Search Results (19)

Ensuring the overall efficiency of hydraulic fracturing treatment depends on the ability to forecast bottomhole pressure. It has a direct impact on fracture geometry, production efficiency, and cost control. Since the complications present in contemporary operations have proven insufficient to overcome inherent uncertainty, the precision of bottomhole pressure predictions is of great importance. Achieving this objective is possible by employing machine learning algorithms that enable real-time forecasting of bottomhole pressure. The primary objective of this study is to produce sophisticated machine learning algorithms that can accurately predict bottomhole pressure while injecting guar cross-linked fluids into the fracture string. Using a large body of work, including 42 vertical wells, an extensive dataset was constructed and meticulously packed using processes such as feature selection and data manipulation. Eleven machine learning models were then developed using parameters typically available during hydraulic fracturing operations as input variables, including surface pressure, slurry flow rate, surface proppant concentration, tubing inside diameter, pressure gauge depth, gel load, proppant size, and specific gravity. These models were trained using actual bottomhole pressure data (measured) from deployed memory gauges. For this study, we carefully developed machine learning algorithms such as gradient boosting, AdaBoost, random forest, support vector machines, decision trees, k-nearest neighbor, linear regression, neural networks, and stochastic gradient descent. The MSE and R² values of the best-performing machine learning predictors, primarily gradient boosting, decision trees, and neural network (L-BFGS) models, demonstrate a very low MSE value and high R² correlation coefficients when mapping the predictions of bottomhole pressure to actual downhole gauge measurements. R² values are reported as 0.931, 0.903, and 0.901, and MSE values are reported at 0.003, 0.004, and 0.004, respectively. Such low MSE values together with high R² values demonstrate the exceptionally high accuracy of the developed models. By illustrating how machine learning models for predicting pressure can act as a viable alternative to expensive downhole pressure gauges and the inaccuracy of conventional models and correlations, this work provides novel insight. Additionally, machine learning models excel over traditional models because they can accommodate a diverse set of cross-linked fracture fluid systems, proppant specifications, and tubing configurations that have previously been intractable within a single conventional correlation or model. Full article

As shale gas development gradually advances to a deeper level, the economic exploitation of deep shale gas has become one of the key technologies for sustainable development. Large-scale, long-term and effective hydraulic fracturing fracture networks are the core technology for achieving economic exploitation of deep shale gas. Due to the high-pressure and high-temperature characteristics of deep shale gas reservoirs, traditional seepage models cannot effectively simulate gas flow in such environments. Therefore, this paper constructs a fluid–solid–thermal coupling model, considering the creep characteristics of deep shale, the effects of proppant embedment and deformation on fracture closure, and deeply analyzes the effects of proppant parameters on the shale gas production process. The results show that factors such as proppant concentration, placement, mechanical properties and particle size have a significant effect on fracture width, fracture surface seepage characteristics and final gas production. Specifically, an increase in proppant concentration can expand the fracture width but has limited effect on increasing gas production; uneven proppant placement will significantly reduce the fracture conductivity, resulting in a significant decrease in gas production; proppants with smaller sizes are more suitable for deep shale gas fracturing construction, which not only reduces construction costs but also improves gas seepage capacity. This study provides theoretical guidance for proppant optimization in deep shale gas fracturing construction. Full article

Solid–liquid two-phase flow often occurs when pumping proppant or temporary plugging agents into hydraulically fractured wells. The final distribution of these injected particles in the fracture has an important influence on the well productivity after hydraulic fracturing. This paper focuses on simulating and analyzing particle migration within slug injection hydraulic fractures in the Sulige gas reservoir. In this study, a particle migration and settlement model in hydraulic fractures is established based on the Multiphase Particle-in-Cell (MP-PIC) method, allowing for effective simulation of particle migration and settlement in fractures. This model is validated by the results of particle-pumping experiments. The influences of fluid viscosity, injection rate, particle density, particle diameter, and particle concentration on the distribution of particles are studied. The results indicate that keeping the viscosity of the particle-carrying liquid above 50 mPa·s is necessary. It is recommended to keep the liquid viscosity above 200 mPa·s so that the particles can move farther in the fractures. For pulse fracturing, a lower flow rate leads to a more dispersed distribution of particles, but for temporary plugging with particles, a lower flow rate can lead to a decrease in particle concentration and reduce the success rate of temporary plugging. Low particle density can lead to more dispersed particles, but the amount of particle settlement will be less, so from the perspective of pulse fracturing, it is recommended that the particle density should not be lower than 2200 $\mathrm{kg}/{\mathrm{m}}^3$. Similarly, the particle size should not be too large for pulse fracturing, and the initial particle concentration should be maintained above $18\%$. Full article

The drilling fluid loss or lost circulation via near-wellbore fractures is one of the most critical problems in the drilling of deep oil and gas resources, which causes other problems such as difficulty in achieving wellbore pressure control and reservoir damage. The conventional treatment is to introduce granular lost circulation material (LCM) into the drilling fluid to plug the fractures. As the migration mechanism of the LCM in irregular fractures has not been completely figured out as of yet, the low success rate of fracture plugging and repeated drilling fluid loss still obstruct the exploitation of deep oil and gas resources. In this paper, the spatial data of actual rock fracture surfaces were obtained through structured light scanning, and an irregular surface identical to the rock was machined on a transparent polymethyl methacrylate plate. On this basis, a visualization experimental apparatus for fracture plugging was established, and the fracture flow space of this device was consistent with that of the actual rock fracture. Employing cylindrical nylon particles as LCM, a visualization experiment study was carried out to investigate the process of LCM bridging and fracture plugging and the influence of LCM injection methods. The experimental results show that the process of fracture plugging includes the sporadic bridging, plugging zone extension and merging, thickening of the plugging zone and complete plugging of the fracture. It was observed in the visualization experiment that a large number of small particles flow deep into the fracture in the traditional fracture plugging method, where all types and sizes of LCM are injected at one time. After changing the injection sequence, which injects the large particles first and the small particles subsequently, it is found that the large particles will form single-particle bridging at a specific depth of the fracture, intercepting subsequently injected particles and thickening the plugging zone, which finally increases the area of the plugging zone by 19%. The visualization experiment results demonstrate that modifying the LCM injection method significantly enhances both the LCM utilization rate and the fracture plugging effect, thereby reducing reservoir damage. This is conducive to reducing the drilling cost of fractured formation. Additionally, the visualized experimental approach introduced in this study can also benefit other research areas, including proppant placement and solute transport in rock fractures. Full article

In previous studies of the transportation of proppants within fractures and the morphology of proppant-supported fractures, researchers have generally treated the fractures as static and have overlooked the interactions between fractures and the proppant during the dynamic closure caused by filtration. To address this limitation, we propose a semi-implicit method to calculate the complete fluid–structure interaction equations for the fracture, fluid, and proppant. The results show that there are three types of closed fracture patterns formed by alternate proppant injection at the end of filtration loss, and the third pattern of fracture formed by injecting small particles first and then large particles has the best support length and filling effect. More effects of the particle size and injection pattern of the injected proppant on the fracture closure pattern after the end of filtration loss are shown graphically and analyzed in detail. Full article

The key performance parameters of proppant are mainly the crushing rate and fracture conductivity, which are usually evaluated using physical experimental methods. However, the testing method for fracture conductivity has limitations, such as its long time-consumption, high testing costs, instability, and even the presence of large errors in testing results under the same conditions. The purpose of this paper is to propose a calculation method that can replace physical experiments. Firstly, we analyze the random and deterministic phenomena in the contact relationship between proppant particles from a microscopic perspective. Subsequently, we develop a physical model of the microscopic arrangement of these particles, enabling us to conduct further computer simulations of their microscopic configuration. Secondly, we conduct a microscopic mechanical analysis of the contact between proppant particles and between particles and boundaries and establish a corresponding mathematical model. Then, utilizing the simulation and mechanical analysis results of the proppant, we calculate the crushing rate. Considering the crushing rate of proppant, we improve the Kozeny–Carmen equation to determine the fracture permeability, and subsequently calculate the fracture conductivity. Finally, the calculated results are compared with the experimental results. The results show that the calculated values for the proppant crushing rate and fracture conductivity matched well with experimental data, and that the model’s calculation values were more accurate. As the number of simulations increased, the accuracy of the calculation results became higher. Research shows that the fracture conductivity is influenced by factors such as the particle size, microstructure, and crushing rate. Numerical calculation methods can replace physical experiments and provide theoretical support for engineering applications of hydraulic fracturing proppant materials. Full article

The conductivity of propped fractures following hydraulic fracturing is crucial in determining the success of the fracturing process. Understanding the primary factors affecting fracture conductivity and uncovering their impact patterns are essential for guiding the selection of fracturing engineering parameters. We conducted experiments to test fracture conductivity and analyzed the effects of proppant particle size, closure pressure, and fracture surface properties on conductivity. Using the orthogonal experimental method, we clarified the primary and secondary relationships of the influencing factors on conductivity. The results indicate that proppant particle size, formation closure pressure, and fracture surface properties significantly affect fracture conductivity, with the order of influence being closure pressure > fracture surface properties > proppant particle size. Using large-particle-size proppants effectively increases interparticle porosity and enhances fracture conductivity. However, large-particle-size proppants reduce the number of contact points between particles, increasing the pressure on individual particles and making them more prone to crushing, which decreases fracture conductivity. Proppants become compacted under closure pressure, leading to a reduction in fracture conductivity. Proppant particles can embed into the fracture surface under closure pressure, further impacting fracture conductivity. Compared to non-laminated fracture surfaces, proppant particles are more likely to embed into laminated fracture surfaces under closure pressure, resulting in a greater embedding depth and reduced conductivity. Full article

Shale reservoirs typically exhibit high density, necessitating the use of horizontal wells and hydraulic fracturing techniques for efficient extraction. Proppants are commonly employed in hydraulic fracturing to prevent crack closure. However, limited research has been conducted on the impact of shale mineral composition and proppant filling patterns on shale stress sensitivity. In this study, shale cylindrical core samples from two different lithologies in Jimusaer, Xinjiang in China were selected. The mineral composition and microscopic structures were tested, and a self-designed stress sensitivity testing system was employed to conduct stress sensitivity tests on natural cores and fractured cores with different proppant filling patterns. The experimental results indicate that the stress sensitivity of natural shale porous cores is weaker, with a stress sensitivity coefficient below 0.03, significantly lower than that of fractured cores. The shale mineral composition has a significant impact on stress sensitivity, with the stress sensitivity of clayey argillaceous shale cores, characterized by higher clay mineral content, being higher than that of sandy argillaceous shale, characterized by higher quartz mineral content. This pattern is also applicable to fractured cores filled with proppants, but the difference gradually diminishes with increased proppant concentration. The choice of large particles and high-concentration proppant bedding can enhance crack conductivity. Within the experimental range, the crack conductivity of 20–40 mesh quartz sand is more than three times that of 70–120 mesh quartz sand. At an effective stress of 60 MPa, the conductivity of cores with a proppant concentration of 2 kg/m² is 3.61 times that of cores with a proppant concentration of 0.3 kg/m². Under different particle size combinations of proppant filling patterns, the crack conductivity at the crack front with large-particle proppants is 6.21 times that of mixed bedding. This study provides valuable insights for the hydraulic fracturing design of shale reservoirs and optimization of production system parameters in subsequent stages. Full article

The small-sized proppant is widely used in the traditional hydraulic fracturing reservoir stimulation, but the theoretical research shows that the large-sized proppant can greatly improve the fracture permeability. Although many scholars have proposed the method of using large-sized proppant, the characteristics of the pressure field change and gas drainage rate during reservoir development are still unclear after pumping large-sized proppant. In this article, to study the change regularity of the reservoir pressure field, two representative proppants are selected: the small-sized proppant and large-sized proppants. First, the Navier–Stokes equations are solved using the numerical simulation method, and the characteristics of the reservoir pressure field are finely reproduced. Then, the production rate is discussed to reveal the huge potential of large-sized proppant for the natural gas development. The results show that under the same conditions, if the particle size of the proppant increases by 5 times, then the reservoir permeability will increase by 27 times approximately, and the single well production efficiency will increase by 17~19 times in the first 3000 days. In addition, a new quantitative model is proposed to evaluate the permeability magnification of the fracture and reservoir when adopting the large-sized proppant. This study further confirms that the method of large-sized proppant proposed by the author in the earlier stage has great potential. This study is helpful for the researchers and engineers to better understand the evolution regularity of the reservoir pressure field and gas production rate in the process of oil and gas exploitation after using the large-sized proppant. Full article

The presence of a reasonable flowback system after fracturing is a necessary condition for the high production of shale gas wells. At present, the optimization of the flowback system lacks a relevant theoretical basis. Due to this lack, this study established a new method for evaluating the conductivity of artificial fractures in shale, which can quantitatively characterize the backflow, embedment, and fragmentation of proppant during the flowback process. Then, the mechanism of the stress sensitivity of artificial fractures on fracture conductivity during the flowback stage of the shale gas well was revealed by performing the artificial fracture conductivity evaluation experiment. The results show that a large amount of proppant migrates, and the fracture conductivity decreases rapidly in the early stage of flowback, and then the decline gradually slows down. When the effective stress is low, the proppant is mainly plastically deformed, and the degree of fragmentation and embedment is low. When the effective stress exceeds 15.0 MPa, the fragmentation and embedment of the proppant will increase, and the fracture conductivity will be greatly reduced. The broken proppant ratio and embedded proppant ratio are the same under the two choke-management strategies. In the mode of increasing choke size step by step, the backflow proppant ratio is lower, and the broken proppant is mainly retained in fractures, so the damage ratio of fracture conductivity is lower. In the mode of decreasing choke size step by step, most of the proppant flows back from fractures, so the damage to fracture conductivity is greater. The research results have important theoretical guiding significance for optimizing the flowback system of shale gas wells. Full article

Coalbed methane reservoirs exhibit a low strength and high heterogeneity, rendering them susceptible to coal fines generation during hydraulic fracturing operations. The detrimental impact of coal fines on the conductivity of the propped fracture has been overlooked, leading to a substantial negative effect on the later-stage recovery of coalbed methane reservoirs. Moreover, the particle size distribution of the composite proppant also affects the conductivity of the propped fracture. To mitigate the damage caused by coal fines to the conductivity of the proppant pack in CBM reservoirs, this study conducted conductivity tests on actual coal rock fractures. The aim was to assess the effect of various particle size ratios in composite proppant blends on the conductivity of complex fractures in CBM reservoirs. The ultimate goal was to identify an optimized proppant blending approach that is suitable for hydraulic fracturing in coal seams. The results indicated that, in terms of the short-term conductivity of coalbed methane reservoirs, the conductivity of composite proppants is primarily influenced by the proportion of large or small particles. A higher proportion of large particles corresponds to a stronger conductivity (e.g., the conductivity is highest at a particle ratio of 5:1:1 for large, medium, and small particles). On the other hand, a higher proportion of small particles leads to a poorer conductivity (the conductivity is lowest when the particle ratio is 1:1:5). In the long-term conductivity of coalbed methane reservoirs, the fluid flushing of the fracture surfaces generates coal fines, and small particles can fill the gaps between larger particles, hindering the infiltration of coal fines. Therefore, it is important to control the particle size ratio of composite proppants, with a predominant proportion of larger particles. This approach can maintain long-term conductivity and prevent the excessive infiltration of coal fines, thereby avoiding fracture blockage (e.g., the conductivity is highest at a particle ratio of 5:1:5, followed by a ratio of 3:1:3). Furthermore, considering the influence of proppant placement methods and the support effect on near-wellbore opening fractures and far-end sliding fractures, segmented placement is utilized to fully fill the fractures for short-term conductivity, whereas mixed placement is employed for long-term conductivity to achieve a balance in particle gaps and hinder the infiltration of coal fines. The findings of this study contribute to the understanding of proppant selection and placement strategies for efficient hydraulic fracturing in coalbed methane reservoirs. Full article

Multi-stage hydraulic fracturing (MsHF) is the main technology to improve hydrocarbon recovery from shale plays. Associated with their rich organic contents and laminated depositional environments, shales exhibit transverse isotropic (TI) characteristics. In several cases, the lamination planes are horizontal in shale formations with a symmetric axis that are vertical to the bedding plane; hence, shale formations are known as transverse isotropic vertical (TIV) rocks. Ignoring the TIV nature of shale formations leads to erroneous estimates of in situ stresses and consequently to inefficient designs of fractural geometry, which negatively affects the ultimate recovery. The goal of this study is to investigate the effects of TIV medium characteristics on fractural geometry, spacing, and stress shadow development in the Jurassic Tuwaiq Mountain formation (TMF) in the Jafurah basin, which is a potential unconventional world-class play. This formation is the main source for prolific Jurassic oil reservoirs in Saudi Arabia. On the basis of a petrophysical evaluation in the Jafurah basin, TMF exhibited exceptional unconventional gas characteristics, such as high total organic content (TOC) and low clay content, and it was in the proper maturity window for oil and gas generation. The unconventional Jafurah field covers a large area that is comparable to the size of the Eagle Ford shale play in South Texas, and it is planned for development through multi-stage hydraulic fracturing technology. In this study, analytical modeling was performed to estimate the fractural geometry and in situ stresses in the anisotropic medium. The results show that the Young’s modulus anisotropy had a noticeable impact on fractural width, whereas the impact of Poisson’s ratio was minimal. Moreover, we investigated the impact of stress anisotropy and other rock properties on the stress shadow, and found that a large stress anisotropy could result in fractures being positioned close to one another or theoretically without minimal fractural spacing concerns. Additionally, we estimated the fractural aspect ratio in different propagation regimes and observed that the highest aspect ratio had occurred in the fractural toughness-dominated regime. This study also compares the elastic properties and confirms that TMF exhibited greater anisotropic properties than those of Eagle Ford. These findings have practical implications for field operations, particularly with regard to the fractural geometry and proppant placement. Full article

Supercritical CO₂ fracturing has unique advantages for improving unconventional reservoir recovery. Supercritical CO₂ can penetrate deep into the reservoir and increase reservoir reform volume, and it is less damaging to reservoir and easy to flow back. However, when the supercritical CO₂ flows as the sand-carrying fluid in the fracture, the settlement of the proppant is still worth studying. Based on the study of supercritical CO₂ density and viscosity properties, assuming that the reservoir has been pressed out of the vertical crack by injecting prepad fluid, the proppant characteristics in sand-carrying fluid under different conditions were studied by numerical simulation. After the analysis, the proppant accumulation and backflow will occur at the end of the crack. Large sand diameters, high fluid flow rates, high sand concentrations, high reservoir temperatures, and low reservoir pressures can help to shorten deposition time, and the small particle size, high fluid flow rate, low sand concentration, low reservoir temperature, and high reservoir pressure can help increase the uniformity of sand deposition. Shortening the sand deposition time can help to complete the fracturing efficiently, and increasing the deposition uniformity can improve the fracture conductivity. This article has studied the proppant settling and crack formation characteristics. It is hoped that this study can provide theoretical support for field fracturing and provide theoretical assistance to relevant researchers. Full article

The stimulation method of the marine natural gas hydrate (NGH) reservoir through hydraulic fracturing has been proposed to resolve the problem of the low production capacity in the conventional development method of pressure drawdown. Nevertheless, due to the strong plasticity and high argillaceous siltstone content of the marine NGH reservoir, conventional small-particle-size proppant cannot form effective support for fractures after fracturing because of serious embedding in the reservoir. To solve this problem, the large-size phase change proppants were developed in this study. First, an epoxy resin curing system that can reduce curing time to 40 min in low temperature and humid environment was developed. Then, the epoxy resin and curing system was emulsified, and through the optimization of the emulsification process, the particle size of the proppant can be controlled in 0.5–4.5 mm and the cementation between the proppant particles during the curing process can be prevented. Finally, the proppant performances were evaluated. The performance evaluation shows that the cured proppants have regular structure and good compressive strength, and the emulsion proppants have good transport capacity. Their large sizes provide effective propping effects for fractures generated in weakly cemented clayey silt marine NGH reservoirs. Full article

Limited-entry fracturing (LEF) technology is a widely used method to realize the simultaneous propagation of multiple fractures in horizontal wells. The key of this technology is to create high perforation friction to maintain the high treatment pressure in the wellbore and realize the uniform fluid entry of multi-fractures; however, high perforation friction cannot be effectively maintained due to the serious perforation erosion effect. Considering that the current laboratory studies mostly used small fluid injection flowrate, low injection pressure, and small proppant dosage, this study has developed a field-scale flow system to investigate the effect of various factors on perforation erosion under real field conditions. The filed-scale flow system uses the real fracturing trucks, proppant, and perforated wellbore, the fluid flow rate through perforation could reach 200 m/s and the injection pressure could reach 105 MPa. The effects of different parameters, such as injection flow rates, proppant concentration, proppant type, proppant size, and carrying fluid viscosity, on the perforation erosion were investigated. The experimental results show that: (1) The perforation friction during erosion goes through two stages, i.e., the roundness erosion stage and the diameter erosion stage. The reduction of perforating friction mainly occurred in the first stage, which was completed after injecting 1 m3 proppant. (2) After erosion, the perforation changes from the original circular shape to a trumpet shape, the inner diameter is much larger than the outer diameter. (3) The more serious perforation erosion is caused by the conditions of high injection flow rate, large proppant size, using ceramic proppant, and low viscosity fluid. The findings of this study can help for a better understanding of perforation erosion during the limited-entry fracturing in the horizontal wells, and also could promote the establishment of a theoretical model of perforation erosion under the field-scale conditions. Full article