Search Results (65)

Recovering oil by fracturing fluid imbibition has demonstrated significant potential for enhanced oil recovery (EOR) in tight oil reservoirs. White mineral oil (WMO), kerosene, or saturated alkanes with matched apparent viscosity have been widely used as “crude oil” to investigate imbibition mechanisms in light shale oil or tight oil. However, the representativeness of these simulated oils for low-maturity crude oils with higher viscosity and greater content of resins and asphaltenes requires further research. In this study, imbibition experiments were conducted and T₂ and T₁–T₂ nuclear magnetic resonance (NMR) spectra were adopted to investigate the oil recovery characteristics among resin–asphaltene-rich Jimusar shale oil and two WMOs. The overall imbibition recovery rates, pore scale recovery characteristics, mobility variations among oils with different occurrence states, as well as key factors influencing imbibition efficiency were analyzed. The results show the following: (1) WMO, kerosene, or alkanes with matched apparent viscosity may not comprehensively replicate the imbibition behavior of resin–asphaltene-rich crude oils. These simplified systems fail to capture the pore-scale occurrence characteristics of resins/asphaltenes, their influence on pore wettability alteration, and may consequently overestimate the intrinsic imbibition displacement efficiency in reservoir formations. (2) Surfactant optimization must holistically address the intrinsic coupling between interfacial tension reduction, wettability modification, and pore-scale crude oil mobilization mechanisms. The alteration of overall wettability exhibits higher priority over interfacial tension in governing displacement dynamics. (3) Imbibition displacement exhibits selective mobilization characteristics for oil phases in pores. Specifically, when the oil phase contains complex hydrocarbon components, lighter fractions in larger pores are preferentially mobilized; when the oil composition is homogeneous, oil in smaller pores is mobilized first. Full article

The development of shale gas relies on hydraulic fracturing technology and requires the injection of a large amount of fracturing fluid. The well shut-off period after fracturing can promote water infiltration and suction. Optimizing the well shut-off time is crucial for enhancing the recovery rate. Among existing methods, the dimensionless time model is widely used, but it has limitations because it does not represent the length of on-site scale features. In this study, we focused on the shut-in time for a deep shale gas well (Lu-A) in Luzhou and a medium-deep shale gas well (Wei-B) in Weiyuan. By integrating the spontaneous seepage and aspiration experiments in the laboratory and the post-pressure backflow data (including mineralization degree, liquid volume recovery rate, etc.), a multi-scale well shutdown time prediction model considering the characteristic length was established. The experimental results show that the spontaneous resorption characteristic times of Lu-A and Wei-B are 3 h and 22 h, respectively. Based on the inversion of crack monitoring data, the key parameters such as the weighted average crack width (1.73/1.30 mm) and crack spacing (0.20/0.32 m) of Lu-A and Wei-B were obtained. Through the scale upgrade calculation of the feature length (0.10/0.16 m), the system determined that the optimal well shutdown times for the two wells were 14.5 days and 16.7 days, respectively. The optimization method based on a multi-parameter analysis of backflow fluid proposed in this study not only solves the limitations of the traditional dimensionless time model in characterizing the feature length but also provides a theoretical basis for the formulation of the well shutdown system and nozzle control strategy of shale gas wells. Full article

Deep coalbed methane (CBM) reservoirs have the characteristics of low permeability, low porosity, and low water saturation, which easily experience wellbore instability due to drilling fluid, severely affecting drilling safety. Based on the physical property analysis of coal samples, the wellbore instability mechanism of the deep CBM reservoir was investigated by multiple methods. It was found that the wellbore instability is mainly caused by drilling fluid intrusion and the interaction between drilling fluid and coal formation; the fracture pressure of coal after immersion decreased from 27.4 MPa to 25.0 MPa because of the imbibition of drilling fluid. A novel nano-plugging agent with a size of 460 nm was prepared that can cement coal particles to form disc-shaped briquettes with a tensile strength of 2.27 MPa. Based on that, an effective anti-collapse drilling fluid for deep coal rock reservoirs was constructed, the invasion depth of the optimized drilling fluid was only 6 mm. The CT result shows that the number of fractures and pores in coal rock significantly reduced after treatment with the wellbore-stabilizing drilling fluid; nano-plugging anti-collapse agent in drilling fluid can form a dense layer on the coal surface, and then the hydration swelling of clay in the wellbore region can be effectively suppressed. Finally, the drilling fluid in this work can achieve the purpose of sealing and wettability alternation to prevent the collapse of the wellbore in the deep coal reservoir. Full article

Spontaneous counter-current imbibition is a crucial recovery mechanism in water-wet fractured reservoirs, especially in unconventional formations like tight and shale reservoirs. The geometric characteristics of microscale fractures require further clarification regarding their impact on imbibition. In this paper, the numerical simulation method is used to study the influence of fracture aperture, length, density, and relative position between fracture and imbibition open face on the counter-current imbibition process of a matrix block. For fractures perpendicular to the imbibition surface and in contact with water, the embedded discrete fracture model is utilized to simulate the impact of varying fracture apertures on counter-current imbibition. For fractures parallel to the imbibition surface, considering the impact of fracture on the capillary discontinuity of the matrix, the effects of varying fracture lengths and densities on counter-current imbibition are simulated. The results show that when fractures are perpendicular to the imbibition surface and in contact with water, the imbibition rate can be increased, and as the fracture aperture decreases, the imbibition rate first increases and then decreases. On the other hand, fractures parallel to the imbibition surface inhibit the imbibition process, with the imbibition rate decreasing as fracture length or density increases. This paper proposes an empirical shape factor considering the geometric characteristics of fractures, which can effectively characterize the influence of microfractures on matrix block imbibition, thus improving the dual-medium numerical simulation model. Full article

This paper describes an innovatively designed experimental method for fracturing fluid energy storage to explore the energy storage mechanism during the well shut-in process of fractured shale reservoirs. By improving the existing core clamp and adding fracturing fluid cavities and large volume intermediate containers to simulate artificial fractures and remote shale reservoirs, the pressure changes in the core during the well shut-in process were monitored under the conditions of a real oil–water ratio and real pressure distribution to explore the energy storage law of the shut-in fluid in fractured shale reservoirs. Compared to the 0.62 MPa energy storage obtained from traditional energy storage experiments (without artificial fractures or remote shale reservoirs), the experimental scheme proposed in this paper achieved a 2.45 MPa energy storage, consistent with the field’s monitoring results. The energy storage effects of four fracturing fluids were compared, namely pure CO₂, CO₂ pre-fracturing fluid, slickwater pre-fracturing fluid, and pure slickwater fracturing fluid. Due to the characteristics of a high expansion coefficient and low interfacial tension of pure CO₂, the energy storage effect was the best, and the pressure equilibrium time was the shortest. Considering factors such as comprehensive economy and energy storage efficiency, the optimal range for CO₂ pre-injection is between 20% and 30%. Based on the optimization criterion of energy storage pressure balance, it is recommended that the optimal CO₂ shut-in time be 5 h and the slickwater be 12.8 h. Considering the economic, sand carrying, and energy storage effects, and other factors, CO₂ pre-storage has the best imbibition effect, and the optimal CO₂ pre-storage range is 20~30%. The research results provide theoretical support for energy storage fracturing construction in other shale oil reservoirs of the same type. Full article

The flowback rate of fracturing fluid in shale reservoirs is often notably low, primarily due to the spontaneous imbibition of the water-based fracturing fluid. Despite their significance, the factors influencing spontaneous imbibition in shale reservoirs remain insufficiently understood. Moreover, whether spontaneous imbibition is ultimately beneficial or detrimental to shale reservoirs is still a subject of debate. This study investigates the spontaneous imbibition process in shale, the factors (the bedding, contact area, porosity, initial water saturation, and fluid type) affecting it, and its impact on shale porosity and permeability. The results reveal that the spontaneous imbibition process can be categorized into three distinct stages: the rapid imbibition stage, the transitional stage, and the stable stage. It is observed that bedding significantly influences the imbibition rate, and the imbibition rate in the parallel bedding direction is greater than that in the vertical bedding direction. The imbibition capacity increases with larger contact area and higher porosity, while it decreases with higher initial water saturation. Furthermore, the imbibition capacity varies with the type of fluid, following this order: distilled water > 5% KCl solution > kerosene. The maximum imbibed volume per unit pore volume of shale in distilled water is twice that in kerosene. Lastly, spontaneous imbibition is found to enhance the porosity and permeability of shale. After three instances of imbibition, the porosity of the matrix and fractured sample increased by 0.85% and 1.68%, and the permeability increased by 0.636 mD and 0.829 mD, respectively. Full article

Laminated shale oil reservoirs feature well-developed microcracks, with significant differences in wettability on either side of these fractures. The complex pore structure of laminated shale oil reservoirs makes capillary imbibition prevalent during both water injection and well shut-in periods. Therefore, based on the phase field method, this study investigates the imbibition behavior and the influencing factors during the injection and shut-in stage. This research shows that the imbibition mode determines the recovery rate: co-current imbibition > co-current imbibition + counter-current imbibition > counter-current imbibition. Co-current imbibition predominantly occurs in the dominant seepage channels, while counter-current imbibition mainly takes place in pore boundary regions. During the water injection stage, a low injection rate is beneficial for synergistic oil recovery through imbibition and displacement. As the injection rate increases, the capillary imbibition effect diminishes. Increased water saturation strengthens the co-current imbibition effect. Compared to injecting for 5 ms, injecting for 10 ms resulted in a 4.53% increase in imbibition recovery during the shut-in stage. The water sweep efficiency increases with the tortuosity of fractures. The wettability differences on either side of the fractures have a certain impact on imbibition. Around the fracture, the recovery in the strongly wetted area is 35% higher than that in the weakly water-wetted area. The wettability difference across fractures causes water to penetrate along the strongly water-wet pores, while only the inlet end and the pores near the fracture in the weakly water-wet zone are affected. Therefore, it is crucial to monitor the injection pressure to maximize the synergistic effects of displacement and imbibition during the development of laminated shale oil reservoirs. Additionally, surfactants should be used judiciously to prevent fingering due to wettability differences. Full article

To study the effects of liquid properties and interface parameters on gas–liquid two-phase flow in porous media. The volume flow model of gas–liquid two-phase flow in porous media was established, and the interface of the two-phase flow was reconstructed by tracing the phase fraction. The microscopic imbibition flow model was established, and the accuracy of the model was verified by comparing the simulation results with the classical capillary imbibition model. The flow characteristics in the fracturing process and backflow process were analyzed. The influence of flow parameters and interface parameters on gas flow was studied using the single-factor variable method. The results show that more than 90% of the flowing channels are invaded by fracturing fluid, and only about 50% of the fluid is displaced in the flowback process. Changes in flow velocity and wetting angle significantly affect Newtonian flow behavior, while variations in surface tension have a pronounced effect on non-Newtonian fluid flow. The relative position of gas breakthrough in porous media is an inherent property of porous media, which does not change with fluid properties and flow parameters. Full article

Spontaneous imbibition (SI) effectively enhances oil recovery in shale reservoirs, significantly changing well shut-in and flowback design. This study conducted SI and displacement experiments to simulate the well shut-in and flowback stages so that the mechanism of imbibition and displacement between crude oil and fracture fluid can be discussed. In addition, the relative contribution to oil recovery of different types of pores in various stages and the effect of wettability were determined with low-field nuclear magnetic resonance (LF-NMR) via each sample’s T₂ transverse relaxation time at each time. The experimental results show that shale has multiscale pore structure characteristics combined with micropores, small mesopores, and mesopores. During the SI process, crude oil is displaced from micropores by fracture fluid at first, and then a large amount of oil production comes from small mesopores. Oil recovery of water-wet core samples is approximately 40.7%. Oil recovery of oil-wet core samples is about 26%. The wettability significantly affects the imbibition and displacement oil recovery of samples. For the process of SI, oil recovered from small mesopores takes the lead in the complete sample recovery. For the displacement process, oil recovered from small mesopores and mesopores take the lead in the complete sample recovery. After displacement, only 12% of fracture fluid flooded from the samples. This research, demonstrating the imbibition and displacement characteristics of terrestrial shale and several relevant affecting factors, contributes to understanding the fracturing fluid retention mechanism in shale reservoirs and provides crucial theoretical foundations for the development of shale oil reservoirs. Full article

Jimsar shale oil in China has undergone a rapid decline in formation energy and has a low recovery rate, with poor reservoir permeability. CO₂ injection has become the main method for improving oil recovery. Pre-fracturing with CO₂ energy storage in Jimsar shale oil has been performed, yielding a noticeable increase in oil recovery. However, the CO₂ injection mechanism still requires a deeper understanding. Focusing on Jimsar shale oil in China, this paper studies the effect of CO₂ on crude oil viscosity reduction, miscible phase testing, and the law of imbibition displacement. The results show that CO₂ has a significant viscosity reduction effect on Jimsar shale oil, with a minimum miscible pressure between CO₂ and Jimsar shale oil of 25.51 MPa, which can allow for miscibility under formation conditions. A rise in pressure increased the displacement capacity of supercritical CO₂, as well as the displacement volume of crude oil. However, the rate of increase gradually declined. This research provides a theoretical basis for CO₂ injection fracturing in Jimsar shale oil, which is helpful for improving the development effects of Jimsar shale oil. Full article

Shale oil reservoirs, as an unconventional hydrocarbon resource, have the potential to substitute conventional hydrocarbon resources and alleviate energy shortages, making their exploration and development critically significant. However, due to the low permeability and the development of nanopores in shale reservoirs, shale oil production is challenging and recovery efficiency is low. During the imbibition stage, fracturing fluid displaces the oil in the pores primarily under capillary forces, but the complex pore structure of shale reservoirs makes the imbibition mechanism unclear. This research studies the imbibition flow mechanism in nanopores based on the capillary force model and two-phase flow theory, coupled with numerical simulation methods. The results indicated that within a nanopore diameter range of 10–20 nm, increasing the pore diameter leads to a higher imbibition displacement volume. Increased pressure can enhance the imbibition displacement, but the effect diminishes gradually. Under the water-wet conditions, the imbibition displacement volume increases as the contact angle decreases. When the oil phase viscosity decreases from 10 mPa·s to 1 mPa·s, the imbibition displacement rate can increase by 72%. Moreover, merely increasing the water phase viscosity results in only a 5% increase in the imbibition displacement rate. The results provide new insights into the imbibition flow mechanism in nanopores within shale oil reservoirs and offer a theoretical foundation and technical support for efficient shale oil development. Full article

Following hydraulic fracturing operations within shale reservoirs, there frequently exists a considerable volume of residual oil that remains encapsulated within the matrix, thereby impeding the singular shale well’s productivity from attaining projected yields. In pursuit of augmenting the recovery efficiency of shale oil, the industry has widely adopted a post-fracture shut-in strategy within shale oil wells. This methodology is predicated on the aspiration to escalate both the production output and the recovery factor of the oil well by leveraging the imbibition and displacement mechanisms of the fracturing fluid throughout the shut-in interval. There are many kinds of surfactants, and how to select surfactants suitable for shale reservoirs from these many surfactants has become a key issue in improving shale reservoir recovery. In this study, a new surfactant screening method for improving imbibition recovery in shale reservoirs is proposed. An interfacial tension test, contact angle test, and anti-adsorption test are carried out for the collected surfactant products, and the interfacial tension, contact angle, and anti-adsorption are gradually used as indicators. The type of surfactant is initially screened. On this basis, the static imbibition experiment of shale is made to determine the type and concentration of surfactants suitable for shale oil development. The results show that the surfactants screened by this method have the characteristics of decreasing oil–water interfacial tension, varying rock wettability, and strong anti-adsorption, which can effectively improve imbibition efficiency. The study results herein can provide technical support for optimizing shale oil surfactants and provide a new idea for improving oil exploitation in low-permeability reservoirs. Full article

It is widely accepted in the oil and gas industry that high-ionic-strength water (HISW) can improve oil and gas recovery in unconventional shale reservoirs by limiting shale hydration. Despite numerous supporting studies, there is a lack of a systematic analysis exploring the effect of HISW on shale permeability evolution, particularly considering varying chemical compositions. In this work, we investigated the impact of different concentrations of NaCl and CaCl₂ on shale permeability through sequential HISW imbibition experiments, beginning with the highest NaCl and lowest CaCl₂ concentrations. After maintaining the highest effective stress for an extended period, significant permeability reduction and potential fracture generation were observed, as indicated by periodic fluctuations in differential pressure. These effects were further intensified by displacements with HISW solutions. Advanced post-experimental analyses using micro-CT scans and SEM-EDS analysis revealed microstructural changes within the sample. Our findings offer initial insight into how HISW-shale interactions influence shale permeability, using innovative approaches to simulate reservoir conditions. The findings indicate that discrepancies in the chemical composition between injected solutions and shale may lead to shale disintegration during hydraulic fracturing processes. Full article

This study utilizes nuclear magnetic resonance (NMR) techniques to monitor complex microstructures and fluid transport, systematically examining fluid distribution and migration during pressure imbibition. The results indicate that increased applied pressure primarily affects micropores and small pores during the initial imbibition stage, enhancing the overall imbibition rate and oil recovery. Higher capillary pressure in the pores strengthens the imbibition ability, with water initially displacing oil from smaller pores. Natural microfractures allow water to preferentially enter and displace oil, thereby reducing oil recovery from these pores. Additionally, clay minerals may induce fracture expansion, facilitating oil flow into the expanding space. This study provides new insights into fluid distribution and migration during pressure imbibition, offering implications for improved oil production in tight reservoirs. Full article

Fracture network fracturing is pivotal for achieving the economical and efficient development of shale gas, with the connectivity among fracture networks playing a crucial role in reservoir stimulation effectiveness. However, flow back data that reflect fracture network connectivity information are often ignored, resulting in an inaccurate prediction of the effective fracture network volume (EFNV). The accurate calculation of the EFNV has become a key and difficult issue in the field of shale fracturing. For this reason, the accurate shale gas effective fracture network volume inversion method needs to be improved. Based on the flow back characteristics of fracturing fluids, a tree-shaped fractal fracture flow back mathematical model for inversion of EFNV was established and combined with fractal theory. A genetic algorithm workflow suitable for EFNV inversion of shale gas was constructed based on the flow back data after fracturing, and the fracture wells in southern Sichuan were used as an example to carry out the EFNV inversion. The reliability of the inversion model was verified by testing production, cumulative gas production, and microseismic results. The field application showed that the inversion method proposed in this paper can obtain tree-shaped fractal fracture network structure parameters, fracture system original pressure, matrix gas breakthrough pressure, fracture compressibility coefficient, reverse imbibition index, equivalent main fracture half length, and effective initial fracture volume (EIFV). The calculated results of the model belong to the same order of magnitude as those of the HD model and Alkouh model, and the model has stronger applicability. This research has important theoretical guiding significance and field application value for improving the accuracy of the EFNV calculation. Full article