Viscosity reduction method for super heavy oil reservoir

Abstract

The invention belongs to the technical field of heavy oil recovery, and particularly relates to a super heavy oil reservoir viscosity reduction method which comprises the specific steps that a plugging agent is injected into an oil well, a nitrogen foam slug is injected into the oil well, a viscosity reduction slug is injected into the oil well, steam is injected into the oil well, well closing and recovery are conducted, and the plugging agent comprises bacterial cellulose, agarose and a cross-linking agent; gel-state substances and foam are used for effective plugging, supercritical fluid is used for further reinforcing plugging, the steam swept volume is enlarged, the oil layer viscosity is effectively reduced, the problems of steam channeling, small steam swept volume and edge and bottom water invasion in steam viscosity reduction are solved, and the viscosity reduction capacity and the recovery rate are effectively improved.

Description

Technical Field

[0001] The invention belongs to the technical field of heavy oil extraction, and in particular relates to a method for reducing the viscosity of an ultra-heavy oil reservoir. Background Art

[0002] my country's heavy oil resources are widely distributed and abundant, accounting for a significant portion of its total oil and gas resources. Heavy oil contains high levels of colloids, asphaltenes, and paraffins, resulting in high viscosity and poor fluidity, making extraction and transportation difficult. In ultra-heavy oil reservoirs, due to the high viscosity of the underground crude oil, steam injection for oil recovery and viscosity reduction presents significant resistance to steam entering the reservoir. This results in a small effective radius for steam injection, a sharp decline in the effectiveness of multiple injection cycles, and a steam injection recovery rate of only around 10%. The high viscosity and resistance of the crude oil in ultra-heavy oil reservoirs make it difficult to establish a driving pressure differential between injection and production wells. Due to the internal heterogeneity of the reservoir, the injected steam front tends to advance along bands of high permeability and low resistance, resulting in severe steam channeling, a small steam sweep volume, and the potential for bottom-to-edge water intrusion. This results in ineffective viscosity reduction, low recovery rates, a low oil-to-gas ratio, and poor economic returns.

[0003] Patent 2019112215581 discloses a steam stimulation oil production method for heterogeneous heavy oil reservoirs. Although this method has a certain effect on reducing the viscosity of heavy oil, due to its general plugging effect, it cannot completely solve the problems of steam channeling and edge and bottom water intrusion during the viscosity reduction process. The effective mobilization radius of steam stimulation is small, which seriously affects the viscosity reduction and production of crude oil. Summary of the Invention

[0004] In response to the current technical problems, the present invention provides a method for reducing the viscosity of ultra-heavy oil reservoirs, which uses gelled substances and foam for effective plugging, uses supercritical fluid to further reinforce the plugging, and expands the steam sweep volume, effectively reducing the viscosity of the oil layer, solving the problems of steam channeling, small steam sweep volume, and edge and bottom water intrusion during the steam viscosity reduction process, and effectively improving the recovery rate.

[0005] The technical solutions of the present invention are as follows:

[0006] A method for reducing viscosity of an ultra-heavy oil reservoir comprises the following steps:

[0007] (1) Injecting plugging agent into the oil well;

[0008] (2) injecting nitrogen foam slugs into the oil well;

[0009] (3) injecting the viscosity reduction slug into the oil well;

[0010] (4) Inject steam into the oil well to seal the well and recover the oil.

[0011] Preferably, in step (1), the blocking agent comprises bacterial cellulose, agarose and a cross-linking agent.

[0012] Further preferably, the mass ratio of bacterial cellulose, agarose and cross-linking agent is: 0.5-5:1-8:0.5-2.

[0013] Further preferably, the blocking agent also includes alginate and its derivatives; the mass ratio of alginate and its derivatives to the cross-linking agent is 0.5-1:1; and alginate and its derivatives include one or more of sodium alginate, potassium alginate, and propylene glycol alginate.

[0014] Preferably, in step (2), nitrogen and foaming liquid are injected into the oil layer to form a nitrogen foam slug; the volume ratio of nitrogen to foaming liquid is 0.3-0.5:0.3-0.5.

[0015] Further preferably, the foaming liquid comprises 0.2-0.5% foaming agent, 0.01-0.2% foam stabilizer, 0.1-2% repair agent, and the balance is water.

[0016] More preferably, the foaming agent is sodium lauryl sulfate, the foam stabilizer is polyacrylamide and diutan, and the repair agent is a combination of hydrogen peroxide and manganese dioxide or a combination of sodium carbonate and sodium bisulfate; when the repair agent is added to the system, when the temperature rises, the repair agent is triggered to produce a large amount of gas, continuously foaming, effectively expanding the steam wave volume, strengthening the plugging, and effectively improving the viscosity reduction ability, which is conducive to increasing the oil recovery rate.

[0017] Preferably, in step (3), supercritical fluid and composite surfactant are injected into the oil layer to form a viscosity-reducing slug.

[0018] Preferably, the mass ratio of the supercritical fluid to the complex surfactant is 15-20:1-3.

[0019] Further preferably, the composite surfactant comprises a composition of betaine and polyoxyethylene diamine or (1S, 2S)-2-aminocyclohexane-1-carboxylic acid hydrochloride; and the supercritical fluid is supercritical CO2 with a volume purity greater than 75%.

[0020] The plugging agent of the present invention is mixed with water during the preparation process to form a gel-like substance, which effectively blocks oil. The bacterial cellulose has a highly porous three-dimensional network structure, high biocompatibility, is non-toxic, biodegradable, and has high stability. It has nanofiber micropores and mesoporous structures, high porosity, high water absorbency, and adsorption. Agarose has the advantages of a large number of hydroxyl groups, a network entanglement structure, non-toxicity, and easy degradation. The bacterial cellulose can form a semi-interpenetrating network with the agarose. At the same time, the bacterial cellulose is rich in a large number of hydroxyl polar groups, which can form intermolecular hydrogen bonds with agarose molecules and can also form intramolecular hydrogen bonds on its own. The addition of alginate and its derivatives can increase the strength of the gel-like substance and also thicken it. The gel-like substance with a stable three-dimensional network structure prepared by the plugging agent is further stabilized by the subsequent injection of steam, effectively achieving plugging, and effectively solving the problems of steam channeling and edge and bottom water intrusion during steam viscosity reduction, effectively reducing viscosity, and improving the recovery rate (oil recovery rate).

[0021] The present invention utilizes nitrogen and a foaming liquid to prepare nitrogen foam, which can, on the one hand, block small pores, and, on the other hand, because the prepared gel-state substance has a three-dimensional network structure and a high-porosity structure, it can adsorb foam and further assist in blocking large pores. The nitrogen foam improves the viscosity reduction capability and the longitudinal sweep volume of steam. Effective blocking is achieved by the gel-state substance and the nitrogen foam, which is conducive to solving the problems of steam channeling and edge and bottom water intrusion, achieving the expansion of the steam sweep volume, and effectively improving the viscosity reduction capability and the recovery rate.

[0022] The present invention utilizes supercritical fluid and composite surfactants, and utilizes supercritical carbon dioxide and composite surfactants to effectively expand the swept volume of gas in the reservoir, reduce the viscosity of crude oil, and help improve the recovery rate; CO2 is in a supercritical state, at which time the density is close to that of liquid and the viscosity is close to that of gas, and has strong seepage and substance dissolving capabilities. The crude oil after dissolving CO2 in heavy oil exhibits foamy oil characteristics, reduces the density and viscosity of crude oil, improves the flow performance of crude oil, is conducive to penetrating into the oil layer, and expands the radius of the viscosity reduction slug.

[0023] The present invention injects plugging agents, nitrogen foam slugs and viscosity reducing slugs before steam injection, which work together to solve the problems of steam channeling, edge and bottom water intrusion, and small steam wave volume in the process of steam viscosity reduction of super-heavy oil, thereby improving the viscosity reduction capability of heavy oil and increasing the recovery rate. DETAILED DESCRIPTION

[0024] The present invention will be further described below with reference to specific embodiments, but is not limited thereto.

[0025] The experimental methods described in the examples are conventional methods unless otherwise specified, and the reagents and materials used are commercially available unless otherwise specified.

[0026] The fiber length of the bacterial cellulose described below is not less than 20 μm and the diameter is 50 nm to 100 nm.

[0027] The present invention provides a method for reducing viscosity of an ultra-heavy oil reservoir, comprising the following steps:

[0028] (1) Injecting plugging agent into the oil well;

[0029] (2) injecting nitrogen foam slugs into the oil well;

[0030] (3) injecting the viscosity reduction slug into the oil well;

[0031] (4) Inject steam into the oil well to seal the well and recover the oil.

[0032] In step (1), the blocking agent includes bacterial cellulose, agarose and a cross-linking agent, and the mass ratio of bacterial cellulose, agarose and cross-linking agent is: 0.5-5:1-8:0.5-2. The blocking agent also includes alginate and its derivatives, and alginate and its derivatives include sodium alginate, potassium alginate or propylene glycol alginate; the mass ratio of alginate and its derivatives to the cross-linking agent is 0.5-1:1; the specific mass ratios of bacterial cellulose, agarose, cross-linking agent, alginate and its derivatives are: 1:1:1:1, 0.5:3:2:2, 2:1:0.5:1, 5:8:1:2, 0.5:8:2:2, 3:3:0.5:0.5, 2:1:2:0.5, etc.

[0033] The gel-like substance formed in the present invention needs to be mixed with water after the plugging agent is injected into the well, and the well needs to be sealed for 24-36 hours after the plugging agent is injected to perform plugging.

[0034] In the specific implementation, the plugging agent and water are injected into the oil well at a low displacement, and the injection pressure is not higher than 70% of the formation fracture pressure. Under normal circumstances, the injection displacement is less than 15m 3 / h, and the well is sealed for 24 to 36 hours. During the sealing process, a gel-like substance is formed.

[0035] The amount of gel material system can be calculated according to the following formula:

[0036] Dosage of gel material system

[0037] Where Q1: the amount of gel substance (m 3 ), r1: treatment radius (m), h: oil layer thickness (m), Porosity (%), depending on the actual reservoir conditions, r1 is usually set to 3-10m.

[0038] In step (2), nitrogen and a foaming liquid are injected into the oil layer to form a nitrogen foam plug; the volume ratio of nitrogen to the foaming liquid is 0.3-0.5:0.3-0.5; the foaming liquid comprises 0.2-0.5% of a foaming agent, 0.01-0.2% of a foam stabilizer, 0.1-2% of a repair agent, and the balance is water; the foaming agent is sodium lauryl sulfate, the foam stabilizer is polyacrylamide (polyacrylamide hydrolysis degree is 20%) and diutan (mass ratio 1:1), and the repair agent is a combination of hydrogen peroxide and manganese dioxide (mass ratio 1:1) or a combination of sodium carbonate and sodium bisulfate (mass ratio 3:1).

[0039] The main purpose of nitrogen foam slug is to increase the longitudinal sweep volume of steam and assist in plugging the pores. The design method of the usage is mainly based on the columnar volume of a certain treatment radius of the oil layer. The usage of nitrogen foam slug Vs is:

[0040]

[0041] Where: Vs is the volume of nitrogen foam in the formation (m 3 ), r2: treatment radius (m), h: oil layer thickness (m), Porosity (%), depending on the actual reservoir conditions, r2 is usually set to 6-12m.

[0042] In step (3), a supercritical fluid and a composite surfactant are injected into the oil layer to form a viscosity-reducing plug; the mass ratio of the supercritical fluid to the composite surfactant is 15-20:1-3; the supercritical fluid is supercritical CO2 with a volume purity greater than 75%, and the composite surfactant is a combination of betaine (purchased from Beijing Inokai Technology Co., Ltd.) and polyoxyethylene diamine (brand P107102-1g, purchased from Beijing Huawei Ruike Chemical Co., Ltd.) or (1S,2S)-2-aminocyclohexane-1-carboxylic acid hydrochloride (brand HWRK000609, purchased from Beijing Huawei Ruike Chemical Co., Ltd.).

[0043] The method for determining the amount of supercritical fluid is:

[0044] Q2=A Vs;

[0045] In the formula, A is a value of 0.5-1, Vs is the usage of the nitrogen foam slug, that is, the usage of Q2 is 0.4-0.8 times the usage of the nitrogen foam slug.

[0046] The present invention provides a method for reducing the viscosity of super-heavy oil reservoirs, which can be applied to the following super-heavy oil reservoir conditions: the crude oil viscosity at the reservoir temperature is 10-100×10 4mP.s, reservoir temperature is 15-90℃, reservoir thickness is 3-15m, mineralization is ≤200000mg / L, and water content is 70-100%.

[0047] The specific implementation is as follows:

[0048] Example 1

[0049] Reservoir conditions: A heavy oil development well has a medium reservoir depth of 315 meters, an effective oil layer thickness of 5.8 meters, an initial oil saturation of 65.61%, an average porosity of 28.3%, a crude oil viscosity of 105177.6 MPa.s at a reservoir temperature of 27.5°C, a salinity of 80,000 mg / L, and is a heterogeneous extra-heavy oil reservoir. The water content of the produced fluid is 92.5%.

[0050] Conventional steam stimulation was carried out for a total of 12 rounds. The oil production in the 12th steam stimulation cycle was 71.2 tons, and the oil-steam ratio was 0.08.

[0051] The steam throughput is determined as follows: r1 is 4m, r2 is 7m, A is 0.5, and the gel material system is 83m 3 , nitrogen foam 253m 3 、Supercritical fluid 127m 3 , cumulative steam injection 1000t. Steam huff and puff oil production:

[0052] (1) Plugging: The injection volume of the gel material system is 83m 3 The gel material was prepared by mixing the following components: 1% bacterial cellulose, 1% agarose, 1% cross-linking agent (calcium chloride), 1% propylene glycol alginate, and the rest was water, and the mixture was sealed for 36 hours.

[0053] (2) Bubble nitrogen 253m 3 Injecting nitrogen and a foaming fluid into the oil well, wherein the volume ratio of the foaming fluid to the nitrogen is 0.5:0.5, and the foaming fluid is composed of the following components in percentage by weight: the foaming fluid includes 0.4% of a foaming agent (sodium lauryl sulfate), 0.1% of a foam stabilizer (polyacrylamide and diutanol in a mass ratio of 1:1), 1% of a repair agent (hydrogen peroxide and manganese dioxide in a mass ratio of 1:1), and the balance is water;

[0054] (3) After the nitrogen foam injection is completed, the supercritical fluid 127m 3 (59t) and 4.1t of composite surfactant were injected into the oil layer; the supercritical fluid was supercritical CO2 with a volume purity greater than 75%, and the composite surfactant consisted of 5% betaine, 5% polyoxyethylene diamine, 5% (1S,2S)-2-aminocyclohexane-1-carboxylic acid hydrochloride, and the balance was water;

[0055] (4) After the nitrogen injection is completed, 1000 tons of steam is injected into the oil layer with an injection pressure of 6.8-7.3 MPa, a steam dryness of 73%, and an injection temperature of 270-283°C. The well is then shut down for 3 days and the oil is recovered.

[0056] By using the steam stimulation oil production method of this embodiment, the oil production in this cycle increased by 94.6% compared with the previous cycle, the comprehensive water content of the cycle decreased from 92.5% to 31.1%, the oil-gas ratio increased from 0.08 to 0.25, and the viscosity reduction rate reached 93.05%.

[0057] Example 2

[0058] Reservoir conditions: A heavy oil development well has a medium reservoir depth of 229.4 meters, an effective oil layer thickness of 7.4 meters, an initial oil saturation of 57.7%, an average porosity of 35.6%, a crude oil viscosity of 136447 MPa.s at a reservoir temperature of 30.8°C, and a salinity of 90,000 mg / L. This is a heterogeneous extra-heavy oil reservoir with a water content of 90.8% in the produced fluid.

[0059] Conventional steam stimulation was carried out for a total of three rounds. The oil production in the third steam stimulation cycle was 38 tons, and the oil-steam ratio was 0.03.

[0060] The steam throughput is determined as follows: r1 is 5m, r2 is 8m, A is 0.6, and the gel material system is 207m 3 , nitrogen foam 530m 3 、Supercritical fluid 318m 3 , cumulative steam injection of 800t. Steam huff and puff oil production:

[0061] (1) Plugging: The injection volume of the gel material system is 207m 3 The gel material was prepared by mixing the following components: 2% bacterial cellulose, 1% agarose, 0.5% cross-linking agent (calcium chloride), 1% sodium alginate, and the balance was water, and the mixture was sealed for 36 hours.

[0062] (2) Bubble nitrogen for 530m 3 Injecting nitrogen and a foaming fluid into the oil well, wherein the volume ratio of the foaming fluid to the nitrogen is 0.3:0.5, and the foaming fluid is composed of the following components in percentage by weight: the foaming fluid includes 0.5% of a foaming agent (sodium lauryl sulfate), 0.2% of a foam stabilizer (polyacrylamide and diutanol in a mass ratio of 1:1), 2% of a repair agent (hydrogen peroxide and manganese dioxide in a mass ratio of 1:1), and the balance is water;

[0063] (3) After the nitrogen foam injection is completed, the supercritical fluid 318m 3(149t) and 12t of composite surfactant were injected into the oil layer; the supercritical fluid was supercritical CO2 with a volume purity greater than 75%, and the composite surfactant was composed of 10% betaine, 5% polyoxyethylene diamine, and the balance was water;

[0064] (4) After the nitrogen injection is completed, 800 tons of steam is injected into the oil layer with an injection pressure of 6.8-7.3 MPa, a steam dryness of 73%, and an injection temperature of 270-283°C. The well is then soaked for 3 days and the oil is recovered.

[0065] By using the steam stimulation oil production method of this embodiment, the oil production in this cycle increased by 93.4% compared with the previous cycle, the comprehensive water content of the cycle decreased from 90.8% to 33.5%, the oil-gas ratio increased from 0.03 to 0.17, and the viscosity reduction rate reached 92.1%.

[0066] Example 3

[0067] Reservoir conditions: A heavy oil development well has a medium depth of 330 meters, an effective oil layer thickness of 6.2 meters, an initial oil saturation of 61.5%, an average porosity of 30.8%, a crude oil viscosity of 108,880 MPa.s at a reservoir temperature of 30°C, and a salinity of 85,000 mg / L. This is a heterogeneous extra-heavy oil reservoir with a water content of 91.2% in the produced fluid.

[0068] Conventional steam stimulation was carried out for 9 rounds in total. The oil production of the 9th steam stimulation cycle was 58 tons, and the oil-steam ratio was 0.06.

[0069] The steam throughput is determined as follows: r1 is 4m, r2 is 6m, A is 0.4, and the gel material system is 96m 3 , nitrogen foam 216m 3 、Supercritical fluid 87m 3 , a total of 900t of steam was injected.

[0070] Steam stimulation and oil recovery:

[0071] (1) Plugging: The injection volume of the gel material system is 96m 3 The gel material preparation includes the following components: 0.5% bacterial cellulose, 3% agarose, 2% cross-linking agent (calcium chloride), 2% sodium alginate, and the rest is water, and the well is sealed for 36 hours;

[0072] (2) Bubble nitrogen 216m 3Injecting nitrogen and a foaming fluid into the oil well, wherein the volume ratio of the foaming fluid to the nitrogen is 0.3:0.5, and the foaming fluid is composed of the following components in percentage by weight: the foaming fluid includes 0.2% of a foaming agent (sodium lauryl sulfate), 0.05% of a foam stabilizer (polyacrylamide and diutanol in a mass ratio of 1:1), 0.5% of a repair agent (sodium carbonate and sodium bisulfate in a mass ratio of 3:1), and the balance is water;

[0073] (3) After the nitrogen foam injection is completed, the supercritical fluid 87m 3 (40t) and 2t of composite surfactant were injected into the oil layer; the supercritical fluid was supercritical CO2 with a volume purity greater than 75%, and the composite surfactant was composed of 5% betaine, 10% (1S,2S)-2-aminocyclohexane-1-carboxylic acid hydrochloride, and the balance was water;

[0074] (4) After the nitrogen injection is completed, 900 tons of steam is injected into the oil layer with an injection pressure of 6.8-7.3 MPa, a steam dryness of 73%, and an injection temperature of 270-283°C. The well is then shut down for 3 days and the oil is recovered.

[0075] By using the steam stimulation oil production method of this embodiment, the oil production in this cycle increased by 92.5% compared with the previous cycle, the comprehensive water content of the cycle decreased from 91.2% to 35.8%, the oil-gas ratio increased from 0.06 to 0.19, and the viscosity reduction rate reached 90.6%.

[0076] Comparative Example

[0077] Reservoir conditions: A heavy oil development well has a medium reservoir depth of 313 meters, an effective oil layer thickness of 5.7 meters, an initial oil saturation of 63.28%, an average porosity of 27.5%, a crude oil viscosity of 104092.5 MPa.s at a reservoir temperature of 27.5°C, a salinity of 80000 mg / L, and a heterogeneous super-heavy oil reservoir. The produced fluid contains 89.8% water.

[0078] Conventional steam stimulation was carried out for a total of 12 rounds. The oil production in the 12th steam stimulation cycle was 71.2 tons, and the oil-steam ratio was 0.08.

[0079] The steam throughput is determined as follows: r1 is 4m, r2 is 7m, A is 0.5, and the gel material system is 79m 3 , nitrogen foam 242m 3 、Supercritical fluid 121m 3 , cumulative steam injection 1000t. Steam huff and puff oil production:

[0080] (1) Plugging: The injection volume of the gel material system is 79m 3 The gel-like substance was prepared by mixing the following components: 5% xanthan gum, 2% urea, 1% borax, and the rest water, and then suffocated for 36 hours.

[0081] (2) Bubble nitrogen 242m 3 Injecting nitrogen and a foaming liquid into the oil well, wherein the volume ratio of the foaming liquid to the nitrogen is 0.5:0.5, and the foaming liquid is composed of the following components in percentage by weight: the foaming liquid includes 0.4% sodium dodecylbenzene sulfonate, 0.1% polyacrylamide, and the balance is water;

[0082] (3) After the nitrogen foam injection is completed, 120m3 of liquid carbon dioxide 3 (80t) and 5.6t of composite surfactant were injected into the oil layer. The composite surfactant consisted of 10% surfactant OP-10, 25% 120# solvent oil, 12% sodium alkylphenol polyoxyethylene ether sulfonate, 1% Tween 80, 3% isopentane, and the balance was water;

[0083] (4) After the nitrogen injection is completed, 900 tons of steam is injected into the oil layer with an injection pressure of 6.8-7.3 MPa, a steam dryness of 73%, and an injection temperature of 270-283°C. The well is then shut down for 3 days and the oil is recovered.

[0084] By using the steam stimulation oil production method of this embodiment, the oil production in this cycle increased by 91.2% compared with the previous cycle, the comprehensive water content of the cycle decreased from 89.8% to 42.6%, the oil-gas ratio increased from 0.08 to 0.16, and the viscosity reduction rate reached 90.03%.

[0085] By comparing Examples 1-3 with the comparative example, it can be found that the methods of Examples 1-3 and the comparative example all significantly improve the oil production, viscosity reduction rate, and gasoline ratio compared to the previous cycle. The oil production increase rate, viscosity reduction rate, and oil-gas ratio of Examples 1-3 are significantly higher than those of the comparative example, and the water content of Examples 1-3 is significantly lower than that of the comparative example. By comparing the examples with the previous cycle and the comparative example, it can be effectively demonstrated that the method of the present invention, which combines plugging, nitrogen foam, and supercritical fluid with a composite active agent, can only effectively plug and reduce viscosity, increase vapor sweep volume, reduce steam channeling, reduce edge and bottom water intrusion, significantly improve viscosity reduction ability, and increase recovery rate when they are coordinated, ultimately achieving the optimal viscosity reduction effect and recovery rate.

[0086] The present invention injects plugging agents, nitrogen foam slugs and viscosity reducing slugs before steam injection, which work together to solve the problems of steam channeling, edge and bottom water intrusion, and small steam wave volume in the process of steam viscosity reduction of heavy oil, thereby improving the viscosity reduction capability of heavy oil and increasing the recovery rate.

[0087] In this specification, references to the same or similar parts between the various embodiments can be made to each other, and each embodiment focuses on the differences from other embodiments. In particular, for the system embodiment, since it is basically similar to the method embodiment, the description is relatively simple, and the relevant parts can be referred to the partial description of the method embodiment.

[0088] The foregoing is merely an embodiment of the present application and is not intended to limit the present application. For those skilled in the art, the present application may have various modifications and variations. Any modifications, equivalent replacements, improvements, etc. made within the spirit and principles of the present application should be included within the scope of the technical solutions of the present application.

Claims

1. A method for reducing the viscosity of an ultra-heavy oil reservoir, characterized in that: The following steps are involved: (1) Injecting plugging agent into the oil well; (2) injecting nitrogen foam slugs into the oil well; (3) injecting the viscosity reduction slug into the oil well; (4) Inject steam into oil wells to block wells and recover oil; In step (1), the blocking agent includes bacterial cellulose, agarose and a cross-linking agent.

2. The method for reducing viscosity of super heavy oil reservoirs according to claim 1, characterized in that: The mass ratio of the bacterial cellulose, agarose and cross-linking agent is: 0.5-5: 1-8: 0.5-2.

3. A method for reducing viscosity of super heavy oil reservoirs according to claim 1 or 2, characterized in that: The blocking agent also includes alginate and its derivatives.

4. The method for reducing viscosity of super heavy oil reservoirs according to claim 3, characterized in that: The mass ratio of the alginate and its derivatives to the cross-linking agent is 0.5-1:

1.

5. The method for reducing viscosity of super heavy oil reservoirs according to claim 1, characterized in that: In step (2), nitrogen and foaming liquid are injected into the oil layer to form a nitrogen foam slug; the volume ratio of nitrogen to foaming liquid is 0.3-0.5:0.3-0.

5.

6. The method for reducing viscosity of super heavy oil reservoirs according to claim 5, characterized in that: Calculated by mass percentage, the foaming liquid includes 0.2-0.5% foaming agent, 0.01-0.2% foam stabilizer, 0.1-2% repair agent, and the balance is water.

7. The method for reducing viscosity of super heavy oil reservoirs according to claim 6, characterized in that: The foaming agent is sodium lauryl sulfate, the foam stabilizing agent is polyacrylamide and diutan, and the repairing agent is a combination of hydrogen peroxide and manganese dioxide or a combination of sodium carbonate and sodium bisulfate.

8. The method for reducing viscosity of super heavy oil reservoirs according to claim 1, characterized in that: In step (3), supercritical fluid and composite surfactant are injected into the oil layer to form a viscosity-reducing slug.

9. The method for reducing viscosity of super heavy oil reservoirs according to claim 8, characterized in that: The mass ratio of the supercritical fluid to the composite surfactant is 15-20:1-3.

10. The method for reducing viscosity of super heavy oil reservoirs according to claim 8, characterized in that: The composite surfactant comprises a composition of betaine and polyoxyethylene diamine or (1S, 2S)-2-aminocyclohexane-1-carboxylic acid hydrochloride.