Method for chemical composite flooding and cold production of oil after steam thermal recovery of heavy oil reservoirs

Abstract

The application discloses a method for chemical composite flooding and cold production of petroleum after steam thermal production of heavy oil reservoirs, comprising the following steps: step 2, selecting a chemical viscosity reducer system, and performing field test injection to test formation injection property and development degree of channeling flow channels, and calculate the ratio of oil well produced liquid volume to well group liquid production volume; step 3, when the ratio of oil well produced liquid volume to well group liquid production volume is less than a threshold value, continuously injecting the chemical viscosity reducer system to exploit heavy oil in the formation; when the ratio of oil well produced liquid volume to well group liquid production volume is greater than or equal to the threshold value, according to fluid properties and formation conditions of the heavy oil reservoir, a channeling flow control system is selected; step 4, the chemical viscosity reducer system and the channeling flow control system are injected into a chemical composite flooding and cold production well group on site to exploit heavy oil in the formation. The method can exploit the heavy oil reservoir at low cost without heating the formation, and has good field test effect, and is especially suitable for low-cost exploitation of the heavy oil reservoir after multiple rounds of steam huff and puff thermal production.

Description

Technical Field

[0001] The present invention relates to the technical field of oil and gas extraction, and in particular to a method for cold oil extraction from a heavy oil reservoir using chemical composite flooding followed by steam thermal extraction. Background Art

[0002] Heavy oil in China is generally buried deep and has high viscosity. Most reservoirs are concentrated in unconsolidated sandstone formations at depths of 1,000-1,500 meters. Crude oil viscosities are generally greater than 400 mPa·s (50°C). Thermal recovery, primarily through steam stimulation, produces approximately 15 million tons annually, with an average recovery rate of less than 20%. The formations are rich in residual oil. However, after multiple rounds of steam stimulation, the thermal radius remains difficult to increase, the oil-gas ratio continues to decline, the water cut continues to rise, and the effectiveness of thermal recovery continues to decline. Consequently, there is an urgent need for alternative technologies to enhance recovery, suitable for the later stages of heavy oil development.

[0003] Currently, there are three main methods for recovering heavy oil reservoirs after multiple rounds of steam stimulation and thermal recovery. One method involves incorporating chemical or physical measures into existing steam stimulation and thermal recovery, using a combination of these measures to enhance steam stimulation and thermal recovery. Another method involves converting individual wells into steam injection wells and continuously injecting high-temperature steam to achieve large-scale heating and viscosity reduction for heavy oil recovery. Finally, another method involves injecting oxygen-containing gases (such as air) into the formation and igniting some of the remaining oil in the formation to heat and reduce viscosity for heavy oil recovery. This multi-measure approach to enhance steam stimulation and thermal recovery does not fundamentally address existing problems; it only extends the benefit cycle of steam stimulation. Steam stimulation and thermal recovery still rely on surface heat sources, generating high-temperature, high-pressure steam for injection into the formation. This approach fails to address wellbore heat loss, low underground dryness, and poor thermal efficiency. Reservoir combustion, which relies on underground heat sources, is technically complex, can produce sand and casing damage, poses safety risks, and is costly. While it may be a future alternative, it cannot meet the current needs of my country for further development of heavy oil reservoirs after steam stimulation. Furthermore, thermal recovery methods all face challenges such as high heating costs, severe corrosion in the heat-gas-electrolyte wellbore, and steam channeling, making them difficult to exploit profitably at current low oil prices. Consequently, no chemical flooding cold recovery method has been developed for heavy oil reservoirs after steam stimulation thermal recovery, either domestically or internationally.

[0004] Invention patent CN111004616 discloses a self-emulsifying corrosion inhibitor and viscosity reducer for cold production of heavy oil reservoirs using huff-and-puff, as well as its preparation method and application. This invention only uses indoor viscosity reduction and corrosion inhibition rates as indicators to develop an indoor self-emulsifying corrosion inhibitor and viscosity reducer system. It does not form a chemical composite flooding cold production method for heavy oil reservoirs after steam huff-and-puff thermal recovery. Furthermore, the indoor viscosity is fundamentally different from the viscosity of underground porous media. The viscosity of the emulsion system after indoor viscosity reduction cannot be used as an indicator of oil-water phase viscosity reduction in porous media at the mesoscopic scale underground. Invention patent CN107143319 discloses a method for cold production of heavy oil in shallow reservoirs. This method targets shallow heavy oil reservoirs and imposes stringent requirements on the acid value, depth, porosity and permeability, formation dip, and well spacing. It is not applicable to my country's current mainstream heavy oil reservoirs of approximately 1000-1500 mm, nor is it suitable for further reservoir development after steam huff-and-puff. Furthermore, it does not address a series of cold production methods such as chemical composite flooding well selection, injection, and regulation. Invention patent CN103510932 discloses a chemical cold recovery method for medium- to deep-layer, low-permeability heavy oil reservoirs. This method involves a single-well chemical viscosity reduction huff-and-puff method and involves future steam huff-and-puff followed by rotary flooding. It also provides no guidance on chemical agent selection, well group selection, test injection, and rotary flooding. Invention patent CN103899286 discloses a method for cold recovery of heavy oil at the edge of a reservoir structure. Its primary purpose is to reduce wellbore viscosity, which is completely different from formation viscosity reduction. It also does not address methods related to formation heavy oil recovery.

[0005] Therefore, in order to address the high cost, high corrosion, and low efficiency problems faced by the technology of further oil recovery after multiple rounds of steam stimulation and thermal recovery in heavy oil reservoirs, a new technology for heavy oil recovery is urgently needed to achieve low-cost, low-corrosion sustainable development of such reservoirs after multiple rounds of steam stimulation and thermal recovery. Summary of the Invention

[0006] In order to solve the above problems in the prior art, the present invention proposes a method for cold recovery of oil by chemical composite flooding followed by steam thermal recovery in heavy oil reservoirs.

[0007] As a specific embodiment of the present invention, the method includes:

[0008] Step 2: Select a chemical viscosity reducer system and conduct on-site test injection to test the formation injectivity and the development of crossflow channels, and calculate the ratio of each well's produced fluid volume to the well group's produced fluid volume;

[0009] Step 3: When the ratio of the produced fluid volume of a single oil well to the produced fluid volume of the well group is less than a threshold, continuously test-injecting the chemical viscosity reducer system to produce the heavy oil in the formation; when the ratio of the produced fluid volume of a single oil well to the produced fluid volume of the well group is greater than or equal to the threshold, selecting a crossflow control system based on the fluid properties and formation conditions of the heavy oil reservoir;

[0010] Step 4: injecting the chemical viscosity reducer system and the crossflow control system into the chemical composite flooding cold production well group on site to produce the formation heavy oil.

[0011] Optional, step 1: determine the heavy oil reservoir to be subjected to chemical combined flooding cold recovery,

[0012] The heavy oil reservoirs requiring chemical combined flooding and cold recovery are determined based on the geological characteristics of the heavy oil reservoirs, the well pattern, the oil-gas ratio of steam huff-and-puff thermal recovery, and the degree of steam cross-over.

[0013] Preferably, geological modeling, reservoir numerical simulation and dynamic reservoir history fitting are used to determine the geological characteristics and well pattern perfection of the heavy oil reservoir; production performance data are used to determine the oil-gas ratio and steam channeling degree of steam stimulation thermal recovery;

[0014] More preferably, a heavy oil reservoir to be treated for chemical composite flooding cold recovery is determined to have a complete well network, geological connectivity between wells, an oil-to-gas ratio of less than 0.4 in the latest round of steam stimulation thermal recovery, and steam channeling in at least three wells within the injection-production well group.

[0015] Preferably, in step 2, the chemical viscosity reducer system includes a water-soluble viscosity reducer; and / or the chemical viscosity reducer system is a composite viscosity reducer including a water-soluble viscosity reducer and an oil-soluble viscosity reducer, and / or in the chemical viscosity reducer system, except for the viscosity reducer, the remaining components are water injected into the formation.

[0016] Preferably, the water-soluble viscosity reducer is a water-soluble surfactant selected from at least one of alkyl sulfonates, alkyl carboxylates, betaine, arbutin, and polyoxyethylene ether, and / or the tension between the interface of the chemical viscosity reducer system and the target heavy oil is less than 10 -1 mN / m, and / or the average particle size of the emulsified oil droplets formed by the chemical viscosity reducer and the target heavy oil is less than 1 / 3 of the average throat diameter of the formation; the oil-soluble viscosity reducer is a polymer of unsaturated acid lipids, EVA, a maleate derivative, etc., and preferably can reduce the internal phase viscosity of the emulsion formed by the chemical viscosity reducer and the target heavy oil to below 100 mPa·s.

[0017] The alkyl sulfonate, alkyl carboxylate, betaine, glycolipid, and polyoxyethylene ether can be any conventional reagent in the art, and the present invention has no special requirements therefor. For example, sodium dodecylbenzenesulfonate, sodium dodecylcarboxylate, sodium petroleum sulfonate, laurylamidopropyl betaine, C10-C18 fatty alcohol polyoxyethylene ether, for example, C13 fatty alcohol polyoxyethylene ether, etc. can be used as the water-soluble surfactant.

[0018] The oil-soluble viscosity reducer is an unsaturated acid polymer, EVA, or a maleate derivative. Any conventional agent in the art can be used, and the present invention has no special requirements therefor. For example, ethylene-vinyl acetate-sodium propylene sulfonate copolymer, methacrylic acid higher carbon mixed alcohol ester copolymer, ethylene-vinyl acetate copolymer, etc. can be used as the oil-soluble surfactant.

[0019] Preferably, in the step 2,

[0020] The chemical viscosity reducer system is subjected to on-site test injection, and the balanced injection pressure is used to characterize the injectivity of the formation. When the balanced injection pressure during the test injection process is not higher than 10 MPa, preferably lower than 5 MPa, it indicates that the formation has good injectivity. The well is selected as the injection well, and the adjacent well is selected as the production well to construct an injection-production well network.

[0021] Preferably, in step three, the threshold is 70%, preferably 50%.

[0022] Preferably, in step three,

[0023] The cross-flow control system includes a particle dispersion suspension system or a jelly gel fluidity mutation system;

[0024] Preferably, the particle dispersion suspension system is a suspension system formed by polymer microspheres, jelly dispersions, pre-crosslinked particles or bulk-swelling particles and water; and / or the particle size of the particle dispersion suspension system is less than 1 / 5 of the average pore diameter of the formation, and can expand more than twice or aggregate into large particles under the conditions of formation temperature and salinity. Preferably, the particle size of the particle dispersion suspension system ranges from 0.1 μm to 1 mm.

[0025] Preferably, the fluidity mutation system of the jelly gel is a composite system solution of a polymer and a cross-linking agent, which forms a semi-solid after aging for 10-48 hours under formation conditions, and the physical and chemical properties are stable for 360 days after the fluidity mutation; and / or

[0026] The type of the crossflow control system is determined in the following manner: when the ratio of the produced fluid volume of a single oil well to the produced fluid volume of a well group is greater than or equal to a threshold value, and other oil wells are also affected to varying degrees, the particle-based dispersed suspension system is selected; when the ratio of the produced fluid volume of a single oil well to the produced fluid volume of a well group is greater than or equal to a threshold value, and there are oil wells that should be affected but are not, the jelly-gel-based fluidity mutation system is selected.

[0027] Preferably, in step 4, the injection process of the chemical viscosity reducing agent system and the crossflow control system is determined according to the type of the crossflow control system in step 3;

[0028] When the crossflow control system is the particle dispersion suspension system, the chemical viscosity reducer system is mixed with the crossflow control system and then injected simultaneously;

[0029] When the crossflow control system is a jelly-type fluidity sudden change system, the crossflow control system is first injected, and after the fluidity sudden change occurs, the chemical viscosity reducer system is injected. In step 4, the injection process of the chemical viscosity reducer system and the crossflow control system is determined based on the type of crossflow control system described in step 3;

[0030] When the crossflow control system is the particle dispersion suspension system, the chemical viscosity reducer system is mixed with the crossflow control system and then injected simultaneously;

[0031] When the cross-flow control system is the jelly-gel fluidity mutation system, the cross-flow control system is injected first, and then the chemical viscosity reducer system is injected after the fluidity mutation occurs.

[0032] The method of the present invention enables low-cost development of heavy oil reservoirs without heating the formation, resolving the technical challenge of successive development of heavy oil reservoirs after multiple rounds of steam stimulation and thermal recovery. Currently, no mature technology exists to address this challenge, making this method a revolutionary breakthrough. Single-well trials using the method of the present invention in a typical well group in the heavy oil block of Shengli Oilfield revealed a cumulative increase of over 2,500 tons in oil production after one year, with no significant corrosion of the oil casing and tubing. Operating costs were reduced by approximately 50% compared to well groups using pure steam stimulation. BRIEF DESCRIPTION OF THE DRAWINGS

[0033] The accompanying drawings are used to provide further understanding of the present invention and constitute a part of the specification. They are used to explain the present invention together with the following specific embodiments, but do not constitute a limitation of the present invention.

[0034] Figure 1 The present invention is a flowchart of the steps of a method for cold recovery of oil from a heavy oil reservoir by multiple rounds of steam stimulation and puffing followed by chemical composite flooding according to an embodiment of the present invention. DETAILED DESCRIPTION

[0035] The following embodiments of the present invention are described in detail with reference to the accompanying drawings. The following embodiments are only used to more clearly illustrate the technical solutions of the present invention and are therefore only examples and are not intended to limit the scope of protection of the present invention.

[0036] Figure 1 A flow chart of a method for cold recovery of oil by multiple rounds of steam stimulation and thermal recovery followed by chemical composite flooding in a heavy oil block well group of Shengli Oilfield according to an embodiment of the present invention is provided. Figure 1 As shown, the method for cold recovery of oil in a heavy oil reservoir by multiple rounds of steam stimulation and puffing followed by chemical composite flooding can be specifically referred to steps S01 to S04.

[0037] S01) Determine the heavy oil reservoir that needs chemical combined flooding and cold recovery of oil.

[0038] Specifically, the team first selected a heavy oil reservoir undergoing steam stimulation and thermal recovery at a depth of approximately 1,200 meters and with an underground crude oil viscosity of 970 mPa·s. The heavy oil reservoirs suitable for chemical flooding and cold recovery were then determined based on their geological characteristics, well pattern integrity, the oil-gas ratio achieved through steam stimulation and thermal recovery, and the degree of gas cross-contamination.

[0039] Among them, geological modeling, reservoir numerical simulation and dynamic reservoir history fitting are used to determine the geological characteristics and well network perfection of heavy oil reservoirs; production dynamic data are used to determine the oil-gas ratio and the degree of steam channeling.

[0040] Specifically, heavy oil reservoirs suitable for chemical composite flooding and cold recovery are identified as those with a complete well network, geological connectivity between wells, an oil-to-gas ratio of 0.32 in the latest round of steam stimulation and thermal recovery, and obvious steam crosstalk between three wells in the one injection and four production well group. A complete well network includes the formation of a five-spot well network, an inverted five-spot well network, and an inverted nine-spot well network. Geological connectivity between wells means that the well group is in the same sand layer and there are no faults or pinch-outs between wells.

[0041] In this embodiment, the test well group for chemical composite flooding cold oil recovery is an inverted five-spot well pattern.

[0042] S02) According to the properties of heavy oil in different heavy oil reservoirs, a chemical viscosity reducer system is selected and field injection is carried out to test the injection property of the formation and the development degree of crossflow channels, and the ratio of the oil well production volume to the well group production volume is calculated.

[0043] Specifically, in this embodiment, the chemical viscosity reducer system is a composite viscosity reducer comprising a water-soluble viscosity reducer and an oil-soluble viscosity reducer in a ratio of 3:1. The water-soluble viscosity reducer is a 0.6% by weight aqueous solution of lauramidopropyl betaine, and the oil-soluble viscosity reducer is a 0.2% by weight ethylene-vinyl acetate-sodium propylene sulfonate copolymer. In addition to the viscosity reducer, the remaining components of the chemical viscosity reducer system are formation injection water. The interfacial tension with the target heavy oil is 0.085 mN / m, the average particle size of the emulsified oil droplets formed with the target heavy oil is 3.8 microns, and the average diameter of the target reservoir throat is 14 microns. Therefore, the average particle size of the emulsified oil droplets is less than 1 / 3 of the average throat diameter of the target reservoir formation, or when the oil-to-water ratio of the emulsified oil is 1:2, the viscosity of the emulsified system is 48 mPa·s.

[0044] The selected chemical viscosity reducer system was tested on site, and the balanced injection pressure was used to characterize the formation injectivity. When the balanced injection pressure during the test injection process was 1.3 MPa, it indicated that the formation injectivity was good. The well was selected as the injection well, and the adjacent well was selected as the production well to construct an injection-production well network.

[0045] Specifically, in the field test well group, the ratio of the produced fluid volume of a single oil well to the production volume of the well group is used to characterize the degree of crossflow channel development. When the produced fluid volume of a single oil well in the effective well is greater than or equal to 50% of the production volume of the well group, it indicates that the crossflow channel is significantly developed, and a crossflow control system is selected and injected. When the produced fluid volume of a single oil well in the effective well is less than 50% of the production volume of the well group, an appropriate chemical viscosity reducer is continuously injected to produce heavy oil until the produced fluid volume of a single oil well is greater than or equal to 50% of the production volume of the well group. Among them, the injection and production well group consisting of the injection well and the surrounding adjacent production wells is the field test well group. The effective wells are the production wells surrounding the injection well in the injection and production well group. After the viscosity reducer is injected, the water content of the corresponding production well should decrease and the oil production capacity should increase.

[0046] In this step, when the selected chemical viscosity reducer system is tested on site, a booster pump is used to inject the selected chemical viscosity reducer system into the injection well at an injection speed of 3m 3 / h, and the infusion duration was 4 months.

[0047] In this embodiment, the field test injection adopts a "gradually increasing displacement" approach, varying the displacement according to the injection pressure of the chemical viscosity reducer system. Test injection is conducted at 50% of the reservoir's injection requirements. When the equilibrium injection pressure does not exceed 5 MPa, the displacement is increased by 10% every 10 days until the injection requirements are met. When the equilibrium pressure exceeds 5 MPa, the displacement is reduced until the pressure meets the requirements. The displacement is dynamically adjusted with injection pressure until the injection displacement meets the injection requirements and the wellhead pressure stabilizes. Injection is continued at this displacement until the produced fluid volume of a single well is equal to or greater than 50% of the well group's production.

[0048] In this embodiment, after the chemical viscosity reducer system is continuously injected for 4 months, the produced fluid volume of a single oil well begins to be greater than 50% of the produced fluid volume of the well group.

[0049] S03) Selecting a crossflow control system based on fluid properties and formation conditions;

[0050] Specifically, when the ratio of the produced fluid volume of the oil well to the produced fluid volume of the well group is less than a threshold value, the chemical viscosity reducer system is continuously injected to produce the heavy oil in the formation; when the ratio of the produced fluid volume of the oil well to the produced fluid volume of the well group is greater than or equal to the threshold value, a crossflow control system is selected based on the fluid properties and formation conditions of the heavy oil reservoir.

[0051] The selected crossflow control systems include particle-based dispersed suspension systems or jelly-gel-based fluidity mutation systems. In the particle-based dispersed suspension system, the difference between the particle density and the injected water density is less than 3%. In this embodiment, a suspension system formed by polyacrylamide microspheres (which can also be a jelly dispersion, pre-crosslinked particles, or bulk-swelling particles primarily composed of polyacrylamide) and water is used. The particles have a particle size of 2.6 microns (the average pore diameter of the formation is 15 microns). Under formation temperature and salinity conditions, they can expand by more than twice, or multiple particles can aggregate into a large aggregate. The jelly-gel-based fluidity mutation system is a composite solution of a polymer and a crosslinker. After injection into the formation, it forms a semi-solid state under formation conditions within 10-48 hours, transitioning from easy flow to difficult flow or non-flow. Physical and chemical properties remain stable for 360 days after the fluidity mutation.

[0052] The particle dispersion suspension system selected for the well group of this embodiment changes from a flowable gel to a semi-solid after aging for 16 hours.

[0053] The type of crossflow control system is determined by the characteristics of the well group: when the ratio of the produced fluid volume of a single oil well to the produced fluid volume of the well group is greater than or equal to 50%, and other oil wells are also affected to varying degrees, a particle-based dispersed suspension system is selected; when the ratio of the produced fluid volume of a single oil well to the produced fluid volume of the well group is greater than or equal to 50%, and there are oil wells that should be affected but are not, a jelly-gel-based fluidity mutation system is selected.

[0054] S04) Inject the chemical viscosity reducer system and crossflow control system into the chemical composite flooding cold production well group on site to produce the formation heavy oil

[0055] In this embodiment, the test well group is an inverted five-point well pattern, and the flow rates of the four oil production wells are 55%, 28%, 8% and 9% respectively. The compound system of betaine and polyoxyethylene sulfonate is selected to be injected into the well group simultaneously to regulate the crossflow channel.

[0056] The chemical viscosity reducer continuously cleans the heavy oil carried within the porous medium. Simultaneously, the selected cross-flow control system, namely pre-cross-linked particles, expands the chemical viscosity reducer's range of action. The pre-cross-linked particles block localized cross-flow pores, allowing the chemical viscosity reducer to bypass areas rich in residual oil, where it emulsifies and reduces the viscosity of the heavy oil, displacing the remaining oil to the production wells (effective wells), achieving enhanced recovery. The synergistic effect of the two allows for the widespread recovery of heavy oil from the formation.

[0057] In this step, a single-well group test was conducted on the heavy oil block of Shengli Oilfield. After one year of the test, the cumulative oil production increased by more than 2,500 tons, there was no obvious corrosion of the oil casing, and the operating cost was reduced by about 50% compared with the pure well group steam throughput.

[0058] The method for cold oil recovery by chemical composite flooding after multiple rounds of steam huff-and-puff thermal recovery in heavy oil reservoirs disclosed in the present application can develop heavy oil reservoirs at low cost without heating the formation, and has shown good results in field tests. The method is particularly suitable for low-cost development of heavy oil reservoirs after multiple rounds of steam huff-and-puff thermal recovery, and can greatly increase the recovery of heavy oil reservoirs under low-cost conditions.

Claims

1. A method for cold recovery of oil by chemical composite flooding in heavy oil reservoirs after steam thermal recovery, characterized in that: include: Step 2: Select a chemical viscosity reducer system and conduct on-site test injection to test the formation injectivity and the development of crossflow channels, and calculate the ratio of each well's produced fluid volume to the well group's produced fluid volume; Step 3: When the ratio of the produced fluid volume of a single oil well to the produced fluid volume of the well group is less than a threshold value, continuously injecting the chemical viscosity reducer system to produce the heavy oil in the formation; When the ratio of the produced fluid volume of a single oil well to the produced fluid volume of the well group is greater than or equal to a threshold, a crossflow control system is selected according to the fluid properties and formation conditions of the heavy oil reservoir, and step 4 is executed; Step 4: injecting the chemical viscosity reducer system and the crossflow control system into the chemical composite flooding cold production well group on site to produce the formation heavy oil. In the step 3, the crossflow control system includes a particle dispersion suspension system or a jelly gel fluidity mutation system; The type of crossflow control system is determined by the following method: when the ratio of the produced fluid volume of a single oil well to the produced fluid volume of the well group is greater than or equal to a threshold value, and other oil wells are also affected to varying degrees, the particle dispersion suspension system is selected; When the ratio of the produced fluid volume of a single oil well to the produced fluid volume of a well group is greater than or equal to a threshold value, and there are oil wells that should be affected but are not, the gel-like fluidity mutation system is selected. In step 4, the injection process of the chemical viscosity reducer system and the crossflow control system is determined according to the type of the crossflow control system in step 3; When the crossflow control system is the particle dispersion suspension system, the chemical viscosity reducer system is mixed with the crossflow control system and then injected simultaneously; When the cross-flow control system is the jelly gel fluidity mutation system, the cross-flow control system is first injected, and then the chemical viscosity reducer system is injected after the fluidity mutation occurs. The method for chemical composite flooding cold recovery of oil in a heavy oil reservoir after steam thermal recovery also includes: Step 1: determining a heavy oil reservoir for chemical composite flooding cold recovery of oil, wherein the heavy oil reservoir for chemical composite flooding cold recovery is determined based on the geological characteristics of the heavy oil reservoir, the perfection of the well network, the oil-gas ratio of steam huff-and-puff thermal recovery, and the degree of steam cross-flow.

2. The method according to claim 1, characterized in that The geological characteristics and well network perfection of the heavy oil reservoir are determined by geological modeling, reservoir numerical simulation and dynamic reservoir history fitting; the oil-gas ratio and steam channeling degree of steam huff-and-puff thermal recovery are determined by production dynamic data.

3. The method according to claim 2, characterized in that Heavy oil reservoirs with complete well network, geological connectivity between wells, oil-gas ratio of the latest round of steam stimulation thermal recovery lower than 0.4, and steam channeling in at least three wells in the injection-production well group are identified as heavy oil reservoirs for chemical composite flooding cold recovery.

4. The method according to claim 1, wherein In step 2, the chemical viscosity reducer system includes a water-soluble viscosity reducer; and / or the chemical viscosity reducer system is a compound viscosity reducer including a water-soluble viscosity reducer and an oil-soluble viscosity reducer; and / or in addition to the viscosity reducer, the chemical viscosity reducer system also includes formation injection water.

5. The method according to claim 4, characterized in that The water-soluble viscosity reducer is a water-soluble surfactant, and / or the interfacial tension between the chemical viscosity reducer system and the target heavy oil is less than 10 -1 mN / m, and / or the average particle size of the emulsified oil droplets formed by the chemical viscosity reducer and the target heavy oil is less than 1 / 3 of the average throat diameter of the formation; the oil-soluble viscosity reducer is a polymer of unsaturated acid lipids.

6. The method according to claim 5, characterized in that The water-soluble viscosity reducer is selected from at least one of alkyl sulfonates, alkyl carboxylates, betaine, arachidonic acid lipids, and polyoxyethylene ethers; the oil-soluble viscosity reducer is capable of reducing the internal phase viscosity of the emulsion formed by the chemical viscosity reducer system and the target heavy oil to below 100 mPa·s.

7. The method according to any one of claims 1 to 6, characterized in that In the second step, the chemical viscosity reducer system is subjected to on-site test injection, and the balanced injection pressure is used to characterize the injectivity of the formation. When the balanced injection pressure during the test injection process is not higher than 10 MPa, it indicates that the injectivity of the formation is good. The well is selected as the injection well, and the adjacent well is selected as the production well to construct an injection-production well network.

8. The method according to claim 7, characterized in that When the balanced injection pressure during the test injection process is no higher than 5 MPa, it indicates that the formation has good injectivity. The well is selected as the injection well, and the adjacent well is selected as the production well to construct an injection-production well network.

9. The method according to any one of claims 1 to 6, characterized in that In step three, the threshold is 50%.

10. The method according to any one of claims 1 to 6, characterized in that In the step three, The particle-type dispersion suspension system is a suspension system formed by polymer microspheres, jelly dispersions, pre-crosslinked particles or bulk-swelled particles and water; and / or the particle size of the particle-type dispersion suspension system is less than 1 / 5 of the average pore diameter of the formation, and expands more than 2 times or aggregates into large particles under the conditions of formation temperature and salinity.

11. The method according to claim 10, wherein The particle size of the particle dispersion suspension system ranges from 0.1 μm to 1 mm.

12. The method according to any one of claims 1 to 6, characterized in that The jelly gel fluidity mutation system is a composite system solution of a polymer and a cross-linking agent, which forms a semi-solid after aging for 10-48 hours under formation conditions, and has stable physical and chemical properties for 360 days after the fluidity mutation.

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