Large-scale Hydraulic Fracturing Research Articles

Numerical simulation of solid diverting particles transport and plugging in large-scale hydraulic fracture

Diversion technology, also known as temporary plugging technology, has become an integral part of hydraulic fracturing in unconventional reservoirs. The solid diverting particles are a common type of chemical diverting agents used in horizontal well multistage fracturing. The transport and plugging of solid diverting particles within the fractures are crucial physical processes in the far-field diversion technology. In this study, in order to clarify the formation of the plugging layer by solid diverting particles in large-scale hydraulic fracture and to offer insights for the quantitative optimization of far-field diversion technology (FFD), an enhanced simplified two-fluid model within the Euler-Euler framework is employed to simulate the transport and plugging process of solid diverting particles within the fracture. And the numerical schemes of the front settlement region, the plugging layer formation region and the rear settlement region are also optimized. The proposed model is verified through comparison with experimental results from visual fracture test device. Based on the numerical results across various particle, pumping and fracture parameters, our findings indicate that: (1) The duration required to form a complete plugging layer can be reduced to 3%∼20% by increasing injection concentration, injection rate, and fracturing fluid viscosity; (2) Increasing the injection concentration (from 10kg/m3 to 30kg/m3) significantly enhances the length of the plugging layer by about 1∼16 times, compensating for the inability to achieve a complete plugging layer with smaller particle sizes. Merely increasing the injection rate alone (from 0.35m3/min to 0.80m3/min) does not remedy the inability of small particles to form a complete plugging layer under identical plugging conditions. Excessive fracturing fluid viscosity (higher than 6mPa·s) impedes the formation of a complete plugging layer with smaller particles. High fracturing fluid leak-off rate (higher than 2.5×10-7m/s) markedly reduces the length of the plugging layer by about 37%∼44%; (3) Achieving a high close packing degree of particles within the plugging layer is facilitated by increasing injection concentration, increasing injection rate, and reducing fluid viscosity; (4) The abrupt variation in fracture width or height along the fracture length affects up to about 18% of the length of the plugging layer at the top of fracture. To ensure large length of the plugging layer at the top of fracture and high close packing degree of particles within the plugging layer, we recommend injection concentration above 10kg/m3, fracturing fluid viscosity below 6mPa·s, and injection rate exceeding 0.35m3/min. For particle size less than 1.8mm, we suggest injection concentration above 20kg/m3, and fracturing fluid viscosity not exceeding 3mPa·s.

Novel fracturing fluid made of low molecular weight polymer and surfactant achieves proppant full suspension and filling entire area of hydraulic fractures

In large-scale hydraulic fracturing of unconventional reservoirs, high viscosity friction reducers (HVFR) which employ high concentration polymers of high molecular weight can improve proppant suspension, but still lack long-distance and long-time proppant transport capability. Herein, for the first time, we report a fracturing fluid made of self- assembled low molecular weight polymer and a surfactant (LMPS). When using only 0.1 wt% of the polymer, LMPS has a viscosity of 29.6 mPa·s (170 s−1, 25 ℃) and can achieve full suspension of 40/70 mesh sand at 80 ℃. LMPS can form robust short molecular chain networks through numerous self-assembling association sites, rather than relying on entanglement. Notably, it achieves a minimum loss tangent as low as 0.1 in the viscoelastic response, demonstrating its strong elastic characteristics. According to the creep-recovery test, the strain recovery rate (87.9 %) of LMPS at 0.2 wt% polymer concentration far exceeds that of the HVFR with a concentration as high as 10.1 %. This indicates that LMPS has a stronger deformation-resisting ability, thereby preventing proppant settling. Taking advantage of LMPS’ superior proppant suspension capability, proppant can move with the slurry to the whole fracture for placement, while the HVFR provides only 48 % height support of the fractures in the form of dunes. A field trial shows that at a polymer concentration of 0.2 wt%, LMPS can stably transport 20/40 mesh quartz sand under a slurry rate of 2.8 m3/min and a proppant concentration of 635 kg/m3 during the fracturing process.

Research on the Pass Capacity Model of Logging Tools for Complex Horizontal Wells

Shale gas, which exists in organic-rich shale or mud shale formations primarily in adsorbed or free states, poses significant development challenges due to the low permeability of shale formations. Traditional vertical wells are ineffective for shale gas extraction, making horizontal wells and large-scale hydraulic fracturing essential for efficient development. However, the complexity of the formation can lead to casing deformation, severely impacting the pass capacity of plug and perforation gun strings in the wellbore. This study analyzes the causes of casing deformation and discusses the rapid development of the cluster perforating technology in perforation operations, and discusses the challenges that might encountered during the process of wireline conveying or pumping. The irregular trajectory of horizontal wells and the high dogleg deflecting severity in the deviated sections can cause cluster perforating strings to suddenly get stuck during the downhole process, leading to a sudden increase in pumping pressure, which may result in premature seating of the fracturing bridge plug, or pull-off accidents at the weak point of the wireline. This research aims to improve engineering efficiency and prevent engineering accidents by conducting a pass capacity analysis of the perforating tool string, which is of significant engineering importance for shale gas development.

EXPERIMENTAL STUDY ON THE FRACTURE CONDUCTIVITY IN SHALE OIL PRODUCTION

Unconventional oil and gas resources, such as shale oil and gas, are gradually attracting great attention from all countries of the world. Horizontal drilling and large-scale hydraulic fracturing technology are used to efficiently extract oil from shale formation. Effective placement of the proppant in the fractures and high long-term conductivity are the keys to solve the problems of oil well flow rate increase in shale oil and gas fields. In this work, the sieve analysis method and FCMS-V fracture conductivity determination device, as well as scanning electron microscope are used. They are used to experimentally investigate the filtration characteristics of hydraulic fracturing fractures and establish the key factors affecting the filtration characteristics. The object of the study is the core of the oil-saturated DG shale formation of Songliao Basin. Also in this paper, the indentation and crushing mechanism of proppant under reservoir conditions is studied. The influence of various factors was evaluated qualitatively and quantitatively. The following studies were conducted: the effect of sand granule size on conductivity, the effect of grain size distribution on conductivity, the effect of proppant concentration on conductivity, the effect of fracture closure pressure on conductivity, and the effect of proppant indentation on conductivity. The granule sizes of the proppant used range from 30/50 to 70/140 mesh. Proppant concentration: 2,5; 5; 10 kg/m2. Ratios of granule sizes for used mixtures: 1:1:1, 1:2:7, 1:4:5.And crack clamping pressure from 20 to 40 MPa. As a result of the study, dependences of initial and long-term fracture conductivity on clamping pressure, granulometric composition of proppant and its concentration were obtained. Using a scanning electron microscope, the degree of indentation and crushing of proppant under reservoir conditions in two media, namely shale core and steel plates, was visually evaluated. The results of experimental studies can be used to optimize the shale oil development system and have scientific and practical significance for shale oil production in continental deposits.

A Review of Fracturing and Enhanced Recovery Integration Working Fluids in Tight Reservoirs

Tight reservoirs, characterized by low porosity, low permeability, and difficulty in fluid flow, rely on horizontal wells and large-scale hydraulic fracturing for development. During fracturing, a significant volume of fracturing fluid is injected into the reservoir at a rate far exceeding its absorption capacity. This not only serves to create fractures but also impacts the recovery efficiency of tight reservoirs. Therefore, achieving the integration of fracturing and enhanced recovery functions within the working fluid (fracturing-enhanced recovery integration) becomes particularly crucial. This study describes the concept and characteristics of fracturing-enhanced recovery integration and analyzes the types and features of working fluids. We also discuss the challenges and prospects faced by these fluids. Working fluids for fracturing-enhanced recovery integration need to consider the synergistic effects of fracturing and recovery; meet the performance requirements during fracturing stages such as fracture creation, proppant suspension, and flowback; and also address the demand for increased recovery. The main mechanisms include (1) enlarging the effective pore radius, (2) super-hydrophobic effects, and (3) anti-swelling properties. Fracturing fluids are pumped into fractures through pipelines, where they undergo complex flow in multi-scale fractures, ultimately seeping through capillary bundles. Flow resistance is influenced by the external environment, and the sources of flow resistance in fractures of different scales vary. Surfactants with polymerization capabilities, biodegradable and environmentally friendly bio-based surfactants, crosslinking agents, and amino acid-based green surfactants with outstanding properties will unleash their application potential, providing crucial support for the effectiveness of fracturing-enhanced recovery integration working fluids. This article provides important references for the green, efficient, and sustainable development of tight oil reservoirs.

Simulation of Key Influencing Factors of Hydraulic Fracturing Fracture Propagation in a Shale Reservoir Based on the Displacement Discontinuity Method (DDM)

In the process of the large-scale hydraulic fracturing of a shale gas field in the Weiyuan area of Sichuan province, the quantitative description and evaluation of hydraulic fracture expansion morphology and the three-dimensional distribution law are the key points of evaluation of block fracturing transformation effect. Many scholars have used the finite element method, discrete element method, grid-free method and other numerical simulation methods to quantitatively characterize hydraulic fractures, but there are often the problems that the indoor physical simulation results are much different from the actual results and the accuracy of most quantitative studies is poor. Considering rock mechanics parameters and based on the displacement discontinuity method (DDM), a single-stage multi-cluster fracture propagation model of horizontal well was established. The effects of Young’s modulus, Poisson’s ratio, the in situ stress difference, the approximation angle, the perforation cluster number and the perforation spacing on the formation of complex fracture networks and on the geometrical parameters of hydraulic fractures were simulated. The research results can provide theoretical reference and practical guidance for the optimization of large-scale fracturing parameters and the quantitative post-fracturing evaluation of horizontal wells in unconventional reservoirs such as shale gas reservoirs.

Simultaneous adjustment on the CO2/oil and CO2/water interface tensions using hydrophilic, lipophilic and CO2-philic surfactants during CO2 flooding to enhance shale oil recovery after hydraulic fracturing

It is an urgent demand to further enhance shale oil recovery after large-scale hydraulic fracturing with a low oil recovery. CO2 flooding technology has been demonstrated to effectively develop shale oil, however, the residual water after hydraulic fracturing can influence the efficiency of CO2 flooding because of the high CO2-water interfacial tension. Here, the hydrophilic, lipophilic and CO2-philic surfactants were investigated to simultaneously adjust the CO2/oil and CO2/water interface tension to accelerate the oil and water flows to enhance shale oil recovery. The results show that the low-carbon alcohol polyoxyethylene polyoxypropylene ether has the hydrophilic, lipophilic and CO2-philic properties. The alkyl chain length and PO groups have great influence on the interfacial tension of CO2-oil, while the presence of EO groups can significantly reduce the interfacial tension of CO2-water. The surfactant of C4EO3PO6 can not only demonstrate the best performance in reducing the interfacial tensions of shale oil-CO2 and water-CO2, but also decrease the minimum miscibility pressure (MMP) of the shale oil-CO2 system to 18.89 MPa from 24.10 MPa. The interfacial tension between water and the CO2 + 1.0 wt% C4EO3PO6 system can be decreased to 6.62 mN/m at 28 MPa and the reduction rate is 56.10 %. The enhancement of surfactants on the extraction effect of CO2 and the mutual diffusion process between CO2 and shale oil or water interface is the major mechanism to decrease the interfacial tensions. Therefore, the addition of surfactant in CO2 can simultaneously decrease the interfacial tensions of CO2-oil and CO2-water and has a potential to enhance shale oil recovery by reducing the capillary resistance of residual water after hydraulic fracturing and increasing the miscibility between CO2 and oil.

Numerical simulation study on evolution law of three-dimensional fracture network in unconventional reservoirs

It has become a consensus that large-scale hydraulic fracturing is adopted to achieve the stimulation of unconventional oil and gas reservoir. The complex fracture network formed by fracturing is closely related to the effect of reservoir stimulation, which has extremely complicated evolution process. Therefore, it is necessary to study the evolution law of fracture network in large-scale hydraulic fracturing of unconventional reservoirs. In this article, the geological engineering parameters of horizontal well H in shale gas reservoir in southern Sichuan are taken as an example, a three-dimensional fracture network expansion model is established based on the boundary element method and finite volume method, and the simulation of the complex fracture network in a whole well section is carried out to analyze the evolution law of reservoir fracture network under different geological and engineering parameters. The results show that the horizontal stress field distribution has a significant effect on fracture geometric form. Hydraulic fractures in reservoirs with larger horizontal stress difference have stronger directivity, while the horizontal wellbore tends to obtain better reservoir stimulation results when it is parallel to the minimum horizontal principal stress setting. The conjugated natural fracture developed in the reservoir inhibits the hydraulic expansion fractures in both directions. Although it increases the complexity of the fractures, it is not necessarily conducive to improving the reservoir stimulation effectiveness. The lower the strength of natural fracture is, the more complex the fracture geometric form becomes, and the smaller the stimulated reservoir volume is. Correspondingly, the higher the strength of natural fracture is, the simpler the fracture geometric form becomes, and the larger the stimulated reservoir volume is. Suitable fracturing construction displacement can not only contribute to form a more complex fracture distribution, but also help to obtain a larger stimulated reservoir volume. The optimal construction displacement ranges from 10 to 14 m3/min. Low viscosity fracturing fluids are suitable for the formation of long-narrow fractures and able to connect with the remote reservoir and form complex fracture networks. Lower viscosity fluids can be used to achieve better reservoir stimulation effectiveness when sand-carrying capacity is met.

Tight Reservoir Characteristics and Controlling Factors of Permian Lucaogou Formation in Yongfeng Sub-Sag, Chaiwopu Sag

On the basis of the observation of rock cores and cuttings, combining the information from thin section identification, physical properties analysis, scanning electron microscopy, X-ray diffraction, etc., the characteristics and controlling factors of the tight reservoir in the Permian Lucaogou Formation of the Yongfeng sub-sag of the Chaiwopu sag have been studied. Based on the analysis, the Lucaogou Formation in the study area can be divided into two lithological sections. The tight sandstone reservoir, characterized by low porosity and low permeability, is mainly developed in the upper section of the Lucaogou Formation. The lithology of the tight reservoirs is mainly lithic sandstone with low compositional and structural maturity. The reservoir space types mainly consist of secondary pores, including intergranular dissolution pores, intragranular dissolution pores and fractures, and the primary pores are severely destroyed. The main controlling factors of reservoirs include sedimentary facies, lithology, diagenesis, later tectonic movements and fractures, and the latter two factors have a significant impact on improving reservoir physical properties and seepage capacity. The tight reservoir has high brittleness and low water sensitivity, which is very conducive to large-scale hydraulic fracturing to transform the reservoir and improve oil and gas production capacity.

Study on formation process and reservoir damage mechanism of blockages caused by polyacrylamide fracturing fluid in production wells

In the process of the large-scale hydraulic fracturing development in oil and gas fields, reservoir damage caused by polymer fracturing fluid is inevitable. The real oil and gas field reservoir conditions make the causes of reservoir damage more complicated, and few reports have provided an in-depth analysis of the composition and structure of actual blockages generated in production wells after hydraulic fracturing. In this work, we innovatively obtained reservoir blockages from production wells after fracturing in oil and gas fields, analyzed their physical and chemical properties by SEM, XRD, IR and other methods, then reproduced the blockages formation process in the laboratory through ampoule aging experiments, and evaluated their impact on the reservoir damage rate and fracture flow capacity by core flow physical simulation experiments. The results indicate that the blockages primarily consist of polyacrylamide and iron ions complexes. For the formation process of blockages, the gel breaker solution will release iron ions after reacting with iron calcite existed in the reservoir. The carboxyl group of polyacrylamides and Fe3+ ions can further form highly stable -(COO)3Fe bonds. The physical simulation results revealed that the generation of Fe3+ ions significantly enhanced the extent of reservoir damage and reduction rate of fracture conductivity associated with polyacrylamide fracturing fluid. In addition, after complete gel breaking, the weak interactions between the short-chain molecular groups and Fe3+ ions result in limited molecular flocculation and entanglement, leading to the reduction in reservoir damage. By identifying the specific formation causes of blockages, we revealed the reservoir damage mechanism from a novel perspective, which is of great significance for guiding the development of low damage fracturing fluid system and further improving oil and gas recovery.

Study on Brittleness Characteristics and Fracturing Crack Propagation Law of Deep Thin-Layer Tight Sandstone in Longdong, Changqing

Tight-sandstone oil and gas resources are the key areas of unconventional oil and gas resources exploration and development. Because tight-sandstone reservoirs usually have the characteristics of a low porosity and ultralow permeability, large-scale hydraulic fracturing is often required to form artificial fractures with a high conductivity to achieve efficient development. The brittleness of rock is the key mechanical factor for whether fracturing can form a complex fracture network. Previous scholars have carried out a lot of research on the brittleness characteristics of conglomerate and shale reservoirs, but there are few studies on the brittleness characteristics of sandstone with different types and different coring angles in tight-sandstone reservoirs and the fracture propagation law of sandstone with different brittleness characteristics. Based on this, this paper carried out a systematic triaxial compression and hydraulic fracturing experiment on the tight sandstone of Shan 1 and He 8 in the Longdong area of the Changqing oilfield. Combined with CT scanning cracks, the brittleness characteristics and fracturing crack propagation law of different types and different coring angles of sandstone under formation-confining pressure were clarified. The results show that there are great differences between different types of sandstone in the yield stage and the failure stage. The sandstone with a quartz content of 100% has the highest peak strength and a strong brittleness. Sandstones with a high content of natural fractures and dolomite have a lower peak strength and a weaker brittleness. There are also differences in the peak strength and fracture morphology of sandstone with different coring angles due to geological heterogeneity. The sandstone with a comprehensive brittleness index of 70.30 produces a more complex fracture network during triaxial compression and hydraulic fracturing than the sandstone with a comprehensive brittleness index of 14.15. The research results have important guiding significance for on-site fracturing construction of tight-sandstone reservoirs.

A Study on the Mechanism of Casing Deformation and Its Control Strategies in Shale Oil Hydraulic Fracturing

The problem of casing deformation caused by large-scale hydraulic fracturing in shale oil wells severely restricts the efficient development of Gulong shale oil. In order to clarify the mechanism of casing deformation in shale oil wells, comprehensive analysis was conducted on engineering factors, multi-arm caliper logging, seismic attributes, and the distribution characteristics of casing deformations. This study shows that casing strength, cementing quality, and wellbore curvature are not the main controlling factors for casing deformation. Casing deformation is caused by the communication between hydraulic fractures and natural fractures during the fracturing process, which increases the fluid pressure in the natural fracture and induces shear slip, resulting in casing deformation due to shear stress. Based on the understanding of the mechanism of casing deformation in shale oil wells, two targeted casing deformation prevention and control methods are proposed. First, temporary plugging was implemented during the hydraulic fracturing process when the fluid volume reached 1000 m3, and the pumping rate was reduced to below 16 m3/min to reduce the internal fluid pressure of the fractures and control fracture slip, thereby minimizing the risk of casing deformation. Second, hollow particles were added to the cement to enhance the consolidation effect of the cement sheath and mitigate casing deformation caused by fracture slip. Research indicates that a hollow particle content of 15% can meet the requirements for casing deformation control in Gulong shale oil. These research results can provide important references for the prediction and prevention of casing deformation risks in shale oil and similar unconventional reservoirs during hydraulic fracturing.

Numerical Simulation of Hydraulic Fracture Propagation in Conglomerate Reservoirs: A Case Study of Mahu Oilfield

Mahu conglomerate oilfield has strong heterogeneity. Currently, large-scale hydraulic fracturing is commonly used for reservoir reconstruction. The geometry of hydraulic fractures is influenced by gravel. By referring to the scanning and logging results of a conglomerate reservoir, and considering the characteristics of gravel development in the Mahu Oilfield reservoir, python programming is used to establish a finite element model containing a matrix, bonding interface, and gravel, which considers the random distribution of gravel position and size. The model uses cohesive element global embedding to study the geometry of a hydraulic fracture. The results show that the hydraulic fracture in the gravel reservoir mainly spreads around the gravel, and the propagation path of the hydraulic fracture is affected by the horizontal stress difference. When the interfacial bonding strength is greater than 2 MPa, the conglomerate is more likely to be penetrated by hydraulic fractures, or the hydraulic fractures stop expanding after entering the conglomerate. The strength of the conglomerate largely determines whether hydraulic fractures can pass through it. When the strength of gravel is greater than 7 MPa, hydraulic fractures will stop expanding after entering the gravel. During the hydraulic fracturing process of conglomerate reservoirs, using a large injection rate can result in longer hydraulic fractures and larger fracture volumes.

Physical Simulation Experiments of Hydraulic Fracture Initiation and Propagation under the Influence of Deep Shale Natural Fractures

Horizontal wells’ multi-section and multi-cluster hydraulic fracturing plays an important role in the efficient development of shale gas. However, the influence of the perforating hole and natural fracture dip angle on the process of hydraulic fracture initiation and propagation has been ignored in the current researches. This paper presents the results related to a tri-axial large-scale hydraulic fracturing experiment under different natural fracture parameters. We discuss the experimental results relating to the near-wellbore tortuosity propagation of hydraulic fractures. Experimental results showed that the triaxial principal stress of the experimental sample was deflected by the natural fracture, which caused significant near-wellbore tortuosity propagation of the hydraulic fractures. The fractures in most rock samples were not perpendicular to the minimum horizontal principal stress after the experiment. As well, the deflection degree of triaxial principal stress direction and the probability of hydraulic fractures near-wellbore tortuosity propagation decreased with the increase of the natural fracture dip angle. After hydraulic fractures’ tortuous propagation, the hydraulic fractures will propagate in the direction controlled by the triaxial stress in the far-wellbore area. For reservoirs with natural fractures, proppant in hydraulic fracturing should be added after the fractures are fully expanded to prevent sand plugging in tortuous fractures. When the permeability of natural fractures is low, the volume of fracturing fluid entering natural fractures is small, and hydraulic fractures are easy to pass through the natural fractures.

Experimental evaluation of the flow resistance of CO2 foam fracturing fluids and simulation prediction for fracture propagation

Shale gas fracturing requires huge amounts of water, but most well pads are located mainly in hilly areas where water is scarce. Water supply issues have limited the industrialization of shale gas development. CO2 foam fracturing fluids can meet the requirements for large-scale hydraulic fracturing of shale gas and relieve pressure on water resources. Friction calculations of CO2 foam fracturing fluids in conduit flow are key to the reliability of overall fracturing procedures, affecting fracture targeting and reservoir stimulation effects. Through the analysis of the experimental data of carbon dioxide foam fracturing fluid flow under the simulated reservoir conditions, the influence of pressure, temperature, shear rate, foam quality and other factors on the friction characteristics of CO2 foam fracturing fluid was obtained, and the mathematical calculation model of the friction coefficient of CO2 foam fracturing fluid was established, and the pipe string friction and bottom hole pressure during the fracturing process were obtained, Thus, the shape and extension behavior of hydraulic fractures in the process of carbon dioxide foam fracturing in shale reservoir are simulated and predicted, which provides a theoretical basis for effective evaluation of fracturing effect.

Optimization of the Lateral Length of Shale-Gas Horizontal Wells Based on Geology–Engineering–Economy Integration

Horizontal wells with extended lateral lengths and large-scale hydraulic fracturing are a key technology for shale gas development. Lateral length is the key factor in determining the production and economic benefits of horizontal wells. Therefore, based on geology–engineering–economy integration, a method for optimizing the lateral length of shale-gas horizontal wells is established. Through fracture-shape prediction, productivity simulation and input–output analysis, the net present-value model of the technical–economic evaluation of the economic lateral length is established. A comprehensive evaluation of lateral lengths in Changning Block is then conducted. The results show that, under the current geological, engineering, and economic conditions in Changning Block, a horizontal well with a lateral length between 175 m and 3508 m is economically viable, and the optimal economic lateral length is 2000 m. The porosity and thickness of the reservoir matrix, the production time, the drilling investment, and the price of the natural gas wellhead in the first year have a great impact on the economic lateral length. On one hand, we can increase the drilling rate by increasing the technical research and development efforts. On the other hand, we can improve the construction management level to reduce investment and reasonably increase the price subsidy to optimize the lateral length of shale-gas horizontal wells.

THE FRACTAL MATHEMATICAL MODELS FOR SPONTANEOUS AND FORCED IMBIBITION WITH DIFFERENT CROSS-SECTION SHAPES IN SHALE OIL RESERVOIR

Large-scale hydraulic fracturing is the critical technology for effective shale oil production. However, the imbibition flow mechanisms of fracturing fluid in shale micropores and the influence of shale microstructure and physical properties are still indistinct, which makes the optimization goal of fracturing flowback unclear and restricts the enhancement of shale oil recovery. Therefore, based on SEM and XRD experiments, it is analyzed that shale has the characteristics of multiple pores, which are divided into organic pores, brittle mineral pores, and clay pores. Nonetheless, how the tube cross-section controls the interface displacement is not well discussed in the available literature, especially in irregular triangles, rectangles and other non-circular shapes. This paper studies the influence of cross-section shapes on the capillary force by considering the corner flow of the wetting phase, and it analyzes the imbibition dynamics of different types of pores. Using the shale multi-pores physical model and fractal theory, the shale semi-analytical solution models of SI and FI are established. Theoretical analysis of the water imbibition mechanisms shows that the key factors controlling SI and FI volume include imbibition time, fluid properties, pore cross-section shapes, tortuosity, and forced pressure.

A Semi-Analytical Model of an Off-Center Multi-Wing Fractured Well in a Low-Permeability Gas Reservoir

Summary Since there are several hydraulic fractures around a wellbore after a large-scale hydraulic fracturing and the well is not in the center of the reservoir, no corresponding semianalytical model for wellbore pressure analysis has been proposed. To bridge this gap, this paper aims to present a semianalytical model of the off-center multiwing fractured well. With consideration of permeability stress sensitivity, the reservoir model and hydraulic fracture model are established, respectively. The coupling approach of the reservoir model and hydraulic fracture model is used to obtain the wellbore pressure solution. Meanwhile, the off-center multiwing fractured well is verified with a numerical solution. The seven flow regimes can be distinguished according to the characteristics of the pressure derivative curve. Furthermore, the effect of different fracture distributions on wellbore pressure and the derivative curve is discussed and analyzed. Assuming that the fracture wing number is equal to the average length of all fracture wings, the wellbore pressure is lowest before the radial flow regime when the fracture wing has a uniform distribution around the angle and all fracture wings are equal in length. Besides, the influence of other important parameters (fracture wing number, off-center distance, etc.) is discussed. According to the analysis, we conclude that fracture wing number has a significant influence on the pressure and derivative curves before the radial flow regime. The off-center distance has no influence on the pressure and derivative curve before the radial flow regime, but it has an obvious influence on arc boundary reaction time. Finally, the advantages of the semianalytical solution are fast calculation speed and high calculation accuracy (especially in the early flow regime).

Application of Large-Scale Hydraulic Fracturing for Reducing Mining-Induced Stress and Microseismic Events: A Comprehensive Case Study

Application of Large-Scale Hydraulic Fracturing for Reducing Mining-Induced Stress and Microseismic Events: A Comprehensive Case Study

Experimental study of water imbibition characteristics of the lacustrine shale in Sichuan Basin

Through the stimulation method of large-scale hydraulic fracturing, the spontaneous imbibition capacity of the water phase in the shale reservoir has great influence on the effect of stimulation. Generally, the lacustrine shale has the characteristics of high clay minerals content, strong expansibility, development of nanopores and micro-pores, and underdevelopment of fractures, which leads to the unclear behavior of spontaneous imbibition of aqueous phase. The lacustrine shale of Da'anzhai Member and marine shale of Longmaxi Formation in Sichuan Basin were selected to prepare both the shale matrix sample and fractured shale sample, and the spontaneous imbibition experiment of simulated formation water was carried out. By means of an XRD test, SEM observation, nuclear magnetic resonance test and linear expansion rate test, the mineral composition, the structure of pores and fractures, the capacity of hydration and expansion of both lacustrine and marine shale are compared and analyzed. The results show that the average spontaneous imbibition rate of lacustrine shale is 60.8% higher than that of marine shale within the initial 12 hours of imbibition. The lacustrine shale has faster imbibition rate than the marine shale in the initial stage of spontaneous imbibition. However, the lacustrine shale has underdeveloped pores and fractures, as well as poor connectivity of pores. Besides, the strong hydration and expansion of clay minerals can easily lead to dispersion and migration of clay minerals on the fracture surface, which will plug up the seepage channels, resulting in poor capacity of spontaneous imbibition. The spontaneous imbibition rate in the middle and late stage of Lacustrine shale is obviously lower than that of the marine shale. The overall spontaneous imbibition rate ability of the lacustrine shale is less than that of the marine shale. According to the characteristics of water imbibition of lacustrine shale, considering the dual effects of hydration expansion of clay minerals on the effective reconstructed volume, the microfractures can be initiated and extended by fully utilizing the hydration of shale. Acidification treatment, oxidation treatment or high temperature treatment can be used to expand pore space, enhance water phase imbibition capacity and improve multi-scale mass transfer capacity of the lacustrine shale.