A polymer-based fracturing fluid and its application

Abstract

The present invention provides a polymer-based fracturing fluid and its application. The fracturing fluid provided by the present invention comprises a flowback promoter, a polymer thickener, a clay stabilizer, a drainage aid and water. The flowback promoter comprises ammonium chloride, sodium nitrite and a flow enhancer. The flow enhancer is a chemically loaded product of a compound shown in the structural diagram of Formula I on nano-silica; wherein A is a naphthalene ring at an optional substituted position; n is an integer from 1 to 10; n Rs are independently selected from a chemical single bond and C1 to C 10 One of the alkylene groups; n Xs are independently selected from -O- or -NH-, and at least one X is -NH-.

Description

[0001] Related applications

[0002] This application claims priority to Chinese patent application CN202310621396.0, entitled “A polymer-based fracturing fluid and its application,” filed on May 30, 2023, and incorporates the entire contents of CN202310621396.0 into this document by reference. Technical Field

[0003] The invention belongs to the technical field of oil and gas reservoir transformation, and in particular relates to a polymer-based fracturing fluid and application thereof. Background Art

[0004] Low-permeability tight oil and gas reservoirs are mostly medium- and low-permeability, with low and ultra-low permeability reservoirs comprising a significant proportion. These reservoirs exhibit significant heterogeneity, low porosity, poor connectivity, and high sensitivity. Experiments are underway both domestically and internationally to utilize volumetric fracturing technology in tight sandstone gas reservoirs. Volumetric fracturing breaks up the reservoir matrix through fracturing. The resulting fractures are primarily shear fractures, followed by tearing fractures that exhibit a combination of tensile and shear fractures, resulting in complex fracture morphologies. Over time, shear fractures and tearing fractures can transform into tensile fractures. This transition is particularly prevalent near the wellbore, forming a network of fractures. This maximizes the contact area between the fracture wall and the reservoir matrix, minimizing the distance for oil and gas to flow from the matrix into the fractures and minimizing the resistance to matrix fluid flow. This significantly improves the overall permeability of the reservoir, achieving a three-dimensional transformation of the reservoir in terms of length, width, and height.

[0005] Polymer thickeners (powders, emulsions) are a key component of the polymer fracturing fluid system used in volumetric fracturing. Polymer fracturing fluids cause significant damage to the reservoir core matrix, with damage rates exceeding 70% and permeability recovery rates in gas-tested cores exceeding 30%. The main factors causing matrix damage include polymer residue in the fracturing fluid, thickener adsorption and retention damage, water lock, and water sensitivity. In particular, the high density of hydrophilic groups in polymer thickeners leads to greater core adsorption and retention damage than plant gums such as guar gum. This directly reduces oil and gas flow channels, hinders oil and gas flowback within the matrix, and results in insignificant oil and gas production increases.

[0006] In view of the above situation, it is necessary to carry out research on flowback promoters, and on this basis form strong flowback fracturing fluids, which can not only provide additional flowback energy, but also overcome the adsorption and retention problems of thickeners, reduce liquid flow resistance, and improve the fracturing transformation effect. Summary of the Invention

[0007] The object of the present invention is to provide a fracturing fluid which can not only overcome the adsorption and retention problem of polymer thickeners, but also reduce the flow resistance of liquid and cause less damage to low-permeability reservoirs.

[0008] The present invention provides a fracturing fluid, which comprises a flowback promoter, a polymer thickener, a clay stabilizer, a drainage aid and water.

[0009] According to a specific embodiment of the present invention, taking the mass of the water as 100%, the mass concentration of the flowback promoter is 12.4wt% to 18.7%, the mass concentration of the polymer thickener is 0.01wt% to 0.75wt%, the mass concentration of the clay stabilizer is 0.1wt% to 1wt%, and the mass concentration of the drainage aid is 0.1wt% to 1wt%;

[0010] Preferably, taking the mass of the water as 100%, the mass concentration of the flowback promoter is 12.4wt% to 18.7wt%, the mass concentration of the polymer thickener is 0.05wt% to 0.3wt%, the mass concentration of the clay stabilizer is 0.2wt% to 0.3wt%, and the mass concentration of the drainage aid is 0.2wt% to 0.4wt%.

[0011] According to a specific embodiment of the present invention, the flowback promoter includes ammonium chloride, sodium nitrite and a flow enhancer.

[0012] According to a specific embodiment of the present invention, taking the mass of the flowback promoter as 100%, the flowback promoter includes 42.8 wt% to 43 wt% of ammonium chloride, 55.2 wt% to 55.5 wt% of sodium nitrite and 1.6 wt% to 2 wt% of the flow enhancer.

[0013] According to a specific embodiment of the present invention, the flow enhancer is a chemically supported product of a compound as shown in Formula I on nano-silica;

[0014]

[0015] Wherein, A is a naphthalene ring optionally substituted at a position; n is an integer from 1 to 10; n Rs are independently selected from chemical single bonds and C1 to C 10 n X are independently selected from -O- or -NH-, and at least one X is -NH-.

[0016] According to a specific embodiment of the present invention, the average particle size of the nano-silicon dioxide is 1 nm to 50 nm;

[0017] Preferably, the nano-silica is hydroxylated nano-silica.

[0018] According to a specific embodiment of the present invention, in Formula I, n is an integer from 2 to 6; and / or

[0019] The n Rs are independently selected from one of a chemical single bond and a C1 to C4 alkylene group.

[0020] According to a specific embodiment of the present invention, the compound is hydroxyaminonaphthalene;

[0021] Preferably, the compound is 2,3-dihydroxy-1-methylaminonaphthalene.

[0022] According to a specific embodiment of the present invention, the flow enhancer is prepared by the following method:

[0023] The hydroxylated nano-silica and hydroxyaminonaphthalene are reacted in water to obtain the flow enhancer;

[0024] Preferably, the mass ratio of the hydroxylated modified nano-silica to hydroxyaminonaphthalene is 1:2 to 1:4;

[0025] Preferably, the first reaction is carried out at 60°C to 80°C for 20 to 24 hours;

[0026] Preferably, the hydroxylated nano-silica is prepared by the following method:

[0027] Allowing the nano-silica to undergo a second reaction in concentrated sulfuric acid to obtain the hydroxylated nano-silica;

[0028] Preferably, before hydroxylation modification, the particle size of the nano-silica is 1 nm to 50 nm;

[0029] Preferably, the concentration of the concentrated sulfuric acid is 70% to 98%, and the volume / mass ratio of the concentrated sulfuric acid to the nano-silicon dioxide is 1:(0.01 to 0.1);

[0030] Preferably, the second reaction is carried out at 120° C. to 150° C. for 10 to 12 hours.

[0031] According to a specific embodiment of the present invention, the hydroxyaminonaphthalene is prepared by the following method:

[0032] A. subjecting halomethoxynaphthalene and copper cyanide to a third reaction to obtain a first intermediate product;

[0033] B. subjecting the first intermediate product to a fourth reaction with lithium aluminum tetrahydride to obtain a second intermediate product;

[0034] C. subjecting the second intermediate product to a fifth reaction in an acidic environment;

[0035] D. subjecting the reaction product obtained by the fifth reaction and butyllithium to a sixth reaction;

[0036] E. subjecting the reaction product obtained by the sixth reaction to a seventh reaction in a neutral or alkaline environment to obtain the hydroxyaminonaphthalene.

[0037] According to a specific embodiment of the present invention, the halomethoxynaphthalene is 1-bromo-2,3-dimethoxynaphthalene; and / or

[0038] The hydroxyaminonaphthalene is 2,3-dihydroxy-1-methylaminonaphthalene.

[0039] According to a specific embodiment of the present invention, the molar ratio of the halomethoxynaphthalene to copper cyanide is 1:1 to 2:1;

[0040] and / or

[0041] The molar ratio of the halomethoxynaphthalene to the lithium aluminum hydroxide is 1:1 to 2:1; and / or

[0042] The molar ratio of the halomethoxynaphthalene to the butyl lithium is 1:1.

[0043] According to a specific embodiment of the present invention, in step A, the third reaction is carried out in a first organic solvent; and / or

[0044] In step B, the fourth reaction is carried out in a second organic solvent; and / or

[0045] In step C, a carboxylic acid-lower alcohol mixture is added to create the acidic environment; and / or

[0046] In step E, an inorganic base is added to adjust the pH to neutral or alkaline;

[0047] Preferably, the first organic solvent is N-methylpyrrolidone; and / or

[0048] The second organic solvent is diethyl ether; and / or

[0049] The carboxylic acid-lower alcohol mixture is a mixture of formic acid and ethanol; and / or

[0050] The inorganic base is sodium hydroxide;

[0051] Preferably, the total mass of the halomethoxynaphthalene, copper cyanide, lithium aluminum tetrahydride and butyl lithium is 100wt%, the amount of the formic acid is 1wt% to 2wt%, and the amount of the ethanol is 3wt% to 5wt%; and / or

[0052] The acidic environment refers to a pH of 3 to 5; and / or

[0053] In step E, the pH is adjusted to 7 to 9.

[0054] According to a specific embodiment of the present invention, the conditions of the third reaction are to react at 200° C. for 4 to 6 hours;

[0055] and / or

[0056] The fourth reaction is carried out at room temperature (ie 25° C.) for 2 to 3 hours; and / or

[0057] The conditions of the fifth reaction are reaction at 60° C. for 2 h; and / or

[0058] The sixth reaction is carried out under the following conditions: reacting at room temperature (i.e. 25° C.) for 1 hour; and / or

[0059] The seventh reaction was carried out at 50° C. for 5 h.

[0060] According to a specific embodiment of the present invention, the clay stabilizer is an alkyl ammonium salt;

[0061] Preferably, the alkylammonium salt is cetyltrimethylammonium chloride; and / or

[0062] The polymer thickener is selected from polyacrylamide and / or acrylamide copolymer; and / or

[0063] The drainage agent is polyoxyethylene ether;

[0064] Preferably, the weight average molecular weight of the polymer thickener is not less than 10 million;

[0065] Preferably, the acrylamide copolymer is a 2-acrylamido-2-methylpropanesulfonic acid / acrylamide / maleic anhydride copolymer, an acrylamide / N,N-dimethylacrylamide / 2-acrylamido-2-methylpropanesulfonic acid copolymer, or an acrylamide / 2-acrylamido-2-methylpropanesulfonic acid / 2-acrylamidohexadecanesulfonic acid copolymer;

[0066] Preferably, the polymer thickener is polyacrylamide;

[0067] Preferably, the weight average molecular weight of the polyacrylamide is 10 million to 20 million.

[0068] In the present invention, the weight average molecular weight of the polymer thickener can be adjusted according to the target reservoir to be actually fractured.

[0069] Application of the fracturing fluid according to the present invention in fracturing reconstruction of low permeability tight oil and gas reservoirs;

[0070] Preferably, the low-permeability tight sandstone oil and gas reservoir is an oil and gas reservoir with a ground pressure coefficient lower than 1 and an average permeability lower than 0.1 mD. Beneficial effects of the present invention:

[0071] In view of the problems of adsorption and retention of polymer thickeners, high flow resistance of return liquid, and high damage to low-permeability reservoirs in the fracturing fluid of the existing volume fracturing technology, the present invention provides a polymer-based fracturing fluid and its application. The fracturing fluid includes a return promoter, a polymer thickener, a clay stabilizer, a drainage aid and water. Among them, the return promoter includes ammonium chloride, sodium nitrite and a flow enhancer, and there is a synergistic effect between the three in enhancing the return capacity of the fracturing fluid. The fracturing fluid provided by the present invention can generate additional fluid return energy by spontaneous gas at reservoir temperature, while reducing the adsorption and retention of polymer thickeners on the rock surface, and can reduce the starting pressure of the liquid in the core, reduce the flow resistance of the liquid, improve the return capacity of the fracturing fluid, and ultimately greatly reduce the damage of the fracturing fluid to the low-permeability reservoir. It is a fracturing fluid that can not only overcome the adsorption and retention problem of the polymer thickener, but also reduce the flow resistance of the liquid and cause less damage to the low-permeability reservoir. When the breaker prepared by mixing the fracturing fluid provided by the present invention with a low-temperature breaker passes through a powder consisting of core particles with an average porosity of 10% and an average permeability of 0.001 mD, the amount of thickener adsorbed on the core particles is 6.8 to 9.1 mg·g -1 At 90°C, a confining pressure of 10 MPa was fixed and the displacement pressure was slowly increased. Nitrogen was used to displace a breaker prepared by mixing the fracturing fluid with a low-temperature breaker. The starting pressure of the breaker containing the fracturing fluid in the experimental rock samples sampled from low-permeability tight sandstone was only 0.32 to 0.56 MPa. According to the method specified in 7.7 of SY / T 5107-2016 "Performance Evaluation Method of Water-Based Fracturing Fluid", a core displacement experiment was conducted on the experimental rock samples sampled from low-permeability tight sandstone at 90°C using the breaker prepared by mixing the fracturing fluid with a low-temperature breaker as the test medium. The measured flowback rate was 71% to 83%, and the damage rate of the fracturing fluid to the matrix permeability of the experimental rock samples was only 20% to 27%. BRIEF DESCRIPTION OF THE DRAWINGS

[0072] Figure 1 This is the infrared spectrum of 2,3-dihydroxy-1-methylaminonaphthalene prepared in Example 1;

[0073] Figure 2 This is a diagram of the device for measuring the amount of thickener adsorption;

[0074] Figure 3 Diagram of the core starting pressure measurement device. DETAILED DESCRIPTION

[0075] The present invention will be further described below with reference to examples. However, the examples are merely illustrative and do not limit the present invention in any way.

[0076] Preparation of flow enhancer

[0077] Example 1

[0078] Preparation of 2,3-dihydroxy-1-methylaminonaphthalene:

[0079] A. 1 mol (i.e., 267 g) of 1-bromo-2,3-dimethoxynaphthalene, 1 mol (i.e., 115.6 g) of copper cyanide, and 2 g of N-methylpyrrolidone were mixed and reacted at 200° C. for 4 h to obtain a first intermediate product, which can be directly used in step B without purification;

[0080] B. The obtained first intermediate product, 1 mol (i.e., 38 g) of lithium aluminum tetrahydride, and 5 g of diethyl ether were mixed and reacted at room temperature (25° C.) for 2 h to obtain a second intermediate product, which could be directly used in step C without purification;

[0081] C. Add a formic acid-ethanol mixture (including 9.69 g of formic acid and 24.2 g of ethanol), adjust the pH of the second intermediate product to 3, react at 60°C for 2 hours, then cool to room temperature (25°C) and add 1 mol (i.e., 64 g) of butyl lithium, react for 1 hour, and finally add sodium hydroxide to adjust the pH to 7, raise the temperature to 50°C and react for 5 hours to obtain 2,3-dihydroxy-1-methylaminonaphthalene.

[0082] Structural characterization of 2,3-dihydroxy-1-methylaminonaphthalene:

[0083] The pure 2,3-dihydroxy-1-methylaminonaphthalene product obtained after recrystallization from ethanol was measured with a Fourier transform infrared spectrometer. Figure 1 .

[0084] from Figure 1 It can be seen that the infrared spectrum shows 1-hydroxyl stretching vibration peak, 4-amino stretching vibration peak, 2-naphthalene ring stretching vibration peak, 3-amino bending vibration peak and 5-hydroxyl bending vibration peak. Combined with the preparation process, it is confirmed that 2,3-dihydroxy-1-methylaminonaphthalene is prepared.

[0085] Preparation of hydroxylated modified nano-silica:

[0086] 5 g of nano-silica with a particle size of 1 to 50 nm was mixed with 100 mL of 98% concentrated sulfuric acid and reacted at 150° C. for 12 h to obtain hydroxylated modified nano-silica.

[0087] Prepare flow enhancer:

[0088] 25 g of hydroxylated modified nano-silica, 50 g of 2,3-dihydroxy-1-methylaminonaphthalene and 25 g of water were mixed and reacted at 80° C. for 24 h to obtain a flow enhancer.

[0089] Preparation of fracturing fluid

[0090] The flow enhancers used in Examples 2 to 8 and Comparative Example 2 were all the flow enhancers prepared in Example 1.

[0091] The polymer thickener used in Examples 2 to 8 and Comparative Examples 1 to 3 is polyacrylamide, which complies with standard Q / SHCG 0149 and is purchased from Dongying Zhongyue Petroleum Technology Co., Ltd. The weight average molecular weight thereof is determined to be 10 million to 20 million.

[0092] Example 2

[0093] Preparation of fracturing fluid:

[0094] 1) Mix a flowback promoter (specifically comprising 5.35 g ammonium chloride, 6.9 g sodium nitrite, and 0.2 g flow enhancer), 0.3 g hexadecyltrimethylammonium chloride, and 100 g water in a mixing container and continue stirring until completely dissolved;

[0095] 2) Add 0.05 g of polyacrylamide to the solution container in step 1) and continue stirring until the polyacrylamide is completely dissolved;

[0096] 3) Add 0.3 g of polyoxyethylene ether to the liquid preparation container in step 2), continue stirring until the polyoxyethylene ether is completely dissolved, avoid foam overflow during the stirring process, and stir evenly to obtain the fracturing fluid.

[0097] Example 3

[0098] Preparation of fracturing fluid:

[0099] 1) Mix a flowback promoter (specifically comprising 5.35 g ammonium chloride, 6.9 g sodium nitrite, and 0.2 g flow enhancer), 0.3 g hexadecyltrimethylammonium chloride, and 100 g water in a mixing container and continue stirring until completely dissolved;

[0100] 2) Add 0.1 g of polyacrylamide to the solution preparation container in step 1) and continue stirring until the polyacrylamide copolymer is completely dissolved;

[0101] 3) Add 0.3 g of polyoxyethylene ether to the liquid preparation container in step 2), continue stirring until the polyoxyethylene ether is completely dissolved, avoid foam overflow during the stirring process, and stir evenly to obtain the fracturing fluid.

[0102] Example 4

[0103] Preparation of fracturing fluid:

[0104] 1) Mix a flowback promoter (specifically comprising 5.35 g ammonium chloride, 6.9 g sodium nitrite, and 0.2 g flow enhancer), 0.2 g hexadecyltrimethylammonium chloride, and 100 g water in a mixing container and continue stirring until completely dissolved;

[0105] 2) Add 0.1 g of polyacrylamide to the solution container in step 1) and continue stirring until the polyacrylamide is completely dissolved;

[0106] 3) Add 0.3 g of polyoxyethylene ether to the liquid preparation container in step 2), continue stirring until the polyoxyethylene ether is completely dissolved, avoid foam overflow during the stirring process, and stir evenly to obtain the fracturing fluid.

[0107] Example 5

[0108] Preparation of fracturing fluid:

[0109] 1) Mix a flowback promoter (specifically comprising 5.35 g ammonium chloride, 6.9 g sodium nitrite, and 0.2 g flow enhancer), 0.3 g hexadecyltrimethylammonium chloride, and 100 g water in a mixing container and continue stirring until completely dissolved;

[0110] 2) Add 0.1 g of polyacrylamide to the solution container in step 1) and continue stirring until the polyacrylamide is completely dissolved;

[0111] 3) Add 0.2 g of polyoxyethylene ether to the liquid preparation container in step 2), continue stirring until the polyoxyethylene ether is completely dissolved, avoid foam overflow during the stirring process, and stir evenly to obtain the fracturing fluid.

[0112] Example 6

[0113] Preparation of fracturing fluid:

[0114] 1) Mix a flowback promoter (specifically comprising 6.42 g ammonium chloride, 8.28 g sodium nitrite, and 0.3 g flow enhancer), 0.3 g hexadecyltrimethylammonium chloride, and 100 g water in a mixing container and continue stirring until completely dissolved;

[0115] 2) Add 0.2 g of polyacrylamide to the solution container in step 1) and continue stirring until the polyacrylamide is completely dissolved;

[0116] 3) Add 0.3 g of polyoxyethylene ether to the liquid preparation container in step 2), continue stirring until the polyoxyethylene ether is completely dissolved, avoid foam overflow during the stirring process, and stir evenly to obtain the fracturing fluid.

[0117] Example 7

[0118] Preparation of fracturing fluid:

[0119] 1) Mix a flowback promoter (specifically comprising 6.42 g ammonium chloride, 8.28 g sodium nitrite, and 0.3 g flow enhancer), 0.3 g hexadecyltrimethylammonium chloride, and 100 g water in a mixing container and continue stirring until completely dissolved;

[0120] 2) Add 0.3 g of polyacrylamide to the solution container in step 1) and continue stirring until the polyacrylamide is completely dissolved;

[0121] 3) Add 0.4 g of polyoxyethylene ether to the liquid preparation container in step 2), continue stirring until the polyoxyethylene ether is completely dissolved, avoid foam overflow during the stirring process, and stir evenly to obtain the fracturing fluid.

[0122] Example 8

[0123] Preparation of fracturing fluid:

[0124] 1) Mix a flowback promoter (specifically comprising 8.025 g of ammonium chloride, 10.35 g of sodium nitrite, and 0.3 g of a flow enhancer), 0.3 g of hexadecyltrimethylammonium chloride, and 100 g of water in a mixing container and continue stirring until completely dissolved;

[0125] 2) Add 0.2 g of polyacrylamide to the solution container in step 1) and continue stirring until the polyacrylamide is completely dissolved;

[0126] 3) Add 0.3 g of polyoxyethylene ether to the liquid preparation container in step 2), continue stirring until the polyoxyethylene ether is completely dissolved, avoid foam overflow during the stirring process, and stir evenly to obtain the fracturing fluid.

[0127] Comparative Example 1

[0128] Preparation of fracturing fluid:

[0129] 1) Mix a flowback promoter (specifically comprising 8.025 g of ammonium chloride and 10.35 g of sodium nitrite), 0.3 g of hexadecyltrimethylammonium chloride, and 100 g of water in a liquid preparation container and continue stirring until completely dissolved;

[0130] 2) Add 0.2 g of polyacrylamide to the solution container in step 1) and continue stirring until the polyacrylamide is completely dissolved;

[0131] 3) Add 0.3 g of polyoxyethylene ether to the liquid preparation container in step 2), continue stirring until the polyoxyethylene ether is completely dissolved, avoid foam overflow during the stirring process, and stir evenly to obtain the fracturing fluid.

[0132] Comparative Example 2

[0133] Preparation of fracturing fluid:

[0134] 1) Mix a flowback promoter (specifically 0.2 g of flow enhancer), 0.3 g of hexadecyltrimethylammonium chloride, and 100 g of water in a mixing container and continue stirring until completely dissolved;

[0135] 2) Add 0.2 g of polyacrylamide to the solution container in step 1) and continue stirring until the polyacrylamide is completely dissolved;

[0136] 3) Add 0.3 g of polyoxyethylene ether to the liquid preparation container in step 2), continue stirring until the polyoxyethylene ether is completely dissolved, avoid foam overflow during the stirring process, and stir evenly to obtain the fracturing fluid.

[0137] Comparative Example 3

[0138] Preparation of fracturing fluid:

[0139] 1) Mix 0.3 g of hexadecyltrimethylammonium chloride and 100 g of water in a mixing container and continue stirring until completely dissolved;

[0140] 2) Add 0.2 g of polyacrylamide to the solution container in step 1) and continue stirring until the polyacrylamide is completely dissolved;

[0141] 3) Add 0.3 g of polyoxyethylene ether to the liquid preparation container in step 2), continue stirring until the polyoxyethylene ether is completely dissolved, avoid foam overflow during the stirring process, and stir evenly to obtain the fracturing fluid.

[0142] Fracturing fluid performance evaluation

[0143] 1. Determination of gas volume generated by fracturing fluid reaction

[0144] i. Directly placing the fracturing fluids prepared in Examples 2 to 8 and Comparative Examples 1 to 3 into sealed wide-mouth bottles with air guide tubes, and connecting the outlets of the air guide tubes to a gas collection device;

[0145] ⅱ Place the wide-mouth bottle containing the fracturing fluid in a constant temperature water bath, heat it to 90℃ and then keep the temperature constant. Collect the gas generated by the fracturing fluid reaction until no more gas is generated. Calculate the amount of gas generated, which is the reaction gas volume of the fracturing fluid.

[0146] See Table 1 for specific results.

[0147] Table 1. Gas production from fracturing fluid reaction

[0148]

[0149]

[0150] As shown in Table 1, the fracturing fluids containing ammonium chloride and sodium nitrite prepared in Examples 2 to 8 reacted to generate gas at 90°C. Comparison of the data in Example 8 with Comparative Example 1 shows that the addition of a flow enhancer did not significantly affect the gas generation from the reaction of ammonium chloride and sodium nitrite. The fracturing fluids prepared in Comparative Examples 2 and 3 did not contain sodium nitrite and ammonium chloride and were unable to generate gas. The mass of sodium nitrite and ammonium chloride in the fracturing fluids prepared in Examples 2 to 5 was equal, and the amount of gas generated by the reaction was almost unchanged. The mass of sodium sulfite and ammonium chloride in the fracturing fluids prepared in Examples 6 and 7 was equal, and the mass of sodium nitrite and ammonium chloride, as well as the total mass proportion of sodium nitrite and ammonium chloride in the fracturing fluids, was greater than that in Examples 2 to 5, resulting in a greater amount of gas generated by the reaction. The mass of sodium nitrite and ammonium chloride in the fracturing fluid prepared in Example 8, as well as the total mass proportion of sodium nitrite and ammonium chloride in the fracturing fluids, was greater than that in Examples 6 and 7, resulting in a greater amount of gas generated by the reaction. Therefore, the total mass proportion of sodium nitrite and ammonium chloride in the fracturing fluid is positively correlated with the amount of reaction gas generated. The greater the total mass proportion of sodium nitrite and ammonium chloride in the fracturing fluid, the more reaction gas generated, the stronger the pressure-increasing ability of the formation, and the better it is to improve the flowback of the fracturing fluid.

[0151] 2. Determination of thickener adsorption capacity, starting pressure, flowback rate and matrix permeability damage rate

[0152] The low-temperature breakers used in the following experiments were purchased from Dongying Zhongyue Petroleum Technology Co., Ltd.

[0153] A. Determination of Thickener Adsorption

[0154] use Figure 2 The apparatus shown was used to measure the thickener adsorption capacity of the fracturing fluids prepared in Examples 2 to 8 and Comparative Examples 1 to 3, and to evaluate the ability of the fracturing fluids to reduce the adsorption damage of the thickener to the core. The specific method is as follows:

[0155] (1) directly adding 600 ppm of low-temperature breaker to the fracturing fluids prepared in Examples 2 to 8 and Comparative Examples 1 to 3, and then aging the fracturing fluids at 35°C for 24 h until the viscosity of the fracturing fluids after adding the low-temperature breaker is less than 5 mPa.s, and then taking out the fracturing fluids to obtain 10 groups of breaker fluids for standby use;

[0156] (2) First, any one of the 10 groups of gel-breaking solutions prepared in step (1) is loaded into an intermediate container; the sand filling tube of the high-temperature and high-pressure filter loss instrument is filled with core particles with a particle size of 0.21 to 0.3 mm (i.e., 70 to 50 mesh), an average porosity of 10%, and an average permeability of 0.001 mD, and then the high-temperature and high-pressure filter loss instrument is preheated to 90°C;

[0157] (3) Close the valve connecting the nitrogen bottle to the high-temperature and high-pressure filter loss instrument, open the valve connecting the high-temperature and high-pressure filter loss instrument to the intermediate container, and drive the flow pump to allow the gel-breaking liquid in the intermediate container to pass through the high-temperature and high-pressure filter loss instrument preheated to 90°C and filled with core particles at a displacement of 5 mL / min. After all the gel-breaking liquid enters the gel-breaking liquid collector, close the valve connecting the high-temperature and high-pressure filter loss instrument to the intermediate instrument, then open the valve connecting the nitrogen bottle to the high-temperature and high-pressure filter loss instrument, and continue to purge with nitrogen for 10 minutes to prevent the gel-breaking liquid from being mechanically retained in the high-temperature and high-pressure filter loss instrument;

[0158] (4) Obtain a sample of the broken gel liquid from the broken gel liquid collector, detect the residual thickener content therein using an ultraviolet spectrophotometer, and calculate the amount of thickener adsorbed by the core particles in the sand filling tube of the high-temperature and high-pressure filter loss meter using formula (1);

[0159]

[0160] Wherein, F is the adsorption amount of thickener, g / g;

[0161] m is the mass of thickener in the gel breaking liquid in the intermediate container without sand filling, g;

[0162] C is the concentration of thickener in the gel-breaking liquid after passing through the sand-filling tube in the gel-breaking liquid collector, g / L;

[0163] V is the volume of the gel-breaking liquid that passes through the sand-filling tube in the gel-breaking liquid collector, L.

[0164] According to steps (2) to (4), experiments were carried out using 10 groups of gel breaking solutions prepared in step (1). The specific results are shown in Table 2.

[0165] B. Start pressure measurement

[0166] use Figure 3 The core starting pressure measuring device shown is used to measure the starting pressure of the fracturing fluid prepared in Examples 2 to 8 and Comparative Examples 1 to 3 when flowing back from the core. The specific steps are as follows:

[0167] ① Drill multiple cores from the same low-permeability, dense sandstone core sample, cut them into samples of equal length, then dry them in an oven at 105°C for 24 hours and place them in a drying dish for later use;

[0168] ② Directly add 600 ppm of low-temperature breaker to the fracturing fluids prepared in Examples 2 to 8 and Comparative Examples 1 to 3, respectively, and then age at 35°C for 24 hours until the viscosity of the fracturing fluids after adding the low-temperature breaker is less than 5 mPa.s, and then remove them to obtain 10 groups of breaker fluids for standby use;

[0169] ③ Use an overburden porosimeter to measure the porosity and permeability of the dried rock samples obtained in step ①. Select 10 rock samples with basically consistent porosity and permeability (average porosity 10% and average permeability 0.001 mD) as experimental rock samples. Then, according to the initial water saturation establishment method in Section 5.1.5 of Q / SH 0501-2013 "Flow Experiment Evaluation Method for Tight Reservoir Sensitivity", use the 10 groups of gel-breaking solutions prepared in step ② to establish an initial saturation of 40% for each of the 10 experimental rock samples.

[0170] ④ First, select any one of the 10 experimental rock samples with an initial breaker saturation of 40% obtained in step ③ and place it in the core holder. Then, adjust the confining pressure pump to apply a confining pressure of 10 MPa to the experimental core. Heat the core holder and the experimental rock sample held thereto to 90°C and maintain a constant temperature. Slowly adjust the input nitrogen pressure using a pressure reducing valve. Observe for 2 minutes each time the pressure is increased by 0.1 MPa to displace the breaker liquid until nitrogen flows out of the soap foam flowmeter. The nitrogen pressure at this point is the starting pressure of the experimental rock sample at an initial breaker saturation of 40%.

[0171] According to the method in step ④, the starting pressures of the 10 experimental rock samples with an initial saturation of 40% breaker solution obtained in step ③ were measured respectively. The specific results are shown in Table 2.

[0172] C. Determination of flowback rate and matrix permeability damage rate

[0173] According to 7.7 of SY / T 5107-2016 “Performance Evaluation Method of Water-Based Fracturing Fluids”, the flowback rate and matrix permeability damage rate were determined.

[0174] In the determination of the flowback rate and matrix permeability damage rate, the 10 groups of gel-breaking solutions prepared in step ② of Experiment B were used as the test medium.

[0175] a. Determination of flowback rate: For the experimental rock sample with an average porosity of 10% and an average permeability of 0.001 mD, an initial water saturation of 40% was established according to Section 5.1.5 of Q / SH0501-2013 “Flow Experiment Evaluation Method for Tight Reservoir Sensitivity”. The experimental rock sample with the obtained initial water saturation of 40% was placed in a core holder. The confining pressure pump was adjusted to apply a confining pressure of 10 MPa to the experimental rock sample. The core holder and the experimental rock sample clamped therein were then heated to 90°C and maintained at a constant temperature. One group of breaking fluids was selected from 10 groups of breaking fluids. A sufficient amount of breaking fluid (the volume was recorded as V1) was added to the intermediate container at the inlet end. The breaking fluid was driven through the core holder at a displacement pressure of 3.5 MPa. The breaking fluid that passed through the experimental rock sample was collected at the outlet end as the flowback fluid. The displacement time was 30 min. The volume of the collected flowback fluid was recorded as V2. The flowback rate was calculated using the following formula (2):

[0176]

[0177] b. Determination of matrix permeability damage rate: For experimental rock samples with an average porosity of 10% and an average permeability of 0.001 mD, an initial water saturation of 40% was established according to the method for establishing initial water saturation in Section 5.1.5 of Q / SH 0501-2013, "Flow Experimental Evaluation Methods for Tight Reservoirs." The resulting experimental rock sample with a water saturation of 40% was placed in a core holder. A confining pressure pump was adjusted to apply a confining pressure of 10 MPa to the experimental rock sample. The core holder and the experimental rock sample were then heated to 90°C and maintained at a constant temperature. At a displacement pressure of 3.5 MPa, a displacement experiment was conducted on the experimental rock sample using one of ten groups of breaking solutions (i.e., a sufficient amount of breaking solution was added to the intermediate container at the inlet end, and the breaking solution was driven through the core holder at a displacement pressure of 3.5 MPa). The matrix permeability damage rate of the experimental rock sample was analyzed.

[0178] According to the methods described in a and b, 10 groups of gel-breaking solutions were used to measure the flowback rate and matrix permeability damage rate. The specific results are shown in Table 2.

[0179] Table 2. Thickener adsorption capacity, starting pressure, flowback rate, matrix permeability damage rate

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[0181]

[0182] The data of thickener adsorption in Table 2 show that when the fracturing fluids prepared from Examples 2 to 8 and Comparative Example 2 containing flow enhancers pass through the powder composed of core particles, the thickener adsorption on the core particles is 6.8 to 9.8 mg·g -1 , the thickener adsorption amount is very low; when the gel-breaking liquid prepared by the fracturing fluid without flow enhancer prepared in Comparative Example 1 and Comparative Example 3 passes through the powder composed of core particles, the thickener adsorption amount on the core particles is 15.2 and 19.4 mg·g respectively. -1 The thickener adsorption amount is significantly higher than that of Examples 2 to 8 and Comparative Example 2, specifically 1.9 times and 2.4 times the thickener adsorption amount of Example 8, respectively. This demonstrates that the fracturing fluids containing flow enhancers prepared in Examples 2 to 8 and Comparative Example 2 have a significant thickener adsorption inhibitory effect, resulting in a low amount of thickener adsorption retention in the experimental rock samples, and can effectively reduce solid phase damage to the formation by the fracturing fluid in practical applications.

[0183] The starting pressure data and flowback rate data in Table 2 show that the starting pressure of the fracturing fluid prepared in Examples 2 to 8 is 0.32 to 0.56 MPa, and the flowback rate is 71% to 83%, while the starting pressure of the fracturing fluid prepared in Comparative Examples 1 to 3 is 1.18 to 2.3 MPa, and the flowback rate is 42% to 63%. The starting pressure of the fracturing fluid prepared in Comparative Examples 1 to 3 is significantly higher than that in Examples 1 to 8, and the flowback rate is significantly lower than that in Examples 2 to 8. The starting pressure of the fracturing fluid prepared in Comparative Examples 1 to 3 is 4.7 times, 3.7 times and 7.2 times the starting pressure of the fracturing fluid prepared in Example 8, and the flowback rate of the fracturing fluid prepared in Example 8 is 1.6 times, 1.3 times and 2 times that of Comparative Examples 1 to 3, respectively. The lower starting pressure and higher flowback rate prove that the fracturing fluid prepared in Examples 2 to 8 is easier to return to the formation.

[0184] The matrix permeability damage rate data in Table 2 show that the matrix permeability damage rate of the fracturing fluids prepared in Examples 2 to 8 is 20% to 27%, while the matrix permeability damage rate of the fracturing fluids prepared in Comparative Examples 1 to 3 is 35% to 50%, which proves that the fracturing fluids prepared in Examples 2 to 8 can significantly reduce the matrix permeability damage rate.

[0185] Combined with the data of thickener adsorption amount, starting pressure, backflow rate and matrix permeability damage rate of the fracturing fluids prepared in Examples 2 to 8 and Comparative Examples 1 to 3 in Table 2 and the formula analysis of the fracturing fluids prepared in Examples 2 to 8 and Comparative Examples 1 to 3: The fracturing fluid prepared in Comparative Example 3 does not contain a backflow promoter (i.e., ammonium chloride, sodium nitrite and flow enhancer), and its thickener adsorption amount, starting pressure and matrix permeability damage rate are the highest, and the backflow rate is the lowest. It can be seen that in actual application, the core damage caused to the formation, including solid phase damage, is the highest, and it is the least likely to flow back; compared with Comparative Example 3, the fracturing fluid prepared in Comparative Example 2 only adds a flow enhancer, and the thickener adsorption amount of the fracturing fluid prepared in Comparative Example 2 is , starting pressure and matrix permeability damage rate are all reduced compared with those in Comparative Example 3, while the flowback rate is significantly improved; compared with Comparative Example 3, only ammonium chloride and sodium nitrite are added to the fracturing fluid prepared in Comparative Example 1, and the thickener adsorption amount, starting pressure and matrix permeability damage rate of the fracturing fluid prepared in Comparative Example 1 are respectively reduced compared with those in Comparative Example 3, and the flowback rate is improved; compared with Comparative Example 3, the fracturing fluid prepared in Example 8 is added with a flowback promoter (i.e., ammonium chloride, sodium nitrite and flow enhancer), and the thickener adsorption amount, starting pressure and matrix permeability damage rate of the fracturing fluid prepared in Example 8 are respectively reduced by 58%, 86% and 60% compared with those in Comparative Example 3, and the flowback rate is improved by 98%. The above results show that in the fracturing fluid provided by the present invention, the ammonium chloride, sodium nitrite and flow enhancer in the flowback promoter have a synergistic effect in reducing the amount of thickener adsorbed by the fracturing fluid, reducing the starting pressure of the fracturing fluid flowback, reducing the matrix permeability damage rate and improving the flowback rate. It can not only improve the flowback capacity of the fracturing fluid, but also further reduce the solid phase damage of the fracturing fluid. It is a fracturing fluid that can overcome the adsorption and retention problems of polymer thickeners and reduce liquid flow resistance, and has lower damage to low-permeability reservoirs. In addition, the preparation method of the fracturing fluid provided by the present invention is simple and does not change the existing construction process. It is of great significance to reduce reservoir damage and improve oil and gas production efficiency.

[0186] Although the present invention has been described with reference to specific embodiments, those skilled in the art will appreciate that various modifications may be made without departing from the true spirit and scope of the invention. Furthermore, the subject matter, spirit, and scope of the invention may be modified in various ways to adapt to specific circumstances, materials, combinations of materials, and methods. All such modifications are intended to be within the scope of the claims.

Claims

1. A fracturing fluid comprising a flowback promoter, a polymer thickener, a clay stabilizer, a drainage aid, and water; in, The flowback promoter includes ammonium chloride, sodium nitrite and flow enhancer; The flow enhancer is a chemically supported product of a compound as shown in the structural diagram of Formula I on nano-silica; Wherein, the nano-silica is hydroxylated modified silica; Wherein, A is a naphthalene ring optionally substituted at a position; n is an integer from 3 to 10; n Rs are independently selected from chemical single bonds and C1 to C 10 n X are independently selected from -O- or -NH-, and at least two X are -O- and at least one X is -NH-.

2. The fracturing fluid according to claim 1, characterized in that Taking the mass of the water as 100%, the mass concentration of the flowback promoter is 12.4 wt% to 18.7 wt%, the mass concentration of the polymer thickener is 0.01 wt% to 0.75 wt%, the mass concentration of the clay stabilizer is 0.1 wt% to 1 wt%, and the mass concentration of the drainage aid is 0.1 wt% to 1 wt%.

3. The fracturing fluid according to claim 1, characterized in that Taking the mass of the flowback promoter as 100%, the flowback promoter includes 42.8 wt % to 43 wt % of ammonium chloride, 55.2 wt % to 55.5 wt % of sodium nitrite, and 1.6 wt % to 2 wt % of the flow enhancer.

4. The fracturing fluid according to claim 1, characterized in that The average particle size of the nano-silicon dioxide is 1 nm to 50 nm.

5. The fracturing fluid according to claim 1, characterized in that In Formula I, n is an integer from 3 to 6; and / or The n Rs are independently selected from one of a chemical single bond and a C1 to C4 alkylene group.

6. The fracturing fluid according to any one of claims 1 to 5, characterized in that The compound is hydroxyaminonaphthalene.

7. The fracturing fluid according to any one of claims 1 to 5, characterized in that The compound is 2,3-dihydroxy-1-methylaminonaphthalene.

8. The fracturing fluid according to any one of claims 1 to 5, characterized in that The clay stabilizer is an alkyl ammonium salt; and / or The polymer thickener is selected from polyacrylamide and / or acrylamide copolymer; and / or The drainage aid is polyoxyethylene ether.

9. The fracturing fluid according to claim 8, characterized in that The alkylammonium salt is hexadecyltrimethylammonium chloride; and / or The polymer thickener is polyacrylamide.

10. The fracturing fluid according to claim 8, characterized in that The weight average molecular weight of the polymer thickener is not less than 10 million.

11. Use of the fracturing fluid according to any one of claims 1 to 10 in fracturing reconstruction of low permeability tight oil and gas reservoirs.

12. The use according to claim 11, characterized in that The low-permeability tight sandstone oil and gas reservoir is an oil and gas reservoir with a ground pressure coefficient lower than 1 and an average permeability lower than 0.1 mD.

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