Horizontal Fracture Research Articles

MULTICENTER EXTERNAL VALIDATION OF THE ACCURACY OF COMPUTED TOMOGRAPHY CRITERIA FOR DETECTING THORACOLUMBAR POSTERIOR LIGAMENTOUS COMPLEX INJURY

Background and Objective Recent studies have proposed computed tomography (CT) criteria for posterior ligamentous complex (PLC) injury: disrupted if ? 2 CT findings, indeterminate if single finding, and intact if 0 CT findings. The study aims to validate the CT criteria for PLC injury externally. Methods Three level 1 trauma centers enrolled 614 consecutive patients with acute thoracolumbar fractures (T1- L5) who received Computed tomography (CT) and magnetic resonance imaging (MRI). Three reviewers from each center were the patients from the respective center for sessed CT for facet joint malalignment, horizontal laminar fracture, spinous process fracture, and interspinous widening and MRI for disrupted PLC. The primary outcome is the diagnostic accuracy of CT criteria (0,1, ? 2 findings) in detecting disrupted PLC on MRI using all CT readings. Subgroup analysis for each participating center and reviewer was done. The inter-reader agreement on PLC status on MRI and CT criteria was assessed using Fleiss Kappa (k). Results The positive predictive value (PPV) for PLC injury was 0 findings, 3%; single positive CT, 43%; ? 2 CT findings, 94%, and was consistent among different centers and reviewers. The AUC for ? 1 CT findings in detecting PLC injury ranged from 90% to 97%, indicating excellent discrimination for all centers. The inter-reader k on PLC status by MRI and CT criteria was substantial (k >0.60). Conclusions This study externally validates the previously proposed CT criteria for PLC injury. ? 2 positive CT findings or 0 CT findings can be used as criteria for a disrupted PLC (B-type injury) or intact PLC (A-type injuries), respectively, without added MRI. A single CT finding implies indeterminate PLC status and the need for further MRI assessment. The CT criteria will potentially guide MRI indications and treatment decisions for burst fractures in patients without neurological impairment.

Effect of Thick–Hard Main Roof Fracturing on the Spatiotemporal Evolution of Overburden Fractures

Gas gushing and the co-mining of coal and gas outbursts are common disasters in coal mines. The weakening of thick–hard main roof fracturing can effectively alleviate the gas overrun in the initial mining stage. Four numerical simulation schemes were designed to determine the optimal fracturing treatment scheme for the gas overrun problem in the initial mining stage of the 6505# working face in the Huanghou Coal Mine. Compared with the scheme of the non-fracturing main roof, the weakening of the main roof fracturing could alleviate the concentration of advanced abutment stress. The fissure ratio of the overburden was solved by the binary method, and the dominant channels of gas migration and their morphological evolution under different fracturing schemes were obtained. On this basis, the permeability model of “permeability–fissure ratio–fractal dimension” was established. The results show that the overburden fracture network of the horizontal fracturing scheme has a larger fractal dimension, indicating that the overburden fracture under the scheme is more fully developed and more conducive to gas migration. The research results provide valuable reference for the design of the gas extraction scheme.

Tibial Insufficiency Fracture with Characteristics of an Atypical Fracture: A Rare Case and Literature Review

Background and Objectives: Osteoporosis is becoming more prevalent with the rise in the aging population, leading to the increased use of bisphosphonates for treatment. While these medications are effective in preventing osteoporotic fractures, long-term use has been associated with atypical insufficiency fractures, primarily in the femur. However, atypical fractures in other weight-bearing bones, such as the tibia, have rarely been reported. This study aims to present a case of an atypical insufficiency fracture of the tibia in an elderly female who has been on long-term bisphosphonate therapy and to review treatment outcomes within the context of the current literature. Patient concerns: A 76-year-old female presented with pain in the proximal right tibia, developing two months prior without trauma. She had been receiving long-term bisphosphonate therapy for osteoporosis, initially taking sodium risedronate orally for 4 years, followed by intravenous ibandronate for 10 years. Physical examination revealed localized tenderness, and radiographs showed cortical thickening and a horizontal fracture line in the proximal right tibia. MRI confirmed these findings, along with surrounding edema. The laboratory results were mostly normal, but the bone formation marker osteocalcin was significantly reduced. The patient had a history of insufficiency fractures in the ipsilateral tibia and contralateral femur, previously treated conservatively with teriparatide. A similar conservative approach was attempted but failed, leading to surgical intervention with intramedullary nailing and supplementary plating. At the 8-month follow-up, the patient showed successful fracture union and resolution of symptoms. Conclusion: Long-term use of bisphosphonates, though effective for osteoporosis, can lead to atypical insufficiency fractures, primarily in the femur but also occasionally in the tibia. Clinicians should consider this possibility when patients present with pain in weight-bearing bones without a history of trauma. Prompt diagnosis through thorough history-taking, physical examination, and appropriate imaging is essential to ensure timely management.

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% to 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 to 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% to 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.

Numerical Modeling of Hydraulic Fracturing Interference in Multi-Layer Shale Oil Wells

Multi-layer horizontal well development and hydraulic fracturing are key techniques for enhancing production from shale oil reservoirs. During well development, the fracturing performance and well-pad production are affected by depletion-induced stress changes. Previous studies generally focused on the stress and fracturing interference within the horizontal layers, and the infilled multi-layer development was not thoroughly investigated. This study introduces a modeling workflow based on finite element and displacement discontinuity methods that accounts for dynamic porous media flow, geomechanics, and hydraulic fracturing modeling. It quantitatively characterizes the in situ stress alteration in various layers caused by the historical production of parent wells and quantifies the hydraulic fracturing interference in infill wells. In situ stress changes and reorientation and the non-planar propagation of hydraulic fractures were simulated. Thus, the workflow characterizes infill-well fracturing interferences in shale oil reservoirs developed by multi-layer horizontal wells. Non-planar fracturing in infill wells is affected by the parent-well history production, infilling layers, and cluster number. They also affect principal stress reorientations and reversal of the fracturing paths. Interwell interference can be decreased by optimizing the infilling layer, infill-well fracturing timing, and cluster numbers. This study extends the numerical investigation of interwell fracturing interference to multi-layer development.

Simulation Study on Reservoir Stimulation of Multihorizontal Wells for Gas Hydrate Production in Low-Permeability Reservoirs.

The feasibility of hydrate exploitation technology has been verified by two rounds of trial productions in the South China Sea, but it is also faced with the problem of low gas production efficiency. Therefore, this paper proposed four different hydrate production cases with multihorizontal wells and established simulation models. Then, the influence patterns of reservoir stimulation and offset distances on hydrate dissociation, saturation change, and pressure distribution were studied. To understand hydrate dissociation behaviors and production performances, the coupling effects of multihorizontal wells were discussed. Through simulation, the following conclusions could be drawn: (1) hydrate reservoir stimulation could effectively increase gas production. In these four production models, the cumulative gas production in Case C (multihorizontal wells + reservoir stimulation) was 5.27 times that of Case A (only multihorizontal wells) in 330 days. However, in Case D with screen completions, the gas output was 15.58% less compared with Case C. (2) Different offset distances of horizontal wells had a relatively minor impact on the cumulative gas yield and daily gas capacity. In addition, the variation range of hydrate saturation changed with offset distances of horizontal wells, indicating that hydrate dissociation occurred mainly around horizontal wells and fractures. (3) Considering interwells coupling, the daily gas rate and cumulative gas production of inner wells were higher than outer wells, and the cumulative gas volume increased by 6.4% in 330 days. Temporally and spatially, the hydrate saturation variation between wells was significantly faster than the outward expansion from the horizontal wells. Moreover, nearer to the axis of the horizontal wells, the variation in the hydrate saturation was more pronounced. These results could provide theoretical data to optimize marine hydrate development with multihorizontal wells.

Analysis of the Impact of Clusters on Productivity of Multi-Fracturing Horizontal Well in Shale Gas

Shale gas reservoirs with nanoporous media have become one of the primary resources for natural gas development. The nanopore diameters of shale reservoirs range from 5 to 200 nm, with permeability ranging from 1 × 10−9 to 1 × 10−6 μm2. The natural gas production from shale gas reservoirs is low, necessitating the use of multi-stage hydraulic fracturing in horizontal wells. Segmented multi-cluster perforation fracturing is an effective method for shale gas extraction in these wells. The number of clusters significantly impacts the productivity of horizontal wells. Therefore, it is essential to analyze the impact of cluster numbers on fracture productivity in shale gas reservoir development. In this study, the equivalent flow resistance method was applied to establish a productivity model for multi-stage hydraulic fracturing horizontal wells in shale gas reservoirs considering diffusion and slip. An approximate analytical solution was obtained, and the effects of cluster length, diffusion coefficient, and fracture network permeability on productivity were analyzed. The results show that gas production gradually increases with the increase in the number of clusters and cluster length. However, as the number of clusters increases, the interference between clusters leads to a decrease in the productivity of individual clusters. As the fracture permeability, fracture network permeability, and diffusion coefficient increase, shale gas production also gradually increases. The permeability of the fracture network has the greatest impact on productivity. These research results are beneficial for the design of clusters in horizontal well fracturing and are of great importance for the development and production of shale gas reservoirs.

Immediate and late treatment of horizontal root fractures

Immediate and late treatment of horizontal root fractures

Immature Central Incisors With Horizontal Root Fracture:36 Months Follow-up

Immature Central Incisors With Horizontal Root Fracture:36 Months Follow-up

Laboratory and numerical investigations on land-sourced solute transport in coastal fractured aquifers

Land-based pollutants threaten coastal aquifers, highlighting the need to protect groundwater and nearshore marine ecosystems. While aquifer heterogeneity has been recognized as a significant factor affecting solute behavior, the impact of fractures on land-sourced solute transport in coastal aquifers remains unclear. This study attempted to address this issue through laboratory experiments and discrete fracture matrix (DFM) models. The impact of horizontal fractures on the temporal and spatial characteristics of solute transport, spreading, and discharge under seawater intrusion was analyzed based on variations in fracture position and length. The results show that fractures/low-velocity zones (LVZ) can accelerate/delay solutes, dividing them into different transport modes and enhancing/prolonging their spreading/discharge duration. Changes in fracture position and length also affect its transport acceleration and path deviation abilities, which ultimately determine when solute discharge occurs. The mixing zone and unsaturated zone, in addition to the LVZ, hinder solute transport, reducing the rate and delaying the end of solute discharge. Meanwhile, fractures facilitate solute transport into the saltwater wedge, expanding the solute discharge zone. However, if solutes are initially within the LVZ, their entry into the fracture rely on their distance from the fracture's near-land edge and the size of the fracture's convergence zone.

CT-Assisted Management with Biodentine Obturation and Aesthetic Rehabilitation of a Geminated Maxillary Central Incisor with Mid-Root Fracture: A Rare Case Report

Gemination, a rare aberration in tooth development, results from the incomplete division of one tooth germ into two. In this case report, a true geminated permanent maxillary central incisor tooth with a horizontal mid-root fracture is successfully treated by non-surgical endodontic treatment. To elucidate the intricate root canal anatomy of this rare geminated incisor, we employed computed tomography imaging technology, enhancing our understanding of this complex case. Utilizing biodentine for obturation proved pivotal, as its capacity to accelerate reparative dentin formation facilitated prompt healing, particularly beneficial in fracture cases. This was followed by aesthetic rehabilitation to achieve a pleasing mesio-distal dimension for both the central incisors using a zirconia-reinforced porcelain crowns. Keywords: Computed Tomography (CT), Gemination, Horizontal root fracture, Biodentine Obturation

Fracture propagation characteristics of layered shale oil reservoirs with dense laminas under cyclic pressure shock fracturing

Forming a fracture network through fracturing stimulation is significant to efficiently developing shale oil resources. However, the complex lithological characteristics and dense laminas of continental shale oil strongly shield fracture propagation. The concept of "cyclic fluid injection induces rock fatigue" was introduced into shale oil fracturing technology, and the cyclic pressure shock fracturing method was designed. The horizontal well fracturing simulation experiments used prepared shale rock samples from the Permian Lucaogou Formation shale oil reservoir outcrop in Jimusar Sag, Junggar Basin. Two pressurization states were obtained through constant injection and rapid release of accumulated high pressure, corresponding to conventional and pressure shock conditions. The characteristics of fracture propagation under different fracturing methods were analyzed by combining acoustic emission monitoring and injection pressure curve response. Research has found that the dense laminas with a certain original width near the wellbore significantly inhibit the vertical propagation of hydraulic fractures (HFs), and conventional constant-rate fracturing methods make it difficult to stimulate the reservoir effectively. Fatigue fracturing can increase the complexity of near-wellbore fractures, but the HFs still tend to be arrested by the laminas. The bottom hole pressure (BHP) is artificially increased to a value far exceeding the rock breakdown pressure near the wellbore by applying the cyclic pressure shock fracturing method. It can avoid the communication between micro-cracks and horizontal laminas during the BHP constant rate increase process and overcome the inhibition of weak layers on vertical propagation. Besides, the fracture height and number of activated laminas positively correlate with the number of cycles. When the shock pressure is about 30 MPa, the fracture height of the three cycles increases by 50% compared to a single shock. In addition, the shock pressure has a more significant effect on the fracture height, and the fracture height increases significantly with the increase of shock pressure. The shock pressure increased by about 57%, and the fracture height increased by 60%. High-pressure shock has a certain effect on the naturally weak surface of the far well, which may cause the slip of the weak surface to produce AE signals. This provides a new approach for improving fracture complexity and control volume in layered shale oil reservoirs with dense laminas.

Characterization of Adsorbed Hydrocarbons in Deposit Sands and Well Fracture in the Burgos Basin

Objective: The objective of this research is to determine the potential adsorption by the solids carried by the hydrocarbon production stream to the surface by characterization to identify its origin. Theoretical framework: In the natural gas producing wells of the Burgos Basin, there is the presence of solids in the production fluids, these can be from the reservoir or from fracture. The reservoir solids are created from the carbonates, sandstones and shales inside the well, the fracture solids are better known as props, they are mixed with the drilling fluid so that inside the well they act as packs in the fractures where the hydrocarbon can flow for extraction. In this Basin, horizontal hydraulic fracturing is used for the extraction of hydrocarbons, the solids present adsorb part of the hydrocarbons and are contaminated with them. Method: Sand samples from 4 wells were used, which were extracted with Soxhlet equipment to separate the organic content of the sand. Using ASTM (2003) and US EPA (1996) methods D5369-93 and 3540C-3541 as a reference. Subsequently, the hydrocarbon concentrate was fractionated using the method reported in the manual of soil analysis techniques of Fernández et al., (2006) who adapted the methods 3600C, 3610B and 3611B of the US EPA (1996). The analytical method consisted of reading the spectra of each fraction in a UV-Visible Shimadzu UV-1800 spectroscopy equipment and by FT-IR spectrophotometry, in a Nicolet iS10 equipment, with a DTGS KBr detector. The physical characterization of the sands was performed by recording the particle size using the API-RP56 standard. Finally, X-ray diffraction is used to determine the phases of the sands by the method 05LA-34080109-DRX-MP-01. Results and discussion: The amount of total hydrocarbon extracted from the sands was in a range of 2,975-0,060 gr. The identification of hydrocarbons extracted by Uv-Visible and FTIR showed functional groups of aliphatic, polycyclic and nitrogen compounds. The particle size of the sands was measured between 45-311 nm. And finally RX identified the type of sand to analyze, being well 1: reservoir sand, well2: fracture sand, well 3: fracture sand and well 4: reservoir sand. Implications of the research: This research presents a study on the classification of the type of sands that are being dragged to the surface with the hydrocarbon stream of well production. These are data that show a fact that occurs and gives the certainty of what happens at the bottom of the well. Originality/value: The analysis of the results allows decisions to be taken to prevent corrosion and plugging problems of surface equipment, which can cause explosions such as the one of September 19, 2012 in the PEMEX gas pipeline at the Km 19 Measuring Center in Reynosa, Tamps. Mexico.

Application of Endothermic Fluids to Lower the Breakdown Pressure of Unconventional Reservoirs: Implications for Hydraulic Fracturing.

Unconventional hydrocarbon reservoirs are challenging media to exploit and develop for energy due to very low permeability. As such, unconventional means, such as horizontal drilling and hydraulic fracturing, are typically practiced. During hydraulic fracturing, the formation breakdown pressure is of great importance and determines the fluid pumping cost. Less attention has been given to breakdown pressure reduction for a cost-effective and enhanced hydraulic fracturing operation. The objective of this study is to explore the application of thermochemical fluids to induce thermal shock with the purpose of generating microcracks and reducing the breakdown pressure in high-temperature unconventional reservoirs. For this, thermochemical fluids of an endothermic nature (reduces the temperature when mixed) and Kentucky Sandstone and Eagle Ford Shale were utilized. In particular, we investigated the effect of endothermic reactions between ammonium chloride (NH4Cl) and sodium hydroxide (NaOH) on the strength and breakdown pressure of both samples by applying multiple cycle treatments. The obtained results indicated a significant reduction in both the strength and breakdown pressure of the rocks, with Kentucky Sandstone showing a reduction of 53.07% and Eagle Ford Shale by 34.71% in breakdown pressure. This novel approach not only provides a promising alternative to traditional fracturing methods in high-temperature reservoirs but also could bring a significant reduction in fluid pumping requirements as well as the operational cost of hydraulic fracturing.

Research on Horizontal Well Multi-Fracture Propagation Law under the Synergistic Effect of Complex Natural Fracture and Reservoir Heterogeneity

Conventional fracturing design generally only considers the propagation of a single fracture in homogeneous storage, but the heterogeneity characteristics of the reservoir and the development of complex natural fractures will affect the fracturing effect. In order to study the horizontal well fracture propagation law under the synergistic effect of complex natural fracture reservoir heterogeneity, the globally embedded cohesive element finite model is established, and the heterogeneous reservoirs are built by Python programming. The influencing factors of multi-fracture propagation with heterogeneous reservoirs are analyzed, including the in situ stress difference, the injection rate of fracturing fluid, the perforation spacing, and the perforating clusters number. The results show that the heterogeneity and the natural fracture of the reservoir will affect the in situ stress distribution and propagation direction. When the in situ stress difference is low, the reservoir heterogeneity and natural fractures have a great influence on the fracture morphology. With the increase in injection rate, the fracture length and fracture width increase. With the in situ stress difference increase, the fracture deflection angle decreases. With the increase in fracturing fluid injection rate, the fracture length increases. The number of hydraulic fractures communicating with natural fractures increases with the natural fracture number and the number of perforation clusters under the synergistic effect of complex natural fracture and reservoir heterogeneity.

Expedited Treatment of a Fractured Tooth by Rebonding: A Case Report

Fractured maxillary anterior are a common occurrence when a person experiences trauma to the face. A patient sought treatment at a endodontics and prosthodontics practice after experiencing trauma to his maxillary right central incisor that resulted in a complete horizontal fracture. This case report describes a novel way to restore a fractured anterior tooth with a highly esthetic outcome that can be completed relatively easily in the clinic or in an austere environment.

Fracture behavior and mechanical properties of engineered cementitious composites exposed to long-term sulfate and chloride environments

The fracture properties of engineered cementitious composites (ECC) exposed to dry-wet cycles in sulfate and sulfate-chloride solutions were studied by three-point bending (TPB) beams at the corrosion periods of 0, 30, 90, 130, 180, 270, and 360 days. The digital image correlation (DIC) technique was used to understand the whole fracture process. The fracture toughness and fracture energy were calculated using the proposed method, and the evolution of the horizontal strain field, displacement field, and fracture process zone (FPZ) were investigated. Meanwhile, the compressive and tensile performance of the specimens at the same corrosion periods were analyzed. The results showed that (1) Compared to water immersion, the environments of sulfate and sulfate-chloride were beneficial in improving the compressive and tensile strength, and weakening the tensile ductility. (2) With increasing the corrosion time, the evolution of the unstable fracture toughness can be distinguished into three phases: a stable phase, an increasing phase, and a rapidly decreasing phase, and the initial fracture toughness followed an increasing and then decreasing trend. The fracture energy initially decreased and tended to stabilize after 130 days. (3) By using DIC technology, as the corrosion time increased, the horizontal opening displacement at the notch tip showed a decreasing trend and stabilized after 90 days generally. The fracture path determined through horizontal displacement was well matched with the macrocrack trajectory. (4) The addition of chloride ions helped to improve the mechanical properties of ECC under long-term corrosion, such as compressive strength, unstable fracture toughness, fracture energy, and opening displacement at the notch tip. Compare to concrete, ECC exhibited greater resistance to sulfate corrosion.

Geologic characteristics, exploration and production progress of shale oil and gas in the United States: An overview

We present a systematic summary of the geological characteristics, exploration and development history and current state of shale oil and gas in the United States. The hydrocarbon-rich shales in the major shale basins of the United States are mainly developed in six geological periods: Middle Ordovician, Middle–Late Devonian, Early Carboniferous (Middle–Late Mississippi), Early Permian, Late Jurassic, and Late Cretaceous (Cenomanian–Turonian). Depositional environments for these shales include intra-cratonic basins, foreland basins, and passive continental margins. Paleozoic hydrocarbon-rich shales are mainly developed in six basins, including the Appalachian Basin (Utica and Marcellus shales), Anadarko Basin (Woodford Shale), Williston Basin (Bakken Shale), Arkoma Basin (Fayetteville Shale), Fort Worth Basin (Barnett Shale), and the Wolfcamp and Leonardian Spraberry/Bone Springs shale plays of the Permian Basin. The Mesozoic hydrocarbon-rich shales are mainly developed on the margins of the Gulf of Mexico Basin (Haynesville and Eagle Ford) or in various Rocky Mountain basins (Niobrara Formation, mainly in the Denver and Powder River basins). The detailed analysis of shale plays reveals that the shales are different in facies and mineral components, and “shale reservoirs” are often not shale at all. The United States is abundant in shale oil and gas, with the in-place resources exceeding 0.246×1012 t and 290×1012 m3, respectively. Before the emergence of horizontal well hydraulic fracturing technology to kick off the “shale revolution”, the United States had experienced two decades of exploration and production practices, as well as theory and technology development. In 2007–2023, shale oil and gas production in the United States increased from approximately 11.2×104 tons of oil equivalent per day (toe/d) to over 300.0×104 toe/d. In 2017, the shale oil and gas production exceeded the conventional oil and gas production in the country. In 2023, the contribution from shale plays to the total U.S. oil and gas production remained above 60%. The development of shale oil and gas has largely been driven by improvements in drilling and completion technologies, with much of the recent effort focused on “cube development” or “co-development”. Other efforts to improve productivity and efficiency include refracturing, enhanced oil recovery, and drilling of “U-shaped” wells. Given the significant resources base and continued technological improvements, shale oil and gas production will continue to contribute significant volumes to total U.S. hydrocarbon production.

Mechanism of inter-well hydraulic fracture interference in the primary horizontal well pattern

Shale reservoirs are characterized by low porosity and low permeability and are difficult to be developed, single horizontal well fracturing has the shortcomings of low modification and insufficient fracture coverage, so multi-well fracturing is often used in the field. Primary horizontal well pattern is one of the main modes for commercialized shale oil and gas extraction, but the interwell interference existing in multi-well fracturing will affect extraction. In this paper, a 3D hydraulic fracturing model was established with the geology‒engineering integration method, and the effects of cluster spacing, fracturing sequence, fracture placement, well spacing, horizontal stress difference and natural fractures (NFs) on hydraulic fracture (HF) propagation and cumulative gas production in multi-well fracturing were investigated. The results are described as follows. Appropriately reducing the cluster spacing to 10 m can effectively reduce interwell fracture hits while obtaining higher initial production; Zipper fracturing has a significant effect on reducing interwell fracture hits. Compared with sequential fracturing, zipper fracturing increases the HF area and cumulative gas production by 4.7% and 4.2% respectively; In order to ensure production while reducing the risk of fracture hits, the well spacing was chosen to be 400m; Compared to symmetric fracture placement, the cumulative production increased by 7.0% and 9.8% for the 1/4 staggered fracture placement and 1/2 staggered fracture placement, respectively; Although more NFs can be communicated and a larger fracture area can be obtained under small stress difference conditions, but the risk of interwell and intercluster fracture hits increases; When the NF inclination is less than 80°, the fracture hits is weakened with increase of NF inclination, when the NF inclination exceeds 80°, the HF tend to pass through the NFs and the fracture hits increases; As the NF density increases, the fracture complexity near the wellbore increases and the fracture hits decreases.

The Formation and Pressure-Bearing Characteristics of Plugging Layers in Hydraulic Fracture: A Visualization Experimental Study

Summary Temporary plugging and diversion fracturing (TPDF) is an important means for improving the artificial fracture complexity in shale gas reservoirs. At present, most scholars’ studies on TPDF mainly focus on the formation conditions of the plugging layer in a horizontal fracture and the fracture propagation behavior after the plugging layer is formed. However, there is a lack of thorough study on the formation and pressure-bearing characteristics of the plugging layer in vertical fracture. For this paper, we conducted a plugging experiment using temporary plugging particles in a hydraulic fracture by use of a visualization hydraulic fracture experimental device to analyze the formation and pressure-bearing characteristics of plugging layers. The research results show that (1) when the ratio of temporary plugging particle diameter to fracture width (d/w) becomes larger, the fluid viscosity and injection rate have less influence on the formation of the plugging layer, and the concentration of temporary plugging particles required to form the plugging layer decreases. When d/w is equal to 0.45, the plugging layer has difficulty forming if the fluid viscosity is greater than 3 mPa·s or the mass concentration of temporary plugging particles is less than 20 kg/m3. If d/w is equal to 0.60, the plugging layer has difficulty forming when the concentration is less than 10 kg/m3. When d/w is equal to 0.75, a plugging layer forms when the concentration is 2.5 kg/m3, and the formation is not affected by the fluid viscosity and injection rate. (2) A smaller d/w, higher carrier fluid viscosity and injection rate, or lower temporary plugging particle concentration all lead to more pronounced fluctuation of the fracture flow channels at the location where the plugging layer is formed. (3) If the plugging layer can form, it is denser and has stronger plugging ability when the temporary plugging particle diameter is smaller and fluid viscosity and injection rate are larger. (4) Due to different lengths and d/w, the plugging layer can be divided into three types according to its morphological change characteristics after pressure-bearing: failure-unstable, locally-damaged, and stable-unchanged plugging layer. To improve the probability of forming the plugging layer with higher stability, the fluid with a viscosity of 3 mPa·s, in which is a temporary plugging particle with a d/w of 0.75, is recommended to plug the hydraulic fractures under an injection rate of 0.65 m3/min.