Journal articles on the topic '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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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Liu, Yajun, Phani Bhushan Gadde, and Mukul Mani Sharma. "Proppant Placement Using Reverse-Hybrid Fracs." SPE Production & Operations 22, no. 03 (August 1, 2007): 348–56. http://dx.doi.org/10.2118/99580-pa.
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Gracia, C., M. Baldini, and M. E. Fernández. "FLOW AND DEPOSITION OF DIFFERENT PROPPANTS CARRIED BY FLUIDS IN ASCALED VERTICAL FRACTURE." Anales AFA 33, Special Fluids (August 16, 2022): 62–65. http://dx.doi.org/10.31527/analesafa.2022.fluidos.62.
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Hydraulic fracturing is a technique used to stimulate the production of conventional and unconventional hydrocarbons, being this type of resource a strategic part of Argentina’s energy reserve. The procedure consists in injecting fluids at high pressure into the wellbore to create fractures in the formation that later act as highly conductive paths through which hydrocarbons can flow. Since releasing the pressure of fracturing fluids causes the fracture to close, proppant(granular materials) is pumped together with fracturing fluids. For that reason, the way proppant is transported and deposited into the formation determines the future conductivity of the fracture. We present experimental results on the transport and settling of particles carried by water in a narrow vertical fracture scaled from typical field conditions. We discuss some basic features of the dynamics of the settlement of the proppant dune and the final placement for different types of proppant. The effect of the chosen material on the proppant transport is significant, yielding a much deeper placement of the dune when in lower density materials are used.
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Gracia, C., M. Baldini, and M. E. Fernández. "FLOW AND DEPOSITION OF DIFFERENT PROPPANTS CARRIED BY FLUIDS IN A SCALED VERTICAL FRACTURE." Anales AFA 33, Special Fluids (August 16, 2022): 62–65. http://dx.doi.org/10.31527/analesafa.2022.33.fluidos.62.
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Hydraulic fracturing is a technique used to stimulate the production of conventional and unconventional hydrocarbons, being this type of resource is a strategic part of Argentina’s energy reserve. The procedure consists in injecting fluids at high pressure into the wellbore to create fractures in the formation that later act as highly conductive paths through which hydrocarbons can flow. Since releasing the pressure of fracturing fluids causes the fracture to close, proppant(granular materials) is pumped together with fracturing fluids. For that reason, the way proppant is transported and deposited into the formation determines the future conductivity of the fracture.We present experimental results on the transport and settling of particles carried by water in a narrow vertical fractures called from typical field conditions. We discuss some basic features of the dynamics of the settlement of the proppant dune and the final placement for different types of proppant. The effect of the chosen material on the proppant transportis significant, yielding a much deeper placement of the dune when in lower density materials are used.
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Witte, L. C., and T. Backers. "Fluid flow of various configurations in a rock-proppant-system." IOP Conference Series: Earth and Environmental Science 1124, no. 1 (January 1, 2023): 012021. http://dx.doi.org/10.1088/1755-1315/1124/1/012021.
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Abstract A high rock mass permeability is essential for developing an enhanced geothermal system and commonly achieved through the fracture conductivity. Hydraulic stimulation of fractures in combination with the use of proppants can significantly increase and maintain rock mass permeability. To investigate and quantify the effect of proppants, which are so far not commonly used to enhance deep geothermal reservoirs, on the rock mass hydraulic conductivity we performed various sets of laboratory experiments. We performed long-term creep deformation tests on a stack of rock samples with simultaneous a) fluid flow and b) acidification and fluid flow, in both cases with and without a proppant-filled fracture between the stacked rock samples. A central borehole served as fluid inlet into the lower sample of the stack. Two more boreholes in the lower sample allowed fluid flow. Sample stacks were placed in a Hoek cell at elevated confining pressures to prevent fluid flow along the sidewalls of the cylindrical sample setup. We compared the axial deformation and injection pressures between the experimental setups. The laboratory tests are part of the ZoKrateS Project, which aims at showing the feasibility of enhancing fractured carbonate rock mass by proppant placement for geothermal applications.
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Dogon, David, and Michael Golombok. "Wellbore to fracture proppant-placement-fluid rheology." Journal of Unconventional Oil and Gas Resources 14 (June 2016): 12–21. http://dx.doi.org/10.1016/j.juogr.2016.01.003.
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Zhang, Tao, Ruoyu Yang, Jianchun Guo, and Jie Zeng. "Numerical Investigation on Proppant–Water Mixture Transport in Slot under High Reynolds Number Conditions." Energies 13, no. 21 (October 29, 2020): 5665. http://dx.doi.org/10.3390/en13215665.
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Water hydraulic fracturing involves pumping low viscosity fluid and proppant mixture into the artificial fracture under a high pumping rate. In that high Reynolds number conditions (HRNCs, Re > 2000), the turbulence effect is one of the key factors affecting proppant transportation and placement. In this paper, a Eulerian multiphase model was used to simulate the proppant particle transport in a parallel slot under HRNCs. Turbulence effects in high pumping rates and frictional stress among the proppant particles were taken into consideration, and the Johnson-Jackson wall boundary conditions were used to describe the particle-wall interaction. The numerical simulation result was validated with laboratory-scale slot experiment results. The simulation results demonstrate that the pattern of the proppant bank is significantly affected by the vortex near the wellbore, and the whole proppant transport process can be divided into four stages under HRNCs. Furthermore, the proppant placement structure and the equilibrium height of proppant dune under HRNCs are comprehensively discussed by a parametrical study, including injection position, velocity, proppant density, concentration, and diameter. As the injection position changes from the lower one to the top one, the unpropped area near the entrance decrease by 7.1 times, and the equilibrium height for the primary dune increase by 5.3%. As the velocity of the slurry jet increases from 2 m/s to 5 m/s (Re = 2000–5000), the vortex becomes stronger, so the non-propped area near the inlet increase by 5.3 times, and the equilibrium height decrease by 5.2%. The change of proppant properties does not significantly change the vortex; however, the equilibrium height is affected by the high-speed flush. Thus, the conventional equilibrium height prediction correlation is not suitable for the HRNCs. Therefore, a modified bi-power law prediction correlation was proposed based on the simulation data, which can be used to accurately predict the equilibrium height of the proppant bank under HRNCs (mean deviation = 3.8%).
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Keshavarz, Alireza, Alexander Badalyan, Raymond Johnson, and Pavel Bedrikovetski. "Improving the efficiency of hydraulic fracturing treatment in CBM reservoirs by stimulating the surrounding natural fracture system." APPEA Journal 55, no. 1 (2015): 351. http://dx.doi.org/10.1071/aj14028.
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A method is proposed for enhancing the conductivity of micro-fractures and cleats around the hydraulically induced fractures in coal bed methane reservoirs. In this technique, placing ultra-fine proppant particles in natural fractures and cleats around hydraulically induced fractures at leak-off conditions keeps the coal cleats open during water-gas production, and this consequently increases the efficiency of hydraulic fracturing treatment. Experimental and mathematical studies for the stimulation of a natural cleat system around the main hydraulic fracture are conducted. In the experimental part, core flooding tests are performed to inject a flow of suspended particles inside the natural fractures of a coal sample. By placing different particle sizes and evaluating the concentration of placed particles, an experimental coefficient is found for optimum proppant placement in which the maximum permeability is achieved after proppant placement. In the mathematical modelling study, a laboratory-based mathematical model for graded proppant placement in naturally fractured rocks around a hydraulically induced fracture is proposed. Derivations of the model include an exponential form of the pressure-permeability dependence and accounts for permeability variation in the non-stimulated zone. The explicit formulae are derived for the well productivity index by including the experimentally found coefficient. Particle placement tests resulted in an almost three-times increase in coal permeability. The laboratory-based mathematical modelling, as performed for the field conditions, shows that the proposed method yields around a six-times increase in the productivity index.
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Keshavarz, Alireza, Kate Mobbs, Aditya Khanna, and Pavel Bedrikovetsky. "Stress-based mathematical model for graded proppant injection in coal bed methane reservoirs." APPEA Journal 53, no. 1 (2013): 337. http://dx.doi.org/10.1071/aj12028.
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A technology called graded proppant (propping agent) injection that consists of the injection of proppant particles, with increasing sizes and decreasing concentrations, into a naturally fractured reservoir results in deeper percolation of the particles into the natural fracture system, and thus expansion of the stimulated reservoir area. The placement of graded proppant particles keeps the fractures open, even after pressure decline due to production. There is, therefore, an enhancement in the well productivity. This proposed technology could be used to improve the productivity of CSG wells and other unconventional resources; for example, in shales, tight gas, and geothermal reservoirs. In this peer-reviewed paper, a mathematical model for well injectivity/productivity was developed for graded particle injection in a vertical well, lying at the centre of a circular drainage area. The model is based on an analytical solution of the quasi 1D problem of coupled axisymmetric fluid flow and geomechanics. Explicit analytical equations were derived for stress, and pressure and permeability distributions, as well as for the well index during injection and production. Results of previous computational fluid dynamic studies were used to determine the hydraulic resistance resulting from proppant plugging in the fractured system. An optimal stimulation radius was identified, which resulted in the highest increment in the productivity index due to the application of graded proppant injection technology. The model was subsequently used for a sensitivity analysis using field data. The results showed that the productivity index increased more than four times by the application of this technology.
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Bybee, Karen. "Propellant/Per forating Technology To Enhance Proppant Placement." Journal of Petroleum Technology 53, no. 10 (October 1, 2001): 32. http://dx.doi.org/10.2118/1001-0032-jpt.
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Wu, Chu-Hsiang, and Mukul M. Sharma. "Modeling Proppant Transport Through Perforations in a Horizontal Wellbore." SPE Journal 24, no. 04 (March 27, 2019): 1777–89. http://dx.doi.org/10.2118/179117-pa.
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Summary Proppant placement plays a crucial role in ensuring that the conductivity of fractures is maintained after a hydraulic-fracturing treatment. The process involves the transport of suspended solids in a liquid, usually a water-based fluid, from the wellbore through perforations and finally into fractures. Many studies have focused on proppant settling and transport in fractures, but relatively few studies have investigated the proppant transport process in a wellbore through perforations. This paper addresses the important issue of proppant transport through perforations using a novel numerical technique. The objective is to evaluate the efficiency of proppant transport in a perforated horizontal well under different suspension flow conditions. In this paper, proppant transport through a perforated horizontal casing is modeled using a coupling of computational fluid dynamics and the discrete element method (CFD-DEM). Reasonable agreements are found between the modeling results and published experimental data. Furthermore, the effectiveness of proppant transport through a perforation is evaluated by the particle transport efficiency (Ei), which is defined as the mass fraction of particles transported through a perforation relative to the total mass of particles in the wellbore upstream of the perforation. The effects of casing diameter, proppant size, proppant density, proppant concentration, fluid-flow rate, fluid rheology, perforation size, and perforation orientation on Ei are investigated. The simulation results show that proppant inertia strongly influences proppant transport into a perforation. The proportion of proppant that goes into a perforation is typically much different than the proportion of fluid that goes into the same perforation. This results in an increase in the proppant concentration in the slurry as the slurry flows from the heel to the toe side of a plug-and-perforate stage. Results and models presented in this paper provide directions to quantify and potentially control proppant distribution in perforation clusters in horizontal wells.
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Manchanda, Ripudaman, Shuang Zheng, Sho Hirose, and Mukul M. Sharma. "Integrating Reservoir Geomechanics with Multiple Fracture Propagation and Proppant Placement." SPE Journal 25, no. 02 (February 4, 2020): 662–91. http://dx.doi.org/10.2118/199366-pa.
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Summary This paper presents the formulation and results from a coupled finite-volume (FV)/finite-area (FA) model for simulating the propagation of multiple hydraulically driven fractures in two and three dimensions at the wellbore and pad scale. The proposed method captures realistic representations of local heterogeneities, layering, fracture turning, poroelasticity, interactions with other fractures, and proppant transport. We account for competitive fluid and proppant distribution between multiple fractures from the wellbore. Details of the model formulation and its efficient numerical implementation are provided, along with numerical studies comparing the model with both analytical solutions and field results. The results demonstrate the effectiveness of the proposed method for the comprehensive modeling of hydraulically driven fractures in three dimensions at a pad scale.
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Yi, Sophie, Chu-Hsiang Wu, and Mukul M. Sharma. "Optimization of Plug-and-Perforate Completions for Balanced Treatment Distribution and Improved Reservoir Contact." SPE Journal 25, no. 02 (October 14, 2019): 558–72. http://dx.doi.org/10.2118/194360-pa.
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Summary Heel-dominated treatment distribution among multiple perforation clusters is frequently observed in plug-and-perforate (plug-and-perf) stages, causing small propped surface areas, suboptimal production, and unexpected fracture hits. A multifracture simulator with a novel wellbore-fluid and proppant-transport model is applied to quantify treatment distribution among multiple perforation clusters in a plug-and-perf operation. A simulation base case is set up on the basis of a field treatment design with four clusters. Simulation results show that the two toe-side clusters screened out early in the treatment and the two heel-side clusters were dominant. The simulated proppant placement is consistent with distributed-acoustic-sensing observations. The impact of different perforating strategies and pumping schedules on final treatment distribution is investigated. Two criteria are defined that quantify the proppant distribution and fracture area: the weighted average (WA) and standard deviation (SD) of the final fluid and proppant distribution, as well as the hydraulic surface area (HSA) and propped surface area (PSA) of the created fractures. An optimal plug-and-perf design is defined as one that minimizes the SD of the treatment distribution among perforation clusters, and maximizes the PSA. Both perforating strategy and pumping schedule are found to affect the final treatment distribution significantly, and uniform treatment distribution is shown to create more PSA. Having fewer perforations per cluster was found to promote uniform fluid and proppant placement. Other helpful strategies include reducing the number of perforations near the heel and using small, lightweight proppant. The stress shadow effect is accounted for using the displacement discontinuity method (DDM) and was found to play a smaller role than perforation friction and proppant inertia in most cases. An automated process is developed to optimize plug-and-perf completion design with multiple decision variables using a genetic algorithm (GA). Thirteen parameters are optimized simultaneously. The optimal design solution creates an almost even treatment distribution and more than doubles the PSA compared with the base case. The multifracture model presented in this paper provides a way to quantify fluid and proppant distribution for any perforating strategy and pumping schedule, and provides more insight into the physics relevant to plug-and-perf treatment distribution. The perforation and pumping schedule recommendations presented in this paper provide directional guidance for the design of fracturing jobs with balanced treatment distribution and large PSA.
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Sotelo, Edith, Yongchae Cho, and Richard L. Gibson Jr. "Compliance estimation and multiscale seismic simulation of hydraulic fractures." Interpretation 6, no. 4 (November 1, 2018): T951—T965. http://dx.doi.org/10.1190/int-2017-0218.1.
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Hydraulic fracturing is a common stimulation technique in unconventional reservoirs to create fractures systems and allow hydrocarbon production. Proppant (granular material) is normally injected during hydraulic fracturing to keep open the fracture network and enhance hydrocarbon production performance. Proppant has a strong influence on fracture compliance and therefore will affect the characteristics of the generated seismic wavefield. To account for the effect of proppant in fracture compliance, we have developed new analytical formulations to obtain normal and tangential compliance for the case of dry and fluid-saturated fractures. We derive these expressions based on Hertz-Mindlin contact theory. Results from the compliance sensitivity analyses provide insights into the effects of proppant distribution and mechanical properties on fracture compliance. We also applied the innovative generalized multiscale finite-element method (GMsFEM) to simulate wave propagation through discrete hydraulic fractures filled with proppant. The GMsFEM approach represents individual fractures on a finely discretized mesh; this fine mesh is used to capture fracture properties by generating quantities (basis functions) that are used for modeling wave propagation on a much coarser grid. This methodology reduces the size of the computational problem, allowing faster results. Simulation results indicate the changes of the scattered wavefield as the proppant placement varies in different parts of the fractures and as the number of fracture stages increases.
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El-M. Shokir, E. M., and A. A. Al-Quraishi. "Experimental and Numerical Investigation of Proppant Placement in Hydraulic Fractures." Petroleum Science and Technology 27, no. 15 (October 21, 2009): 1690–703. http://dx.doi.org/10.1080/10916460802608768.
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Lengyel, Tamás, Attila Varga, Ferenc Safranyik, and Anita Jobbik. "Coupled Numerical Method for Modeling Propped Fracture Behavior." Applied Sciences 11, no. 20 (October 17, 2021): 9681. http://dx.doi.org/10.3390/app11209681.
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Hydraulic fracturing is a well-known production intensification technique in the petroleum industry that aims to enhance the productivity of a well drilled mostly in less permeable reservoirs. The process’s effectiveness depends on the achieved fracture conductivity, the product of fracture width, and the permeability of the proppant pack placed within the fracture. This article presents an innovative method developed by our research activity that incorporates the benefit of the Discrete—and Finite Element Method to describe the in situ behavior of hydraulic fractures with a particular emphasis on fracture conductivity. DEM (Discrete Element Method) provided the application of random particle generation and non-uniform proppant placement. We also used FEM (Finite Element Method) Static Structural module to simulate the elastic behavior of solid materials: proppant and formation, while CFD (Computational Fluid Dynamics) module was applied to represent fluid dynamics within the propped fracture. The results of our numerical model were compared to data of API RP-19D and API RP-61 laboratory measurements and findings gained by publishers dealing with propped fracture conductivity. The match of the outcomes verified the method and encouraged us to describe proppant deformation and embedment and their effect as precisely as possible. Based on the results, we performed sensitivity analysis which pointed out the impact of several factors affecting proppant embedment, deformation, and fracture conductivity and let one be aware of a reasonable interpretation of propped hydraulic fracture operation. However, DEM–CFD coupled models were introduced regarding fracturing before, to the best of our knowledge, the developed workflow of coupling DEM–FEM–CFD for modeling proppant-supported fracture behavior has not been applied yet, thus arising new perspectives for explorers and engineers.
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Zhang, Guodong, and Kun Chao. "Downward flow of proppant slurry through curving pipes during horizontal well fracturing." Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles 73 (2018): 31. http://dx.doi.org/10.2516/ogst/2018032.
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The transport of proppant-fracturing fluid mixture in a fracturing pipe can significantly affect the final proppant placement in a hydraulic fracture in horizontal well fracturing. To improve the understanding of the hydrodynamic performance of proppants in a curving fracturing pipe, a modified two-layer transport model was proposed by taking the viscoelastic properties of carrier fluid into consideration. Fluid temperature was determined by an energy equation in order to accurately characterize its rheological properties, and the Chang–Darby model was used to represent the viscosity-shear rate relationship. The flow pattern of particle-fluid mixture in a curving fracturing pipe was investigated, the effects of particle and fluid properties and injection parameters were analyzed, and a flow pattern map was established. Three transport stages are observed: (1) particles keep suspended in the carrier fluid at small inclined angle; (2) a small number of particles settle and accumulate on pipe bottom to form a particle bed load flow at intermediate inclined angle; (3) numerous particles settle out of carrier fluid and the particle bed quickly develops in an approximate horizontal pipe. The transition processes between different stages were observed, and the transition velocity from particle bed load flow to full suspension flow increases with the increase in inclined angle. However, an inverse transition phenomenon occurs at intermediate inclined angle, where the full suspension flow inversely turns into particle bed load flow with the increase in injected velocity.
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Liu, Huifeng, Pavel Bedrikovetsky, Zebo Yuan, Jv Liu, and Yuxuan Liu. "An optimized model of calculating optimal packing ratio for graded proppant placement with consideration of proppant embedment and deformation." Journal of Petroleum Science and Engineering 196 (January 2021): 107703. http://dx.doi.org/10.1016/j.petrol.2020.107703.
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Gong, Yiwen, Mohamed Mehana, Ilham El-Monier, and Hari Viswanathan. "Proppant placement in complex fracture geometries: A computational fluid dynamics study." Journal of Natural Gas Science and Engineering 79 (July 2020): 103295. http://dx.doi.org/10.1016/j.jngse.2020.103295.
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Hou, Tengfei, Shicheng Zhang, Xinfang Ma, Junjie Shao, Yunan He, Xinrun Lv, and Jingyu Han. "Experimental and theoretical study of fracture conductivity with heterogeneous proppant placement." Journal of Natural Gas Science and Engineering 37 (January 2017): 449–61. http://dx.doi.org/10.1016/j.jngse.2016.11.059.
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Fernández, Matías E., Martín Sánchez, and Luis A. Pugnaloni. "Proppant transport in a scaled vertical planar fracture: Vorticity and dune placement." Journal of Petroleum Science and Engineering 173 (February 2019): 1382–89. http://dx.doi.org/10.1016/j.petrol.2018.10.007.
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Chuprakov, Dimitry, Ilmir Bekerov, and Aliia Iuldasheva. "Productivity of hydraulic fractures with heterogeneous proppant placement and acid etched walls." Applications in Engineering Science 3 (September 2020): 100018. http://dx.doi.org/10.1016/j.apples.2020.100018.
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Qu, Hai, Rui Wang, Xiang Ao, Ling Xue, Zhonghua Liu, and Hun Lin. "The Investigation of Proppant Particle-Fluid Flow in the Vertical Fracture with a Contracted Aperture." SPE Journal 27, no. 01 (September 29, 2021): 274–91. http://dx.doi.org/10.2118/206733-pa.
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Summary Proppant placement plays a crucial role in maintaining the conductivity of fractures after a hydraulic fracturing treatment. The process involves the transport of particles by fluid flow in complex fractures. Many studies have focused on proppant transport and distribution in the fracture with a constant aperture, but relatively few studies have investigated the proppant-fluid flow in a vertical fracture with a contracted aperture. In this work, we examine experimentally proppant transport in a fracture with a contracted aperture. The objective is to evaluate the distribution of particle beds in the contracted fracture at different flow conditions. In this paper, particle-fluid flow in the contracted fracture is studied experimentally by a laboratory size slot. A planar slot with a constant width is used to benchmark the experimental results, and a published correlation validates the bed equilibrium heights in the planar slot. Six types of particles are chosen to simulate the effects of particle density and size. The proppant distribution is evaluated by the bed height when the bed reaches the equilibrium states. The effects of fluid velocity, fluid viscosity, particle density, particle size, and particle volume fraction on particle distribution are investigated. The results confirm that the proppant particle-fluid flow in the contracted slot is more complicated than that in the planar slot. The phenomena of particle vortices and resuspension were observed at the contraction of the cross-section. The shape on the top of the bed is like a descending stair in which the height gradually decreases in the length direction. The bed height in the contracted slot is lower and more irregular than that in the planar slot at the same flow conditions. Smaller sands injected at a high flow rate and fluid viscosity can form a lower bed. The trend would be reversed by using denser particles and high particle volume fraction. A reliable model expressed by four dimensionless numbers is developed by the linear regression method for predicting the bed equilibrium height. The model and experimental results provide directions to quantitatively evaluate the particle transport and distribution in a fracture with a contracted aperture.
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Aslannezhad, Masoud, Azim Kalantariasl, Zhenjiang You, Stefan Iglauer, and Alireza Keshavarz. "Micro-proppant placement in hydraulic and natural fracture stimulation in unconventional reservoirs: A review." Energy Reports 7 (November 2021): 8997–9022. http://dx.doi.org/10.1016/j.egyr.2021.11.220.
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Pokalai, Kunakorn, David Kulikowski, Raymond L. Johnson, Manouchehr Haghighi, and Dennis Cooke. "Development of a new approach for hydraulic fracturing in tight sand with pre-existing natural fractures." APPEA Journal 56, no. 1 (2016): 225. http://dx.doi.org/10.1071/aj15017.
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Hydraulic fracturing in tight gas reservoirs has been performed in the Cooper Basin for decades in reservoirs containing high stress and pre-existing natural fractures, especially near faults. The hydraulic fracture is affected by factors such as tortuosity, high entry pressures, and the rock fabric including natural fractures. These factors cause fracture plane rotation and complexities, leading to fracture disconnection or reduced proppant placement during the treatment. In this paper, rock properties are estimated for a targeted formation using well logs to create a geomechanical model. Natural fracture and stress azimuths within the interval were interpreted from borehole image logs. The image log interpretations inferred that fissures are oriented 30–60° relative to the maximum horizontal stress. Next, diagnostic fracture injection test (DFIT) data was used with the poro-elastic stress equations to predict tectonic strains. Finally, the geomechanical model was history-matched with a planar 3D hydraulic fracturing simulator, and gave more insight into fracture propagation in an environment of pre-existing natural fractures. The natural fracture azimuths and calibrated geomechanical model are input into a framework to evaluate varying scenarios that might result based on a vertical or inclined well design. A well design is proposed based on the natural fracture orientation relative to the hydraulic fracture that minimises complexity to optimise proppant placement. In addition, further models and diagnostics are proposed to aid predicting the hydraulically induced fracture geometry, its impact on gas production, and optimising wellbore trajectory to positively interact with pre-existing natural fractures.
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Seales, Maxian B., Robert Dilmore, Turgay Ertekin, and John Yilin Wang. "A Numerical Study of Factors Affecting Fracture-Fluid Cleanup and Produced Gas/Water in Marcellus Shale: Part II." SPE Journal 22, no. 02 (September 12, 2016): 596–614. http://dx.doi.org/10.2118/183632-pa.
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Summary Horizontal wells combined with successful multistage-hydraulic-fracture treatments are currently the most-established method for effectively stimulating and enabling economic development of gas-bearing organic-rich shale formations. Fracture cleanup in the stimulated reservoir volume (SRV) is critical to stimulation effectiveness and long-term well performance. However, fluid cleanup is often hampered by formation damage, and post-fracture well performance frequently falls to less than expectations. A systematic study of the factors that hinder fracture-fluid cleanup in shale formations can help optimize fracture treatments and better quantify long-term volumes of produced water and gas. Fracture-fluid cleanup is a complex process influenced by multiphase flow through porous media (relative permeability hysteresis, capillary pressure), reservoir-rock and -fluid properties, fracture-fluid properties, proppant placement, fracture-treatment parameters, and subsequent flowback and field operations. Changing SRV and fracture conductivity as production progresses further adds to the complexity of this problem. Numerical simulation is the best and most-practical approach to investigate such a complicated blend of mechanisms, parameters, their interactions, and subsequent effect on fracture-fluid cleanup and well deliverability. In this paper, a 3D, two-phase, dual-porosity model was used to investigate the effect of multiphase flow, proppant crushing, proppant diagenesis, shut-in time, reservoir-rock compaction, gas slippage, and gas desorption on fracture-fluid cleanup and well performance in Marcellus Shale. The research findings have shed light on the factors that substantially constrain efficient fracture-fluid cleanup in gas shales, and we have provided guidelines for improved fracture-treatment designs and water management.
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Gaurina-Međimurec, Nediljka, Vladislav Brkić, Matko Topolovec, and Petar Mijić. "Fracturing Fluids and Their Application in the Republic of Croatia." Applied Sciences 11, no. 6 (March 21, 2021): 2807. http://dx.doi.org/10.3390/app11062807.
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Hydraulic fracturing operations are performed to enhance well performance and to achieve economic success from improved production rates and the ultimate reserve recovery. To achieve these goals, fracturing fluid is pumped into the well at rates and pressures that result in the creation of a hydraulic fracture. Fracturing fluid selection presents the main requirement for the successful performance of hydraulic fracturing. The selected fracturing fluid should create a fracture with sufficient width and length for proppant placement and should carry the proppant from the surface to the created fracture. To accomplish all those demands, additives are added in fluids to adjust their properties. This paper describes the classification of fracturing fluids, additives for the adjustment of fluid properties and the requirements for fluid selection. Furthermore, laboratory tests of fracturing fluid, fracture stimulation design steps are presented in the paper, as well as a few examples of fracturing fluids used in Croatia with case studies and finally, hydraulic fracturing performance and post-frac well production results. The total gas production was increased by 43% and condensate production by 106% in selected wells including wellhead pressure, which allowed for a longer production well life.
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Carpenter, Chris. "Multiple Factors Reduce Costs of Downhole Proppant Delivery." Journal of Petroleum Technology 74, no. 06 (June 1, 2022): 72–74. http://dx.doi.org/10.2118/0622-0072-jpt.
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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 204153, “Reducing the Placement Cost of a Pound of Proppant Delivered Downhole,” by Jon Sochovka, SPE, Kyle George, and Howard Melcher, Liberty Oilfield Services, et al. The paper has not been peer reviewed. The shale industry has changed immensely during the last decade and is once again in rapid transition. The authors write that they are unsure about the nature of innovations to make US shale more competitive, but that they are certain that the current downturn will drive a further reduction in the total cost to lift a barrel of US shale oil to the surface ($/BO). In the complete paper, the authors discuss what components have contributed to this reduction and use several case studies, only three of which are discussed in this synopsis, to illustrate the potential for further cost reductions. Background The industry has been changing to address the issues of proppant delivery, constantly striving to find better chemical products while pumping fewer of them. First, a general desire exists to move away from more-expensive chemical-derivative guar systems to simpler low-concentration guar systems and fiction-reducer (FR) -based fluid systems. Second, both proppant-delivery and formation-treatment chemicals that are part of the fracture treatment have become more effective, fewer in number on the market, and smaller in quantity. The intended approach is to measure the individual and combined performance of these chemicals and the effect they have on physical rock and fluid parameters using a range of laboratory and field-testing tools and to compare the potential effects of these choices in the authors’ extensive production database. The elusive goal for fracturing fluids is to be composed 100% of water. In some cases, a water composition of 99.83% has been achieved. Higher rates still may be realized if pump rates for fracturing jobs continue to rise, proppant size reduces, and properties of some concentrated additives continue to improve as they have during the rapid progression to water experienced over the past 15 years of the shale revolution.
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Lee, Taeyeob, Daejin Park, Changhoon Shin, Daein Jeong, and Jonggeun Choe. "Efficient production estimation for a hydraulic fractured well considering fracture closure and proppant placement effects." Energy Exploration & Exploitation 34, no. 4 (May 15, 2016): 643–58. http://dx.doi.org/10.1177/0144598716650066.
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Fei, Yang, Kunakorn Pokalai, Ray Johnson, Mary Gonzalez, and Manouchehr Haghighi. "Experimental and simulation study of foam stability and the effects on hydraulic fracture proppant placement." Journal of Natural Gas Science and Engineering 46 (October 2017): 544–54. http://dx.doi.org/10.1016/j.jngse.2017.08.020.
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Keshavarz, Alireza, Alexander Badalyan, Themis Carageorgos, Pavel Bedrikovetsky, and Raymond Johnson. "Stimulation of coal seam permeability by micro-sized graded proppant placement using selective fluid properties." Fuel 144 (March 2015): 228–36. http://dx.doi.org/10.1016/j.fuel.2014.12.054.
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Wong, Ron CK, and Marolo C. Alfaro. "Fracturing in low-permeability soils for remediation of contaminated ground." Canadian Geotechnical Journal 38, no. 2 (April 1, 2001): 316–27. http://dx.doi.org/10.1139/t00-097.
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This paper presents a field study on hydraulic fracturing for in situ remediation of contaminated ground. Sand-propped hydraulic fractures were placed from vertical and horizontal wells at a test facility. Field excavations were conducted to expose the fractures and inspect their distribution and geometry. Fractures that were mapped by field excavation were found to be near horizontal, implying that the soil formation is overconsolidated. It was also observed that the sand "proppant" was thicker at locations where the soil layers were relatively weak or contained weak fissures. Electrical resistivity tomography (ERT) was also conducted in an attempt to map the fractures. There was no indication that fractures were being mapped by this geophysical technique. Fracture mapping based on tiltmeter data analyses conformed closely with the actual fracture placement in the vertical well but did not properly predict the actual fracture placement in the horizontal well.Key words: hydraulic fracturing, field test, low-permeability soil, electrical resistivity tomography, tiltmeters, horizontal well, vertical well.
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Mehmood, Faisal, Michael Z. Hou, Jianxing Liao, Muhammad Haris, Cheng Cao, and Jiashun Luo. "Multiphase Multicomponent Numerical Modeling for Hydraulic Fracturing with N-Heptane for Efficient Stimulation in a Tight Gas Reservoir of Germany." Energies 14, no. 11 (May 26, 2021): 3111. http://dx.doi.org/10.3390/en14113111.
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Conventionally, high-pressure water-based fluids have been injected for hydraulic stimulation of unconventional petroleum resources such as tight gas reservoirs. Apart from improving productivity, water-based frac-fluids have caused environmental and technical issues. As a result, much of the interest has shifted towards alternative frac-fluids. In this regard, n-heptane, as an alternative frac-fluid, is proposed. It necessitates the development of a multi-phase and multi-component (MM) numerical simulator for hydraulic fracturing. Therefore fracture, MM fluid flow, and proppant transport models are implemented in a thermo-hydro-mechanical (THM) coupled FLAC3D-TMVOCMP framework. After verification, the model is applied to a real field case study for optimization of wellbore x in a tight gas reservoir using n-heptane as the frac-fluid. Sensitivity analysis is carried out to investigate the effect of important parameters, such as fluid viscosity, injection rate, reservoir permeability etc., on fracture geometry with the proposed fluid. The quicker fracture closure and flowback of n-heptane compared to water-based fluid is advantageous for better proppant placement, especially in the upper half of the fracture and the early start of natural gas production in tight reservoirs. Finally, fracture designs with a minimum dimensionless conductivity of 30 are proposed.
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Wang, Haitao, Chen Chen, Yiming Yao, Jingrui Zhao, Qijun Zeng, and Cong Lu. "A Novel Experimental Study on Conductivity Evaluation of Intersected Fractures." Energies 15, no. 21 (November 2, 2022): 8170. http://dx.doi.org/10.3390/en15218170.
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Massive hydraulic fracturing (MHF) is currently the most effective technology used to create fracture networks with sufficient conductivity and maximize the stimulated reservoir volume (SRV) in tight oil and gas reservoirs. The newly initiated fracture networks during MHF usually exhibit complex fracture morphology and contain intersected fractures and fracture branches. The conductivity of these fractures plays a pivotal role in determining long-term productivity. Due to the complex geometry, it is difficult to accurately evaluate intersected fracture conductivity through traditional conductivity measurement methods and devices which are designed for a single primary fracture. Unlike previous studies where fracture conductivity was measured using two rock slabs under single-direction (vertical) loading, we establish a novel conductivity measurement apparatus that can mimic different fracture intersection scenarios under both vertical and transverse loading to facilitate the evaluation of intersected fracture conductivity. Based on this apparatus, a standard conductivity measurement framework for intersected fractures under biaxial compaction conditions is also proposed, and stable and reliable conductivity testing data are obtained. Sensitivity analyses are performed to find out the controlling factors of intersected fracture conductivity and the corresponding conductivity evolution law. Results indicate that the overall intersected fracture conductivity of intersected fractures can be divided into three stages, with closure pressure increasing, videlicet, the conductivity rapid reduction stage at low closure pressure, the conductivity slow reduction stage, and the conductivity stabilization stage. Higher proppant concentration results in higher conductivity. However, the conductivity differences among cases with different proppant concentration are relatively small at high closure pressure (conductivity stabilization stage). The more complex the fracture intersecting pattern is, the higher the conductivity would be. The experimental results can provide guidance for the design of proppant placement procedure for intersected fractures.
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Duenckel, Robert J., Terrence T. Palisch, Xiaogang Han, and Pedro Saldungaray. "Environmental Stewardship: Global Applications of a Nonradioactive Method to Identify Proppant Placement and Propped-Fracture Height." SPE Production & Operations 29, no. 04 (November 1, 2014): 231–42. http://dx.doi.org/10.2118/166251-pa.
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Keshavarz, Alireza, Alexander Badalyan, Raymond Johnson, and Pavel Bedrikovetsky. "Productivity enhancement by stimulation of natural fractures around a hydraulic fracture using micro-sized proppant placement." Journal of Natural Gas Science and Engineering 33 (July 2016): 1010–24. http://dx.doi.org/10.1016/j.jngse.2016.03.065.
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Bolintineanu, Dan S., Rekha R. Rao, Jeremy B. Lechman, Joseph A. Romero, Carlos F. Jove-Colon, Enrico C. Quintana, Stephen J. Bauer, and Mathew D. Ingraham. "Simulations of the effects of proppant placement on the conductivity and mechanical stability of hydraulic fractures." International Journal of Rock Mechanics and Mining Sciences 100 (December 2017): 188–98. http://dx.doi.org/10.1016/j.ijrmms.2017.10.014.
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Carpenter, Chris. "Field/Laboratory/Field Cycle Optimizes Fracture Placement, Well Performance." Journal of Petroleum Technology 74, no. 07 (July 1, 2022): 73–76. http://dx.doi.org/10.2118/0722-0073-jpt.
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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 204189, “8,070 Miles From the Field to the Laboratory and Back: A Pragmatic Sequencing of Laboratory- and Field-Based Fluid Testing and Quality Assurance/Quality Control—A Case History From Sichuan Region, China,” by A. Casero, SPE, A. Gomaa, and J. Ronderos, SPE, Titan Global Oil Services, et al. The paper has not been peer reviewed. This paper illustrates comprehensive laboratory efforts undertaken to evaluate different high-viscosity friction reducers (HVFRs) and crosslinked gel products, their successful field application supported by a robust and effective field quality-assurance/quality-control (QA/QC) process, and the critical importance of maintaining an effective field/laboratory/field cycle to optimize fluid design and maximize results. A successful execution of several treatments in a challenging shale play in the Sichuan region of China achieved record proppant placements and, just as importantly, demonstrated repeatability and consistency over time, which had not previously been attained. Geological Setting The Sichuan Basin in southern China is a very active unconventional play targeting the Longmaxi Shale, a high-pressure/high-temperature shallow-to-deep marine shale deposited on top of the Baota limestone during the Late Ordovician and Early Silurian ages. The highly complex subsurface geomechanical environment is considered the main root cause of widespread casing deformation and associated challenges facing hydraulic fracturing.
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Baldini, Mauro, C. Manuel Carlevaro, Luis A. Pugnaloni, and Martín Sánchez. "Numerical simulation of proppant transport in a planar fracture. A study of perforation placement and injection strategy." International Journal of Multiphase Flow 109 (December 2018): 207–18. http://dx.doi.org/10.1016/j.ijmultiphaseflow.2018.08.005.
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Tran, Tuan, M. E. Gonzalez Perdomo, Klaudia Wilk, Piotr Kasza, and Khalid Amrouch. "Performance evaluation of synthetic and natural polymers in nitrogen foam-based fracturing fluids in the Cooper Basin, South Australia." APPEA Journal 60, no. 1 (2020): 227. http://dx.doi.org/10.1071/aj19062.
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Hydraulic fracturing is a well-known stimulation technique for creating fractures in a subsurface formation to achieve profitable production rates in low-permeability reservoirs. Slickwater has been widely used as a traditional fracturing fluid. However, it has multiple disadvantages, such as high consumption of water, clay swelling and low flowback recovery. Foam, as an alternative fracturing fluid, consumes less liquid and provides additional energy. However, foam bubbles are typically unstable due to the degradation of surfactants, particularly in high temperature reservoirs, which reduces their capabilities of carrying and placing proppants into fractures. The purpose of this study is to provide general guidelines for an optimised application of polymers to improve the foam stability in high temperature reservoirs while increasing the proppant placement and water usage efficiencies. In this paper, the effects of natural hydroxypropyl guar (HPG) and synthetic polyacrylamide (PAM) polymers on the rheological properties of nitrogen foam-based fluids were examined by laboratory experiments conducted using temperatures up to 110°C. Then, a 3D hydraulic fracture propagation model was developed to study the fracturing performance of HPG-foamed and PAM-foamed fluids in the Toolachee Formation, Cooper Basin. It was found that synthetic PAM polymers were more effective than natural HPG polymers in stabilising foam viscosity under high temperature conditions. The simulation results indicate that foam-based fluids totally outperform slickwater in the field case application. This paper emphasises the significance of crosslinkers, foam quality and thermal stability on the performance of foams in high temperature environments.
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Hammond, P. "Settling and slumping in a Newtonian slurry, and implications for proppant placement during hydraulic fracturing of gas wells." International Journal of Multiphase Flow 22 (December 1996): 104. http://dx.doi.org/10.1016/s0301-9322(97)88220-1.
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