Articles de revues : « Fracturing fluids »

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Ovchinnikov, V. P., D. S. Gerasimov, P. V. Ovchinnikov, Ya M. Kurbanov et A. F. Semenenko. « ANALYSIS OF THE EFFICIENCY OF USING BIOPOLYMERS FOR HYDRAULIC FRACTURING FLUIDS ». Oil and Gas Studies, n^o 3 (1 juillet 2017) : 76–80. http://dx.doi.org/10.31660/0445-0108-2017-3-76-80.

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Hydraulic fracturingis the most appropriate technological method of stimulating reservoir fluid inflow into the well bore. The efficiency of this method is determined by the properties of disperse and dispersion media. The article gives analysis of various types of fracturing fluids and shows promising applications of biopolymer dispersion media. The authors proposed a composition of fracturing fluids with a biopolymer and destructor.

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Wilk, Klaudia. « Experimental and Simulation Studies of Energized Fracturing Fluid Efficiency in Tight Gas Formations ». Energies 12, n^o 23 (23 novembre 2019) : 4465. http://dx.doi.org/10.3390/en12234465.

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The use of water-based fracturing fluids during fracturing treatment can be a problem in water-sensitive formations due to the permeability damage hazard caused by clay minerals swelling. The article includes laboratory tests, analyses and simulations for nitrogen foamed fracturing fluids. The rheology and filtration coefficients of foamed fracturing fluids were examined and compared to the properties of conventional water-based fracturing fluid. Laboratory results provided the input for numerical simulation of the fractures geometry for water-based fracturing fluids and 50% N2 foamed fluids, with addition of natural, fast hydrating guar gum. The results show that the foamed fluids were able to create shorter and thinner fractures compared to the fractures induced by the non-foamed fluid. The simulation proved that the concentration of proppant in the fracture and its conductivity are similar or slightly higher when using the foamed fluid. The foamed fluids, when injected to the reservoir, provide additional energy that allows for more effective flowback, and maintain the proper fracture geometry and proppant placing. The results of laboratory work in combination with the 3D simulation showed that the foamed fluids have suitable viscosity which allows opening the fracture, and transport the proppant into the fracture, providing successful fracturing operation. The analysis of laboratory data and the performed computer simulations indicated that fracturing fluids foamed by nitrogen are a good alternative to non-foamed fluids. The N2-foamed fluids exhibit good rheological parameters and proppant-carrying capacity. Simulated fracture of water-based fracturing fluid is slightly longer and higher compared to foamed fluid. At the same time, when using a fluid with a gas additive, the water content in fracturing fluid is reduced which means the minimization of the negative results of the clay minerals swelling.

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Wang, Yi Dan, et Hong Fu Fan. « Research on and Application of Clean Fracturing Fluids in Coal-Bed Methane ». Advanced Materials Research 1092-1093 (mars 2015) : 212–15. http://dx.doi.org/10.4028/www.scientific.net/amr.1092-1093.212.

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The development history of fracturing fluids is reviewed, the compositions and action mechanisms of the clean fracturing fluid systems used currently are analyzed, the recent research and application of the clean fracturing fluids in coal—bed methane production are summarized, and the development trend of clean fracturing fluids is presented in this paper.

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Chen, Hai Hui, Hong Fu Fan, Jian Ping Guo, Meng Tang et Fei Ni. « Evaluation and Prediction of Coalbed Gas Fracturing Fluid ». Advanced Materials Research 1008-1009 (août 2014) : 257–63. http://dx.doi.org/10.4028/www.scientific.net/amr.1008-1009.257.

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There is a wide variety of coalbed gas fracturing fluids. It’s important that choose suitable fracturing fluids for different kinds of formations. We summed up the advantages and disadvantages of each type of fracturing fluid by analyzing and comparing different types of fracturing fluid, and produced a performance comparison table between each type. Pointed out that the existing problems and solutions of fracturing fluid in coalbed and envisaged the future trends.

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Zheng, Shuang, et Mukul M. Sharma. « Modeling Hydraulic Fracturing Using Natural Gas Foam as Fracturing Fluids ». Energies 14, n^o 22 (16 novembre 2021) : 7645. http://dx.doi.org/10.3390/en14227645.

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Stranded gas emission from the field production because of the limitations in the pipeline infrastructure has become one of the major contributors to the greenhouse effects. How to handle the stranded gas is a troublesome problem under the background of global “net-zero” emission efforts. On the other hand, the cost of water for hydraulic fracturing is high and water is not accessible in some areas. The idea of using stranded gas in replace of the water-based fracturing fluid can reduce the gas emission and the cost. This paper presents some novel numerical studies on the feasibility of using stranded natural gas as fracturing fluids. Differences in the fracture creating, proppant placement, and oil/gas/water flowback are compared between natural gas fracturing fluids and water-based fracturing fluids. A fully integrated equation of state compositional hydraulic fracturing and reservoir simulator is used in this paper. Public datasets for the Permian Basin rock and fluid properties and natural gas foam properties are collected to set up simulation cases. The reservoir hydrocarbon fluid and natural gas fracturing fluids phase behavior is modeled using the Peng-Robinson equation of state. The evolving of created fracture geometry, conductivity and flowback performance during the lifecycle of the well (injection, shut-in, and production) are analyzed for the gas and water fracturing fluids. Simulation results show that natural gas and foam fracturing fluids are better than water-based fracturing fluids in terms of lower breakdown pressure, lower water leakoff into the reservoir, and higher cluster efficiency. NG foams tend to create better propped fractures with shorter length and larger width, because of their high viscosity. NG foam is also found to create better stimulated rock volume (SRV) permeability, better fracturing fluid flowback with a large water usage reduction, and high natural gas consumption. The simulation results presented in this paper are helpful to the operators in reducing natural gas emission while reducing the cost of hydraulic fracturing operation.

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Wilk-Zajdel, Klaudia, Piotr Kasza et Mateusz Masłowski. « Laboratory Testing of Fracture Conductivity Damage by Foam-Based Fracturing Fluids in Low Permeability Tight Gas Formations ». Energies 14, n^o 6 (23 mars 2021) : 1783. http://dx.doi.org/10.3390/en14061783.

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In the case of fracturing of the reservoirs using fracturing fluids, the size of damage to the proppant conductivity caused by treatment fluids is significant, which greatly influence the effective execution of hydraulic fracturing operations. The fracturing fluid should be characterized by the minimum damage to the conductivity of a fracture filled with proppant. A laboratory research procedure has been developed to study the damage effect caused by foamed and non-foamed fracturing fluids in the fractures filled with proppant material. The paper discusses the results for high quality foamed guar-based linear gels, which is an innovative aspect of the work compared to the non-foamed frac described in most of the studies and simulations. The tests were performed for the fracturing fluid based on a linear polymer (HPG—hydroxypropyl guar, in liquid and powder form). The rheology of nitrogen foamed-based fracturing fluids (FF) with a quality of 70% was investigated. The quartz sand and ceramic light proppant LCP proppant was placed between two Ohio sandstone rock slabs and subjected to a given compressive stress of 4000–6000 psi, at a temperature of 60 °C for 5 h. A significant reduction in damage to the quartz proppant was observed for the foamed fluid compared to that damaged by the 7.5 L/m3 natural polymer-based non-foamed linear fluid. The damage was 72.3% for the non-foamed fluid and 31.5% for the 70% foamed fluid, which are superior to the guar gum non-foamed fracturing fluid system. For tests based on a polymer concentration of 4.88 g/L, the damage to the fracture conductivity by the non-foamed fluid was 64.8%, and 26.3% for the foamed fluid. These results lead to the conclusion that foamed fluids could damage the fracture filled with proppant much less during hydraulic fracturing treatment. At the same time, when using foamed fluids, the viscosity coefficient increases a few times compared to the use of non-foamed fluids, which is necessary for proppant carrying capacities and properly conducted stimulation treatment. The research results can be beneficial for optimizing the type and performance of fracturing fluid for hydraulic fracturing in tight gas formations.

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Gaurina-Međimurec, Nediljka, Vladislav Brkić, Matko Topolovec et Petar Mijić. « Fracturing Fluids and Their Application in the Republic of Croatia ». Applied Sciences 11, n^o 6 (21 mars 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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Mihail, Silin, Magadova Lyubov, Malkin Denis, Krisanova Polina, Borodin Sergei et Filatov Andrey. « Applicability Assessment of Viscoelastic Surfactants and Synthetic Polymers as a Base of Hydraulic Fracturing Fluids ». Energies 15, n^o 8 (13 avril 2022) : 2827. http://dx.doi.org/10.3390/en15082827.

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Hydraulic fracturing (HF) is currently the most widespread and effective method of oil production stimulation. The most commonly used fracturing fluid is crosslinked guar gels. However, when using these systems, problems such as clogging of the pore space, cracking, and proppant packing with the remains of the undestroyed polymer arise. Therefore, the efficiency of the hydraulic fracturing process decreases. In this work, compositions based on viscoelastic surfactants (VES) and synthetic polymers (SP) were considered as alternatives capable of minimizing these disadvantages. Most often, the possibility of using a composition as a fracturing fluid is evaluated using rotational viscometry. However, rotational viscometry is not capable of fully assessing the structural and mechanical properties of fracturing fluid. This leads to a reduced spread of systems based on VES and SP. This paper proposes an integrated approach to assessing the effectiveness of a water-based fracturing fluid. The proposed comprehensive approach includes an assessment of the main characteristics of water-based fracturing fluids, including an analysis of their structural and mechanical properties, which is based on a combination of rotational and oscillatory rheology and a comparative analysis of methods for studying the influence of fluids on the reservoir rock. The use of the developed approach to assess the technological properties of fracturing fluids makes it possible to demonstrate the potential applicability of new, unconventional fracturing fluids such as systems based on VES and SP.

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Ramadhan, Dimas, Hidayat Tulloh et Cahyadi Julianto. « Analysis Study Of The Effect In Selecting Combination Of Fracturing Fluid Types And Proppant Sizes On Folds Of Increase (FOI) To Improve Well Productivity ». Journal of Petroleum and Geothermal Technology 1, n^o 2 (26 novembre 2020) : 92. http://dx.doi.org/10.31315/jpgt.v1i2.3886.

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As fracturing materials, fracturing fluid and proppant are two very important parameters in doing hydraulic fracturing design. The combination of fractuirng fluid and proppant selection is the main focus and determinant of success in the hydraulic fracturing process. The high viscosity of the fracturing fluid will make it easier for the proppant to enter to fill the fractured parts, so that the conductivity of the fractured well will be better and can increase the folds of increase (FOI) compared to fracturing fluid with lower viscosity (Economides, 2000). This research was conducted by using the sensitivity test method on the selection of fracturing fluid combinations carried out at the TX-01 well with various sizes of proppants (namely; 12/18, 16/20, and 20/40 mesh) with the proppant selected being ceramic proppant type carbolite performed using the FracCADE simulator. Fracturing fluid was selected based on its viscosity, namely YF240OD and PrimeFRAC20 fluids with viscosity value of 4.123 cp and 171.1 cp, with a fixed pump rate of 14 bpm. The results showed that the combination of high-viscosity fluids (PrimeFRAC20) and 16/20 mesh proppant size resulted in a greater incremental fold (FOI) between the choice of another combination fracturing fluids and proppant sizes, namely 6.25.

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Shevtsova, Anna, Sergey Stanchits, Maria Bobrova, Egor Filev, Sergey Borodin, Vladimir Stukachev et Lyubov Magadova. « Laboratory Study of the Influence of Fluid Rheology on the Characteristics of Created Hydraulic Fracture ». Energies 15, n^o 11 (24 mai 2022) : 3858. http://dx.doi.org/10.3390/en15113858.

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In the last decade, the negative impact of hydraulic fracturing fluids on the reservoir properties has been noted, which has led to the new trend of improving characteristics and developing new hydraulic fracturing fluids. As an alternative option to the traditionally used cross-linked fluids based on guar solution, in our laboratory we have tested fluids having a branched spatial structure, which allowed them to hold and transport proppants, despite the low viscosity of this kind of fluids (100–200 mPa·s measured at 100 s−1). Existing theoretical models of hydraulic fracture (HF) propagation have some limitations in predicting the influence of fracturing fluids on reservoir properties. Unfortunately, in situ experiments in the target reservoir are difficult and expensive. Thus, laboratory experiments can be considered as a reasonable alternative for testing new fluids, since they can provide comprehensive information about the properties of the created HF before the application of a new hydraulic fracturing technique in the field conditions. This paper presents the results of an experimental study of hydraulic fracturing of granite samples in laboratory conditions. The injection of water- and oil-based unconventional fracturing fluids was performed to study the influence of fluid rheology on the dynamics of the hydraulic fracture propagation process and parameters of the created HF. We have found that the fracturing fluid viscosity affects the parameters of the created HF, such as aperture, propagation velocity, breakdown pressure, and HF surface tortuosity. The obtained relationships can be taken into account for Hydraulic Fracture modelling, which may increase the efficiency of the hydraulic fracturing in the field conditions.

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LaGrone, C. C., S. A. Baumgartner et R. A. Woodroof. « Chemical Evolution of a High- Temperature Fracturing Fluid ». Society of Petroleum Engineers Journal 25, n^o 05 (1 octobre 1985) : 623–28. http://dx.doi.org/10.2118/11794-pa.

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Abstract Reservoirs with bottomhole temperatures (BHT's) in excess of 250 deg. F [121 deg. C] and permeabilities of less than 1.0 md are commonly encountered in drilling and completing geothermal and deep gas wells. Successful stimulation of these wells often requires the use of massive hydraulic fracturing (MHF) treatments. Fracturing fluids chosen for these large treatments must possess shear and thermal stability at high BHT'S. The use of conventional fracturing fluids has been limited traditionally to wells with BHT's of 250 deg. F [121 deg. C] or less. Above 250 deg. F [121 deg. C], high polymer concentrations and/or large fluid volumes are required to maintain effective fluid viscosities in the fracture. However, high polymer concentrations lead to high friction pressures, high costs, and high gel residue levels. The large fluid volumes also increase significantly the cost of the treatment. Greater understanding of fracturing fluid properties has led to the development of a crosslinked fracturing fluid designed specifically for wells with BHT's above 250 deg F [121 deg C). The specialized chemistry of this fluid combines a high-ph hydroxypropyl guar gum (HPG) solution with a high-temperature gel stabilizer and a proprietary crosslinker. The fluid remains stable at 250 to proprietary crosslinker. The fluid remains stable at 250 to 350 deg. F [121 to 177 deg. C] for extended periods of time under shear. This paper describes the rheologial evaluations used in the systematic development of this fracturing fluid. In field applications, this fracturing fluid has been used to stimulate successfully wells with BHT's ranging from 250 to 540 deg. F [121 to 282 deg C). Case histories that include pretreatment and posttreatment production data are presented. Introduction Temperatures exceeding 250 deg F [121 deg C) and permeabilities less than 1.0 md are frequently encountered in permeabilities less than 1.0 md are frequently encountered in deep gas and geothermal wells. Successful economic completion of these wells requires that long, conductive fractures with optimal proppant distribution be created. Ultimately, the amount of production from these formations depends on the propped fracture length created. One successful stimulation technique used to create these long fractures is MHF. In these treatments, the fracturing fluids are often exposed to shear in the fracture for prolonged periods of time at high temperatures. Thus the fracturing fluids must exhibit extended shear and thermal stability at the high BHT'S. In addition, the fracturing fluid must not leak off rapidly into the formation, or the fracture may not be extended to the desired length. Many early treatments were limited by fracturing fluids that lost viscosity rapidly at high BHT's because of excessive thermal and/or shear degradation. Creation of a narrow fracture width, excessive fluid loss to the formation, and insufficient proppant transport resulted from the use of these low viscosity fluids. The solution to conventional fracturing fluid deficiencies was to develop a more efficient fracturing fluid (low polymer concentrations) with greater viscosity retention under shear at high temperatures, better fluid-loss control, and lower friction pressures. Generally, the components that make up crosslinked fracturing fluids include a polymer, buffer, gel stabilizer, and crosslinker. Each of these components is critical to the development of the desired fracturing fluid properties. The role of polymers in fracturing fluids is to properties. The role of polymers in fracturing fluids is to provide fracture width, to suspend proppants, to help provide fracture width, to suspend proppants, to help control fluid loss to the formation, and to reduce friction pressure in the tubular goods. Guar gum and cellulosic pressure in the tubular goods. Guar gum and cellulosic derivatives are the most common types of polymers used in fracturing fluids. The cellulosic derivatives are residue-free and thus help minimize fracturing fluid damage to the formation. However, the cellulosic derivatives are difficult to disperse because of their rapid rate of hydration. Guar gum and its derivatives are easily dispersed but produce some residue when broken. Buffers are used in conjunction with polymers so that the optimal pH for polymer hydration can be attained. When the optimal pH is reached, the maximal viscosity yield from the polymer is more likely to be obtained. The most common example of fracturing fluid buffers is a weak-acid/weak-base blend, whose ratios can be adjusted to that the desired ph is reached. However, some of these buffers dissolve slowly, particularly at cooler temperatures. Gel stabilizers are added to polymer solutions to inhibit chemical degradation. Examples of gel stabilizers used in fracturing fluids include methanol and various inorganic sulfur compounds. Other stabilizers are useful in inhibiting the chemical degradation process, but many interfere with the mechanism of crosslinking. The sulfur containing stabilizers possess an advantage over methanol, which is flammable, toxic, and expensive. SPEJ P. 623

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Almubarak, Tariq, Mohammed AlKhaldi, Jun Hong Ng et Hisham A. Nasr-El-Din. « Design and Application of High-Temperature Raw-Seawater-Based Fracturing Fluids ». SPE Journal 24, n^o 04 (25 avril 2019) : 1929–46. http://dx.doi.org/10.2118/195597-pa.

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Summary Typically, water-based fracturing treatments consume a large volume of fresh water. Providing consistent freshwater sources is difficult and sometimes not feasible, especially in remote areas and offshore operations. Therefore, several seawater-based fracturing fluids have been developed in an effort to preserve freshwater resources. However, none of these fluids minimizes fracture-face skin and proppant-conductivity impairment, which can be critical for unconventional well treatments. Several experiments and design iterations were conducted to tailor raw-seawater-based fracturing fluids. These fluids were designed to have rheological properties that can transport proppant under dynamic and static conditions. The optimized seawater-based fracturing-fluid formulas were developed such that no scale forms when additives are mixed in or when the fracturing-fluid filtrate is mixed with different formation brines. The tests were conducted using a high-pressure/high-temperature (HP/HT) rheometer, coreflood, and by aging cells at 250 to 300°F. The developed seawater-based fracturing fluids were optimized with an apparent viscosity greater than 100 cp at a shear rate of 100 seconds–1 and a temperature of 300°F for more than 1 hour. The use of polymeric- and phosphonate-based scale inhibitors (SIs) prevented the formation of severe calcium sulfate (CaSO4) scale in mixtures of seawater and formation brines at 300°F. Controlling the pH of fracturing fluids prevented magnesium and calcium hydroxide precipitation that occurs at a pH value of greater than 9.5. Most importantly, SIs had a negative effect on the viscosity of seawater fracturing fluid during testing because of their negative interaction with metallic crosslinkers. The developed seawater-based fracturing fluids were applied for the first time in an unconventional and a conventional carbonate well and showed very promising results; details of field treatments are discussed in this paper.

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Xu, Zhengming, Kan Wu, Xianzhi Song, Gensheng Li, Zhaopeng Zhu et Baojiang Sun. « A Unified Model To Predict Flowing Pressure and Temperature Distributions in Horizontal Wellbores for Different Energized Fracturing Fluids ». SPE Journal 24, n^o 02 (31 décembre 2018) : 834–56. http://dx.doi.org/10.2118/194195-pa.

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Summary Energized fracturing fluids, including foams, carbon dioxide (CO2), and nitrogen (N2), are widely used for multistage fracturing in horizontal wells. However, because density, rheology, and thermal properties are sensitive to temperature and pressure, it is important to understand the flow and thermal behaviors of energized fracturing fluids along the wellbore. In this study, a unified steady-state model is developed to simulate the flow and thermal behaviors of different energized fracturing fluids and to investigate the changes of fluid properties from the wellhead to the toe of the horizontal wellbore. The velocity and pressure are calculated using continuity and momentum equations. Temperature profiles of the whole wellbore/formation system are obtained by simultaneously solving energy equations of different thermal regions. Temperature, pressure, and energized-fluid properties are coupled in both depth and radial directions using an iteration scheme. This model is verified against field data from energized-fluid-injection operations. The relative average errors for pressure and temperature are less than 5%. The effects of injection pressure, mass-flow rate, annulus-fluid type, foam quality, and proppant volumetric concentration on pressure and temperature distributions are analyzed. Influence degrees of these operating parameters on the bottomhole pressure (BHP) for different energized fracturing fluids are calculated. The required injection parameters at the surface to achieve designed bottomhole treating parameters for different energized fracturing fluids are compared. The results of this study might help field operators to select the most-suitable energized fluid and further optimize energized-fluid-fracturing treatments.

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Zheng, Shuang, et Mukul M. Sharma. « Evaluating different energized fracturing fluids using an integrated equation-of-state compositional hydraulic fracturing and reservoir simulator ». Journal of Petroleum Exploration and Production Technology 12, n^o 3 (27 octobre 2021) : 851–69. http://dx.doi.org/10.1007/s13202-021-01342-8.

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AbstractHorizontal wells are often drilled and hydraulically fractured in tight reservoirs to produce hydrocarbons or heat. Different fracturing fluids such as slick water, gas, foam, gel, or a combination can be used with slick water being the most common fracturing fluid. In this paper, we study the impacts of different fracturing fluids on fractured well productivity using an in-house integrated hydraulic fracturing and reservoir simulator with an equation-of-state compositional model. We analyzed the fracture geometry, stress interference, proppant placement, and the subsequent well productivity using different fracturing fluids. The results clearly show that different fracturing fluids result in very different fracture shape, sand distribution, and water and hydrocarbon production. By conducting fracturing and production simulations in one simulator, we ensure that no physics and data loss occurs due to data migration between two different software packages for hydraulic fracturing and reservoir simulation. To the best of the authors’ knowledge, this is the first time that a single integrated equation-of-state compositional hydraulic fracturing and reservoir simulator has been presented and applied for well lifecycle simulation.

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Wang, Minghao, Hanlie Cheng, Jianfei Wei, Ke Zhang, David Cadasse et Qiang Qin. « High-Temperature-Resistant, Clean, and Environmental-Friendly Fracturing Fluid System and Performance Evaluation of Tight Sandstone ». Journal of Environmental and Public Health 2022 (3 août 2022) : 1–7. http://dx.doi.org/10.1155/2022/5833491.

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Hydraulic fracturing, as an oil-water well stimulation and injection technology, is particularly important in the production and stimulation of low-permeability oil and gas fields, and the performance of the fracturing fluid directly affects the success of the fracturing operation. Compared with traditional water-based fracturing fluids, clean fracturing fluids have the advantages of strong sand-carrying ability and easy gel breaking with no residue. Aiming at the problem of poor temperature resistance and shear resistance of the clean fracturing fluid, based on previous research, this paper selects a high-temperature-resistant clean fracturing fluid system and evaluates the performance of the system. The research results show that the system has better rheological properties, better sand-carrying performance, shorter gel-breaking time, and less damage to the reservoir.

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Payne, Madeleine E., Heather F. Chapman, Janet Cumming et Frederic D. L. Leusch. « In vitro cytotoxicity assessment of a hydraulic fracturing fluid ». Environmental Chemistry 12, n^o 3 (2015) : 286. http://dx.doi.org/10.1071/en14010.

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Environmental context Hydraulic fracturing fluids, used in large volumes by the coal seam gas mining industry, are potentially present in the environment either in underground formations or in mine wastewater (produced water). Previous studies of the human health and environmental effects of this practice have been limited because they use only desktop methods and have not considered combined mixture toxicity. We use a novel in vitro method for toxicity assessment, and describe the toxicity of a hydraulic fracturing fluid on a human gastrointestinal cell line. Abstract Hydraulic fracturing fluids are chemical mixtures used to enhance oil and gas extraction. There are concerns that fracturing fluids are hazardous and that their release into the environment – by direct injection to coal and shale formations or as residue in produced water – may have effects on ecosystems, water quality and public health. This study aimed to characterise the acute cytotoxicity of a hydraulic fracturing fluid using a human gastrointestinal cell line and, using this data, contribute to the understanding of potential human health risks posed by coal seam gas (CSG) extraction in Queensland, Australia. Previous published research on the health effects of hydraulic fracturing fluids has been limited to desktop studies of individual chemicals. As such, this study is one of the first attempts to characterise the toxicity of a hydraulic fracturing mixture using laboratory methods. The fracturing fluid was determined to be cytotoxic, with half maximal inhibitory concentrations (IC50) values across mixture variations ranging between 25 and 51mM. When used by industry, these fracturing fluids would be at concentrations of over 200mM before injection into the coal seam. A 5-fold dilution would be sufficient to reduce the toxicity of the fluids to below the detection limit of the assay. It is unlikely that human exposure would occur at these high (‘before use’) concentrations and likely that the fluids would be diluted during use. Thus, it can be inferred that the level of acute risk to human health associated with the use of these fracturing fluids is low. However, a thorough exposure assessment and additional chronic and targeted toxicity assessments are required to conclusively determine human health risks.

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Cai, Bo, Yun Hong Ding, Yong Jun Lu, Chun Ming He et Gui Fu Duan. « Leak-Off Coefficient Analysis in Stimulation Treatment Design ». Advanced Materials Research 933 (mai 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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F, Yehia. « Hydraulic Fracturing Process Systems and Fluids : An Overview ». Petroleum & ; Petrochemical Engineering Journal 6, n^o 3 (29 juillet 2022) : 1–7. http://dx.doi.org/10.23880/ppej-16000306.

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Hydraulic fracturing has become a critical component of global petroleum and natural gas development, with most the countries around the globe, for example, Canada, India, England, and China actively pursuing the implementation of this technology to increase oil production after declination as well as tap into this new source of energy. Hydraulic fracturing has created jobs and increased revenue in several states across the country. However, as with any advanced technology, there are concerns about its long-term environmental impact. Thus, many researchers and technicians continuously conduct advanced studies to inform industries about any new or upcoming regulations. In this study, a mini-review of the fracking process is considered an important section of the petroleum and natural gas industries. Moreover, researchers demonstrated knowledge about the frac systems and different hydraulic fracturing fluids that are utilized for a fracking job which were different from one fracking system to another in addition to the nature of the reservoir formation. It is a significant factor that production engineers take into consideration when applying hydraulic fracturing to enhance oil or gas production and treat the formation damage, as well. Since the formation damage considers the most critical issue affecting oil and gas production due to fine migration.

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Shen, Yunqi, Zhiwen Hu, Xin Chang et Yintong Guo. « Experimental Study on the Hydraulic Fracture Propagation in Inter-Salt Shale Oil Reservoirs ». Energies 15, n^o 16 (15 août 2022) : 5909. http://dx.doi.org/10.3390/en15165909.

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In response to the difficulty of fracture modification in inter-salt shale reservoirs and the unknown pattern of hydraulic fracture expansion, corresponding physical model experiments were conducted to systematically study the effects of fracturing fluid viscosity, ground stress and pumping displacement on hydraulic fracture expansion, and the latest supercritical CO2 fracturing fluid was introduced. The test results show the following. (1) The hydraulic fractures turn and expand when they encounter the weak surface of the laminae. The fracture pressure gradually increases with the increase in fracturing fluid viscosity, while the fracture pressure of supercritical CO2 is the largest and the fracture width is significantly lower than the other two fracturing fluids due to the high permeability and poor sand-carrying property. (2) Compared with the other two conventional fracturing fluids, under the condition of supercritical CO2 fracturing fluid, the increase in ground stress leads to the increase in inter-salt. (3) Compared with the other two conventional fracturing fluids, under the conditions of supercritical CO2 fracturing fluid, the fracture toughness of shale increases, the fracture pressure increases, and the fracture network complexity decreases as well. (4) With the increase in pumping displacement, the fracture network complexity increases, while the increase in the displacement of supercritical CO2 due to high permeability leads to the rapid penetration of inter-salt shale hydraulic fractures to the surface of the specimen to form a pressure relief zone; it is difficult to create more fractures with the continued injection of the fracturing fluid, and the fracture network complexity decreases instead.

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Guo, Yintong, Peng Deng, Chunhe Yang, Xin Chang, Lei Wang et Jun Zhou. « Experimental Investigation on Hydraulic Fracture Propagation of Carbonate Rocks under Different Fracturing Fluids ». Energies 11, n^o 12 (15 décembre 2018) : 3502. http://dx.doi.org/10.3390/en11123502.

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Deep carbonate reservoirs are rich in oil and gas resources. However, due to poor pore connectivity and low permeability, it is necessary to adopt hydraulic fracturing technology for their development. The mechanism of hydraulic fracturing for fracture initiation and propagation in carbonate rocks remains unclear, especially with regard to selection of the type of fracturing fluid and the fracturing parameters. In this article, an experimental study focusing on the mechanisms of hydraulic fracturing fracture initiation and propagation is discussed. Several factors were studied, including the type of injecting fracturing fluids, pump flow rate, fracturing pressure curve characteristics, and fracture morphology. The results showed the following: (1) The viscosity of fracturing fluid had a significant effect on fracturing breakdown pressure. Under the same pump flow rate, the fracturing breakdown pressure of slick water was the lowest. Fracturing fluids with low viscosity could easily activate weakly natural fractures or filled fractures, leading to open microcracks, and could effectively reduce the fracturing breakdown pressure. (2) The fluctuations in fracturing pump pressure corresponded with the acoustic emission hits and changes in radial strain; for every drop of fracturing pressure, acoustic emission hits and changes in radial strain were mutated. (3) Under the same fracturing fluid, the pump flow rate mainly affected fracturing breakdown pressure and had little effect on fracture morphology. (4) The width of the main fracture was affected by the viscosity and pump flow rate. Maximum changes in radial strain at the fracturing breakdown pressure point occurred when the fracturing fluid was guar gum. (5) With gelled acid and cross-linked acid fracturing, the main fractures were observed on the surface. The extension of the fracturing crack was mainly focused near the crack initiation parts. The crack expanded asymmetrically; the wormhole was dissolved to break through to the surface of the specimen. (6) The dissolution of gelled acid solution could increase the width of the fracturing crack and improve the conductivity of carbonate reservoirs.

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Elgibaly, A. A., A. M. Salem et Y. A. Soliman. « Improving hydraulic fracturing effectiveness in depleted and low-pressure reservoirs using N2-energized fluids ». Journal of Petroleum Exploration and Production Technology 11, n^o 2 (6 janvier 2021) : 857–73. http://dx.doi.org/10.1007/s13202-020-01060-7.

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AbstractFoamed and energized fluids fracturing has been used in both conventional and unconventional reservoirs, as they reduce the amount of water used and hence minimize deleterious impact on water-sensitive formations. They also aid in the flow back after treatment in reservoirs where drawdown is limited. In this paper, the most important foam properties are presented, in addition, when to use energized fluids fracturing and how to choose the best energizing component with the best quality. The impact of N2-energized fluids fracturing (NEF) on wells that were previously fractured using conventional fracturing fluids is also presented. In addition, a comparison between the results of N2-energized fluids fractured and conventional fluid fractured wells is presented. The effect of using 20 to 50% (NEF) on production through surface well testing and live production data showed excellent and sustainable production rates. An economical study is presented through comparing the total capital cost of both NEF and conventional fluids fracturing, in addition to the hydrocarbon recovery of wells after both types. Data considered in this work represent about 40 wells fractured using NEF in the Egyptian Western Desert.

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Mehana, Mohamed, Fangxuan Chen, Mashhad Fahes, Qinjun Kang et Hari Viswanathan. « Geochemical Modelling of the Fracturing Fluid Transport in Shale Reservoirs ». Energies 15, n^o 22 (16 novembre 2022) : 8557. http://dx.doi.org/10.3390/en15228557.

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Field operations report that at least half of the fracturing fluid used in shale reservoirs is trapped. These trapped fluids can trigger various geochemical interactions. However, the impact of these interactions on well performance is still elusive. We modeled a hydraulic fracture stage where we simulated the initial conditions by injecting the fracturing fluid and shutting the well to allow the fluids to soak into the formation. Our results suggest a positive correlation between the dissolution and precipitation rates and the carbonate content of the rock. In addition, we observed that gas and load recovery are overestimated when geochemical interactions are overlooked. We also observed promising results for sea water as a good alternative fracturing fluid. Moreover, we observed better performance for cases with lower-saline connate water. The reactions of carbonates outweigh the reactions of clays in most cases. Sensitivity analysis suggests that the concentration of SO4, K and Na ions in the fracturing fluid, and the illite and calcite mineral content, along with the reservoir temperature, are the key factors affecting well performance. In conclusion, geochemical interactions should be considered for properly modeling the fate of the fracturing fluids and their impact on well performance.

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Tian, Jizhen, Jincheng Mao, Wenlong Zhang, Xiaojiang Yang, Chong Lin, Meng Cun, Jinhua Mao et Jinzhou Zhao. « Application of a Zwitterionic Hydrophobic Associating Polymer with High Salt and Heat Tolerance in Brine-Based Fracturing Fluid ». Polymers 11, n^o 12 (3 décembre 2019) : 2005. http://dx.doi.org/10.3390/polym11122005.

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ZID16PM, a zwitterionic hydrophobic associating polymer, has equivalent positive and negative charges and some hydrophobic monomers with twin-tailed long hydrophobic chains. It exhibits a great heat resistance and salt tolerance to the common salt in formation brine (MgCl2, CaCl2, NaCl, and KCl), which is attributed to its anti-polyelectrolyte effect and strong association force. High-salinity water (seawater or formation water) can be prepared as a fracturing fluid directly. In this paper, the formation water of the West Sichuan Gas Field is directly prepared into fracturing fluid with a concentration of 0.3% ZID16PM (Fluid-1), and the seawater of the Gulf of Mexico is directly prepared into fracturing fluid with a concentration of 0.3% ZID16PM (Fluid-2). Finally, rheological measurements, proppant suspension tests, and core matrix permeability damage rate tests for the Fluid-1 and Fluid-2 are conducted. Results show that after 120 min of shearing at 140 and 160 °C, respectively, the viscosity of Fluid-1 remains in the range of 50–85 mPa·s, and the viscosity of Fluid-2 remains in the range of 60–95 mPa·s. And the wastewater produced by an oilfield in Shaanxi, Xinjiang, and Jiangsu are also prepared into fracturing fluids with a concentration of 0.3% ZID16PM, the viscosity of these fracturing fluids can remain 32, 42, and 45 mPa·s, respectively, after 120 min of shearing at 160 °C. All results demonstrate that the polymer ZID16PM displays prominent performance in fracturing fluids.

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Silveira de Araujo, Isa, et Zoya Heidari. « Quantifying Interfacial Interactions Between Minerals and Reservoir/Fracturing Fluids ». Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description 63, n^o 6 (1 décembre 2022) : 658–70. http://dx.doi.org/10.30632/pjv63n6-2022a6.

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Chemical interactions between the injected fluids and the minerals during the fracturing process can affect fluid flow and production. However, there is still a need to understand the impact of geochemistry on the interactions at the rock-fluid interface and how these interactions affect the wettability of the rock and fluid flow in organic-rich mudrocks. In this paper, we quantify the mineral-fluid affinity by performing adsorption calculations. Molecular dynamics simulations (MDS) are carried out to (i) quantify the adsorption of fracturing fluids on the surface of minerals, (ii) perform sensitivity analysis on the composition of fracturing fluid and reservoir temperature on adsorption and mobility, and (iii) analyze the spatial distribution of water and chemicals on mineral surfaces. The minerals evaluated include illite and calcite, and the fracturing-fluid components are methanol, citric acid, sodium chloride, and water. We evaluate the effect of each chemical separately. First, systems composed of mineral surfaces in contact with brine are generated. Then, we analyze the mineral in contact with a solution containing brine and methanol and with a solution composed of brine and citric acid. MDS are carried out in the canonical (NVT) ensemble at the temperature of 330 K to evaluate the adsorption of the fracturing fluid. To quantify the impacts of reservoir temperature, we carry out MDS at a temperature of 360 K. Results suggest that methanol does not have a strong effect on water adsorption and the ion spatial distribution on the mineral’s surface. We found that citric acid tends to form aggregates and that some cations present in the solution might participate in these aggregates. When methanol or citric acid is added to the brine solution, the mobility of both sodium and water on the illite surface decreases. The effects of each additive on the affinity between the mineral and fracturing fluids were also investigated. We found that the number of hydrogen bonds between illite and the fluid did not change when additives were added. However, the number of hydrogen bonds between calcite and the fluid was affected when methanol was added to the system. The quantification of adsorption in the molecular scale provides a fundamental understanding of the electrochemical interactions between the rock surface and the fracturing/reservoir fluids at reservoir conditions, which enables the enhanced design of fracturing-fluid composition for different reservoir types. This information can also be used to quantify the impacts of injected and reservoir fluids on the wettability of the rocks.

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Malhotra, Sahil, Eric R. Lehman et Mukul M. Sharma. « Proppant Placement Using Alternate-Slug Fracturing ». SPE Journal 19, n^o 05 (10 mars 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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Roodhart, L. P. « Fracturing Fluids : Fluid-Loss Measurements Under Dynamic Conditions ». Society of Petroleum Engineers Journal 25, n^o 05 (1 octobre 1985) : 629–36. http://dx.doi.org/10.2118/11900-pa.

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Abstract When filter-cake-building additives are used in fracturing fluids, the commonly applied static, 30-minute API filtration test is unsatisfactory, because in a dynamic situation (like fracturing) the formation of a thick filter cake will be inhibited by the shearing forces of the fracturing fluid. A dynamic, filter-cake-controlled, leakoff coefficient that is dependent on the shear rate and shear stress at the fracture face is, therefore, introduced. A test apparatus has been constructed in which the fluid leakoff is measured under conditions of temperature, rate of shear, duration of shear, and fluid-flow pattern as encountered under fracturing conditions. The effects of rock permeability, shear rate, and differential pressure on the permeability, shear rate, and differential pressure on the dynamic leakoff coefficient are presented for various, commonly used fracturing-fluid/fluid-loss-additive combinations. Introduction An important parameter in hydraulic fracturing design is the rate at which the fracturing fluid leaks into the formation. This parameter, known as fluid loss, not only determines the development of fracture length and width, but also governs the time required for a fracture to heal after the stimulation treatment has been terminated. The standard leakoff test is a static test, in which the effect of shear rate in the fracture on the viscosity of the fracturing fluid and on the filter-cake buildup is ignored. Dynamic vs. Static Tests The three stages in filter-cake buildup arespurt loss during initiation of the filter cake,buildup of filtercake thickness, during which time leakoff is proportional to the square root of time, andlimitation of filter-cake growth by erosion. In the standard API leakoff test, 1 the fracturing fluid, with or without leakoff additives, is forced through a disk of core material under a pressure differential of 1000 psi [7 MPa), and the flow rate of the filtrate is determined. In such a static test, the third stage-erosion of the filter cake-is absent. In a dynamic situation there is an equilibrium whereby flow along the filter cake limits the filter-cake thickness, and the leakoff rate becomes constant. The duration of each of these stages depends on the type of fluid, the type of additive, the rock permeability, and the test conditions. The differences between dynamic and static filtration tests are shown in Fig. 1, where the cumulative filtrate volume (measured in some experiments with the dynamic fluid-loss apparatus described below) is expressed as a function of time (Fig. la) and as a function of the square root of time (Fig. ]b), The shear rate at the surface of the disk is either static (O s -1 ), or 109 s -1 or 611 s -1. The curves indicate that the dynamic filtration velocities are higher than those measured in a static test and increase rapidly with increasing shear rate. This is in agreement with the observations made by Hall, who used an axially transfixed cylindrical core sample along which fracturing fluid was pumped, while the filtrate was collected from a bore through the center. Fig. la shows how the lines were drawn to fit the data: Vc = Vsp + A t + Bt, .........................(1) where Vc = cumulative volume per unit area, t = filtration time, Vsp= spurt loss, A = static leakoff component, andB = dynamic leakoff component. In static leakoff theory, B =0 and then A =2Cw, twice the static leakoff coefficient.-3 Each of the terms in Eq. 1 represents one of the stages in the leakoff process-spurt loss, buildup of filter cake, and erosion of filter cake. Analysis of the experimental data shows that the spurt loss, Vsp, and the static leakoff component, A, are independent of the shear rate, but the dynamic component, B, varies strongly with the shear rate (see Table 1). This means that, the higher the shear rate, the more the leakoff process is controlled by the third stage. process is controlled by the third stage. One model commonly used is based solely on square-root-of-time behavior with a constant spurt loss. Fig. 1 shows that little accuracy is lost by describing the leakoff with a single square-root-of-time equation: Vc = VsP + m t,...........................(2) where the dynamic leakoff coefficient. Cw = 1/2m, depends heavily on shear. and the spurt loss remains the same as in Eq. 1 and independent of the shear rate Table 2 shows that the error in C, that arises as a result of measuring under static conditions can be more than 100%. SPEJ P. 629

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Qu, Guanzheng, Jian Su, Ming Zhao, Xingjia Bai, Chuanjin Yao et Jiao Peng. « Optimizing Composition of Fracturing Fluids for Energy Storage Hydraulic Fracturing Operations in Tight Oil Reservoirs ». Energies 15, n^o 12 (11 juin 2022) : 4292. http://dx.doi.org/10.3390/en15124292.

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Energy storage fracturing technology is a technical means by which oil displacement fluid is injected into the reservoir before the traditional hydraulic fracturing and subsequent implement fracturing. It provides a good solution for developing tight oil reservoirs. The efficiency of this technology significantly depends on the injection performance of the fracturing fluid, and the ability of its liquid phase to penetrate the formation. According to the needs of energy storage fracturing, four surfactants were selected. Then, based on the performance evaluation of the four surfactants, the compositions of two surfactant systems were determined. The performance of slickwater fracturing fluids for energy storage hydraulic fracturing was evaluated. The mechanism of tight oil displacement in energy storage hydraulic fracturing was analyzed. The results showed that the compositions of oil–displacement agents 1 and 2 for energy storage fracturing were successfully acquired. The performance of oil–displacement agent 2 was slightly better than that of oil–displacement agent 1 at a concentration of 0.25 wt%. The defined composition of the fracturing fluid met requirements for energy storage hydraulic fracturing. It was demonstrated that the tight oil in small pores was effectively substituted by the fracturing fluid, and subsequently aggregated in the large pores. The tight oil displacement ratio increased with an increase in temperature, and the difference among the tight oil displacement ratios of tight sandstone cores increased with increases in their permeability differences.

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Gao, Chaoli, Shiqing Cheng, Mingwei Wang, Wen Wu, Zhendong Gao, Song Li et Xuangang Meng. « Optimization of Carbon Dioxide Foam Fracturing Technology for Shale Gas Reservoir ». Geofluids 2023 (13 février 2023) : 1–11. http://dx.doi.org/10.1155/2023/6187764.

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Major shale gas exploration and development fields are located in the Sichuan basin. It requires huge water sources for shale gas fracking, but the well sites are mostly in the hills, which limits the industrialization of shale gas development. CO2 foam fluids can meet the requirements of fracking fluids and relieve water stress. It analyzed the feasibility of CO2 foaming fracturing for shale gas formation fracturing, proposed a design philosophy for CO2 foaming fracturing, and optimized fracturing parameters such as foam mass, proppant concentration, friction, and discharge rate. The flowchart of CO2 foam fracturing was established in, where the fracture morphology and propagation behavior of CO2 foam fracturing were obtained from numerical simulations comparable to the hydraulic fracture generated by conventional hydraulic fracturing. The CO2 foaming fracturing technique can provide a discharge rate of 6.0 m3/min and fluid volume and captures the volume effect of the current stimulated reservoir, which needs to be improved. It can be considered an initial survey of CO2 foam fracturing available in the Sichuan Basin shale formation, which may provide new methods and clues for stimulation.

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Tang, Shanfa, Yahui Zheng, Weipeng Yang, Jiaxin Wang, Yingkai Fan et Jun Lu. « Experimental Study of Sulfonate Gemini Surfactants as Thickeners for Clean Fracturing Fluids ». Energies 11, n^o 11 (16 novembre 2018) : 3182. http://dx.doi.org/10.3390/en11113182.

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Hydraulic fracturing is one of the important methods to improve oil and gas production. The performance of the fracturing fluid directly affects the success of hydraulic fracturing. The traditional cross-linked polymer fracturing fluid can cause secondary damage to oil and gas reservoirs due to the poor flow-back of the fracturing fluid, and existing conventional cleaning fracturing fluids have poor performance in high temperature. Therefore, this paper has carried out research on novel sulfonate Gemini surfactant cleaning fracturing fluids. The rheological properties of a series of sulfonate Gemini surfactant (DSm-s-m) solutions at different temperatures and constant shear rate (170 s−1) were tested for optimizing the temperature-resistance and thickening properties of anionic Gemini surfactants in clean fracturing fluid. At the same time, the microstructures of solutions were investigated by scanning electron microscope (SEM). The experimental results showed that the viscosity of the sulfonate Gemini surfactant solution varied with the spacer group and the hydrophobic chain at 65 °C and 170 s−1, wherein DS18-3-18 had excellent viscosity-increasing properties. Furthermore, the microstructure of 4 wt.% DS18-3-18 solution demonstrated that DS18-3-18 self-assembled into dense layered micelles, and the micelles intertwined with each other to form the network structure, promoting the increase in solution viscosity. Adding nano-MgO can increase the temperature-resistance of 4 wt.% DS18-3-18 solution, which indicated that the rod-like and close-packed layered micelles were beneficial to the improvement of the temperature-resistance and thickening performances of the DS18-3-18 solution. DS18-3-18 was not only easy to formulate, but also stable in all aspects. Due to its low molecular weight, the damage to the formation was close to zero and the insoluble residue was almost zero because of the absence of breaker, so it could be used as a thickener for clean fracturing fluids in tight reservoirs.

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Wang, Lei. « Experimental Research on Damage to Fracture Conductivity Caused by Fracturing Fluid Residues ». Advanced Materials Research 774-776 (septembre 2013) : 303–7. http://dx.doi.org/10.4028/www.scientific.net/amr.774-776.303.

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Experimental research on damage to fracture conductivity caused by fracturing fluid residues has been done for the first time in China using FCES-100 (Fracture Conductivity Evaluation System). In the experiments, the degree of damage to conductivity caused by different types and concentrations of fracturing fluids were studied in the condition of different concentrations and types of proppants. The mechanism of damage to conductivity was studied and some methods on how to decrease the damage were brought forward, which is significant for the research on development of fracturing fluids and also for field treatments.

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Dutta, R., C. H. H. Lee, S. Odumabo, P. Ye, S. C. C. Walker, Z. T. T. Karpyn et 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, n^o 01 (30 janvier 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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Xin, Hui, Bo Fang, Luyao Yu, Yongjun Lu, Ke Xu et Kejing Li. « Rheological Performance of High-Temperature-Resistant, Salt-Resistant Fracturing Fluid Gel Based on Organic-Zirconium-Crosslinked HPAM ». Gels 9, n^o 2 (11 février 2023) : 151. http://dx.doi.org/10.3390/gels9020151.

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Development of low-cost, high-temperature-resistant and salt-resistant fracturing fluids is a hot and difficult issue in reservoir fluids modification. In this study, an organic zirconium crosslinker that was synthesized and crosslinked with partially hydrolyzed polyacrylamide (HPAM) was employed as a cost-effective polymer thickener to synthesize a high-temperature-resistant and salt-resistant fracturing fluid. The rheological properties of HPAM in tap water solutions and 2 × 104 mg/L salt solutions were analyzed. The results demonstrated that addition of salt reduced viscosity and viscoelasticity of HPAM solutions. Molecular dynamics (MD) simulation results indicated that, due to electrostatic interaction, the carboxylate ions of HPAM formed an ionic bridge with metal cations, curling the conformation, decreasing the radius of rotation and thus decreasing viscosity. However, optimizing fracturing fluids formulation can mitigate the detrimental effects of salt on HPAM. The rheological characteristics of the HPAM fracturing fluid crosslinking process were analyzed and a crosslinking rheological kinetic equation was established under small-amplitude oscillatory shear (SAOS) test. The results of a large-amplitude oscillation shear (LAOS) test indicate that the heating effect on crosslinking is stronger than the shear effect on crosslinking. High-temperature-resistant and shear-resistant experiments demonstrated good performance of fracturing fluids of tap water and salt solution at 200 °C and 180 °C.

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Fan, Haiming, Zheng Gong, Zhiyi Wei, Haolin Chen, Haijian Fan, Jie Geng, Wanli Kang et Caili Dai. « Understanding the temperature–resistance performance of a borate cross-linked hydroxypropyl guar gum fracturing fluid based on a facile evaluation method ». RSC Advances 7, n^o 84 (2017) : 53290–300. http://dx.doi.org/10.1039/c7ra11687j.

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A facile procedure has been proposed to evaluate the temperature–resistance performance of fracturing fluids, which was used to understand the temperature–tolerance performance of a borate cross-linked hydroxypropyl guar gum fracturing fluid.

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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, n^o 2 (1 mai 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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Harris, Phillip C. « Dynamic Fluid Loss Characteristics of Foam Fracturing Fluids ». Journal of Petroleum Technology 37, n^o 10 (1 octobre 1985) : 1847–52. http://dx.doi.org/10.2118/11065-pa.

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Jie, Yang. « Experiment Study on the properties of Su-53 fracturing fluid ». Highlights in Science, Engineering and Technology 25 (13 décembre 2022) : 293–97. http://dx.doi.org/10.54097/hset.v25i.3505.

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The sand carrying performance of the fracturing fluid is one of the decisive properties of the sand laying form of the proppant in the reservoir, and the sand carrying performance of the seven fracturing fluids on appeal is tested according to the Stokes theoretical formula for two melon samples and five viscoelastic surfactant samples. Single-particle sedimentation test and multi-particle sedimentation test were carried out and the fracturing fluid was optimized based on test data.The treatment of fracturing fluid flowback has always been a problem in the industry. In this paper, a redistribution experiment was carried out on 7 samples according to a redistribution method of fracturing flowback fluid, and viscosity was used as the main reference index. The recyclability of each fracturing fluid was compared based on the retention rate; the fracturing fluid with the most recyclability was selected.

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Denney, Dennis. « Hydraulic Fracturing : Internal Breakers for Viscoelastic-Surfactant Fracturing Fluids ». Journal of Petroleum Technology 60, n^o 03 (1 mars 2008) : 70–71. http://dx.doi.org/10.2118/0308-0070-jpt.

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Sun, Zepeng, Yue Ni, Yongli Wang, Zhifu Wei, Baoxiang Wu, Jing Li, Wenhua Fan, Gailing Wang et Yunxiao Li. « Experimental investigation of the effects of different types of fracturing fluids on the pore structure characteristics of Shale Reservoir Rocks ». Energy Exploration & ; Exploitation 38, n^o 3 (26 novembre 2019) : 682–702. http://dx.doi.org/10.1177/0144598719888937.

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The chemical and physical capabilities of shale can be altered by the interactions between fracturing fluid and shale formation, affecting the long-term reservoir productivity. To obtain information regarding how fracturing fluids with different components impact the pore structure, porosity and mineral compositions of shale reservoir rocks over time, two different types of commercial fracturing fluids (slick water and crosslinked gel) were used to react with the shales from Longmaxi Formation of Lower Silurian in the Sichuan Basin of South China. Experiments were conducted with various time intervals (1, 4 and 10 days) in a reactor at 50 MPa and 100°C, and then analytical methods including X-ray diffraction, low pressure nitrogen adsorption, field emission scanning electron microscopy and porosity measurement were used to examine the changes of mineralogical compositions, pore structure and porosity. The results demonstrated that the mineral compositions of shale samples were significantly changed after treatment with two different fracturing fluids for 4 days. The analysis of field emission scanning electron microscopy revealed that the carbonate minerals were dissolved and developed many dissolution pores after slick water treatment, while the crosslinked gel mainly caused the precipitation of carbonate minerals. After exposure to different fracturing fluids, the total pore volume and specific surface area decreased over time. Moreover, the fractal dimensions (D1 and D2) of shale showed an apparent decrease trend after treatment with two different fracturing fluids, indicating that the pore surface and structure become smooth and regular. The porosity of shale significantly decreased by 15.9% and 17.8%, respectively, after 10 days of slick water and crosslinked gel treatment. These results indicated that the injection of the two different types of fracturing fluids may negatively impact the shale gas production through reducing the nanopore structure and porosity of shale reservoir rocks.

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Xu, Tianlu, Yingxian Lei, Chengmei Wu et Yinghao Shen. « Insight into the Methods for Improving the Utilization Efficiency of Fracturing Liquid in Unconventional Reservoirs ». Geofluids 2021 (18 novembre 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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Jennings, Alfred R. « Fracturing Fluids - Then and Now ». Journal of Petroleum Technology 48, n^o 07 (1 juillet 1996) : 604–10. http://dx.doi.org/10.2118/36166-jpt.

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Jennings Jr, Alfred R. « Fracturing Fluids - Then and Now ». Journal of Petroleum Technology 48, n^o 07 (1 juillet 1996) : 604–10. http://dx.doi.org/10.2118/36166-ms-jpt.

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Barbati, Alexander C., Jean Desroches, Agathe Robisson et Gareth H. McKinley. « Complex Fluids and Hydraulic Fracturing ». Annual Review of Chemical and Biomolecular Engineering 7, n^o 1 (7 juin 2016) : 415–53. http://dx.doi.org/10.1146/annurev-chembioeng-080615-033630.

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Duan, Junrui, Renjie Zhang et Jiahui Zhao. « Research Progress of Anhydrous Fracturing ». Academic Journal of Science and Technology 3, n^o 1 (11 octobre 2022) : 83–87. http://dx.doi.org/10.54097/ajst.v3i1.1965.

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Oil and gas reserves in our country are large and widely distributed, and usually fracturing techniques are needed to extract oil and gas. Currently, the more mature hydraulic fracturing technology is difficult to extract coal bed methane. Combined with the research progress of fracturing at home and abroad, this paper summarizes the development of relevant anhydrous fracturing technology, fracturing fluid, fracturing process and other aspects, compares and analyzes the advantages and disadvantages of fracturing technology, and provides some ideas for the development of anhydrous fracturing technology in the future. In order to reduce the cost of anhydrous fracturing, meet the requirements of field application, and accelerate the research progress of anhydrous fracturing, the commonly used fracturing technologies are combined to study new fracturing fluids and carry out composite anhydrous fracturing.

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Zhong, Shuang Fei, Fu Jian Liu et Dong Xu Li. « Laboratory Study and Evaluation on a Novel Clearfrac Fluid System ». Advanced Materials Research 488-489 (mars 2012) : 133–36. http://dx.doi.org/10.4028/www.scientific.net/amr.488-489.133.

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Hydraulic fracturing is an effective measure to recover the permeabilityof reservoir and important to enhance oil and gas well production and water injection well. Fracturing fluid is the key factor in the fracture treatments. At present, water-based fracturing fluids are popular, because of low costs and steady performance, which has the largest applications. However, it performs badly in residue. The novel developed clearfrac fluid system named CF1 has lowresidue, cost affectivity, prior temperature resistance properties. Evaluation through a series of lab experiments, the experiments result show that the novel clearfrac fluid system can satisfy with the requirement of low damage and have favorable temperature resistance under 120 。C. The damage to the core matrix due to with the broken frac-fluid is low. Prior properties of the novel clear-fracturing fluid are suitable to high temperature and high pressure reservoirs. It is also a novel environmental friendly viscoelastic surfactant fracturing fluid. The development of the novel clear-fracturing fluid for hydraulic fracturing industry is significant.

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Xu, Shiliang, Mengke Cui, Renjie Chen, Qiaoqing Qiu, Jiacai Xie, Yuxin Fan, Xiaohu Dai et Bin Dong. « Design of facile technology for the efficient removal of hydroxypropyl guar gum from fracturing fluid ». PLOS ONE 16, n^o 3 (4 mars 2021) : e0247948. http://dx.doi.org/10.1371/journal.pone.0247948.

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With the increasing demand for energy, fracturing technology is widely used in oilfield operations over the last decades. Typically, fracturing fluids contain various additives such as cross linkers, thickeners and proppants, and so forth, which makes it possess the properties of considerably complicated components and difficult processing procedure. There are still some difficult points needing to be explored and resolved in the hydroxypropyl guar gum (HPG) removal process, e.g., high viscosity and removal of macromolecular organic compounds. Our works provided a facile and economical HPG removal technology for fracturing fluids by designing a series of processes including gel-breaking, coagulation and precipitation according to the diffusion double layer theory. After this treatment process, the fracturing fluid can meet the requirements of reinjection, and the whole process was environment friendly without secondary pollution characteristics. In this work, the fracturing fluid were characterized by scanning electron microscopy (SEM), Energy dispersive X-ray (EDX), X-ray diffraction (XRD) and Fourier transformed infrared (FTIR) spectroscopy technologies, etc. Further, the micro-stabilization and destabilization mechanisms of HPG in fracturing fluid were carefully investigated. This study maybe opens up new perspective for HPG removal technologies, exhibiting a low cost and strong applicability in both fundamental research and practical applications.

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Xu, Ke, Yongjun Lu, Jin Chang et Yang Li. « Research Progress of High Temperature Resistant Fracturing Fluid System ». Journal of Physics : Conference Series 2076, n^o 1 (1 novembre 2021) : 012039. http://dx.doi.org/10.1088/1742-6596/2076/1/012039.

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Abstract China has made significant progress in the efficient exploration and development of deep-seated oil and gas wells. Reservoir reformation, as the core tool of high-temperature deep-seated exploration and development, puts forward a strong demand for fracturing fluids. The ultra-high temperature fracturing fluid system developed in my country is mainly divided into two types: ultra-high temperature guar gum fracturing fluid and ultra-high temperature synthetic polyacrylamide fracturing fluid. The high temperature resistant fracturing fluid system is mainly composed of high temperature resistant thickener, high temperature resistant crosslinking agent and temperature stabilizing additives and other additives. Based on indoor research and a large amount of literature, this article summarizes the research and application of high temperature resistant fracturing fluid system, high temperature resistant thickener, high temperature resistant crosslinking agent and temperature stabilizing additives in my country in recent years, and pointed out the shortcomings and limitations of the high-temperature fracturing fluid, the technical direction of the development of high-temperature resistant fracturing fluid technology is proposed.

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Lu, Cong, Li Ma, Zhili Li, Fenglan Huang, Chuhao Huang, Haoren Yuan, Zhibin Tang et Jianchun Guo. « A Novel Hydraulic Fracturing Method Based on the Coupled CFD-DEM Numerical Simulation Study ». Applied Sciences 10, n^o 9 (26 avril 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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Tang, Yong, Bin Wang, Fanhua Zeng et Jun Wang. « The Key and the Countermeasures Research of Shale Gas Fracturing Technology ». Open Petroleum Engineering Journal 8, n^o 1 (19 août 2015) : 325–32. http://dx.doi.org/10.2174/1874834101508010325.

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Shale gas resources are abundantly distributed with low porosity and permeability. Horizontal well and fracturing are prior considerations. Fracturing is a widely-used technology to enhance gas production. In this paper, the author (a) investigated the present stimulation of Barnett and Haynesvile gas fields (Fig. 1) in America, Sichuan basin (Fig. 2) in China and Cooper basin (Fig. 3) in Australia; (b) compared different characteristics and limitations of multi-stage fracturing, water-fracturing, simultaneous fracturing, net fracturing, refracturing and hydraulic jet fracturing; (c) analyzed the critical point of the shale fracturing; (d) offered solutions to the fracturing fluid manufacture, selection and improvement of the fracturing fluids, fractures extension, equipments, fracturing effect evaluation and reservoir protection. It has a farreaching significance to improve fracturing and stimulation of shale gas reservoirs, in view of the high risk, low success ratio and poor stimulation effect the shale gas exploration would face.

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Liu, Peng, Caili Dai, Mingwei Gao, Xiangyu Wang, Shichun Liu, Xiao Jin, Teng Li et Mingwei Zhao. « Development of the Gemini Gel-Forming Surfactant with Ultra-High Temperature Resistance to 200 °C ». Gels 8, n^o 10 (20 septembre 2022) : 600. http://dx.doi.org/10.3390/gels8100600.

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In order to broaden the application of clean fracturing fluid in ultra-high temperature reservoirs, a surfactant gel for high-temperature-resistant clean fracturing fluid was developed with a gemini cationic surfactant as the main agent in this work. As the fracturing fluid, the rheological property, temperature resistance, gel-breaking property, filtration property, shear recovery performance and core damage property of surfactant gel were systematically studied and evaluated. Results showed the viscosity of the system remained at 25.2 mPa·s for 60 min under a shear rate of 170 s−1 at 200 °C. The observed core permeability damage rate was only 6.23%, indicating low formation damage after fracturing. Due to micelle self-assembly properties in surfactant gel, the fluid has remarkable shear self-repairability. The filtration and core damage experimental results meet the national industry standard for fracturing fluids. The gel system had simple formulation and excellent properties, which was expected to enrich the application of clean fracturing fluid in ultra-high temperature reservoirs.

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Yu, Xiaoxi, Yuan Li, Yuquan Liu, Yuping Yang et Yining Wu. « Flow Patterns of Viscoelastic Fracture Fluids in Porous Media : Influence of Pore-Throat Structures ». Polymers 11, n^o 8 (2 août 2019) : 1291. http://dx.doi.org/10.3390/polym11081291.

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Viscoelastic surfactant (VES) fluid and hydrolyzed polyacryamide (HPAM) solution are two of the most common fracturing fluids used in the hydraulic fracturing development of unconventional reservoirs. The filtration of fracturing fluids in porous media is mainly determined by the flow patterns in pore-throat structures. In this paper, three different microdevices analogue of porous media allow access to a large range of Deborah number (De) and concomitantly low Reynolds number (Re). Continuous pore-throat structures were applied to study the feedback effect of downstream structure on upstream flow of VES fluid and HPAM solution with Deborah (De) number from 1.11 to 146.4. In the infinite straight channel, flow patterns between VES fluids and HPAM solution were similar. However, as pore length shortened to 800 μm, flow field of VES fluid exhibited the triangle shape with double-peaks velocity patterns. The flow field of HPAM solution presented stable and centralized streamlines when Re was larger than 4.29 × 10−2. Additionally, when the pore length was further shortened to 400 μm, double-peaks velocity patterns were vanished for VES fluid and the stable convergent flow characteristic of HPAM solution was observed with all flow rates.

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