and can calculate the swelling factor accurately. After adding 1.0% DEG, the expansion and extraction amounts of CO2 for hexadecane are respectively increased to 1.75 times and 2.25 times. The results show that glycol ether additives assisted CO2 have potential application for EOR. This study can provide theoretical guidance for the optimization of CO2 composite systems for oil displacement.

A review of the flow characteristics of shale oil and the microscopic mechanism of CO2 flooding by molecular dynamics simulation

Shale oil is stored in nanoscale shale reservoirs. To explore enhanced recovery, it is essential to characterize the flow of hydrocarbons in nanopores. Molecular dynamics simulation is required for high-precision and high-cost experiments related to nanoscale pores. This technology is crucial for studying the kinetic characteristics of substances at the micro- and nanoscale and has become an important research method in the field of micro-mechanism research of shale oil extraction. This paper presents the principles and methods of molecular dynamics simulation technology, summarizes common molecular models and applicable force fields for simulating shale oil flow and enhanced recovery studies, and analyzes relevant physical parameters characterizing the distribution and kinetic properties of shale oil in nanopores. The physical parameters analyzed include interaction energy, density distribution, radial distribution function, mean-square displacement, and diffusion coefficient. This text describes how molecular dynamics simulation explains the mechanism of oil driving in CO2 injection technology and the factors that influence it. It also summarizes the advantages and disadvantages of molecular dynamics simulation in CO2 injection for enhanced recovery of shale oil. Furthermore, it presents the development trend of molecular dynamics simulation in shale reservoirs. The aim is to provide theoretical support for the development of unconventional oil and gas.

Application of Machine Learning for Shale Oil and Gas “Sweet Spots” Prediction

With the continuous improvement of shale oil and gas recovery technologies and achievements, a large amount of geological information and data have been accumulated for the description of shale reservoirs, and it has become possible to use machine learning methods for “sweet spots” prediction in shale oil and gas areas. Taking the Duvernay shale oil and gas field in Canada as an example, this paper attempts to build recoverable shale oil and gas reserve prediction models using machine learning methods and geological and development big data, to predict the distribution of recoverable shale oil and gas reserves and provide a basis for well location deployment and engineering modifications. The research results of the machine learning model in this study are as follows: ① Three machine learning methods were applied to build a prediction model and random forest showed the best performance. The R2 values of the built recoverable shale oil and gas reserves prediction models are 0.7894 and 0.8210, respectively, with an accuracy that meets the requirements of production applications; ② The geological main controlling factors for recoverable shale oil and gas reserves in this area are organic matter maturity and total organic carbon (TOC), followed by porosity and effective thickness; the main controlling factor for engineering modifications is the total proppant volume, followed by total stages and horizontal lateral length; ③ The abundance of recoverable shale oil and gas reserves in the central part of the study area is predicted to be relatively high, which makes it a favorable area for future well location deployment.

Mechanisms of carbon dioxide extracting oil at the boundary layer on shale nanopore surface: insights from molecular dynamics

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.

Mechanisms of CO2-rich industrial waste gas enhanced shale oil recovery in kerogen slit based on adsorption behavior, gas flooding and surfactant synergy study

Enhanced oil recovery (EOR) by injection of CO2-rich industrial waste gas has been proposed as an energy-efficient and environmentally friendly method for shale oil reservoirs, in which the waste gas can be utilized and sequestered to reduce greenhouse gas emissions. In this work, the adsorption behaviors of shale oil and waste gas components in kerogen slits and the effects of gas flooding on EOR were investigated using molecular dynamics (MD) method, which can provide technical guide for shale oil development. In terms of the adsorption behaviors, an intensity decrease of oil adsorption is observed in kerogen slits after the injection of the waste gas components. Desorption of shale oil during injection of SO2 and CO2 is more pronounced in shallow reservoirs, whereas it is more evident for NO and N2 in deep reservoirs. The desorption efficiency can be 10.91 % for pure CO2 injection and 9.09 % for NO injection at a depth of 1000 m, and the relative stability ratios of CO2 and NO sequestration are 77.09 % and 76.06 %, respectively. For gas flooding, the existence of pressure difference provides favorable conditions for gas molecules to pass through the oil zone, and waste gas can be more effective than pure CO2 as driving gas. For the waste gas injection, the percentage of CO2 retained in the kerogen nanopores is much higher than that of pure CO2 injection, suggesting that more CO2 molecules can enter into kerogen matrix to take part in the displacement process. Furthermore, the effect of surfactants on oil desorption and displacement was also investigated and the interaction energy of the surfactant/oil/gas system was calculated and analyzed, finding that addition of the oil-soluble surfactants can be beneficial to shale oil displacement. This work can provide a comprehensive evaluation of the feasibility of CO2-rich industrial waste gas application for EOR, which is of great significance in the effective production of shale oil and the sequestration of waste gas in shale reservoirs.

Integrated Study on Carbon Dioxide Geological Sequestration and Gas Injection Huff-n-Puff to Enhance Shale Oil Recovery

Integrated Study on Carbon Dioxide Geological Sequestration and Gas Injection Huff-n-Puff to Enhance Shale Oil Recovery

Comparative Study on the Macroscopic Exploitation and Microscopic Mobilization Characteristics of CO2 and N2 HnP to Enhance Shale Oil Recovery

Comparative Study on the Macroscopic Exploitation and Microscopic Mobilization Characteristics of CO₂ and N₂ HnP to Enhance Shale Oil Recovery