Viscosity-reducing foam agent for improving recovery ratio of thickened oil reservoir and preparation method and application thereof

Abstract

The application discloses a viscosity-reducing foam agent for improving the recovery ratio of thickened oil reservoirs, which comprises 1-20 parts of alkyl benzene polyether sulfonate, 5-30 parts of alpha-olefin sulfonate, 1-20 parts of lauryl alcohol polyoxyethylene ether sulfosuccinic acid monolipid salt, 2-20 parts of cocamide propyl betaine, 1-20 parts of fatty alcohol polyether carboxylate and 30-70 parts of water. The application discloses a preparation method of the viscosity-reducing foam agent for improving the recovery ratio of thickened oil reservoirs, which comprises the following steps: (1) putting the formula amount of alkyl benzene polyether sulfonate into a reaction container, adding 20%-60% of the formula amount of water into the reaction container, and continuously stirring to obtain a first mixed solution; (2) sequentially adding the formula amount of alpha-olefin sulfonate, lauryl alcohol polyoxyethylene ether sulfosuccinic acid monolipid salt, fatty alcohol polyether carboxylate and cocamide propyl betaine into the reaction container, uniformly stirring and then obtaining a second mixed solution; and (3) adding the remaining formula amount of water into the reaction container, and continuously stirring to obtain the viscosity-reducing foam agent.

Description

Technical Field

[0001] This invention belongs to the field of heavy oil viscosity reduction and cold recovery technology, and relates to a viscosity-reducing foaming agent for improving the recovery rate of heavy oil reservoirs, its preparation method and application. Background Technology

[0002] Heavy oil reservoirs are rich in resources, but conventional methods of enhancing oil recovery through water injection result in low recovery rates and high energy consumption in thermal recovery of heavy oil, which contradicts the general trend of energy conservation and emission reduction. For example, Zhao Yan et al., in their article "Physical Simulation Experiment of High-Dryness Steam Drive in Deep Heavy Oil Reservoirs" published in the second issue of "Fault-Block Oil and Gas Fields" in 2018, pointed out that: Shengli Oilfield has abundant heavy oil resources, but most heavy oil reservoirs are deeply buried with active edge and bottom water, making it difficult to reduce reservoir pressure to 5 MPa. Conventional steam drive well bottom steam injection with a dryness of around 30% implemented in the field does not significantly improve the recovery rate.

[0003] Chinese patent application CN 103510932A discloses a chemical cold recovery method suitable for medium-deep, low-permeability heavy oil reservoirs. The method comprises the following steps: a. Selecting an oil reservoir with a depth of 1500–2800 m and a permeability ≤ 50 × 10⁻⁶ m. -3 um 2 For medium-deep, low-permeability heavy oil reservoirs with a total oil layer thickness ≥3.0m, a net-total thickness ratio ≥0.3, a porosity ≥0.10, and a permeability variation coefficient ≤0.8, a microemulsion viscosity-reducing system combined with liquid carbon dioxide is injected into the selected oil layer. The microemulsion viscosity-reducing system and liquid carbon dioxide are injected alternately in the form of slugs. After shut-in and well quenching, and well opening and blowout, continuous oil production is carried out by pumping. Another example is Chinese patent application CN 108729893A, which discloses a foam composite cold production method to improve the recovery rate of heavy oil reservoirs. This method mainly includes: alternately injecting a heavy oil viscosity-reducing agent, water, and a polymer composite foam flooding system into a water injection well, followed by water flooding. From the above two patent documents, it can be seen that in order to improve the effect of viscosity-reducing cold production, viscosity-reducing chemical flooding must be combined with methods to improve reservoir sweep efficiency in order to significantly improve the recovery rate of heavy oil reservoirs.

[0004] To reduce the viscosity of heavy oil and improve oil recovery, viscosity-reducing displacement agents are generally used. For example, Chinese patent application CN111440604A discloses a self-demulsifying, salt-resistant cold-production displacement agent for heavy oil, which, by mass percentage, comprises: 40-50 wt% active ingredient, 15-20 wt% additive, 5-8 wt% penetrant, and the balance being deionized water; the active ingredient includes: fatty alcohol polyoxyethylene ether carboxylate, polyoxyethylene castor oil, and fatty acid-amine complex in a mass ratio of (8-10):(1-3):(4-6). Another example is Chinese invention patent CN 114853958B, which discloses a supramolecular nano-displacement agent for cold production of heavy oil and its preparation method. The preparation method is as follows: Allyl (diisopropylamino)dimethylsilane, potassium styrene trifluoroborate, 2-acrylamide-2-methylpropanesulfonic acid, allyl alcohol polyoxyethylene ether, diallylamine, Tween 80, sodium dodecyl sulfate, buffer salt, and water are added sequentially to a reactor to form an emulsion; 80-90% of the emulsion is transferred to a first high-level tank, and Tween 80, sodium dodecyl sulfate, buffer salt, and water are added to the reactor; an initiator is added to a second high-level tank, and a reducing agent is added to a third high-level tank, both added dropwise simultaneously for prepolymerization; an initiator is added to a second high-level tank, and a reducing agent is added to a third high-level tank, and polymerization is carried out simultaneously by adding the first, second, and third high-level tanks dropwise; the product is obtained by cooling. Although viscosity-reducing cold flooding can fully utilize the properties of viscosity-reducing flooding agents to lower crude oil viscosity and improve its fluidity, the injection of these agents makes it easier to displace crude oil along the main flow lines, resulting in greater reservoir heterogeneity. Heavy oil in non-main flow lines and low-permeability zones is less likely to be displaced, and the injected chemicals will flow out along high-permeability channels with less residual oil, reducing the effectiveness of the viscosity-reducing flooding fluid and weakening the effect of viscosity-reducing chemical flooding on improving reservoir recovery. Summary of the Invention

[0005] Objective of the Invention: To address the shortcomings of the prior art, this invention provides a viscosity-reducing foaming agent for improving the recovery rate of heavy oil reservoirs, along with its preparation method and application. This viscosity-reducing foaming agent exhibits excellent viscosity-reducing properties for heavy oil and also possesses good foaming ability with gases such as nitrogen, air, and carbon dioxide. Through the dual effects of viscosity reduction and foaming in heavy oil reservoirs, it improves the fluidity of heavy oil and the sweep area of ​​the displacing fluid, thereby further enhancing the recovery rate of heavy oil reservoirs.

[0006] Technical solution: A viscosity-reducing foaming agent for improving the recovery rate of heavy oil reservoirs, composed of the following components by weight:

[0007] 1-20 parts alkylbenzene polyether sulfonate, 5-30 parts α-olefin sulfonate, 1-20 parts lauryl alcohol polyoxyethylene ether sulfosuccinate monoester, 2-20 parts cocamidopropyl betaine, 1-20 parts fatty alcohol polyether carboxylate and 30-70 parts water.

[0008] Furthermore, the alkylbenzene polyether sulfonate is one of sodium alkylbenzene polyether sulfonate, potassium alkylbenzene polyether sulfonate, and ammonium alkylbenzene polyether sulfonate.

[0009] Furthermore, the alkylbenzene polyether sulfonate is sodium alkylbenzene polyether sulfonate.

[0010] Furthermore, the alkylbenzene polyether sulfonate is an alkylbenzene polyether sulfonate with a carbon chain length of 12 to 18.

[0011] Furthermore, the α-olefin sulfonate is an α-olefin sulfonate with an olefinic carbon chain length of 12 to 18.

[0012] Furthermore, lauryl alcohol polyoxyethylene ether sulfosuccinate monoester salt is one of the following: disodium lauryl alcohol polyoxyethylene ether sulfosuccinate monoester salt, dipotassium lauryl alcohol polyoxyethylene ether sulfosuccinate monoester salt, and diammonium lauryl alcohol polyoxyethylene ether sulfosuccinate monoester salt.

[0013] Furthermore, lauryl alcohol polyoxyethylene ether sulfosuccinate monoester salt is lauryl alcohol polyoxyethylene ether sulfosuccinate monoester disodium salt.

[0014] Furthermore, the fatty alcohol polyether carboxylate is one of sodium fatty alcohol polyether carboxylate, potassium fatty alcohol polyether carboxylate, and ammonium fatty alcohol polyether carboxylate.

[0015] Furthermore, the fatty alcohol groups in the fatty alcohol polyether carboxylate contain alkyl carbon chains of length 12 to 18.

[0016] The preparation method of the above-mentioned viscosity-reducing foaming agent for improving the recovery rate of heavy oil reservoirs includes the following steps:

[0017] (1) Take the alkylbenzene polyether sulfonate of the formula into a reaction vessel, and add 20% to 60% of the formula amount of water into the reaction vessel while stirring. After stirring for a period of time, the first mixture is obtained.

[0018] (2) Add the following ingredients in sequence to the reaction vessel: α-olefin sulfonate, lauryl alcohol polyoxyethylene ether sulfosuccinate monoester, fatty alcohol polyether carboxylate, and cocamidopropyl betaine. Stir until homogeneous to obtain a second mixture.

[0019] (3) Add the remaining amount of water (i.e., 40% to 80% of the amount of water in the formula) to the reaction vessel and continue stirring for a period of time to obtain a viscosity-reducing foaming agent that improves the recovery rate of heavy oil reservoirs.

[0020] Furthermore, in step (1), the stirring speed is 60-100 rpm and the stirring time is at least 20 minutes, preferably 20-30 minutes.

[0021] Furthermore, in step (2), the stirring speed is 50-80 rpm and the stirring time is at least 20 minutes, preferably 20-30 minutes.

[0022] Furthermore, in step (3), the stirring speed is 50-80 rpm and the stirring time is at least 30 minutes, preferably 30-60 minutes.

[0023] The above-mentioned viscosity-reducing foaming agents for improving the recovery rate of heavy oil reservoirs are applied in oil extraction.

[0024] The principle of this invention is based on the principle of balanced distribution of surfactants at the oil-water interface and gas-liquid interface. By selecting a variety of anionic and amphoteric surfactants with properties similar to crude oil, and through synergistic addition, a surfactant formulation with a wide range of applications, high viscosity reduction efficiency, good foaming ability and stability is developed. Through reasonable compounding, an oil displacement agent product with good viscosity reduction and foaming properties is formed, which can play a good role in the field of heavy oil viscosity reduction and cold extraction.

[0025] Effects of the Invention: The viscosity-reducing foaming agent for improving the recovery rate of heavy oil reservoirs disclosed in this invention, its preparation method, and its application have the following beneficial effects:

[0026] 1. Compared with other formulas for improving oilfield recovery, it has the characteristics of low cost and dual effect (foaming + viscosity reduction) in one agent. It can not only significantly reduce the viscosity of heavy oil, but also has good foaming ability, foam stability and good compatibility with formation water with high salinity. It can play the role of viscosity reducer foaming and profile control in the formation according to the different oil and water in contact.

[0027] 2. The chemical components used are all active ingredients that are currently available on the market with mature technology, large production volume, relatively low price, and environmental friendliness, and have good value for on-site application and promotion. Attached Figure Description

[0028] Figure 1 This is a flowchart of the preparation method of a viscosity-reducing foaming agent for improving the recovery rate of heavy oil reservoirs disclosed in this invention. Detailed Implementation

[0029] The following is a detailed description of specific embodiments of the present invention. It should be noted that the following detailed description is exemplary and intended to provide further explanation of the invention. Unless otherwise specified, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this invention pertains.

[0030] It should be noted that the terminology used herein is for the purpose of describing particular embodiments only and is not intended to limit the exemplary embodiments of the present invention. As used herein, the singular form is intended to include the plural form as well, unless the context clearly indicates otherwise. Furthermore, it should be understood that when the terms "comprising" and / or "including" are used in this specification, they indicate the presence of features, steps, operations, and / or combinations thereof.

[0031] To enable those skilled in the art to better understand the technical solution of the present invention, the technical solution of the present invention will be described in detail below with reference to specific embodiments.

[0032] Unless otherwise specified, the instruments, reagents, and materials used in the following embodiments are all conventional instruments, reagents, and materials already available in the prior art and can be obtained through legitimate commercial channels. Unless otherwise specified, the experimental methods and detection methods used in the following embodiments are all conventional experimental methods and detection methods already available in the prior art.

[0033] In this application: α-olefin sulfonate, abbreviated as AOS.

[0034] Disodium lauryl ether sulfosuccinate monoester, abbreviated as MES-30.

[0035] Cocamidopropyl betaine, abbreviated as CAB.

[0036] Fatty alcohol polyether carboxylate, abbreviated as AEC.

[0037] This invention discloses a viscosity-reducing foaming agent for improving the recovery rate of heavy oil reservoirs, its preparation method, and its application. The viscosity-reducing foaming agent for improving the recovery rate of heavy oil reservoirs can significantly reduce the viscosity of heavy oil. Simultaneously, it can mix with injected gas to form foam, increasing the sweep area of ​​the displacement medium. This allows the chemical agent to interact with more heavy oil, further reducing its viscosity and making it easier to displace. The viscosity-reducing foaming agent possesses the characteristics of both reducing heavy oil viscosity and increasing the sweep area of ​​the foam, thus significantly improving the recovery rate of heavy oil reservoirs.

[0038] To enable those skilled in the art to more clearly understand the technical solution of the present invention, the technical solution of the present invention will be described in detail below with reference to specific embodiments. The following examples are used to help understand the present invention and are not intended to, nor should they be construed as, limiting the invention in the listed claims in any way.

[0039] Example 1

[0040] A viscosity-reducing foaming agent for improving oil recovery in heavy oil reservoirs, composed of the following components by weight:

[0041] 10 parts alkylbenzene polyether sulfonate, 15 parts α-olefin sulfonate, 10 parts lauryl alcohol polyoxyethylene ether sulfosuccinate monoester, 10 parts cocamidopropyl betaine, 10 parts fatty alcohol polyether carboxylate and 50 parts water.

[0042] Furthermore, the alkylbenzene polyether sulfonate is sodium alkylbenzene polyether sulfonate.

[0043] Furthermore, the alkylbenzene polyether sulfonate is hexadecylbenzene polyether sulfonate.

[0044] Furthermore, the α-olefin sulfonate is an α-olefin sulfonate with a carbon chain length of 14 for the olefin group.

[0045] Furthermore, lauryl alcohol polyoxyethylene ether sulfosuccinate monoester salt is lauryl alcohol polyoxyethylene ether sulfosuccinate monoester disodium salt.

[0046] Furthermore, the fatty alcohol polyether carboxylate is sodium fatty alcohol polyether carboxylate.

[0047] Furthermore, the fatty alcohol group in the fatty alcohol polyether carboxylate contains an alkyl carbon chain with a length of 14.

[0048] The preparation method of the above-mentioned viscosity-reducing foaming agent for improving the recovery rate of heavy oil reservoirs includes the following steps:

[0049] (1) Take the alkylbenzene polyether sulfonate of the formula into a reaction vessel, add 40% of the formula amount of water into the reaction vessel while stirring, and continue stirring for a period of time to obtain the first mixture;

[0050] (2) Add the following ingredients in sequence to the reaction vessel: α-olefin sulfonate, lauryl alcohol polyoxyethylene ether sulfosuccinate monoester, fatty alcohol polyether carboxylate, and cocamidopropyl betaine. Stir until homogeneous to obtain a second mixture.

[0051] (3) Add 60% of the formula amount of water to the reaction vessel and continue stirring for a period of time to obtain the viscosity-reducing foaming agent that improves the recovery rate of heavy oil reservoirs, referred to as No. 1 viscosity-reducing foaming agent.

[0052] Furthermore, in step (1), the stirring speed is 80 rpm and the stirring time is up to 25 minutes.

[0053] Furthermore, in step (2), the stirring speed is 60 rpm and the stirring time is 25 minutes.

[0054] Furthermore, in step (3), the stirring speed is 60 rpm and the stirring time is 45 minutes.

[0055] The above-mentioned viscosity-reducing foaming agents for improving the recovery rate of heavy oil reservoirs are applied in oil extraction.

[0056] Example 2

[0057] A viscosity-reducing foaming agent for improving oil recovery in heavy oil reservoirs, composed of the following components by weight:

[0058] 1 part alkylbenzene polyether sulfonate, 5 parts α-olefin sulfonate, 1 part lauryl alcohol polyoxyethylene ether sulfosuccinate monoester, 2 parts cocamidopropyl betaine, 1 part fatty alcohol polyether carboxylate and 30 parts water.

[0059] Furthermore, the alkylbenzene polyether sulfonate is potassium alkylbenzene polyether sulfonate.

[0060] Furthermore, the alkylbenzene polyether sulfonate is dodecylbenzene polyether sulfonate.

[0061] Furthermore, the α-olefin sulfonate is an α-olefin sulfonate with a carbon chain length of 12 for the olefin group.

[0062] Furthermore, lauryl alcohol polyoxyethylene ether sulfosuccinate monoester salt is lauryl alcohol polyoxyethylene ether sulfosuccinate monoester dipotassium salt.

[0063] Furthermore, the fatty alcohol polyether carboxylate is a fatty alcohol polyether carboxylate potassium.

[0064] Furthermore, the fatty alcohol group in the fatty alcohol polyether carboxylate contains an alkyl carbon chain with a length of 12.

[0065] The preparation method of the above-mentioned viscosity-reducing foaming agent for improving the recovery rate of heavy oil reservoirs includes the following steps:

[0066] (1) Take the alkylbenzene polyether sulfonate of the formula into a reaction vessel, add 20% of the formula amount of water into the reaction vessel while stirring, and continue stirring for a period of time to obtain the first mixture;

[0067] (2) Add the following ingredients in sequence to the reaction vessel: α-olefin sulfonate, lauryl alcohol polyoxyethylene ether sulfosuccinate monoester, fatty alcohol polyether carboxylate, and cocamidopropyl betaine. Stir until homogeneous to obtain a second mixture.

[0068] (3) Add 80% of the formula amount of water to the reaction vessel and continue stirring for a period of time to obtain the viscosity-reducing foaming agent that improves the recovery rate of heavy oil reservoirs, referred to as No. 2 viscosity-reducing foaming agent.

[0069] Furthermore, in step (1), the stirring speed is 60 rpm and the stirring time is 30 minutes.

[0070] Furthermore, in step (2), the stirring speed is 50 rpm and the stirring time is 30 minutes.

[0071] Furthermore, in step (3), the stirring speed is 50 rpm and the stirring time is 60 minutes.

[0072] The above-mentioned viscosity-reducing foaming agents for improving the recovery rate of heavy oil reservoirs are applied in oil extraction.

[0073] Example 3

[0074] A viscosity-reducing foaming agent for improving oil recovery in heavy oil reservoirs, composed of the following components by weight:

[0075] 20 parts alkylbenzene polyether sulfonate, 30 parts α-olefin sulfonate, 20 parts lauryl alcohol polyoxyethylene ether sulfosuccinate monoester, 20 parts cocamidopropyl betaine, 20 parts fatty alcohol polyether carboxylate and 70 parts water.

[0076] Furthermore, the alkylbenzene polyether sulfonate is ammonium alkylbenzene polyether sulfonate.

[0077] Furthermore, the alkylbenzene polyether sulfonate is octadecylbenzene polyether sulfonate.

[0078] Furthermore, the α-olefin sulfonate is an α-olefin sulfonate with a carbon chain length of 18 for the olefin group.

[0079] Furthermore, lauryl alcohol polyoxyethylene ether sulfosuccinate monoester salt is lauryl alcohol polyoxyethylene ether sulfosuccinate monoester diammonium salt.

[0080] Furthermore, the fatty alcohol polyether carboxylate is fatty alcohol polyether ammonium carboxylate.

[0081] Furthermore, the fatty alcohol group in the fatty alcohol polyether carboxylate contains an alkyl carbon chain with a length of 18.

[0082] The preparation method of the above-mentioned viscosity-reducing foaming agent for improving the recovery rate of heavy oil reservoirs includes the following steps:

[0083] (1) Take the alkylbenzene polyether sulfonate of the formula into a reaction vessel, add 60% of the formula amount of water into the reaction vessel while stirring, and continue stirring for a period of time to obtain the first mixture;

[0084] (2) Add the following ingredients in sequence to the reaction vessel: α-olefin sulfonate, lauryl alcohol polyoxyethylene ether sulfosuccinate monoester, fatty alcohol polyether carboxylate, and cocamidopropyl betaine. Stir until homogeneous to obtain a second mixture.

[0085] (3) Add 40% of the formula amount of water to the reaction vessel and continue stirring for a period of time to obtain the viscosity-reducing foaming agent that improves the recovery rate of heavy oil reservoirs, referred to as No. 3 viscosity-reducing foaming agent.

[0086] Furthermore, in step (1), the stirring speed is 100 rpm and the stirring time is 20 minutes.

[0087] Furthermore, in step (2), the stirring speed is 80 rpm and the stirring time is 20 minutes.

[0088] Furthermore, in step (3), the stirring speed is 80 rpm and the stirring time is 30 minutes.

[0089] The above-mentioned viscosity-reducing foaming agents for improving the recovery rate of heavy oil reservoirs are applied in oil extraction.

[0090] Verification experiment:

[0091] 1. Performance in reducing the viscosity of heavy oil:

[0092] #1 Viscosity-reducing foaming agent:

[0093] The crude oil in Block A of Shengli Oilfield has a surface viscosity of 86 mPa·s at 50°C. After using the No. 1 viscosity-reducing foaming agent prepared in Example 1, the viscosity was reduced to 5.6 mPa·s, with a viscosity reduction rate as high as 93.4%.

[0094] #2 Viscosity-reducing foaming agent:

[0095] The crude oil in Block B of Shengli Oilfield has a surface viscosity of 686 mPas at 50°C. After viscosity reduction, the viscosity is 15.2 mPas, with a viscosity reduction rate of 97.8%.

[0096] #3 Viscosity-reducing foaming agent:

[0097] The crude oil in Block C of Shengli Oilfield has a surface viscosity of 587 mPas at 50℃, and the viscosity after viscosity reduction is 21.6 mPas, with a viscosity reduction rate of 96.3%.

[0098] 2. Possesses excellent foaming ability with gases such as nitrogen, air, and carbon dioxide – Foam performance test:

[0099] Testing instrument: foam scanner;

[0100] Test temperature 50℃, concentration 0.5%,

[0101] #1 Viscosity-reducing foaming agent:

[0102] When nitrogen is used as the foaming gas, the foaming volume is 230 ml and the half-life is 185 min. When air is used as the foaming gas, the foaming volume is 225 ml and the half-life is 181 min. When CO2 is used as the foaming gas, the foaming volume is 180 ml and the half-life is 35 min.

[0103] #2 Viscosity-reducing foaming agent:

[0104] When nitrogen is used as the foaming gas, the foaming volume is 185 ml and the half-life is 160 min. When air is used as the foaming gas, the foaming volume is 175 ml and the half-life is 150 min. When CO2 is used as the foaming gas, the foaming volume is 170 ml and the half-life is 24 min.

[0105] #3 Viscosity-reducing foaming agent:

[0106] When nitrogen is used as the foaming gas, the foaming volume is 220 ml and the half-life is 175 min. When air is used as the foaming gas, the foaming volume is 200 ml and the half-life is 165 min. When CO2 is used as the foaming gas, the foaming volume is 160 ml and the half-life is 30 min.

[0107] 3. Improve the fluidity of heavy oil and the sweep area of ​​the displacement fluid – verified through a two-tube oil displacement test:

[0108] #1 Viscosity-reducing foaming agent:

[0109] Model dimensions: φ25mm × 600mm. High-depth pipe permeability: 1567 × 10⁻⁶. -3 μm 2 Low permeability tube permeability 452×10 -3 μm 2 When the water drive reaches a total water cut of 98%, the recovery rate is 61.6% for high-permeability pipes and 22.5% for low-permeability pipes, resulting in a total water drive recovery of 42.5%. The stable pressure differential in the later stages of water drive is 0.1 MPa.

[0110] After waterflooding, viscosity reducer flooding (i.e., adding No. 1 viscosity-reducing foaming agent) was performed. The concentration of No. 1 viscosity-reducing foaming agent was 0.3%, and 0.3 PV was injected into the slug. After viscosity reducer flooding, the recovery rate of high-permeability tubes was 68.6%, an increase of 7 percentage points; the recovery rate of low-permeability tubes was 25.7%, an increase of 6.2 percentage points. After viscosity reducer flooding, waterflooding was switched to waterflooding with a pressure differential of 0.07 MPa. The swept area was improved, and the recovery rate was significantly increased.

[0111] #2 Viscosity-reducing foaming agent:

[0112] Model dimensions: φ25mm × 600mm. High-depth pipe permeability: 1862 × 10⁻⁶. -3 μm 2 Low permeability tube permeability 396×10 -3 μm 2 When the water drive reached a total water cut of 98%, the recovery rate of high-permeability tubes was 58.3%, the recovery rate of low-permeability tubes was 17.6%, the overall water drive recovery rate was 36.2%, and the stable pressure differential in the later stage of water drive was 0.15 MPa.

[0113] Following waterflooding, viscosity reducer flooding (i.e., adding No. 2 viscosity-reducing foaming agent) was performed at a concentration of 0.3%, with 0.3 PV injected into the slug. After viscosity reducer flooding, the recovery rate in high-permeability tubing reached 64.5%, an increase of 6.2 percentage points; the recovery rate in low-permeability tubing reached 23.4%, an increase of 5.8 percentage points. After viscosity reducer flooding, waterflooding was resumed with a pressure differential of 0.11 MPa. The swept area was improved, and the recovery rate was significantly increased.

[0114] #3 Viscosity-reducing foaming agent:

[0115] Model dimensions: φ25mm × 600mm. High-depth pipe permeability: 1579 × 10⁻⁶. -3 μm 2 Low permeability tube permeability 386×10 -3 μm 2 When the water drive reached a total water cut of 98%, the recovery rate was 61.2% with high-permeability pipes and 20.5% with low-permeability pipes, resulting in a total water drive recovery of 39.4%. The stable pressure differential in the later stages of water drive was 0.12 MPa.

[0116] Following waterflooding, viscosity-reducing foam flooding (i.e., adding No. 3 viscosity-reducing foaming agent) was performed. The concentration of No. 3 viscosity-reducing foaming agent was 0.3%, the gas-liquid ratio was 1:1, the injected gas was nitrogen, and the injected slug volume was 0.3 PV. After viscosity-reducing foam flooding, the recovery rate of high-permeability tubing was 85.2%, an increase of 24 percentage points; the recovery rate of low-permeability tubing was 53.9%, an increase of 31.4 percentage points, and the overall recovery rate increased by 27.5%. The injection-production pressure differential of foam flooding increased to 1.2 MPa, and after switching to waterflooding for 1 PV, the pressure differential was 0.32 MPa. The swept area was improved, and the recovery rate was significantly increased.

[0117] The embodiments of the present invention have been described in detail above. However, the present invention is not limited to the above embodiments, and various changes can be made within the scope of knowledge possessed by those skilled in the art without departing from the spirit of the present invention.

Claims

1. A viscosity-reducing foam agent for improving the recovery efficiency of a heavy oil reservoir, characterized by, consists of, by mass parts: 1-20 parts of alkyl benzene polyether sulfonate, 5-30 parts of alpha olefin sulfonate, 1-20 parts of lauryl alcohol polyoxyethylene ether sulfosuccinic acid monolipid salt, 2-20 parts of cocamidopropyl betaine, 1-20 parts of fatty alcohol polyether carboxylate and 30-70 parts of water, wherein: the alkyl benzene polyether sulfonate is alkyl benzene polyether sulfonate with carbon chain length of 12 to 18; the alpha olefin sulfonate is alpha olefin sulfonate with carbon chain length of 12 to 18; the fatty alcohol group in the fatty alcohol polyether carboxylate contains alkyl carbon chain with length of 12 to 18.

2. The viscosity-reducing foam agent for enhanced recovery of a heavy oil reservoir according to claim 1, wherein the alkyl benzene polyether sulfonate is one of sodium alkyl benzene polyether sulfonate, potassium alkyl benzene polyether sulfonate and ammonium alkyl benzene polyether sulfonate.

3. The viscosity-reducing foam agent for enhanced recovery of a heavy oil reservoir according to claim 2, wherein the alkyl benzene polyether sulfonate is sodium alkyl benzene polyether sulfonate.

4. The viscosity-reducing foam agent for enhanced recovery of a heavy oil reservoir according to claim 1, wherein the lauryl alcohol polyoxyethylene ether sulfosuccinic acid monolipid salt is one of lauryl alcohol polyoxyethylene ether sulfosuccinic acid monolipid disodium salt, lauryl alcohol polyoxyethylene ether sulfosuccinic acid monolipid dipotassium salt and lauryl alcohol polyoxyethylene ether sulfosuccinic acid monolipid diammonium salt.

5. The viscosity-reducing foam agent for enhanced recovery of a heavy oil reservoir according to claim 4, wherein the lauryl alcohol polyoxyethylene ether sulfosuccinic acid monolipid salt is lauryl alcohol polyoxyethylene ether sulfosuccinic acid monolipid disodium salt.

6. The viscosity-reducing foam agent for enhanced recovery of a heavy oil reservoir according to Claim 1, wherein the fatty alcohol polyether carboxylate is one of sodium fatty alcohol polyether carboxylate, potassium fatty alcohol polyether carboxylate and ammonium fatty alcohol polyether carboxylate.

7. The method for preparing the viscosity-reducing foam agent for enhancing the recovery of heavy oil reservoirs according to any one of claims 1 to 6, characterized in that, The steps are as follows: (1), take the formula amount of alkyl benzene polyether sulfonate in the reaction container, while stirring, add 20% to 60% of the formula amount of water to the reaction container, continue to stir for a period of time to obtain a first mixture; (2), add the formula amount of alpha olefin sulfonate, the formula amount of lauryl alcohol polyoxyethylene ether sulfosuccinic acid monolipid salt, the formula amount of fatty alcohol polyether carboxylate and the formula amount of cocamidopropyl betaine to the reaction container in turn, stir uniformly to obtain a second mixture; (3), add the remaining formula amount of water to the reaction container, continue to stir for a period of time to obtain a viscosity reducing foam for improving the recovery of thickened oil reservoir.

8. The method according to claim 7, wherein the viscosity-reducing foam for enhanced recovery of heavy oil reservoirs is prepared by adding 0.1 to 5 parts by weight of the surfactant to 100 parts by weight of the base fluid. The stirring speed in step (1) is 60-100 revolutions per minute, and the stirring time is at least 20 minutes.

9. The method according to claim 8, wherein the viscosity-reducing foam for enhanced recovery of heavy oil reservoirs is prepared by adding 0.1 to 5 parts by weight of the surfactant to 100 parts by weight of the base fluid. The stirring time in step (1) is 20-30 minutes.

10. The method for preparing the viscosity-reducing foaming agent for improving the recovery rate of heavy oil reservoirs as described in claim 7, characterized in that, The stirring speed in step (2) is 50-80 revolutions per minute, and the stirring time is at least 20 minutes.

11. The method for preparing the viscosity-reducing foaming agent for improving the recovery rate of heavy oil reservoirs as described in claim 10, characterized in that, The stirring time in step (2) is 20-30 minutes.

12. The method for preparing the viscosity-reducing foaming agent for improving the recovery rate of heavy oil reservoirs as described in claim 7, characterized in that, The stirring speed in step (3) is 50-80 revolutions per minute, and the stirring time is at least 30 minutes.

13. The method for preparing the viscosity-reducing foaming agent for improving the recovery rate of heavy oil reservoirs as described in claim 12, characterized in that, The stirring time in step (3) is 30-60 minutes.

14. The viscosity reducing foam for improving the recovery of thickened oil reservoir according to any one of claims 1-6 is applied in oil exploitation.

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