Spontaneous Imbibition and Oil Displacement Experimental Investigation in Fracture–Matrix Cores of Tight Sandstone Reservoirs

Spontaneous Imbibition and Oil Displacement Experimental Investigation in Fracture–Matrix Cores of Tight Sandstone Reservoirs | Research Square window.SnipcartSettings = { analytics: { enabled: false } }; (function() { var accessVector = localStorage.getItem('access_vector') || ''; window.dataLayer = window.dataLayer || []; if (accessVector) { window.dataLayer.push({ user: { profile: { profileInfo: { snid: accessVector } } } }); } })(); (function(w,d,s,l,i){w[l]=w[l]||[];w[l].push({'gtm.start':new Date().getTime(),event:'gtm.js'});var f=d.getElementsByTagName(s)[0],j=d.createElement(s),dl=l!='dataLayer'?'&l='+l:'';j.async=true;j.src='https://www.googletagmanager.com/gtm.js?id='+i+dl;f.parentNode.insertBefore(j,f);})(window,document,'script','dataLayer','GTM-K279D39R'); Browse Preprints In Review Journals COVID-19 Preprints AJE Video Bytes Research Tools Research Promotion AJE Professional Editing AJE Rubriq About Preprint Platform In Review Editorial Policies Our Team Advisory Board Help Center Sign In Submit a Preprint Cite Share Download PDF Article Spontaneous Imbibition and Oil Displacement Experimental Investigation in Fracture–Matrix Cores of Tight Sandstone Reservoirs Weihua Chen, Rui He, Li Li, Jiejing Bai, Zhengyong Li, Tao Wang, and 3 more This is a preprint; it has not been peer reviewed by a journal. https://doi.org/ 10.21203/rs.3.rs-8698096/v1 This work is licensed under a CC BY 4.0 License Status: Published Journal Publication published 18 Mar, 2026 Read the published version in Scientific Reports → Version 1 posted 10 You are reading this latest preprint version Abstract Tight sandstone reservoirs are characterized by low porosity and low permeability, which results in great difficulty in oil production and low recovery. In this work, based on fractured–matrix tight sandstone core models and field crude oil, the interfacial activity and reservoir adaptability of the oil displacement agent C-22 were evaluated. Subsequently, oil displacement agents with different interfacial tension levels were optimized and selected as control groups for subsequent oil displacement experiments. The migration behavior of crude oil in fractured–matrix cores during spontaneous imbibition and oil displacement processes using C-22 was systematically investigated, and the key development parameters for oil displacement were further optimized. The results show that C-22 exhibits excellent interfacial activity and good reservoir adaptability. An ultralow interfacial tension of 0.12 mN/m can be achieved at a concentration of 0.1 wt%, and the interfacial tension remains stable after 7 d of aging. In the oil displacement experiments, as the pressure decreases from 15 MPa to 0 MPa, the final oil recovery reaches 18.94%. Nuclear magnetic resonance analysis indicates that oil in mesopores and macropores is predominantly mobilized at the early stage, whereas oil in micropores is mainly produced at the later stage. Furthermore, the key development parameters for the oil displacement process were optimized. The optimal oil displacement performance is achieved when the interfacial tension is reduced to the 10 − 2 mN/m level, the concentration of C-22 is 0.2 wt%, and the shut-in time is 12 h. We expect that this study can provide valuable insights into the effective development of tight sandstone reservoirs and offer theoretical guidance for the selection of field operational parameters. Physical sciences/Energy science and technology Physical sciences/Engineering Physical sciences/Materials science tight sandstone reservoirs fracture–matrix cores spontaneous imbibition oil displacement Figures Figure 1 Figure 2 Figure 3 Figure 4 Figure 5 Figure 6 Figure 7 Figure 8 Figure 9 Figure 10 Figure 11 Figure 12 1. Introduction The global share of unconventional oil and gas resources is steadily increasing. As most conventional reservoirs have entered the late stage of development, unconventional resources have become a critical focus for exploration and production [ 1 – 3 ]. Tight sandstone reservoirs, as representative unconventional reservoirs, are characterized by poor petrophysical properties, low permeability, pronounced matrix–fracture heterogeneity, complex pore structures, and strong anisotropy [ 4 – 6 ]. These features lead to the limited effectiveness of conventional water injection in such reservoirs and place greater demands on advanced reservoir stimulation technologies, such as hydraulic fracturing [ 7 , 8 ]. Hydraulic fracturing is a key stimulation technology for the development of unconventional oil and gas reservoirs [ 9 , 10 ]. It enhances well productivity by injecting high-pressure fracturing fluids to generate artificial fractures, thereby improving the permeability of hydrocarbon-bearing formations. However, the narrow pore throats and limited flow capacity inherent to tight sandstone reservoirs restrict the overall effectiveness of stimulation [ 11 – 13 ]. Therefore, to achieve efficient reservoir modification, it is necessary that, following the creation of a large-scale fracture network by hydraulic fracturing to enhance crude oil mobility, the fracturing fluid continues to function as an effective agent for imbibition and displacement [ 14 – 16 ]. This ensures that the energy invested in fracturing is utilized to the maximum extent possible. The integrated fracturing flooding technology has been proposed and has attracted widespread attention [ 17 , 18 ]. This approach involves a shut-in period after the fracturing fluid completes fracture creation, during which imbibition and displacement occur between the fracturing fluid and crude oil. Driven by the pressure differential during flowback, well productivity can be significantly improved [ 19 , 20 ]. Imbibition refers to the process in which the wetting phase displaces the non-wetting phase under the influence of capillary forces in the porous medium [ 21 – 23 ]. Since the nineteenth century, extensive studies have been conducted worldwide to investigate the role of imbibition in enhancing oil recovery [ 24 – 26 ]. Yang et al. [ 27 ] examined the influence of fracture distribution on surfactant imbibition in tight sandstone reservoirs and found that fractures can effectively reduce oil droplet adsorption on the core surface, increasing imbibition recovery by approximately 10%. Moreover, surfactants were shown to further improve oil recovery by about 15% through enhancing water wettability of the rock surface, reducing interfacial tension, and weakening oil droplet adhesion. Liu et al. [ 28 ] developed a novel hydrophilic silica, and spontaneous imbibition experiments demonstrated that it can readily enter reservoir pores and adsorb onto rock surfaces, alter wettability to promote crude oil detachment, and ultimately achieve an oil recovery of 36%. Despite the extensive research on surfactant flooding and spontaneous imbibition, studies that specifically elucidate oil-phase flow characteristics and mobilization mechanisms in fracture–matrix core systems remain limited. During production, several key challenges must be addressed, including the coupling between interfacial tension and capillary forces, preferential channeling of displacing fluids along fractures, coupled fracture–matrix flow, low sweep efficiency, and difficulties in pore–throat characterization and large-scale numerical simulation [ 29 , 30 ]. Therefore, there is an urgent need to clarify the oil flow behavior in both fractures and the matrix and to elucidate the mechanisms governing oil mobilization within pores during spontaneous imbibition. In this work, fractured–matrix tight sandstone core models and field crude oil were employed to evaluate the interfacial activity and reservoir adaptability of the oil displacement agent C-22. Oil displacement agents with different interfacial tension levels were subsequently optimized and selected as control groups for comparative oil displacement experiments. The migration behavior of crude oil in fractured–matrix cores during spontaneous imbibition and displacement processes using C-22 was systematically investigated, and the key operational parameters governing oil displacement were further optimized. Based on these results, an oil displacement strategy tailored for tight sandstone reservoir is proposed, providing theoretical insight and technical support for the efficient development of tight sandstone reservoirs. 2. Results and Discussion 2.1. SARA Analysis, Density, and Viscosity of Field Crude Oil The crude oil was analyzed for SARA composition, density, and viscosity, and the results are presented in Table 1 . It can be seen that the content of saturated hydrocarbon and aromatic hydrocarbon in the light component of crude oil is more than 90%, which makes the crude oil show low density and low viscosity. This kind of crude oil has good fluidity and is easy to exploit. Table 1 Crude oil composition and property analysis. SARS analysis/% Density/ (g/cm 3 ) Viscosity /mPa·s Saturates Aromatics Resins Asphaltenes 72.32 18.04 3.98 5.66 0.84 11.47 2.2. Interfacial Activity of Oil Displacing Agents 2.2.1. Screening of Control Groups with Oil Displacing Agents at Different Interfacial Tension Magnitudes The core of the oil increasing effect of the working fluid for fracture-flooding depends on three factors: interfacial activity, wetting change performance and emulsifying solubilization performance. The interfacial activity can reduce the oil-water interfacial tension and weaken the adhesion of crude oil. The wettability change performance can change the wettability of rock from lipophilic to hydrophilic, and improve the efficiency of oil washing. The emulsification solubilization performance can make the residual oil form a stable emulsion and expand the displacement range. Surfactant is a commonly used oil displacement chemical agent because of its amphiphilicity. It can not only change the wettability of rock and reduce the interfacial tension of oil and water, but also regulate the above three properties, synergistically improve the effect of pressure flooding and increase oil production, and adapt to the development needs of different reservoirs. To meet the requirements of subsequent imbibition experiments, three surfactants with different magnitudes of interfacial tension were selected for comparison using a TX-500C full-range spinning drop interfacial tensiometer based on reservoir crude oil. The screening results are presented in Table 2 . Table 2 Screening surfactants corresponding to crude oil with different orders of magnitude of interfacial tension. System Name Concentration/% Interfacial Tension /(mN/m) C-22 0.3 0.0599 LHSB 0.1 2.5580 THSB35 0.1 0.7923 CAB-35 0.1 1.0561 LAS-30 0.1 0.4044 AEO15 0.1 1.6145 NPES 0.1 1.0473 CAB-35: LAS-30 = 8:2 0.1 0.2219 THSB35: LAS-30 = 5:5 0.1 0.1436 THSB35: LAS-30 = 4:6 0.1 0.0184 THSB35: LAS-30 = 3:7 0.1 0.0068 Based on the experimental data, the following surfactants and their corresponding interfacial tensile strength levels were selected: THSB35 at a concentration of 0.1% as the surfactant with interfacial tension at the 10 − 1 mN/m magnitude; C-22 at a concentration of 0.3% as the surfactant with interfacial tension at the 10 − 2 mN/m magnitude. The blended system THSB35:LAS-30 = 3:7 as the surfactant with interfacial tension at the 10 − 3 mN/m magnitude. 2.2.2. Interfacial Tension of Oil Displacing Agent (C-22) at Different Concentrations Interfacial tension is one of the key indicators for evaluating the performance of a displacing agent. A lower value signifies a stronger ability of the displacing agent to reduce oil-water interfacial tension and mobilize residual oil, thereby leading to higher displacement efficiency. To further understand the performance of the selected displacing agent (C-22), this study measured its interfacial tension against the target reservoir crude oil under different concentration conditions. The experimental results are shown in Fig. 1 . The interfacial tension exhibits a trend of first decreasing significantly and then stabilizing as the concentration increases. At lower concentrations, increasing the C-22 concentration allows more molecules to adsorb at the oil-water interface, effectively reducing the tension. When the concentration is sufficiently high and the interface becomes saturated, further increases in concentration primarily lead to the formation of micelles within the bulk solution, and no significant change in interfacial tension is observed thereafter. 2.2.3. Interfacial Tension of Oil Displacing Agent (C-22) at Different Aging Times In the process of fracturing-flooding, surfactant is used as the core oil displacement agent. After being injected into the subsurface, surfactants must endure formation high-temperature and high-pressure conditions, and their stability is a key performance indicator determining displacement efficiency [ 31 , 32 ]. Therefore, to evaluate the long-term stability of the displacing agent under simulated high-temperature reservoir conditions, the displacing agent solution was aged at reservoir temperature to mimic formation conditions. During the experiment, regular testing is required to observe whether the solution has state changes such as stratification and precipitation, and to monitor the fluctuation of interfacial tension, so as to provide key data support for the selection of displacement agents and the optimization of oil displacement schemes. Figure 3 shows photographs of the oil displacement agent solution aged at 68°C during the aging process for 0, 2, 4, and 7 d, respectively. The solution remained clear and transparent throughout the 7 d aging period, preliminarily indicating its stability under simulated reservoir conditions. Interfacial tension measurements between the oil displacement agent and crude oil from the corresponding reservoir were conducted, with results shown in Fig. 2 . The interfacial tension remained essentially stable as aging time increased, demonstrating that the oil displacement agent C-22possesses good reservoir compatibility and can maintain effective oil displacement performance over extended durations. 2.3. Spontaneous Imbibition in Fracture-Matrix Models 2.3.1. Evaluation of Spontaneous Imbibition Recovery Using Oil Displacing Agents at Different Concentrations Spontaneous imbibition occurs during the soaking process after the formation fracturing is completed. At this time, the working fluid for fracture-flooding encapsulates the rock matrix and is in a static state. At this time, the capillary force is the main force. The wettability of the imbibition medium determines whether the capillary force is the driving force or the resistance. Good emulsification disperses large pieces of crude oil into small oil droplets that are easier to pass through the pore throat of the rock. The imbibition medium enters the small pore channel to replace the crude oil into the large pore channel, and finally discharges the matrix system into the fracture or the wellbore. To investigate the effect of interfacial tension on crude oil flow during spontaneous imbibition experiments, tests were designed and conducted using displacing agents at different concentrations, corresponding to varying magnitudes of interfacial tension. The spontaneous imbibition recovery results are shown in Fig. 4 . The recovery factors for simulated formation water, 0.02 wt%, 0.3 wt%, and 0.4 wt% displacing agent solutions were 5.79%, 15.87%, 27.37%, and 32.57%, respectively. As the concentration of the displacing agent C-22 increased, the imbibition recovery showed a progressive upward trend. Particularly in the early stage of imbibition, higher concentrations led to faster imbibition rates. At a concentration of 0.02 wt%, the interfacial tension was greater than 1 mN/m. When the concentration of C-22 reached 0.3 wt%, the interfacial tension could be reduced to the order of 10 − 2 mN/m, resulting in a significant improvement in recovery. At a concentration of 0.4 wt%, the interfacial tension reached the order of 10 − 1 mN/m. The displacing agent C-22 can more effectively reduce the oil-water interfacial tension, significantly lowering the flow resistance of crude oil in small pores and throats, promoting the emulsification and stripping of crude oil, and reducing its migration resistance. This enhances the liquid's penetration ability within the rock pores, thereby promoting crude oil stripping and flow and improving the recovery factor. The highest imbibition recovery was achieved when the interfacial tension was on the order of 10 − 1 mN/m. 2.3.2. Characteristics of Crude Oil Flow During Imbibition in Fracture-Matrix Cores Nuclear magnetic resonance (NMR) technology can detect the signal of T 2 relaxation of hydrogen nuclei, which effectively indicates the existence of substances that can produce this signal. Therefore, by using heavy water to shield the hydrogen signal of water in the oil displacement agent solution, the nuclear magnetic resonance T 2 spectrum can only identify the hydrogen signal of crude oil in the core, so that the dynamic migration characteristics of crude oil in the large, medium and micropore throat system of the core can be qualitatively identified by this method, and the start-up, flow and retention mode of crude oil in the matrix can be clearly analyzed, which provides reliable experimental data support for optimizing the displacement scheme and enhancing oil recovery. As shown in Fig. 5 , before the imbibition experiment began, the core saturated with simulated oil exhibited the highest signal intensity. As imbibition progressed, the NMR signal from within the pores continuously decreased. This indicates that crude oil in pores of different sizes was mobilized to varying degrees throughout the imbibition process. In the early stage of imbibition, the core signal changed noticeably. By 48 h of imbibition, the signal amplitude had decreased significantly, indicating that a substantial amount of oil had been displaced from the core. When imbibition continued beyond 96 h, the signal amplitude in the core still decreased but no longer markedly, suggesting that the oil-water migration within the core had largely stabilized. To further investigate the extent of oil mobilization in different pore types during various imbibition stages, the area under the curve for different pore regions in Fig. 5 was calculated through integration. This allowed the determination of oil mobilization extents in small, medium, and large pores at different imbibition stages. The results are shown in Fig. 6 . During the early imbibition stage (0–48 h), the oil mobilization extents for small, medium, and large pores were 30.76%, 33.50%, and 99.91%, respectively. Large pores exhibited the highest mobilization extent, primarily because oil in the fractures of the fractured matrix core is more readily mobilized and nearly completely displaced during the early imbibition phase. In the middle imbibition stage, medium pores showed relatively higher oil mobilization compared to small and large pores. Between 48 and 96 h, the oil mobilization extents for small, medium, and large pores were 10.47%, 29.95%, and 0.086%, respectively. This is attributed to the smaller pore-throat size and more complex pore structure in small pores, which contain a higher proportion of inaccessible pores, whereas medium pores, with relatively simpler structures, continue to contribute significantly to oil mobilization. In the late imbibition stage, simulated oil in small pores exhibited the highest mobilization extent. Between 96 and 144 h, the mobilization extent of simulated oil in small pores was 15.52%, while that in medium pores was 6.57%, indicating relatively low mobilization. At this stage, most of the oil in medium pores had already been displaced, and the displacing agent solution continued to enter small pores to mobilize the remaining oil. 2.4. Characteristics of Crude Oil Flow During Depletion Production in Fracture-Matrix Models The results of crude oil depletion production are shown in Fig. 7 . When the pressure was reduced from 15 MPa to 10 MPa, the recovery factor was 3.67%. As the pressure was further reduced to 5 MPa, the recovery factor increased to 10.25%. When the pressure was lowered to 0 MPa, the recovery factor reached 18.94%. During production by depressurization, the decrease in reservoir pressure disrupts the original equilibrium: fluids expand elastically due to the pressure drop, while the rock matrix contracts as effective stress increases, leading to pore volume reduction. The combined release of elastic energy from both mechanisms creates a displacement force that overcomes flow resistance, thereby driving oil migration and production. As shown in Fig. 8 and Fig. 9 , the T 2 spectra and pore mobilization patterns during crude oil depletion production indicate that when the pressure was reduced to 10 MPa, a synchronous and significant decline in signals was observed across pores of all scales. Combined with the mobilization patterns presented in Fig. 9 , medium and large pores contributed over 60% of the oil mobilization during the early stage, serving as the primary driver of displacement. In the later stage, small pores became the main contributors to oil displacement relative to medium and large pores. In summary, the oil flow behavior during depletion production can be described as follows: in the early production stage, the fracture system preferentially contributes through medium and large pores, while in the later stage, matrix pores take over as the main contributors, reflecting typical dual-porosity production characteristics. 2.5. Refined Optimization of Operational Parameters Based on Physically Simulated Displacement Experiments To optimize the construction parameters for shut-in well stimulation with oil displacement agents, multiple sets of physical simulation displacement experiments were conducted. These experiments systematically investigated the performance differences of various types of displacement agents, the displacement efficiency at different concentrations, and the impact of different shut-in durations on imbibition effects. Through comparative analysis of the experimental data, the optimal type of displacement agent and its corresponding concentration suitable for the target reservoir conditions were screened. Additionally, the minimum effective soaking time required to achieve the best imbibition displacement effect was determined. This study provides a reliable experimental basis and technical support for the precise optimization of displacement agent type, concentration ratio, and soaking process parameters in field pilot tests. 2.5.1. Optimization of Interfacial Tension for Oil Displacing Agents As shown in Fig. 10 , the recovery factors during depletion production at different interfacial tensions indicate that different displacing agents exhibit varying displacement performances due to their distinct properties. For the displacing agent C-22, when its concentration is 0.02%, the interfacial tension with crude oil exceeds 1 mN/m. When the concentration is increased to 0.3%, the interfacial tension decreases to the order of 10 − 2 mN/m. Further increasing the concentration to 0.4% raises the interfacial tension back to the level of 10 − 1 mN/m. At the same concentration of 0.1%, LAS-30 exhibits an interfacial tension with crude oil at the order of 10 − 1 mN/m, while the blended system of LHSB and LAS-30 at a 3:7 ratio can reduce the interfacial tension to the order of 10 − 3 mN/m. The core mechanism of surfactant flooding technology is to significantly reduce the interfacial tension between oil displacement agent and crude oil, so as to effectively enhance oil recovery. When the interfacial tension is reduced, the capillary resistance required for the migration of crude oil in rock pores can be significantly reduced, making the residual oil more likely to deform and be driven. It can be observed that as the interfacial tension between the displacing agent and crude oil decreases, the recovery factor increases sequentially. When the interfacial tensions of different displacing agents with crude oil are within the same order of magnitude, they exhibit relatively similar displacement performance. This is because the oil displacement efficiency is largely controlled by the number of capillaries (which is the ratio of the product of viscosity and flow rate to interfacial tension). The lower the interfacial tension, the larger the number of capillaries, and the more conducive to the start-up of crude oil. 2.5.2. Optimization of Oil Displacing Agent Concentration As shown in Fig. 11 , the recovery factors during depletion production at different displacing agent concentrations indicate that after the pressure was reduced to 0 MPa, the recovery factor was 12.79% at a concentration of 0.1%. As the concentration of the displacing agent C-22 increased, the crude oil recovery factor improved. At a concentration of 0.2%, the recovery factor was 16.54%. At 0.3% concentration, the recovery factor reached 18.15%, showing no significant improvement compared to the recovery factor achieved with the 0.2% concentration solution. 2.5.3. Soaking Time Optimization Based on the experimental result curves, these three sets of test data clearly demonstrate the influence of shut-in time on crude oil recovery factor. Overall, a prolonged shut-in period correlates with a higher recovery factor, as the shut-in process provides sufficient contact time between the injected fluid and the formation crude oil, thereby enhancing the oil recovery efficiency. As the shut-in time increases, the crude oil recovery factor shows a corresponding improvement. However, when the shut-in period exceeds 12 h, the enhancement in recovery becomes less significant. This behavior is attributed to the well-connected pore network in sandstone, which facilitates efficient diffusion of the injected fluid during the shut-in period and promotes effective crude oil mobilization. Therefore, extending the soaking time to 12 h results in a substantial increase in recovery, whereas further extension beyond this timeframe yields only marginal additional gains. 3. Materials and Methods 3.1. Materials and Equipments Materials: Crude oil, sourced from Well X located at a tight oil field in Western China; C-22 displacing agent, sourced from the laboratory of the tight oil field; Lauramidopropyl betaine (LHSB), sourced from Shanghai Aladdin Biochemical Technology Co., Ltd.; Tetradecyl hydroxypropyl sulfobetaine (THSB35), sourced from Shanghai Aladdin Biochemical Technology Co., Ltd.; Cocamidopropyl betaine (CAB-35), sourced from Shanghai Deyi Chemical Co., Ltd.; Sodium dodecylbenzenesulfonate (LAS-30), sourced from Linyi Lvsen Chemical Co., Ltd.; Alcohol ethoxylate 15 (AEO15), sourced from Shanghai Aladdin Biochemical Technology Co., Ltd.; Sodium nonylphenol ethoxylate (10) sulfate (NPES), sourced from Jiangsu Haian Petrochemical Plant; Heavy water, sourced from Shanghai Aladdin Biochemical Technology Co., Ltd.; Sandstone core, sourced from Well X. Equipment: PS-80A CNC Ultrasonic Cleaner, Dongguan Jiekang Ultrasonic Equipment Co., Ltd.; Multi-functional Flow Test and Evaluation System, Beijing Yongruida Technology Co., Ltd.; MacroMR12-150H-I Online Nuclear Magnetic Resonance Analysis and Detection System, Suzhou Niumag Analytical Instrument Co., Ltd.; Analytical Balance, Mettler-Toledo International Trading (Shanghai) Co., Ltd.; UPR Series Ultra-Pure Water System, Sichuan UPR Ultra-Pure Technology Co., Ltd.; Vacuum Drying Oven, Qingdao Lanten Science and Education Instrument Equipment Co., Ltd.; TX-500C Interfacial Tensiometer, Krüss GmbH, Germany; High-Pressure Oil Saturation Device, Haian Petroleum Scientific Research Instrument Co., Ltd. 3.2. Experimental Methods 3.2.1. Determination of the Amount of Foaming Agent (1) All syringes, sample tubes, and tube caps were cleaned with petroleum ether and ethanol, followed by rinsing with the test solution. (2) After rinsing, an appropriate volume of the test surfactant was drawn into a syringe and slowly injected into the sample tube, ensuring that no air bubbles were generated. (3) An appropriate amount of the test formation oil was then drawn into another syringe, and a single droplet was injected into the sample tube. The syringe was quickly withdrawn to ensure the droplet remained suspended without adhering to the tube wall. (4) The sample tube was held horizontally, securely capped, and placed onto the instrument's rotating shaft, after which the shaft cap was attached. The interfacial tensiometer and associated software were turned on, and the temperature was set to 68°C, the rotational speed to 6000 r·min⁻¹, and the density difference between the oil sample and the test solution was input. The test was then initiated. (5) The microscope was fine-tuned to locate the target oil droplet. The leveling button was used to keep the droplet stationary within the on-screen field of view. After stabilization, the interfacial tension was measured. 3.2.2. Static Spontaneous Imbibition and T 2 Spectrum Experiments (1) The constant-temperature water bath was switched on and set to 68°C. (2) The imbibition cell was cleaned sequentially with petroleum ether, ethanol, and the test fluid. (3) The core was placed at the bottom of the imbibition cell, which was partially filled with the test fluid without exceeding its rim. Vaseline was applied around the rim, the cell was covered with its lid, and the seal was reinforced with plastic film to prevent evaporation. (4) The test fluid was continuously added via the extended rubber tubing until the imbibition cell was completely filled. (5) The volume of expelled oil was recorded at designated time intervals, and the recovery factor was calculated accordingly. (6) The T 2 spectra were measured using the Nuclear Magnetic Resonance (NMR) system at 0 h, 48 h, 96 h, and 144 h of the imbibition process. 3.2.3. Displacement Experiment (1) The core was prepared into a fractured core using a core orientation and splitting device. Following cleaning and drying, the core was saturated with crude oil using a vacuum-pressure saturation system. (2) The multifunctional flow test and evaluation system was started. The sample solution was filled into the intermediate container, the ISCO pump was activated, and the core was placed into the core holder with all flow lines connected. The oven temperature was set to 68°C. After temperature stabilization, the confining pressure of the core holder was set to 18 MPa and the back pressure to 15 MPa. (3) The valve at the outlet end of the core holder was closed. The ISCO pump was reactivated and set to constant pressure mode. The sample solution was injected into the crude oil-saturated fractured core from the inlet end until the system pressure stabilized at 15 MPa. Subsequently, the inlet valve was closed, and the shut-in period was initiated. (4) Depletion production was simulated by gradually reducing the pressure at the outlet end using the back pressure regulator, with stepwise decreases to 10 MPa, 5 MPa, and finally 0 MPa. Pressure changes and recovery factors were recorded throughout the entire process. 3.2.4. Nuclear Magnetic Resonance Experiment Based on the aforementioned oil displacement experimental procedure, the online nuclear magnetic resonance analysis and detection system was employed to scan the T 2 spectra of the fractured matrix core saturated with simulated oil under initial conditions and at pressure reduction stages of 10 MPa, 5 MPa, and 0 MPa, respectively. The distribution of remaining oil within the core was observed, and the extent of oil phase mobilization in the core matrix was analyzed. Throughout the NMR scanning experiment, heavy water was used to prepare all solutions in order to eliminate interference from water signals [ 33 , 34 ]. The parameters of the cores used in the experiment are listed in Table 3 . Table 3 Core parameters. Number Length/cm Diameter/cm Porosity/% Permeability /10 − 3 µm 2 1 5.06 2.48 4.98 0.13 2 4.96 2.47 4.87 0.15 3 5.04 2.49 4.76 0.12 4 5.04 2.48 4.80 0.13 5 5.08 2.49 4.86 0.17 6 5.03 2.49 4.93 0.12 7 4.99 2.50 4.95 0.13 8 4.99 2.50 4.95 0.13 9 5.01 2.53 4.94 0.17 10 5.03 2.52 4.98 0.12 11 4.98 2.47 4.81 0.12 12 5.02 2.51 5.01 0.16 13 4.97 2.47 4.96 0.15 14 4.98 2.50 4.79 0.14 15 5.00 2.48 5.02 0.17 16 5.01 2.47 4.84 0.16 17 4.99 2.52 478 0.18 18 5.03 2.52 4.89 0.13 4. Conclusions (1) When the concentration of the displacing agent C-22 is 0.4%, the interfacial tension between the agent and crude oil is at the order of 10 − 1 mN/m, and the highest spontaneous imbibition recovery achieved is 32.57%. NMR T 2 spectra analysis reveals the mobilization sequence during the imbibition process: in the early stage, oil in large pores and throats is rapidly mobilized, while in the mid to late stages, medium and small pores/throats contribute successively. This indicates that imbibition efficiency is closely related to the mobilization sequence of pore-throat structures. (2) During the production process as pressure was depleted from 15 MPa to 0 MPa, the ultimate recovery factor reached 18.94%. The mobilization behavior demonstrates a dual-porosity flow mechanism: early production is primarily dominated by the fracture system (medium and large pores/throats), while later production relies on supplementary contribution from matrix pores. This pattern indicates that effectively mobilizing the crude oil within the matrix is critical for enhancing the performance of depletion-based production. (3) Based on physical simulation experiments, the optimal parameter combination for achieving the best development performance has been determined: the interfacial tension should be maintained at the order of 10 − 2 mN/m, the concentration of C-22 should be optimized to 0.3%, and the soaking time should be set to 12 h (this conclusion is based on the research of this paper, which may have some limitations, and further research is needed in the next step). This parameter set ensures displacement efficiency while promoting balanced mobilization of the fracture-matrix system, providing critical theoretical support and practical guidance for the efficient development of tight sandstone reservoirs. Declarations Declaration of competing interest The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper. Funding The work was supported by the CNPC Major Science and Technology Projects (Number 2023ZZ17YJ03). Author Contribution A.B.: Supervision, Funding Acquisition, Project Administration, Conceptualization, Investigation, Writing – Review & Editing.C.D.: Conceptualization, Methodology, Experimental Design, Investigation, Formal Analysis, Writing – Original Draft.E.F.: Supervision, Investigation, Validation, Resources, Writing – Review & Editing.G.H.: Investigation, Data Curation, Formal Analysis, Visualization.I.J.: Supervision, Validation, Writing – Review & Editing.K.L.: Investigation, Resources, Writing – Review & Editing.M.N.: Supervision, Project Administration, Investigation.O.P.: Project Administration, Resources, Writing – Review & Editing.Q.R.: Experimental Design, Writing – Review & Editing.All authors have read and agreed to the published version of the manuscript. Data Availability The datasets generated and/or analysed during the current study are not publicly available due to the proprietary nature of the oil displacement agent and its supporting data, which are currently in the initial stage of field application. Public release at this critical phase could compromise commercial interests and ongoing technology transfer agreements. The data are available from the corresponding author on reasonable request, subject to a confidentiality agreement. References Abdulhadi, D., Ali, J. A. & Hama, S. M. Advanced Techniques for Improving the Production of Natural Resources from Unconventional Reservoirs: A State-of-the-Art Review. Energy Fuels . 39 (23), 10853–10876. 10.1021/acs.energyfuels.5c01259 (2025). Guo, B. E., Xiao, N., Martyushev, D. & Zhao, Z. Deep learning-based pore network generation: Numerical insights into pore geometry effects on microstructural fluid flow behaviors of unconventional resources. 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Fine description of natural fractures in the tight sandstone reservoir of the Yanchang reservoirs in the southern Ordos Basin. Sci. Rep. 15 (1), 6152. 10.1038/s41598-025-90757-y (2025). Xu, M. et al. Experimental Study on the Mechanical Damage and Permeability Evolution of Tight Sandstone Reservoir Under Triaxial Loading. Processes 13 (12), 3919–3933. https://doi.org/10.3390/pr13123919 (2025). Shi, F. et al. Influence of Imbibition Fracturing Fluid on the Original Water and Methane Occurrence in Actual Coalbed Methane Reservoirs Using the Integrated Device of Displacement and Low-Field Nuclear Magnetic Resonance. Langmuir 40, (6), 3063–3073. (2024). 10.1021/acs.langmuir.3c03351 Xu, Z. et al. Nanoslickwater Fracturing Fluid with Enhanced Imbibition Capacity for Low-Permeability Reservoirs. Energy Fuels . 39 (2), 1141–1151. 10.1021/acs.energyfuels.4c04890 (2025). Zhang, T. et al. The imbibition mechanism for enhanced oil recovery by gel breaking fluid of SiO2-enhanced seawater-based VES fracturing fluid in offshore low permeability reservoir. Geoenergy Sci. Eng. 244 , 213403. https://doi.org/10.1016/j.geoen.2024.213403 (2025). Wu, G. et al. Effect of nano-SiO 2 on the flowback-flooding integrated performance of water-based fracturing fluids. J. Mol. Liq. 379 , 121686. https://doi.org/10.1016/j.molliq.2023.121686 (2023). Zhao, M. et al. Characteristics and efficient imbibition-oil displacement mechanism of gemini surfactant slickwater for integrated fracturing flooding technology. Acta Petrolei Sinica . 45 (9), 1409–1421. 10.7623/syxb202409008 (2024). Liu, J. et al. Recent advances in nanoparticle-enhanced clean VES fracturing fluids: a comprehensive review of performance improvement, synergy, and challenges. Chem. Eng. Sci. 319 , 122240. https://doi.org/10.1016/j.ces.2025.122240 (2026). Su, Y. et al. Investigation of fully coupled fracture propagation and oil–water two-phase flow mechanisms in fracturing flooding. Phys. Fluids . 37 (5), 056611. 10.1063/5.0268819 (2025). Ma, Z. F. et al. Experimental study of imbibition depth and oil migration mechanism of a magnetic nanofluid for low-permeability reservoir oil recovery improvement. Pet. Sci. https://doi.org/10.1016/j.petsci.2025.11.026 (2025). Wei, J. et al. Online NMR Quantification of Pore-Scale Imbibition and Oil Recovery in Shale Reservoirs. Energy Fuels . 39 (51), 24152–24161. 10.1021/acs.energyfuels.5c05095 (2025). Zhao, M. et al. Study on the main factors and mechanism of functional silica nanofluid spontaneous imbibition for enhanced oil recovery. J. Mol. Liq. 394 , 123699. https://doi.org/10.1016/j.molliq.2023.123699 (2024). Han, X. et al. Investigation on oil recovery and countercurrent imbibition distance coupling carbonated water with surfactant in shale oil reservoirs. Fuel 374 , 132409. https://doi.org/10.1016/j.fuel.2024.132409 (2024). Li, S., Du, K., Wei, Y., Li, M. & Wang, Z. Experimental Study on Forced Imbibition and Wettability Alteration of Active Carbonated Water in Low-Permeability Sandstone Reservoir. SPE J. 29 (05), 2607–2623. 10.2118/219454-PA (2024). Qu, H. et al. Experimental Study on the Mechanism of Enhanced Imbibition with Different Types of Surfactants in Low-Permeability Glutenite Reservoirs. Molecules 29 (24), 5953–5973. 10.3390/molecules29245953 (2024). Yang, K., Wang, F. Y. & Zhao, J. Y. Experimental study of surfactant-enhanced spontaneous imbibition in fractured tight sandstone reservoirs: The effect of fracture distribution. Pet. Sci. 20 (1), 370–381. https://doi.org/10.1016/j.petsci.2022.09.033 (2023). Liu, C. et al. Preparation and performance evaluation of nano-composite fracturing fluid with good oil displacement ability in tight reservoir. J. Mol. Liq. 367 , 120494. https://doi.org/10.1016/j.molliq.2022.120494 (2022). Cheng, Z. et al. Effect of Fracture-Matrix Interaction on CO 2 -Oil Displacement via Dual-Permeability Microfluidics. Energy Fuels . 39 (36), 17386–17396. 10.1021/acs.energyfuels.5c03117 (2025). Zhang, L. et al. A mathematical model and digital rock simulation of spontaneous imbibition in shale fracture-matrix systems. Phys. Fluids . 37 (8), 083602. 10.1063/5.0278553 (2025). Li, Q. et al. Synergistic enhancement of foam stability by nanocellulose and hydrocarbon surfactants. Chem. Eng. Sci. 299 , 120418. https://doi.org/10.1016/j.ces.2024.120418 (2024). Sun, X. et al. Effects of polymer, surfactant and solid particle on the stability of wastewater produced from surfactant/polymer flooding. Colloids Surf., A . 698 , 134419. https://doi.org/10.1016/j.colsurfa.2024.134419 (2024). Gong, H. et al. Effects of Kerogen on the Flow and EOR Performance of Oil in Shale Cores during CO 2 Flooding Process Investigated by NMR Technology. SPE J. 27 (04), 2244–2256. 10.2118/209581-PA (2022). Liu, J. R., Zhang, D. F., Liu, S. Y., Gong, R. D. & Wang, L. Multiscale investigation into EOR mechanisms and influencing factors for CO 2 -WAG injection in heterogeneous sandy conglomerate reservoirs using NMR technology. Pet. Sci. 22 (7), 2977–2991. https://doi.org/10.1016/j.petsci.2025.04.004 (2025). Additional Declarations No competing interests reported. Cite Share Download PDF Status: Published Journal Publication published 18 Mar, 2026 Read the published version in Scientific Reports → Version 1 posted Editorial decision: Revision requested 16 Feb, 2026 Reviews received at journal 13 Feb, 2026 Reviews received at journal 11 Feb, 2026 Reviewers agreed at journal 05 Feb, 2026 Reviewers agreed at journal 05 Feb, 2026 Reviewers invited by journal 05 Feb, 2026 Editor assigned by journal 04 Feb, 2026 Editor invited by journal 04 Feb, 2026 Submission checks completed at journal 03 Feb, 2026 First submitted to journal 03 Feb, 2026 You are reading this latest preprint version Research Square lets you share your work early, gain feedback from the community, and start making changes to your manuscript prior to peer review in a journal. As a division of Research Square Company, we’re committed to making research communication faster, fairer, and more useful. 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Also discoverable on Platform About Our Team In Review Editorial Policies Advisory Board Help Center Resources Author Services Accessibility API Access RSS feed Manage Cookie Preferences © Research Square 2026 | ISSN 2693-5015 (online) Privacy Policy Terms of Service Do Not Sell My Personal Information {"props":{"pageProps":{"initialData":{"identity":"rs-8698096","acceptedTermsAndConditions":true,"allowDirectSubmit":false,"archivedVersions":[],"articleType":"Article","associatedPublications":[],"authors":[{"id":586425368,"identity":"ad92a833-d1f2-443b-8517-e40f9ccc61b7","order_by":0,"name":"Weihua Chen","email":"","orcid":"","institution":"Engineering Technology Research Institute of Southwest Oil \u0026 Gas Field Company","correspondingAuthor":false,"prefix":"","firstName":"Weihua","middleName":"","lastName":"Chen","suffix":""},{"id":586425369,"identity":"85b13a80-a1f1-41ce-bbd0-f5f9decfc6ab","order_by":1,"name":"Rui 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China)","correspondingAuthor":false,"prefix":"","firstName":"Wei","middleName":"","lastName":"Zhang","suffix":""}],"badges":[],"createdAt":"2026-01-26 08:26:06","currentVersionCode":1,"declarations":"","doi":"10.21203/rs.3.rs-8698096/v1","doiUrl":"https://doi.org/10.21203/rs.3.rs-8698096/v1","draftVersion":[],"editorialEvents":[{"content":"https://doi.org/10.1038/s41598-026-44044-z","type":"published","date":"2026-03-18T15:57:30+00:00"}],"editorialNote":"","failedWorkflow":false,"files":[{"id":102246818,"identity":"ad7d3a61-4ed3-4253-969b-79d225ffcbcd","added_by":"auto","created_at":"2026-02-09 18:21:48","extension":"png","order_by":1,"title":"Figure 1","display":"","copyAsset":false,"role":"figure","size":8320,"visible":true,"origin":"","legend":"\u003cp\u003eInterfacial tension between crude oil and oil displacement agents with different 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time.\u003c/p\u003e","description":"","filename":"Onlinefloatimage3.png","url":"https://assets-eu.researchsquare.com/files/rs-8698096/v1/7c9c1fb19e54c9719c1d1a90.png"},{"id":102297557,"identity":"1c75a579-c6c1-42c1-89a8-a71f220b8bc1","added_by":"auto","created_at":"2026-02-10 10:28:12","extension":"png","order_by":4,"title":"Figure 4","display":"","copyAsset":false,"role":"figure","size":12611,"visible":true,"origin":"","legend":"\u003cp\u003eVariation of crude oil recovery via spontaneous imbibition versus time.\u003c/p\u003e","description":"","filename":"Onlinefloatimage4.png","url":"https://assets-eu.researchsquare.com/files/rs-8698096/v1/967f3c54f2e0b7bbbdd75fe2.png"},{"id":102297547,"identity":"72a41d07-73c2-4dfb-b4ab-49cd60e96aeb","added_by":"auto","created_at":"2026-02-10 10:28:09","extension":"png","order_by":5,"title":"Figure 5","display":"","copyAsset":false,"role":"figure","size":45220,"visible":true,"origin":"","legend":"\u003cp\u003e\u003cem\u003eT\u003c/em\u003e\u003csub\u003e2\u003c/sub\u003e spectra of crude oil during spontaneous imbibition.\u003c/p\u003e","description":"","filename":"Onlinefloatimage5.png","url":"https://assets-eu.researchsquare.com/files/rs-8698096/v1/2095d863ab094a6a5c8ad557.png"},{"id":102297285,"identity":"57dcd1b5-18fa-42a5-af74-09a9379595f0","added_by":"auto","created_at":"2026-02-10 10:26:45","extension":"png","order_by":6,"title":"Figure 6","display":"","copyAsset":false,"role":"figure","size":5888,"visible":true,"origin":"","legend":"\u003cp\u003eMobilization patterns of crude oil in pores during spontaneous imbibition.\u003c/p\u003e","description":"","filename":"Onlinefloatimage6.png","url":"https://assets-eu.researchsquare.com/files/rs-8698096/v1/ea3dae5c3d260de47d6667f5.png"},{"id":102246823,"identity":"88c8e8dd-a48c-4365-a1d4-a852b650930f","added_by":"auto","created_at":"2026-02-09 18:21:48","extension":"png","order_by":7,"title":"Figure 7","display":"","copyAsset":false,"role":"figure","size":9637,"visible":true,"origin":"","legend":"\u003cp\u003eDisplacement pressure versus recovery factor curve during depletion production\u003c/p\u003e","description":"","filename":"Onlinefloatimage7.png","url":"https://assets-eu.researchsquare.com/files/rs-8698096/v1/54b00cfc16d133ef7b1ee971.png"},{"id":102398565,"identity":"f226fac8-e5a7-42b3-92cd-0f2e6c4d922a","added_by":"auto","created_at":"2026-02-11 10:23:34","extension":"png","order_by":8,"title":"Figure 8","display":"","copyAsset":false,"role":"figure","size":37767,"visible":true,"origin":"","legend":"\u003cp\u003e\u003cem\u003eT\u003c/em\u003e\u003csub\u003e2\u003c/sub\u003e spectra during depletion production.\u003c/p\u003e","description":"","filename":"Onlinefloatimage8.png","url":"https://assets-eu.researchsquare.com/files/rs-8698096/v1/3a2c001e52c62f53c3093fac.png"},{"id":102297535,"identity":"2e98c5ae-970d-44da-9405-51540be80989","added_by":"auto","created_at":"2026-02-10 10:28:04","extension":"png","order_by":9,"title":"Figure 9","display":"","copyAsset":false,"role":"figure","size":5997,"visible":true,"origin":"","legend":"\u003cp\u003ePore mobilization patterns during depletion production.\u003c/p\u003e","description":"","filename":"Onlinefloatimage9.png","url":"https://assets-eu.researchsquare.com/files/rs-8698096/v1/54356d136b78544ea1ab4f1f.png"},{"id":102246827,"identity":"e497dd9e-a091-480e-9cc7-93f19bf2a413","added_by":"auto","created_at":"2026-02-09 18:21:48","extension":"png","order_by":10,"title":"Figure 10","display":"","copyAsset":false,"role":"figure","size":12546,"visible":true,"origin":"","legend":"\u003cp\u003eRecovery factor during depletion production at different interfacial tensions.\u003c/p\u003e","description":"","filename":"Onlinefloatimage10.png","url":"https://assets-eu.researchsquare.com/files/rs-8698096/v1/49e6ba4a43eb908fdab5861f.png"},{"id":102297622,"identity":"ee4012af-282b-4abe-afa3-bc1d2687fb5f","added_by":"auto","created_at":"2026-02-10 10:28:32","extension":"png","order_by":11,"title":"Figure 11","display":"","copyAsset":false,"role":"figure","size":9455,"visible":true,"origin":"","legend":"\u003cp\u003eRecovery factor during depletion production at different displacing agent concentrations.\u003c/p\u003e","description":"","filename":"Onlinefloatimage11.png","url":"https://assets-eu.researchsquare.com/files/rs-8698096/v1/388ac3568d231640b95b391c.png"},{"id":102246829,"identity":"4df98a55-a7cd-4a52-b215-9297658b49af","added_by":"auto","created_at":"2026-02-09 18:21:48","extension":"png","order_by":12,"title":"Figure 12","display":"","copyAsset":false,"role":"figure","size":8821,"visible":true,"origin":"","legend":"\u003cp\u003eRecovery factor during depletion production at different soaking time.\u003c/p\u003e","description":"","filename":"Onlinefloatimage12.png","url":"https://assets-eu.researchsquare.com/files/rs-8698096/v1/25849d756743840764168db3.png"},{"id":105224856,"identity":"2b312726-2f09-452d-8adc-aad2cf177c86","added_by":"auto","created_at":"2026-03-23 16:16:46","extension":"pdf","order_by":0,"title":"","display":"","copyAsset":false,"role":"manuscript-pdf","size":1950093,"visible":true,"origin":"","legend":"","description":"","filename":"manuscript.pdf","url":"https://assets-eu.researchsquare.com/files/rs-8698096/v1/c5c355ec-88eb-4447-9052-955e93bd3f53.pdf"}],"financialInterests":"No competing interests reported.","formattedTitle":"Spontaneous Imbibition and Oil Displacement Experimental Investigation in Fracture–Matrix Cores of Tight Sandstone Reservoirs","fulltext":[{"header":"1. Introduction","content":"\u003cp\u003eThe global share of unconventional oil and gas resources is steadily increasing. As most conventional reservoirs have entered the late stage of development, unconventional resources have become a critical focus for exploration and production [\u003cspan additionalcitationids=\"CR2\" citationid=\"CR1\" class=\"CitationRef\"\u003e1\u003c/span\u003e\u0026ndash;\u003cspan citationid=\"CR3\" class=\"CitationRef\"\u003e3\u003c/span\u003e]. Tight sandstone reservoirs, as representative unconventional reservoirs, are characterized by poor petrophysical properties, low permeability, pronounced matrix\u0026ndash;fracture heterogeneity, complex pore structures, and strong anisotropy [\u003cspan additionalcitationids=\"CR5\" citationid=\"CR4\" class=\"CitationRef\"\u003e4\u003c/span\u003e\u0026ndash;\u003cspan citationid=\"CR6\" class=\"CitationRef\"\u003e6\u003c/span\u003e]. These features lead to the limited effectiveness of conventional water injection in such reservoirs and place greater demands on advanced reservoir stimulation technologies, such as hydraulic fracturing [\u003cspan citationid=\"CR7\" class=\"CitationRef\"\u003e7\u003c/span\u003e, \u003cspan citationid=\"CR8\" class=\"CitationRef\"\u003e8\u003c/span\u003e].\u003c/p\u003e \u003cp\u003eHydraulic fracturing is a key stimulation technology for the development of unconventional oil and gas reservoirs [\u003cspan citationid=\"CR9\" class=\"CitationRef\"\u003e9\u003c/span\u003e, \u003cspan citationid=\"CR10\" class=\"CitationRef\"\u003e10\u003c/span\u003e]. It enhances well productivity by injecting high-pressure fracturing fluids to generate artificial fractures, thereby improving the permeability of hydrocarbon-bearing formations. However, the narrow pore throats and limited flow capacity inherent to tight sandstone reservoirs restrict the overall effectiveness of stimulation [\u003cspan additionalcitationids=\"CR12\" citationid=\"CR11\" class=\"CitationRef\"\u003e11\u003c/span\u003e\u0026ndash;\u003cspan citationid=\"CR13\" class=\"CitationRef\"\u003e13\u003c/span\u003e]. Therefore, to achieve efficient reservoir modification, it is necessary that, following the creation of a large-scale fracture network by hydraulic fracturing to enhance crude oil mobility, the fracturing fluid continues to function as an effective agent for imbibition and displacement [\u003cspan additionalcitationids=\"CR15\" citationid=\"CR14\" class=\"CitationRef\"\u003e14\u003c/span\u003e\u0026ndash;\u003cspan citationid=\"CR16\" class=\"CitationRef\"\u003e16\u003c/span\u003e]. This ensures that the energy invested in fracturing is utilized to the maximum extent possible.\u003c/p\u003e \u003cp\u003eThe integrated fracturing flooding technology has been proposed and has attracted widespread attention [\u003cspan citationid=\"CR17\" class=\"CitationRef\"\u003e17\u003c/span\u003e, \u003cspan citationid=\"CR18\" class=\"CitationRef\"\u003e18\u003c/span\u003e]. This approach involves a shut-in period after the fracturing fluid completes fracture creation, during which imbibition and displacement occur between the fracturing fluid and crude oil. Driven by the pressure differential during flowback, well productivity can be significantly improved [\u003cspan citationid=\"CR19\" class=\"CitationRef\"\u003e19\u003c/span\u003e, \u003cspan citationid=\"CR20\" class=\"CitationRef\"\u003e20\u003c/span\u003e]. Imbibition refers to the process in which the wetting phase displaces the non-wetting phase under the influence of capillary forces in the porous medium [\u003cspan additionalcitationids=\"CR22\" citationid=\"CR21\" class=\"CitationRef\"\u003e21\u003c/span\u003e\u0026ndash;\u003cspan citationid=\"CR23\" class=\"CitationRef\"\u003e23\u003c/span\u003e]. Since the nineteenth century, extensive studies have been conducted worldwide to investigate the role of imbibition in enhancing oil recovery [\u003cspan additionalcitationids=\"CR25\" citationid=\"CR24\" class=\"CitationRef\"\u003e24\u003c/span\u003e\u0026ndash;\u003cspan citationid=\"CR26\" class=\"CitationRef\"\u003e26\u003c/span\u003e]. Yang et al. [\u003cspan citationid=\"CR27\" class=\"CitationRef\"\u003e27\u003c/span\u003e] examined the influence of fracture distribution on surfactant imbibition in tight sandstone reservoirs and found that fractures can effectively reduce oil droplet adsorption on the core surface, increasing imbibition recovery by approximately 10%. Moreover, surfactants were shown to further improve oil recovery by about 15% through enhancing water wettability of the rock surface, reducing interfacial tension, and weakening oil droplet adhesion. Liu et al. [\u003cspan citationid=\"CR28\" class=\"CitationRef\"\u003e28\u003c/span\u003e] developed a novel hydrophilic silica, and spontaneous imbibition experiments demonstrated that it can readily enter reservoir pores and adsorb onto rock surfaces, alter wettability to promote crude oil detachment, and ultimately achieve an oil recovery of 36%. Despite the extensive research on surfactant flooding and spontaneous imbibition, studies that specifically elucidate oil-phase flow characteristics and mobilization mechanisms in fracture\u0026ndash;matrix core systems remain limited. During production, several key challenges must be addressed, including the coupling between interfacial tension and capillary forces, preferential channeling of displacing fluids along fractures, coupled fracture\u0026ndash;matrix flow, low sweep efficiency, and difficulties in pore\u0026ndash;throat characterization and large-scale numerical simulation [\u003cspan citationid=\"CR29\" class=\"CitationRef\"\u003e29\u003c/span\u003e, \u003cspan citationid=\"CR30\" class=\"CitationRef\"\u003e30\u003c/span\u003e]. Therefore, there is an urgent need to clarify the oil flow behavior in both fractures and the matrix and to elucidate the mechanisms governing oil mobilization within pores during spontaneous imbibition.\u003c/p\u003e \u003cp\u003eIn this work, fractured\u0026ndash;matrix tight sandstone core models and field crude oil were employed to evaluate the interfacial activity and reservoir adaptability of the oil displacement agent C-22. Oil displacement agents with different interfacial tension levels were subsequently optimized and selected as control groups for comparative oil displacement experiments. The migration behavior of crude oil in fractured\u0026ndash;matrix cores during spontaneous imbibition and displacement processes using C-22 was systematically investigated, and the key operational parameters governing oil displacement were further optimized. Based on these results, an oil displacement strategy tailored for tight sandstone reservoir is proposed, providing theoretical insight and technical support for the efficient development of tight sandstone reservoirs.\u003c/p\u003e"},{"header":"2. Results and Discussion","content":"\u003cdiv id=\"Sec3\" class=\"Section2\"\u003e \u003ch2\u003e2.1. SARA Analysis, Density, and Viscosity of Field Crude Oil\u003c/h2\u003e \u003cp\u003eThe crude oil was analyzed for SARA composition, density, and viscosity, and the results are presented in Table\u0026nbsp;\u003cspan refid=\"Tab1\" class=\"InternalRef\"\u003e1\u003c/span\u003e. It can be seen that the content of saturated hydrocarbon and aromatic hydrocarbon in the light component of crude oil is more than 90%, which makes the crude oil show low density and low viscosity. This kind of crude oil has good fluidity and is easy to exploit.\u003c/p\u003e \u003cp\u003e \u003cdiv class=\"gridtable\"\u003e\u003ctable float=\"Yes\" id=\"Tab1\" border=\"1\"\u003e \u003ccaption language=\"En\"\u003e \u003cdiv class=\"CaptionNumber\"\u003eTable 1\u003c/div\u003e \u003cdiv class=\"CaptionContent\"\u003e \u003cp\u003eCrude oil composition and property analysis.\u003c/p\u003e \u003c/div\u003e \u003c/caption\u003e \u003ccolgroup cols=\"6\"\u003e \u003cdiv align=\"left\" class=\"colspec\" colname=\"c1\" colnum=\"1\"\u003e\u003c/div\u003e \u003cdiv align=\"left\" class=\"colspec\" colname=\"c2\" colnum=\"2\"\u003e\u003c/div\u003e \u003cdiv align=\"left\" class=\"colspec\" colname=\"c3\" colnum=\"3\"\u003e\u003c/div\u003e \u003cdiv align=\"left\" class=\"colspec\" colname=\"c4\" colnum=\"4\"\u003e\u003c/div\u003e \u003cdiv align=\"left\" class=\"colspec\" colname=\"c5\" colnum=\"5\"\u003e\u003c/div\u003e \u003cdiv align=\"left\" class=\"colspec\" colname=\"c6\" colnum=\"6\"\u003e\u003c/div\u003e \u003cthead\u003e \u003ctr\u003e \u003cth align=\"left\" colspan=\"4\" nameend=\"c4\" namest=\"c1\"\u003e \u003cp\u003eSARS analysis/%\u003c/p\u003e \u003c/th\u003e \u003cth align=\"left\" colname=\"c5\" morerows=\"1\" rowspan=\"2\"\u003e \u003cp\u003eDensity/\u003c/p\u003e \u003cp\u003e(g/cm\u003csup\u003e3\u003c/sup\u003e)\u003c/p\u003e \u003c/th\u003e \u003cth align=\"left\" colname=\"c6\" morerows=\"1\" rowspan=\"2\"\u003e \u003cp\u003eViscosity /mPa\u0026middot;s\u003c/p\u003e \u003c/th\u003e \u003c/tr\u003e \u003ctr\u003e \u003cth align=\"left\" colname=\"c1\"\u003e \u003cp\u003eSaturates\u003c/p\u003e \u003c/th\u003e \u003cth align=\"left\" colname=\"c2\"\u003e \u003cp\u003eAromatics\u003c/p\u003e \u003c/th\u003e \u003cth align=\"left\" colname=\"c3\"\u003e \u003cp\u003eResins\u003c/p\u003e \u003c/th\u003e \u003cth align=\"left\" colname=\"c4\"\u003e \u003cp\u003eAsphaltenes\u003c/p\u003e \u003c/th\u003e \u003c/tr\u003e \u003c/thead\u003e \u003ctbody\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e72.32\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e \u003cp\u003e18.04\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c3\"\u003e \u003cp\u003e3.98\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c4\"\u003e \u003cp\u003e5.66\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c5\"\u003e \u003cp\u003e0.84\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c6\"\u003e \u003cp\u003e11.47\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003c/tbody\u003e \u003c/colgroup\u003e \u003c/table\u003e\u003c/div\u003e \u003c/p\u003e \u003c/div\u003e \u003cdiv id=\"Sec4\" class=\"Section2\"\u003e \u003ch2\u003e2.2. Interfacial Activity of Oil Displacing Agents\u003c/h2\u003e \u003cdiv id=\"Sec5\" class=\"Section3\"\u003e \u003ch2\u003e2.2.1. Screening of Control Groups with Oil Displacing Agents at Different Interfacial Tension Magnitudes\u003c/h2\u003e \u003cp\u003eThe core of the oil increasing effect of the working fluid for fracture-flooding depends on three factors: interfacial activity, wetting change performance and emulsifying solubilization performance. The interfacial activity can reduce the oil-water interfacial tension and weaken the adhesion of crude oil. The wettability change performance can change the wettability of rock from lipophilic to hydrophilic, and improve the efficiency of oil washing. The emulsification solubilization performance can make the residual oil form a stable emulsion and expand the displacement range. Surfactant is a commonly used oil displacement chemical agent because of its amphiphilicity. It can not only change the wettability of rock and reduce the interfacial tension of oil and water, but also regulate the above three properties, synergistically improve the effect of pressure flooding and increase oil production, and adapt to the development needs of different reservoirs. To meet the requirements of subsequent imbibition experiments, three surfactants with different magnitudes of interfacial tension were selected for comparison using a TX-500C full-range spinning drop interfacial tensiometer based on reservoir crude oil. The screening results are presented in Table\u0026nbsp;\u003cspan refid=\"Tab2\" class=\"InternalRef\"\u003e2\u003c/span\u003e.\u003c/p\u003e \u003cp\u003e \u003cdiv class=\"gridtable\"\u003e\u003ctable float=\"Yes\" id=\"Tab2\" border=\"1\"\u003e \u003ccaption language=\"En\"\u003e \u003cdiv class=\"CaptionNumber\"\u003eTable 2\u003c/div\u003e \u003cdiv class=\"CaptionContent\"\u003e \u003cp\u003eScreening surfactants corresponding to crude oil with different orders of magnitude of interfacial tension.\u003c/p\u003e \u003c/div\u003e \u003c/caption\u003e \u003ccolgroup cols=\"3\"\u003e \u003cdiv align=\"left\" class=\"colspec\" colname=\"c1\" colnum=\"1\"\u003e\u003c/div\u003e \u003cdiv align=\"char\" char=\".\" class=\"colspec\" colname=\"c2\" colnum=\"2\"\u003e\u003c/div\u003e \u003cdiv align=\"char\" char=\".\" class=\"colspec\" colname=\"c3\" colnum=\"3\"\u003e\u003c/div\u003e \u003cthead\u003e \u003ctr\u003e \u003cth align=\"left\" colname=\"c1\"\u003e \u003cp\u003eSystem Name\u003c/p\u003e \u003c/th\u003e \u003cth align=\"left\" colname=\"c2\"\u003e \u003cp\u003eConcentration/%\u003c/p\u003e \u003c/th\u003e \u003cth align=\"left\" colname=\"c3\"\u003e \u003cp\u003eInterfacial Tension /(mN/m)\u003c/p\u003e \u003c/th\u003e \u003c/tr\u003e \u003c/thead\u003e \u003ctbody\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003eC-22\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e \u003cp\u003e0.3\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c3\"\u003e \u003cp\u003e0.0599\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003eLHSB\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e \u003cp\u003e0.1\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c3\"\u003e \u003cp\u003e2.5580\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003eTHSB35\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e \u003cp\u003e0.1\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c3\"\u003e \u003cp\u003e0.7923\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003eCAB-35\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e \u003cp\u003e0.1\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c3\"\u003e \u003cp\u003e1.0561\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003eLAS-30\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e \u003cp\u003e0.1\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c3\"\u003e \u003cp\u003e0.4044\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003eAEO15\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e \u003cp\u003e0.1\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c3\"\u003e \u003cp\u003e1.6145\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003eNPES\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e \u003cp\u003e0.1\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c3\"\u003e \u003cp\u003e1.0473\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003eCAB-35: LAS-30\u0026thinsp;=\u0026thinsp;8:2\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e \u003cp\u003e0.1\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c3\"\u003e \u003cp\u003e0.2219\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003eTHSB35: LAS-30\u0026thinsp;=\u0026thinsp;5:5\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e \u003cp\u003e0.1\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c3\"\u003e \u003cp\u003e0.1436\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003eTHSB35: LAS-30\u0026thinsp;=\u0026thinsp;4:6\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e \u003cp\u003e0.1\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c3\"\u003e \u003cp\u003e0.0184\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003eTHSB35: LAS-30\u0026thinsp;=\u0026thinsp;3:7\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e \u003cp\u003e0.1\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c3\"\u003e \u003cp\u003e0.0068\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003c/tbody\u003e \u003c/colgroup\u003e \u003c/table\u003e\u003c/div\u003e \u003c/p\u003e \u003cp\u003eBased on the experimental data, the following surfactants and their corresponding interfacial tensile strength levels were selected: THSB35 at a concentration of 0.1% as the surfactant with interfacial tension at the 10\u003csup\u003e\u0026minus;\u0026thinsp;1\u003c/sup\u003emN/m magnitude; C-22 at a concentration of 0.3% as the surfactant with interfacial tension at the 10\u003csup\u003e\u0026minus;\u0026thinsp;2\u003c/sup\u003e mN/m magnitude. The blended system THSB35:LAS-30\u0026thinsp;=\u0026thinsp;3:7 as the surfactant with interfacial tension at the 10\u003csup\u003e\u0026minus;\u0026thinsp;3\u003c/sup\u003e mN/m magnitude.\u003c/p\u003e \u003c/div\u003e \u003cdiv id=\"Sec6\" class=\"Section3\"\u003e \u003ch2\u003e2.2.2. Interfacial Tension of Oil Displacing Agent (C-22) at Different Concentrations\u003c/h2\u003e \u003cp\u003eInterfacial tension is one of the key indicators for evaluating the performance of a displacing agent. A lower value signifies a stronger ability of the displacing agent to reduce oil-water interfacial tension and mobilize residual oil, thereby leading to higher displacement efficiency. To further understand the performance of the selected displacing agent (C-22), this study measured its interfacial tension against the target reservoir crude oil under different concentration conditions. The experimental results are shown in Fig.\u0026nbsp;\u003cspan refid=\"Fig1\" class=\"InternalRef\"\u003e1\u003c/span\u003e. The interfacial tension exhibits a trend of first decreasing significantly and then stabilizing as the concentration increases. At lower concentrations, increasing the C-22 concentration allows more molecules to adsorb at the oil-water interface, effectively reducing the tension. When the concentration is sufficiently high and the interface becomes saturated, further increases in concentration primarily lead to the formation of micelles within the bulk solution, and no significant change in interfacial tension is observed thereafter.\u003c/p\u003e \u003cp\u003e \u003c/p\u003e \u003c/div\u003e \u003cdiv id=\"Sec7\" class=\"Section3\"\u003e \u003ch2\u003e2.2.3. Interfacial Tension of Oil Displacing Agent (C-22) at Different Aging Times\u003c/h2\u003e \u003cp\u003eIn the process of fracturing-flooding, surfactant is used as the core oil displacement agent. After being injected into the subsurface, surfactants must endure formation high-temperature and high-pressure conditions, and their stability is a key performance indicator determining displacement efficiency [\u003cspan citationid=\"CR31\" class=\"CitationRef\"\u003e31\u003c/span\u003e, \u003cspan citationid=\"CR32\" class=\"CitationRef\"\u003e32\u003c/span\u003e]. Therefore, to evaluate the long-term stability of the displacing agent under simulated high-temperature reservoir conditions, the displacing agent solution was aged at reservoir temperature to mimic formation conditions. During the experiment, regular testing is required to observe whether the solution has state changes such as stratification and precipitation, and to monitor the fluctuation of interfacial tension, so as to provide key data support for the selection of displacement agents and the optimization of oil displacement schemes.\u003c/p\u003e \u003cp\u003e \u003c/p\u003e \u003cp\u003e \u003c/p\u003e \u003cp\u003eFigure \u003cspan refid=\"Fig3\" class=\"InternalRef\"\u003e3\u003c/span\u003e shows photographs of the oil displacement agent solution aged at 68\u0026deg;C during the aging process for 0, 2, 4, and 7 d, respectively. The solution remained clear and transparent throughout the 7 d aging period, preliminarily indicating its stability under simulated reservoir conditions. Interfacial tension measurements between the oil displacement agent and crude oil from the corresponding reservoir were conducted, with results shown in Fig.\u0026nbsp;\u003cspan refid=\"Fig2\" class=\"InternalRef\"\u003e2\u003c/span\u003e. The interfacial tension remained essentially stable as aging time increased, demonstrating that the oil displacement agent C-22possesses good reservoir compatibility and can maintain effective oil displacement performance over extended durations.\u003c/p\u003e \u003c/div\u003e \u003c/div\u003e \u003cdiv id=\"Sec8\" class=\"Section2\"\u003e \u003ch2\u003e2.3. Spontaneous Imbibition in Fracture-Matrix Models\u003c/h2\u003e \u003cdiv id=\"Sec9\" class=\"Section3\"\u003e \u003ch2\u003e2.3.1. Evaluation of Spontaneous Imbibition Recovery Using Oil Displacing Agents at Different Concentrations\u003c/h2\u003e \u003cp\u003eSpontaneous imbibition occurs during the soaking process after the formation fracturing is completed. At this time, the working fluid for fracture-flooding encapsulates the rock matrix and is in a static state. At this time, the capillary force is the main force. The wettability of the imbibition medium determines whether the capillary force is the driving force or the resistance. Good emulsification disperses large pieces of crude oil into small oil droplets that are easier to pass through the pore throat of the rock. The imbibition medium enters the small pore channel to replace the crude oil into the large pore channel, and finally discharges the matrix system into the fracture or the wellbore. To investigate the effect of interfacial tension on crude oil flow during spontaneous imbibition experiments, tests were designed and conducted using displacing agents at different concentrations, corresponding to varying magnitudes of interfacial tension.\u003c/p\u003e \u003cp\u003e \u003c/p\u003e \u003cp\u003eThe spontaneous imbibition recovery results are shown in Fig.\u0026nbsp;\u003cspan refid=\"Fig4\" class=\"InternalRef\"\u003e4\u003c/span\u003e. The recovery factors for simulated formation water, 0.02 wt%, 0.3 wt%, and 0.4 wt% displacing agent solutions were 5.79%, 15.87%, 27.37%, and 32.57%, respectively. As the concentration of the displacing agent C-22 increased, the imbibition recovery showed a progressive upward trend. Particularly in the early stage of imbibition, higher concentrations led to faster imbibition rates. At a concentration of 0.02 wt%, the interfacial tension was greater than 1 mN/m. When the concentration of C-22 reached 0.3 wt%, the interfacial tension could be reduced to the order of 10\u003csup\u003e\u0026minus;\u0026thinsp;2\u003c/sup\u003e mN/m, resulting in a significant improvement in recovery. At a concentration of 0.4 wt%, the interfacial tension reached the order of 10\u003csup\u003e\u0026minus;\u0026thinsp;1\u003c/sup\u003e mN/m. The displacing agent C-22 can more effectively reduce the oil-water interfacial tension, significantly lowering the flow resistance of crude oil in small pores and throats, promoting the emulsification and stripping of crude oil, and reducing its migration resistance. This enhances the liquid's penetration ability within the rock pores, thereby promoting crude oil stripping and flow and improving the recovery factor. The highest imbibition recovery was achieved when the interfacial tension was on the order of 10\u003csup\u003e\u0026minus;\u0026thinsp;1\u003c/sup\u003e mN/m.\u003c/p\u003e \u003c/div\u003e \u003cdiv id=\"Sec10\" class=\"Section3\"\u003e \u003ch2\u003e2.3.2. Characteristics of Crude Oil Flow During Imbibition in Fracture-Matrix Cores\u003c/h2\u003e \u003cp\u003eNuclear magnetic resonance (NMR) technology can detect the signal of \u003cem\u003eT\u003c/em\u003e\u003csub\u003e2\u003c/sub\u003e relaxation of hydrogen nuclei, which effectively indicates the existence of substances that can produce this signal. Therefore, by using heavy water to shield the hydrogen signal of water in the oil displacement agent solution, the nuclear magnetic resonance \u003cem\u003eT\u003c/em\u003e\u003csub\u003e2\u003c/sub\u003e spectrum can only identify the hydrogen signal of crude oil in the core, so that the dynamic migration characteristics of crude oil in the large, medium and micropore throat system of the core can be qualitatively identified by this method, and the start-up, flow and retention mode of crude oil in the matrix can be clearly analyzed, which provides reliable experimental data support for optimizing the displacement scheme and enhancing oil recovery.\u003c/p\u003e \u003cp\u003e \u003c/p\u003e \u003cp\u003eAs shown in Fig.\u0026nbsp;\u003cspan refid=\"Fig5\" class=\"InternalRef\"\u003e5\u003c/span\u003e, before the imbibition experiment began, the core saturated with simulated oil exhibited the highest signal intensity. As imbibition progressed, the NMR signal from within the pores continuously decreased. This indicates that crude oil in pores of different sizes was mobilized to varying degrees throughout the imbibition process. In the early stage of imbibition, the core signal changed noticeably. By 48 h of imbibition, the signal amplitude had decreased significantly, indicating that a substantial amount of oil had been displaced from the core. When imbibition continued beyond 96 h, the signal amplitude in the core still decreased but no longer markedly, suggesting that the oil-water migration within the core had largely stabilized.\u003c/p\u003e \u003cp\u003e \u003c/p\u003e \u003cp\u003eTo further investigate the extent of oil mobilization in different pore types during various imbibition stages, the area under the curve for different pore regions in Fig.\u0026nbsp;\u003cspan refid=\"Fig5\" class=\"InternalRef\"\u003e5\u003c/span\u003e was calculated through integration. This allowed the determination of oil mobilization extents in small, medium, and large pores at different imbibition stages. The results are shown in Fig.\u0026nbsp;\u003cspan refid=\"Fig6\" class=\"InternalRef\"\u003e6\u003c/span\u003e. During the early imbibition stage (0\u0026ndash;48 h), the oil mobilization extents for small, medium, and large pores were 30.76%, 33.50%, and 99.91%, respectively. Large pores exhibited the highest mobilization extent, primarily because oil in the fractures of the fractured matrix core is more readily mobilized and nearly completely displaced during the early imbibition phase. In the middle imbibition stage, medium pores showed relatively higher oil mobilization compared to small and large pores. Between 48 and 96 h, the oil mobilization extents for small, medium, and large pores were 10.47%, 29.95%, and 0.086%, respectively. This is attributed to the smaller pore-throat size and more complex pore structure in small pores, which contain a higher proportion of inaccessible pores, whereas medium pores, with relatively simpler structures, continue to contribute significantly to oil mobilization. In the late imbibition stage, simulated oil in small pores exhibited the highest mobilization extent. Between 96 and 144 h, the mobilization extent of simulated oil in small pores was 15.52%, while that in medium pores was 6.57%, indicating relatively low mobilization. At this stage, most of the oil in medium pores had already been displaced, and the displacing agent solution continued to enter small pores to mobilize the remaining oil.\u003c/p\u003e \u003c/div\u003e \u003c/div\u003e \u003cdiv id=\"Sec11\" class=\"Section2\"\u003e \u003ch2\u003e2.4. Characteristics of Crude Oil Flow During Depletion Production in Fracture-Matrix Models\u003c/h2\u003e \u003cp\u003eThe results of crude oil depletion production are shown in Fig.\u0026nbsp;\u003cspan refid=\"Fig7\" class=\"InternalRef\"\u003e7\u003c/span\u003e. When the pressure was reduced from 15 MPa to 10 MPa, the recovery factor was 3.67%. As the pressure was further reduced to 5 MPa, the recovery factor increased to 10.25%. When the pressure was lowered to 0 MPa, the recovery factor reached 18.94%. During production by depressurization, the decrease in reservoir pressure disrupts the original equilibrium: fluids expand elastically due to the pressure drop, while the rock matrix contracts as effective stress increases, leading to pore volume reduction. The combined release of elastic energy from both mechanisms creates a displacement force that overcomes flow resistance, thereby driving oil migration and production.\u003c/p\u003e \u003cp\u003eAs shown in Fig.\u0026nbsp;\u003cspan refid=\"Fig8\" class=\"InternalRef\"\u003e8\u003c/span\u003e and Fig.\u0026nbsp;\u003cspan refid=\"Fig9\" class=\"InternalRef\"\u003e9\u003c/span\u003e, the \u003cem\u003eT\u003c/em\u003e\u003csub\u003e2\u003c/sub\u003e spectra and pore mobilization patterns during crude oil depletion production indicate that when the pressure was reduced to 10 MPa, a synchronous and significant decline in signals was observed across pores of all scales. Combined with the mobilization patterns presented in Fig.\u0026nbsp;\u003cspan refid=\"Fig9\" class=\"InternalRef\"\u003e9\u003c/span\u003e, medium and large pores contributed over 60% of the oil mobilization during the early stage, serving as the primary driver of displacement. In the later stage, small pores became the main contributors to oil displacement relative to medium and large pores.\u003c/p\u003e \u003cp\u003eIn summary, the oil flow behavior during depletion production can be described as follows: in the early production stage, the fracture system preferentially contributes through medium and large pores, while in the later stage, matrix pores take over as the main contributors, reflecting typical dual-porosity production characteristics.\u003c/p\u003e \u003cp\u003e \u003c/p\u003e \u003cp\u003e \u003c/p\u003e \u003cp\u003e \u003c/p\u003e \u003c/div\u003e \u003cdiv id=\"Sec12\" class=\"Section2\"\u003e \u003ch2\u003e2.5. Refined Optimization of Operational Parameters Based on Physically Simulated Displacement Experiments\u003c/h2\u003e \u003cp\u003eTo optimize the construction parameters for shut-in well stimulation with oil displacement agents, multiple sets of physical simulation displacement experiments were conducted. These experiments systematically investigated the performance differences of various types of displacement agents, the displacement efficiency at different concentrations, and the impact of different shut-in durations on imbibition effects. Through comparative analysis of the experimental data, the optimal type of displacement agent and its corresponding concentration suitable for the target reservoir conditions were screened. Additionally, the minimum effective soaking time required to achieve the best imbibition displacement effect was determined. This study provides a reliable experimental basis and technical support for the precise optimization of displacement agent type, concentration ratio, and soaking process parameters in field pilot tests.\u003c/p\u003e \u003cdiv id=\"Sec13\" class=\"Section3\"\u003e \u003ch2\u003e2.5.1. Optimization of Interfacial Tension for Oil Displacing Agents\u003c/h2\u003e \u003cp\u003e \u003c/p\u003e \u003cp\u003eAs shown in Fig.\u0026nbsp;\u003cspan refid=\"Fig10\" class=\"InternalRef\"\u003e10\u003c/span\u003e, the recovery factors during depletion production at different interfacial tensions indicate that different displacing agents exhibit varying displacement performances due to their distinct properties. For the displacing agent C-22, when its concentration is 0.02%, the interfacial tension with crude oil exceeds 1 mN/m. When the concentration is increased to 0.3%, the interfacial tension decreases to the order of 10\u003csup\u003e\u0026minus;\u0026thinsp;2\u003c/sup\u003emN/m. Further increasing the concentration to 0.4% raises the interfacial tension back to the level of 10\u003csup\u003e\u0026minus;\u0026thinsp;1\u003c/sup\u003e mN/m. At the same concentration of 0.1%, LAS-30 exhibits an interfacial tension with crude oil at the order of 10\u003csup\u003e\u0026minus;\u0026thinsp;1\u003c/sup\u003e mN/m, while the blended system of LHSB and LAS-30 at a 3:7 ratio can reduce the interfacial tension to the order of 10\u003csup\u003e\u0026minus;\u0026thinsp;3\u003c/sup\u003e mN/m.\u003c/p\u003e \u003cp\u003eThe core mechanism of surfactant flooding technology is to significantly reduce the interfacial tension between oil displacement agent and crude oil, so as to effectively enhance oil recovery. When the interfacial tension is reduced, the capillary resistance required for the migration of crude oil in rock pores can be significantly reduced, making the residual oil more likely to deform and be driven. It can be observed that as the interfacial tension between the displacing agent and crude oil decreases, the recovery factor increases sequentially. When the interfacial tensions of different displacing agents with crude oil are within the same order of magnitude, they exhibit relatively similar displacement performance. This is because the oil displacement efficiency is largely controlled by the number of capillaries (which is the ratio of the product of viscosity and flow rate to interfacial tension). The lower the interfacial tension, the larger the number of capillaries, and the more conducive to the start-up of crude oil.\u003c/p\u003e \u003c/div\u003e \u003cdiv id=\"Sec14\" class=\"Section3\"\u003e \u003ch2\u003e2.5.2. Optimization of Oil Displacing Agent Concentration\u003c/h2\u003e \u003cp\u003eAs shown in Fig.\u0026nbsp;\u003cspan refid=\"Fig11\" class=\"InternalRef\"\u003e11\u003c/span\u003e, the recovery factors during depletion production at different displacing agent concentrations indicate that after the pressure was reduced to 0 MPa, the recovery factor was 12.79% at a concentration of 0.1%. As the concentration of the displacing agent C-22 increased, the crude oil recovery factor improved. At a concentration of 0.2%, the recovery factor was 16.54%. At 0.3% concentration, the recovery factor reached 18.15%, showing no significant improvement compared to the recovery factor achieved with the 0.2% concentration solution.\u003c/p\u003e \u003cp\u003e \u003c/p\u003e \u003c/div\u003e \u003cdiv id=\"Sec15\" class=\"Section3\"\u003e \u003ch2\u003e2.5.3. Soaking Time Optimization\u003c/h2\u003e \u003cp\u003eBased on the experimental result curves, these three sets of test data clearly demonstrate the influence of shut-in time on crude oil recovery factor. Overall, a prolonged shut-in period correlates with a higher recovery factor, as the shut-in process provides sufficient contact time between the injected fluid and the formation crude oil, thereby enhancing the oil recovery efficiency.\u003c/p\u003e \u003cp\u003eAs the shut-in time increases, the crude oil recovery factor shows a corresponding improvement. However, when the shut-in period exceeds 12 h, the enhancement in recovery becomes less significant. This behavior is attributed to the well-connected pore network in sandstone, which facilitates efficient diffusion of the injected fluid during the shut-in period and promotes effective crude oil mobilization. Therefore, extending the soaking time to 12 h results in a substantial increase in recovery, whereas further extension beyond this timeframe yields only marginal additional gains.\u003c/p\u003e \u003cp\u003e \u003c/p\u003e \u003c/div\u003e \u003c/div\u003e"},{"header":"3. Materials and Methods","content":"\u003cdiv id=\"Sec17\" class=\"Section2\"\u003e \u003ch2\u003e3.1. Materials and Equipments\u003c/h2\u003e \u003cp\u003eMaterials: Crude oil, sourced from Well X located at a tight oil field in Western China; C-22 displacing agent, sourced from the laboratory of the tight oil field; Lauramidopropyl betaine (LHSB), sourced from Shanghai Aladdin Biochemical Technology Co., Ltd.; Tetradecyl hydroxypropyl sulfobetaine (THSB35), sourced from Shanghai Aladdin Biochemical Technology Co., Ltd.; Cocamidopropyl betaine (CAB-35), sourced from Shanghai Deyi Chemical Co., Ltd.; Sodium dodecylbenzenesulfonate (LAS-30), sourced from Linyi Lvsen Chemical Co., Ltd.; Alcohol ethoxylate 15 (AEO15), sourced from Shanghai Aladdin Biochemical Technology Co., Ltd.; Sodium nonylphenol ethoxylate (10) sulfate (NPES), sourced from Jiangsu Haian Petrochemical Plant; Heavy water, sourced from Shanghai Aladdin Biochemical Technology Co., Ltd.; Sandstone core, sourced from Well X.\u003c/p\u003e \u003cp\u003eEquipment: PS-80A CNC Ultrasonic Cleaner, Dongguan Jiekang Ultrasonic Equipment Co., Ltd.; Multi-functional Flow Test and Evaluation System, Beijing Yongruida Technology Co., Ltd.; MacroMR12-150H-I Online Nuclear Magnetic Resonance Analysis and Detection System, Suzhou Niumag Analytical Instrument Co., Ltd.; Analytical Balance, Mettler-Toledo International Trading (Shanghai) Co., Ltd.; UPR Series Ultra-Pure Water System, Sichuan UPR Ultra-Pure Technology Co., Ltd.; Vacuum Drying Oven, Qingdao Lanten Science and Education Instrument Equipment Co., Ltd.; TX-500C Interfacial Tensiometer, Kr\u0026uuml;ss GmbH, Germany; High-Pressure Oil Saturation Device, Haian Petroleum Scientific Research Instrument Co., Ltd.\u003c/p\u003e \u003c/div\u003e \u003cdiv id=\"Sec18\" class=\"Section2\"\u003e \u003ch2\u003e3.2. Experimental Methods\u003c/h2\u003e \u003cdiv id=\"Sec19\" class=\"Section3\"\u003e \u003ch2\u003e3.2.1. Determination of the Amount of Foaming Agent\u003c/h2\u003e \u003cp\u003e(1) All syringes, sample tubes, and tube caps were cleaned with petroleum ether and ethanol, followed by rinsing with the test solution.\u003c/p\u003e \u003cp\u003e(2) After rinsing, an appropriate volume of the test surfactant was drawn into a syringe and slowly injected into the sample tube, ensuring that no air bubbles were generated.\u003c/p\u003e \u003cp\u003e(3) An appropriate amount of the test formation oil was then drawn into another syringe, and a single droplet was injected into the sample tube. The syringe was quickly withdrawn to ensure the droplet remained suspended without adhering to the tube wall.\u003c/p\u003e \u003cp\u003e(4) The sample tube was held horizontally, securely capped, and placed onto the instrument's rotating shaft, after which the shaft cap was attached. The interfacial tensiometer and associated software were turned on, and the temperature was set to 68\u0026deg;C, the rotational speed to 6000 r\u0026middot;min⁻\u0026sup1;, and the density difference between the oil sample and the test solution was input. The test was then initiated.\u003c/p\u003e \u003cp\u003e(5) The microscope was fine-tuned to locate the target oil droplet. The leveling button was used to keep the droplet stationary within the on-screen field of view. After stabilization, the interfacial tension was measured.\u003c/p\u003e \u003c/div\u003e \u003cdiv id=\"Sec20\" class=\"Section3\"\u003e \u003ch2\u003e3.2.2. Static Spontaneous Imbibition and T\u003csub\u003e2\u003c/sub\u003e Spectrum Experiments\u003c/h2\u003e \u003cp\u003e(1) The constant-temperature water bath was switched on and set to 68\u0026deg;C.\u003c/p\u003e \u003cp\u003e(2) The imbibition cell was cleaned sequentially with petroleum ether, ethanol, and the test fluid.\u003c/p\u003e \u003cp\u003e(3) The core was placed at the bottom of the imbibition cell, which was partially filled with the test fluid without exceeding its rim. Vaseline was applied around the rim, the cell was covered with its lid, and the seal was reinforced with plastic film to prevent evaporation.\u003c/p\u003e \u003cp\u003e(4) The test fluid was continuously added \u003cem\u003evia\u003c/em\u003e the extended rubber tubing until the imbibition cell was completely filled.\u003c/p\u003e \u003cp\u003e(5) The volume of expelled oil was recorded at designated time intervals, and the recovery factor was calculated accordingly.\u003c/p\u003e \u003cp\u003e(6) The \u003cem\u003eT\u003c/em\u003e\u003csub\u003e2\u003c/sub\u003e spectra were measured using the Nuclear Magnetic Resonance (NMR) system at 0 h, 48 h, 96 h, and 144 h of the imbibition process.\u003c/p\u003e \u003c/div\u003e \u003cdiv id=\"Sec21\" class=\"Section3\"\u003e \u003ch2\u003e3.2.3. Displacement Experiment\u003c/h2\u003e \u003cp\u003e(1) The core was prepared into a fractured core using a core orientation and splitting device. Following cleaning and drying, the core was saturated with crude oil using a vacuum-pressure saturation system.\u003c/p\u003e \u003cp\u003e(2) The multifunctional flow test and evaluation system was started. The sample solution was filled into the intermediate container, the ISCO pump was activated, and the core was placed into the core holder with all flow lines connected. The oven temperature was set to 68\u0026deg;C. After temperature stabilization, the confining pressure of the core holder was set to 18 MPa and the back pressure to 15 MPa.\u003c/p\u003e \u003cp\u003e(3) The valve at the outlet end of the core holder was closed. The ISCO pump was reactivated and set to constant pressure mode. The sample solution was injected into the crude oil-saturated fractured core from the inlet end until the system pressure stabilized at 15 MPa. Subsequently, the inlet valve was closed, and the shut-in period was initiated.\u003c/p\u003e \u003cp\u003e(4) Depletion production was simulated by gradually reducing the pressure at the outlet end using the back pressure regulator, with stepwise decreases to 10 MPa, 5 MPa, and finally 0 MPa. Pressure changes and recovery factors were recorded throughout the entire process.\u003c/p\u003e \u003c/div\u003e \u003cdiv id=\"Sec22\" class=\"Section3\"\u003e \u003ch2\u003e3.2.4. Nuclear Magnetic Resonance Experiment\u003c/h2\u003e \u003cp\u003eBased on the aforementioned oil displacement experimental procedure, the online nuclear magnetic resonance analysis and detection system was employed to scan the \u003cem\u003eT\u003c/em\u003e\u003csub\u003e2\u003c/sub\u003e spectra of the fractured matrix core saturated with simulated oil under initial conditions and at pressure reduction stages of 10 MPa, 5 MPa, and 0 MPa, respectively. The distribution of remaining oil within the core was observed, and the extent of oil phase mobilization in the core matrix was analyzed. Throughout the NMR scanning experiment, heavy water was used to prepare all solutions in order to eliminate interference from water signals [\u003cspan citationid=\"CR33\" class=\"CitationRef\"\u003e33\u003c/span\u003e, \u003cspan citationid=\"CR34\" class=\"CitationRef\"\u003e34\u003c/span\u003e]. The parameters of the cores used in the experiment are listed in Table\u0026nbsp;\u003cspan refid=\"Tab3\" class=\"InternalRef\"\u003e3\u003c/span\u003e.\u003c/p\u003e \u003cp\u003e \u003cdiv class=\"gridtable\"\u003e\u003ctable float=\"Yes\" id=\"Tab3\" border=\"1\"\u003e \u003ccaption language=\"En\"\u003e \u003cdiv class=\"CaptionNumber\"\u003eTable 3\u003c/div\u003e \u003cdiv class=\"CaptionContent\"\u003e \u003cp\u003eCore parameters.\u003c/p\u003e \u003c/div\u003e \u003c/caption\u003e \u003ccolgroup cols=\"5\"\u003e \u003cdiv align=\"left\" class=\"colspec\" colname=\"c1\" colnum=\"1\"\u003e\u003c/div\u003e \u003cdiv align=\"char\" char=\".\" class=\"colspec\" colname=\"c2\" colnum=\"2\"\u003e\u003c/div\u003e \u003cdiv align=\"char\" char=\".\" class=\"colspec\" colname=\"c3\" colnum=\"3\"\u003e\u003c/div\u003e \u003cdiv align=\"left\" class=\"colspec\" colname=\"c4\" colnum=\"4\"\u003e\u003c/div\u003e \u003cdiv align=\"char\" char=\".\" class=\"colspec\" colname=\"c5\" colnum=\"5\"\u003e\u003c/div\u003e \u003cthead\u003e \u003ctr\u003e \u003cth align=\"left\" colname=\"c1\"\u003e \u003cp\u003eNumber\u003c/p\u003e \u003c/th\u003e \u003cth align=\"left\" colname=\"c2\"\u003e \u003cp\u003eLength/cm\u003c/p\u003e \u003c/th\u003e \u003cth align=\"left\" colname=\"c3\"\u003e \u003cp\u003eDiameter/cm\u003c/p\u003e \u003c/th\u003e \u003cth align=\"left\" colname=\"c4\"\u003e \u003cp\u003ePorosity/%\u003c/p\u003e \u003c/th\u003e \u003cth align=\"left\" colname=\"c5\"\u003e \u003cp\u003ePermeability\u003c/p\u003e \u003cp\u003e/10\u003csup\u003e\u0026minus;\u0026thinsp;3\u003c/sup\u003e \u0026micro;m\u003csup\u003e2\u003c/sup\u003e\u003c/p\u003e \u003c/th\u003e \u003c/tr\u003e \u003c/thead\u003e \u003ctbody\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e1\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e \u003cp\u003e5.06\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c3\"\u003e \u003cp\u003e2.48\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e4.98\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c5\"\u003e \u003cp\u003e0.13\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e2\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e \u003cp\u003e4.96\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c3\"\u003e \u003cp\u003e2.47\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e4.87\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c5\"\u003e \u003cp\u003e0.15\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e3\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e \u003cp\u003e5.04\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c3\"\u003e \u003cp\u003e2.49\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e4.76\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c5\"\u003e \u003cp\u003e0.12\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e4\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e \u003cp\u003e5.04\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c3\"\u003e \u003cp\u003e2.48\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e4.80\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c5\"\u003e \u003cp\u003e0.13\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e5\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e \u003cp\u003e5.08\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c3\"\u003e \u003cp\u003e2.49\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e4.86\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c5\"\u003e \u003cp\u003e0.17\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e6\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e \u003cp\u003e5.03\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c3\"\u003e \u003cp\u003e2.49\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e4.93\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c5\"\u003e \u003cp\u003e0.12\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e7\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e \u003cp\u003e4.99\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c3\"\u003e \u003cp\u003e2.50\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e4.95\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c5\"\u003e \u003cp\u003e0.13\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e8\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e \u003cp\u003e4.99\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c3\"\u003e \u003cp\u003e2.50\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e4.95\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c5\"\u003e \u003cp\u003e0.13\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e9\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e \u003cp\u003e5.01\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c3\"\u003e \u003cp\u003e2.53\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e4.94\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c5\"\u003e \u003cp\u003e0.17\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e10\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e \u003cp\u003e5.03\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c3\"\u003e \u003cp\u003e2.52\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e4.98\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c5\"\u003e \u003cp\u003e0.12\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e11\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e \u003cp\u003e4.98\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c3\"\u003e \u003cp\u003e2.47\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e4.81\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c5\"\u003e \u003cp\u003e0.12\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e12\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e \u003cp\u003e5.02\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c3\"\u003e \u003cp\u003e2.51\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e5.01\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c5\"\u003e \u003cp\u003e0.16\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e13\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e \u003cp\u003e4.97\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c3\"\u003e \u003cp\u003e2.47\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e4.96\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c5\"\u003e \u003cp\u003e0.15\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e14\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e \u003cp\u003e4.98\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c3\"\u003e \u003cp\u003e2.50\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e4.79\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c5\"\u003e \u003cp\u003e0.14\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e15\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e \u003cp\u003e5.00\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c3\"\u003e \u003cp\u003e2.48\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e5.02\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c5\"\u003e \u003cp\u003e0.17\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e16\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e \u003cp\u003e5.01\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c3\"\u003e \u003cp\u003e2.47\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e4.84\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c5\"\u003e \u003cp\u003e0.16\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e17\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e \u003cp\u003e4.99\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c3\"\u003e \u003cp\u003e2.52\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e478\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c5\"\u003e \u003cp\u003e0.18\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e18\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e \u003cp\u003e5.03\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c3\"\u003e \u003cp\u003e2.52\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e4.89\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c5\"\u003e \u003cp\u003e0.13\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003c/tbody\u003e \u003c/colgroup\u003e \u003c/table\u003e\u003c/div\u003e \u003c/p\u003e \u003c/div\u003e \u003c/div\u003e"},{"header":"4. Conclusions","content":"\u003cp\u003e(1) When the concentration of the displacing agent C-22 is 0.4%, the interfacial tension between the agent and crude oil is at the order of 10\u003csup\u003e\u0026minus;\u0026thinsp;1\u003c/sup\u003e mN/m, and the highest spontaneous imbibition recovery achieved is 32.57%. NMR \u003cem\u003eT\u003c/em\u003e\u003csub\u003e2\u003c/sub\u003e spectra analysis reveals the mobilization sequence during the imbibition process: in the early stage, oil in large pores and throats is rapidly mobilized, while in the mid to late stages, medium and small pores/throats contribute successively. This indicates that imbibition efficiency is closely related to the mobilization sequence of pore-throat structures.\u003c/p\u003e \u003cp\u003e(2) During the production process as pressure was depleted from 15 MPa to 0 MPa, the ultimate recovery factor reached 18.94%. The mobilization behavior demonstrates a dual-porosity flow mechanism: early production is primarily dominated by the fracture system (medium and large pores/throats), while later production relies on supplementary contribution from matrix pores. This pattern indicates that effectively mobilizing the crude oil within the matrix is critical for enhancing the performance of depletion-based production.\u003c/p\u003e \u003cp\u003e(3) Based on physical simulation experiments, the optimal parameter combination for achieving the best development performance has been determined: the interfacial tension should be maintained at the order of 10\u003csup\u003e\u0026minus;\u0026thinsp;2\u003c/sup\u003e mN/m, the concentration of C-22 should be optimized to 0.3%, and the soaking time should be set to 12 h (this conclusion is based on the research of this paper, which may have some limitations, and further research is needed in the next step). This parameter set ensures displacement efficiency while promoting balanced mobilization of the fracture-matrix system, providing critical theoretical support and practical guidance for the efficient development of tight sandstone reservoirs.\u003c/p\u003e"},{"header":"Declarations","content":"\u003cp\u003e \u003ch2\u003eDeclaration of competing interest\u003c/h2\u003e \u003cp\u003eThe authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper.\u003c/p\u003e \u003c/p\u003e\u003ch2\u003eFunding\u003c/h2\u003e \u003cp\u003eThe work was supported by the CNPC Major Science and Technology Projects (Number 2023ZZ17YJ03).\u003c/p\u003e\u003ch2\u003eAuthor Contribution\u003c/h2\u003e\u003cp\u003eA.B.: Supervision, Funding Acquisition, Project Administration, Conceptualization, Investigation, Writing \u0026ndash; Review \u0026amp; Editing.C.D.: Conceptualization, Methodology, Experimental Design, Investigation, Formal Analysis, Writing \u0026ndash; Original Draft.E.F.: Supervision, Investigation, Validation, Resources, Writing \u0026ndash; Review \u0026amp; Editing.G.H.: Investigation, Data Curation, Formal Analysis, Visualization.I.J.: Supervision, Validation, Writing \u0026ndash; Review \u0026amp; Editing.K.L.: Investigation, Resources, Writing \u0026ndash; Review \u0026amp; Editing.M.N.: Supervision, Project Administration, Investigation.O.P.: Project Administration, Resources, Writing \u0026ndash; Review \u0026amp; Editing.Q.R.: Experimental Design, Writing \u0026ndash; Review \u0026amp; Editing.All authors have read and agreed to the published version of the manuscript.\u003c/p\u003e\u003ch2\u003eData Availability\u003c/h2\u003e\u003cp\u003eThe datasets generated and/or analysed during the current study are not publicly available due to the proprietary nature of the oil displacement agent and its supporting data, which are currently in the initial stage of field application. Public release at this critical phase could compromise commercial interests and ongoing technology transfer agreements. The data are available from the corresponding author on reasonable request, subject to a confidentiality agreement.\u003c/p\u003e"},{"header":"References","content":"\u003col\u003e\u003cli\u003e\u003cspan\u003eAbdulhadi, D., Ali, J. A. \u0026amp; Hama, S. M. Advanced Techniques for Improving the Production of Natural Resources from Unconventional Reservoirs: A State-of-the-Art Review. \u003cem\u003eEnergy Fuels\u003c/em\u003e. \u003cb\u003e39\u003c/b\u003e (23), 10853\u0026ndash;10876. \u003cspan class=\"ExternalRef\"\u003e\u003cspan class=\"RefSource\"\u003e10.1021/acs.energyfuels.5c01259\u003c/span\u003e\u003cspan address=\"10.1021/acs.energyfuels.5c01259\" targettype=\"DOI\" class=\"RefTarget\"\u003e\u003c/span\u003e\u003c/span\u003e (2025).\u003c/span\u003e\u003c/li\u003e \u003cli\u003e\u003cspan\u003eGuo, B. E., Xiao, N., Martyushev, D. \u0026amp; Zhao, Z. 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Sci.\u003c/em\u003e \u003cb\u003e22\u003c/b\u003e (7), 2977\u0026ndash;2991. \u003cspan class=\"ExternalRef\"\u003e\u003cspan class=\"RefSource\"\u003ehttps://doi.org/10.1016/j.petsci.2025.04.004\u003c/span\u003e\u003cspan address=\"10.1016/j.petsci.2025.04.004\" targettype=\"DOI\" class=\"RefTarget\"\u003e\u003c/span\u003e\u003c/span\u003e (2025).\u003c/span\u003e\u003c/li\u003e\u003c/ol\u003e"}],"fulltextSource":"","fullText":"","funders":[],"hasAdminPriorityOnWorkflow":false,"hasManuscriptDocX":true,"hasOptedInToPreprint":true,"hasPassedJournalQc":"","hasAnyPriority":false,"hideJournal":false,"highlight":"","institution":"","isAcceptedByJournal":true,"isAuthorSuppliedPdf":false,"isDeskRejected":"","isHiddenFromSearch":false,"isInQc":false,"isInWorkflow":false,"isPdf":false,"isPdfUpToDate":true,"isWithdrawnOrRetracted":false,"journal":{"display":true,"email":"[email protected]","identity":"scientific-reports","isNatureJournal":false,"hasQc":true,"allowDirectSubmit":false,"externalIdentity":"scirep","sideBox":"Learn more about [Scientific Reports](http://www.nature.com/srep/)","snPcode":"","submissionUrl":"","title":"Scientific Reports","twitterHandle":"","acdcEnabled":true,"dfaEnabled":true,"editorialSystem":"stoa","reportingPortfolio":"Scientific Reports","inReviewEnabled":true,"inReviewRevisionsEnabled":true},"keywords":"tight sandstone reservoirs, fracture–matrix cores, spontaneous imbibition, oil displacement","lastPublishedDoi":"10.21203/rs.3.rs-8698096/v1","lastPublishedDoiUrl":"https://doi.org/10.21203/rs.3.rs-8698096/v1","license":{"name":"CC BY 4.0","url":"https://creativecommons.org/licenses/by/4.0/"},"manuscriptAbstract":"\u003cp\u003eTight sandstone reservoirs are characterized by low porosity and low permeability, which results in great difficulty in oil production and low recovery. In this work, based on fractured\u0026ndash;matrix tight sandstone core models and field crude oil, the interfacial activity and reservoir adaptability of the oil displacement agent C-22 were evaluated. Subsequently, oil displacement agents with different interfacial tension levels were optimized and selected as control groups for subsequent oil displacement experiments. The migration behavior of crude oil in fractured\u0026ndash;matrix cores during spontaneous imbibition and oil displacement processes using C-22 was systematically investigated, and the key development parameters for oil displacement were further optimized. The results show that C-22 exhibits excellent interfacial activity and good reservoir adaptability. An ultralow interfacial tension of 0.12 mN/m can be achieved at a concentration of 0.1 wt%, and the interfacial tension remains stable after 7 d of aging. In the oil displacement experiments, as the pressure decreases from 15 MPa to 0 MPa, the final oil recovery reaches 18.94%. Nuclear magnetic resonance analysis indicates that oil in mesopores and macropores is predominantly mobilized at the early stage, whereas oil in micropores is mainly produced at the later stage. Furthermore, the key development parameters for the oil displacement process were optimized. The optimal oil displacement performance is achieved when the interfacial tension is reduced to the 10\u003csup\u003e\u0026minus;\u0026thinsp;2\u003c/sup\u003e mN/m level, the concentration of C-22 is 0.2 wt%, and the shut-in time is 12 h. We expect that this study can provide valuable insights into the effective development of tight sandstone reservoirs and offer theoretical guidance for the selection of field operational parameters.\u003c/p\u003e","manuscriptTitle":"Spontaneous Imbibition and Oil Displacement Experimental Investigation in Fracture–Matrix Cores of Tight Sandstone Reservoirs","msid":"","msnumber":"","nonDraftVersions":[{"code":1,"date":"2026-02-09 18:21:08","doi":"10.21203/rs.3.rs-8698096/v1","editorialEvents":[{"type":"communityComments","content":0},{"type":"decision","content":"Revision requested","date":"2026-02-16T08:30:47+00:00","index":"","fulltext":""},{"type":"editorInvitedReview","content":"","date":"2026-02-14T04:04:59+00:00","index":"hide","fulltext":""},{"type":"editorInvitedReview","content":"","date":"2026-02-12T02:15:03+00:00","index":"hide","fulltext":""},{"type":"reviewerAgreed","content":"11029455541590004983739291405447365521","date":"2026-02-05T14:23:35+00:00","index":"hide","fulltext":""},{"type":"reviewerAgreed","content":"147241929016389007444381820389859531918","date":"2026-02-05T07:59:56+00:00","index":"hide","fulltext":""},{"type":"reviewersInvited","content":"","date":"2026-02-05T06:18:59+00:00","index":"","fulltext":""},{"type":"editorAssigned","content":"","date":"2026-02-05T03:59:56+00:00","index":"","fulltext":""},{"type":"editorInvited","content":"","date":"2026-02-05T03:50:43+00:00","index":"","fulltext":""},{"type":"checksComplete","content":"","date":"2026-02-03T08:18:34+00:00","index":"","fulltext":""},{"type":"submitted","content":"Scientific Reports","date":"2026-02-03T07:52:24+00:00","index":"","fulltext":""}],"status":"published","journal":{"display":true,"email":"[email protected]","identity":"scientific-reports","isNatureJournal":false,"hasQc":true,"allowDirectSubmit":false,"externalIdentity":"scirep","sideBox":"Learn more about [Scientific Reports](http://www.nature.com/srep/)","snPcode":"","submissionUrl":"","title":"Scientific Reports","twitterHandle":"","acdcEnabled":true,"dfaEnabled":true,"editorialSystem":"stoa","reportingPortfolio":"Scientific Reports","inReviewEnabled":true,"inReviewRevisionsEnabled":true}}],"origin":"","ownerIdentity":"6d0db1c2-f558-4806-8305-a0fe26e6aff6","owner":[],"postedDate":"February 9th, 2026","published":true,"recentEditorialEvents":[],"rejectedJournal":[],"revision":"","amendment":"","status":"published-in-journal","subjectAreas":[{"id":62393295,"name":"Physical sciences/Energy science and technology"},{"id":62393296,"name":"Physical sciences/Engineering"},{"id":62393297,"name":"Physical sciences/Materials science"}],"tags":[],"updatedAt":"2026-03-23T16:16:23+00:00","versionOfRecord":{"articleIdentity":"rs-8698096","link":"https://doi.org/10.1038/s41598-026-44044-z","journal":{"identity":"scientific-reports","isVorOnly":false,"title":"Scientific Reports"},"publishedOn":"2026-03-18 15:57:30","publishedOnDateReadable":"March 18th, 2026"},"versionCreatedAt":"2026-02-09 18:21:08","video":"","vorDoi":"10.1038/s41598-026-44044-z","vorDoiUrl":"https://doi.org/10.1038/s41598-026-44044-z","workflowStages":[]},"version":"v1","identity":"rs-8698096","journalConfig":"researchsquare"},"__N_SSP":true},"page":"/article/[identity]/[[...version]]","query":{"redirect":"/article/rs-8698096","identity":"rs-8698096","version":["v1"]},"buildId":"XKTyCvWXoU3ODBz1xrDgd","isFallback":false,"isExperimentalCompile":false,"dynamicIds":[84888],"gssp":true,"scriptLoader":[]}