Mechanism of Low Chemical Agent Adsorption by High Pressure for Hydraulic Fracturing-Assisted Oil Displacement Technology: A Study of Molecular Dynamics Combined with Laboratory Experiments

Molecular interactions of surfactants with other chemicals in chemical flooding processes: A comprehensive review on molecular dynamics simulation studies

Due to the growing demand for fossil fuels and the transition of many oil fields into a high water-cut stage, enhanced oil recovery (EOR) techniques have become more prevalent to meet this rising demand. Among these techniques, chemical flooding stands out as an effective method, supported by numerous experimental and simulation studies. However, the complexity of a chemical slug composition under harsh reservoir conditions makes the physicochemical phenomena involved in a chemical flooding process highly intricate. To comprehensively understand the microscopic mechanisms governing the phase behavior of complex fluid systems underground, molecular dynamics (MD) simulations have been increasingly employed in recent years to investigate the molecular interactions between various chemicals involved in chemical flooding processes. In this work, we have comprehensively reviewed the recent MD studies focusing on the molecular interactions between surfactants and other chemicals in the chemical flooding processes. Based on the molecular interactions within different chemicals, various nanoscale mechanisms have been proposed to shed light on the physicochemical flow in porous media. Additionally, the MD techniques used in these studies have been summarized, and challenges in the application of MD simulations in the field of chemical flooding have been identified for improving the quality of future MD studies.

Microscopic Mechanism for the Displacement of Shale Oil in a Nanochannel by CO2 at Different Pressures

Aiming at the problems of unclear utilization degree of shale oil in different occurrence states. In this paper, the CO2 displacement process of shale oil under different pressure conditions is simulated by the molecular dynamics method, the microscopic mechanism of CO2 displacement of shale oil is clarified, and the influence of pressure on the utilization degree of different occurrence states of shale oil is revealed. The results show that CO2 cannot form an effective flow channel under low pressure (1 MPa), and most of the oil and water remain in the channel. The water molecules form a water bridge at the outlet of the pore that CO2 cannot break through under medium pressure conditions (5 and 10 MPa). CO2 forms a stable flow channel under high pressure (15 MPa). With the increase of displacement pressure, the kinetic energy of oil and gas molecules in the channel increases. But limited by the system space, the diffusion capacity of shale oil system, the degree of oil and gas miscibility, and the competitive adsorption effect all show a trend of increasing first, then stabilizing, and rapidly increasing at last. The final recoveries of shale oil are 33.24%, 75.82%, 64.69%, and 83.03% under different displacement pressure conditions. Among them, the degree of oil and gas miscibility and shale oil utilization in the adsorbed layer is higher than that in the free layer under 1 MPa condition. And the shale oil utilization degree in the free layer is higher than that in the adsorbed layer under the other pressure conditions. This study can provide a theoretical basis for efficient development of shale oil.

Optimization of Shut-In Time for Hydraulic Fracturing-Assisted Oil Displacement in Offshore Low-Permeability Reservoirs

To optimize the shut-in time for hydraulic fracturing assisted oil displacement in offshore low-permeability reservoirs, a coupled mathematical model encompassing injection, shut-in well, and production is established. The accuracy of the model is validated using production data. The law of pressure diffusion and oil-water two-phase flow during the shut-in well process is clarified, and the mechanism of hydraulic fracturing assisted oil displacement to enhance oil recovery is summarized. The sensitivity analysis is conducted, and then the main controlling factors affecting the optimal shut-in time for hydraulic fracturing assisted oil displacement are identified. The research results indicate that the primary function of the shut-in well is to enhance the effect of formation energy supplementation after injection, thereby further increasing the swept volume, controlling greater geological reserves, and ultimately enhancing oil recovery. During the initial stage of shut-in well, a larger portion of geological reserves are controlled mainly by fluid pressure diffusion, while in the later stage, oil-water exchange is mainly achieved by imbibition effect. The main controlling factors affecting the shut-in time are cumulative injection volume, formation pressure coefficient before hydraulic fracturing assisted oil displacement, and permeability, which should be given special attention on site. The research results provide a theoretical basis for the design of shut-in time for hydraulic fracturing assisted oil displacement operations in offshore low-permeability reservoirs.

The influence of temperature, seepage and stress on the area and category of wellbore instability

This study investigates the challenge of borehole instability in shale gas development, focusing on the interactions among temperature, fluid flow, and stress. Using a thermal-hydro-mechanical coupling model of borehole elastic stress combined with a true triaxial rock strength criterion and tensile failure criterion, the research systematically examines the effects of different models on borehole stability in shale formations. The findings reveal that while temperature has a relatively minor impact on the stress distribution and failure zones around boreholes, bottom hole pressure plays a critical role in influencing both the extent of unstable regions and the modes of rock failure. Under varying inclination angles, the unstable zones and failure patterns generally remain consistent, with higher stability observed when drilling aligns with the direction of minimum horizontal stress. Moreover, the study highlights the significance of appropriate drilling fluid density in maintaining borehole stability. Specifically, when the bottom hole pressure ranges from 50.66 to 70.66 MPa, the tensile and shear instability areas are minimized within seven days of contact with the drilling fluid. The research underscores the importance of optimizing drilling fluid density, carefully managing bottom hole pressure, and selecting proper borehole trajectories to enhance stability during shale gas drilling. These findings provide both theoretical insights and practical guidance, contributing to the optimization of shale gas drilling engineering practices.

Pressure Analysis of Vertical-Wells with the Hydraulic Fracturing Assisted Water Injection in Low-Permeability Hydrogen and Carbon Reservoirs

Enhancing the energy of hydrogen and carbon reservoirs is crucial for the extraction of these resources. Currently, the conventional water-flooding technology faces challenges in replenishing the energy of hydrogen and carbon reservoirs due to the low injection rates caused by their low-permeability properties. To address this, hydraulic fracturing-assisted water injection technology has been employed to enhance the energy of these reservoirs. However, there has been a lack of research on pressure analysis for vertical wells using this technology. Existing studies on pressure analysis are not applicable to this scenario due to the unique behavior of dynamic fracture propagation. In this article, we present a pressure analysis model for vertical wells with hydraulic fracturing-assisted water injection in low-permeability hydrogen and carbon reservoirs, considering dynamic fracture propagation. The model examines the effects of key parameters on the pressure and fluid flow fronts, and it is applied to field wells for validation. Our findings include the following: the typical pressure response curve for vertical wells with hydraulic fracturing-assisted water injection in low-permeability hydrogen and carbon reservoirs can be divided into six stages: dynamic fracture propagation region, linear flow region in hydrogen and carbon reservoirs, bilinear flow region, radial flow region, transition flow region, and boundary control flow region. The production rate affects the pressure and pressure derivatives in the later stages of the process. However, reservoir permeability influences all flow regions, causing the pressure and pressure derivative curves to shift left with increasing permeability. Increases in both the injection rate and production rate result in a rise in the position of fluid fronts. The impact of permeability on fluid fronts is more significant in the early stages than in later stages. This work is of great significance for the development of low-permeability hydrogen and carbon reservoirs, providing a deeper understanding of the pressure dynamics involved in hydraulic fracturing-assisted water injection.

Dynamic Behavior of Impacting Droplet on the Edges of Different Wettability Surface

The dynamic behavior of impacting droplet shearing by the surface edge with different wettabilities is complicated and has great significance for engineering application. The morphological evolution of droplet with various Weber numbers (We) and wettability impacting on the edge of square substrate is investigated by high-speed photography. Moreover, the effects of the contact angle (α) and Weber numbers (We) on the shear breaking process of droplets are obtained. There are three types morphological evolution of impacting droplet are observed experimentally, including unbroken, tensile breakup, and shear breakup. Contact angle and Weber number have been proved to be the significant factors affecting the type of droplet morphological evolution. Meanwhile, the critical Weber number of different types are obtained quantitatively. Moreover, as α increases, the critical Weber numbers for breakup increase. In the shear breakup process, the mass ratio between the droplets remaining on the substrate and the initial droplets is maintained at 50%. Particularly, a reliable prediction model for the spreading of droplet impacting the side wall is proposed and compared with the experimental data. Overall, this study provides new direction and guidance for exploring droplet breakup kinetics.

Study on rock fracture mechanism and hydraulic fracturing propagation law of heterogeneous tight sandstone reservoir

Hydraulic fracturing technology is an effective way to develop tight sandstone reservoirs with low porosity and permeability. The tight sandstone reservoir is heterogeneous and the heterogeneity characteristics has an important influence on fracture propagation. To investigate hydraulic fracture performance in heterogeneous tight reservoir, the X-ray diffraction experiments are carried out, the Weibull distribution method and finite element method are applied to establish the uniaxial compression model and the hydraulic fracture propagation model of heterogeneous tight sandstone. Meanwhile, the sensitivity of different heterogeneity characterization factors and the multi-fracture propagation mechanism during hydraulic fracture propagation is analyzed. The results indicate that the pressure transfer in the heterogeneous reservoir is non-uniform, showing a multi-point initiation fracture mode. For different heterogeneity characterization factors, the heterogeneity characteristics based on elastic modulus are the most sensitive. The multi-fracture propagation of heterogeneous tight sandstone reservoir is different from that of homogeneous reservoir, the fracture propagation morphology is more complex. With the increase of stress difference, the fracture propagation length increases. With the increase of injection rate, the fracture propagation length increases. With the increase of cluster spacing, the propagation length of multiple fractures tends to propagate evenly. This study clarifies the influence of heterogeneity on fracture propagation and provides some guidance for fracturing optimization of tight sandstone reservoirs.

Molecular Insights into Soaking in Hybrid N2-CO2 Huff-n-Puff: A Case Study of a Single Quartz Nanopore-Hydrocarbon System

Hybrid N2-CO2 huff-n-puff (HnP) has been experimentally demonstrated to be a promising approach for improving oil recovery from tight/ultratight shale oil reservoirs. Despite this, the detailed soaking process and interaction mechanisms remain unclear. Adopting molecular dynamic simulations, the soaking behavior of hybrid N2-CO2 HnP was investigated at the molecular and atomic levels. Initially, the soaking process of fluid pressure equilibrium after injection pressure decays in a single matrix nanopore connected to a shale oil reservoir is studied. The study revealed that counter-current and cocurrent displacement processes exist during the CO2 and hybrid N2-CO2 soaking, but cocurrent displacement occurs much later than counter-current displacement. Although the total displacement efficiency of the hybrid N2-CO2 soaking system is lower than that of the CO2 soaking system, the cocurrent displacement initiates earlier in the hybrid N2-CO2 soaking system than in the CO2 soaking system. Moreover, the N2 soaking process is characterized by only counter-current displacement. Next, the soaking process of fluid pressure nonequilibrium before the injection pressure decays is investigated. It was discovered that counter-current and cocurrent displacement processes initiate simultaneously during the CO2, N2, and hybrid N2-CO2 soaking process, but cocurrent displacement exerts a dominant influence. During the CO2 soaking process, many hydrocarbon molecules in the nanopore are dissolved in CO2 while simultaneously exhibiting a substantial retention effect in the nanopore. After pure N2 injection, there is a tendency to form a favorable path of N2 through the oil phase. The injection of hybrid CO2-N2 facilitates the most significant cocurrent displacement effect and the reduction in residual oil retained in the nanopore during the soaking process, thus resulting in the best oil recovery. However, the increase rate in total displacement efficiencies of the different soaking systems over time (especially the hybrid N2-CO2 soaking system) was significantly larger before than after injection pressure decays. Additionally, the displacement effect induced by oil volume swelling is significantly restricted before the injection pressure decays compared to the soaking process after the injection pressure decays. This study explains the role of CO2-induced oil swelling and N2-induced elastic energy played by hybrid N2 and CO2 at different stages of the hybrid N2-CO2 soaking process before and after pressure decays and provides theoretical insights for hybrid gas HnP-enhanced recovery. These pore-scale results highlight the importance of injection pressure and medium composition during the soaking process in unconventional oil reservoirs.

Quantitative evaluation of acid flow behavior in fractures and optimization of design parameters based on acid wormhole filtration losses

The technique of matrix acidification or acid fracturing is commonly utilized to establish communication with natural fractures during reservoir reconstruction. However, this process often encounters limitations due to filtration, which restricts the expansion of the primary acid-etching fracture. To address this issue, a computational model has been developed to simulate the expansion of an acid-etching wormhole by considering various factors such as formation process, injection duration, pressure build-up, and time-varying acid percolation rate. By analyzing the pumping displacement of acid-etching wormholes, this model provides valuable insights into the time-dependent quantities of acid percolation. It has been revealed that the filtration rate of acid-etching wormholes is strongly influenced by pumping displacement, viscosity, and concentration of the acid fluid used in stimulation as well as physical properties of the reservoir itself. Notably, viscosity plays a significant role in determining the effectiveness of acid fracturing especially in low-viscosity conditions. Acid concentration within 15% to 20% exhibits maximum impact on successful acid fracturing while concentrations below 15% or above 20% show no obvious effect. Furthermore, it was found that pumping displacement has a major influence on effective fracturing. However, beyond a certain threshold (> 5.0 m3/min), increased pumping displacement leads to slower etching distance for acids used in construction purposes. The simulation also provides real-time distribution analysis for acidity levels within eroded fractures during matrix-acidification processes and quantifies extent of chemical reactions between acids and rocks within these fractures thereby facilitating optimization efforts for design parameters related to matrix-acidification.

Preparation and performance evaluation of a novel temperature-resistant anionic/nonionic surfactant

Aiming at oil extraction from a tight reservoir, the Jilin oil field was selected as the research object of this study. Based on the molecular structures of conventional long-chain alkyl anionic surfactants, a new temperature-resistant anionic/nonionic surfactant (C8P10E5C) was prepared by introducing polyoxyethylene and polyoxypropylene units into double-chain alcohols. The resulting structures were characterized by Fourier transform infrared spectroscopy (FT-IR), nuclear magnetic resonance spectroscopy (1H-NMR), and electrospray ionization mass spectrometry (ESI-MS). Then, based on surface tension, interfacial tension, adsorption resistance, wettability, and emulsification performance tests, the performance of C8P10E5C was evaluated. The FT-IR, ESI-MS, and NMR spectra confirmed that C8P10E5C was successfully prepared. The critical micelle concentration (CMC) of C8P10E5C in water was 2.9510 × 10-4 mol/L (the corresponding mass concentration is 0.26%), and the surface tension of the aqueous C8P10E5C solution at this concentration was 30.5728 mN/m. At 0.3% concentration, the contact angle of the C8P10E5C solution was 31.4°, which is 60.75% lower than the initial contact angle. Under high-temperature conditions, C8P10E5C can still reduce the oil-water interfacial tension to 10-2 mN/m, exhibiting good temperature resistance. At 110 °C, upon adsorption to oil sand, the C8P10E5C solution could reduce the oil-water interfacial tension to 0.0276 mN/m, and the interfacial tension can still reach the order of 10-2 mN/m, indicating that C8P10E5C has strong anti-adsorption capability. Additionally, it has good emulsifying performance; upon forming an emulsion with crude oil, the highest drainage rate was only 50%. The forced imbibition oil recovery of C8P10E5C is 65.8%, which is 38.54, 24.22, and 27.25% higher than those of sodium dodecyl benzene sulfonate, alkyl polyoxyethylene ether carboxylate, and alkyl ether carboxylate, respectively.

A Supramolecular Reinforced Gel Fracturing Fluid with Low Permeability Damage Applied in Deep Reservoir Hydraulic Fracturing

Gel fracturing fluid is the optimum fracturing fluid for proppant suspension, which is commonly applied in deep reservoir hydraulic fracturing. The content of polymers and crosslinkers in gel fracturing fluid is usually high to meet the needs of high-temperature resistance, leading to high costs and reservoir permeability damage caused by incomplete gel-breaking. In this paper, a supramolecular reinforced gel (SRG) fracturing fluid was constructed by strengthening the supramolecular force between polymers. Compared with single network gel (SNG) fracturing fluid, SRG fracturing fluid could possess high elasticity modulus (G' = 12.20 Pa) at lower polymer (0.4 wt%) and crosslinker (0.1 wt%) concentrations. The final viscosity of SRG fracturing fluid was 72.35 mPa·s, meeting the temperature resistance requirement of gel fracturing fluid at 200 °C. The gel-breaking time could be extended to 90-120 min using an encapsulated gel breaker. Gel particles are formed after the gel fracturing fluid is broken. The median particle size of gel particles in the SRG-breaking solution was 126 nm, which was much smaller than that in the industrial gel (IDG) breaking fluid (587 nm). The damage of the SRG-breaking solution to the core permeability was much less than the IDG-breaking solution. The permeability damage of cores caused by the SRG-breaking solutions was only about half that of IDG-breaking solutions at 1 mD.