A corrosion inhibitor for acidizing and plugging removal, and an acidizing and plugging removal system

Abstract

The present invention relates to a corrosion inhibitor and an acidizing deblocking system for acidizing deblocking, and belongs to the technical field of oilfield chemistry. The present invention's corrosion inhibitor for acidizing deblocking mainly comprises a nitrite, a tungstate, and a pickling corrosion inhibitor, SGR-0405; the mass ratio of the nitrite, tungstate, and the pickling corrosion inhibitor, SGR-0405, is 1:4:7. The present invention's corrosion inhibitor for acidizing deblocking is an oxide film-type corrosion inhibitor, which has the advantages of good high-temperature corrosion resistance, low surface tension, and good compatibility, and can effectively inhibit acid corrosion of tubing strings and casings.

Description

Technical Field

[0001] The invention relates to a corrosion inhibitor for acidizing and unblocking and an acidizing and unblocking system, belonging to the technical field of oilfield chemistry. Background Art

[0002] Acidizing is an important technical means to remove formation damage caused during oil well drilling, completion, and production, improve reservoir permeability, and increase single-well production. However, in production practice, acidizing can cause severe corrosion to metal tubing in oil wells. To mitigate acid corrosion on the tubing, acidizing can be performed by repeatedly raising and lowering the tubing, but this method has the problem of a long operation cycle. To achieve static tubing construction, the wellhead protector can be modified during static tubing construction, and the construction process can be changed to achieve acidizing. However, this method is costly and difficult to implement. Alternatively, corrosion inhibitors can be added to the acidizing deblocking system, and acid can be injected into the casing annulus on-site, ultimately squeezing out the relevant chemicals in the static tubing acidizing deblocking system, preventing acid corrosion on pumps, tubing, and rods, thereby reducing operating costs and improving the production efficiency of the oil well.

[0003] Acidizing corrosion inhibitors are popular due to their advantages such as low dosage, simple construction process, and no need for special additional equipment (such as electrochemical protection). During the acidizing construction process, the main method currently relies on adding acidizing corrosion inhibitors to the acid solution to inhibit the corrosion of downhole pipes and equipment by the acid solution. With the development of the industrial economy and social progress, the types of corrosion inhibitors are increasing, and their functions and application ranges are also constantly expanding. Conventional inorganic salt corrosion inhibitors, such as nitrites and tungstates, although they have a lower price, have the problems of low corrosion inhibition efficiency and poor anti-corrosion performance when used for acidizing and unblocking. Summary of the Invention

[0004] The purpose of the present invention is to provide a corrosion inhibitor for acidification and blockage removal, which is used to solve the problems of low corrosion inhibition efficiency and poor anti-corrosion performance of conventional inorganic salt corrosion inhibitors.

[0005] Another object of the present invention is to provide an acidification plugging removal system.

[0006] In order to achieve the above-mentioned purpose, the technical solution adopted by the corrosion inhibitor for acidification and blockage removal of the present invention is:

[0007] A corrosion inhibitor for acidizing and unblocking mainly consists of nitrite, tungstate and pickling corrosion inhibitor SGR-0405; the mass ratio of the nitrite, tungstate and pickling corrosion inhibitor SGR-0405 is 1:4:7.

[0008] The corrosion inhibitor for acid deblocking of the present invention is an oxide film type corrosion inhibitor, which can inhibit the corrosion of the medium to the metal by forming an adsorption protective film through physical adsorption or chemical adsorption of molecules or ions on the metal surface. It has the advantages of good high-temperature corrosion resistance, low surface tension and good compatibility, and can effectively inhibit the corrosion of acid on the pipe column and casing.

[0009] Preferably, the nitrite is sodium nitrite. Nitrite can form a dense passivation film on the surface of steel.

[0010] Preferably, the tungstate is sodium tungstate. Tungstate can react with metal ions in the anode area of ​​the metal surface to generate an oxide or hydroxide oxide film covering the anode to form a protective film.

[0011] Pickling corrosion inhibitor SGR-0405 can prevent water and dissolved oxygen in water from diffusing to the metal surface.

[0012] The technical solution adopted by the acidification declogging system of the present invention is:

[0013] An acidizing plugging removal system comprises a pre-pad fluid, a main treatment fluid, a post-pad fluid and a displacement fluid; the pre-pad fluid, the main treatment fluid, the post-pad fluid and the displacement fluid are all added with the above-mentioned corrosion inhibitor for acidizing plugging removal.

[0014] The acidizing and declogging system of the present invention has a good corrosion inhibition effect during the acidizing treatment process and has the advantage of low corrosion to downhole tools such as casing, oil pipe, and oil pump.

[0015] Preferably, the pre-pad is obtained by mixing water and the following raw materials in parts by weight: 7 parts of hydrochloric acid, 3 parts of organic acid, 1 part of the above-mentioned corrosion inhibitor for acidification and plugging removal, 1 part of anti-swelling agent, 0.05 parts of anti-emulsifier, 0.3 parts of surfactant, and 5 parts of mutual solvent.

[0016] Further preferably, the pre-fluid is obtained by mixing the following raw materials in parts by weight: 7 parts of hydrochloric acid, 3 parts of organic acid, 1 part of the above-mentioned corrosion inhibitor for acidification and declogging, 1 part of anti-swelling agent, 0.05 parts of anti-emulsifier, 0.3 parts of surfactant, 5 parts of mutual solvent, and 82.65 parts of water.

[0017] Since citric acid and acetic acid can be hydrolyzed to produce more H + , which has the beneficial effect of deep acidification. Preferably, in the pre-pad solution, the organic acid consists of citric acid and acetic acid, and the mass ratio of citric acid to acetic acid is 4:1.

[0018] Preferably, the anti-swelling agent in the prepad fluid is composed of 3-chloro-2-hydroxypropyltrimethylammonium chloride and p-phenylenediamine, with the mass ratio of 3-chloro-2-hydroxypropyltrimethylammonium chloride to p-phenylenediamine being 7:1. Using 3-chloro-2-hydroxypropyltrimethylammonium chloride and p-phenylenediamine as anti-swelling agents, because both can generate positively charged polynuclear ions with six or more charges, these ions can tightly attract the negative charges on the clay surface to form an octahedral structure with the clay, thereby preventing the clay from swelling and dispersing. This allows the anti-swelling agent to prevent the hydration, swelling, dispersion, and migration of clay minerals in the reservoir, thereby significantly improving the apparent water absorption index (the apparent water absorption index is the ratio of the daily injection volume of the injection well to the wellhead pressure) of the oilfield water injection.

[0019] Preferably, in the pre-fluid, the anti-emulsifier is mainly composed of potassium sulfate, 1,4-butanediol diglycidyl ether and toluene diisocyanate, and the mass ratio of potassium sulfate, 1,4-butanediol diglycidyl ether and toluene diisocyanate is 4:5:7. Furthermore, in the pre-fluid, the anti-emulsifier is mainly composed of potassium sulfate, 1,4-butanediol diglycidyl ether and toluene diisocyanate, and the mass ratio of potassium sulfate, 1,4-butanediol diglycidyl ether and toluene diisocyanate is 4:5:7. Using potassium sulfate, 1,4-butanediol diglycidyl ether and toluene diisocyanate as anti-emulsifiers has the following beneficial effects: preventing oleic acid emulsification and avoiding emulsion plugging; reducing fluid surface tension, which is beneficial for drainage after fracturing and acidizing; maintaining and improving formation water wettability, and further improving the fracturing and acidizing effect.

[0020] Preferably, the surfactant in the prepad fluid consists of cetyltrimethylammonium bromide, n-butanol, polyether L61, and water, with the mass ratio of cetyltrimethylammonium bromide, n-butanol, polyether L61, and water being 20:1:30:49. Cetyltrimethylammonium bromide, n-butanol, and polyether L61 can adsorb on the rock pore surfaces, displacing any "water film" that has formed on them. This can also invert the rock pore surface to a strongly hydrophobic effect, thereby altering the rock's wettability.

[0021] Preferably, in the pre-pad solution, the mutual solvent is composed of choline chloride, KCl and water, and the mass ratio of choline chloride, KCl and water is 3:1:6. Choline chloride and KCl can accelerate the mutual dissolution of the components, thereby having the beneficial effect of increasing the effective ingredients.

[0022] Preferably, the main treatment liquid is obtained by mixing water and the following raw materials in parts by weight: 12 parts of hydrochloric acid, 7 parts of phosphoric acid, 4 parts of citric acid, 1 part of acetic acid, 2 parts of hydrofluoric acid, 1.5 parts of the above-mentioned corrosion inhibitor for acidification and declogging, 1 part of anti-swelling agent, 0.05 parts of anti-emulsifier, 0.5 parts of drainage aid, 1 part of scale inhibitor, 0.5 parts of mutual solvent, 3 parts of iron ion stabilizer, and 1 part of surfactant.

[0023] Further preferably, the main treatment liquid is obtained by mixing the following raw materials in parts by weight: 12 parts of hydrochloric acid, 7 parts of phosphoric acid, 4 parts of citric acid, 1 part of acetic acid, 2 parts of hydrofluoric acid, 1.5 parts of the above-mentioned corrosion inhibitor for acidification and declogging, 1 part of anti-swelling agent, 0.05 parts of anti-emulsifier, 0.5 parts of drainage aid, 1 part of scale inhibitor, 0.5 parts of mutual solvent, 3 parts of iron ion stabilizer, 1 part of surfactant, and 65.45 parts of water.

[0024] Preferably, in the main treatment fluid, the anti-swelling agent comprises 3-chloro-2-hydroxypropyltrimethylammonium chloride and p-phenylenediamine, with the mass ratio of 3-chloro-2-hydroxypropyltrimethylammonium chloride to p-phenylenediamine being 7:1. Using 3-chloro-2-hydroxypropyltrimethylammonium chloride and p-phenylenediamine as anti-swelling agents, since both can generate positively charged polynuclear ions with six or more charges, these ions can tightly attract the negative charges on the clay surface to form an octahedral structure with the clay, thereby preventing the clay from swelling and dispersing. This allows the anti-swelling agent to prevent the hydration, swelling, dispersion, and migration of clay minerals in the reservoir, thereby significantly improving the apparent water absorption index (the apparent water absorption index is the ratio of the daily injection volume of the injection well to the wellhead pressure) of the oilfield water injection.

[0025] Preferably, the demulsifier in the main treatment fluid is primarily composed of potassium sulfate, 1,4-butanediol diglycidyl ether, and toluene diisocyanate, with the mass ratio of potassium sulfate, 1,4-butanediol diglycidyl ether, and toluene diisocyanate being 4:5:7. Furthermore, the demulsifier in the main treatment fluid is primarily composed of potassium sulfate, 1,4-butanediol diglycidyl ether, and toluene diisocyanate, with the mass ratio of potassium sulfate, 1,4-butanediol diglycidyl ether, and toluene diisocyanate being 4:5:7. Using potassium sulfate, 1,4-butanediol diglycidyl ether, and toluene diisocyanate as demulsifiers has the following beneficial effects: preventing oleic acid emulsification and preventing emulsion plugging; reducing fluid surface tension, facilitating drainage after fracturing and acidizing; and maintaining and improving formation water wettability, further enhancing the effectiveness of fracturing and acidizing.

[0026] Preferably, the drainage aid in the primary treatment fluid consists of polyether L61, sodium dodecylbenzene sulfonate, and water, with the mass ratio of polyether L61, sodium dodecylbenzene sulfonate, and water being 10:15:75. Polyether L61 and sodium dodecylbenzene sulfonate can reduce oil-water interfacial tension and promote liquid flowback after subsequent construction.

[0027] Preferably, the scale inhibitor in the primary treatment solution consists of an organophosphorus carboxylic acid, sodium lauryl sulfate, and water, with the mass ratio of organophosphorus carboxylic acid, sodium lauryl sulfate, and water being 30:20:50. Preferably, the organophosphorus carboxylic acid in the scale inhibitor is aminotrimethylenephosphonic acid. Using organophosphorus carboxylic acid and sodium lauryl sulfate as the main components of the scale inhibitor has the beneficial effect of preventing or interfering with the precipitation and scaling of sparingly soluble inorganic salts on metal surfaces.

[0028] Preferably, in the main treatment solution, the mutual solvent consists of choline chloride, KCl and water, and the mass ratio of choline chloride, KCl and water is 3:1:6.

[0029] Preferably, in the main treatment solution, the iron ion stabilizer is composed of an iron complexing agent and an iron reducing agent. Preferably, the mass ratio of the iron complexing agent to the iron reducing agent is 4:6. Preferably, the iron complexing agent is ferric thiocyanate. Preferably, the iron reducing agent is ferrous sulfate.

[0030] Preferably, the surfactant in the primary treatment fluid consists of cetyltrimethylammonium bromide, n-butanol, polyether L61, and water, with the mass ratio of cetyltrimethylammonium bromide, n-butanol, polyether L61, and water being 20:1:30:49. Cetyltrimethylammonium bromide, n-butanol, and polyether L61 can adsorb on the rock pore surfaces, dispelling any "water film" that has formed on them. Simultaneously, they can invert the rock pore surface to a strongly hydrophobic one, thereby altering the rock's wettability.

[0031] Preferably, the post-flushing liquid is obtained by mixing water and the following raw materials in parts by weight: 10 parts of hydrochloric acid, 0.2 parts of citric acid, 1 part of anti-swelling agent, 0.05 parts of anti-emulsifier, 0.1 parts of surfactant, and 1.5 parts of the above-mentioned corrosion inhibitor for acidification and plugging removal.

[0032] Further preferably, the post-flushing liquid is obtained by mixing the following raw materials in parts by weight: 10 parts of hydrochloric acid, 0.2 parts of citric acid, 1 part of anti-swelling agent, 0.05 parts of anti-emulsifier, 0.1 parts of surfactant, 1.5 parts of the above-mentioned corrosion inhibitor for acidification and plugging removal, and 87.15 parts of water.

[0033] Preferably, the anti-swelling agent in the post-flush fluid is composed of 3-chloro-2-hydroxypropyltrimethylammonium chloride and p-phenylenediamine, with the mass ratio of 3-chloro-2-hydroxypropyltrimethylammonium chloride to p-phenylenediamine being 7:1. Using 3-chloro-2-hydroxypropyltrimethylammonium chloride and p-phenylenediamine as anti-swelling agents, since both can generate positively charged polynuclear ions with six or more charges, these ions can tightly attract the negative charges on the clay surface to form an octahedral structure with the clay, thereby preventing the clay from swelling and dispersing. This allows the anti-swelling agent to prevent the hydration, swelling, dispersion, and migration of clay minerals in the reservoir, thereby significantly improving the apparent water absorption index (the apparent water absorption index is the ratio of the daily injection volume of the injection well to the wellhead pressure) of the oilfield water injection.

[0034] Preferably, in the post-flushing fluid, the anti-emulsifier is mainly composed of potassium sulfate, 1,4-butanediol diglycidyl ether and toluene diisocyanate, and the mass ratio of potassium sulfate, 1,4-butanediol diglycidyl ether and toluene diisocyanate is 4:5:7. Furthermore, in the post-flushing fluid, the anti-emulsifier is mainly composed of potassium sulfate, 1,4-butanediol diglycidyl ether and toluene diisocyanate, and the mass ratio of potassium sulfate, 1,4-butanediol diglycidyl ether and toluene diisocyanate is 4:5:7. Using potassium sulfate, 1,4-butanediol diglycidyl ether and toluene diisocyanate as anti-emulsifiers has the following beneficial effects: preventing oleic acid emulsification and avoiding emulsion plugging; reducing fluid surface tension, which is beneficial for post-fracture acidizing drainage; maintaining and improving formation water wettability, and further improving the fracturing acidizing effect.

[0035] Preferably, the surfactant in the postflushing fluid consists of cetyltrimethylammonium bromide, n-butanol, polyether L61, and water, with the mass ratio of cetyltrimethylammonium bromide, n-butanol, polyether L61, and water being 20:1:30:49. Cetyltrimethylammonium bromide, n-butanol, and polyether L61 can adsorb on the rock pore surfaces, displacing any "water film" that has formed on them. Simultaneously, they can invert the rock pore surface to a strongly hydrophobic one, thereby altering the rock's wettability.

[0036] Preferably, the displacement fluid is primarily composed of water and the aforementioned acidizing corrosion inhibitor, with the mass fraction of the acidizing corrosion inhibitor in the displacement fluid being 1.5%. Within the aforementioned range, the acidizing corrosion inhibitor reacts with the metal surface or other ions in the acid solution, producing a coating of the reaction products on the metal surface, thereby inhibiting corrosion.

[0037] The acidification plugging removal system of the present invention has good water solubility, little pollution to the reservoir, and no pollution to the environment. DETAILED DESCRIPTION

[0038] The technical solution of the present invention will be further described below with reference to specific embodiments.

[0039] The pickling corrosion inhibitor SGR-0405 in the embodiment of the present invention is produced by Xingrui (Shandong) Environmental Technology Co., Ltd. The hydrochloric acid used in Example 2 is hydrochloric acid with a mass fraction of 30%, and the hydrofluoric acid used in Example 2 is hydrofluoric acid with a mass fraction of 40%.

[0040] 1. Specific examples of the corrosion inhibitor for acidification and blockage removal of the present invention are as follows:

[0041] Example 1

[0042] The corrosion inhibitor for acid declogging in this embodiment consists of nitrite, tungstate and pickling corrosion inhibitor SGR-0405, the mass ratio of nitrite, tungstate and pickling corrosion inhibitor SGR-0405 is 1:4:7, the nitrite is sodium nitrite, and the tungstate is sodium tungstate.

[0043] Comparative Example 1

[0044] The corrosion inhibitor for acid declogging in this comparative example consists of nitrite and pickling corrosion inhibitor SGR-0405, the mass ratio of nitrite to pickling corrosion inhibitor SGR-0405 is 1:7, and the nitrite is sodium nitrite.

[0045] Comparative Example 2

[0046] The corrosion inhibitor for acidizing and declogging in this comparative example consists of tungstate and pickling corrosion inhibitor SGR-0405, the mass ratio of tungstate to pickling corrosion inhibitor SGR-0405 is 4:7, and the tungstate is sodium tungstate.

[0047] Comparative Example 3

[0048] The corrosion inhibitor for acidification and plugging removal in this comparative example consists of nitrite and tungstate, the mass ratio of nitrite to tungstate is 1:4, the nitrite is sodium nitrite, and the tungstate is sodium tungstate.

[0049] 2. Specific embodiments of the acidification and plugging removal system of the present invention are as follows:

[0050] Example 2

[0051] The acidizing and plugging removal system of this embodiment includes a pre-fluid, a main treatment fluid, a post-fluid, and a displacement fluid.

[0052] The pre-pad solution is prepared by mixing the following raw materials in parts by weight: 7 parts of hydrochloric acid, 3 parts of organic acid, 1 part of the corrosion inhibitor for acidification and plugging removal in Example 1, 1 part of anti-swelling agent, 0.05 parts of anti-emulsifier, 0.3 parts of surfactant, 5 parts of mutual solvent, and 82.65 parts of water.

[0053] The organic acid in the prepad solution consists of citric acid and acetic acid, with a mass ratio of citric acid to acetic acid of 4:1. The anti-swelling agent in the prepad solution consists of 3-chloro-2-hydroxypropyltrimethylammonium chloride and p-phenylenediamine, with a mass ratio of 3-chloro-2-hydroxypropyltrimethylammonium chloride to p-phenylenediamine of 7:1. The anti-emulsifier in the prepad solution consists of potassium sulfate, 1,4-butanediol diglycidyl ether, and toluene diisocyanate, with a mass ratio of potassium sulfate, 1,4-butanediol diglycidyl ether, and toluene diisocyanate of 4:5:7. The surfactant in the prepad solution consists of hexadecyltrimethylammonium bromide, n-butanol, polyether L61, and water, with a mass ratio of hexadecyltrimethylammonium bromide, n-butanol, polyether L61, and water of 20:1:30:49. The mutual solvent in the prepad solution consists of choline chloride, KCl, and water, with a mass ratio of choline chloride, KCl, and water of 3:1:6.

[0054] The main treatment liquid is obtained by mixing the following raw materials in parts by weight: 12 parts of hydrochloric acid, 7 parts of phosphoric acid, 4 parts of citric acid, 1 part of acetic acid, 2 parts of hydrofluoric acid, 1.5 parts of the corrosion inhibitor for acidification and plugging in Example 1, 1 part of anti-swelling agent, 0.05 parts of anti-emulsifier, 0.5 parts of drainage aid, 1 part of scale inhibitor, 0.5 parts of mutual solvent, 3 parts of iron ion stabilizer, 1 part of surfactant, and 65.45 parts of water.

[0055] In the main treatment liquid, the anti-swelling agent is composed of 3-chloro-2-hydroxypropyltrimethylammonium chloride and p-phenylenediamine, and the mass ratio of 3-chloro-2-hydroxypropyltrimethylammonium chloride and p-phenylenediamine is 7:1; in the main treatment liquid, the anti-emulsifier is composed of potassium sulfate, 1,4-butanediol diglycidyl ether and toluene diisocyanate, and the mass ratio of potassium sulfate, 1,4-butanediol diglycidyl ether and toluene diisocyanate is 4:5:7; in the main treatment liquid, the drainage aid is composed of polyether L61, sodium dodecylbenzenesulfonate and water, and the mass ratio of polyether L61, sodium dodecylbenzenesulfonate and water is 10:15:75; in the main treatment liquid, the scale inhibitor is composed of organic phosphorus carboxylic acid, sodium dodecyl sulfate and water, and the mass ratio of The mass ratio of organophosphorus carboxylic acid, sodium lauryl sulfate and water is 30:20:50, and the organophosphorus carboxylic acid is aminotrimethylenephosphonic acid; in the main treatment liquid, the mutual solvent is composed of choline chloride, KCl and water, and the mass ratio of choline chloride, KCl and water is 3:1:6; in the main treatment liquid, the iron ion stabilizer is composed of an iron chelating agent and an iron reducing agent, the iron chelating agent is ferric thiocyanate, and the iron reducing agent is ferrous sulfate, and the mass ratio of the iron chelating agent to the iron reducing agent is 4:6; in the main treatment liquid, the surfactant is composed of hexadecyltrimethylammonium bromide, n-butanol, polyether L61 and water, and the mass ratio of hexadecyltrimethylammonium bromide, n-butanol, polyether L61 and water is 20:1:30:49.

[0056] The post-dip solution is prepared by mixing the following raw materials in parts by weight: 10 parts of hydrochloric acid, 0.2 parts of citric acid, 1 part of anti-swelling agent, 0.05 parts of anti-emulsifier, 0.1 parts of surfactant, 1.5 parts of corrosion inhibitor for acidification and plugging removal of Example 1, and 87.15 parts of water.

[0057] In the post-flush liquid, the anti-swelling agent consists of 3-chloro-2-hydroxypropyltrimethylammonium chloride and p-phenylenediamine, and the mass ratio of 3-chloro-2-hydroxypropyltrimethylammonium chloride and p-phenylenediamine is 7:1; in the post-flush liquid, the anti-emulsification agent consists of potassium sulfate, 1,4-butanediol diglycidyl ether and toluene diisocyanate, and the mass ratio of potassium sulfate, 1,4-butanediol diglycidyl ether and toluene diisocyanate is 4:5:7; in the post-flush liquid, the surfactant consists of hexadecyltrimethylammonium bromide, n-butanol, polyether L61 and water, and the mass ratio of hexadecyltrimethylammonium bromide, n-butanol, polyether L61 and water is 20:1:30:49.

[0058] The displacement fluid consists of water and the corrosion inhibitor for acidizing and unblocking the blockage in Example 1. The mass fraction of the corrosion inhibitor for acidizing and unblocking the blockage in Example 1 in the displacement fluid is 1.5%.

[0059] Experimental Example 1

[0060] The anti-corrosion performance is tested by the hanging plate method. The test method refers to JB / T6073 "Laboratory Full Immersion Corrosion Test of Metal Coverings", which specifically includes the following steps:

[0061] (1) Pretreatment of hanging pieces

[0062] Steel (N80 steel) used in acidizing operations was selected as the test coupon. After polishing, cleaning, and drying, the steel was weighed and measured. The length, width, height, and inner diameter of the hole were measured twice, and the average value was taken to facilitate the calculation of the coupon's surface area.

[0063] (2) Post-processing of hanging pieces

[0064] The pretreated coupons were placed in acid solution A, acid solution B, or acid solution C, respectively, and then corrosion tests were conducted at 70°C and an oxygen partial pressure of 0.09 MPa. The corrosion inhibitor of Example 1, Comparative Example 1, Comparative Example 2, or Comparative Example 3 was then added to acid solution A, acid solution B, or acid solution C, respectively, to obtain acid solution A, acid solution B, or acid solution C containing the corrosion inhibitor, wherein the mass fraction of the corrosion inhibitor in acid solution A, acid solution B, or acid solution C containing the corrosion inhibitor was 1%, 1.5%, and 1.5%, respectively. The pretreated coupons were then placed in acid solution A, acid solution B, or acid solution C, respectively, containing the corrosion inhibitor, and then corrosion tests were conducted at 70°C and an oxygen partial pressure of 0.09 MPa. The corrosion tests were conducted on the pretreated coupons in the different acid solutions for the same time.

[0065] The only difference between acid solution A and the pre-fluid in the acidizing and plugging removal system of Example 2 is that acid solution A does not contain a corrosion inhibitor. The only difference between acid solution B and the main treatment fluid in the acidizing and plugging removal system of Example 2 is that acid solution B does not contain a corrosion inhibitor. The only difference between acid solution C and the post-fluid in the acidizing and plugging removal system of Example 2 is that acid solution C does not contain a corrosion inhibitor.

[0066] ① After the experiment is completed, turn off the temperature control switch and the speed adjustment switch to allow the reactor to cool naturally to room temperature. At the same time, open the vent valve to reduce the pressure, then open the reactor and remove the coupons in order to discharge the corrosive medium from the reactor.

[0067] ② Use a stiff brush to remove corrosion products from the removed coupons and collect them for phase analysis. Rinse the coupons in anhydrous ethanol, dry them with filter paper, and clean them in an ultrasonic cleaner using an acid wash solution. The acid wash should last for at least 10 minutes to completely remove all corrosion products. The acid wash solution is a mixture of 35 mL of organic acid, 315 mL of distilled water, and 3.15 g of hexamethylenetetramine. The pickling temperature is 25°C, and the total pickling time is 15 to 20 minutes.

[0068] ③ After pickling, rinse the sample with distilled water and soak it in a NaOH solution (mass fraction of 6%) for neutralization (<1 min). After neutralization, rinse it with distilled water again, wipe it dry with filter paper, and soak it in anhydrous ethanol for dehydration (5 min). After dehydration, soak it in acetone for degreasing, take it out and blow it dry with cold air from a hair dryer, wrap it with filter paper, and place it in a drying oven to dry to constant weight. Finally, weigh it with an electronic analytical balance, accurate to 0.0001 g. After the experiment, measure the mass of the sample after the experiment, calculate the average corrosion rate according to formula (1-1), and calculate the local corrosion rate according to formula (1-2).

[0069]

[0070] In formula (1-1), r corr is the corrosion rate (mm / a); m0 is the original mass of the sample (g); m t is the mass of the sample after the test (g); A is the total surface area of ​​the sample (cm 2 ); ρ is the density of the sample material (g / cm 3 ); t is the time of corrosion experiment (h).

[0071]

[0072] In formula (1-2), v d is the local corrosion rate (mm / a); Δh is the depth of the corrosion pit (mm); t is the time of the corrosion experiment (a).

[0073] After the sample is tested, the average corrosion rate obtained by the coupon weight loss method can only reflect the average corrosion rate of the sample during the entire experimental period. By comparing with the blank group without corrosion inhibitor, the corrosion inhibition rate after adding corrosion inhibitor is calculated according to formula (1-3).

[0074]

[0075] In formula (1-3), R is the corrosion inhibition rate; F0 is the corrosion rate (mm / a) obtained by testing in acid solution without adding corrosion inhibitor; F1 is the corrosion rate (mm / a) obtained by testing in acid solution with adding corrosion inhibitor.

[0076] The experimental results are shown in Table 1.

[0077] Table 1 Local corrosion rate, average local corrosion rate and corrosion inhibition rate obtained by coupon method in acid solution containing different mass fractions of the corrosion inhibitor of Example 1

[0078]

[0079] Table 2 Local corrosion rate, average local corrosion rate and corrosion inhibition rate obtained by coupon method in acid solution containing different mass fractions of corrosion inhibitor of comparative example 1

[0080]

[0081]

[0082] Table 3 Local corrosion rate, average local corrosion rate and corrosion inhibition rate obtained by hanging plate method in acid solution containing different mass fractions of corrosion inhibitor of comparative example 2

[0083]

[0084] Table 4 Local corrosion rate, average local corrosion rate and corrosion inhibition rate obtained by hanging plate method in acid solution containing different mass fractions of corrosion inhibitor of comparative example 3

[0085]

[0086]

[0087] It can be seen from Tables 1-4 that compared with the corrosion rate of the sample tested in acid solution without corrosion inhibitor, the corrosion rate of the sample tested in acid solution A with 1% corrosion inhibitor decreased by 90.86%; after testing in acid solution A with 1% corrosion inhibitor, the surface of the coupon sample remained flat and intact, with no obvious signs of corrosion and a slight degree of corrosion. Its corrosion rate reached the oil field control index.

[0088] After adding 1% corrosion inhibitor, there are no obvious signs of corrosion on the surface of the steel sample matrix. The corrosion product film formed on the surface of the steel sample matrix is ​​flat and dense with good integrity. Under high-power microscope, no obvious pores are found, which can effectively hinder the progress of corrosion and reduce the corrosion rate of the pipe, which is consistent with the weight loss rate results.

[0089] Experimental Example 2

[0090] In this experimental example, the acidizing and plugging removal system of Example 2 was applied to Well B in Oilfield A. The reformed layers in this experimental example were as follows: Chang 8 reservoir; well section: 2621.78 m - 3799 m.

[0091] Oilfield A is a typical low-permeability, low-pressure, low-abundance, and low-yield oilfield, making it extremely challenging to exploit. Historical production overview of Well B in Oilfield A: The well was put into production after fracturing in October 2012, initially producing 10.52 tons of liquids and 4.53 tons of oil per day, with a water cut of 57% and a dynamic liquid level of 1,452 meters. Production resumed on April 4, 2019, and has since been producing 7.5 tons of liquids and 3.83 tons of oil per day, with a water cut of 49%. In December 2020, an underground fault prevented the well from pumping, and pumping was halted. Prior to the cessation of pumping, it had been producing 2.7 tons of liquids and 0.97 tons of oil per day, with a water cut of 64% and a dynamic liquid level of 1,895 meters.

[0092] The well achieved high initial production and good reservoir conditions. After the addition of a scale inhibitor in January 2016, significant oil production increases were observed. Currently, pumping is suspended without fluid replenishment. Considering the scale accumulation in the adjacent well, B1, it is suspected that the well is experiencing energy deficiency and scale blocking the seepage channel. Therefore, it is recommended that the well undergo a non-stop string acidification operation.

[0093] First, 3 tons of the pre-fluid in the acidizing and deblocking system of Example 2 are mixed with 27 cubic meters of water to obtain a pre-treatment liquid; then 2 tons of the post-fluid in the acidizing and deblocking system of Example 2 are mixed with 18 cubic meters of water to obtain a post-treatment liquid. First, the pressure is released to reach the upper repair condition and then the upper repair is carried out. The polished rod is poured out, a 250-type gate is installed on the pressure cover, and a pressure gauge is installed. The oil-casing annulus injection pipeline, the ground pipeline and the wellhead are connected to a pressure test of 21MPa, and the pressure is stabilized for 30 minutes. If the pressure does not drop, it is qualified. Then the pre-treatment liquid, the main liquid in the acidizing and deblocking system of Example 2, the post-treatment liquid and the displacement liquid in the acidizing and deblocking system of Example 2 are directly injected into the well through the oil-casing annulus plug. The injection pressure is lower than 18Mpa, and the injection speed is injected at the maximum displacement under the conditions of the rated safety pressure of the wellhead and pipeline to increase the penetration distance of the deblocking liquid.

[0094] The specific construction steps are as follows:

[0095] (1) First, shut down the pump and close the liquid inlet valve.

[0096] (2) Then 30m 3 The pre-treatment fluid is injected into the well with a displacement of 0.2 to 0.5 m 3 / min, the volume of the pre-fluid in the acidification plugging removal system of Example 2 is 1.5 times the annular volume of the reverse displacement well casing. When injecting, the oil pipe outlet gate is closed and the pre-fluid is injected into the well to perform preliminary cleaning treatment on the inner wall of the tubing string, the blasthole, and the near-wellbore area. During subsequent flowback, dissolved matter or organic corrosion inhibitors are prevented from being adsorbed on the rock formation surface;

[0097] (3) Then inject 50m 3 The main liquid in the acidification and plugging removal system of Example 2 has a displacement of 0.2 to 0.5 m 3 / min, to eliminate blockage caused by formation scaling, eliminate damage caused by fracturing fluid invasion, and reduce the surface tension of acid to facilitate subsequent flowback;

[0098] (4) Inject another 20m 3 Post-treatment fluid, displacement is 0.2~0.5m 3 / min;

[0099] (5) Then inject 25m 3 The displacement fluid in the acidification and plugging removal system of Example 2 has a displacement volume of 0.2 to 0.5 m 3 / min, stewing for 1 hour;

[0100] (6) Finally inject 30m 3 The displacement fluid in the acidification and plugging removal system of Example 2 has a displacement volume of 0.2 to 0.5 m 3 / min, shut in the well for 24 hours; after the reaction, slowly flow back the residual liquid.

[0101] After the experiment, the well (Well B in Oilfield A) produced an average of 6.7 tons of liquid per day, with a water content of 61% and an oil production of 2.61 tons. It has now accumulated 96 days of production and a cumulative oil production of 249 tons. The current daily production is 5.80 tons of liquid per day, with a water content of 58% and an oil production of 2.43 tons. The dynamic liquid level is 1,775 meters.

Claims

1. An acidification and plugging removal system, characterized in that: The method comprises a pre-pad fluid, a main treatment fluid, a post-pad fluid and a displacement fluid; wherein the pre-pad fluid, the main treatment fluid, the post-pad fluid and the displacement fluid are all added with an acidizing and declogging corrosion inhibitor, wherein the acidizing and declogging corrosion inhibitor comprises nitrite, tungstate and pickling corrosion inhibitor SGR-0405; and the mass ratio of the nitrite, tungstate and pickling corrosion inhibitor SGR-0405 is 1:4:7; The pre-pad is prepared by mixing water and the following raw materials in parts by weight: 7 parts of hydrochloric acid, 3 parts of organic acid, 1 part of the corrosion inhibitor for acidification and plugging, 1 part of anti-swelling agent, 0.05 parts of anti-emulsifier, 0.3 parts of surfactant, and 5 parts of mutual solvent; In the prepad solution, the organic acid consists of citric acid and acetic acid, and the mass ratio of citric acid to acetic acid is 4:1; in the prepad solution, the anti-swelling agent consists of 3-chloro-2-hydroxypropyltrimethylammonium chloride and p-phenylenediamine, and the mass ratio of 3-chloro-2-hydroxypropyltrimethylammonium chloride to p-phenylenediamine is 7:1; in the prepad solution, the anti-emulsification agent mainly consists of potassium sulfate, 1,4-butanediol diglycidyl ether and toluene diisocyanate, and the mass ratio of potassium sulfate, 1,4-butanediol diglycidyl ether and toluene diisocyanate is 4:5:7; in the prepad solution, the surfactant consists of hexadecyltrimethylammonium bromide, n-butanol, polyether L61 and water, and the mass ratio of hexadecyltrimethylammonium bromide, n-butanol, polyether L61 and water is 20:1:30:49; in the prepad solution, the mutual solvent consists of choline chloride, KCl and water, and the mass ratio of choline chloride, KCl and water is 3:1:

6.

2. The acidification and plugging removal system according to claim 1, characterized in that: The nitrite is sodium nitrite; the tungstate is sodium tungstate.

3. The acidification and plugging removal system according to claim 1, characterized in that: The main treatment liquid is obtained by mixing water and the following raw materials in parts by weight: 12 parts of hydrochloric acid, 7 parts of phosphoric acid, 4 parts of citric acid, 1 part of acetic acid, 2 parts of hydrofluoric acid, 1.5 parts of the corrosion inhibitor for acidification and declogging, 1 part of anti-swelling agent, 0.05 parts of anti-emulsification agent, 0.5 parts of drainage aid, 1 part of scale inhibitor, 0.5 parts of mutual solvent, 3 parts of iron ion stabilizer, and 1 part of surfactant.

4. The acidification and plugging removal system according to claim 3, characterized in that: In the main treatment liquid, the anti-swelling agent is composed of 3-chloro-2-hydroxypropyltrimethylammonium chloride and p-phenylenediamine, and the mass ratio of 3-chloro-2-hydroxypropyltrimethylammonium chloride and p-phenylenediamine is 7:1; in the main treatment liquid, the anti-emulsifier is mainly composed of potassium sulfate, 1,4-butanediol diglycidyl ether and toluene diisocyanate, and the mass ratio of potassium sulfate, 1,4-butanediol diglycidyl ether and toluene diisocyanate is 4:5:7; in the main treatment liquid, the drainage agent is composed of polyether L61, sodium dodecylbenzenesulfonate and water, and the mass ratio of polyether L61, sodium dodecylbenzenesulfonate and water is 10:15:75; in the main treatment liquid, the scale inhibitor is composed of organic phosphorus carboxylic acid, dodecane The invention relates to a method for preparing a main treatment liquid comprising: preparing a main treatment liquid comprising sodium lauryl sulfate and water, wherein the mass ratio of the organophosphorus carboxylic acid, sodium lauryl sulfate and water is 30:20:50, and the organophosphorus carboxylic acid is aminotrimethylenephosphonic acid; in the main treatment liquid, the mutual solvent comprises choline chloride, KCl and water, and the mass ratio of choline chloride, KCl and water is 3:1:6; in the main treatment liquid, the iron ion stabilizer comprises an iron chelating agent and an iron reducing agent, and the mass ratio of the iron chelating agent and the iron reducing agent is 4:6; in the main treatment liquid, the surfactant comprises cetyltrimethylammonium bromide, n-butanol, polyether L61 and water, and the mass ratio of cetyltrimethylammonium bromide, n-butanol, polyether L61 and water is 20:1:30:

49.

5. The acidification plugging removal system according to claim 1, characterized in that: The post-flushing liquid is obtained by mixing water and the following raw materials in parts by weight: 10 parts of hydrochloric acid, 0.2 parts of citric acid, 1 part of anti-swelling agent, 0.05 parts of anti-emulsifier, 0.1 parts of surfactant, and 1.5 parts of the corrosion inhibitor for acidification and plugging removal.

6. The acidification plugging removal system according to claim 5, characterized in that: In the post-flush liquid, the anti-swelling agent is composed of 3-chloro-2-hydroxypropyltrimethylammonium chloride and p-phenylenediamine, and the mass ratio of 3-chloro-2-hydroxypropyltrimethylammonium chloride to p-phenylenediamine is 7:1; in the post-flush liquid, the anti-emulsification agent is mainly composed of potassium sulfate, 1,4-butanediol diglycidyl ether and toluene diisocyanate, and the mass ratio of potassium sulfate, 1,4-butanediol diglycidyl ether and toluene diisocyanate is 4:5:7; in the post-flush liquid, the surfactant is composed of hexadecyltrimethylammonium bromide, n-butanol, polyether L61 and water, and the mass ratio of hexadecyltrimethylammonium bromide, n-butanol, polyether L61 and water is 20:1:30:

49.

7. The acidification plugging removal system according to claim 1, characterized in that: The displacement fluid mainly consists of water and the acidizing and unblocking corrosion inhibitor, and the mass fraction of the acidizing and unblocking corrosion inhibitor in the displacement fluid is 1.5%.

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