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Статті в журналах з теми "Proppant placement"
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Lu, Cong, Li Ma, Zhili Li, Fenglan Huang, Chuhao Huang, Haoren Yuan, Zhibin Tang, and Jianchun Guo. "A Novel Hydraulic Fracturing Method Based on the Coupled CFD-DEM Numerical Simulation Study." Applied Sciences 10, no. 9 (April 26, 2020): 3027. http://dx.doi.org/10.3390/app10093027.
Повний текст джерелаАнотація:
For the development of tight oil reservoirs, hydraulic fracturing employing variable fluid viscosity and proppant density is essential for addressing the problems of uneven placement of proppants in fractures and low propping efficiency. However, the influence mechanisms of fracturing fluid viscosity and proppant density on proppant transport in fractures remain unclear. Based on computational fluid dynamics (CFD) and the discrete element method (DEM), a proppant transport model with fluid–particle two-phase coupling is established in this study. In addition, a novel large-scale visual fracture simulation device was developed to realize the online visual monitoring of proppant transport, and a proppant transport experiment under the condition of variable viscosity fracturing fluid and proppant density was conducted. By comparing the experimental results and the numerical simulation results, the accuracy of the proppant transport numerical model was verified. Subsequently, through a proppant transport numerical simulation, the effects of fracturing fluid viscosity and proppant density on proppant transport were analyzed. The results show that as the viscosity of the fracturing fluid increases, the length of the “no proppant zone” at the front end of the fracture increases, and proppant particles can be transported further. When alternately injecting fracturing fluids of different viscosities, the viscosity ratio of the fracturing fluids should be adjusted between 2 and 5 to form optimal proppant placement. During the process of variable proppant density fracturing, when high-density proppant was pumped after low-density proppant, proppants of different densities laid fractures evenly and vertically. Conversely, when low-density proppant was pumped after high-density proppant, the low-density proppant could be transported farther into the fracture to form a longer sandbank. Based on the abovementioned observations, a novel hydraulic fracturing method is proposed to optimize the placement of proppants in fractures by adjusting the fracturing fluid viscosity and proppant density. This method has been successfully applied to more than 10 oil wells of the Bohai Bay Basin in Eastern China, and the average daily oil production per well increased by 7.4 t, significantly improving the functioning of fracturing. The proppant settlement and transport laws of proppant in fractures during variable viscosity and density fracturing can be efficiently revealed through a visualized proppant transport experiment and numerical simulation study. The novel fracturing method proposed in this study can significantly improve the hydraulic fracturing effect in tight oil reservoirs.
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Zhang, Zhaopeng, Shicheng Zhang, Xinfang Ma, Tiankui Guo, Wenzhe Zhang, and Yushi Zou. "Experimental and Numerical Study on Proppant Transport in a Complex Fracture System." Energies 13, no. 23 (November 28, 2020): 6290. http://dx.doi.org/10.3390/en13236290.
Повний текст джерелаАнотація:
Slickwater fracturing can create complex fracture networks in shale. A uniform proppant distribution in the network is preferred. However, proppant transport mechanism in the fracture network is still uncertain, which restricts the optimization of sand addition schemes. In this study, slot flow experiments are conducted to analyze the proppant placement in the complex fracture system. Dense discrete phase method is used to track the particle trajectories to study the transport mechanism into the branch. The effects of the pumping rate, sand ratio, sand size, and branch angle and location are discussed in detail. Results demonstrate that: (1) under a low pumping rate or coarse proppant conditions, the dune development in the branch depends on the dune geometry in the primary fracture, and a high proportion of sand can transport into the branch; (2) using a high pumping rate or fine proppants is beneficial to the uniform placement in the fracture system; (3) sand ratio dominates the proppant placement in the branch and passing-intersection fraction of a primary fracture; (4) more proppants may settle in the near-inlet and large-angle branch due to the size limit. Decreasing the pumping rate can contribute to a uniform proppant distribution in the secondary fracture. This study provides some guidance for the optimization of proppant addition scheme in the slickwater fracturing in unconventional resources.
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Liu, Guoliang, Shuang Chen, Hongxing Xu, Fujian Zhou, Hu Sun, Hui Li, Zuwen Wang, et al. "Experimental Investigation on Proppant Transport Behavior in Hydraulic Fractures of Tight Oil and Gas Reservoir." Geofluids 2022 (March 24, 2022): 1–14. http://dx.doi.org/10.1155/2022/1385922.
Повний текст джерелаАнотація:
Proppant concentration and fracture surface morphology are two significant fractures that can affect proppant transport and deposition behavior especially in tight and oil and gas reservoirs. This paper proposed a new set of similarity criteria for proppant experimental design by incorporating proppant concentration and fracture roughness. Based on the proposed criterion, proppant transport experiments in hydraulic fractures of tight oil and gas reservoirs were conducted to explore the proppant placement behavior and identify the key parameters that affected the fracture propping efficiency. Results showed that the proposed similarity criterion can be used to evaluate the onsite proppant transport behavior and optimize hydraulic fracturing parameters. Results showed that the fracture placement efficiency of LD C7 tight oil reservoir is mainly affected by sand ratio and fracturing fluid viscosity. The sand ratio in the LD C7 tight oil reservoir should not be less than 8%, and the optimal carrying fluid viscosity is 5 mPa s. The proppant placement efficiency of the SLG H8 tight gas reservoir is mainly affected by the displacement rate and frac fluid viscosity. The displacement rate of SLG H8 tight gas reservoir should not be less than 3.5 m3/min, and the optimal carrying fluid viscosity is 15 mPa s.
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Li, Haoze, Bingxiang Huang, Qingying Cheng, and Xinglong Zhao. "Optimization of proppant parameters for CBM extraction using hydrofracturing by orthogonal experimental process." Journal of Geophysics and Engineering 17, no. 3 (March 13, 2020): 493–505. http://dx.doi.org/10.1093/jge/gxaa009.
Повний текст джерелаАнотація:
Abstract Proppant placement concentration, particle size and creep time are important factors that affect the embedment of proppant into coal. Based on multistage creep, an orthogonal test is conducted, and an optimal proppant scheme for different closure stresses obtained. The results show that with increased proppant placement concentration, the number of coal fractures increases and the elastic modulus of the fracture area decreases. As the proppant particle size decreases, the plasticity of fracture-proppant assemblies increases gradually. The yield limit is highest when the particle size is 20/40 mesh. During the proppant embedding process, localization or uneven distribution of proppant results in tensile stress parallel to the fracture surface, which induces tensile fracture in the coal. In the fracture-proppant assembly areas, proppant fractures are severe and yield lines appear. As proppant concentration increases, more energy is accumulated during the proppant compaction stage, resulting in energy release producing craters and crevasses. The energy released also causes increased stress in the proppant-coal contact area and fracturing to the coal mass. The longer the creep time, the weaker the impact and the smaller is fluctuation. Moreover, we find that the orthogonal test can effectively analyze the importance of each parameter. Proppant placement concentration was found to have the highest influence on the process of proppant embedding into coal, followed by particle size and then time. Under experimental conditions, the lowest proppant-embedded value in coal samples was observed with proppant placement concentration of 2 kg m−2 and particle size of 20/40 mesh.
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Malhotra, Sahil, Eric R. Lehman, and Mukul M. Sharma. "Proppant Placement Using Alternate-Slug Fracturing." SPE Journal 19, no. 05 (March 10, 2014): 974–85. http://dx.doi.org/10.2118/163851-pa.
Повний текст джерелаАнотація:
Summary New fracturing techniques, such as hybrid fracturing (Sharma et al. 2004), reverse-hybrid fracturing (Liu et al. 2007), and channel (HiWAY) fracturing (Gillard et al. 2010), have been deployed over the past few years to effectively place proppant in fractures. The goal of these methods is to increase the conductivity in the proppant pack, providing highly conductive paths for hydrocarbons to flow from the reservoir to the wellbore. This paper presents an experimental study on proppant placement by use of a new method of fracturing, referred to as alternate-slug fracturing. The method involves an alternate injection of low-viscosity and high-viscosity fluids, with proppant carried by the low-viscosity fluid. Alternate-slug fracturing ensures a deeper placement of proppant through two primary mechanisms: (i) proppant transport in viscous fingers, formed by the low-viscosity fluid, and (ii) an increase in drag force in the polymer slug, leading to better entrainment and displacement of any proppant banks that may have formed. Both these effects lead to longer propped-fracture length and better vertical placement of proppant in the fracture. In addition, the method offers lower polymer costs, lower pumping horsepower, smaller fracture widths, better control of fluid leakoff, less risk of tip screenouts, and less gel damage compared with conventional gel fracture treatments. Experiments are conducted in simulated fractures (slot cells) with fluids of different viscosity, with proppant being carried by the low-viscosity fluid. It is shown that viscous fingers of low-viscosity fluid and viscous sweeps by the high-viscosity fluid lead to a deeper placement of proppant. Experiments are also conducted to demonstrate slickwater fracturing, hybrid fracturing, and reverse-hybrid fracturing. Comparison shows that alternate-slug fracturing leads to the deepest and most-uniform placement of proppant inside the fracture. Experiments are also conducted to study the mixing of fluids over a wide range of viscosity ratios. Data are presented to show that the finger velocities and mixing-zone velocities increase with viscosity ratio up to viscosity ratios of approximately 350. However, at higher viscosity ratios, the velocities plateau, signifying no further effect of viscosity contrast on the growth of fingers and mixing zone. The data are an integral part of design calculations for alternate-slug-fracturing treatments.
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Kim, Brice Y., I. Yucel Akkutlu, Vladimir Martysevich, and Ronald G. Dusterhoft. "Monolayer Microproppant-Placement Quality Using Split-Core-Plug Permeability Measurements Under Stress." SPE Journal 24, no. 04 (April 5, 2019): 1790–808. http://dx.doi.org/10.2118/189832-pa.
Повний текст джерелаАнотація:
Summary The stress-dependent permeabilities of split shale core plugs from Eagle Ford, Bakken, and Barnett Formation samples are investigated in the presence of microproppants. An analytical permeability model is developed for the investigation, including the interactions between the fracture walls and monolayer microproppants under stress. The model is then used to analyze a series of pressure-pulse-decay measurements of the propped shale samples in the laboratory. The analysis provides the propped-fracture permeability of the samples and predicts a parameter related to the quality of the proppant areal distribution in the fracture. The proppant-placement quality can be used as a measure of success of the delivery of proppants into microfractures and to design stimulation experiments in the laboratory.
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Wang, Junchao, Lei Wang, Jiacheng Li, Haiyang Ma, Mingwei Ma, and Chong Chen. "An Experimental Study on Multiscale Conductivity of Shale Fracturing." Journal of Physics: Conference Series 2399, no. 1 (December 1, 2022): 012023. http://dx.doi.org/10.1088/1742-6596/2399/1/012023.
Повний текст джерелаАнотація:
Abstract Volumetric fracturing is an effective way to develop shale oil. Fracturing forms a complex system of fractures of various scales that can be divided into micro-fractures, secondary fractures, and primary fractures. To improve the conductivity of multiscale fractures in volumetric fracturing of Jimsar shale oil, conductivity experiments were performed under such conditions as rough fractures without proppant placement, rough fractures with proppant placement, and straight fractures with discontinuous sanding, thereby studying the change law of fracture conductivity at various scales. According to the results, micro-fracture conductivity is largely affected by the roughness of the fracture face; placing proppants can significantly increase the conductivity of rough fractures; the conductivity under the condition of discontinuous sanding is highly sensitive to stress; fractures with discontinuous sanding of an area of 40% show the best conductivity.
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Cutler, R. A., D. O. Enniss, A. H. Jones, and S. R. Swanson. "Fracture Conductivity Comparison of Ceramic Proppants." Society of Petroleum Engineers Journal 25, no. 02 (April 1, 1985): 157–70. http://dx.doi.org/10.2118/11634-pa.
Повний текст джерелаАнотація:
Abstract Lightweight, intermediate-strength proppants have been developed that are intermediate in cost between sand and bauxite. A wide variety of proppant materials is characterized and compared in a laboratory fracture conductivity study. Consistent sample preparation, test, and data reduction procedures were practiced, which allow a relative comparison of the conductivity of various proppants at intermediate and high stresses. Specific gravity, proppants at intermediate and high stresses. Specific gravity, corrosion resistance, and crush resistance of each proppant also were determined. proppant also were determined. Fracture conductivity was measured to a laminar flow of deaerated, deionized water over a closure stress range of 6.9 to 96.5 MPa [1,000 to 14,000 psi] in 6.9-MPa [1,000-psi] increments. Testing was performed at a constant 50 degrees C [122 degrees F] temperature. Results of the testing are compared with values from the literature and analyzed to determine proppant acceptability in the intermediate and high closure stress regions. Fracture strengths for porous and solid proppants agree well with calculated values. Several oxide ceramics were found to have acceptable conductivity at closure stresses to 96.5 MPa [14,000 psi]. Resin-coated proppants have lower conductivities than uncoated, intermediate-strength oxide proppants when similar size distributions are tested. Recommendations are made for obtaining valid conductivity data for use in proppant selection and economic analyses. proppant selection and economic analyses. Introduction Massive hydraulic fracturing (MHF) is used to increase the productivity of gas wells in low-permeability reservoirs by creating deeply penetrating fractures in the producing formation surrounding the well. Traditionally, producing formation surrounding the well. Traditionally, high-purity silica sand has been pumped into the created fracture to prop it open and maintain gas permeability after completing the stimulation. The relatively low cost, abundance, sphericity, and low specific gravity of high-quality sands (e.g., Jordan, St. Peters, and Brady formation silica sands) have made sand a good proppant for most hydraulic fracturing treatments. The closure stress on the proppants increases with depth, and even for selected high-quality sands the fracture conductivity has been found to deteriorate rapidly when closure stresses exceed approximately 48 MPa [7,000 psi]. Several higher-strength proppants have been developed to withstand the increased closure stress of deeper wells. Sintered bauxite, fused zirconia, and resin-coated sands have been the most successful higher-strength proppants introduced. These proppants have improved proppants introduced. These proppants have improved crush resistance and have been used successfully in MHF treatments. The higher cost of these materials as compared to sand has been the largest single factor inhibiting their widespread use. The higher specific gravity of bauxite and zirconia proppants not only increases the volume cost differential compared to sand but also enhances proppant settling. Lower-specific-gravity proppants not only are more cost effective but also have the potential to improve proppant transport. Novotny showed the effect of proppant diameter on settling velocity in non-Newtonian fluids and concluded that proppant settling may determine the success or failure of a hydraulic fracturing treatment. By using the same proppant settling equation as Novotny, the settling velocity of 20/40 mesh proppants is calculated for four different specific gravities and shown as a function of fluid shear rate in Fig. 1. The specific gravity of bauxite is 3.65 and sand is 2.65; therefore, bauxite is 37.7 % more dense than sand. The settling velocity for bauxite, as shown in Fig. 1, however, is approximately 65 % higher than sand. Work on proppants with specific gravities lower than bauxite was initiated to improve the transport characteristics of the proppant during placement. It has been demonstrated that vertical propagation of the fracture can be limited by reducing the fracturing fluid pressure. The viscosity range of existing fracturing pressure. The viscosity range of existing fracturing fluids makes minimizing fluid viscosity a much more effective method of controlling pressure than lowering the pumping rate. A potential advantage of decreasing the pumping rate. A potential advantage of decreasing the specific gravity of the proppant is that identical proppant transport to that currently achievable can take place in lower-viscosity fluids. (Alternatively, higher volumes of proppant can be pumped in a given amount of a proppant can be pumped in a given amount of a high-viscosity fracturing fluid.) Not only are low-viscosity fluids capable of allowing better fracture control, they are also less expensive. More importantly, it recently was shown that the conductivity of a created hydraulic fracture in the Wamsutter area is about one-tenth of that predicted by laboratory conductivity tests. P. 157
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Wang, Jiehao, Amit Singh, Xinghui Liu, Margaretha Rijken, Yunhui Tan, and Sarvesh Naik. "Efficient Prediction of Proppant Placement along a Horizontal Fracturing Stage for Perforation Design Optimization." SPE Journal 27, no. 02 (January 17, 2022): 1094–108. http://dx.doi.org/10.2118/208613-pa.
Повний текст джерелаАнотація:
Summary Multistage plug and perforation (plug-n-perf) fracturing is commonly used for horizontal well completion in unconventional reservoirs. Uniform distribution of proppant across all clusters in each stage has proved to be challenging with low viscosity slickwater owing to its limited transport capability. Computational fluid dynamics (CFD) has been used to model proppant transport in wellbore to improve perforation and fracturing design for achieving uniform proppant placement. However, traditional CFD modeling of a full-scale stage is computationally expensive, which limits its applicability in the completion design optimization. A new approach was developed in this paper to efficiently predict proppant placement along a multicluster stage based on a machine learning (ML) model trained with extensive CFD modeling results. Its high computational efficiency permits quick sensitivity analyses to optimize perforation and fracturing designs. The new approach was validated against full-stage CFD modeling results as well as post-treatment field diagnostics. Sensitivity analyses show that proppant inertia effect is a key factor affecting proppant placement in heel clusters with higher slurry flow rates, allowing more proppant carried to the toe owing to its higher density in comparison with fluid. Proppant settling allows bottom perforations to accept more proppant than top perforations. This gravitational effect is not negligible near the heel at high flow rates and becomes more dominant near toe clusters where the flow rate is reduced. Near-uniform proppant placement is achievable via perforation design optimization by taking advantage of these two key mechanisms controlling proppant transport in horizontal wellbores. It is demonstrated that in-line perforating designs with all perforations having the same orientation in each cluster or the entire stage, especially with perforations at the bottom or on the side of the wellbore, improve the proppant placement uniformity. However, it is recommended that the optimum perforation design should be identified case by case depending on specific input parameters. The ML-based model developed in this study has overcome some of the limitations from existing models in the literature and is able to provide quick and yet reliable solutions to proppant placement prediction and design optimization.
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Wu, Zhiying, Chunfang Wu, and Linbo Zhou. "Experimental Study of Proppant Placement Characteristics in Curving Fractures." Energies 15, no. 19 (September 29, 2022): 7169. http://dx.doi.org/10.3390/en15197169.
Повний текст джерелаАнотація:
Proppant placement in hydraulic fractures is crucial for avoiding fracture closure and maintaining a high conductivity pathway for oil and gas flow from the reservoir. The curving fracture is the primary fracture form in formation and affects proppant–fluid flow. This work experimentally examines proppant transport and placement in narrow curving channels. Four dimensionless numbers, including the bending angle, distance ratio, Reynolds number, and Shields number, are used to analyze particle placement in curving fractures. The results indicate that non-uniform proppant placement occurs in curving fractures due to the flow direction change and induces an irregular proppant dune. The dune height and covered area are lower than that in the straight fracture. The curving pathway hinders proppant distribution and leads to a dune closer to the inlet. When the distance increases between the inlet and curving section, a large depleted zone in the curving section will be formed and hinder oil and gas flowback. The covered area has negative linear correlations with the Reynolds number and Shields numbers. Four dimensionless parameters are used to develop a model to quantitatively predict the covered area of particle dune in curving fractures.
Дисертації з теми "Proppant placement"
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Fei, Yang. "Experimental and Numerical Investigation of Nanotechnology on Foam Stability for Hydraulic Fracturing Application." Thesis, 2017. http://hdl.handle.net/2440/119242.
Повний текст джерелаАнотація:
Hydraulic fracturing is a well-known stimulation technique for creating fractures in a subsurface formation to achieve profitable production rates in a wellbore. The process involves the injection of a high-pressure fracturing fluid to induce fractures around the wellbore in a target interval enhancing oil and gas production in damaged wells or low permeability reservoirs. The pressure of injecting fracturing fluid should be high enough to overcome the subsurface in situ stresses and tensile strength of a fluid saturated porous rock, forming a tensile crack or fracture. Sand or other hard solid particles, referred to as proppant, is added in later stages of pumping. The fracturing fluid is required to have sufficient viscosity to suspend and carry the proppant deep into the created fracture system to keep the fractures open after hydraulic fracturing operation and during flowback and hydrocarbon production. Slick water or cross-linked gel is currently used as fracturing fluid in almost all hydraulic fracturing operations. Foam as an alternative fracturing fluid is attracting attention because their liquid content (water) is small, reducing the water usage and reducing damage potential to water-sensitive formations. Foam as a fracturing fluid should remain stable to be able to carry a large amount of proppant. Gas-in-water foams is generally not stable in the presence of a surfactant, particularly in high temperatures reservoirs. Previously, guar gel and synthetic polymers were used as foam stabiliser. However, the damage to the formation increases because of the presence of gelling residue. Thus, stable foam with low formation damage is a key factor for the extensive use of foam as a fracturing fluid. The principal goal of this study is to develop non-damaging and stable foam, which can transport proppant effectively. The secondary objective is to evaluate the performance and the stability of the developed foam using proppant placement efficiency (large uniform proppant distribution) and water usage efficiency (less water consumption to generate comparable or better productivity). In this study, a non-damaging and stable foam is developed using silica nanoparticles and a living polymer made of worm-like surfactant micelles. The experimental results show that foam stability increases two to three times in the presence of 0.8 wt% silica nanoparticles under 90 ℃. The enhancement of foam lifetime by nanoparticle application allows better proppant suspension, which maintains post-fracture conductivity and minimise productivity loss. The simulation results show that foam stability is directly dependent on proppant placement and fracture conductivity distribution. When foam fracturing fluids experience long closure time, foam breakage leads to proppant settling and accumulation at the bottom of the formation; which causes reduction of the propped dimension. Both a high pumping rate and high foam quality provide a large initial propped area; however, foam stability is still the major factor that controls the final propped area, and the resulting productivity. Those results are critical findings for developing a guideline for an optimized application of nano-stabilised foams in unconventional reservoirs.Thesis (Ph.D.) -- University of Adelaide, Australian School of Petroleum (ASP), 2017
Книги з теми "Proppant placement"
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Jones, Jack, and Larry K. Britt. Design and Appraisal of Hydraulic Fractures. Society of Petroleum EngineersRichardson, Texas, USA, 2009. http://dx.doi.org/10.2118/9781555631437.
Повний текст джерелаАнотація:
Using an interdisciplinary approach, Design and Appraisal of Hydraulic Fractures offers a basic yet comprehensive introduction to the completion and reservoir engineering aspects of hydraulic fracture stimulation. The book is divided into three sections. Section 1 covers the design and placement of a hydraulic fracture stimulation; topics include the basics of the hydraulic fracturing process, stress issues, fracture geometry, controls on generated length and width, fluid and proppant selection, quality control, and quality assurance. Section 2 introduces the use of dynamic data to characterize the in-place hydraulic fracture, outlining the methods of pressure-transient analysis for both pressure-drawdown and pressure-buildup tests. The discussion includes effective wellbore radius, effective fracture half-length, equivalent skin, and their relationships; simulated and field examples illustrate the basic analysis procedure and many common pitfalls. The final section covers the prediction of long-term rate performance and recoverable volumes. Three approaches are discussed: rate-decline type curves, analytical and semianalytical methods, and numerical simulation. Essential elements are given for each and illustrated with field examples. Design and Appraisal of Hydraulic Fractures is a valuable reference for all members of the geotechnical and surface engineering communities who need to understand the important issues around and the full impact of hydraulic fracture stimulation on well performance.
Частини книг з теми "Proppant placement"
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Xu, Guoqing, Xianyou Yang, Yang Shi, Yun Jiang, and Futao Li. "Experimental Study of Discontinuous Proppant Placement in Conductivity." In Springer Series in Geomechanics and Geoengineering, 1187–97. Singapore: Springer Singapore, 2018. http://dx.doi.org/10.1007/978-981-10-7560-5_109.
Повний текст джерела
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Wu, Hu, Mingxing Wang, Bo Wang, and Liyan Pan. "Study on Proppant Placement Law of Visualized Large Model Slick Water Fracturing." In Proceedings of the International Field Exploration and Development Conference 2021, 1923–32. Singapore: Springer Nature Singapore, 2022. http://dx.doi.org/10.1007/978-981-19-2149-0_178.
Повний текст джерела
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Sahai, Raki, and Rouzbeh G. Moghanloo. "Proppant placement." In Unconventional Shale Gas Development, 249–78. Elsevier, 2022. http://dx.doi.org/10.1016/b978-0-323-90185-7.00004-2.
Повний текст джерелаТези доповідей конференцій з теми "Proppant placement"
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Liu, Yajun, Phani Bhushan Gadde, and Mukul Mani Sharma. "Proppant Placement Using Reverse-Hybrid Fracs." In SPE Gas Technology Symposium. Society of Petroleum Engineers, 2006. http://dx.doi.org/10.2118/99580-ms.
Повний текст джерела
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Malhotra, Sahil, Eric R. Lehman, and Mukul M. Sharma. "Proppant Placement Using Alternate-Slug Fracturing." In SPE Hydraulic Fracturing Technology Conference. Society of Petroleum Engineers, 2013. http://dx.doi.org/10.2118/163851-ms.
Повний текст джерела
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Wang, HaiYang, Desheng Zhou, Jinze Xu, Shun Liu, Erhu Liu, Qian Gao, Xiong Liu, Minhao Guo, and Panfeng Wang. "An Optimal Design Algorithm for Proppant Placement in Slickwater Fracturing." In Abu Dhabi International Petroleum Exhibition & Conference. SPE, 2021. http://dx.doi.org/10.2118/207617-ms.
Повний текст джерелаАнотація:
Abstract Slickwater fracturing technology is one of the significant stimulation measures for the development of unconventional reservoirs. An effective proppant placement in hydraulic fractures is the key to increase the oil production of unconventional reservoirs. However, previous studies on optimizing proppant placement are mainly focused on CFD numerical simulation and related laboratory experiments, and an optimization design method that comprehensively consider multiple influencing factors has not been established. The objective of this study is to establish an optimal design algorithm for proppant placement based on the construction characteristics of slickwater fracturing combined with Back Propagation (BP) neural network. In this paper, a proppant placement simulation experimental device was built to analyze proppant placement form data. We established a BP neural network model that considers multiple influencing factors and used the proppant placement form data to train and calibrate the model, which the proppant placement form prediction model is finally obtained. Using the proppant placement form prediction model, we designed an algorithm that can quickly select the three groups of construction schemes with the best proppant-filling ratio based on the massive construction schemes. The results indicate that the prediction results of the algorithm for proppant placement form are consistent with the CFD simulation results and experimental results, and the numerical error of the balanced height and the distance between the front edge of the proppant sandbank and the fracture entrance is within 5%. After using this algorithm to optimize the design of the fracturing construction scheme for the C8 oil well in Changqing Oilfield, the stimulation performance of the C8 oil well after fracturing is 2.7 times that of the adjacent well. The optimal design algorithm for proppant placement established in this paper is an effective, accurate, and intelligent optimization algorithm. This algorithm will provide a novel method for hydraulic fracturing construction design in oilfields.
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Shelley, R. F., and J. M. McGowen. "Pump-in Test Correlation Predicts Proppant Placement." In SPE Rocky Mountain Regional Meeting. Society of Petroleum Engineers, 1986. http://dx.doi.org/10.2118/15151-ms.
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Xie, Jun, Jizhou Tang, Sijie Sun, Yuwei Li, Yi Song, Haoyong Huang, Hao Pei, and Fengshou Zhang. "Numerical Investigation of Proppant Transport and Placement Along Opened Bedding Interfaces." In SPE Western Regional Meeting. SPE, 2021. http://dx.doi.org/10.2118/200801-ms.
Повний текст джерелаАнотація:
Abstract Slurry, as a proppant-laden fluid for hydraulic fracturing, is pumped into initial perforated cracks to generate a conductive pathway for hydrocarbon movement. Recently, numerous studies have been done to investigate mechanisms of proppant transport within vertical fractures. However, the distribution of proppant during stimulation becomes much more complicated if bedding planes (BPs), natural fractures (NFs) or other discontinuities pervasively distributed throughout the formation. Thus, how to capture the transport and placement mechanisms of proppant particles in the opened BPs becomes a significant issue. In this paper, we propose a closed-form continuous proppant transport model based on the conservation of total proppant volume and sedimentation of proppant particles. This model enables to integrate with the fluid flow section of a 3-D hydro-mechanical coupled fracture propagation model and then predict the distribution of proppant velocity and slurry volume fraction within a dynamic fracture network. Stokes’ law is applied to determine the sedimentation velocity. In the fracture propagation model, rock deformation is governed by the analytical solution of penny-shaped crack to determine fracture width. Fluid flow is characterized by finite differentiation scheme and then the fluid velocity is obtained. These two parameters above are inputs for the proppant transport model and both slurry viscosity and density are updated in this step. Afterwards, both fracture width and fluid velocity would be altered in the fracture model. Analysis of the proppant distribution within crossing-shaped fracture is conducted to study mechanisms of proppant transport along opened BPs. From our numerical analysis, we find that the distribution of proppant concentration is independent with the fluid viscosity, but highly dependent on the volume fraction of pumping slurry, under a given pumping pressure. Due to the difference of viscosity and proppant volume fraction at locations of upper and lower BPs, we observe that two symmetric BPs are unevenly opened, with different channel length along BP. Moreover, the width of opened upper BP is much smaller than that of opened lower BP as a result of discrepancy of proppant sedimentation. Last but not the least, a criterion of flow bed mobilization is established for dynamically tracking the sedimentation along the BP. Then the effect of different parameters (such as proppant size, proppant density, fluid viscosity, injection rate) on proppant distribution along opened BPs is also studied. Our model fully considers the proppant transport and settlement, proppant bed formation and interaction between fracture and proppant, which helps to predict the influence of proppant during fracturing treatment. Additionally, our model is also capable of dynamically tracking the settlement of proppant along opened BPs.
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Wang, Jiacheng, and Jon Olson. "Efficient Modeling of Proppant Transport During Three-Dimensional Hydraulic Fracture Propagation." In SPE Annual Technical Conference and Exhibition. SPE, 2021. http://dx.doi.org/10.2118/206337-ms.
Повний текст джерелаАнотація:
Abstract We propose an adaptive Eulerian-Lagrangian (E-L) proppant module and couple it with our simplified three-dimensional displacement discontinuity method (S3D DDM) hydraulic fracture model. The integrated model efficiently calculates proppant transport during three-dimensional (3D) hydraulic fracture propagation in multi-layer formations. The results demonstrate that hydraulic fracture height growth mitigates the form of proppant bed, so the proppant placement is more uniform in the hydraulic fracture under a smaller stress contrast. A higher fracturing fluid viscosity improves the suspension of proppant particles and generates a fracture larger in height and width but shorter in length. Lower proppant density and particle size reduce the proppant settling and create more uniform proppant placements, while they do not affect the hydraulic fracture geometry. Moreover, a larger proppant particle size limits the accessibility of the hydraulic fracture to the proppant, so the larger proppant particles do not fill the fracture tip and edge where the fracture width is small.
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Passamaneck, R. S. "A Rapid Sequential Fracturing And Proppant Placement Method." In Low Permeability Reservoirs Symposium. Society of Petroleum Engineers, 1991. http://dx.doi.org/10.2118/21882-ms.
Повний текст джерела
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Maxwell, S. C., T. I. Urbancic, J. H. Le Calvez, K. V. Tanner, and W. D. Grant. "Passive seismic imaging of hydraulic fracture proppant placement." In SEG Technical Program Expanded Abstracts 2004. Society of Exploration Geophysicists, 2004. http://dx.doi.org/10.1190/1.1851294.
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Zhang, Min, and Maša Prodanović. "Optimizing Proppant Placement in Rough-Walled Rock Fractures." In Unconventional Resources Technology Conference. Tulsa, OK, USA: American Association of Petroleum Geologists, 2019. http://dx.doi.org/10.15530/urtec-2019-1081.
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Zhang, Min, Chu-Hsiang Wu, and Mukul Sharma. "Proppant Placement in Perforation Clusters in Deviated Wellbores." In Unconventional Resources Technology Conference. Tulsa, OK, USA: American Association of Petroleum Geologists, 2019. http://dx.doi.org/10.15530/urtec-2019-298.
Повний текст джерелаЗвіти організацій з теми "Proppant placement"
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Ingraham, Mathew Duffy, Dan Stefan Bolintineanu, Rekha R. Rao, Lisa Ann Mondy, Jeremy B. Lechman, Enrico C. Quintana, and Stephen J. Bauer. Final Report for LDRD: The Effect of Proppant Placement on Closure of Fractured Shale Gas Wells. Office of Scientific and Technical Information (OSTI), September 2016. http://dx.doi.org/10.2172/1601327.
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