A corrosion and scale inhibitor for oilfield water injection systems and its preparation method

Abstract

This invention belongs to the field of oilfield chemical technology, and specifically relates to a corrosion and scale inhibitor for oilfield water injection systems and its preparation method. The corrosion and scale inhibitor for oilfield water injection systems is synthesized from maleic anhydride, acrylic acid, and diethylenetriamine as raw materials, with a weight ratio of maleic anhydride to acrylic acid and diethylenetriamine of 15-20:10-20:10-20. A redox initiator is used, and the maleic anhydride / acrylic acid / diethylenetriamine copolymer is synthesized through a polymerization reaction. This corrosion and scale inhibitor for oilfield water injection systems can simultaneously alleviate complex scaling in oilfield water injection systems, such as CaCO3 scale, CaSO4 scale, and BaSO4 scale, by chelating and dispersing scale-forming ions. This corrosion and scale inhibitor for oilfield water injection systems is phosphorus-free and will not provide nutrients to bacteria in the water within the oilfield water injection system, thus reducing microbial corrosion and clogging of equipment in the water injection system.

Description

Technical Field

[0001] This invention relates to the field of oilfield chemical technology, and in particular to a corrosion and scale inhibitor for oilfield water injection systems and its preparation method. Background Technology

[0002] As oilfield development enters its mid-to-late stages, water injection production technology is widely adopted. When conditions such as temperature and pressure change, or when incompatible water comes into contact, scale formation often occurs in the oilfield water. Severe scale formation significantly impacts normal oilfield production, leading to decreased oil and gas output, increased water injection pressure, damage to downhole and surface equipment, and even well shutdowns and abandonment. Adding scale inhibitors to oilfield wastewater can effectively suppress scale formation. This method is economical, convenient, and commonly used in oilfields. Significant progress has been made in the research, application, and development of water injection treatment agents. These agents are primarily used in the petroleum, chemical, and related industrial sectors to reduce environmental pollution and production costs, inhibit scale formation in oilfield water injection systems, improve water injection efficiency, and alleviate scale problems in water injection systems.

[0003] The development of scale inhibitors has progressed from simple inorganic and organic compounds to polymers, from high-phosphorus and low-phosphorus compounds to phosphate-free compounds, and from single-use to compound-use, gradually evolving from single-use to diversified technologies. In the 1960s, natural organic polymers such as tannins, starch, cellulose, and lignin were used as scale inhibitors and dispersants, playing an important role in controlling scale formation in circulating cooling water systems. However, due to their unstable performance, large dosage, high cost, and inferior scale inhibition and dispersion effects compared to synthetic polymer scale inhibitors, they are now rarely used. The phospho-based polyacrylic acid, phospho-based polymaleic acid, and methyl acrylate / acrylic acid copolymers that emerged in the 1970s and early 1980s, and the terpolymers such as acrylic acid / hydroxypropyl acrylate / methyl acrylate and acrylic acid / acrylamide methyl propane / hypophosphoric acid that appeared in the late 1980s, were all developed for inhibiting calcium phosphate. This promoted the development of "organophosphate (salt) copolymers" and phosphorus-based all-organic formulations, but phosphorus-based formulations still accounted for a large proportion until the early 1990s. Inorganic polyphosphate scale inhibitors such as tripolyphosphate and hexametaphosphate can effectively inhibit the formation of these scales. However, inorganic polyphosphates are easily hydrolyzed into orthophosphates, which not only reduces the effectiveness of these scale inhibitors, but also, if not properly controlled, can turn a less serious CaCO3 scale problem into a very serious Ca3(PO)4 scale problem. In addition, the enrichment of water bodies with phosphorus also limits the application of these inorganic polyphosphates. The advent of organophosphate (salt) scale inhibitors and polycarboxylic acid (PCA) inhibitors such as polyacrylic acid and polymaleic acid in the 1960s and 1970s brought about a breakthrough in scale inhibition technology. Compared with inorganic polyphosphate scale inhibitors, they have good chemical stability, are not easily hydrolyzed, can withstand higher water temperatures and high alkalinity, and have excellent inhibitory effects on CaCO3 scale. To reduce the phosphorus content in water, the phosphorus-based formulation of "inorganic polyphosphate-organophosphate (salt)-polyacrylic acid" has been widely used. However, organophosphate scale inhibitors easily form insoluble organophosphate-calcium ion complexes with calcium ions. The degradation products of organophosphate scale inhibitors can also form calcium phosphate precipitates with calcium ions. At high calcium ion concentrations, polyacrylic acid can also form insoluble polyacrylic acid-calcium ion complexes with calcium ions. These insoluble complexes and calcium phosphate precipitates not only reduce the scale inhibition effect of the scale inhibitor itself, but also induce the formation of other scale. Currently, oilfield water injection systems often employ a combination of various organophosphate scale inhibitors (such as ethylenediaminetetramethylene phosphoric acid and butane-1,2,4-tricarboxylic acid 2-phosphate). These scale inhibitors utilize their chelating effect on calcium ions and their dispersing effect on inorganic scale to alleviate single types of scaling, but they cannot comprehensively solve the scaling problem in oilfield water injection systems. Furthermore, while phosphorus-containing scale inhibitors disperse inorganic scale in the water, they also provide abundant nutrients for bacteria, making sterilization during oilfield injection water treatment more difficult. Poor sterilization can easily lead to equipment corrosion, scaling, and blockage. Summary of the Invention

[0004] To overcome the limitations of existing drag-reducing agents, which can only alleviate single types of scaling and cannot comprehensively solve the scaling problem in oilfield water injection systems, this invention provides a corrosion and scale inhibitor for oilfield water injection systems and its preparation method. Through the chelation and dispersion of scale-forming ions, it can simultaneously alleviate complex scaling in oilfield water injection systems, such as CaCO3 scale, CaSO4 scale, and BaSO4 scale. Moreover, the corrosion and scale inhibitor of this invention for oilfield water injection systems is phosphorus-free and will not provide nutrients to bacteria in the water within the oilfield water injection system, thereby reducing microbial corrosion and clogging of equipment in the water injection system.

[0005] The technical solution adopted in this invention is: a corrosion and scale inhibitor for oilfield water injection systems. The corrosion and scale inhibitor is a maleic anhydride / acrylic acid / diethylenetriamine copolymer synthesized through a polymerization reaction using maleic anhydride, acrylic acid, and diethylenetriamine as raw materials and a redox initiator. The corrosion and scale inhibitor has the structure shown in Formula I.

[0006] Formula I;

[0007] Where m ranges from 7 to 722, n ranges from 62 to 3180, and x ranges from 74 to 2286.

[0008] The weight ratio of maleic anhydride to acrylic acid and diethylenetriamine is 15-20:10-20:10-20.

[0009] A method for preparing a corrosion and scale inhibitor for oilfield water injection systems includes the following steps:

[0010] S1: Dissolve 15-20 parts by weight of maleic anhydride, 10-20 parts by weight of acrylic acid, and 2-4 parts by weight of 5% ferrous sulfate aqueous solution in 25-45 parts by weight of water and stir until completely dissolved. The temperature is controlled at 30-45℃ and kept at a constant temperature for 1-2 hours.

[0011] S2: Add 10-20 parts of a 50% diethylenetriamine aqueous solution and 4-6 parts of a 5% ammonium persulfate aqueous solution to the mixed solution in S1 in sequence. The heat released by the reaction raises the temperature of the mixed solution to 95-100℃.

[0012] S3: When the temperature of the mixed solution in S2 drops to 70-75℃, add 15-18 parts of 1% sodium hydroxide aqueous solution by mass percentage, control the pH value to 6-8, and keep it at a constant temperature in a water bath at 60-90℃ for 4-7 hours to obtain a maleic anhydride / acrylic acid / diethylenetriamine copolymer solution.

[0013] S4: Add 160-266 parts of ethanol to S3 and filter. Dry the insoluble matter at 50-60°C to obtain maleic anhydride / acrylic acid / diethylenetriamine copolymer.

[0014] The formed polymer undergoes a chelation reaction with divalent cations in water as follows:

[0015]

[0016] Where R 2+ For Ca 2+ Mg 2+ Ba 2+ 、Sr 2+ .

[0017] In steps S1 and S2, the weight ratio of maleic anhydride to acrylic acid, diethylenetriamine, and water is 15-20:10-20:10-20.

[0018] In step S3, the solid content in the maleic anhydride / acrylic acid / diethylenetriamine copolymer solution is ≥50%.

[0019] A method for preparing a corrosion and scale inhibitor for oilfield water injection systems yields an emulsion-type scale inhibitor with the following properties: scale inhibition rate of CaCO3 scale ≥91.5%, scale inhibition rate of CaSO4 scale ≥95.6%, scale inhibition rate of BaSO4 scale ≥90.5%, and corrosion inhibition rate ≤0.076 mm / a.

[0020] The corrosion and scale inhibitor prepared by the aforementioned method for use in oilfield water injection systems is added before the oilfield water source is treated, at a dosage of 30–80 mg / L.

[0021] When using the corrosion and scale inhibitor prepared by the aforementioned method for oilfield water injection systems, it is added after the oilfield injection water treatment, i.e., before the water injection pump, at a dosage of 30–50 mg / L.

[0022] The beneficial effects of this invention are as follows: 1. The corrosion and scale inhibitor of this invention for oilfield water injection systems, through chelation and dispersion of scale-forming ions, can simultaneously alleviate complex scaling in oilfield water injection systems, such as CaCO3 scale, CaSO4 scale, and BaSO4 scale, compared to existing single-scale treatment scale inhibitors; 2. The preparation method of this invention uses an oxidant / reducant initiation system. Utilizing the copolymerization characteristics of acrylic acid and maleic anhydride, free radical polymerization can be initiated at a lower temperature. The reaction conditions are mild, the system temperature fluctuation is small, and the polymerization process is easy to control. The resulting product is a polyacid-based anionic polymer. The final product is then obtained through diethyltriamine amidation. The amidated anionic polymer compound has stronger electronegativity and a stronger cation-chelating ability; 3. The raw materials required for preparing the corrosion and scale inhibitor for oilfield water injection systems according to this invention are readily available, the preparation process is simple, and the product quality is stable; 4. The corrosion and scale inhibitor of this invention for oilfield water injection systems is phosphorus-free and will not provide nutrients to bacteria in the water of the oilfield water injection system, thus reducing microbial corrosion and clogging of equipment in the water injection system.

[0023] The following will provide further explanation in conjunction with the accompanying drawings. Attached Figure Description

[0024] Figure 1 This is a scanning electron microscope image of calcium carbonate scale in an embodiment of the present invention.

[0025] Figure 2 This is a scanning electron microscope image of calcium carbonate scale after the addition of polymer in an embodiment of the present invention.

[0026] Figure 3 This is a scanning electron microscope image of calcium sulfate scale in an embodiment of the present invention.

[0027] Figure 4 This is a scanning electron microscope image of calcium sulfate scale after the addition of polymer in an embodiment of the present invention.

[0028] Figure 5 This is a graph showing the change in ion content in the produced fluid of well 102 in Example 1 of the present invention. Detailed Implementation

[0029] Example 1

[0030] A corrosion and scale inhibitor for oilfield water injection systems, comprising a maleic anhydride / acrylic acid / diethylenetriamine copolymer synthesized by polymerization reaction using maleic anhydride, acrylic acid, and diethylenetriamine as raw materials and employing a redox initiator, and having the structure shown in Formula I:

[0031] Formula I;

[0032] Where m ranges from 7 to 722, n ranges from 62 to 3180, and x ranges from 74 to 2286.

[0033] The weight ratio of maleic anhydride to acrylic acid and diethylenetriamine is 15-20:10-20:10-20.

[0034] Example 2

[0035] A method for preparing a corrosion and scale inhibitor for oilfield water injection systems includes the following steps:

[0036] S1: Dissolve 15-18 parts by weight of maleic anhydride, 10-20 parts by weight of acrylic acid, and 2-4 parts by weight of 5% ferrous sulfate aqueous solution in 25-45% water and stir until completely dissolved. Control the temperature at 30-45℃ and keep it at a constant temperature for 1-2 hours. If the temperature is below 30℃, maleic anhydride is not easily soluble in water. 0.5 hours is required to ensure that maleic anhydride is fully hydrolyzed into maleic acid. The temperature should not exceed 45℃ to prevent the reaction from being too violent when diethylenetriamine is added later.

[0037] S2: Add 10-20 parts of a 50% diethylenetriamine aqueous solution and 4-6 parts of a 5% ammonium persulfate aqueous solution to the mixed solution in S1 in sequence. The heat released by the reaction raises the temperature of the mixed solution to 95-100°C. The order of addition cannot be changed during the reaction. If ammonium persulfate is added first, maleic anhydride and acrylic acid will polymerize first, forming a water-insoluble gel.

[0038] S3: When the temperature of the mixed solution in S2 drops to 70-75℃, add 15-18 parts of a 1% sodium hydroxide aqueous solution, control the pH value to 6-8, and maintain the temperature in a constant temperature water bath at 60-90℃ for 4-7 hours to obtain a maleic anhydride / acrylic acid / diethylenetriamine copolymer solution. Adjust the pH value to 6-8 to make the acrylic acid polymer form a salt to increase the solubility of the product. Add diethylenetriamine copolymerization to increase the steric hindrance of the product, control the molecular weight, and prevent the product from gelling. Control the temperature and time to ensure the conversion rate of the polymer monomers.

[0039] S4: Add 160-266 parts of ethanol to S3 and filter. Dry the insoluble matter at 50-60°C to obtain maleic anhydride / acrylic acid / diethylenetriamine copolymer.

[0040] The formed polymer undergoes a chelation reaction with divalent cations in water as follows:

[0041]

[0042] Where R 2+ For Ca 2+ Mg2+ Ba 2+ 、Sr 2+ .

[0043] Scanning electron microscopy (SEM) of calcium carbonate scale with and without polymer was used to compare the calcium carbonate scale. Figure 1 , Figure 2 As shown, and a comparison of scanning electron microscopy of calcium sulfate scale with and without polymer, such as... Figure 3 , Figure 4 As shown, the addition of polymer alters the formation of calcium carbonate and calcium sulfate scale, making them looser and less dense. This is because during crystal growth, the polymer is adsorbed into the crystal growth lattice. This adsorption alters the normal morphology of the crystals, hindering their growth into larger crystals. The adsorption of scale inhibitor molecules significantly disrupts the regularity of the crystals, causing crystal deformation and reducing the strength of the scale crystals, making them looser and more easily washed away by water flow. This is the distortion effect of the polymer. Furthermore, polymer molecules can adsorb around crystal nuclei or particles, with their polar parts facing the aqueous phase and their non-polar parts adsorbed on the outside of the particles, resulting in particles carrying a slight negative charge. This charge repulsion prevents the particles from agglomerating due to collisions and hinders their growth. Scale-forming particles can be calcium and magnesium ions, or they can be composed of hundreds or thousands of CaCO3 and MgCO3 molecules.

[0044] In steps S1 and S2, the weight ratio of maleic anhydride to acrylic acid, diethylenetriamine, and water is 15-20:10-20:10-20.

[0045] In step S3, the solid content in the maleic anhydride / acrylic acid / diethylenetriamine copolymer solution is ≥50%. The solid content refers to the solid substance obtained by drying the polymer aqueous solution in S3 at 105±1℃ for 4 hours, with a solid content of ≥50%, to ensure the effect of corrosion inhibition and scale inhibition.

[0046] A method for preparing a corrosion and scale inhibitor for oilfield water injection systems yields an emulsion-type scale inhibitor with the following properties: scale inhibition rate of CaCO3 scale ≥91.5%, scale inhibition rate of CaSO4 scale ≥95.6%, scale inhibition rate of BaSO4 scale ≥90.5%, and corrosion inhibition rate ≤0.076 mm / a.

[0047] The corrosion and scale inhibitor prepared by the aforementioned method for use in oilfield water injection systems is added before the oilfield water source is treated, at a dosage of 30–80 mg / L.

[0048] When using the corrosion and scale inhibitor prepared by the aforementioned method for oilfield water injection systems, it is added after the oilfield injection water treatment, i.e., before the water injection pump, at a dosage of 30–50 mg / L.

[0049] Example 3

[0050] This embodiment employs the preparation method of a corrosion and scale inhibitor for oilfield water injection systems described in Example 2. The specific process is as follows: 20g of maleic anhydride, 35g of acrylic acid, 0.3g of ferrous sulfate, and 46g of water are added to a four-necked flask equipped with a stirrer, thermometer, pH meter, and dropping funnel. The mixture is stirred for 1.5 hours in a constant-temperature water bath at 40°C. Then, 10g of diethylenetriamine and 0.8g of 50% ammonium persulfate are added slowly in sequence. The temperature is lowered to 80°C, and 14g of 50% sodium hydroxide aqueous solution is added, resulting in a pH of 6.5. The constant-temperature water bath temperature is controlled at 65°C, and the mixture is stirred for 4 hours. A reddish-brown maleic anhydride / acrylic acid / diethylenetriamine polymer solution with a solid content of not less than 50% is obtained.

[0051] Example 4

[0052] This embodiment employs the preparation method of a corrosion and scale inhibitor for oilfield water injection systems described in Example 2. The specific process is as follows: 20g of maleic anhydride, 15g of acrylic acid, 0.3g of ferrous sulfate, and 46g of water are added to a four-necked flask equipped with a stirrer, thermometer, pH meter, and dropping funnel. The mixture is stirred for 1.5 hours in a constant-temperature water bath at 40°C. Then, 15g of diethylenetriamine and 0.8g of a 50% ammonium persulfate aqueous solution are added slowly in sequence. The temperature is lowered to 80°C, and 14g of a 50% sodium hydroxide aqueous solution is added, resulting in a pH of 6.5. The constant-temperature water bath temperature is controlled at 65°C, and the mixture is stirred at this temperature for 4 hours. A reddish-brown maleic anhydride / acrylic acid / diethylenetriamine polymer solution with a solid content of not less than 50% is obtained.

[0053] Example 5

[0054] This embodiment employs the preparation method of a corrosion and scale inhibitor for oilfield water injection systems described in Example 2. The specific process is as follows: 15g of maleic anhydride, 15g of acrylic acid, 0.3g of ferrous sulfate, and 36g of water are added to a four-necked flask equipped with a stirrer, thermometer, pH meter, and dropping funnel. The mixture is stirred for 1.5 hours in a constant-temperature water bath at 55°C. Then, 15g of diethylenetriamine and 0.8g of 50% ammonium persulfate are added slowly in sequence. The temperature is lowered to 80°C, and 14g of 50% sodium hydroxide aqueous solution is added, resulting in a pH of 6.5. The constant-temperature water bath temperature is controlled at 75°C, and the mixture is stirred for 4 hours. A reddish-brown maleic anhydride / acrylic acid / diethylenetriamine polymer solution with a solid content of not less than 50% is obtained.

[0055] Example 6

[0056] This embodiment employs the preparation method of a corrosion and scale inhibitor for oilfield water injection systems described in Example 2. The specific process is as follows: 20g of maleic anhydride, 15g of acrylic acid, 0.3g of ferrous sulfate, and 56g of water are added to a four-necked flask equipped with a stirrer, thermometer, pH meter, and dropping funnel. The mixture is stirred for 1.5 hours in a constant-temperature water bath at 55°C. Then, 10g of diethylenetriamine and 0.8g of a 50% ammonium persulfate aqueous solution are added slowly in sequence. The temperature is lowered to 80°C, and 14g of a 50% sodium hydroxide aqueous solution is added, resulting in a pH of 6.5. The constant-temperature water bath temperature is maintained at 90°C, and the mixture is stirred for 4 hours. A reddish-brown maleic anhydride / acrylic acid / diethylenetriamine polymer solution with a solid content of not less than 50% is obtained.

[0057] The performance of the corrosion and scale inhibitors prepared in Examples 3-6 for use in oilfield water injection systems was determined using the following methods:

[0058] 1. The scale inhibition rate of CaCO3 scale follows these steps:

[0059] (a) Take a 200 mL volumetric flask and add 6.00 mL of CaCl2 solution. 2+ Add 7.5 mL of a 1000 mg / L corrosion and scale inhibitor solution to a concentration of 4.00 mg / mL. Let stand for 10 minutes, then add 6.00 mL of Na₂CO₃ solution dropwise while shaking. 2- The concentration of the corrosion and scale inhibitor is 6.28 mg / mL. Dilute it to the mark with distilled water, shake well, and the concentration of the corrosion and scale inhibitor is 30 mg / L. Put the above solution into a 250 mL ground glass joint Erlenmeyer flask, cover it with a rubber stopper, weigh the total weight and record the reading. Place it in a 50±1℃ water bath and keep it at a constant temperature for half an hour. After the temperature is balanced, open the stopper to release the gas, then tighten the stopper and let it stand in a 50±1℃ water bath for 16 hours.

[0060] (b) The experiment was conducted simultaneously without the addition of corrosion and scale inhibitors, with all other steps being the same, and was recorded as blank 1;

[0061] (c) During the experiment, CO3 was added without the addition of Na2CO3 solution. 2- The sample was 6.28 mg / mL and without corrosion and scale inhibitors, with the other steps being the same; this was recorded as blank 2.

[0062] (d) After standing in a water bath at 50±1℃ for 16 hours, take out each ground glass flask and let it stand at room temperature. Weigh the total weight of the flask after cooling to room temperature and compare it with the total weight weighed in (a). If the weight loss is greater than or equal to 0.5g, distilled water must be added to the flask to make up for the moisture loss during the constant temperature period.

[0063] (e) Filter the supernatant by pouring it out using medium-speed qualitative filter paper. Collect the filtrate in a dry and clean Erlenmeyer flask. Then accurately transfer 25.00 mL of the supernatant into a clean Erlenmeyer flask and titrate it with 0.005 mol / L EDTA standard solution according to GB / T 7476.

[0064] (f) Presentation of experimental results

[0065] The scale inhibition rate x1 (%) of the CaCO3 scale inhibitor is calculated according to formula A1:

[0066]

[0067] Where: Ca 2+ 加样 After adding corrosion and scale inhibitors, the solution Ca 2+ Concentration, in milligrams per liter (mg / L); V 加样 To titrate the solution containing Ca after adding corrosion and scale inhibitors 2+ The concentration is expressed as the volume of EDTA standard solution consumed, in milliliters (mL); Ca 2+ 空白1 Ca in blank solution 1 2+ Concentration, in milligrams per liter (mg / L); V 空白1 To titrate Ca in blank solution 1 2+ The concentration is expressed as the volume of EDTA standard solution consumed, in milligrams (mL); Ca 2+ 空白2- Ca in blank solution 2 2+ Concentration, in milligrams per liter (mg / L); V 空白2 To titrate Ca in blank solution 2 2+ The concentration is expressed as the volume of EDTA standard solution consumed, in milliliters (mL).

[0068] 2. The scale inhibition rate of CaSO4 scale follows these steps.

[0069] (a) Take 150 mL of distilled water into a 250 mL volumetric flask, add 25.00 mL of CaCl2 solution, Ca 2+ Add 7.5 mL of a 1000 mg / L corrosion and scale inhibitor solution (calculated at 30.00 mg / mL), let stand for 10 minutes, then add 25.00 mL of Na₂SO₄ solution dropwise while shaking. 2- The concentration was 73.35 mg / mL. Dilute to the mark with distilled water, shake well, and the concentration was 30 mg / L. Pour the solution into a 250 mL Erlenmeyer flask with a ground glass stopper, seal with a rubber stopper, weigh the flask, record the reading, and place it in a 50±1℃ water bath. Maintain the temperature for half an hour until it reaches equilibrium, then open the stopper to release the gas, and then tighten the stopper. Let it stand in the 50±1℃ water bath for 24 hours.

[0070] (b) The experiment was conducted simultaneously without the addition of 1000 mg / L corrosion and scale inhibitor solution, with the other steps being the same, and was recorded as blank 1;

[0071] (c) The experiment simultaneously involved a solution without 1000 mg / L corrosion and scale inhibitor, and a Na2SO4 solution. 2- The concentration was 73.35 mg / mL. The remaining steps were the same, and this was recorded as blank 2.

[0072] (d) After standing in a water bath at 50±1℃ for 24 hours, take out each ground glass flask and let it stand at room temperature. Weigh the total weight of the flask after cooling to room temperature and compare it with the total weight weighed in (a). If the weight loss is greater than or equal to 0.5g, distilled water must be added to the flask to make up for the moisture loss during the constant temperature period.

[0073] (e) Filter the supernatant by pouring it out with medium-speed qualitative filter paper. Collect the filtrate in a dry and clean Erlenmeyer flask. Then accurately transfer 10.00 mL of the supernatant into a clean Erlenmeyer flask and titrate it with 0.05 mol / L EDTA standard solution according to GB / T 7476.

[0074] (f) Expression of experimental results

[0075] The scale inhibition rate of CaSO4 scale inhibitor x2 (%) is calculated according to formula A2:

[0076]

[0077] Where: Ca 2+ 加样 After adding corrosion and scale inhibitors, the solution Ca 2+ Concentration, in milligrams per liter (mg / L); V 加样 To titrate the solution containing Ca after adding corrosion and scale inhibitors 2+ The concentration is expressed as the volume of EDTA standard solution consumed, in milliliters (mL); Ca 2+ 空白1 Ca in blank solution 1 2+ Concentration, in milligrams per liter (mg / L); V 空白1 To titrate Ca in blank solution 1 2+ The concentration is expressed as the volume of EDTA standard solution consumed, in milligrams (mL); Ca 2+ 空白2 Ca in blank solution 2 2+ Concentration, in milligrams per liter (mg / L); V 空白2 To titrate Ca in blank solution 2 2+ The concentration is expressed as the volume of EDTA standard solution consumed, in milliliters (mL).

[0078] 3. The scale inhibition rate of BaSO4 scale follows these steps.

[0079] (a) Take 200 mL of distilled water into a 250 mL volumetric flask, add 5.00 mL of BaCl2 solution, Ba 2+ Add 2.06 mg / mL of a 1000 mg / L corrosion and scale inhibitor to 15.0 mL, let stand for 10 minutes, then add 5.00 mL of Na2SO4 solution dropwise while shaking. 2- The concentration of the corrosion and scale inhibitor is 2.06 mg / mL. Dilute to the mark with distilled water, shake well, and the concentration of the inhibitor is 60 mg / L. Pour the above solution into a 250 mL ground glass stoppered Erlenmeyer flask, seal with a rubber stopper, weigh the total amount and record the reading. Place the flask in a 50±1℃ water bath and maintain the temperature for half an hour until it reaches equilibrium. Afterward, open the stopper to release the gas, then tighten the stopper. Let the flask stand in the 50±1℃ water bath for 24 hours.

[0080] (b) A blank 1 was conducted simultaneously in the experiment without the addition of 1000 mg / L corrosion and scale inhibitor, with all other steps being the same.

[0081] (c) The experiment was conducted simultaneously without the addition of 1000 mg / L corrosion and scale inhibitor and Na2SO4 solution, SO4 2- The concentration was 2.06 mg / mL. The remaining steps were the same, and this was recorded as blank 2.

[0082] (d) After standing in a water bath at 50±1℃ for 24 hours, take out each ground glass flask and let it stand at room temperature. Weigh the total weight of the flask after cooling to room temperature and compare it with the total weight weighed in (a). If the weight loss is greater than or equal to 0.5g, distilled water must be added to the flask to make up for the moisture loss during the constant temperature period.

[0083] (e) Filter the supernatant using medium-speed qualitative filter paper, collect the filtrate in a dry and clean Erlenmeyer flask, then accurately transfer 25.0 mL of the supernatant into a clean Erlenmeyer flask, add 5.0 mL of ammonia-ammonium chloride buffer solution, and prepare according to the method specified in 4.1.3.3.1 of GB / T603--2002. Adjust the pH of the solution to 9-11, then add 2.0 mL of 0.01 mol / L EDTA-MgNa2 reagent solution, shake well, then add 1 to 2 drops of 5 g / L Chrome Black T indicator solution, and titrate with ET0.0025 mol / L EDTA standard solution. The endpoint is reached when the solution color changes abruptly from pink to pure blue.

[0084] (f) Presentation of experimental results

[0085] BaSO4 scale inhibitor scale inhibition rate x3

[0086]

[0087] In the formula: Ba 2+ 加样 To reduce the amount of Ba in the solution after adding corrosion and scale inhibitors 2+ Concentration, in milligrams per liter (mg / L); V 加样 To titrate the solution containing Ba after adding corrosion and scale inhibitors 2+ The concentration is measured in milliliters (mL) of the volume of EDTA standard solution consumed. 2+ 空白1 Ba in blank solution 1 2+ Concentration, in milligrams per liter (ml / L); V 空白1 To titrate Ba in blank solution 1 2+ The concentration is expressed as the volume of EDTA standard solution consumed, in milliliters (mL); Ba 2+ 空白2 Ba in blank solution 2 2+ Concentration, in milligrams per liter (mg / L); V 空白2 To titrate Ba in blank solution 2 2+ The concentration is expressed as the volume of EDTA standard solution consumed, in milliliters (mL).

[0088] 4. Determination of corrosion rate

[0089] (a) Preparation of the corrosive solution

[0090] Weigh out 50.0g NaCl, 2.0g MgCl2·6H2O, 6.0g Na2SO4, and 4.0g anhydrous CaCl2, dissolve them in distilled water to prepare a 950mL solution. Then weigh out 0.4g NaHCO3, dissolve it in a small amount of distilled water, mix the solutions before use, and dilute the solution to 1L. Prepare a 5L solution in a 5L bottom-necked bottle. Before use, add 80mg / L sodium sulfite directly to the prepared water to remove oxygen. This solution is used for an evaluation experiment to determine the corrosion rate.

[0091] (b) Operating procedures

[0092] b1: Directly inject 1120mL of the prepared corrosion solution into a 1L test bottle with the pre-coated scale inhibitor. Use a 4mL pipette to transfer 4.0mL of scale inhibitor solution into the test bottle, with a concentration of 50mg / L.

[0093] b2: After filling the corrosive solution, immediately attach the oxygen-removing balloon to the vent pipe at the top of the glass hanger, then use a spring clamp to hold the liquid inlet tube at the top of the test bottle, and finally seal the mouth of the test bottle with collodion.

[0094] b3: Place the sealed test bottle in a constant temperature water bath at 50±1℃ and let it stand for 72 hours;

[0095] b4: After the experiment is completed, remove the test piece and perform post-treatment of the test piece according to the requirements of 3.6.10 in SY / T 5273--2000;

[0096] (c) Presentation of experimental results

[0097] Corrosion rate calculation rcorr

[0098]

[0099] In the formula: rcorr is the corrosion rate, in millimeters per year (mm / year); m is the mass of the sample before the experiment, in grams (g); m1 is the mass of the sample after the experiment, in grams (g); S is the surface area of ​​the test site, in square centimeters (cm²). 2 ); t is the experimental time, in hours (h); p is the density of the sample, in grams per cubic centimeter (g / cm³). 2 ).

[0100] Table 1 Performance test results of corrosion and scale inhibitors prepared in Examples 3-6 for use in oilfield water injection systems

[0101]

[0102] As shown in Table 1, the corrosion and scale inhibitor of this invention for oilfield water injection systems, through chelation and dispersion of scale-forming ions, can simultaneously alleviate complex scaling in oilfield water injection systems, including CaCO3, CaSO4, and BaSO4 scales, compared to existing single-scale treatment agents. Furthermore, this corrosion and scale inhibitor is phosphorus-free and will not provide nutrients to bacteria in the water of the oilfield water injection system, thus reducing microbial corrosion of the equipment. The corrosion and scale inhibitor of this invention for oilfield water injection systems was applied to Well 102 in the Yumen Oilfield using a remote intelligent dosing device via annular injection. After one year of dynamic monitoring, the changes in ions in the produced fluid before and after the dosing were dynamically monitored. Figure 5 As shown, after the addition of the drug, the iron ion content decreased from 275 mg / L to 35 mg / L, and the Ca... 2+ The content increased from 130 mg / L to 228 mg / L, Ba 2+ The content increased from 38 mg / L to 62 mg / L, the iron ion concentration decreased, indicating a reduction in corrosion, and the scale-forming particle concentration increased, indicating a reduction in scaling. The anti-corrosion and anti-scaling effects are significant. It has good compatibility with chemical additives used in oil fields and can be widely used in oil and water wells.

[0103] The above examples are merely illustrative of the present invention and do not constitute a limitation on the scope of protection of the present invention. All designs that are the same as or similar to the present invention fall within the scope of protection of the present invention. The reagents, raw materials, or methods not described in detail in this invention are all prior art and will not be further described in this invention.

Claims

1. A method for preparing a corrosion and scale inhibitor for oilfield water injection systems, characterized in that: Corrosion and scale inhibitors are maleic anhydride / acrylic acid / diethylenetriamine copolymers synthesized through polymerization reaction using maleic anhydride, acrylic acid, and diethylenetriamine as raw materials and a redox initiator. The corrosion and scale inhibitors have the structure shown in Formula I. Formula I; Where m ranges from 7 to 722, n ranges from 62 to 3180, and x ranges from 74 to 2286, its preparation includes the following steps: S1: Dissolve 15-20 parts by weight of maleic anhydride, 10-20 parts by weight of acrylic acid, and 2-4 parts by weight of 5% ferrous sulfate aqueous solution in 25-45 parts by weight of water and stir until completely dissolved. Keep the temperature at 30-45℃ for 1-2 hours. S2: Add 10-20 parts of a 50% diethylenetriamine aqueous solution and 3-6 parts of a 5% ammonium persulfate aqueous solution to the mixed solution in S1 in sequence. The heat released by the reaction raises the temperature of the mixed solution to 95-100℃. S3: When the temperature of the mixed solution in S2 drops to 70-75℃, add 15-18 parts of 1% sodium hydroxide aqueous solution by mass percentage, control the pH value to 6-8, and keep it at a constant temperature in a water bath at 60-90℃ for 4-7 hours to obtain a maleic anhydride / acrylic acid / diethylenetriamine copolymer solution. S4: Add 160-266 parts of ethanol to S3 and filter. Dry the insoluble matter at 50-60°C to obtain maleic anhydride / acrylic acid / diethylenetriamine copolymer. The resulting polymer undergoes a chelation reaction with divalent cations in water as follows: Where R 2+ For Ca 2+ Mg 2+ Ba 2+ 、Sr 2+ .

2. The method for preparing a corrosion and scale inhibitor for oilfield water injection systems according to claim 1, characterized in that: The weight ratio of maleic anhydride to acrylic acid and diethylenetriamine is 15-20:10-20:10-20.

3. The method for preparing a corrosion and scale inhibitor for oilfield water injection systems according to claim 1, characterized in that: In step S3, the solid content in the maleic anhydride / acrylic acid / diethylenetriamine copolymer solution is ≥50%.

4. The emulsion-type scale inhibitor prepared by the method for preparing a corrosion and scale inhibitor for an oilfield water injection system according to claim 1 has the following properties: scale inhibition rate of CaCO3 scale ≥ 91.5%, scale inhibition rate of CaSO4 scale ≥ 95.6%, scale inhibition rate of BaSO4 scale ≥ 90.5%, and corrosion inhibition rate ≤ 0.076 mm / a.

5. The method of using the corrosion and scale inhibitor prepared by the method of preparing the corrosion and scale inhibitor for oilfield water injection system according to claim 1, wherein the corrosion and scale inhibitor is added before the oilfield water source is treated, and the addition amount is 30~80mg / L.

6. The method of using the corrosion and scale inhibitor prepared by the method of preparing a corrosion and scale inhibitor for an oilfield water injection system according to claim 1, wherein the corrosion and scale inhibitor is added after the oilfield injection water treatment, i.e. before the water injection pump, and the addition amount is 30~50mg / L.

Images