Edge-bottom water heavy oil reservoir multi-agent combined development method

Abstract

The invention discloses a multi-agent combined development method for an edge-bottom water heavy oil reservoir. The multi-agent combined development method comprises the following steps: (1) evaluating and screening the suitability of chemical agents and an oil reservoir; (2) injecting a water plugging section plug; (3) a plug removal section plug is injected; (4) injecting into the stratum to adsorb the subsidy slug; (5) injecting a viscosity-reducing main slug; (6) soaking the oil well; and (7) opening the oil well for production. According to the method, the polymer, the oil-soluble viscosity reducer and the hydrosolvent viscosity reducer are comprehensively used, four injection slugs of water plugging, plug removal, patching and viscosity reduction are designed, and the three problems that in edge-bottom water heavy oil reservoir exploitation, edge-bottom water invades, the position near the bottom of the heavy oil well is prone to being blocked, and the exploitation economic benefits are poor are solved; according to the invention, the polymer is utilized to solve the problem of small huff-puff wave and range of a single viscosity reducer for thick oil, the oil-soluble viscosity reducer is utilized to solve the problem of blockage near the well bottom, and the water-soluble viscosity reducer slugs with different concentrations are utilized to solve the problem of high viscosity of crude oil and improve the development economic benefit.

Description

Technical Field

[0001] The present invention belongs to the technical field of oilfield development, and particularly relates to a multi-agent combined development method for edge-bottom water heavy oil reservoirs. Background Art

[0002] Heavy oil resources are an important strategic replacement resource. It is predicted that about 70% of the remaining world oil resources are heavy oil. How to economically and effectively exploit this part of resources is of great significance. Due to the high viscosity and poor fluidity of heavy oil, the development effect or economic benefit of conventional exploitation methods is poor.

[0003] At present, the main heavy oil exploitation methods are thermal oil recovery technology by steam injection and water flooding development technology by conventional water injection.

[0004] Chinese Patent CN 104747155 B discloses a steam development method for heavy oil reservoirs, including the following steps: fracturing the oil layer of the heavy oil reservoir; conducting steam development on the fractured oil layer of the heavy oil reservoir, and the steam development includes steam huff and puff and steam flooding; after the steam development reaches a predetermined time, fracturing the oil layer of the heavy oil reservoir for the second time. Although the fracturing and thermal oil recovery technologies of steam huff and puff or steam flooding are mature, both fracturing and thermal recovery are not suitable for edge-bottom water heavy oil reservoirs, and edge water or bottom water is likely to advance rapidly during development, ultimately causing oil well water flooding. Therefore, the above patent technology is limited in edge-bottom water heavy oil reservoirs.

[0005] Chinese Patent CN 107605444 B discloses a polymer flooding method for heavy oil reservoirs, including selecting an injection-production well pattern with a central well as a horizontal well and corner wells as vertical wells in the target heavy oil reservoir, using the horizontal well as the injection well and the vertical well as the production well; injecting an emulsifying viscosity reducer solution into the horizontal well; after injecting the emulsifying viscosity reducer solution, continuously injecting polymer solutions with gradually increasing concentrations into the horizontal well to form a preflush protection slug, a main slug, and a postflush protection slug in sequence; after injecting the postflush protection slug, continue to inject a displacement fluid; while injecting the emulsifying viscosity reducer solution and polymer solution into the horizontal well, collecting the heavy oil produced from the vertical well. However, the above technical solution still has the following deficiencies: the displacement method requires a complete injection-production well pattern, and the displacement is less adaptable to blocks significantly affected by edge-bottom water. At the same time, the above patent does not consider the influence of asphaltene plugging near the production well on production.

[0006] In summary, the method of improving crude oil viscosity by injecting chemical agents has attracted the attention of major oil companies, and it is gradually forming a new heavy oil exploitation technology. The development effect of heavy oil exploitation by chemical methods is usually affected by various factors such as formation conditions, crude oil properties and components, the action principle of chemical agents, and the price of chemical agents. Currently, this technology is in the experimental stage. Summary of the Invention

[0007] Object of the Invention: Aiming at the deficiencies of the above-mentioned existing technologies, the present invention provides a multi-agent combined development method for edge-bottom water heavy oil reservoirs, which can solve the problems of formation edge-bottom water invasion existing in the exploitation of edge-bottom water heavy oil reservoirs by thermal recovery technology, the high requirements for well patterns in polymer flooding development, and the blockage at the production end, resulting in poor development effects. The present invention integrates the characteristics of three different chemical agents and can provide important practical significance for the development of edge-bottom water heavy oil reservoirs.

[0008] A multi-agent combined development method for edge-bottom water heavy oil reservoirs fully considers the geological characteristics of the reservoir, utilizes the action principles and characteristics of different chemical agents, and at the same time considers the price factors of different viscosity reducers. It integrates the characteristics of three agents, namely polymer, oil-soluble viscosity reducer, and water-soluble viscosity reducer, and designs four injection slugs. It is an economical and effective development method for edge-bottom water heavy oil. Practice has shown that this development method not only plays a role in increasing production but also increases development benefits and has good application and promotion prospects.

[0009] The present invention first screens out suitable chemical agents (i.e., polymer, oil-soluble viscosity reducer, and water-soluble viscosity reducer), and then injects the three chemical agents into the production wells of the edge-bottom water heavy oil reservoir in four slugs in sequence, namely: the first slug is a water shutoff slug, the second slug is a plugging removal slug, the third slug is a formation adsorption subsidy slug, and the fourth slug is a main viscosity reduction slug. Then, after soaking the well for a period of time, the well is opened for production, where:

[0010] The water shutoff slug is an aqueous polymer solution;

[0011] The plugging removal slug is an oil-soluble viscosity reducer;

[0012] The formation adsorption subsidy slug is an aqueous solution of a high-concentration water-soluble viscosity reducer;

[0013] The main viscosity reduction slug is an aqueous solution of a low-concentration water-soluble viscosity reducer.

[0014] Technical Solution: A multi-agent combined development method for edge-bottom water heavy oil reservoirs includes the following steps:

[0015] (1) Evaluation and screening of the compatibility between chemical agents and the reservoir, where:

[0016] The chemical agents include polymer, oil-soluble viscosity reducer, and water-soluble viscosity reducer;

[0017] (2) Injecting the water shutoff slug;

[0018] (3) Injecting the plugging removal slug;

[0019] (4) Injecting the formation adsorption subsidy slug;

[0020] (5) Injecting the main viscosity reduction slug;

[0021] (6)Soaking the oil well

[0022] (7)Putting the oil well into production

[0023] Furthermore, the specific steps of step (1) are as follows:

[0024] (11)Obtaining oil samples and water samples from the oil wells to be comprehensively exploited for viscosity reduction

[0025] (12)Evaluating and screening the compatibility of polymers, oil-soluble viscosity reducers and water-soluble viscosity reducers by using the obtained oil samples and water samples

[0026] Furthermore, the requirements for the polymer in step (12) are: the viscosity of the polymer aqueous solution with a concentration of 3000 mg / L is greater than 150 mPa·s, where:

[0027] The solvent of the polymer aqueous solution uses the water sample obtained in step (11).

[0028] Furthermore, the requirements for the oil-soluble viscosity reducer in step (12) are: when the oil-soluble viscosity reducer is mixed with the oil sample described in step (11) according to a mass ratio of 1:9, its viscosity reduction rate is above 85%.

[0029] Furthermore, the requirements for the water-soluble viscosity reducer in step (12) are:

[0030] a. It has the function of forming an oil-in-water emulsion;

[0031] b. After the oil sample in step (11) is mixed with the water-soluble viscosity reducer solution according to a mass ratio of 7:3, its viscosity reduction rate is above 90%, where:

[0032] The water-soluble viscosity reducer solution is a 0.3% mass fraction water-soluble viscosity reducer solution prepared by using the water sample obtained in step (11).

[0033] Furthermore, the water plugging slug in step (2) is the aqueous solution of the polymer screened in step (1), with an injection concentration of 3000 - 7000 mg / L and an injection volume of 200 - 600 t. The aqueous solution of the polymer is used to block the water channel, ensuring that the subsequent injected viscosity reducer can contact the crude oil to the greatest extent.

[0034] Furthermore, the plug removal slug in step (3) is the oil-soluble viscosity reducer screened in step (1), with an injection volume of 20 - 50 t. The oil-soluble viscosity reducer is used to solve the blockage caused by the precipitation of gum and asphaltene in the viscous oil within a range of 3 - 5 meters near the wellbore.

[0035] Further, the formation adsorption subsidy slug in step (4) is an aqueous solution of the water-soluble viscosity reducer screened in step (1) with a high concentration. Its injection concentration is 7-10%, and the injection volume is 100-200 t. The formation adsorption subsidy slug is placed before the main viscosity reduction slug to pre-subsidize the formation's adsorption of the water-soluble viscosity reduction slug.

[0036] Further, the main viscosity reduction slug in step (5) is an aqueous solution of the water-soluble viscosity reducer screened in step (1) with a low concentration. Its injection concentration is 0.3-1%, and the injection volume is 500-2000 t. The main viscosity reduction slug is used to reduce the viscosity of crude oil and improve its fluidity.

[0037] Further, the shut-in time of the oil well in step (6) is 3-5 days.

[0038] Further, after the injection of the water shut-off slug in step (2) is completed, 5-15 t of water is injected and then step (3) is entered.

[0039] Further, after the injection of the main viscosity reduction slug in step (5) is completed, 10-30 t of water is injected and then step (6) is entered.

[0040] The present invention includes 4 slugs, and the injection sequence is polymer solution, oil-soluble viscosity reducer, high-concentration water-soluble viscosity reducer solution, and low-concentration water-soluble viscosity reducer solution. The 4 slugs respectively play the roles of water shut-off, plugging removal, subsidizing the adsorption loss of the formation to the water-soluble viscosity reducer, and reducing the viscosity of heavy oil.

[0041] Compared with the prior art, the present invention has the following beneficial effects:

[0042] 1. The present invention uses polymers to solve the problem of small sweep range of single viscosity reducer huff and puff for heavy oil, uses oil-soluble viscosity reducers to solve the problem of blockage near the bottom of the well, and uses water-soluble viscosity reducer slugs with different high and low concentrations to solve the problem of high viscosity of crude oil while improving the development economic benefits, and finally improves the development effect of edge-bottom water heavy oil reservoirs.

[0043] 2. Field practice has proved that the method of the present invention can greatly increase the oil production and significantly improve the economic benefits. Description of the Drawings

[0044] Figure 1 It is a flow chart of a multi-agent combined development method for edge-bottom water heavy oil reservoirs disclosed by the present invention.

[0045] Figure 2 It is a comparison chart of the effects after the implementation of a multi-agent combined development method for edge-bottom water heavy oil reservoirs disclosed by the present invention in Well P35.

[0046] Figure 3This is a comparison chart of the effects after implementing a multi-agent joint development method for edge-bottom water heavy oil reservoirs disclosed by the present invention in Well Z18. Specific implementation manner:

[0047] The following details the specific implementation manner of the present invention.

[0048] It should be noted that the following detailed description is exemplary and is intended to provide further illustration of the present invention. Unless otherwise specified, all technical and scientific terms used herein have the same meaning as commonly understood by those skilled in the art.

[0049] It should be noted that the terms used herein are only for describing the specific implementation manner and are not intended to limit the exemplary embodiments according to the present invention. As used herein, unless the context clearly indicates otherwise, the singular form is also intended to include the plural form. In addition, 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.

[0050] In this application, the viscosity is measured by the rotation method in the viscosity measurement method of GB-T 10247-2008.

[0051] In this application: The chemical agents in step (1) include polymers, oil-soluble viscosity reducers, and water-soluble viscosity reducers, where:

[0052] The polymer is partially hydrolyzed polyacrylamide with a molecular weight of 10 million - 30 million.

[0053] The oil-soluble viscosity reducer is at least one of condensates of naphthalene, long-chain fatty acid esters, polymerized alkyl-substituted phenolic resins, and maleic anhydride-styrene-octadecyl acrylate terpolymers.

[0054] The water-soluble viscosity reducer is at least one of anionic surfactants, non-ionic surfactants, betaine surfactants, and anionic-non-ionic surfactants.

[0055] In order to enable those skilled in the art to more clearly understand the technical solution of the present invention, the following will detail the technical solution of the present invention with specific embodiments.

[0056] Example 1

[0057] In Well P35 in Block T of Shengli Oilfield, the crude oil viscosity is 6250 mPa·s. It is a high-porosity, high-permeability heavy oil reservoir with serious reservoir heterogeneity and obvious water channeling. At the same time, the near-wellbore zone is significantly blocked, and the daily liquid production of a single well is less than 4 t / d during the normal production period. Before using the present invention, the oil well had no production benefit and was in a shut-in state.

[0058] In late August 2020, a multi-agent combined development method for edge-bottom water heavy oil reservoirs disclosed by the present invention was used to improve the development effect. The example process is as follows:

[0059] (1) Evaluation and screening of the compatibility between chemical agents and the reservoir

[0060] (11) Extract oil samples and water samples from Well P35;

[0061] (12) According to the requirements of the present invention, three polymers are selected, namely:

[0062] Polymer A1: Partially hydrolyzed polyacrylamide, with a molecular weight of 18 million;

[0063] Polymer A2: Partially hydrolyzed polyacrylamide, with a molecular weight of 11 million;

[0064] Polymer A3: Partially hydrolyzed polyacrylamide, with a molecular weight of 30 million;

[0065] Then, solutions with a concentration of 3000 mg / L of Polymer A1, Polymer A2, and Polymer A3 are prepared respectively using the water sample, and their viscosities are measured respectively. The measured viscosities are as follows:

[0066] Viscosity (mPa.s) Polymer A1 162 Polymer A2 142 Polymer A3 147

[0067] Therefore, the viscosity of Polymer A1 is the largest, which is 162 mPa·s and meets the screening requirements of the present invention. Therefore, Polymer A1 is selected as the agent for the water plugging slug;

[0068] (13) Select three oil-soluble viscosity reducers, namely oil-soluble viscosity reducer A1, oil-soluble viscosity reducer A2, and oil-soluble viscosity reducer A3, and their components are as follows:

[0069] Component Oil-soluble viscosity reducer A1 Condensation product of chlorinated paraffin and naphthalene Oil-soluble viscosity reducer A2 Oleate Oil-soluble viscosity reducer A3 Maleic anhydride-styrene-octadecyl acrylate terpolymer

[0070] Using the oil sample, the viscosity reduction rates of the three oil-soluble viscosity reducers A1, A2, and A3 are measured respectively according to the mass ratio of oil-soluble viscosity reducer / oil of 1:9. The specific results are as follows:

[0071] Viscosity reduction rate Oil-soluble viscosity reducer A1 81％ Oil-soluble viscosity reducer A2 85％ Oil-soluble viscosity reducer A3 88％

[0072] The viscosity reduction rate of oil-soluble viscosity reducer A3 is the highest, which is 88%, and meets the screening standard. Oil-soluble viscosity reducer A3 is selected as the agent for the current plug removal slug;

[0073] In addition, if the viscosity reduction rates of the three oil-soluble viscosity reducers selected in step (13) do not meet the requirements, other oil-soluble viscosity reducers need to be re-screened until a suitable oil-soluble viscosity reducer is selected;

[0074] (14) Three water-soluble viscosity reducers were selected, namely water-soluble viscosity reducer A1, water-soluble viscosity reducer A2, and water-soluble viscosity reducer A3, and their components are as follows:

[0075]

[0076] Using oil samples and water samples, when the mass ratio of oil to the water-soluble viscosity reducer solution (an aqueous solution of the water-soluble viscosity reducer with a mass fraction of 0.3%) is 7:3, the viscosity reduction rates of water-soluble viscosity reducer A1, water-soluble viscosity reducer A2, and water-soluble viscosity reducer A3 were measured respectively, and the results are as follows:

[0077] Viscosity reduction rate Water-soluble viscosity reducer A1 90％ Water-soluble viscosity reducer A2 98％ Water-soluble viscosity reducer A3 88％

[0078] The viscosity reduction rate of water-soluble viscosity reducer A2 is the highest, reaching 98%, and it meets the screening criteria. Therefore, water-soluble viscosity reducer A2 was selected as the viscosity reducer for this time.

[0079] If the viscosity reduction rates of the three water-soluble viscosity reducers selected in step (14) do not meet the requirements, other water-soluble viscosity reducers need to be re-screened until a suitable water-soluble viscosity reducer is selected;

[0080] (2) Inject the water shutoff slug

[0081] Inject an aqueous solution of 200 t of polymer A1 with a concentration of 7000 mg / L into Well P35;

[0082] (3) Inject the plug removal slug

[0083] Inject 10 t of clear water into the wellbore to completely push the polymer solution into the formation, and then inject 40 t of oil-soluble viscosity reducer A3 into Well P35;

[0084] (4) Inject the formation adsorption subsidy slug

[0085] Inject 100 t of an aqueous solution of water-soluble viscosity reducer A2 with a mass concentration of 10% into the wellbore;

[0086] (5) Inject the main viscosity reduction slug

[0087] Inject 800 t of an aqueous solution of water-soluble viscosity reducer A2 with a mass concentration of 0.8% into the wellbore;

[0088] (6) Shut in the oil well;

[0089] Inject 20 t of clear water into the wellbore to completely push the injected fluid in the wellbore into the formation, and then close the oil well for 3 days.

[0090] (7) Open the oil well for production.

[0091] Using the method of the present invention, a total of 778,000 yuan was invested in four different slugs. The daily oil production can be increased from 0 t / d before using this method to a maximum of 4.7 t / d. The cumulative increase in crude oil production is 1,643 t. Calculated at an oil price of 40 US dollars per barrel, the increased revenue is 3.083 million yuan, and the profit is 2.305 million yuan. The economic benefits are remarkable. For specific production effects, see Figure 2 。

[0092] Example 2

[0093] Well Z18 in Block Z of Shengli Oilfield has a crude oil viscosity of 8,185 mPa·s and is a high-porosity, high-permeability heavy oil reservoir with severe reservoir heterogeneity and obvious water channeling. Before using the present invention, the daily oil production of the well was 1.2 t / d and the water cut was 90.5%.

[0094] In late September 2020, a multi-agent combined development method for edge-bottom water heavy oil reservoirs disclosed by the present invention was used to improve the development effect. The example process is as follows:

[0095] (1) Evaluation and screening of the compatibility between chemical agents and the reservoir

[0096] (11) Extract oil samples and water samples from Well Z18.

[0097] (12) According to the requirements of the present invention, three polymers are selected, namely:

[0098] Polymer B1: Partially hydrolyzed polyacrylamide with a molecular weight of 21 million;

[0099] Polymer B2: Partially hydrolyzed polyacrylamide with a molecular weight of 10 million;

[0100] Polymer B3: Partially hydrolyzed polyacrylamide with a molecular weight of 28 million;

[0101] Then, solutions with a concentration of 3000 mg / L of Polymer B1, Polymer B2, and Polymer B3 are prepared using the water sample respectively, and their viscosities are measured. The measured viscosities are as follows:

[0102] Viscosity (mPa.s) Polymer B1 213 Polymer B2 140 Polymer B3 136

[0103] Therefore, the viscosity of Polymer B1 is the largest, which is 213 mPa·s and meets the screening requirements of the present invention. Therefore, Polymer B1 is selected as the agent for the water plugging slug;

[0104] (13) Select three oil-soluble viscosity reducers, namely oil-soluble viscosity reducer B1, oil-soluble viscosity reducer B2, and oil-soluble viscosity reducer B3, and their components are as follows:

[0105] Component Oil-soluble viscosity reducer B1 Maleic anhydride-styrene-octadecyl acrylate terpolymer Oil-soluble viscosity reducer B2 Polymerized alkyl-substituted phenolic resin Oil-soluble viscosity reducer B3 Compound of naphthalene condensate and long-chain fatty acid ester

[0106] Using the oil sample, measure the viscosity reduction rates of three oil-soluble viscosity reducers, namely oil-soluble viscosity reducer B1, oil-soluble viscosity reducer B2, and oil-soluble viscosity reducer B3, respectively, at an oil-soluble viscosity reducer / oil mass ratio of 1:9. The specific results are as follows:

[0107] Viscosity reduction rate Oil-soluble viscosity reducer B1 80％ Oil-soluble viscosity reducer B2 75％ Oil-soluble viscosity reducer B3 91％

[0108] The viscosity reduction rate of oil-soluble viscosity reducer B3 is the highest, at 88%, and it meets the screening criteria. Select oil-soluble viscosity reducer B3 as the agent for this plugging removal slug;

[0109] In addition, if the viscosity reduction rates of the three oil-soluble viscosity reducers selected in step (13) do not meet the requirements, other oil-soluble viscosity reducers need to be re-screened until a suitable oil-soluble viscosity reducer is selected;

[0110] (14) Select three water-soluble viscosity reducers, namely water-soluble viscosity reducer B1, water-soluble viscosity reducer B2, and water-soluble viscosity reducer B3, and their components are as follows:

[0111]

[0112]

[0113] Using the oil sample and water sample, when the mass ratio of oil to the water-soluble viscosity reducer solution (an aqueous solution of water-soluble viscosity reducer with a mass fraction of 0.3%) is 7:3, measure the viscosity reduction rates of water-soluble viscosity reducer B1, water-soluble viscosity reducer B2, and water-soluble viscosity reducer B3, respectively. The results are as follows:

[0114] Viscosity reduction rate Water-soluble viscosity reducer B1 97％ Water-soluble viscosity reducer B2 86％ Water-soluble viscosity reducer B3 90％

[0115] The viscosity reduction rate of water-soluble viscosity reducer B1 is the highest, at 97%, and it meets the screening criteria. Therefore, select water-soluble viscosity reducer B1 as the agent for this viscosity reduction;

[0116] If the viscosity reduction rates of the three water-soluble viscosity reducers selected in step (14) do not meet the requirements, other water-soluble viscosity reducers need to be re-screened until a suitable water-soluble viscosity reducer is selected;

[0117] (2) Inject the water shutoff slug

[0118] Inject 300 t of an aqueous solution of polymer B1 with a concentration of 5000 mg / L into Well Z18;

[0119] (3) Inject the plugging removal slug

[0120] Inject 5 t of clear water into the wellbore to completely push the polymer solution into the formation, and then inject 20 t of oil-soluble viscosity reducer B3 into Well Z18;

[0121] (4) Inject the formation adsorption subsidy slug

[0122] Inject 200 t of an aqueous solution of water-soluble viscosity reducer B1 with a mass concentration of 7% into the wellbore;

[0123] (5) Inject the main viscosity reduction slug

[0124] Inject 500 t of an aqueous solution of water-soluble viscosity reducer B1 with a mass concentration of 1% into the wellbore;

[0125] (6) Shut in the oil well

[0126] Inject 10 t of clear water into the wellbore to completely displace the above-mentioned injected fluid in the wellbore into the formation, and then shut in the oil well for 5 days.

[0127] (7) Open the oil well for production.

[0128] Using the method of the present invention, a total of 466,000 yuan is invested in four different slugs. The daily oil production can be increased from 1.2 t / d before using this method to a maximum of 6.7 t / d, and the cumulative increase in crude oil production is 648 t. Calculated at an oil price of 40 US dollars / barrel, the increased income is 1.216 million yuan, and a profit of 750,000 yuan is achieved. The economic benefits are remarkable. For specific production effects, see Figure 3 .

[0129] Example 3

[0130] Well P46 in Block Q of Shengli Oilfield has a crude oil viscosity of 5510 mPa·s and is a high-porosity, high-permeability heavy oil reservoir. The reservoir has severe heterogeneity and obvious water channeling. At the same time, the near-wellbore area is significantly blocked, and the normal daily liquid production of a single well is less than 3 t / d. Before using the present invention, the oil well had no production benefit and was in a shut-in state.

[0131] In late September 2020, a multi-agent combined development method for edge-bottom water heavy oil reservoirs disclosed by the present invention was used to improve the development effect. The example process is as follows:

[0132] (1) Evaluation and screening of the compatibility between chemical agents and the reservoir

[0133] (11) Extract oil samples and water samples from Well P46;

[0134] (12) According to the requirements of the present invention, select three polymers, namely:

[0135] Polymer C1: Partially hydrolyzed polyacrylamide with a molecular weight of 16 million;

[0136] Polymer C2: Partially hydrolyzed polyacrylamide with a molecular weight of 12 million;

[0137] Polymer C3: Partially hydrolyzed polyacrylamide with a molecular weight of 28 million;

[0138] Then, solutions with a concentration of 3000 mg / L of polymer C1, polymer C2, and polymer C3 were prepared using water samples respectively, and their viscosities were measured. The measured viscosities are as follows:

[0139] Viscosity (mPa.s) Polymer C1 168 Polymer C2 145 Polymer C3 150

[0140] Therefore, the viscosity of polymer C1 is the highest, which is 168 mPa·s and meets the screening requirements of the present invention. Therefore, polymer C1 is selected as the agent for the water plugging slug;

[0141] (13) Three oil-soluble viscosity reducers, namely oil-soluble viscosity reducer C1, oil-soluble viscosity reducer C2, and oil-soluble viscosity reducer C3, were selected, and their components are as follows:

[0142] Component Oil-soluble viscosity reducer C1 Linoleate Oil-soluble viscosity reducer C2 Polymerized alkyl-substituted phenolic resin Oil-soluble viscosity reducer C3 Maleic anhydride-styrene-octadecyl acrylate terpolymer

[0143] Using oil samples, the viscosity reduction rates of the three oil-soluble viscosity reducers C1, C2, and C3 were measured respectively according to the mass ratio of oil-soluble viscosity reducer to oil of 1:9. The specific results are as follows:

[0144] Viscosity reduction rate Oil-soluble viscosity reducer C1 80％ Oil-soluble viscosity reducer C2 83％ Oil-soluble viscosity reducer C3 88％

[0145] The viscosity reduction rate of oil-soluble viscosity reducer C3 is the highest, which is 88%, and meets the screening criteria. Oil-soluble viscosity reducer C3 is selected as the agent for the current plugging removal slug;

[0146] In addition, if the viscosity reduction rates of the three oil-soluble viscosity reducers selected in step (13) do not meet the requirements, other oil-soluble viscosity reducers need to be re-screened until suitable oil-soluble viscosity reducers are selected;

[0147] (14) Three water-soluble viscosity reducers, namely water-soluble viscosity reducer C1, water-soluble viscosity reducer C2, and water-soluble viscosity reducer C3, were selected, and their components are as follows:

[0148] Component Water-soluble viscosity reducer C1 Anionic-nonionic surfactant Water-soluble viscosity reducer C2 Anionic surfactant Water-soluble viscosity reducer C3 Betaine surfactant

[0149] Using oil samples and water samples, when the mass ratio of oil to the water-soluble viscosity reducer solution (an aqueous solution of water-soluble viscosity reducer with a mass fraction of 0.3%) is 7:3, the viscosity reduction rates of water-soluble viscosity reducers C1, C2, and C3 were measured respectively. The results are as follows:

[0150] Viscosity reduction rate Water-soluble viscosity reducer C1 85％ Water-soluble viscosity reducer C2 96％ Water-soluble viscosity reducer C3 87％

[0151] The viscosity reduction rate of water-soluble viscosity reducer C2 is the highest, which is 96%, and meets the screening criteria. Therefore, water-soluble viscosity reducer C2 is selected as the agent for the current viscosity reduction.

[0152] If the viscosity reduction rates of the three water-soluble viscosity reducers selected in step (14) do not meet the requirements, other water-soluble viscosity reducers need to be re-screened until a suitable water-soluble viscosity reducer is selected;

[0153] (2) Inject a water shutoff slug

[0154] Inject an aqueous solution of polymer C1 with a concentration of 3000 mg / L and a volume of 600 t into Well P46;

[0155] (3) Inject a plug removal slug

[0156] Inject 15 t of fresh water into the wellbore to completely push the polymer solution into the formation, and then inject 50 t of oil-soluble viscosity reducer C3 into Well P46;

[0157] (4) Inject a formation adsorption subsidy slug

[0158] Inject an aqueous solution of water-soluble viscosity reducer C2 with a mass concentration of 8% and a volume of 150 t into the wellbore;

[0159] (5) Inject a main viscosity reduction slug

[0160] Inject an aqueous solution of water-soluble viscosity reducer C2 with a mass concentration of 0.3% and a volume of 2000 t into the wellbore;

[0161] (6) Soak the oil well

[0162] Inject 30 t of fresh water into the wellbore to completely push the injection fluid in the wellbore into the formation, and then close the oil well for 4 days.

[0163] (7) Open the oil well for production.

[0164] Using the method of the present invention, a total of 695,000 yuan is invested in four different slugs. The daily oil production can be increased from 0 t / d before using this method to a maximum of 5 t / d, and the cumulative increase in crude oil production is 1645 t. Calculated at an oil price of 40 US dollars / barrel, the increased income is 3.376 million yuan, and the profit is 2.681 million yuan, showing remarkable economic benefits.

[0165] The above embodiments are preferred embodiments of the present invention, but the embodiments of the present invention are not limited to the above embodiments. Any other changes, modifications, substitutions, combinations, and simplifications made without departing from the spirit and principle of the present invention shall be equivalent replacement methods and are all included in the protection scope of the present invention.

Claims

1. A multi-agent joint development method for edge and bottom water heavy oil reservoirs, characterized in that: The following steps are involved: (1) Evaluation and screening of chemical agent and reservoir compatibility, including: The chemical agent includes a polymer, an oil-soluble viscosity reducer and a water-soluble viscosity reducer; (2) Injecting water plugging slug; (3) Injection to remove the plug; (4) Injection of adsorption into the formation to compensate for the plug; (5) Injection of viscosity-reducing main slug; (6) Oil well stewing; (7) Oil well opening and production.

2. A multi-agent joint development method for edge and bottom water heavy oil reservoirs as claimed in claim 1, characterized in that: The specific steps of step (1) are as follows: (11) Obtaining oil and water samples from oil wells that are scheduled to undergo comprehensive viscosity reduction recovery; (12) Use the obtained oil and water samples to evaluate and screen the compatibility of polymers, oil-soluble viscosity reducers, and water-soluble viscosity reducers.

3. A multi-agent joint development method for edge and bottom water heavy oil reservoirs as claimed in claim 2, characterized in that: The requirement for the polymer in step (12) is that the viscosity of the polymer aqueous solution with a concentration of 3000 mg / L is greater than 150 mPa.s, wherein: The solvent of the polymer aqueous solution is the water sample obtained in step (11).

4. A multi-agent joint development method for edge and bottom water heavy oil reservoirs as claimed in claim 2, characterized in that: The requirement for the oil-soluble viscosity reducer in step (12) is that when the oil-soluble viscosity reducer is mixed with the oil sample in step (11) at a mass ratio of 1:9, the viscosity reduction rate is above 85%.

5. The multi-agent joint development method for edge and bottom water heavy oil reservoirs according to claim 2, characterized in that: The requirements for the water-soluble viscosity reducing agent in step (12) are: a. It has the function of forming oil-in-water emulsion; b. After the oil sample in step (11) is mixed with the water-soluble viscosity reducer solution in a mass ratio of 7:3, the viscosity reduction rate is above 90%, wherein: The water-soluble viscosity reducer solution is a water-soluble viscosity reducer solution with a mass fraction of 0.3% prepared using the water sample obtained in step (11).

6. The multi-agent joint development method for edge and bottom water heavy oil reservoirs according to claim 1, characterized in that: The water plugging section in step (2) is an aqueous solution of the polymer screened out in step (1), with an injection concentration of 3000-7000 mg / L and an injection volume of 200-600 t.

7. The multi-agent joint development method for edge and bottom water heavy oil reservoirs according to claim 1, characterized in that: The unblocking plug in step (3) is the oil-soluble viscosity reducer screened out in step (1), and its injection amount is 20-50t.

8. The multi-agent joint development method for edge-bottom water heavy oil reservoirs according to claim 1, characterized in that: The formation adsorption supplement plug in step (4) is a high-concentration aqueous solution of the water-soluble viscosity reducer screened out in step (1), with an injection concentration of 7-10% and an injection volume of 100-200t.

9. The multi-agent joint development method for edge and bottom water heavy oil reservoirs according to claim 1, characterized in that: The viscosity reducing main plug in step (5) is a low-concentration aqueous solution of the water-soluble viscosity reducing agent screened out in step (1), with an injection concentration of 0.3-1% and an injection volume of 500-2000t.

10. The multi-agent joint development method for edge and bottom water heavy oil reservoirs according to claim 1, characterized in that: In step (6), the oil well is kept warm for 3-5 days.

11. The multi-agent joint development method for edge and bottom water heavy oil reservoirs according to claim 1, characterized in that: After the water plugging is injected in step (2), 5-15 t of water is then injected before entering step (3).

12. The multi-agent joint development method for edge and bottom water heavy oil reservoirs according to claim 1, characterized in that: After the injection of the viscosity reducing main plug is completed in step (5), 10-30t of water is injected and then step (6) is entered.

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