A composition and fracturing fluid containing the same

Abstract

The present application provides a composition and a fracturing fluid containing the same. The composition provided by the present application comprises ammonium chloride, sodium nitrite and a flow enhancer. The flow enhancer is a chemical loading product of a compound shown in a structural diagram as Formula I on nano-silicon dioxide; wherein A is an optionally substituted naphthalene ring; n is an integer from 1 to 10; n R is independently selected from one of a chemical single bond and a C1 to C 10 alkylene group; and n X is independently selected from -O- or -NH-, and at least one X is -NH-. The fracturing fluid comprises the composition, a thickening agent, a clay stabilizer, a cleanup agent, a crosslinking agent, a pH regulator and water.

Description

[0001] Related applications

[0002] This application claims priority to Chinese patent application CN202310621391.8, filed on May 30, 2023, entitled “A composition and fracturing fluid containing the same,” and the entire contents of CN202310621391.8 are incorporated herein by reference. Technical Field

[0003] The invention belongs to the technical field of oil and gas reservoir transformation, and in particular relates to a composition and a fracturing fluid containing the composition. Background Art

[0004] Domestic tight oil and gas reservoirs with normal pressure, low pressure, and low permeability are characterized by low porosity, low permeability, and insufficient flowback displacement pressure. During fracturing, bio-based fracturing fluid residue, adsorption retention, and water lock damage can lead to severe core matrix damage, with a core damage rate of approximately 30%. To address this issue, research and application of self-reactive energized fracturing fluids have been conducted both domestically and internationally. This is an effective technical approach to enhance the kinetic energy of fracturing fluid flowback and reduce reservoir damage.

[0005] However, the bio-based thickeners in existing self-reactive energized fracturing fluids can cause adsorption damage to rocks. Hydrogen bonding and chemical bonding are key sources of adsorption between guar gum and rock. Conventional self-reactive energized fracturing fluids fail to address this thickener adsorption and retention issue, and also fail to reduce the additional flow resistance caused by the hydrophilic nature of the fracturing fluid and the inner walls of the core matrix pores. Therefore, a fracturing fluid is urgently needed that can overcome this thickener adsorption and retention issue, reduce fluid flow resistance, and minimize damage to low-permeability reservoirs. Summary of the Invention

[0006] The object of the present invention is to provide a fracturing fluid that can not only overcome the adsorption and retention problem of the thickener, but also reduce the flow resistance of the liquid and cause less damage to low-permeability reservoirs.

[0007] To achieve the above object, the present invention provides a composition in a first aspect, which comprises ammonium chloride, sodium nitrite and a flow enhancer.

[0008] According to one embodiment of the present invention, taking the mass of the composition as 100%, the composition includes 42.8 wt % to 43.5 wt % of ammonium chloride, 55.2 wt % to 56.1 wt % of sodium nitrite and 0.5 wt % to 2 wt % of the flow enhancer.

[0009] 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;

[0010]

[0011] 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-.

[0012] According to a specific embodiment of the present invention, the average particle size of the nano-silicon dioxide is 1 nm to 50 nm;

[0013] Preferably, the nano-silica is hydroxylated nano-silica.

[0014] According to a specific embodiment of the present invention, in Formula I, n is an integer from 2 to 6; and / or

[0015] The n Rs are independently selected from one of a chemical single bond and a C1 to C4 alkylene group.

[0016] According to a specific embodiment of the present invention, the compound is hydroxyaminonaphthalene;

[0017] Preferably, the compound is 2,3-dihydroxy-1-methylaminonaphthalene.

[0018] According to a specific embodiment of the present invention, the flow enhancer is prepared by the following method:

[0019] The hydroxylated nano-silica and hydroxyaminonaphthalene are reacted in water to obtain the flow enhancer;

[0020] Preferably, the mass ratio of the hydroxylated modified nano-silica to hydroxyaminonaphthalene is 1:2 to 1:4;

[0021] Preferably, the first reaction is carried out at 60°C to 80°C for 20 to 24 hours;

[0022] Preferably, the hydroxylated nano-silica is prepared by the following method:

[0023] Allowing the nano-silica to undergo a second reaction in concentrated sulfuric acid to obtain the hydroxylated nano-silica;

[0024] Preferably, before hydroxylation modification, the particle size of the nano-silica is 1 nm to 50 nm;

[0025] 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);

[0026] Preferably, the second reaction is carried out at 120° C. to 150° C. for 10 to 12 hours.

[0027] According to a specific embodiment of the present invention, the hydroxyaminonaphthalene is prepared by the following method:

[0028] A. subjecting halomethoxynaphthalene and copper cyanide to a third reaction to obtain a first intermediate product;

[0029] B. subjecting the first intermediate product to a fourth reaction with lithium aluminum tetrahydride to obtain a second intermediate product;

[0030] C. subjecting the second intermediate product to a fifth reaction in an acidic environment;

[0031] D. subjecting the reaction product obtained by the fifth reaction and butyllithium to a sixth reaction;

[0032] E. subjecting the reaction product obtained by the sixth reaction to a seventh reaction in a neutral or alkaline environment to obtain the hydroxyaminonaphthalene.

[0033] According to a specific embodiment of the present invention, the halomethoxynaphthalene is 1-bromo-2,3-dimethoxynaphthalene; and / or

[0034] The hydroxyaminonaphthalene is 2,3-dihydroxy-1-methylaminonaphthalene.

[0035] According to a specific embodiment of the present invention, the molar ratio of the halomethoxynaphthalene to copper cyanide is 1:1 to 2:1;

[0036] and / or

[0037] The molar ratio of the halomethoxynaphthalene to the lithium aluminum hydroxide is 1:1 to 2:1; and / or

[0038] The molar ratio of the halomethoxynaphthalene to the butyl lithium is 1:1.

[0039] 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

[0040] In step B, the fourth reaction is carried out in a second organic solvent; and / or

[0041] In step C, a carboxylic acid-lower alcohol mixture is added to create the acidic environment; and / or

[0042] In step E, an inorganic base is added to adjust the pH to neutral or alkaline;

[0043] Preferably, the first organic solvent is N-methylpyrrolidone; and / or

[0044] The second organic solvent is diethyl ether; and / or

[0045] The carboxylic acid-lower alcohol mixture is a mixture of formic acid and ethanol; and / or

[0046] The inorganic base is sodium hydroxide;

[0047] 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

[0048] The acidic environment refers to a pH of 3 to 5; and / or

[0049] In step E, the pH is adjusted to 7 to 9.

[0050] 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;

[0051] and / or

[0052] The fourth reaction is carried out at room temperature (ie 25° C.) for 2 to 3 hours; and / or

[0053] The conditions of the fifth reaction are reaction at 60° C. for 2 h; and / or

[0054] The sixth reaction is carried out at room temperature (ie 25° C.) for 1 hour; and / or

[0055] The seventh reaction was carried out at 50° C. for 5 h.

[0056] A second aspect of the present invention provides a fracturing fluid comprising a composition, a thickener, a clay stabilizer, a drainage aid, a cross-linking agent, a pH adjuster, and water;

[0057] The composition is the composition described in the first aspect of the present invention.

[0058] According to a specific embodiment of the present invention, taking the mass of the water as 100%, the mass concentration of the composition is 12.4 wt% to 18.5 wt%, the mass concentration of the thickener is 0.1 wt% to 1 wt%, the mass concentration of the clay stabilizer is 0.1 wt% to 1 wt%, the mass concentration of the drainage agent is 0.1 wt% to 1 wt%, the mass concentration of the cross-linking agent is 0.1 wt% to 1 wt%, and the mass concentration of the pH regulator is 0.1 wt% to 0.3 wt%;

[0059] Preferably, taking the mass of the water as 100%, the mass concentration of the composition is 12.4 wt% to 18.5 wt%, the mass concentration of the thickener is 0.3 wt% to 0.6 wt%, the mass concentration of the clay stabilizer is 0.2 wt% to 0.3 wt%, the mass concentration of the drainage agent is 0.3 wt% to 0.4 wt%, the mass concentration of the cross-linking agent is 0.3 wt% to 0.4 wt%, and the mass concentration of the pH adjuster is 0.1 wt% to 0.3 wt%.

[0060] According to a specific embodiment of the present invention, the thickening agent is selected from at least one of guar gum, fenugreek gum, sesbania gum and konjac gum; and / or

[0061] The clay stabilizer is an alkyl ammonium salt; and / or

[0062] The drainage aid is polyoxyethylene ether; and / or

[0063] The cross-linking agent is an organic boron cross-linking agent and / or an inorganic boron cross-linking agent; and / or

[0064] The pH regulator is a carbonate and / or hydroxide;

[0065] Preferably, the alkylammonium salt is cetyltrimethylammonium chloride; and / or

[0066] The inorganic boron cross-linking agent is an aqueous solution of sodium borate; and / or

[0067] The organic boron cross-linking agent is a complex of sodium borate and an organic ligand.

[0068] According to a specific embodiment of the present invention, in the sodium borate aqueous solution, the mass fraction of the sodium borate is 5 wt %.

[0069] In the present invention, the product name of the organoboron crosslinking agent is guar gum fracturing fluid crosslinking agent 60°C, which implements the standard Q / SHCG 128 and is purchased from Dongying Shipurui Petroleum Engineering Technology Co., Ltd.

[0070] According to a specific embodiment of the present invention, the pH value of the fracturing fluid is 7 to 9.

[0071] Use of the composition according to the first aspect of the present invention or the fracturing fluid according to the second aspect of the present invention in fracturing reconstruction of low-pressure and low-permeability tight oil and gas reservoirs;

[0072] Preferably, the low-pressure, low-permeability, tight 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.

[0073] In view of the problems of adsorption retention of thickening agent, high liquid flow resistance and high damage to low permeability reservoir in the fracturing fluid in the prior art, the application provides a composition and a fracturing fluid containing the same. The composition provided by the application comprises ammonium chloride, sodium nitrite and a flow synergist. The fracturing fluid comprises the composition, a thickening agent, a clay stabilizer, a cleanup agent, a crosslinking agent, a pH regulator and water. There is a synergistic effect among the ammonium chloride, the sodium nitrite and the flow synergist in the composition, the fracturing fluid containing the same can generate additional fluid flowback energy at the reservoir temperature, at the same time, the adsorption retention of the thickening agent on the rock surface is reduced, the start-up pressure of the liquid in the core is reduced, the liquid flow resistance is reduced, the flowback capacity of the fracturing fluid is improved, and finally the damage of the fracturing fluid to the low permeability reservoir is greatly reduced. When the gel breaking fluid prepared by mixing the fracturing fluid provided by the application with a low-temperature gel breaker passes through the powder composed of core particles with an average porosity of 10% and an average permeability of 0.001 mD, the adsorption amount of the thickening agent on the core particles is 3.6 to 5.9 mg·g -1 ; when the gel breaking fluid prepared by mixing the fracturing fluid provided by the application with a low-temperature gel breaker is driven by nitrogen gas at 90 DEG C from a confining pressure of 10 MPa, the start-up pressure of the experimental rock sample with an average porosity of 10% and an average permeability of 0.001 mD sampled from the low-permeability and dense sandstone core is only 0.2 to 0.7 MPa; according to the method specified in 7.7 of SY / T 5107-2016 “Performance Evaluation Method of Water-based Fracturing Fluid”, the gel breaking fluid prepared by mixing the fracturing fluid provided by the application with a low-temperature gel breaker is used as the test medium, and the experimental rock sample is subjected to the displacement experiment at 90 DEG C, and it is measured that the damage rate of the fracturing fluid to the core matrix permeability is only 11% to 15%. BRIEF DESCRIPTION OF DRAWINGS

[0074] Figure 1 The infrared spectrum of 2,3-dihydroxy-1-methylamino naphthalene prepared in Example 1 is shown in the figure;

[0075] Figure 2 The figure is a thickening agent adsorption amount determination device;

[0076] Figure 3 The figure is a core start-up pressure determination device. DETAILED DESCRIPTION

[0077] The application will be further described below in combination with examples, but the examples of the application are only exemplary descriptions, and the implementation manner does not constitute a limitation on the application in any case.

[0078] Preparation of flow synergist

[0079] Example 1

[0080] Preparation of 2,3-dihydroxy-1-methylamino naphthalene:

[0081] 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;

[0082] 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;

[0083] 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.

[0084] Structural characterization of 2,3-dihydroxy-1-methylaminonaphthalene:

[0085] The pure 2,3-dihydroxy-1-methylaminonaphthalene product obtained after recrystallization from ethanol was measured with a Fourier transform infrared spectrometer. Figure 1 .

[0086] 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.

[0087] Preparation of hydroxylated modified nano-silica:

[0088] 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.

[0089] Prepare flow enhancer:

[0090] 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.

[0091] Preparation composition and fracturing fluid

[0092] The flow enhancers used in Examples 2 to 10 and Comparative Example 1 were all the flow enhancers prepared in Example 1.

[0093] The organoboron crosslinking agent used in Examples 6 to 10 and Comparative Examples 5 to 7 is a product called Guar Gum Fracturing Fluid Crosslinking Agent 60°C, which complies with the standard Q / SHCG 128 and was purchased from Dongying Shipurui Petroleum Engineering Technology Co., Ltd.

[0094] Example 2

[0095] The composition in this example includes 5.35 g ammonium chloride, 6.9 g sodium nitrite, and 0.2 g flow enhancer.

[0096] Preparation of fracturing fluid:

[0097] 1) Mix 5.35g of ammonium chloride, 6.9g of sodium nitrite, 0.2g of flow enhancer, 0.3g of hexadecyltrimethylammonium chloride and 100g of water in a mixing container and continue stirring until completely dissolved;

[0098] 2) Add 0.4 g of guar gum to the solution container in step 1) and continue stirring until the guar gum is completely dissolved;

[0099] 3) adding 0.3 g of polyoxyethylene ether to the liquid preparation container in step 2) and stirring continuously until the polyoxyethylene ether is completely dissolved, avoiding foam overflow during stirring;

[0100] 4) adding 0.3 g of sodium carbonate to the liquid preparation container in step 3) to adjust the pH, and continuing stirring until the sodium carbonate is completely dissolved to obtain a base solution with a pH of 9;

[0101] 5) Add 0.3 g of 5 wt% sodium borate aqueous solution into the liquid preparation container in step 4) and stir evenly to obtain the fracturing fluid.

[0102] Comparative Example 1

[0103] Preparation of fracturing fluid: except for removing 0.2 g of flow enhancer in step 1) of Example 2, the rest of the steps for preparing fracturing fluid were the same as those in Example 2.

[0104] Comparative Example 2

[0105] Preparation of fracturing fluid: except for removing 5.35 g of ammonium chloride and 6.9 g of sodium nitrite in step 1) of Example 2, the rest of the steps for preparing the fracturing fluid were the same as those in Example 2.

[0106] Comparative Example 3

[0107] Preparation of fracturing fluid: except for 5.35 g of ammonium chloride, 6.9 g of sodium nitrite and 0.2 g of flow enhancer in step 1) of Example 2, the rest of the steps for preparing the fracturing fluid were the same as those in Example 2.

[0108] Example 3

[0109] The composition in this example includes 5.35 g ammonium chloride, 6.9 g sodium nitrite, and 0.2 g flow enhancer.

[0110] Preparation of fracturing fluid:

[0111] 1) Mix 5.35g of ammonium chloride, 6.9g of sodium nitrite, 0.2g of flow enhancer, 0.3g of hexadecyltrimethylammonium chloride and 100g of water in a mixing container and continue stirring until completely dissolved;

[0112] 2) Add 0.4 g of fennel gum to the liquid preparation container in step 1) and continue stirring until the fennel gum is completely dissolved;

[0113] 3) adding 0.3 g of polyoxyethylene ether to the liquid preparation container in step 2) and stirring continuously until the polyoxyethylene ether is completely dissolved, avoiding foam overflow during stirring;

[0114] 4) adding 0.3 g of sodium carbonate to the liquid preparation container in step 3) to adjust the pH, and continuing stirring until the sodium carbonate is completely dissolved to obtain a base solution with a pH of 9;

[0115] 5) Add 0.3 g of 5 wt% sodium borate aqueous solution into the liquid preparation container in step 4) and stir evenly to obtain the fracturing fluid.

[0116] Comparative Example 4

[0117] Preparation of fracturing fluid: except for removing 0.2 g of flow enhancer in step 1) of Example 3, the rest of the steps for preparing fracturing fluid were the same as those in Example 3.

[0118] Example 4

[0119] The composition in this example includes 5.35 g ammonium chloride, 6.9 g sodium nitrite, and 0.2 g flow enhancer.

[0120] Preparation of fracturing fluid:

[0121] 1) Mix 5.35g of ammonium chloride, 6.9g of sodium nitrite, 0.2g of flow enhancer, 0.3g of hexadecyltrimethylammonium chloride and 100g of water in a mixing container and continue stirring until completely dissolved;

[0122] 2) Add 0.4 g of sesbania gum to the solution container in step 1) and continue stirring until the sesbania gum is completely dissolved;

[0123] 3) adding 0.3 g of polyoxyethylene ether to the liquid preparation container in step 2) and stirring continuously until the polyoxyethylene ether is completely dissolved, avoiding foam overflow during stirring;

[0124] 4) Add 0.3 g of sodium carbonate to the solution container in step 3) to adjust the pH, continue to stir until the sodium carbonate is completely dissolved to obtain a base solution with a pH of 9;

[0125] 5) Add 0.3 g of a 5 wt% sodium borate aqueous solution to the solution container in step 4), stir uniformly to obtain the fracturing fluid.

[0126] Example 5

[0127] The composition in this example includes 5.35 g of ammonium chloride, 6.9 g of sodium nitrite, and 0.2 g of a flow enhancer.

[0128] Prepare the fracturing fluid:

[0129] 1) Mix 5.35 g of ammonium chloride, 6.9 g of sodium nitrite, 0.2 g of a flow enhancer, and 0.3 g of cetyltrimethylammonium chloride, and 100 g of water in a solution container, continue to stir until completely dissolved;

[0130] 2) Add 0.4 g of konjac gum to the solution container in step 1), continue to stir until the konjac gum is completely dissolved;

[0131] 3) Add 0.3 g of polyoxyethylene ether to the solution container in step 2), continue to stir until the polyoxyethylene ether is completely dissolved, avoid foam overflow during stirring;

[0132] 4) Add 0.2 g of sodium carbonate to the solution container in step 3) to adjust the pH, continue to stir until the sodium carbonate is completely dissolved to obtain a base solution with a pH of 9;

[0133] 5) Add 0.3 g of a 5 wt% sodium borate aqueous solution to the solution container in step 4), stir uniformly to obtain the fracturing fluid.

[0134] Example 6

[0135] The composition in this example includes 6.42 g of ammonium chloride, 8.28 g of sodium nitrite, and 0.3 g of a flow enhancer.

[0136] Prepare the fracturing fluid:

[0137] 1) Mix 6.42 g of ammonium chloride, 8.28 g of sodium nitrite, 0.3 g of a flow enhancer, and 0.3 g of cetyltrimethylammonium chloride, and 100 g of water in a solution container, continue to stir until completely dissolved;

[0138] 2) Add 0.5 g of guar gum to the solution container in step 1), continue to stir until the guar gum is completely dissolved;

[0139] 3) adding 0.3 g of polyoxyethylene ether to the liquid preparation container in step 2) and stirring continuously until the polyoxyethylene ether is completely dissolved, avoiding foam overflow during stirring;

[0140] 4) adding 0.2 g of sodium hydroxide to the liquid preparation container in step 3) to adjust the pH, and continuing stirring until the sodium hydroxide is completely dissolved to obtain a base solution with a pH of 8;

[0141] 5) Add 0.3 g of an organic boron crosslinking agent to the liquid preparation container in step 4) and stir evenly to obtain the fracturing fluid.

[0142] Comparative Example 5

[0143] Preparation of fracturing fluid: except for removing 0.3 g of flow enhancer in step 1) of Example 6, the rest of the steps for preparing fracturing fluid were the same as those in Example 6.

[0144] Example 7

[0145] The composition in this example includes 6.42 g of ammonium chloride, 8.28 g of sodium nitrite, and 0.3 g of a flow enhancer.

[0146] Preparation of fracturing fluid:

[0147] 1) Mix 6.42g of ammonium chloride, 8.28g of sodium nitrite, 0.3g of flow enhancer, 0.2g of hexadecyltrimethylammonium chloride and 100g of water in a mixing container and continue stirring until completely dissolved;

[0148] 2) Add 0.6 g of guar gum to the solution container in step 1) and continue stirring until the guar gum is completely dissolved;

[0149] 3) adding 0.4 g of polyoxyethylene ether to the liquid preparation container in step 2) and stirring continuously until the polyoxyethylene ether is completely dissolved, avoiding foam overflow during stirring;

[0150] 4) adding 0.2 g of sodium hydroxide to the liquid preparation container in step 3) to adjust the pH, and continuing stirring until the sodium hydroxide is completely dissolved to obtain a base solution with a pH of 8;

[0151] 5) Add 0.4 g of an organic boron crosslinking agent to the liquid preparation container in step 4) and stir evenly to obtain the fracturing fluid.

[0152] Example 8

[0153] The composition in this example includes 8.025 g of ammonium chloride, 10.35 g of sodium nitrite, and 0.1 g of a flow enhancer.

[0154] Preparation of fracturing fluid:

[0155] 1) Mix 8.025 g of ammonium chloride, 10.35 g of sodium nitrite, 0.1 g of flow enhancer and 0.2 g of cetyl trimethyl ammonium chloride and 100 g of water in a liquid preparation container, continue to stir until completely dissolved;

[0156] 2) Add 0.3 g of guar gum to the liquid preparation container of step 1), continue to stir until the guar gum is completely dissolved;

[0157] 3) Add 0.4 g of polyoxyethylene ether to the liquid preparation container in step 2), continue to stir until the polyoxyethylene ether is completely dissolved, avoid foam overflow during stirring;

[0158] 4) Add 0.1 g of sodium hydroxide to the liquid preparation container in step 3) to adjust the pH, continue to stir until the sodium hydroxide is completely dissolved to obtain a base solution with a pH of 7;

[0159] 5) Add 0.4 g of organic boron crosslinking agent to the liquid preparation container in step 4), stir uniformly to obtain the fracturing fluid.

[0160] Comparative Example 6

[0161] Prepare the fracturing fluid: remove 0.1 g of flow enhancer in step 1) of Example 8, and the rest is the same as the steps of preparing the fracturing fluid in Example 8.

[0162] Example 9

[0163] The composition in this example includes 8.025 g of ammonium chloride, 10.35 g of sodium nitrite and 0.1 g of flow enhancer.

[0164] Prepare the fracturing fluid:

[0165] 1) Mix 8.025 g of ammonium chloride, 10.35 g of sodium nitrite, 0.1 g of flow enhancer and 0.2 g of cetyl trimethyl ammonium chloride and 100 g of water in a liquid preparation container, continue to stir until completely dissolved;

[0166] 2) Add 0.3 g of guar gum to the liquid preparation container of step 1), continue to stir until the guar gum is completely dissolved;

[0167] 3) Add 0.4 g of polyoxyethylene ether to the liquid preparation container in step 2), continue to stir until the polyoxyethylene ether is completely dissolved, avoid foam overflow during stirring;

[0168] 4) Add 0.1 g of sodium carbonate to the liquid preparation container in step 3) to adjust the pH, continue to stir until the sodium carbonate is completely dissolved to obtain a base solution with a pH of 7;

[0169] 5) Add 0.4 g of organic boron crosslinking agent to the liquid preparation container in step 4), stir uniformly to obtain the fracturing fluid.

[0170] Comparative Example 7

[0171] Preparation of fracturing fluid: except for removing 0.1 g of flow enhancer in step 1) of Example 9, the rest of the steps for preparing fracturing fluid were the same as those in Example 9.

[0172] Example 10

[0173] The composition in this example includes 8.025 g of ammonium chloride, 10.35 g of sodium nitrite, and 0.1 g of a flow enhancer.

[0174] Preparation of fracturing fluid:

[0175] 1) Mix 8.025g of ammonium chloride, 10.35g of sodium nitrite, 0.1g of flow enhancer, 0.2g of hexadecyltrimethylammonium chloride, and 100g of water in a mixing container and continue stirring until completely dissolved;

[0176] 2) Add 0.3 g of sesbania gum to the solution container in step 1) and continue stirring until the sesbania gum is completely dissolved;

[0177] 3) adding 0.4 g of polyoxyethylene ether to the liquid preparation container in step 2) and stirring continuously until the polyoxyethylene ether is completely dissolved, avoiding foam overflow during stirring;

[0178] 4) adding 0.1 g of sodium carbonate to the liquid preparation container in step 3) to adjust the pH, and continuing stirring until the sodium carbonate is completely dissolved to obtain a base solution with a pH of 7;

[0179] 5) Add 0.4 g of an organic boron crosslinking agent to the liquid preparation container in step 4) and stir evenly to obtain the fracturing fluid.

[0180] Fracturing fluid performance evaluation

[0181] 1. Determination of gas volume generated by fracturing fluid reaction

[0182] i. Directly placing the fracturing fluids prepared in Examples 2 to 10 and Comparative Examples 1 to 7 into sealed wide-mouth bottles with air guide tubes, and connecting the outlets of the air guide tubes to a gas collection device;

[0183] 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.

[0184] See Table 1 for specific results.

[0185] Table 1. Gas production from fracturing fluid reaction

[0186] Serial number Reaction gas amount / mol Example 2 0.09 Comparative Example 1 0.09 Comparative Example 2 0 Comparative Example 3 0 Example 3 0.09 Comparative Example 4 0.09 Example 4 0.09 Example 5 0.09 Example 6 0.11 Comparative Example 5 0.11 Example 7 0.11 Example 8 0.13 Comparative Example 6 0.13 Example 9 0.13 Comparative Example 7 0.13 Example 10 0.13

[0187] From the data in Table 1, it can be seen that the fracturing fluids containing ammonium chloride and sodium nitrite prepared in Examples 2 to 10 can react to generate gas at 90℃, and the data of Comparative Example 2 and Comparative Example 1, Example 3 and Comparative Example 4, Example 6 and Comparative Example 5, Example 8 and Comparative Example 6, Example 9 and Comparative Example 7 show that the addition of flow enhancer does not affect the gas generation effect of ammonium chloride and sodium nitrite. There is a positive correlation between the total mass ratio of sodium nitrite and ammonium chloride in the fracturing fluid and the amount of gas generated by the reaction, the greater the total mass ratio of sodium nitrite and ammonium chloride in the fracturing fluid, the more the amount of gas generated by the reaction, the stronger the pressure boosting capacity to the formation, which is beneficial to improve the flowback of the fracturing fluid.

[0188] 2. Determination of adsorption amount of thickening agent, starting pressure and damage rate of matrix permeability

[0189] The low-temperature gel breaker used in the following experiments was purchased from Dongying Supre Petroleum Engineering Technology Co., Ltd.

[0190] A. Determination of adsorption amount of thickening agent

[0191] Using the device shown in FIG. 1, the adsorption amount of thickening agent of the fracturing fluids prepared in Examples 2 to 10 and Comparative Examples 1 to 7 was determined, and the inhibitory capacity of the fracturing fluids to reduce the adsorption damage of thickening agent to the core was evaluated. The specific method is as follows: Figure 2 (1) 600 ppm of low-temperature gel breaker was directly added to the fracturing fluids prepared in Examples 2 to 10 and Comparative Examples 1 to 7, and then the fracturing fluids were aged at a temperature of 35℃ for 24 hours until the viscosity of the fracturing fluids after the addition of the low-temperature gel breaker was lower than 5 mPa.s, and then the fracturing fluids were taken out to obtain 16 groups of gel breaking fluids for standby;

[0192] (2) any one of the 16 groups of gel breaking fluids prepared in step (1) was first filled into an intermediate container, the sand filling tube of the high-temperature and high-pressure filtration instrument was 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 filtration instrument was preheated to 90℃;

[0193] (3) the valve connecting the nitrogen cylinder to the high-temperature and high-pressure filtration instrument was closed, the valve connecting the high-temperature and high-pressure filtration instrument to the intermediate container was opened, and under the drive of the flow pump, the gel breaking fluid in the intermediate container passed through the high-temperature and high-pressure filtration instrument preheated to 90℃ and filled with core particles at a discharge of 5 mL / min, and after all the gel breaking fluid entered the gel breaking fluid collector, the valve connecting the high-temperature and high-pressure filtration instrument to the intermediate instrument was closed, and then the valve connecting the nitrogen cylinder to the high-temperature and high-pressure filtration instrument was opened, and nitrogen was continued to be blown for 10 minutes to prevent the gel breaking fluid from being mechanically retained in the high-temperature and high-pressure filtration instrument;

[0194]

[0195] ​(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);

[0196]

[0197] Where, F is the adsorption amount of thickener, g / g;

[0198] m is the mass of thickener in the gel breaking liquid in the intermediate container without sand filling, g;

[0199] 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;

[0200] V is the volume of the gel-breaking liquid that passes through the sand-filling tube in the gel-breaking liquid collector, L.

[0201] According to steps (2) to (4), 16 groups of gel breaking solutions were used to measure the adsorption capacity of the thickener. The specific results are shown in Table 2.

[0202] B. Start pressure measurement

[0203] 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 10 and Comparative Examples 1 to 7 when flowing back from the core. The specific steps are as follows:

[0204] 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;

[0205] ② Directly add 600 ppm of low-temperature breaker to the fracturing fluids prepared in Examples 2 to 10 and Comparative Examples 1 to 7, and then age them 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 16 groups of breaker fluids for standby use;

[0206] ③ The porosity and permeability of the dried rock samples obtained in step ① were measured using an overburden porosimeter. 16 rock samples with substantially consistent porosity and permeability (average porosity 10% and average permeability 0.001 mD) were selected as experimental rock samples. Then, according to the method for establishing initial water saturation in 5.1.5 of Q / SH 0501-2013 "Flow Experimental Evaluation Method for Tight Reservoir Sensitivity", 16 groups of breaking fluids prepared using the fracturing fluids prepared in Examples 2 to 10 and Comparative Examples 1 to 7 in step ② were used to establish an initial saturation of 40% with breaking fluid for each of the 16 experimental rock samples.

[0207] ④ Perform a starting pressure test on the 16 experimental rock samples with an initial breaker saturation of 40% obtained in step ③: Place any experimental rock sample with an initial breaker saturation of 40% obtained in step ③ into a 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 therein to 90°C and maintain a constant temperature. Slowly adjust the input displacement nitrogen pressure using a pressure reducing valve. Increase the pressure by 0.1 MPa and observe for 2 minutes each time 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 with an initial breaker saturation of 40%. The specific results are shown in Table 2.

[0208] C. Determination of matrix permeability and damage rate

[0209] 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 Section 5.1.5 of the Initial Water Saturation Establishment Method in Q / SH 0501-2013, "Flow Experimental Evaluation Method for Tight Reservoirs Sensitivity." Using any of the 16 groups of breakers prepared in Step ② of Experiment B as the test medium, a core flooding experiment was conducted at 90°C on the experimental rock samples with an average porosity of 10%, an average permeability of 0.001 mD, and an initial water saturation of 40%, according to Section 7.7 of SY / T 5107-2016, "Performance Evaluation Method for Water-Based Fracturing Fluids." The experiment involved adding a sufficient amount of breakers to the intermediate container at the inlet end, maintaining a displacement pressure of 3.5 MPa, and displacing the breakers through the core holder. The matrix permeability damage rate of the experimental rock samples was analyzed.

[0210] According to the above method, 16 groups of gel-breaking solutions were used to measure the matrix permeability and damage rate. The specific results are shown in Table 2.

[0211] Table 2. Thickener adsorption, starting pressure, matrix permeability damage rate

[0212]

[0213]

[0214] From the data of thickener adsorption in Table 2, it can be seen that when the fracturing fluid containing flow enhancer prepared in Examples 2 to 10 passes through the powder composed of core particles, the thickener adsorption amount on the core particles is 3.6 to 5.9 mg·g -1 , the thickener adsorption amount is very low; when the fracturing fluid prepared in Comparative Examples 1 and Comparative Examples 4 to 7 without flow enhancer is passed through the powder composed of core particles, the thickener adsorption amount on the core particles is 12 to 16 mg g -1The thickener adsorption amount is significantly higher. This shows that the fracturing fluids prepared in Examples 2 to 10 have a significant thickener adsorption inhibition effect, and the amount of thickener adsorbed and retained in the formation is small, which can effectively reduce the solid phase damage of the fracturing fluid to the formation.

[0215] From the starting pressure data in Table 2, it can be seen that the flowback starting pressure of the fracturing fluids prepared in Examples 2 to 10 is 0.2 to 0.7 MPa, while the flowback starting pressure of the fracturing fluids prepared in Comparative Examples 1 and Comparative Examples 4 to 7 is 1.2 to 1.5 MPa, which is significantly higher than that of Examples 2 to 10, proving that the fracturing fluids prepared in Examples 2 to 10 are easier to flow back into the formation.

[0216] From the matrix permeability damage rate data in Table 2, it can be seen that the matrix permeability damage rate of the fracturing fluids prepared in Examples 2 to 10 is 11 to 15%, while the matrix permeability damage rate of the fracturing fluids prepared in Comparative Examples 1 and Comparative Examples 4 to 7 is 24 to 27%, which proves that the fracturing fluids prepared in Examples 2 to 10 can significantly reduce the matrix permeability damage rate.

[0217] Combined with the data of thickener adsorption, starting pressure and matrix permeability damage rate of the fracturing fluids prepared in Example 2 and Comparative Examples 1 to 3 in Table 2 and the formula analysis of the fracturing fluids prepared in Example 2 and Comparative Examples 1 to 3, the fracturing fluid prepared in Comparative Example 3 does not contain the composition provided by the present invention (i.e., ammonium chloride, sodium nitrite and flow enhancer), and its thickener adsorption, starting pressure and matrix permeability damage rate are the highest, which are 18 mg·g -1, 2.1MPa, 32%, it can be seen that the degree of core damage to the formation, including solid phase damage, is the highest, and it is 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, starting pressure and matrix permeability damage rate of the fracturing fluid prepared in Comparative Example 2 are reduced by 53%, 57% and 46% respectively compared with Comparative Example 3; compared with Comparative Example 3, the fracturing fluid prepared in Comparative Example 1 only adds ammonium chloride and sodium nitrite, and the thickener adsorption amount, starting pressure and matrix permeability damage rate of the fracturing fluid prepared in Comparative Example 1 are reduced by 33%, 43% and 25% respectively compared with Comparative Example 3; compared with Comparative Example 3, the fracturing fluid prepared in Example 2 adds the composition provided by the present invention (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 2 are reduced by 75%, 80% and 65% respectively compared with Comparative Example 3. The above results show that in the fracturing fluid comprising the composition provided by the present invention, the ammonium chloride, sodium nitrite and flow enhancer in the composition have a synergistic effect in reducing the amount of thickener adsorbed by the fracturing fluid, reducing the fracturing fluid backflow starting pressure and reducing the matrix permeability damage rate of the fracturing fluid. It can not only improve the backflow capacity of the fracturing fluid, but also further reduce the solid phase damage of the fracturing fluid. In addition, the preparation method of the fracturing fluid is simple and does not change the existing construction process. It is of great significance to reducing reservoir damage and improving oil and gas production efficiency.

[0218] 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 composition comprising ammonium chloride, sodium nitrite and a flow enhancer; The flow enhancer is a chemically supported product of a compound as shown in Formula I on nano-silica; in, A is a naphthalene ring with an optional substitution 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-; The nano-silica is hydroxylated nano-silica; The average particle size of the nano-silicon dioxide is 1 nm to 50 nm.

2. The composition according to claim 1, characterized in that Based on 100% by mass of the composition, the composition includes 42.8 wt% to 43.5 wt% of ammonium chloride, 55.2 wt% to 56.1 wt% of sodium nitrite, and 0.5 wt% to 2 wt% of the flow enhancer.

3. The composition 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.

4. The composition according to any one of claims 1 to 3, characterized in that The compound is hydroxyaminonaphthalene.

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

6. A fracturing fluid comprising a composition, a thickener, a clay stabilizer, a drainage aid, a cross-linking agent, a pH adjuster, and water; The composition is the composition according to any one of claims 1 to 5.

7. The fracturing fluid according to claim 6, characterized in that Taking the mass of the water as 100%, the mass concentration of the composition is 12.4 wt % to 18.5 wt %, the mass concentration of the thickener is 0.1 wt % to 1 wt %, the mass concentration of the clay stabilizer is 0.1 wt % to 1 wt %, the mass concentration of the drainage agent is 0.1 wt % to 1 wt %, the mass concentration of the cross-linking agent is 0.1 wt % to 1 wt %, and the mass concentration of the pH regulator is 0.1 wt % to 0.3 wt %.

8. The fracturing fluid according to claim 6 or 7, characterized in that: The thickening agent is selected from at least one of guar gum, fenugreek gum, sesbania gum and konjac gum; and / or The clay stabilizer is an alkyl ammonium salt; and / or The drainage aid is polyoxyethylene ether; and / or The cross-linking agent is an organic boron cross-linking agent and / or an inorganic boron cross-linking agent; and / or The pH regulator is carbonate and / or hydroxide.

9. The fracturing fluid according to claim 8, characterized in that The alkylammonium salt is hexadecyltrimethylammonium chloride; and / or The inorganic boron cross-linking agent is an aqueous solution of sodium borate; and / or The organic boron cross-linking agent is a complex of sodium borate and an organic ligand.

10. Use of the composition according to any one of claims 1 to 5 or the fracturing fluid according to any one of claims 6 to 9 in fracturing reconstruction of low-pressure and low-permeability tight oil and gas reservoirs.

11. The use according to claim 10, characterized in that The low-pressure, low-permeability, tight 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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