Non-aqueous phase scale inhibitor, use thereof, reagent combination for oilfield squeeze treatment method, and Anti-scaling squeeze treatment method for oilfields
By using a low-density non-aqueous scale inhibitor, the problem of poor performance of traditional water-based scale inhibitors under specific downhole conditions is solved, achieving more efficient scale inhibition and reducing operating costs. It is suitable for oilfield scale prevention and injection methods.
Patent Information
- Authority / Receiving Office
- WO · WO
- Patent Type
- Applications
- Current Assignee / Owner
- CHINA NAT PETROLEUM CORP
- Filing Date
- 2025-12-18
- Publication Date
- 2026-07-09
Smart Images
Figure CN2025143593_09072026_PF_FP_ABST
Abstract
Description
Non-aqueous scale inhibitors and their applications, oilfield injection methods for use with casing agents, and oilfield scale prevention injection methods.
[0001] Cross-references to related applications
[0002] This application claims the benefit of Chinese patent application 202411990404.X, filed on December 31, 2024, the contents of which are incorporated herein by reference. Technical Field
[0003] This invention relates to the field of oil and gas, specifically to a non-aqueous scale inhibitor and its application, a casing agent for oilfield injection methods, and a method for preventing scale buildup during oilfield injection. Background Technology
[0004] During oilfield production, changes in pressure and temperature, or the mixing of incompatible water phases, can cause scaling in formations, wellbores, and pipelines. Without effective anti-scaling measures, scaling can lead to blockages in oil passages and damage to production equipment, severely impacting crude oil production. Currently, many oilfields have entered a high water-cut phase, and scaling problems are becoming increasingly prominent. Typical scaling problems are related to the formation of barium sulfate (BaSO4), strontium sulfate (SrSO4), calcium sulfate (CaSO4), and calcium carbonate (CaCO3). Solutions are highly dependent on on-site operating conditions and the severity of scaling. To prevent the formation of these inorganic scales in the system, the most common and economical method is continuous injection of chemical scale inhibitors or periodic scale inhibitor injection treatment. When performing scale prevention treatment in the near-wellbore formation perimeter area, scale inhibitor injection is usually the best choice. The scale inhibitor injection process includes the following steps: (i) pre-flushing with pre-fluid through the production well; (ii) injection of the main scale inhibitor solution (injecting a 5-20% concentration of scale inhibitor into the formation through the production well); (iii) post-fluid propulsion; (iv) well shut-in; and (v) well opening for production and collecting water samples for scale inhibitor concentration determination. The requirements for chemical scale inhibitors in the injection technology are: high scale prevention efficiency, preventing scale formation in near-wellbore formations, perforation holes, well tubing, nozzles, and surface equipment; good thermal stability suitable for reservoir temperature conditions and easy trace detection; easy and good adsorption into the formation, and slow desorption and release; good compatibility with formation fluids and other chemical treatment agents; and no damage to the formation. From an economic perspective, the minimum effective concentration (MEC) of the scale inhibitor should be as low as possible, and it should be non-toxic and non-polluting. Each successful treatment design should achieve a well protection cycle of more than six months.
[0005] Traditional scale injection treatments often rely on water-based scale inhibitors, which may be unsuitable or ineffective in certain situations, particularly when special fluid media are required or when facing extreme downhole conditions. For example, scale injection treatment is necessary for low-water-producing wells or water-sensitive formations. Furthermore, some wells in late-stage oilfields often face relatively low reservoir pressures. Injecting large amounts of brine-based scale inhibitors into the formation without effective booster measures can damage the well. Traditional scale injection treatments typically involve pumping tens of tons of scale inhibitor brine solution into the formation to achieve a good scale inhibitor injection life. Summary of the Invention
[0006] The purpose of this invention is to provide a low-density non-aqueous scale inhibitor. This low-density non-aqueous scale inhibitor can improve the efficiency and effectiveness of scale inhibition treatment and reduce the maintenance requirements of downhole equipment, thereby reducing long-term operating costs.
[0007] The inventors of this invention have discovered that the density of scale inhibitor brine solutions is usually greater than 1. For wells with low reservoir pressure, brine-based injection treatment is not a good option. If a fluid with a density less than 1 and close to that of crude oil is used, pumping in tens of tons of the lighter fluid can help lift the well and quickly restore the oil production level to the level before injection. In addition, according to the principle of relative permeability, using non-aqueous scale inhibitor injection treatment can sometimes lead to increased crude oil production.
[0008] To achieve the above objectives, the first aspect of the present invention provides a non-aqueous scale inhibitor, the non-aqueous scale inhibitor comprising: an acrylic copolymer, an alcohol ether solvent, an alkyl diol solvent, and water;
[0009] The density of the non-aqueous scale inhibitor is not higher than 0.97 g / cm³. 3 The acrylic copolymer has a diallyl ammonium salt structural unit as shown in formula (I) and an acrylic structural unit as shown in formula (II);
[0010] In equation (I), R 111 R 112 R 10 R 11 R 12 R 13 R 14 R 15 R 16 R 17 R 18 and R 19 Each is independently selected from H or an organic group having 1-20 carbon atoms, X - It is an anion; in formula (II), R 21 R 22 and R23 Each is independently selected from H, C1-C6 alkyl or phenyl.
[0011] The second aspect of the present invention provides an application of a non-aqueous scale inhibitor in oilfield scale prevention, wherein the non-aqueous scale inhibitor is the non-aqueous scale inhibitor described in the first aspect of the present invention.
[0012] The third aspect of the present invention provides a casing agent for an oilfield scale inhibitor injection method, the casing agent comprising: a pre-fluid; the non-aqueous scale inhibitor described in the first aspect of the present invention; and a post-fluid.
[0013] A fourth aspect of the present invention provides a method for preventing scale buildup in oilfields, the method comprising:
[0014] S1. Pre-flushing with pre-fluid through the production well;
[0015] S2. Inject non-aqueous phase scale inhibitor;
[0016] S3, rear-mounted liquid propulsion;
[0017] Wherein, the pre-fluid, the non-aqueous scale inhibitor, and the post-fluid are respectively the pre-fluid, the non-aqueous scale inhibitor, and the post-fluid in the kit described in the third aspect of the present invention.
[0018] Through the above technical solution, the present invention has at least the following beneficial effects:
[0019] The non-aqueous scale inhibitor of this invention has a lower density, allowing it to be used in a wider range of geological conditions and downhole environments. This improves the applicability and flexibility of the treatment. Applying it to non-aqueous products avoids water-related formation damage (water or emulsion blockage, the influence of relative permeability, etc.), facilitates rapid well cleaning, reduces well static head pressure, and extends the life of the scale inhibitor injection. At the same time, it can more effectively prevent and control scale formation, thereby enhancing the scale inhibition effect. In other words, the non-aqueous scale inhibitor of this invention can improve the efficiency and effectiveness of scale inhibition treatment and reduce the maintenance requirements of downhole equipment, thus reducing long-term operating costs. Attached Figure Description
[0020] Figure 1 is a schematic diagram of an oilfield anti-scaling injection method according to one embodiment of the present invention;
[0021] Figure 2 is a graph showing the relationship between the aqueous phase transfer and distribution of the non-aqueous scale inhibitor and time under different mixing ratios of the non-aqueous scale inhibitor and crude oil in Example 1. Detailed Implementation
[0022] The endpoints and any values of the ranges disclosed herein are not limited to the precise ranges or values, and these ranges or values should be understood to include values close to these ranges or values. For numerical ranges, the endpoint values of the various ranges, the endpoint values of the various ranges and individual point values, and individual point values can be combined with each other to obtain one or more new numerical ranges, which should be considered as specifically disclosed herein.
[0023] The first aspect of this invention provides a non-aqueous scale inhibitor, the non-aqueous scale inhibitor comprising: an acrylic copolymer, an alcohol ether solvent, an alkyl glycol solvent, and water;
[0024] The density of the non-aqueous scale inhibitor is not higher than 0.97 g / cm³. 3 The acrylic copolymer has a diallyl ammonium salt structural unit as shown in formula (I) and an acrylic structural unit as shown in formula (II);
[0025] In equation (I), R 111 R 112 R 10 R 11 R 12 R 13 R 14 R 15 R 16 R 17 R 18 and R 19 Each is independently selected from H or an organic group having 1-20 carbon atoms, X - It is an anion; in formula (II), R 21 R 22 and R 23 Each is independently selected from H, C1-C6 alkyl or phenyl.
[0026] The non-aqueous low-density scale inhibitor of this invention can be used in a wider range of geological conditions and downhole environments, improving the applicability of the treatment. It offers better applicability and flexibility. Applying non-aqueous products avoids water-related formation damage (water or emulsion blockage, the effects of relative permeability), and has advantages such as rapid well cleaning, reduced well static head pressure, and extended scale inhibitor injection life.
[0027] In this invention, the non-aqueous phase refers to a fluid composition in which a non-aqueous solvent (such as alcohol ethers or alkyl glycols) is the main continuous phase. This composition may contain a small amount of water, but its physicochemical properties (such as density and miscibility with crude oil) are dominated by the non-aqueous solvent.
[0028] The densities mentioned in this invention refer to values measured under standard temperature and pressure conditions (25°C, 1 standard atmosphere). Densities can be measured using conventional instruments such as standard densitometers or oscillating tube densitometers.
[0029] The non-aqueous scale inhibitor of this invention has a low density, which can be selected within a wide range. In a preferred embodiment, the density of the non-aqueous scale inhibitor is 0.93 g / cm³. 3 -0.95g / cm 3 .
[0030] According to a preferred embodiment of the present invention, the pH of the non-aqueous scale inhibitor is 2.5-3.5.
[0031] In this invention, any method in the art can be used to adjust the pH of the non-aqueous scale inhibitor to 2.5-3.5. In a preferred embodiment, the non-aqueous scale inhibitor contains a pH adjuster, the content of which is such that the pH of the non-aqueous scale inhibitor is 2.5-3.5. That is, in this invention, a pH adjuster is used to adjust the pH value of the mixed system.
[0032] According to a preferred embodiment of the present invention, the pH adjuster is selected from at least one of hydrochloric acid, formic acid and acetic acid, preferably hydrochloric acid.
[0033] In this invention, the hydrochloric acid is an aqueous solution of hydrogen chloride, and its concentration is generally 36-38 wt%.
[0034] In this invention, the specific amount of the alcohol ether solvent is not particularly limited, as long as it can completely dissolve the acrylic copolymer. According to a preferred embodiment of the invention, the weight ratio of the alcohol ether solvent to the acrylic copolymer is (7-17):1, for example, 7:1, 8:1, 9:1, 12:1, 13:1, 14:1, 15:1, 16:1, 17:1, and any range of any two ratios, preferably (8-15):1.
[0035] According to a preferred embodiment of the present invention, the weight ratio of the alcohol ether solvent to the alkyl diol solvent is (20-45):1, for example, 20:1, 24:1, 27:1, 28:1, 30:1, 35:1, 42:1, 45:1, and any range between any two ratios, preferably (24-36):1.
[0036] In this invention, by controlling the ratio of alcohol ether solvents to alkyl diol solvents within the above-mentioned range, a better scale inhibition effect can be achieved.
[0037] According to a preferred embodiment of the present invention, the weight ratio of the alcohol ether solvent to water is (10-14):1, for example, 10:1, 11:1, 12:1, 13:1, 14:1, and any range between any two ratios.
[0038] In this invention, by controlling the ratio of alcohol ether solvent to water within the above-mentioned range, a better scale inhibition effect can be achieved.
[0039] In this invention, the alcohol ether solvent refers to a solvent containing hydroxyl groups and ether bonds. According to a preferred embodiment of this invention, the structure of the alcohol ether solvent is shown in formula (A).
[0040] In formula (A), Y is selected from ethylidene or propyleneide, n is 1, 2 or 3, Z is a C1-C6 alkyl group, OH is a hydroxyl group, and O is an oxygen atom.
[0041] In this invention, when Y is propylidene, the propylidene can be orthopropylidene or isopropylidene, preferably orthopropylidene.
[0042] In a preferred embodiment of the present invention, in formula (A): Y is selected from ethylene. By employing the aforementioned embodiments, a better scale inhibition effect can be achieved.
[0043] According to a preferred embodiment of the present invention, in formula (A): n is 1 or 2, preferably 1.
[0044] In this invention, in formula (A): Z is a C1-C6 alkyl group. The C1-C6 alkyl group refers to an alkyl group containing 1-6 carbon atoms. When the number of carbon atoms is not less than 3, it can be a straight-chain alkyl group or a branched-chain alkyl group, preferably a straight-chain alkyl group.
[0045] According to a preferred embodiment of the present invention, in formula (A): Z is a C4-C6 alkyl group, preferably a C4-C6 straight-chain alkyl group.
[0046] Specific alcohol ether solvents that can be listed in this invention include diethylene glycol butyl ether, diethylene glycol hexyl ether, propylene glycol butyl ether, ethylene glycol hexyl ether, and ethylene glycol butyl ether.
[0047] According to a preferred embodiment of the present invention, the alkyl glycol solvent is selected from C2-C6 alkyl glycols, such as ethylene glycol, 1,2-propanediol, and 1,2-butanediol. Preferably, the alkyl alcohol solvent is selected from at least one of ethylene glycol, propylene glycol, and butanediol.
[0048] According to the present invention, it is understood that the scale inhibitor is mainly composed of acrylic copolymers. As long as the purpose of the present invention can be achieved, any acrylic copolymer containing acrylic structural units and diallyl ammonium salt structural units is applicable to the system of the present invention, and there is no special limitation on the size of the copolymer.
[0049] In a preferred embodiment, the weight-average molecular weight of the acrylic copolymer is 2000 g / mol to 4000 g / mol.
[0050] The weight-average molecular weight in this invention can be detected by gel chromatography.
[0051] In this invention, R 111 R 112 R 10 R 11 R 12 R 13 R 14 R 15 R 16 R 17 R 18 and R 19 The specific functional group is not particularly limited. Organic functional groups with 1-20 carbon atoms well known in the art are all applicable to the system of the present invention. According to a preferred embodiment of the present invention, in formula (I), R 111 R 112 R 10 R 11 R 12 R 13 R 14 R 15 R 16 R 17 R 18 and R 19 Each is independently selected from H or C1-C20 alkyl groups.
[0052] According to a preferred embodiment of the present invention, in formula (I), R 111 R 112 Each is independently selected from C1-C20 alkyl groups; in formula (I), R 10 R 11 R 12 R 13 R 14 R 15 R 16 R 17 R 18 and R 19 Each is independently selected from H or C1-C20 alkyl groups.
[0053] In this invention, the C1-C20 alkyl group refers to an alkyl group having 1-20 carbon atoms. It can be a straight-chain alkyl group or a branched-chain alkyl group, preferably a straight-chain alkyl group. Examples of C1-C20 alkyl groups include C1 alkyl (methyl), C2 alkyl (ethyl), C3 alkyl (e.g., n-propyl, isopropyl), C4 alkyl (e.g., n-butyl, tert-butyl), C5 alkyl (e.g., n-pentyl), C6 alkyl (e.g., n-hexyl), C7 alkyl (e.g., n-heptyl), and C8 alkyl (e.g., n-hepyl). Alkyl (e.g., n-octyl), C9 alkyl (e.g., n-nonyl), C10 alkyl (e.g., n-decyl), C11 alkyl (e.g., n-undecyl), C12 alkyl (e.g., n-dodecyl), C13 alkyl (e.g., n-tridecyl), C14 alkyl (e.g., n-tetradecyl), C15 alkyl (e.g., n-pentadecanyl), C16 alkyl (e.g., n-hexadecyl), C17 alkyl (e.g., n-heptadecyl), C18 alkyl (e.g., n-octadecyl), C20 alkyl (e.g., n-eicosyl), etc.
[0054] In a preferred embodiment, in formula (I), R 111 R 112 R 10 R 11 R 12 R 13 R 14 R 15 R 16 R 17 R 18 and R 19 Each alkyl group is independently selected from H or C1-C10, preferably each alkyl group is independently selected from H or C1-C5.
[0055] In a preferred embodiment, in formula (I), R 111 R 112 R 10 R 11 R 12 R 13 R 14 R 15 R 16 R 17 R 18 and R 19 They can be the same or different; preferably, R 111 and R 112 Same, R 10 R 11 R 12 and R 13 Same, R 14 R 15 R 16 and R17 Same, R 18 and R 19 same.
[0056] In formula (I) of this invention, "R" is used. 111 and R 112 Methyl', R 10 R 11 R 12 and R 13 For H, R 14 R 15 R 16 and R 17 For H, R 18 and R 19 The use of "H" is intended to illustrate the advantages of the present invention, but should not be construed as a limitation thereof.
[0057] According to a preferred embodiment of the present invention, in formula (II), R 21 R 22 and R 23 Each is independently selected from H or C1-C6 alkyl groups (e.g., methyl, ethyl, propyl, butyl, pentyl, or hexyl). In formula (II) of this invention, "R" is used to indicate the alkyl group. 21 R 22 and R 23 The use of "H" is intended to illustrate the advantages of the present invention, but should not be construed as a limitation thereof.
[0058] In this invention, unless otherwise specified, the content of each structural unit in the acrylic copolymer is based on the amount of the corresponding monomer fed.
[0059] In this invention, the content of diallyl ammonium salt structural units and acrylic structural units in the acrylic copolymer can be selected within a wide range. According to a preferred embodiment of the invention, the molar ratio of the diallyl ammonium salt structural units to the acrylic structural units is 1:(1-30), for example, 1:1, 1:3, 1:5, 1:7, 1:9, 1:12, 1:14, 1:15, 1:16, 1:18, 1:20, 1:22, 1:25, 1:27, 1:30, and any range between any two ratios.
[0060] In this invention, the acrylic copolymer may also contain other structural units besides diallyl ammonium salt structural units and acrylic structural units as needed.
[0061] According to a preferred embodiment of the present invention, the acrylic copolymer further comprises a sulfonic acid-containing structural unit as shown in formula (III).
[0062] In equation (III), R 31 Selected from monovalent metal ions, R 32 R 33 R 34 Each is independently selected from H or C1-C6 alkyl groups (e.g., methyl, ethyl, propyl, butyl, pentyl, or hexyl).
[0063] According to a preferred embodiment of the present invention, in formula (III): R 31 Selected from potassium ions or sodium ions.
[0064] According to the present invention, when the acrylic copolymer of the present invention contains sulfonic acid structural units, the content of the sulfonic acid structural units can be selected within a wide range. According to a preferred embodiment of the present invention, the molar ratio of the sulfonic acid structural units to the acrylic structural units is 1:(1-30), for example, 1:1, 1:3, 1:5, 1:7, 1:9, 1:12, 1:14, 1:15, 1:16, 1:18, 1:20, 1:22, 1:25, 1:27, 1:30, and any range between any two ratios.
[0065] According to a preferred embodiment of the present invention, the acrylic copolymer further comprises a diacid structural unit as shown in formula (IV).
[0066] In equation (IV), R 41 R 42 Each is independently selected from H, C1-C6 alkyl or phenyl groups.
[0067] According to a preferred embodiment of the present invention, in formula (IV), R 41 R 42 Each is independently selected from H or C1-C3 alkyl groups.
[0068] According to the present invention, when the acrylic copolymer of the present invention contains diacid structural units, the content of the diacid structural units can be selected within a wide range. According to a preferred embodiment of the present invention, the molar ratio of the diacid structural units to the acrylic structural units is 1:(1-30), and is 1:1, 1:3, 1:5, 1:7, 1:9, 1:12, 1:14, 1:15, 1:16, 1:18, 1:20, 1:22, 1:25, 1:27, 1:30, and any range between any two ratios.
[0069] The acrylic copolymers of this invention can be prepared according to methods well known to those skilled in the art. Particularly preferably, the acrylic copolymers of this invention can be polymerized by providing monomers with corresponding structural units under solution free radical polymerization conditions. The structures of the monomers corresponding to the diallyl ammonium salt structural units are shown in formula (IA), and the structures of the monomers corresponding to the acrylic structural units are shown in formula (IIA).
[0070] R in equation (IA) 111 R 112 R 10 R 11 R 12 R 13 R 14 R 15 R 16 R 17 R 18 R 19 and X - The definition of R as described in equation (I) 111 R 112 R 10 R 11 R 12 R 13 R 14 R 15 R 16 R 17 R 18 R 19 and X - The definitions correspond to the same; R in equation (IIA) 21 R 22 and R 23 The definition of R in equation (II) 21 R 22 and R 23 The definitions correspond to the same; R in equation (IIIA) 31 R 32 R 33 R 34 The definition of R in equation (III) 31 R 32 R 33 R 34 The definitions correspond to the same; R in equation (IVA) 41 R 42 The definition of R in equation (IV) 41 R 42 The definitions correspond to the same.
[0071] In the preparation of acrylic copolymers by solution radical polymerization, the solution radical polymerization of monomers can be achieved under conditions known in the prior art. For example, the solution radical polymerization reaction is carried out in the presence of an initiator and a chain transfer agent. The amount of initiator is generally 0.1-1 wt% of the total monomer, and the amount of chain transfer agent is generally 5-10 wt% of the total monomer. The chain transfer agent is generally a hypophosphite (e.g., sodium hypophosphite), and the initiator is generally a peroxide initiator (e.g., sodium persulfate, potassium persulfate, ammonium persulfate, hydrogen peroxide, etc.). In the art, during the polymerization reaction, the initiator and chain transfer agent are generally dissolved separately in water, or... Simultaneously, it is dissolved in water and slowly introduced into the polymerization reaction system; the solvent used in solution free radical polymerization is generally water, and the amount of water is generally 0.8-6 times the weight of the monomer. During polymerization, an alkaline neutralizing agent (such as an aqueous solution of sodium hydroxide) can be added to make the pH of the polymerization reaction system 6-8; in order to avoid the influence of active components such as oxygen in the air on the polymerization reaction, nitrogen can be used to purge the system before polymerization (i.e. before the initiator is added); in the specific polymerization, after the initiator and chain transfer agent are added, the reaction can continue at the reflux temperature for 1-3 hours, and then the acrylic copolymer can be separated according to the conventional separation method in the art.
[0072] The non-aqueous scale inhibitor of the present invention can be used in a variety of scale inhibition scenarios. The second aspect of the present invention provides an application of the non-aqueous scale inhibitor in oilfield scale prevention, wherein the non-aqueous scale inhibitor is the non-aqueous scale inhibitor described in the first aspect of the present invention.
[0073] The non-aqueous scale inhibitor in this invention exhibits good compatibility with formation water and crude oil under formation temperature conditions when used for scale prevention in oilfields. It does not damage the bottom layer and has excellent scale inhibition efficiency, i.e., a low minimum effective concentration (MEC). In this invention, the minimum effective concentration (MEC) refers to the lowest scale inhibition concentration that can prevent scale formation under standard test conditions such as dynamic loop testing.
[0074] The third aspect of the present invention provides a casing agent for an oilfield scale inhibitor injection method, the casing agent comprising: a pre-fluid; the non-aqueous scale inhibitor described in the first aspect of the present invention; and a post-fluid.
[0075] In this invention, the "casing agent" refers to a set of independent fluid combinations used in conjunction with a complete oilfield scale prevention and injection operation. In this invention, the casing agent containing the non-aqueous scale inhibitor described herein, used in the oilfield scale prevention and injection method, facilitates rapid well cleaning and flowback after injection treatment, and the scale inhibitor exhibits excellent rock adsorption properties, thereby ensuring the injection treatment cycle.
[0076] The pre-fluid and post-fluid in this invention can be non-aqueous fluids conventional in the art, including but not limited to diesel and / or mineral oil.
[0077] A fourth aspect of the present invention provides a method for preventing scale buildup in oilfields, the method comprising:
[0078] S1. Pre-flushing with pre-fluid through the production well;
[0079] S2. Inject non-aqueous phase scale inhibitor;
[0080] S3, rear-mounted liquid propulsion;
[0081] Wherein, the pre-fluid, the non-aqueous scale inhibitor, and the post-fluid are respectively the pre-fluid, the non-aqueous scale inhibitor, and the post-fluid in the kit described in the third aspect of the present invention.
[0082] The oilfield scale prevention and injection method of the present invention can help with rapid well cleaning and backflow after injection treatment, and can thus ensure the injection treatment cycle.
[0083] According to a preferred embodiment of the present invention, in step S3, the amount of the post-treatment liquid is sufficient to advance the non-aqueous scale inhibitor into the formation to a depth of 3-5 meters.
[0084] According to a specific embodiment of the present invention, as shown in FIG1, the method for preventing scale buildup in oilfields includes:
[0085] (1) Perform pre-flushing with a non-aqueous fluid such as diesel or mineral oil through the production well; (2) Inject a non-aqueous scale inhibitor; (3) Propel the post-fluid with a non-aqueous fluid such as diesel or mineral oil. The amount of post-fluid should be such that the scale inhibitor is propelled to a formation depth of about 3-5 meters; (4) Shut down the well; (5) Start production and collect water samples to determine the scale inhibitor concentration.
[0086] The present invention will be described in detail below through examples. Unless otherwise specified, the raw materials used in the following preparation examples and embodiments are commercially available.
[0087] Preparation Example
[0088] Preparation Example 1
[0089] Preparation of polyacrylic acid-diallyldimethylammonium chloride:
[0090] A reactor equipped with a mechanical stirrer, condenser, thermometer, and inlet was prepared. Acrylic acid, diallyl dimethyl ammonium chloride, and deionized water were added and heated to 60°C for mixing. A 38 wt% sodium hydroxide aqueous solution was added to neutralize the reaction mixture to pH 7. The mixture was then purged with nitrogen for 30 minutes and heated to 70°C. A 25 wt% sodium persulfate aqueous solution and a 33 wt% sodium hypophosphite aqueous solution were added to induce polymerization. The reaction mixture was then heated to reflux and stirred for 2 hours. Finally, polyacrylic acid-diallyl dimethyl ammonium chloride was obtained and its weight-average molecular weight was measured to be 2942 g / mol.
[0091] The weight ratio of acrylic acid, diallyl dimethyl ammonium chloride, deionized water, sodium persulfate, and sodium hypophosphite is 1:0.13:0.9:0.008:0.09.
[0092] Preparation Example 2
[0093] Preparation of polyacrylic acid-sodium propylene sulfonate-diallyl dimethyl ammonium chloride:
[0094] A reactor equipped with a mechanical stirrer, condenser, thermometer, and inlet was prepared. Acrylic acid, diallyl dimethyl ammonium chloride, sodium propylene sulfonate, and deionized water were added and heated to 60°C for mixing. A 38 wt% sodium hydroxide aqueous solution was added to neutralize the reaction mixture to pH 7.5. The mixture was then purged with nitrogen for 30 minutes and heated to 70°C. A 25 wt% sodium persulfate aqueous solution and a 33 wt% sodium hypophosphite aqueous solution were added to induce polymerization. The reaction mixture was then heated to reflux and stirred for 2 hours. Finally, polyacrylic acid-sodium propylene sulfonate-diallyl dimethyl ammonium chloride was obtained, with a weight-average molecular weight of 3846 g / mol.
[0095] The weight ratio of acrylic acid, sodium propylene sulfonate, diallyl dimethyl ammonium chloride, deionized water, sodium persulfate, and sodium hypophosphite is 1:0.09:0.09:1:0.009:0.1.
[0096] Preparation Example 3
[0097] Preparation of polyacrylic acid-maleic acid-diallyldimethylammonium chloride:
[0098] A reactor equipped with a mechanical stirrer, condenser, thermometer, and inlet was prepared. Acrylic acid, diallyl dimethyl ammonium chloride, maleic acid, and deionized water were added and heated to 60°C for mixing. A 38wt% sodium hydroxide aqueous solution was added to neutralize the reaction mixture to a pH of 6.9. The mixture was then purged with nitrogen for 30 minutes and heated to 70°C. A 25wt% sodium persulfate aqueous solution and a 33wt% sodium hypophosphite aqueous solution were added to induce polymerization. The reaction mixture was then heated to reflux and stirred for 2 hours. Finally, polyacrylic acid-maleic acid-diallyl dimethyl ammonium chloride was obtained, with a weight-average molecular weight of 3634 g / mol.
[0099] The weight ratio of acrylic acid, sodium propylene sulfonate, maleic acid, deionized water, sodium persulfate, and sodium hypophosphite is 1:0.09:0.09:1:0.009:0.1.
[0100] Example 1
[0101] Preparation of non-aqueous scale inhibitors:
[0102] By weight, 6.25 parts of polyacrylate-diallyldimethylammonium chloride, 83.75 parts of ethylene glycol butyl ether, 3 parts of ethylene glycol, and 7 parts of water from Preparation Example 1 were added and mixed. The pH of the mixture was then adjusted to 3 using 36 wt% hydrochloric acid to obtain a non-aqueous scale inhibitor with a density of 0.942 g / cm³. 3 .
[0103] Example 2
[0104] Preparation of non-aqueous scale inhibitors:
[0105] By weight, 9.65 parts of polyacrylic acid-maleic acid-diallyldimethylammonium chloride, 81.35 parts of ethylene glycol butyl ether, 2.3 parts of propylene glycol, and 6.7 parts of water from Preparation Example 2 were added and mixed. The pH of the mixture was then adjusted to 2.5 using 36wt% hydrochloric acid to obtain a non-aqueous scale inhibitor with a density of 0.948 g / cm³. 3 .
[0106] Example 3
[0107] Preparation of non-aqueous scale inhibitors:
[0108] By weight, 9 parts of polyacrylic acid-maleic acid-diallyldimethylammonium chloride, 84 parts of ethylene glycol hexyl ether, 3.5 parts of ethylene glycol, and 7.5 parts of water from Preparation Example 3 were added and mixed. The pH of the mixture was then adjusted to 2.8 using 36 wt% hydrochloric acid to obtain a non-aqueous scale inhibitor with a density of 0.949 g / cm³. 3 .
[0109] Example 4
[0110] By weight, 6.25 parts of polyacrylate-diallyldimethylammonium chloride, 83.75 parts of ethylene glycol butyl ether, 3 parts of ethylene glycol, and 7 parts of water from Preparation Example 1 were added and mixed. The pH of the mixture was then adjusted to 3 using 10wt% sulfuric acid to obtain a non-aqueous scale inhibitor with a density of 0.947 g / cm³. 3 .
[0111] Example 5
[0112] By weight, 6.25 parts of polyacrylate-diallyldimethylammonium chloride, 86 parts of ethylene glycol butyl ether, 1 part of ethylene glycol, and 7 parts of water from Preparation Example 1 were added and mixed. The pH of the mixture was then adjusted to 3 using 36 wt% hydrochloric acid to obtain a non-aqueous scale inhibitor with a density of 0.937 g / cm³. 3 .
[0113] Example 6
[0114] By weight, 6.25 parts of polyacrylate-diallyldimethylammonium chloride, 80 parts of ethylene glycol butyl ether, 6.75 parts of ethylene glycol, and 7 parts of water from Preparation Example 1 were added and mixed. The pH of the mixture was then adjusted to 3 using 36 wt% hydrochloric acid to obtain a non-aqueous scale inhibitor with a density of 0.944 g / cm³. 3 .
[0115] Example 7
[0116] By weight, 6.25 parts of polyacrylate-diallyldimethylammonium chloride, 83.75 parts of propylene glycol methyl ether, 3 parts of ethylene glycol, and 7 parts of water from Preparation Example 1 were added and mixed. The pH of the mixture was then adjusted to 3 using 36wt% hydrochloric acid to obtain a non-aqueous scale inhibitor with a density of 0.967 g / cm³. 3 .
[0117] Example 8
[0118] By weight, 6.25 parts of polyacrylate-diallyldimethylammonium chloride, 83.75 parts of ethylene glycol butyl ether acetate, 3 parts of ethylene glycol, and 7 parts of water from Preparation Example 1 were added and mixed. The pH of the mixture was then adjusted to 3 using 36 wt% hydrochloric acid to obtain a non-aqueous scale inhibitor with a density of 0.952 g / cm³. 3 .
[0119] Comparative Example 1
[0120] By weight, 6.25 parts of polyacrylate-diallyldimethylammonium chloride, 35 parts of ethylene glycol butyl ether, 41.75 parts of ethylene glycol, and 17 parts of water were mixed, and the pH of the mixture was adjusted to 3 with 36 wt% hydrochloric acid to obtain a scale inhibitor with a non-aqueous phase and a density of 1.032 g / cm³. 3 .
[0121] Test case
[0122] The analysis of synthetic formation brine (i.e., experimental water) and synthetic seawater in the test examples is shown in Table 1.
[0123] Table 1
[0124] 1. Matching test between non-aqueous scale inhibitor and crude oil formation water
[0125] The mixing weight ratios of crude oil and non-aqueous scale inhibitor were 10:90, 25:75, 50:50, 75:25, and 90:10. The non-aqueous scale inhibitors were those used in Examples 1-8 and Comparative Example 1. All mixed samples were mixed in the presence of 20 wt% synthetic formation brine, and then placed at 95°C for 24 hours. The test results showed that after 24 hours at 95°C, the mixing state of all combinations of brine-crude oil-non-aqueous scale inhibitor in Examples 1-8 remained clear and stable, indicating that the non-aqueous scale inhibitor in this invention has good fluid compatibility with crude oil and formation water. The mixing state of all combinations of non-aqueous scale inhibitor and crude oil-formation water in Comparative Example 1 was not uniform.
[0126] 2. Scale inhibitor aqueous phase transfer and distribution test
[0127] The purpose of the scale inhibitor aqueous phase transfer partition test is to determine how much copolymer component of the scale inhibitor moves to the aqueous phase within a given time when it is mixed with crude oil and water in the non-aqueous phase.
[0128] The test temperature was 95℃. Each test sample contained 20wt% synthetic formation brine and the remaining 80wt% was a mixture of non-aqueous scale inhibitor and crude oil, with the mixing ratio varying between 10:90, 25:75, 50:50, 75:25, 90:10 and 100:0.
[0129] All test sample vials were placed in an oven preheated to 95°C, and small water samples were taken at given time intervals to analyze the concentration of the copolymer component.
[0130] Figure 2 shows the relationship between the non-aqueous scale inhibitor's transfer to the aqueous phase and time when the non-aqueous scale inhibitor was mixed with crude oil at different ratios in Example 1. Each group consists of three bars, and from left to right, each group represents the transfer rate of the copolymer component to the aqueous phase within time intervals of 2 hours, 4 hours, and 16 hours. As can be seen from Figure 2, within the time intervals of 2, 4, and 16 hours, all samples showed over 90 wt% of the copolymer component being transferred to the aqueous phase.
[0131] The non-aqueous scale inhibitors in Examples 2-8 were tested using the same method described above. The test results showed that more than 90 wt% of the copolymer component was transferred to the aqueous phase at time intervals of 2, 4, and 16 hours.
[0132] 3. Dynamic loop test
[0133] The dynamic scale inhibitor performance test aimed to evaluate the ability of scale inhibitors to prevent scale growth on metal surfaces. All tests were conducted using a 50:50 (by weight) mixture of synthetic formation water and synthetic seawater. Test conditions were selected to represent the most favorable barium sulfate scaling conditions. The scale inhibitors tested were the non-aqueous phase scale inhibitors from the examples and comparative examples.
[0134] During testing, synthetic formation water and seawater brine were separated into non-scaling cationic and anionic brine fractions so that the mixed brine fractions of the cationic and anionic fractions would represent the mixture of synthetic formation water and seawater.
[0135] Two separate pumps were used to pump the two brine solutions into the heating coil. This ensured that the fluids reached the test temperature before being mixed and entering the loop. After passing through the heating coil, the cationic and anionic brine solutions were mixed at the T-junction entering the scaling loop. Scale formation within the loop was tracked by measuring the change in pressure differential across the loop as a function of time. If the scale inhibitor effectively prevents scale adhesion and growth within the loop, the loop pressure differential will not increase. The lowest concentration of scale inhibitor that prevents scale formation within the loop is often referred to as the minimum effective concentration (MEC) of the scale inhibitor.
[0136] The results are shown in Table 2.
[0137] Table 2
[0138] 4. Core experiments of the non-aqueous scale inhibitor in Example 1
[0139] The purpose of the core experiment was to (i) evaluate the core injectability of the formulated non-aqueous scale inhibitor and (ii) test whether the formulation of the non-aqueous scale inhibitor was compatible with the formation core.
[0140] Core test conditions: temperature 95℃; pH of the synthesized formation brine pH 6.
[0141] The core testing procedure is as follows:
[0142] First, synthetic formation brine was injected at a flow rate of 60 mL / min for 12 hours; mineral oil was injected at a flow rate of 60 mL / min for 2 hours; crude oil was injected until saturated and heated to 95°C, then the injection was stopped and the system was shut off for 16 hours; the permeability of crude oil in the forward and reverse flow directions was measured; the permeability of brine in the forward and reverse flow directions was measured.
[0143] Then, synthetic formation brine was injected into the forward flow direction at a flow rate of 60 mL / min for 12 hours; 10 pore volumes of non-aqueous phase scale inhibitor were injected into the reverse flow direction; the injection was stopped and the system was shut off for 16 hours; the permeability of the treated brine in the forward and reverse flow directions was measured; crude oil was injected and the permeability of the crude oil in the forward and reverse flow directions was measured.
[0144] Experimental results:
[0145] During the injection of the non-aqueous scale inhibitor, the injection pressure remained constant, indicating that there were no injection problems in the core experiment's application of the non-aqueous scale inhibitor. No movement of microparticles was observed during this stage.
[0146] Oil permeability assessment: Oil permeability assessment is typically performed at different stages of core testing. Any decrease in oil permeability indicates some degree of pore channel blockage in the tested core. Damage mechanisms typically involve water blockage, solid precipitation, emulsion formation, and fine particle movement.
[0147] In some cases, due to the immiscibility between oil and injected fluid, the relative permeability effect plays a significant role in the reduction of oil permeability if the residual fluid saturation changes. Scale inhibitors adsorbed onto pore surfaces may alter hydrophilicity and the relative water-oil permeability of the core.
[0148] The crude oil permeability measured in both forward and reverse flow directions at the initial and final stages is shown in Table 3.
[0149] Table 3
[0150] Core test results show that the injection of non-aqueous scale inhibitor in this invention does not damage the core.
[0151] Field application of non-aqueous scale inhibitor in Example 1
[0152] In the injection treatment design, diesel fuel was selected as both the pre-flush and post-flush fluid. The non-aqueous scale inhibitor was pushed to approximately 4 meters into the formation by the post-flush fluid. Furthermore, the shut-in time was limited to 16 hours, and all fluids were filtered before being pumped into the well.
[0153] As shown in Figure 1, the steps of the injection process are as follows:
[0154] (1) Pre-flushing with 0.8M solution: 3 Inject 9M at a rate of / min 3 diesel fuel;
[0155] (2) Main treatment with non-aqueous scale inhibitor: 1M 3 Inject 82M at a rate of / min 3 Non-aqueous scale inhibitors;
[0156] (3) Post-flush propulsion: at 0.8M 3 Injecting 110M at a rate of / min 3 diesel fuel;
[0157] (4) Replacement of void volume in oil pipes: with a volume of 0.8M 3 Inject 75M at a rate of / min 3 diesel fuel;
[0158] (5) Well shutdown: 16 hours.
[0159] During the injection process, the non-aqueous scale inhibitor was successfully injected, and no significant pressure increase occurred. Post-injection production regression analysis showed no backflow issues. The well was rapidly flushed back immediately after the injection treatment. Table 4 shows a comparison of oil production rate, water production rate, and water cut before and after the injection treatment.
[0160] Table 4
[0161] Table 4 shows that the treated wells produced more oil and less water. The oil yield increased from 190 sm³. 3 / day increased to 273Sm 3 / day, water cut decreased from 25 wt% to 16 wt%. The increase in oil production lasted for more than three months. This may be related to wellbore cleaning or the relative permeability effect due to reduced residual water saturation. Regular monitoring of scale inhibitor concentration showed that the minimum effective concentration (MEC) of scale inhibitor in the produced water remained at over one year. Successful injection treatment protected the production well from scale damage, thus achieving the design goals.
[0162] The preferred embodiments of the present invention have been described in detail above; however, the present invention is not limited thereto. Within the scope of the inventive concept, various simple modifications can be made to the technical solutions of the present invention, including combinations of various technical features in any other suitable manner. These simple modifications and combinations should also be considered as the content disclosed in the present invention and are all within the protection scope of the present invention.
Claims
1. A non-aqueous scale inhibitor, characterized in that, The non-aqueous scale inhibitor comprises: acrylic copolymers, alcohol ether solvents, alkyl glycol solvents, and water; The density of the non-aqueous scale inhibitor is not higher than 0.97 g / cm³. 3 The acrylic copolymer has a diallyl ammonium salt structural unit as shown in formula (I) and an acrylic structural unit as shown in formula (II); In equation (I), R 111 R 112 R 10 R 11 R 12 R 13 R 14 R 15 R 16 R 17 R 18 and R 19 Each is independently selected from H or an organic group having 1-20 carbon atoms, X - It is an anion; In equation (II), R 21 R 22 and R 23 Each is independently selected from H, C1-C6 alkyl or phenyl.
2. The non-aqueous scale inhibitor according to claim 1, characterized in that, The density of the non-aqueous scale inhibitor is 0.93-0.95 g / cm³. 3 ; and / or The pH of the non-aqueous scale inhibitor is 2.5-3.
5.
3. The non-aqueous scale inhibitor according to claim 2, characterized in that, The non-aqueous scale inhibitor contains a pH adjuster, the content of which makes the pH of the non-aqueous scale inhibitor 2.5-3.
5.
4. The non-aqueous scale inhibitor according to claim 3, characterized in that, The pH adjuster is selected from at least one of hydrochloric acid, formic acid, and acetic acid.
5. The non-aqueous scale inhibitor according to claim 4, characterized in that, The pH adjuster is hydrochloric acid.
6. The non-aqueous scale inhibitor according to claim 1, characterized in that, The weight ratio of the alcohol ether solvent to the acrylic copolymer is (7-17):1; and / or The weight ratio of the alcohol ether solvent to the alkyl diol solvent is (20-45):1; and / or The weight ratio of the alcohol ether solvent to water is (10-14):
1.
7. The non-aqueous scale inhibitor according to claim 6, characterized in that, The weight ratio of the alcohol ether solvent to the acrylic copolymer is (8-15):1; and / or The weight ratio of the alcohol ether solvent to the alkyl diol solvent is (24-36):
1.
8. The non-aqueous scale inhibitor according to claim 1, characterized in that, The structure of the alcohol ether solvent is shown in formula (A). In formula (A), Y is selected from ethylidene or propyleneide, n is 1, 2 or 3, Z is a C1-C6 alkyl group, OH is a hydroxyl group, and O is an oxygen atom; and / or The alkyl diol solvent is selected from C2-C6 alkyl diols.
9. The non-aqueous scale inhibitor according to claim 8, characterized in that, In formula (A): Y is selected from ethylene; and / or n is 1 or 2; and / or Z is a C4-C6 alkyl group; and / or The alkyl glycol solvent is selected from at least one of ethylene glycol, propylene glycol, and butanediol.
10. The non-aqueous scale inhibitor according to claim 1, characterized in that, The acrylic copolymer has a weight-average molecular weight of 2000 g / mol to 4000 g / mol; and / or In equation (I), R 111 R 112 R 10 R 11 R 12 R 13 R 14 R 15 R 16 R 17 R 18 and R 19 Each is independently selected from H or C1-C20 alkyl groups, X - Halogen ions; and / or In equation (II), R 21 R 22 and R 23 Each is independently selected from H or C1-C6 alkyl groups; and / or The molar ratio of the diallyl ammonium salt structural unit to the acrylic structural unit is 1:(1-30).
11. The non-aqueous scale inhibitor according to claim 1, characterized in that, The acrylic copolymer also has a sulfonic acid-containing structural unit as shown in formula (III). In equation (III), R 31 Selected from monovalent metal ions, R 32 R 33 R 34 Each is independently selected from H or C1-C6 alkyl groups.
12. The non-aqueous scale inhibitor according to claim 11, characterized in that, In formula (III): R 31 Selected from potassium or sodium ions; and / or The molar ratio of the sulfonic acid structural unit to the acrylic structural unit is 1:(1-30).
13. The non-aqueous scale inhibitor according to claim 1, characterized in that, The acrylic copolymer also has the diacid structural unit shown in formula (IV). In equation (IV), R 41 R 42 Each is independently selected from H, C1-C6 alkyl or phenyl groups.
14. The non-aqueous scale inhibitor according to claim 13, characterized in that, In equation (IV), R 41 R 42 Each alkyl group is independently selected from H or C1-C3; and / or The molar ratio of the diacid structural unit to the acrylic structural unit is 1:(1-30).
15. The application of a non-aqueous scale inhibitor in oilfield scale prevention, characterized in that, The non-aqueous scale inhibitor is the non-aqueous scale inhibitor described in any one of claims 1-14.
16. A casing agent for an oilfield scale prevention injection method, characterized in that, The kit comprises: a pre-treatment solution; a non-aqueous scale inhibitor as described in any one of claims 1-14; and a post-treatment solution.
17. The sleeve according to claim 16, characterized in that, The pre-fluid and post-fluid are each independently selected from non-aqueous phase fluids.
18. The sleeve according to claim 17, characterized in that, The non-aqueous fluids include diesel oil and / or mineral oil.
19. A method for preventing scale buildup in oilfields, characterized in that, The method includes: S1. Pre-flushing with pre-fluid through the production well; S2. Inject non-aqueous phase scale inhibitor; S3, rear-mounted liquid propulsion; Wherein, the pre-fluid, the non-aqueous scale inhibitor, and the post-fluid are respectively the pre-fluid, the non-aqueous scale inhibitor, and the post-fluid in the kit described in any one of claims 15-17.
20. The method according to claim 19, characterized in that, In step S3, the amount of post-treatment liquid is used to advance the non-aqueous scale inhibitor into the formation to a depth of 3-5 meters.