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1
Papanastasiou, Panos. "Formation stability after hydraulic fracturing." International Journal for Numerical and Analytical Methods in Geomechanics 23, no. 15 (December 25, 1999): 1927–44. http://dx.doi.org/10.1002/(sici)1096-9853(19991225)23:15<1927::aid-nag41>3.0.co;2-u.
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Abass, S. Y. "STUDY OF FILTRATION OF FORMATION FLUIDSAFTER HYDRAULIC FRACTURING." Oil and Gas Studies, no. 4 (September 1, 2017): 50–54. http://dx.doi.org/10.31660/0445-0108-2017-4-50-54.
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The technology of conducting hydraulic fracturing in extracting and injection wells and the techniques of selection of wells for hydraulic fracturing in operational fund of wells of Priobskoye field had been reviewed. Based on the conducted analysis of technologies of enhanced oil recovery the necessity of conducting hydraulic fracturing in low-productivity reservoirs was proved.
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Cai, Bo, Yun Hong Ding, Yong Jun Lu, Chun Ming He, and Gui Fu Duan. "Leak-Off Coefficient Analysis in Stimulation Treatment Design." Advanced Materials Research 933 (May 2014): 202–5. http://dx.doi.org/10.4028/www.scientific.net/amr.933.202.
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Hydraulic fracturing was first used in the late 1940s and has become a common technique to enhance the production of low-permeability formations.Hydraulic fracturing treatments were pumped into permeable formations with permeable fluids. This means that as the fracturing fluid was being pumped into the formation, a certain proportion of this fluid will being lost into formation as fluid leak-off. Therefore, leak-off coefficient is the most leading parameters of fracturing fluids. The accurate understanding of leak-off coefficient of fracturing fluid is an important guidance to hydraulic fracturing industry design. In this paper, a new field method of leak-off coefficient real time analysis model was presented based on instantaneous shut-in pressure (ISIP). More than 100 wells were fractured using this method in oil field. The results show that average liquid rates of post-fracturing was 22m3/d which double improvement compared with the past treatment wells. It had an important role for hydraulic fracturing stimulation treatment design in low permeability reservoirs and was proven that the new model for hydraulic fracturing treatment is greatly improved.
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Rudko, G. I., Ye M. Staroselskyi, N. Ya Marmalevskyi, V. O. Tipusiak, and E. R. Avakian. "THE SIGNIFICANCE OF GEOLOGICAL DATA AT HYDRAULIC FRACTURING PLANNING." Мінеральні ресурси України, no. 1 (March 30, 2018): 45–47. http://dx.doi.org/10.31996/mru.2018.1.45-47.
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Scientific and methodological aspects of the development of oil and gas fields at the use of hydraulic fracturing have been considered. The causes of unsatisfactory results at hydraulic fracturing, and also factors to be taken into account when choosing a well and a bed for hydraulic fracturing have been analyzed. It has been established that geological factors (in-place permeability, skin-factor, bed formation pressure, bed formation lithology, thickness, mechanical reservoir characteristics etc.) at hydraulic fracturing planning have a main impact on the hydraulic fracturing efficiency, and the errors introduced at the study of these factors are predetermined either by the insufficient study of collecting and host properties of the bed formation, or by the insufficient study of a trap.
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Sarmadivaleh, Mohammad, and Vamegh Rasouli. "Simulation of hydraulic fracturing in tight formations." APPEA Journal 50, no. 1 (2010): 581. http://dx.doi.org/10.1071/aj09035.
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Production from tight formations is becoming a main focus around the world and particularly in Australia. Hydraulic fracturing is one of the commonly used approaches to stimulate production from tight reservoirs. A good understanding of mechanical properties of formation and the in-situ stresses is essential for a hydraulic fracturing study. In this work, using the log based approach, the mechanical properties and in-situ stresses were estimated in a tight gas formation. This data is then used as input for 2D numerical simulation of hydraulic fracturing in particle flow code (PFC). The initiation and propagation of an induced fracture was studied by increasing the rock strength to simulate a tight formation response. Thereafter, the model was divided into two zones to investigate the fracture containment capacity to simulate a fracture intersecting an interbed with formation properties being different on the two sides. The formation bond strength was increased on one side of the interbed and fracture extension was monitored. The results of both simulations showed how, by increasing formation strength equivalent to a tighter formation, the fracture extension ability reduces and the interbed containment capacity increases. The results were compared with some of the analytical models and good agreement was observed.
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Lwisa, Essa Georges. "Propellant Stimulation and Hydraulic Fracturing." International Journal for Innovation Education and Research 9, no. 6 (June 1, 2021): 80–96. http://dx.doi.org/10.31686/ijier.vol9.iss6.3149.
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The Propellant Stimulation is applied to increase the permeability of rocks; a certain quantity of explosive material is donated at the bottom of the well opposite the producing layer, which causes many cracks in the near well area. A good Propellant Stimulation process must consider the explosive material quality and quantity, and the explosion should be prevented from vertically spread so all its energy will be used to crack the rocks. The first part of this chapter explains all the above in addition to the directed explosions and its calculation in an easy way. In the second part, I explained the Hydraulic Fracturing of the reservoir rocks in details, from principal elements of the process passing through cracking fluids, proppants, preparing the wells and ending with evaluating the effectiveness and discussing the methods of hydraulic fracturing. Hydraulic fracturing is the process of pumping fluid into a wellbore at an injection rate that is too high for the formation to accept without breaking. During injection the resistance to flow in the formation increases, the pressure in the wellbore increases to a value called the break-down pressure, that is the sum of the in-situ compressive stress and the strength of the formation. Once the formation “breaks down,” a fracture is formed, and the injected fluid flows through it.
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Bulgakova, Guzel T., Andrey R. Sharifullin, and Marat R. Sitdikov. "Mathematical modeling heat and mass transfer in a vertical hydraulic fracture crack during inflation and cleaning*." Tyumen State University Herald. Physical and Mathematical Modeling. Oil, Gas, Energy 6, no. 2 (2020): 41–62. http://dx.doi.org/10.21684/2411-7978-2020-6-2-41-62.
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When designing hydraulic fracturing for high-temperature formations, it is important to know the temperature change in the fracture during the injection of fracturing fluid. The temperature profile in the hydraulic fracture is necessary to calculate the optimal composition of the fracturing fluid, which necessarily includes a crosslinker (crosslinker) and a breaker (breaker), the concentration of which is calculated by the temperature at the end of the crack. Currently, this concentration is calculated based on the maximum temperature of the formation, which can lead to a decrease in the efficiency of hydraulic fracturing, since a breaker will not completely destroy the crosslinked gel. Therefore, when a well is brought into operation after the stimulation, proppant removal may occur, reducing the effectiveness of stimulation to zero. In this regard, the optimization of the decision-making process in the design of hydraulic fracturing in terrigenous and carbonate reservoirs by calculating the optimal parameters of process fluids based on predicting heat and mass transfer processes occurring during processing is a very urgent task. A tool has been developed to improve the design efficiency of hydraulic fracturing based on mathematical modeling of temperature fields in a hydraulic fracture during its development and during the period of technological sludge. A mathematical model that describes the temperature dynamics in a hydraulic fracture taking into account fluid leakage into the formation represents the evolutionary equation of convective heat transfer with a source, which is defined as the density of the heat flux from the formation. To check the adequacy of the model of temperature dynamics in a hydraulic fracture, a model of temperature recovery in a fracture is presented with the subsequent adaptation of simulation results to actual data. Developed mathematical models can be used in hydraulic fracturing simulators.
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Song, Zhaojing, Junqian Li, Xiaoyan Li, Ketong Chen, Chengyun Wang, Peng Li, Yongbo Wei, et al. "Coupling Relationship between Lithofacies and Brittleness of the Shale Oil Reservoir: A Case Study of the Shahejie Formation in the Raoyang Sag." Geofluids 2022 (January 15, 2022): 1–17. http://dx.doi.org/10.1155/2022/2729597.
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Analyzing the characteristics of rock brittleness in low-permeability mudstone and shale (MS) formations is imperative for efficient hydraulic fracturing stimulation. Rock brittleness depends on the mineral composition, organic matter abundance, and bedding structure. Based on the MS from Shahejie Formation mineral composition (clay mineral, felsic mineral, and calcareous mineral contents), total organic content, and bedding structure (laminated, laminar, and massive), six types of lithofacies were identified: clay-rich MS, felsic-rich MS, calcareous-rich MS, clay MS, felsic MS, and calcareous MS. The quartz, feldspar, calcite, and dolomite of the Shahejie Formation are brittle minerals. Consequently, lithofacies with high felsic and calcareous mineral contents are more brittle. In addition, laminated and laminar MS are also conducive to hydraulic fracturing. Therefore, laminated, organic-rich, and calcareous-rich MS are the dominant lithofacies for hydraulic fracturing in the Shahejie Formation. The lithofacies and brittleness index were predicted by the response characteristics between mineral compositions and logging curves. The 3521–3552 m section of well B11x is dominated by calcareous-rich MS with developed laminae, representing a favorable section for hydraulic fracturing. Fragile minerals and oil are widely developed in the lower part of the lower 1st member of the Shahejie Formation (Es1L) in the southwestern part of Zhaohuangzhuang-Suning, where hydraulic fracturing can be used to increase shale oil production.
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Fattakhov, I. G., L. S. Kuleshova, R. N. Bakhtizin, V. V. Mukhametshin, and A. V. Kochetkov. "Complexing the hydraulic fracturing simulation results when hybrid acid-propant treatment performing and with the simultaneous hydraulic fracture initiation in separated intervals." SOCAR Proceedings, SI2 (December 30, 2021): 103–11. http://dx.doi.org/10.5510/ogp2021si200577.
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The purpose of the work is to substantiate and formulate the principles of data generation with multiple results of hydraulic fracturing (HF) modeling. Qualitative data for assessment, intercomparison and subsequent statistical analysis are characterized by a single numerical value for each considered hydraulic fracturing parameter. For a number of hydraulic fracturing technologies, uncertainty may arise due to obtaining several values for the parameter under consideration. The scientific novelty of the work lies in the substantiation of a new approach for evaluating the obtained data series during hydraulic fracturing modeling. A number of data can be obtained both during the formation and modeling of several hydraulic fractures, and for one fracture when calculating in different modules of the simulator. As a result, an integration technique was developed that allows forming a uniform data array regardless of the number of elements in the hydraulic fracturing modeling results. Keywords: hydraulic fracturing; acid-proppant hydraulic fracturing; hydraulic fracturing of layered rocks; hydraulic fracturing modeling; pseudo-three-dimensional fracture model; data preparation; statistical analysis.
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Piggott, A. R., and D. Elsworth. "Displacement of formation fluids by hydraulic fracturing." Géotechnique 46, no. 4 (December 1996): 671–81. http://dx.doi.org/10.1680/geot.1996.46.4.671.
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Smirnov, Nickolay, Kairui Li, Evgeniya Skryleva, Dmitriy Pestov, Anastasia Shamina, Chengzhi Qi, and Alexey Kiselev. "Mathematical Modeling of Hydraulic Fracture Formation and Cleaning Processes." Energies 15, no. 6 (March 8, 2022): 1967. http://dx.doi.org/10.3390/en15061967.
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The effectiveness of the hydraulic fracturing procedure is crucially dependent on the stage of fracture planning and design. Forecasting fracture behavior in rock formations characterized by non-uniform toughness is a serious challenge. In the present paper, a planar-3D model considering the rock’s non-uniform fracture toughness has been developed for the uneven propagation of a hydraulic fracture. The series of numerical experiments were designed to study the effect of inhomogenous fracture toughness. The results show that the fracture toughness contract significantly controls the overall direction of fracture propagation, and a combination of toughness contrast and the proportion between the pay zone and barrier zone determine the fracture profile: from almost circular with or without a pair of narrow wedges when the proportion is small to almost rectangular otherwise. This paper also discusses the process of cleaning a fracture from hydraulic fracturing fluid by oil. Using numerical modeling on the basis of the constructed mathematical model, a relationship is established between the quality of hydraulic fracture cleaning and the geometrical parameters of the fracture and the region filled with the hydraulic fracturing fluid. The results of numerical experiments show that while fracturing fluid is more viscous than oil, the length of the fracture has a greater influence on the cleaning process than the viscosity of the fracturing fluid.
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Guo, Yintong, Lei Wang, Xin Chang, Jun Zhou, and Xiaoyu Zhang. "Study on Fracture Morphological Characteristics of Refracturing for Longmaxi Shale Formation." Geofluids 2020 (March 4, 2020): 1–13. http://dx.doi.org/10.1155/2020/1628431.
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Refracturing technology has become an important means for the regeneration of old wells reconstruction. It is of great significance to understand the formation mechanism of hydraulic fracturing fracture for the design of hydraulic fracturing. In order to accurately evaluate and improve fracturing volume after refracturing, it is necessary to understand the mechanism of refracturing fracture in shale formation. In this paper, a true triaxial refracturing test method was established. A series of large-scale true triaxial fracturing experiments were carried out to characterize the refracturing fracture initiation and propagation. The results show that for shale reservoirs with weak bedding planes and natural fractures, hydraulic fracturing can not only form the main fracturing fracture, which is perpendicular to horizontal minimum principal stress, but it can also open weak bedding plane or natural fractures. The characteristics of fracturing pump curve indicated that the evolution of fracturing fractures, including initiation and propagation and communication of multiple fractures. The violent fluctuation of fracturing pump pressure curve indicates that the sample has undergone multiple fracturing fractures. The result of refracturing shows that initial fracturing fracture channels can be effectively closed by temporary plugging. The refracturing breakdown pressure is generally slightly higher than that of initial fracturing. After temporary plugging, under the influence of stress induced by the initial fracturing fracture, the propagation path of the refracturing fracture is deviated. When the new fracturing fracture communicates with the initial fracturing fracture, the original fracturing fracture can continue to expand and extend, increasing the range of the fracturing modifications. The refracturing test results was shown that for shale reservoir with simple initial fracturing fractures, the complexity fracturing fracture can be increased by refracturing after temporary plugging initial fractures. The effect of refracturing is not obvious for the reservoir with complex initial fracturing fractures. This research results can provide a reliable basis for optimizing refracturing design in shale gas reservoir.
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Novokreshchennykh, Dmitrii V., and Aleksei V. Raspopov. "WAYS OF IMPROVING THE FORMATION HYDRAULIC FRACTURING EFFECTIVENESS IN CARBONATE DEPOSITS OF FIELDS OF THE REPUBLIC OF KOMI AND NENETS AUTONOMOUS OKRUG." Вестник Пермского национального исследовательского политехнического университета. Геология. Нефтегазовое и горное дело 20, no. 2 (June 2020): 175–81. http://dx.doi.org/10.15593/2224-9923/2020.2.7.
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The study presents an overview of the formation hydraulic fracturing application in carbonate deposits of fields of the Republic of Komi and Nenets Autonomous Okrug. The formation hydraulic fracturing technology has become widely used in carbonate reservoirs since 2012, with over three hundred well jobs performed. A significant share of residual recoverable reserves in carbonate deposits needs to be withdrawn; production rates need to be increased, inter alia, by way of the formation hydraulic fracturing. In the conditions of gradual deterioration of porosity and permeability of candidate wells, maintaining a steady level of technological effectiveness of hydraulic fracturing is ensured by implementing new technologies and optimizing standard processes. The hydraulic fracturing implementation issues are inextricably connected to the main issues of oilfield developments and specific structural features of carbonate reservoirs. Taking into account the specific structural features of carbonate reservoirs and existing development issues, the main objectives of the formation hydraulic fracturing have been determined: fracture conductivity increase; horizontal and vertical sweep increase; reduction of uncontrolled leakage of fracturing fluid; reduction of fracture height in conditions of adjacent water- and gas-saturated interbeds. Presently, a number of technologies has been successfully adapted and is used at the Republic of Komi and Nenets Autonomous Okrug sites. Due to the implementation of the integral approach to selection of the hydraulic fracturing technology modifications, taking into account the existing oilfield development issues and structural peculiarities of carbonate reservoirs, the reliable effectiveness of the method has been ensured in the conditions of deteriorating candidate wells; the technology application range has been extended. The study suggests expanding the range of the existing laboratory analyses to include such aspects as determination of stress intensity factor – fracture resistance and Biot’s poroelastic parameter, study of leakage rate dynamics in regard to various fracturing fluids, depending on the reservoir properties of core samples at given gradients, determination of dependence of proppants dynamic transfer on rheological properties of fracturing fluids and their filtration rates for various degrees of fracture model opening.
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Helmi, Mia Ferian, Muhammad Zakiy Y., Dinar Kaesti, Maulida Aulia Fadhina, and Anisa Novia Risky. "Analysis of the Difference between Hydraulic Fracturing and Flow Channel Fracturing." Journal of Petroleum and Geothermal Technology 1, no. 1 (July 17, 2020): 1. http://dx.doi.org/10.31315/jpgt.v1i1.3320.
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As time goes by, there will be a decline in formation productivity, as reflected in the decline in the rate of oil production from production wells. The decline in the rate of production was caused by many things such as a decrease in reservoir pressure, also formation damage. Where damage to the formation will result in a decrease in rock permeability. The decrease in rock permeability is caused by the blockage of rock pores due to the invasion of solids and drill mud filtrate, cementing, fluid fluids or previous stimulation. Besides the small rate of oil production can also be caused by the low natural permeability of rocks. With the decreasing productivity of the formation, it is necessary to make efforts to increase the productivity of the formation again, where one of them is by the method of hydraulic fracture stimulation. In this analysis, we will discuss the difference between conventional stimulation methods and flow channel fracturing. Flow channel fracturing is a fracturing process by making a network around proppant granules to form proppant pillar, so that a path is formed for the fluid to flow more easily. What distinguishes between conventional hydraulic fracturing with flow channel fracturing is the resulting fracture form, fracturing fluid injection pattern, and the amount of proppant used.
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Advani, S. H., T. S. Lee, and R. H. Dean. "Variational Principles for Hydraulic Fracturing." Journal of Applied Mechanics 59, no. 4 (December 1, 1992): 819–26. http://dx.doi.org/10.1115/1.2894048.
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A new application of an energy rate variational principle for hydraulic fracturing processes is introduced. The formation structural, fracture mechanics, and fracture fluid flow responses are integrally coupled in this treatment. This unified principle, with various specialized forms, provides a formal framework for the study of continuum as well as discrete models. The applicability of the developed formulations is demonstrated by deriving time-explicit solutions for a penny-shaped model and comparing numerical results with corresponding responses from Lagrangian and finite element methods.
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Abass, S. Y. "ANALYSIS OF INCREASING IN WELLS PRODUCTIVITY AFTER HYDRAULIC FRACTURING." Oil and Gas Studies, no. 6 (December 1, 2017): 53–55. http://dx.doi.org/10.31660/0445-0108-2017-6-53-55.
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In the article an analysis was made of the flow characteristics of fluids at different fracture points formed as a result of hydraulic fracturing of the formation. The effect of damaged formations on the filtration properties of the formation and the behavior of fluids in the fracture and how the flow rate decreases as a result of the destroyed formation were also studied.
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Humoodi, Akram, Maha Hamoudi, and Rasan Sarbast. "Implementation of Hydraulic Fracturing Operation for a Reservoir in KRG." UKH Journal of Science and Engineering 3, no. 2 (December 27, 2019): 10–21. http://dx.doi.org/10.25079/ukhjse.v3n2y2019.pp10-21.
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This study focuses on procedures to enhance permeability and flow rate for a low permeability formation by creating a conductive path using the hydraulic fracturing model. Well data are collected from the Qamchuqa KRG oil field formation. A Fracpro simulator is used for modelling the hydraulic fracturing process in an effective way. The study focuses on an effective hydraulic fracturing design procedure and the parameters affecting the fracture design. Optimum design of fracturing is achieved by selecting the proper fracturing fluid with a suitable proppant carried in a slurry, determining the formation fracturing pressure, selection of a fracture propagation fluid, and also a good proppant injection schedule, using a high pump rate and good viscosity. Permeability and conductivity are calculated before and after applying the hydraulic fracturing. Fracture height, length, and width are calculated from the Fracpro software, among other parameters, and the production rate changes. From the results, it is observed that by using hydraulic fracturing technology, production will increase and permeability will be much higher. The original formation permeability is 2.55 md, and after treatment, the average fracture conductivity has significantly increased to 1742.3 md-ft. The results showed that average fracture width is 0.187 inch. The proppant used in this treatment has a permeability of 122581 md. The suitable fluid choice is hyper with an apparent viscosity of 227.95 cp, and the proper proppant type is Brady sand with a conductivity of 2173.41 md-ft. Fracture orientation from the Khurmala oil field in Kurdistan is vertical fractures produced at a depth of 1868 m. Fracture half-length, total fracture height, and average fracture width are 220 ft, 42 ft, and 0.47 inch, respectively. After fracturing, the maximum and average area of fracture are 33.748 and 17.248 ft2, respectively. The recommended pump hydraulic horse power is 3200 HHP, and the total required fluid is 1076.3 bbl. In this study, hydraulic fracture is designed, and then, it has been analyzed after that production is optimized.
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Zhang, Xin, and Mei Yin. "Investigation of the Hydraulic Fracture Propagation Law of Layered Rock Strata Using the Discrete-Particle Model." Geofluids 2022 (April 26, 2022): 1–16. http://dx.doi.org/10.1155/2022/8038085.
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Hydraulic fracturing is a rock structure transformation method that significantly weakens the mechanical properties of the hard roof strata. Considering the poor hydraulic fracturing effect of special structure such as composite layered rock, this paper carries out hydraulic fracturing numerical simulation experiments and compares the hydraulic fracture morphology and bedding plane interaction mode under different injection rate and injection modes. The experimental results show that the bedding plane can change the trajectory and propagation direction of hydraulic fracture. Under the low injection rate, hydraulic fracturing is conducive to open the bedding plane, but the expansion length of the main hydraulic fracture is easy to be limited. Under the high injection rate, the hydraulic fracture can extend for a long distance. But the fracture morphology tends to be slender and single, which is not conducive to the formation of fracture network. Compared with conventional hydraulic fracturing, stepped variable injection rate hydraulic fracturing can activate more bedding planes, so as to improve the effect of rock strata transformation. The experimental results are instructive in achieving effective control of composite layered rock.
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Zhang, Xin, and Mei Yin. "Investigation of the Hydraulic Fracture Propagation Law of Layered Rock Strata Using the Discrete-Particle Model." Geofluids 2022 (April 26, 2022): 1–16. http://dx.doi.org/10.1155/2022/8038085.
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Hydraulic fracturing is a rock structure transformation method that significantly weakens the mechanical properties of the hard roof strata. Considering the poor hydraulic fracturing effect of special structure such as composite layered rock, this paper carries out hydraulic fracturing numerical simulation experiments and compares the hydraulic fracture morphology and bedding plane interaction mode under different injection rate and injection modes. The experimental results show that the bedding plane can change the trajectory and propagation direction of hydraulic fracture. Under the low injection rate, hydraulic fracturing is conducive to open the bedding plane, but the expansion length of the main hydraulic fracture is easy to be limited. Under the high injection rate, the hydraulic fracture can extend for a long distance. But the fracture morphology tends to be slender and single, which is not conducive to the formation of fracture network. Compared with conventional hydraulic fracturing, stepped variable injection rate hydraulic fracturing can activate more bedding planes, so as to improve the effect of rock strata transformation. The experimental results are instructive in achieving effective control of composite layered rock.
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Zhang, Xin, and Yuqi Zhang. "Experimental and Numerical Investigation on Basic Law of Dense Linear Multihole Directional Hydraulic Fracturing." Geofluids 2021 (July 21, 2021): 1–19. http://dx.doi.org/10.1155/2021/8355737.
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Using the dense linear multihole to control the directional hydraulic fracturing is a significant technical method to realize roof control in mining engineering. By combining the large-scale true triaxial directional hydraulic fracturing experiment with the discrete element numerical simulation experiment, the basic law of dense linear holes controlling directional hydraulic fracturing was studied. The results show the following: (1) Using the dense linear holes to control directional hydraulic fracturing can effectively form directional hydraulic fractures extending along the borehole line. (2) The hydraulic fracturing simulation program is very suitable for studying the basic law of directional hydraulic fracturing. (3) The reason why the hydraulic fracture can be controlled and oriented is that firstly, due to the mutual compression between the dense holes, the maximum effective tangential tensile stress appears on the connecting line of the drilling hole, where the hydraulic fracture is easy to be initiated. Secondly, due to the effect of pore water pressure, the disturbed stress zone appears at the tip of the hydraulic fracture, and the stress concentration zone overlaps with each other to form the stress guiding strip, which controls the propagation and formation of directional hydraulic fractures. (4) The angle between the drilling line and the direction of the maximum principal stress, the in situ stress, and the hole spacing has significant effects on the directional hydraulic fracturing effect. The smaller the angle, the difference of the in situ stress, and the hole spacing, the better the directional hydraulic fracturing effect. (5) The directional effect of synchronous hydraulic fracturing is better than that of sequential hydraulic fracturing. (6) According to the multihole linear codirectional hydraulic fracturing experiments, five typical directional hydraulic fracture propagation modes are summarized.
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Wang, Jingyin, Ying Guo, Kaixun Zhang, Guangying Ren, and Jinlong Ni. "Experimental Investigation on Hydraulic Fractures in the Layered Shale Formation." Geofluids 2019 (November 29, 2019): 1–14. http://dx.doi.org/10.1155/2019/4621038.
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Multistage fracturing of horizontal wells to form a complex fracture network is an essential technology in the exploitation of shale gas. Different from the conventional reservoirs, the mechanical characteristics of shale rock have significant heterogeneity due to the existence of beddings, which makes it difficult to predict the fracture geometry in the shale reservoir. Based on the laboratory experiments, the factors that affect fracture propagation were analyzed. The experimental results revealed that the hydraulic fracture would cross the beddings under the high vertical stress difference, while it would propagate along with the bedding under the low vertical stress difference; besides, the low injection rate and viscosity of the fracturing fluid were beneficial to generate a complex fracture network. Under the high injection rate and viscosity, a planar fracture was created, while a nonplanar fracture was observed under the low injection rate and viscosity, and branch fracture was created. According to the acoustic emission events, the shear events were the main events that occurred during the hydraulic fracturing process, and the acoustic emission events could be adopted to describe the fracture network. Lastly, the supercritical carbon dioxide fracturing was more effective compared with the hydraulic fracturing because the fracture network was more complex.
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Kalinin, V. R. "FORMATION HYDRAULIC FRACTURING FLUID BASED ON CARBOXYMETHYL CELLULOSE: ITS ADVANTAGES AND LIMITATIONS, APPLICATION PROSPECTS." Oil and Gas Studies, no. 2 (May 1, 2016): 49–57. http://dx.doi.org/10.31660/0445-0108-2016-2-49-57.
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The article considers the advantages and limitations of hydraulic fracturing fluid based on carboxymethyl cellulose determined as a result of laboratory studies. As a result of testing the studied fluid manufacturing features compared with similar fracturing fluids it was determined that the fluid of interest can be effectively used as a fluid for formation hydraulic fracturing especially in low permeability reservoirs. This fluid is widely available and has a low cost. It can easily replace the foreign analogues.
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Eaton, David W., and Ryan Schultz. "Increased likelihood of induced seismicity in highly overpressured shale formations." Geophysical Journal International 214, no. 1 (May 11, 2018): 751–57. http://dx.doi.org/10.1093/gji/ggy167.
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SUMMARY Fluid-injection processes such as disposal of saltwater or hydraulic fracturing can induce earthquakes by increasing pore pressure and/or shear stress on faults. Natural processes, including transformation of organic material (kerogen) into hydrocarbon and cracking to produce gas, can similarly cause fluid overpressure. Here, we document two examples from the Western Canada Sedimentary Basin where earthquakes induced by hydraulic fracturing are strongly clustered within areas characterized by pore-pressure gradient in excess of 15 kPa m−1. Despite extensive hydraulic-fracturing activity associated with resource development, induced earthquakes are virtually absent in the Montney and Duvernay Formations elsewhere. Statistical analysis suggests a negligible probability that this spatial correlation developed by chance. This implies that, in addition to known factors such as anthropogenic pore-pressure increase and proximity to critically stressed faults, high in situ overpressure of shale formations may also represent a controlling factor for inducing earthquakes by hydraulic fracturing. On a geological timescale, natural pore-pressure generation may lead to fault-slip episodes that regulate the magnitude of formation overpressure.
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Babenkov, M. B. "Temperature of rock formation and fracturing fluid during the hydraulic fracturing process." IOP Conference Series: Earth and Environmental Science 193 (October 30, 2018): 012076. http://dx.doi.org/10.1088/1755-1315/193/1/012076.
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Zhu, Wei, Shangxu Wang, Xu Chang, Hongyu Zhai, and Hezhen Wu. "Three-Dimensional Ultrasonic Imaging and Acoustic Emission Monitoring of Hydraulic Fractures in Tight Sandstone." Applied Sciences 11, no. 19 (October 8, 2021): 9352. http://dx.doi.org/10.3390/app11199352.
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Hydraulic fracturing is an important means for the development of tight oil and gas reservoirs. Laboratory rock mechanics experiments can be used to better understand the mechanism of hydraulic fracture. Therefore, in this study we carried out hydraulic fracturing experiments on Triassic Yanchang Formation tight sandstone from the Ordos Basin, China. Sparse tomography was used to obtain ultrasonic velocity images of the sample during hydraulic fracturing. Then, combining the changes in rock mechanics parameters, acoustic emission activities, and their spatial position, we analyzed the hydraulic fracturing process of tight sandstone under high differential stress in detail. The experimental results illuminate the fracture evolution processes of hydraulic fracturing. The competition between stress-induced dilatancy and fluid flow was observed during water injection. Moreover, the results prove that the “seismic pump” mode occurs in the dry region, while the “dilation hardening” and “seismic pump” modes occur simultaneously in the partially saturated region; that is to say, the hydraulic conditions dominate the failure mode of the rock.
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Zheng, Yongxiang, Jianjun Liu, and Yun Lei. "The Propagation Behavior of Hydraulic Fracture in Rock Mass with Cemented Joints." Geofluids 2019 (June 27, 2019): 1–15. http://dx.doi.org/10.1155/2019/5406870.
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The formation of the fracture network in shale hydraulic fracturing is the key to the successful development of shale gas. In order to analyze the mechanism of hydraulic fracturing fracture propagation in cemented fractured formations, a numerical simulation about fracture behavior in cemented joints was conducted based firstly on the block discrete element. And the critical pressure of three fracture propagation modes under the intersection of hydraulic fracturing fracture and closed natural fracture is derived, and the parameter analysis is carried out by univariate analysis and the response surface method (RSM). The results show that at a low intersecting angle, hydraulic fractures will turn and move forward at the same time, forming intersecting fractures. At medium angles, the cracks only turn. At high angles, the crack will expand directly forward without turning. In conclusion, low-angle intersecting fractures are more likely to form complex fracture networks, followed by medium-angle intersecting fractures, and high-angle intersecting fractures have more difficulty in forming fracture networks. The research results have important theoretical guiding significance for the hydraulic fracturing design.
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Akaha-Tse, Homa Viola, Michael Oti, Selegha Abrakasa, and Charles Ugwu Ugwueze. "Valuation of hydraulic fracturing potentials of organic-rich shales from the Anambra basin using rock mechanical properties from wireline logs." Scientia Africana 19, no. 3 (February 24, 2021): 45–44. http://dx.doi.org/10.4314/sa.v19i3.3.
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This study was carried out to determine the rock mechanical properties relevant for hydrocarbon exploration and production by hydraulic fracturing of organic rich shale formations in Anambra basin. Shale samples and wireline logs were analysed to determine the petrophysical, elastic, strength and in-situ properties necessary for the design of a hydraulic fracturing programme for the exploitation of the shales. The results obtained indicated shale failure in shear and barreling under triaxial test conditions. The average effective porosity of 0.06 and permeability of the order of 10-1 to 101 millidarcies showed the imperative for induced fracturing to assure fluid flow. Average Young’s modulus and Poisson’s ratio of about 2.06 and 0.20 respectively imply that the rocks are favourable for the formation and propagation of fractures during hydraulic fracking. The minimum horizontal stress, which determines the direction of formation and growth of artificially induced hydraulic fractures varies from wellto-well, averaging between 6802.62 to 32790.58 psi. The order of variation of the in-situ stresses is maximum horizontal stress>vertical stress>minimum horizontal stress which implies a reverse fault fracture regime. The study predicts that the sweet spots for the exploration and development of the shale-gas are those sections of the shale formations that exhibit high Young’s modulus, low Poisson’s ratio, and high brittleness. The in-situ stresses required for artificially induced fractures which provide pore space for shale gas accumulation and expulsion are adequate. The shales possess suitable mechanical properties to fracture during hydraulic fracturing. Application of these results will enhance the potentials of the onshore Anambra basin as a reliable component in increasing Nigeria’s gas reserves, for the improvement of the nation’s economy and energy security.
Key Words: Hydraulic Fracturing, Organic-rich Shales, Rock Mechanical Properties, Petrophysical Properties, Anambra Basin
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Pei, Yuxin, Nanlin Zhang, Huaxing Zhou, Shengchuan Zhang, Wei Zhang, and Jinhong Zhang. "Simulation of multiphase flow pattern, effective distance and filling ratio in hydraulic fracture." Journal of Petroleum Exploration and Production Technology 10, no. 3 (November 23, 2019): 933–42. http://dx.doi.org/10.1007/s13202-019-00799-y.
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AbstractHydraulic fracturing is a key measure to increase production and transform oil and gas reservoirs, which plays an important role in oil and gas field development. Common hydraulic fracturing is of inevitable bottlenecks such as difficulty in sand adding, sand plugging, equipment wearing and fracturing fluid damage. To solve these problems, a new type of fracturing technology, i.e., the self-propping fracturing technology is currently under development. Technically, the principle is to inject a self-propping fracturing liquid system constituting a self-propping fracturing liquid and a channel fracturing liquid into the formation. Self-propping fracturing liquid changes from liquid to solid through phase transition under the formation temperature, replacing proppants such as ceramic particles and quartz sand to achieve the purpose of propping hydraulic fractures. The flow pattern, effective distance and filling ratio of the self-propping fracturing liquid system in the hydraulic fracture are greatly affected by the parameters such as the fluid leak-off rate, surface tension and injection velocity. In this paper, a set of mathematical models for the flow distribution of self-propping fracturing liquid system considering fluid leak-off was established to simulate the flow pattern, effective distance, as well as filling ratio under different leak-off rates, surface tensions and injection velocities. The mathematical model was verified by physical experiments, proving that the mathematical model established herein could simulate the flow of self-propping fracturing liquid systems in hydraulic fractures. In the meantime, these results have positive impacts on the research of interface distribution of liquid–liquid two-phase flow.
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Gudoshnik, E., E. Ibragimov, and K. Eremenko. "Safe Drilling Simultaneous Operation for Hydraulic Fracturing of Formation and Drilling on Multiple Well Platform." Bulletin of Science and Practice 6, no. 7 (July 15, 2020): 235–42. http://dx.doi.org/10.33619/2414-2948/56/24.
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The article discusses the specifics of conducting simultaneous hydraulic fracturing and drilling on a well pad. Describes the actions before starting work. Features of drilling and construction of wells. The causes of accidents and methods for preventing accidents and indicators during hydraulic fracturing and drilling are determined. Safety enhancements are proposed while carrying out work.
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Abass, Hazim Abass, Chris Lamei Lamei, Kaveh Amini Amini, and Tadesse Teklu Teklu. "Hydraulic Fracturing Tight Reservoirs: Rock Mechanics and Transport Phenomena." Journal of Petroleum Research and Studies 8, no. 2 (May 6, 2021): 122–43. http://dx.doi.org/10.52716/jprs.v8i2.239.
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Conventional reservoirs have been fracture stimulated using acid fracturing and proppant fracturing.Acid fracturing is performed to improve well productivity in acid-soluble formations such aslimestone, dolomite, and chalk. Hydrochloric acid is generally used to create an etched fracture,which is the main mechanism for maintaining the fracture open during the life of a well. Proppantfracturing is an alternative option that has been applied in carbonaceous and siliceous formations.There is no quantitative method to provide an answer of whether acid fracturing or proppantfracturing is an appropriate stimulation method for a given carbonate formation. How rockmechanics can be applied to decide on what method is more effective? Laboratory experiments havebeen performed to simulate acid etched to study the effect of elastic, plastic and viscoelastic rockbehavior and their effects on fracture conductivity. Comparison of acid vs. proppant fracturingconductivity in carbonate formation is presented.Fracturing low permeability reservoirs is totally different than fracturing tight formations. Thefracture geometry required in low permeability reservoirs need to be planar, conductive andpenetrating deep in the reservoir. Fracture complexity in these reservoirs is to be avoided foroptimum stimulation treatment. However, in fracturing tight formation, a complex fracture networkis desirable for better recovery. Creating multiple fractures in horizontal wells without the use ofmechanical intervention, is becoming essential especially in tight gas reservoirs. We have learnedhow to initiate hydraulic fractures into a specific direction and place as many fractures as desired inhorizontal wells but with casing and perforation. The challenge now is to initiate weak point acrossthe horizontal well such that fracturing fluid will initiate a fracture there. How rock mechanics hasbeen applied to achieve this objective? We are fracturing tight gas sand in harsh environment, atdepth more than 18000 ft, of temperature close to 400 °F, and one can figure out the extreme in-situstresses relevant to this depth.When the reservoir pressure decreases, the elastic displacement in response to the increase ineffective stress will cause natural fractures to close leading to a decline in reservoir productivity.
The matrix medium feeds the natural tensile fractures which carry the fluids to the wellbore. Thedecline in conductivity with increasing effective stress should follow a logical declining rate tosupport a given production rate. How the concept of effective stress has been applied to understandthe stress-dependent conductivity of various conductive components of a given reservoir? Rockmechanics testing of these stress sensitive reservoirs becomes vital to optimize fracturing tightformations.Economical production from tight reservoirs, including shale gas and shale oil formations, requireshorizontal well drilling and massive proppant hydraulic fracturing stimulation. The stimulationinvolves generating sufficient fractures network or stimulated reservoir volume (SRV), which isachieved by placing optimized stimulation treatments along the horizontal section of wellboresideally drilled from multi-well pads to increase the production rate and ultimate recovery. Hydraulicfracturing in naturally fractured formations is characterized by generating a fractures’ network thatshould be designed for in extremely low permeability of unconventional reservoirs. Fractures shouldextensively reach shale matrix to achieve commercial gas production. Therefore, production rate andultimate recovery depend on the size of the created SRV.The transport phenomena controlling fluid flow through tight formation is no longer sufficient to bemodeled by Darcy’s flow. Diffusion and imbibition are important transport mechanisms. The conceptof osmosis and flow through a semi-permeable membrane component are critical. Additionally,diffusion and a special case of molecular flow due to Knudson effect will be discussed. Conventionalreservoir simulation collapses when trying to simulate fluid flow through tight reservoirs. Numericalstudies on a hydraulically fractured well to simulate the dynamic processes during fracturinginjection, following well shut-in (soaking), and production are discussed.
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Hou, Bing, Zhi Chang, Weineng Fu, Yeerfulati Muhadasi, and Mian Chen. "Fracture Initiation and Propagation in a Deep Shale Gas Reservoir Subject to an Alternating-Fluid-Injection Hydraulic-Fracturing Treatment." SPE Journal 24, no. 04 (May 14, 2019): 1839–55. http://dx.doi.org/10.2118/195571-pa.
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Summary Deep shale gas reservoirs are characterized by high in-situ stresses, a high horizontal-stress difference (12 MPa), development of bedding seams and natural fractures, and stronger plasticity than shallow shale. All of these factors hinder the extension of hydraulic fractures and the formation of complex fracture networks. Conventional hydraulic-fracturing techniques (that use a single fluid, such as guar fluid or slickwater) do not account for the initiation and propagation of primary fractures and the formation of secondary fractures induced by the primary fractures. For this reason, we proposed an alternating-fluid-injection hydraulic-fracturing treatment. True triaxial hydraulic-fracturing tests were conducted on shale outcrop specimens excavated from the Shallow Silurian Longmaxi Formation to study the initiation and propagation of hydraulic fractures while the specimens were subjected to an alternating fluid injection with guar fluid and slickwater. The initiation and propagation of fractures in the specimens were monitored using an acoustic-emission (AE) system connected to a visual display. The results revealed that the guar fluid and slickwater each played a different role in hydraulic fracturing. At a high in-situ stress difference, the guar fluid tended to open the transverse fractures, whereas the slickwater tended to activate the bedding planes as a result of the temporary blocking effect of the guar fluid. On the basis of the development of fractures around the initiation point, the initiation patterns were classified into three categories: (1) transverse-fracture initiation, (2) bedding-seam initiation, and (3) natural-fracture initiation. Each of these fracture-initiation patterns had a different propagation mode. The alternating-fluid-injection treatment exploited the advantages of the two fracturing fluids to form a large complex fracture network in deep shale gas reservoirs; therefore, we concluded that this method is an efficient way to enhance the stimulated reservoir volume compared with conventional hydraulic-fracturing technologies.
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Ashena, Rahman, Fred Aminzadeh, and Amir Khoramchehr. "Production Improvement via Optimization of Hydraulic Acid Fracturing Design Parameters in a Tight Carbonate Reservoir." Energies 15, no. 5 (March 7, 2022): 1947. http://dx.doi.org/10.3390/en15051947.
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Hydraulic fracturing can be utilized to extract trapped hydrocarbon where integrated fracture networks do not exist for sufficient production. In this work, design parameters of a hydraulic acid fracturing of a tight carbonate reservoir in the Middle East were optimized. The effect of optimized hydraulic fracturing on production performance and rate was investigated. Using the petrophysical well logs, formation integrity tests, core data the Mechanical Earth Model (MEM) of the tight carbonate reservoir was created, which resulted in rock mechanical properties and in-situ stresses. The other required parameters for fracturing design were either measured or found from empirical correlations. Following a candidate selection of suitable layers for fracturing, the input parameters were loaded in GOHFER software to design and optimize the fracturing job. Finally, the production forecast was performed and compared with current conditions. The injection parameters (flow rate, total volume, and number of stages) of the fracturing fluid (composed of guar and CMHPG and polymer with 15% HCL acid) were optimized to reach optimum resultant fracture geometry. Finally, optimized injection parameters were found at the injection flow rate of 18 barrels per minute, total injection volume of 90 K-gal, and three stages of injection. Using the optimal injection parameters, the optimized fracture geometrical sizes were determined: the fracture half-length (Lf): 148 m (486 ft), fracture height (Hf) of 64 m (210 ft) and fracture width (Wf) of 0.0962 in. Finally, the effect of this stimulation method on future production performance was investigated. The well production rate showed an increase from 840 STB/Day (before fracturing) to 1270 STB/Day (post fracturing). This study contributes to the practical design and optimization of hydraulic fracturing in the tight carbonate formation of the investigated oilfield and the other potential fields in the region. The results showed that this stimulation method can efficiently improve production performance from reservoir formation.
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Kamal, Muhammad, Marwan Mohammed, Mohamed Mahmoud, and Salaheldin Elkatatny. "Development of Chelating Agent-Based Polymeric Gel System for Hydraulic Fracturing." Energies 11, no. 7 (June 26, 2018): 1663. http://dx.doi.org/10.3390/en11071663.
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Hydraulic Fracturing is considered to be one of the most important stimulation methods. Hydraulic Fracturing is carried out by inducing fractures in the formation to create conductive pathways for the flow of hydrocarbon. The pathways are kept open either by using proppant or by etching the fracture surface using acids. A typical fracturing fluid usually consists of a gelling agent (polymers), cross-linkers, buffers, clay stabilizers, gel stabilizers, biocide, surfactants, and breakers mixed with fresh water. The numerous additives are used to prevent damage resulting from such operations, or better yet, enhancing it beyond just the aim of a fracturing operation. This study introduces a new smart fracturing fluid system that can be either used for proppant fracturing (high pH) or acid fracturing (low pH) operations in sandstone formations. The fluid system consists of glutamic acid diacetic acid (GLDA) that can replace several additives, such as cross-linker, breaker, biocide, and clay stabilizer. GLDA is also a surface-active fluid that will reduce the interfacial tension eliminating the water-blockage effect. GLDA is compatible and stable with sea water, which is advantageous over the typical fracturing fluid. It is also stable in high temperature reservoirs (up to 300 °F) and it is also environmentally friendly and readily biodegradable. The new fracturing fluid formulation can withstand up to 300 °F of formation temperature and is stable for about 6 h under high shearing rates (511 s−1). The new fracturing fluid formulation breaks on its own and the delay time or the breaking time can be controlled with the concentrations of the constituents of the fluid (GLDA or polymer). Coreflooding experiments were conducted using Scioto and Berea sandstone cores to evaluate the effectiveness of the developed fluid. The flooding experiments were in reasonable conformance with the rheological properties of the developed fluid regarding the thickening and breaking time, as well as yielding high return permeability.
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Lee, Sheng-Qing, Huan-Ran Li, Xi-Hao Gu, and Xiao-Ming Tang. "Near-borehole characteristics of hydraulic fractures and fracturing-induced sonic-wave attenuation." GEOPHYSICS 84, no. 3 (May 1, 2019): D81—D87. http://dx.doi.org/10.1190/geo2018-0263.1.
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The downhole hydraulic fracturing process, besides fracturing formation rocks, generates small, secondary fractures around the borehole, allowing evaluation of the result of fracturing using borehole sonic measurements. We analyzed the near-borehole fracture network from an existing laboratory hydraulic fracturing experiment to study the fracture distribution around the borehole. The result indicates that the fracture distribution exhibits fractal characteristics. The fractal dimension is high in the near-borehole region and decreases away from borehole. Because the fractal dimension increases with fracture density, this indicates that fracturing produces a high fracture-density zone in the near-borehole region. The high concentration of the hydraulic fractures in turn can causes significant attenuation in the sonic-logging waveforms acquired after fracturing. The fracturing-induced sonic attenuation, averaged over the sonic frequency band, can be estimated using a median frequency shift method. Comparison of the attenuation of the fracturing interval with that of an unfractured interval, or with that of the same interval before fracturing allows for evaluating the result of fracturing and the fracture extension along the borehole. The application of the method is demonstrated with field-data examples and validated by comparing results from existing borehole techniques, thus offering a useful technique for evaluating the result of hydraulic fracturing using the borehole sonic-wave attenuation.
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Xu, Tianlu, Yingxian Lei, Chengmei Wu, and Yinghao Shen. "Insight into the Methods for Improving the Utilization Efficiency of Fracturing Liquid in Unconventional Reservoirs." Geofluids 2021 (November 18, 2021): 1–13. http://dx.doi.org/10.1155/2021/6438148.
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A large amount of fracturing fluid will be injected into the unconventional reservoirs during hydraulic fracturing. At present, the maximum amount of fracturing fluid injected into shale oil reaches 70000 m3 in Jimsar. The main function of fracturing fluid is to make fractures for traditional reconstruction of fracturing; for unconventional reservoirs, fracturing fluid is also used to increase formation energy by large-scale injection. It is of great significance to improve the utilization efficiency of large-scale hydraulic fracturing fluid for shale oil to increase production and recovery. In this study, the method of improving the utilization efficiency of the large-scale hydraulic fracturing fluids is explored by experiment, numerical simulation, and field test of Jimsar shale oil formation. This research shows that fracture complexity can effectively increase the contact area between the fracturing fluids and the formation. The water absorption rate of the fractured core is increased, which lays the foundation for improving the liquid utilization efficiency. Reasonably, well shutting before production ensures the pressure balance in the fractures, and the fluid pressure can be transmitted to the far end, which improves the fracture effectiveness, increases formation energy, and promotes imbibition and oil displacement. By using the additive of enhanced imbibition displacement, the displacement efficiency and the displacement amount of crude oil in the micro-nanopores can be greatly improved, and the utilization ratio of liquid can be further enhanced. The experiment adopted in the field proves that improving energy utilization efficiency has an important impact on production. This study has great guiding significance for the efficient development and practical production of unconventional reservoirs.
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Yang, Yi, and Mark D. Zoback. "The role of preexisting fractures and faults during multistage hydraulic fracturing in the Bakken Formation." Interpretation 2, no. 3 (August 1, 2014): SG25—SG39. http://dx.doi.org/10.1190/int-2013-0158.1.
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We performed an integrated study of multistage hydraulic fracture stimulation of two parallel horizontal wells in the Bakken Formation in the Williston Basin, North Dakota. There are three distinct parts of this study: development of a geomechanical model for the study area, interpretation of multiarray downhole recordings of microseismic events, and interpretation of hydraulic fracturing data in a geomechanical context. We estimated the current stress state to be characterized by an NF/SS regime, with [Formula: see text] oriented approximately [Formula: see text]. The microseismic events were recorded in six vertical observation wells during hydraulic fracturing of parallel wells X and Z with three unusual aspects. First, rather than occurring in proximity to the stages being pressurized, many of the events occurred along the length of well Y, a parallel well located between wells X and Z that had been in production for approximately [Formula: see text] years at the time X and Z were stimulated. Second, relatively few fracturing stages were associated with an elongated cloud of events trending in the direction of [Formula: see text] as was commonly observed during hydraulic fracturing. Instead, the microseismic events in a few stages appeared to trend approximately [Formula: see text], approximately 30° from the direction of [Formula: see text]. Earthquake focal plane mechanisms confirmed slip on faults with this orientation. Finally, the microseismic events were clustered at two distinct depths: one near the depth of the well being pressurized in the Middle Bakken Formation and the other approximately [Formula: see text] above in the Mission Canyon Formation. We proposed that steeply dipping N75°E striking faults with a combination of normal and strike-slip movement were being stimulated during hydraulic fracturing and provided conduits for pore pressure to be transmitted to the overlaying formations. We tested a simple geomechanical analysis to illustrate how this occurred in the context of the stress field, pore pressure, and depletion in the vicinity of well Y.
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Shen, Feng, Zhou Wu, Nan Wang, and Yong Ming Li. "The Prediction of Wellhead Pressure of Hydraulic Fracturing." Applied Mechanics and Materials 405-408 (September 2013): 3323–27. http://dx.doi.org/10.4028/www.scientific.net/amm.405-408.3323.
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The accurate prediction of wellhead pressure in process of hydraulic fracturing is a keypoint to guide the design and construction of the fracturing, and does help in choosing appropriate wellhead equipment and pipeline. This paper calculates the formation breakdown pressure by using a self-made formation stress calculation software, analyzes perforation friction and near-wellbore friction on the basis of Michael theory, eatablishes a model of wellbore friction through Darcy-Weisbach equation and the momentum interaction theory of two-phase flow, and according to the composition of wellhead pressure, makes calculation software which can also analyze the influencing factor of wellbore friction, such as delivery rate, pipe diameter, fracturing fluid density and proppant size. Finally, case analysis verifies the accuracy of the computing method.
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McLennan, J. D., H. S. Hasegawa, J. C. Roegiers, and Alan M. Jessop. "Hydraulic fracturing experiment at the University of Regina Campus." Canadian Geotechnical Journal 23, no. 4 (November 1, 1986): 548–55. http://dx.doi.org/10.1139/t86-084.
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A hydraulic fracturing stress determination was carried out during May and June, 1979, in a water well intended for the Geothermal Feasibility Project on the campus of the University of Regina, Saskatchewan. Four intervals between depths of 2062 and 2215 m were fractured successfully, one in the Winnipeg Formation (2034–2083 m), two in the Deadwood Formation (2083–2209 m), and one under the Phanerozoic sequence near the top of the Precambrian basement (2209–2215 m).Over the depth range (2062–2215 m) covered by this hydrofracture experiment, the results and inferences are as follow. Downhole breakdown pressure ranges from 42 to 45 MPa, and downhole shut-in pressure from 35 to 42 MPa. The minimum horizontal stress component, σhmin, is taken as being equal to the corresponding shut-in pressure. The vertical stress component, σv, is assumed to be essentially equal to the overburden pressure and varies from 51 to 56 MPa. Whereas σv and σhmin apparently vary smoothly across the Deadwood Formation, the maximum horizontal component, σhmax, appears to undergo a discontinuity in the upper part of the Deadwood Formation, as σHMAX varies from 40 MPa in the Winnipeg Formation to 53 MPa in the upper part of the Precambrian basement. In so far as seismotectonics is concerned, the physical implications of these measurements are that normal faulting should prevail in the Winnipeg (and overlying) formations whereas strike-slip faulting could occur in the Precambrian basement; however, the latter inference has not been firmly established. Breakdown pressure is a useful guide (upper limit) for the potential geothermal demonstration project. Key words: hydraulic fracture, fracture mechanics, faulting, stresses, in situ, breakdown, shut-in pressure, seismotectonics.
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Rodríguez-Pradilla, Germán, and David W. Eaton. "Automated Microseismic Processing and Integrated Interpretation of Induced Seismicity during a Multistage Hydraulic-Fracturing Stimulation, Alberta, Canada." Bulletin of the Seismological Society of America 110, no. 5 (August 18, 2020): 2018–30. http://dx.doi.org/10.1785/0120200082.
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ABSTRACT The development of organic-rich, low-permeability formations for hydrocarbon production requires the use of unconventional techniques such as multiwell pad drilling of horizontal wells and massive multistage hydraulic-fracturing stimulations. However, proliferation of these unconventional development methods has been linked to localized cases of fault reactivation during or shortly after hydraulic fracturing. In the Duvernay formation, located in Alberta, Canada, induced seismicity from hydraulic fracturing has occurred on nearly vertical strike-slip faults that are difficult to detect with conventional seismic exploration methods. In such cases, faults may only be discernible from seismic events with precise and accurate locations, which generally requires dense seismic monitoring arrays deployed near the stimulated wells. In this study, we introduce a new, semiautomated workflow for processing passive seismic data from a dense array and then integrate it with a 3D seismic dataset to characterize seismicity clusters related to hydraulic fracturing and pre-existing faults. The reactivated faults inferred from the distribution of the microseismic events directly overlie a system of incised, middle Devonian channels below the Duvernay formation observed in time slices extracted from the 3D seismic data. The channel system exhibits a set of lateral offsets, interpreted as ancient strike-slip fault displacements, the detection of which is further enhanced by use of a similarity attribute calculated from the 3D seismic data. Taken together, integrated interpretation of induced seismicity and 3D seismic data support a model of a regional left-lateral strike-slip fault system that was active during the middle Devonian and reactivated in a reverse sense (right-lateral strike slip) during hydraulic-fracturing operations.
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Rafikov, R. B., R. Yu Shamsutdinov, I. R. Safiullin, I. Sh Shchekaturova, and A. A. Rakhmatullin. "Comparative analysis and intensification of a formation hydraulic fracturing technologies (a formation hydraulic fracturing (FHF), gas-dynamic fracturing of a formation (GDFF) and gas-dynamic fracturing of a formation-k (GDFF-K)) when developing D0, D1 formations of Alkeevskaya area." Oilfield Engineering, no. 3 (2018): 35–39. http://dx.doi.org/10.30713/0207-2351-2018-3-35-39.
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Zhang, Lifu, Michael Tice, and Berna Hascakir. "A Laboratory Study of the Impact of Reinjecting Flowback Fluids on Formation Damage in the Marcellus Shale." SPE Journal 25, no. 02 (January 21, 2020): 788–99. http://dx.doi.org/10.2118/195336-pa.
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Summary Reuse of flowback water in hydraulic fracturing is usually used by industry to reduce consumption, transportation, and disposal cost of water. However, because of complex interactions between injected water and reservoir rocks, induced fractures may be blocked by impurities carried by flowback and mineral precipitation by water/rock interactions, which causes formation damage. Therefore, knowledge of flowback water/rock interactions is important to understand the changes within the formation and effects on hydraulic fracturing performance. This study focuses on investigating flowback water/rock interactions during hydraulic fracturing in Marcellus Shale. Simple deionized water (DI)/rock interactions and complicated flowback water/rock interactions were studied under static and dynamic conditions. In static experiments, crushed reservoir rock samples were exposed to water for 3 weeks at room condition. In the dynamic experiment, continuous water flow interacted with rock samples through the coreflooding experimental system for 3 hours at reservoir condition. Before and after experiments, rock samples were characterized to determine the change on the rock surfaces. Water samples were analyzed to estimate the particle precipitation tendency and potential to modify flow pathway. Surface elemental concentrations, mineralogy, and scanning electron microscope (SEM) images of rock samples were characterized. Ion contents, particle size, total dissolved solids (TDS), and zeta-potential in the water samples were analyzed. After flowback water/rock interaction, the surface of the rock sample shows changes in the compositions and more particle attachment. In produced water, Na, Sr, and Cl concentrations are extremely high because of flowback water contamination. Water parameters show that produced water has the highest precipitation tendency relative to all water samples. Therefore, if flowback water without any treatment is reused in hydraulic fracturing, formation damage is more likely to occur from blockage of pores. Flowback water management is becoming very important due to volumes produced in every hydraulic fracturing operation. Deep well injection is no longer a favorable option because it results in disposal of high volumes of water that cannot be used for other purposes. A second option is the reuse of waste water for fracturing purposes, which reduces freshwater use significantly. However, the impurities present in flowback water may deteriorate the fracturing job and reduce or block the hydraulic fracturing apertures. This study shows that a simple filtration process applied to the flowback water allows for reinjection of the flowback water without further complication to the water/rock interaction, and does not cause significant formation damage in the fractures.
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Tan, Jingqiang, Jun Xie, Lei Li, Qiao Lyu, Jianqiang Han, and Zhengguang Zhao. "Multifractal Analysis of Acoustic Emissions during Hydraulic Fracturing Experiments under Uniaxial Loading Conditions: A Niutitang Shale Example." Geofluids 2020 (August 10, 2020): 1–19. http://dx.doi.org/10.1155/2020/8845292.
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Fracture characterization is essential for estimating the stimulated reservoir volume and guiding subsequent hydraulic fracturing stimulations in shale reservoirs. Laboratory fracturing experiments can help provide theoretical and technical guidance for field operations. In this study, hydraulic fracturing experiments on the shale samples from Niutitang Formation in Hunan Province (China) under a uniaxial loading condition are conducted. The multifractal method is used to analyze the acoustic emission (AE) signals and characterize fracture initiation and propagation. The hydraulic fracturing process can be divided into three stages based on the characteristics of AE signals: the initial stage, the quite stage, and the fracturing stage. The multifractal analysis results showed that: (1) the value of the spectrum width, Δα, continues to increase as the energy accumulates until the fracturing stage starts; and (2) the difference in the multifractal spectrum values, Δf, reflects the relationship between small and large signal frequencies and can quantify the fracture scale, i.e., the lower the Δf, the larger the fracture scale and vice versa. The results were further verified using a time-frequency analysis of the AE signals and micro-CT scanning of the samples. This study demonstrates that the multifractal method is feasible for quantitatively characterizing hydraulic fractures and can aid field hydraulic fracturing operations.
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Mannanov, I. I., and L. I. Garipova. "OPTIMIZATION OF THE FORMATION ACID FRACTURING AT THE FACILITIES OF OJSC «TATNEFT»." Oil and Gas Studies, no. 4 (August 30, 2015): 72–76. http://dx.doi.org/10.31660/0445-0108-2015-4-72-76.
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The authors analyzed the process parameters of the formation acid hydraulic fracturing (FAHF) operations performing taking into account the additional production achieved. The analysis was based on a comparison of results of the laboratory study of the optimal rate of acid injection into the formation and actual field data on execution of the formation acid hydraulic fracturing based on interpretation of jobs execution mode schedules. The relationships between the jobs performance conditions and the results in the increase of additional production are proposed for optimization of the FAHF process.
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Cai, Bo, Yun Hong Ding, Yuan Peng Shi, and Yong Jun Lu. "Low-Damage Hydraulic Fracturing Design Technique to Exploration Wells of Erlian Basin in China." Advanced Materials Research 753-755 (August 2013): 48–52. http://dx.doi.org/10.4028/www.scientific.net/amr.753-755.48.
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In China,more and more low permeability reservoirs have become the mainly oil production potential part for the soaring consumer market. Hydraulic fracturing treatment has always been playing an important role in these low permeability reservoirs.however,some inappropricate fracturing designs and treatments may decrease the productions as a result of high damage within both formations and artifical fractures.In order to minimize reduce formation and fracture damage, we take the wells in Erlian Basin as an example to explain the low-damage hydraulic fracturing technique which had been used in many of oil fields .Through eight years step by step study and field application, a comprehensive industrialize design technology was put forward. By the application of this technique, the low-damage degree is highlighted compared to the past.As a result the performance of post-fracturing wells have remarkably improved.
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Dutta, R., C. H. H. Lee, S. Odumabo, P. Ye, S. C. C. Walker, Z. T. T. Karpyn, and L. F. F. Ayala H. "Experimental Investigation of Fracturing-Fluid Migration Caused by Spontaneous Imbibition in Fractured Low-Permeability Sands." SPE Reservoir Evaluation & Engineering 17, no. 01 (January 30, 2014): 74–81. http://dx.doi.org/10.2118/154939-pa.
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Summary During hydraulic-fracturing operations in low-permeability formations, spontaneous imbibition of fracturing fluid into the rock matrix is believed to have a significant impact on the retention of water-based fracturing fluids in the neighborhood of the induced fracture. This may affect the post-fracturing productivity of the well. However, there is lack of direct experimental and visual evidence of the extent of fluid retention, evolution of the resulting imbibing-fluid front, and how they relate to potential productivity hindrance. In this paper, laboratory experiments have been carefully designed to represent the vicinity of a hydraulic fracture. The evolution of fracturing fluid leakoff is monitored as a function of space and time by use of X-ray computed tomography (CT). The X-ray CT imaging technique allows us to map saturations at controlled time intervals to monitor the migration of fracturing fluid into the reservoir formation. It is generally expected for low-permeability formations (5 to 10 md) to show strong capillary forces because of their small characteristic pore radii, but this driving mechanism is in competition with the low permeability and spatial heterogeneities found in low-permeability sands. The relevance of capillarity as a driver of fluid migration and retention in a low-permeability sand sample is interpreted visually and quantified and compared with high-permeability Berea sandstone in our experiments. It is seen that although low-permeability sands are subject to strong capillary forces, the effect can be suppressed by the low permeability of the formation and the heterogeneous nature of the sample. Nevertheless, saturation values attained as a result of spontaneous imbibition are comparable with those obtained for high-permeability samples. Leakoff of fracturing fluids during the shut-in period of a well can result in delayed gas flowback and can hinder gas production. Results from this investigation are expected to provide fundamental insight regarding critical variables affecting the retention and migration of water-based fracturing fluids in the neighborhood of hydraulic fractures, and consequently affecting the post-fracturing productivity of the well.
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Panikarovski, V. V., E. V. Panikarovski, and S. K. Sohoshko. "USE OF FORMATION HYDRAULIC FRACTURING FOR OIL RECOVERY ENHANCEMENT." Oil and Gas Studies, no. 4 (August 30, 2015): 76–80. http://dx.doi.org/10.31660/0445-0108-2015-4-76-80.
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The article briefly reviews the conduction of jobs aimed at intensification of influx and improvement of oil recovery of the layer VK in the field Krasnoleninskoye. The analysis is made of FHF technology to select the wells for FHF implementation in the development well stock under operation in the Em-Yogov area of the said field. Based on the structure of residual reserves a decision was made about the necessity to perform FHF in the low productive reservoirs.
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Barkovsky, N. N., A. M. Amirov, D. V. Beloglazov, and M. V. Shmakov. "Laboratory modeling of cracks after a formation hydraulic fracturing." Geology, Geophysics and Development of Oil and Gas Fields, no. 7 (2018): 36–40. http://dx.doi.org/10.30713/2413-5011-2018-7-36-40.
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Aleksandrov, Vadim, Marsel Kadyrov, Andrey Ponomarev, Denis Drugov, and Irina Bulgakova. "Microseismic Multistage Formation Hydraulic Fracturing (MFHF) Monitoring Analysis Results." Key Engineering Materials 785 (October 2018): 107–17. http://dx.doi.org/10.4028/www.scientific.net/kem.785.107.
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Microseismic monitoring of hydrocarbon fields is one of the promising areas of modern seismology. In recent years, the methodology of microseismic monitoring for seismic emission has been actively developing in the oil and gas industry in order to study the impact of various technogenic processes on the hydrocarbon (HC) fields being developed. The technology does not require powerful sources of sounding signals, but uses constantly existing weak seismic fields of artificial or natural origin. During the development of the field, periodic monitoring of the intensity and spatial position of the zones of microseismic activity allows controling the behavior of HC deposits in order to optimize their development. Distinctive features of this technology are high mobility, fast deployment time, high resolution, and low cost of receiving, transferring and processing of microseismic data. The purpose was to analyze the results and evaluate the effectiveness of MFHF using microseismic monitoring of seismic emission processes. The results were obtained with the help of quantitative microseismic monitoring of seismic foci occurring successively near the well ports at different times during MFHF.
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Sarris, E., and P. Papanastasiou. "Modeling of Hydraulic Fracturing in a Poroelastic Cohesive Formation." International Journal of Geomechanics 12, no. 2 (April 2012): 160–67. http://dx.doi.org/10.1061/(asce)gm.1943-5622.0000121.
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Abousleiman, Y., A. H. D. Cheng, and H. Gu. "Formation Permeability Determination by Micro or Mini-Hydraulic Fracturing." Journal of Energy Resources Technology 116, no. 2 (June 1, 1994): 104–14. http://dx.doi.org/10.1115/1.2906014.
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This paper presents a theory and its application for post-fracture pressure-transient analyses. The proposed procedure, known as “impulse fracture test,” is an injection/falloff test designed for the determination of formation permeability and reservoir pressure. The hydraulically induced fracture can pass the near wellbore damaged zone and expose a larger formation area to flow. The permeability and reservoir pressure determined are therefore more representative of the reservoir. The theory is based on the distribution of sources with variable intensity along the fracture trajectory. For field applications, asymptotic solutions are derived to give the “type-curve” capability for the estimation of formation permeability and reservoir pressure. Assorted slope behaviors, such as −1, −2, +1/2 and +1 slopes, are predicted from various pressure and pressure derivative plots. Analyses of data from two wells which were inadvertently fractured support these behaviors.