Method for plugging multi-scale fractures in fractured reservoir

Abstract

The invention relates to a plugging method for multi-scale cracks in a fractured reservoir, and belongs to the technical field of profile control and water plugging. According to the plugging method for the multi-scale cracks in the fractured reservoir, a multi-round plugging process is adopted, the plugging agent is injected into the high-dip-angle large-scale cracks, the sodium bentonite, the calcium bentonite and the silica fume in the plugging agent can play a synergistic plugging role, step-by-step effective plugging of the high-dip-angle large-scale cracks is achieved, and the plugging effect of the high-dip-angle large-scale cracks is improved. Secondary fractures are effectively displaced step by step, so that the purposes of enlarging the water injection swept volume and improving the water injection development effect are achieved.

Description

Technical Field

[0001] The present invention relates to a method for plugging multi-scale fractures in a fractured reservoir, belonging to the technical field of profile control and water shutoff. Background Art

[0002] As an important technical measure to expand the swept volume of injected water and improve the water flooding development effect, the profile control technology has been successfully applied in high water cut oilfields at home and abroad. However, for tight fractured reservoirs, due to the relatively large fracture scale in some well groups, the cumulative injection volume is small during water channeling, which belongs to a large-scale fracture water channeling path. Previous on-site tests have shown that it is difficult to effectively plug large-scale fracture water channeling paths.

[0003] There are also many patent reports on the profile control methods for fractured tight oil reservoirs. For example, Chinese Patent Document CN105298438A discloses a multi-round polymer gel deep profile control method. However, this plugging method aims to fill the water injection preferential channels with gel plugging agents of different strengths, forcing the injected water to divert and flow through low-permeability layers for oil displacement. If the target block has high dip large-scale fractures (i.e., fractures with a fracture dip of 80-90°, a fracture length of 10-500 m, and a core fracture aperture of 0.5-1 mm obtained by geological interpretation), the above-mentioned fine profile control method cannot achieve effective plugging. Summary of the Invention

[0004] The purpose of the present invention is to provide a method for plugging multi-scale fractures in a fractured reservoir, which is used to solve the problem that effective plugging cannot be achieved when using gel plugging agents to plug high dip large-scale fractures in a fractured reservoir at present.

[0005] In order to achieve the above purpose, the technical solution adopted by the method for plugging multi-scale fractures in a fractured reservoir of the present invention is as follows:

[0006] A method for plugging multi-scale fractures in a fractured reservoir includes the following steps: during the water injection and oil production process of a target well group, when water channeling occurs in a target production well in the target well group, perform more than one round of plugging operations on the target production well. Each round of plugging operation includes the following steps: inject a plugging agent into the target production well to form a plugging slug, and then inject a displacement fluid to displace the plugging slug to a predetermined position, and shut in the well for waiting for setting; the target production well is a production well with a high dip large-scale fracture existing between it and an injection well.

[0007] The plugging agent used in each round of plugging operation independently includes an active substance and water; the active substance includes the following components in parts by mass: 4-6 parts of acrylamide monomer, 0.04-0.05 parts of initiator, 0.1-0.2 parts of crosslinked polymerization monomer, 0.2-0.3 parts of polymer, 0.1-0.2 parts of organic chromium crosslinking agent, and 1-2 parts of nano / micro particle reinforcing agent; the crosslinked polymerization monomer contains more than two ethylenically unsaturated carbon-carbon double bonds in its molecule; the nano / micro particle reinforcing agent includes sodium bentonite, calcium bentonite, and microsilica powder.

[0008] The plugging method for multi-scale fractures in a fractured reservoir of the present invention adopts a multi-round plugging process, injecting a plugging agent into high-dip large-scale fractures. The sodium bentonite, calcium bentonite, and microsilica powder in the plugging agent can play a synergistic plugging role, realizing the step-by-step effective plugging of high-dip large-scale fractures and the step-by-step effective displacement of secondary fractures, achieving the purpose of expanding the water injection swept volume and improving the water injection development effect.

[0009] It can be understood that the high-dip large-scale fractures refer to fractures with a fracture dip angle of 80-90°, a fracture length of 10-500 m, and a core fracture aperture of 0.5-1 mm.

[0010] In order to reduce costs, increase the reaction rate and plugging strength, preferably, the acrylamide monomer is acrylamide and / or methacrylamide.

[0011] In order to increase the reaction rate and shorten the plugging time, preferably, the initiator is a water-soluble azo initiator. For example, the initiator is azodicyanovaleric acid.

[0012] In order to increase the plugging strength, oil production, and stable production time, preferably, the crosslinked polymerization monomer is N,N'-methylenebisacrylamide.

[0013] In order to increase the plugging strength, oil production, and stable production time, preferably, the polymer is an anionic partially hydrolyzed polyacrylamide. In order to further increase the plugging strength, more preferably, the anionic partially hydrolyzed polyacrylamide has a molecular weight of 15 million - 18 million and a hydrolysis degree of 10-12%.

[0014] In order to reduce costs and improve the plugging effect, preferably, the particle size of the sodium bentonite is not less than 1000 mesh; the particle size of the calcium bentonite is not less than 1000 mesh; the particle size of the microsilica powder is not less than 1300 mesh.

[0015] To improve the construction time and storage stability of the plugging agent, preferably, the active substance further includes an inhibitor, and in the active substance, the mass fraction of the inhibitor is not more than 0.05 parts. For example, in the active substance, the mass fraction of the inhibitor is 0.04 - 0.05 parts. Preferably, the inhibitor is potassium ferrocyanide.

[0016] To ensure that the plugging agent has good pumpability and fluidity, and at the same time to ensure that the plugging agent has a high reaction rate and a short response time, preferably, the mass fraction of water in the plugging agent used in each round of plugging operation is 91.2 - 94.52%.

[0017] To obtain a better displacement effect, preferably, the displacement fluid mainly consists of partially hydrolyzed polyacrylamide and water. The mass fraction of partially hydrolyzed polyacrylamide in the displacement fluid is 0.4 - 0.8%, the number-average molecular weight of the partially hydrolyzed polyacrylamide is not more than 15 million, and the degree of hydrolysis is 10 - 12%.

[0018] Preferably, after a round of plugging operation is completed, when the target well group continues to be injected with water for oil production until the daily oil production of the target production well is not more than the daily oil production at the time of water breakthrough and the chloride ion content of the produced water from the target production well is less than the chloride ion content of the produced water before water breakthrough, the next round of plugging operation is carried out.

[0019] Preferably, during a round of plugging operation, the ratio of the volume of the plugging agent injected into the target production well to the volume of the fracture space during this round of plugging operation is 0.2 - 0.3, and the ratio of the volume of the displacement fluid injected into the target production well to the volume of the fracture space during this round of plugging operation is 0.25 - 0.3.

[0020] Preferably, the volume of the plugging agent injected into the target production well during a round of plugging operation is not more than the volume of the plugging agent injected into the target production well during the next round of plugging operation after this round of plugging operation. For example, when two rounds of plugging operations are carried out on the target production well, the volume of the plugging agent injected into the target production well during the second round of plugging operation is not less than the volume of the plugging agent injected into the target production well during the first round of plugging operation.

[0021] Preferably, during each round of plugging operation, the injection speed of the plugging agent is 1.5 - 2m 3 / h, and the injection speed of the displacement fluid is 1.5 - 2m 3 / h.

[0022] In the present invention, the volume of the fracture space during a certain round of plugging operations is determined by the following method: before a certain round of plugging operations is carried out, water containing tracers is stably injected into the water injection wells in the target well group, and the time for the target oil production wells to see the tracers is monitored at the same time, and the volume of the fracture space during the certain round of plugging operations is determined based on the injection displacement of the water containing tracers and the time for the tracers to see the tracers.

[0023] In order to ensure that the plugging agent can be cross-linked after being injected into the formation to improve the plugging strength, preferably, the formation temperature of the target well group is 60-70° C. and the mineralization is 50,000-80,000 mg / L. DETAILED DESCRIPTION

[0024] The technical solution of the present invention is further described below in conjunction with specific embodiments.

[0025] Example

[0026] In the method for plugging multi-scale fractures in a fractured oil reservoir of this embodiment, a well group W in an oil reservoir M is taken as an example. The well group includes an oil production well A, an oil production well B and a water injection well H. When water injection is performed on the well group for oil production, when the water injection time into the water injection well H is 12 days and the water injection volume is 310m 3 When the injection time of water into the water injection well H was 57 days and the injection volume was 980m 3 When the water injection effect was achieved, the oil production well B showed the effect of water injection, showing the characteristics of increased liquid production, increased oil production, and basically stable water content and chloride ion content. By the time the oil production well B showed the effect, the injection pressure of the water injection well was still 0. Through geological analysis, it was found that there were large-scale cracks with high inclination angles (i.e., cracks with inclination angles of 80-90°, crack lengths of 10-500m, and core crack openings of 0.5-1mm) between the oil production well A and the water injection well H, and only small-scale cracks existed between the oil production well B and the water injection well H.

[0027] In order to further increase the water injection development effect of the well group, the high-angle large-scale fractures between the oil production well A and the water injection well H are plugged, and while the small-scale fractures between the oil production well B and the water injection well H are retained, the crude oil in the direction of the oil production well A is further displaced, thereby improving the crude oil recovery rate of the entire well group;

[0028] The method for plugging multi-scale fractures in a fractured oil reservoir of this embodiment specifically comprises the following steps:

[0029] (1) Optimizing the plugging agent and its injection parameters, and optimizing the displacement fluid and its injection parameters;

[0030] Due to the relatively large scale of the target fracture to be plugged, a plugging agent with good compatibility with the formation and a breakthrough pressure greater than 10 MPa / m is preferably selected. In this embodiment, the formation temperature of well group W is 60 - 70 °C and the salinity is 50000 - 80000 mg / L. Therefore, plugging agents D1 and D2 are preliminarily screened out. Both plugging agents D1 and D2 are composed of a base fluid and a nano / micro particle enhancer. The viscosity of the base fluid in plugging agent D1 at 25 °C is 210 - 370 mPa·s, and the viscosity of the base fluid in plugging agent D2 at 25 °C is 20 - 80 mPa·s;

[0031] The base fluid in plugging agent D1 is composed of acrylamide monomers, initiators, crosslinking polymerization monomers, retarders, polymers, organic chromium crosslinking agents and water. The acrylamide monomer is acrylamide, the initiator is azodicyanovaleric acid, the crosslinking polymerization monomer is N,N'-methylenebisacrylamide, the retarder is potassium ferrocyanide, and the polymer is an anionic partially hydrolyzed polyacrylamide with a number average molecular weight of 15 million - 18 million and a hydrolysis degree of 10% - 12%. The polymer in this embodiment is a commercially available anionic partially hydrolyzed polyacrylamide (number average molecular weight of 15 million, hydrolysis degree of 10%);

[0032] The mass ratio of acrylamide monomers, initiators, crosslinking polymerization monomers, retarders, polymers and organic chromium crosslinking agents is 4:0.04:0.1:0.04:0.2:0.1. The mass ratio of the acrylamide monomers in the base fluid to the mass of the nano / micro particle enhancer is 4:1. The mass fraction of water in plugging agent D1 is 91.2%;

[0033] The nano / micro particle enhancer in plugging agent D1 is composed of sodium bentonite, calcium bentonite and microsilica powder. The average particle sizes of sodium bentonite, calcium bentonite and microsilica powder are 1000 mesh, 1000 mesh and 1300 mesh respectively;

[0034] In addition, the viscosity of the base fluid in plugging agent D2 is relatively low and it is easy to flow into production well A along high - dip large - scale fractures. Therefore, plugging agent D1 is selected as the best plugging agent from plugging agents D1 and D2. The dosage of plugging agent D1 is 0.2 PV and the injection rate is 2 m 3 / h;

[0035] In this embodiment, the following types of displacement fluids are preferably selected: polymer system displacement fluid, organic crosslinking agent system displacement fluid (composed of organic crosslinking agent and water); According to the displacement plugging effect, the preferred displacement fluid is the polymer system displacement fluid. The preferred polymer system displacement fluid is composed of polymer and water, with a viscosity of 240 mPa·s and an injection rate of 2 m 3 / h, the injection volume is 0.3 PV, the polymer is partially hydrolyzed polyacrylamide (partially hydrolyzed polyacrylamide is a commercially available product, the number average molecular weight is 12 million, and the hydrolysis degree is 10%), and the mass fraction of the polymer in the displacement fluid is 0.6%;

[0036] (2) Inject plugging agent D1 into production well A, the injection volume is 0.2 PV (that is, the ratio of the volume of plugging agent D1 to the volume of the fracture space is 0.2), and the injection rate is 2 m 3 / h, then inject the displacement fluid, and the injection rate of the displacement fluid is 2 m 3 / h, the injection volume is 0.3 PV (that is, the ratio of the volume of the displacement fluid to the volume of the fracture space is 0.3). After injecting the displacement fluid, shut in the well and wait for coagulation. After the plugging agent D1 solidifies into a gel, complete the first-round plugging operation; in this embodiment, the volume of the fracture space during the first-round plugging operation is determined by the following method: Before the first-round plugging operation, carry out tracer monitoring. The water injection volume when production well A sees the tracer is the volume of the fracture space. The specific method is as follows: Stably inject water containing tracer into injection well H, and at the same time monitor the tracer seeing time of production well A. Determine the volume of the fracture space according to the injection displacement of the water containing tracer and the tracer seeing time (fracture space volume = injection displacement of water containing tracer × tracer seeing time);

[0037] After the first-round plugging operation, inject water into injection well H, and all production wells in the well group are opened for production. When the daily oil production of production well A is not greater than the daily oil production during water channeling, and the chloride ion content in the produced water of production well A is less than the chloride ion content in the produced water before water channeling, carry out the second-round plugging operation on production well A;

[0038] The second-round plugging operation includes the following steps: Inject plugging agent D1 into production well A, the injection volume is 0.3 PV (that is, the ratio of the volume of plugging agent D1 to the volume of the fracture space is 0.3), and the injection rate is 2 m 3 / h, then inject the displacement fluid, and the injection rate of the displacement fluid is 2 m 3 / h, the injection volume is 0.3 PV (that is, the ratio of the volume of the displacement fluid to the volume of the fracture space is 0.3); the displacement fluid used in the second-round plugging operation is the same as the displacement fluid used in the first-round plugging operation; in this embodiment, the volume of the fracture space during the second-round plugging operation is determined by the following method: Before the second-round plugging operation, carry out tracer monitoring. The water injection volume when production well A sees the tracer is the volume of the fracture space. The specific method is as follows: Stably inject water containing tracer into injection well H, and at the same time monitor the tracer seeing time of production well A. Determine the volume of the fracture space according to the injection displacement of the water containing tracer and the tracer seeing time (fracture space volume = injection displacement of water containing tracer × tracer seeing time).

[0039] Comparative Example 1

[0040] To investigate the influence of the plugging agent composition on the plugging effect, a well group W1 similar to that in the embodiment and located in reservoir M was selected for a plugging experiment. The well group W1 in this comparative example includes production well A1, production well B1, and injection well H1. There is a high-angle large-scale fracture between production well A1 and injection well H1 (the fracture dip angle is 80 - 90°, the fracture length is 10 - 500 m, and the core fracture aperture is 0.5 - 1 mm). There is only a small-scale fracture between production well B1 and injection well H1. The formation temperature of the well group W1 in this comparative example is 60 - 70 °C, and the salinity is 50000 - 80000 mg / L. When water breakthrough occurs significantly in production well A1 during water injection and oil production in this well group, plugging agent D11 is injected into production well A1. The injection volume is 0.2 PV (i.e., the ratio of the volume of plugging agent D11 to the fracture space volume is 0.2), and the injection speed is 2 m 3 / h, and then a displacement fluid is injected. The injection speed of the displacement fluid is 2 m 3 / h, and the injection volume is 0.3 PV (i.e., the ratio of the volume of the displacement fluid to the fracture space volume is 0.3). After injecting the displacement fluid, the well is shut in for waiting for gelation. After the plugging agent D11 solidifies into a gel, the first-round plugging operation is completed;

[0041] After the first-round plugging operation, water is injected into injection well H1, and all production wells in the well group are opened for production. When the daily oil production of production well A1 is not greater than the daily oil production during water breakthrough and the chloride ion content in the produced water of production well A1 is less than the chloride ion content in the produced water before water breakthrough, a second-round plugging operation is carried out on production well A1;

[0042] The second-round plugging operation includes the following steps: Inject plugging agent D11 into production well A1. The injection volume is 0.3 PV (i.e., the ratio of the volume of plugging agent D11 to the fracture space volume is 0.3), and the injection speed is 2 m 3 / h, and then a displacement fluid is injected. The injection speed of the displacement fluid is 2 m 3 / h, and the injection volume is 0.3 PV (i.e., the ratio of the volume of the displacement fluid to the fracture space volume is 0.3);

[0043] The method for determining the fracture space volume during each round of plugging operation in this comparative example is the same as the method for determining the fracture space volume during each round of plugging operation in the embodiment;

[0044] The displacement fluids used in the first-round and second-round plugging operations in this comparative example are the same as the displacement fluid used in the embodiment;

[0045] In this comparative example, the plugging agent D11 used in the first-round plugging operation and the second-round plugging operation is the same. The only difference between the plugging agent D11 and the plugging agent D1 used in the examples is that the nano / micro particle enhancer in the plugging agent D11 is sodium-based bentonite (the sodium-based bentonite is the same as the sodium-based bentonite in the examples).

[0046] Comparative Example 2

[0047] In order to investigate the influence of the plugging agent composition on the plugging effect, a well group W2 similar to that in the examples and located in reservoir M was selected for a plugging experiment. The well group W2 in this comparative example includes production well A2, production well B2, and injection well H2. There is a high-angle large-scale fracture between production well A2 and injection well H2 (the fracture dip angle is 80 - 90°, the fracture length is 10 - 500 m, and the core fracture aperture is 0.5 - 1 mm). There is only a small-scale fracture between production well B2 and injection well H2. The formation temperature of the well group W2 in this comparative example is 60 - 70 °C, and the salinity is 50000 - 80000 mg / L. When obvious water channeling occurs in production well A2 during water injection and oil production in this well group, the plugging agent D12 is injected into production well A2 at an injection volume of 0.2 PV (i.e., the ratio of the volume of the plugging agent D12 to the volume of the fracture space is 0.2), and the injection rate is 2 m 3 / h, and then a displacement fluid is injected. The injection rate of the displacement fluid is 2 m 3 / h, and the injection volume is 0.3 PV (i.e., the ratio of the volume of the displacement fluid to the volume of the fracture space is 0.3). After injecting the displacement fluid, the well is shut in for gel setting. After the plugging agent D12 solidifies into a gel, the first-round plugging operation is completed;

[0048] After the first-round plugging operation, water is injected into injection well H2, and all production wells in the well group are opened for production. When the daily oil production of production well A2 is not greater than the daily oil production during water channeling and the chloride ion content in the produced water of production well A2 is less than the chloride ion content in the produced water before water channeling, a second-round plugging operation is carried out on production well A2;

[0049] The second-round plugging operation includes the following steps: Inject the plugging agent D12 into production well A2 at an injection volume of 0.3 PV (i.e., the ratio of the volume of the plugging agent D12 to the volume of the fracture space is 0.3), and the injection rate is 2 m 3 / h, and then a displacement fluid is injected. The injection rate of the displacement fluid is 2 m 3 / h, and the injection volume is 0.3 PV (i.e., the ratio of the volume of the displacement fluid to the volume of the fracture space is 0.3);

[0050] In this comparative example, the method for determining the fracture space volume during each round of plugging operation is the same as the method for determining the fracture space volume during each round of plugging operation in the examples;

[0051] In this comparative example, the displacement fluids used in the first-round plugging operation and the second-round plugging operation are the same as those used in the examples;

[0052] The plugging agent D12 used in the first-round plugging operation and the second-round plugging operation in this comparative example is the same. The only difference between the plugging agent D12 and the plugging agent D1 used in the examples is that the nano / micro particle enhancer in the plugging agent D12 is calcium-based bentonite (the calcium-based bentonite is the same as the calcium-based bentonite in the examples).

[0053] Comparative Example 3

[0054] In order to investigate the influence of the plugging agent composition on the plugging effect, a well group W3 similar to that in the examples located in reservoir M was selected for a plugging experiment. The well group W3 in this comparative example includes production well A3, production well B3, and injection well H3. There is a high-dip large-scale fracture between production well A3 and injection well H3 (the fracture dip angle is 80 - 90°, the fracture length is 10 - 500 m, and the core fracture aperture is 0.5 - 1 mm). There is only a small-scale fracture between production well B3 and injection well H3. The formation temperature of the well group W3 in this comparative example is 60 - 70 °C, and the salinity is 50000 - 80000 mg / L. When obvious water channeling occurred in production well A3 during water injection and oil production in this well group, the plugging agent D13 was injected into production well A3 at an injection volume of 0.2 PV (i.e., the ratio of the volume of the plugging agent D13 to the volume of the fracture space is 0.2), and the injection rate was 2 m 3 / h, and then the displacement fluid was injected. The injection rate of the displacement fluid was 2 m 3 / h, and the injection volume was 0.3 PV (i.e., the ratio of the volume of the displacement fluid to the volume of the fracture space is 0.3). After injecting the displacement fluid, the well was shut in for waiting for gelation. After the plugging agent D13 solidified into a gel, the first-round plugging operation was completed;

[0055] After the first-round plugging operation, water was injected into injection well H3, and all production wells in the well group were opened for production. When the daily oil production of production well A3 was not greater than the daily oil production during water channeling, and the chloride ion content in the produced water of production well A3 was less than the chloride ion content in the produced water before water channeling, the second-round plugging operation was carried out on production well A3;

[0056] The second-round plugging operation includes the following steps: Inject the plugging agent D13 into production well A3 at an injection volume of 0.3 PV (i.e., the ratio of the volume of the plugging agent D13 to the volume of the fracture space is 0.3), and the injection rate is 2 m 3 / h, and then the displacement fluid was injected. The injection rate of the displacement fluid was 2 m 3 / h, and the injection volume was 0.3 PV (i.e., the ratio of the volume of the displacement fluid to the volume of the fracture space is 0.3);

[0057] In this comparative example, the method for determining the crack space volume during each round of plugging operation is the same as that in the example;

[0058] The displacement fluids used in the first-round and second-round plugging operations in this comparative example are the same as those used in the example;

[0059] The plugging agent D13 used in the first-round and second-round plugging operations in this comparative example is the same. The difference between plugging agent D13 and plugging agent D1 used in the example is only that the nano / micro particle enhancer in plugging agent D13 is microsilica powder (the same microsilica powder as that in the example).

[0060] The difference in the average daily oil production of production wells A, A1, A2, or A3 during water channeling does not exceed 5%.

[0061] Experimental Example

[0062] To evaluate the plugging and profile control effects of the plugging methods in the example and Comparative Examples 1-3, the average daily oil production of the target production wells (production wells A, A1, A2, or A3) during water channeling in the example and Comparative Examples 1-3 is defined as the daily basic production. The time when the daily oil production of the target production wells after the first-round or second-round plugging operation in the example and Comparative Examples 1-3 is greater than the daily basic production is defined as the stable production time. The difference between the total oil production of the target production wells during the stable production time and the product of the daily basic production and the stable production time is defined as the cumulative increased oil production. The ratio of the cumulative increased oil production to the stable production time is defined as the average daily increased oil production. For example, in the example, the average daily oil production (daily basic production) of production well A during water channeling is x t, the time (stable production time) when the daily oil production of production well A after the first-round plugging operation is greater than the daily basic production is 25 d, and the total oil production of production well A during the stable production time is (12.5 + 25x) t. Then, the cumulative increased oil production of production well A is 12.5 + 25x - 25x = 12.5 t, and the average daily increased oil production of production well A is 12.5 ÷ 25 = 0.5 t / d. The stable production time, cumulative increased oil production, and average daily increased oil production of the target production wells after the first-round and second-round plugging operations in the plugging methods of the example and Comparative Examples 1-3 are shown in Table 1.

[0063] Table 1 Plugging Effects of Different Plugging Methods

[0064]

[0065] Note: In Table 1, " / " indicates that the daily oil production of the target oil production well after the plugging operation is not greater than the daily basic production, and the chloride ion content of the produced water in the target oil production well is less than the chloride ion content of the produced water before water channeling.

[0066] In order to study the influence of the proportion of each component in the plugging agent, the composition of the displacement fluid, and the construction parameters of the plugging on the experimental results, plugging experiments were carried out on other well groups similar to well group W in reservoir M according to the method of the examples. The difference is that the polymer in the plugging agent was replaced with a commercially available anionic partially hydrolyzed polyacrylamide with a number average molecular weight of 18 million and a hydrolysis degree of 12%, or the mass ratio of acrylamide monomer, initiator, crosslinking polymerization monomer, retarder, polymer, and organic chromium crosslinking agent was adjusted to 6:0.05:0.2:0.05:0.3:0.2, or the mass ratio of the acrylamide monomer to the nano / micro particle enhancer was adjusted to 6:2, or the mass fraction of water in the plugging agent was adjusted to 94.52%, or the mass of the retarder was adjusted to 0, or the mass fraction of partially hydrolyzed polyacrylamide in the displacement fluid was adjusted to 0.4% or 0.8%, or the injection volume of the plugging agent in the first-round plugging operation was adjusted to 0.3 PV, or the injection volume of the displacement fluid in the first-round plugging operation was adjusted to 0.25 PV, or the injection volume of the plugging agent in the second-round plugging operation was adjusted to 0.25 PV, or the injection volume of the displacement fluid in the second-round plugging operation was adjusted to 0.25 PV, or the injection rate of the plugging agent in the first-round plugging operation was adjusted to 1.5 m 3 / h, or the injection rate of the displacement fluid in the first-round plugging operation was adjusted to 1.5 m 3 / h, or the injection rate of the plugging agent in the second-round plugging operation was adjusted to 1.5 m 3 / h, or the injection rate of the displacement fluid in the second-round plugging operation was adjusted to 1.5 m 3 / h. It was found that the plugging effect after adjusting the parameters was close to that of the examples.

Claims

1. A plugging method for multi-scale fractures in a fractured reservoir, characterized in that, The method includes the following steps: During the water injection and oil production process of the target well group, when water breakthrough occurs in the target oil production well in the target well group, more than one round of plugging operations is carried out on the target oil production well. Each round of plugging operation includes the following steps: injecting a plugging agent into the target oil production well to form a plugging slug, and then injecting a displacement fluid to displace the plugging slug to a predetermined position, and then shutting in the well for waiting for setting; the target oil production well is an oil production well with a high dip angle and large-scale fractures between it and the water injection well. The plugging agents used in each round of plugging operation independently include an active substance and water; the active substance includes the following components in parts by mass: 4-6 parts of acrylamide monomer, 0.04-0.05 part of initiator, 0.1-0.2 part of crosslinked polymerization monomer, 0.2-0.3 part of polymer, 0.1-0.2 part of organic chromium crosslinking agent, and 1-2 parts of nano / micro particle reinforcing agent; the molecule of the crosslinked polymerization monomer contains more than two ethylenically unsaturated carbon-carbon double bonds; the nano / micro particle reinforcing agent includes sodium bentonite, calcium bentonite and microsilica powder.

2. The plugging method for multi-scale fractures in a fractured reservoir according to claim 1, characterized in that The high dip angle and large-scale fracture refers to a fracture with a fracture dip angle of 80-90°, a fracture length of 10-500 m, and a core fracture aperture of 0.5-1 mm.

3. The plugging method for multi-scale fractures in a fractured reservoir as described in claim 1, characterized in that, The particle size of the sodium bentonite is not less than 1000 mesh; the particle size of the calcium bentonite is not less than 1000 mesh; the particle size of the microsilica powder is not less than 1300 mesh.

4. The plugging method for multi-scale fractures in a fractured reservoir according to claim 1, characterized in that, During a certain round of plugging operation, the ratio of the volume of the plugging agent injected into the target oil production well to the volume of the fracture space during this round of plugging operation is 0.2-0.3, and the ratio of the volume of the displacement fluid injected into the target oil production well to the volume of the fracture space during this round of plugging operation is 0.25-0.

3.

5. The plugging method for multi-scale fractures in a fractured reservoir according to claim 4, characterized in that, The volume of the fracture space during a certain round of plugging operation is determined by the following method: before the construction of a certain round of plugging operation, inject water containing a tracer stably into the water injection well in the target well group, and at the same time monitor the tracer appearance time of the target oil production well, and determine the volume of the fracture space during this round of plugging operation according to the injection displacement of the water containing the tracer and the tracer appearance time.

6. The plugging method for multi-scale fractures in a fractured reservoir according to claim 1, wherein The volume of the plugging agent injected into the target oil production well during a certain round of plugging operation is not greater than the volume of the plugging agent injected into the target oil production well during the next round of plugging operation after this round of plugging operation.

7. The plugging method for multi-scale fractures in a fractured reservoir according to any one of claims 1-6, characterized in that, After a certain round of plugging operation is completed, continue water injection and oil production in the target well group until the daily oil production of the target oil production well is not greater than the daily oil production at the time of water breakthrough and the chloride ion content of the produced water from the target oil production well is less than the chloride ion content of the produced water before water breakthrough, and then carry out the next round of plugging operation.

8. The plugging method for multi-scale fractures in a fractured reservoir according to any one of claims 1-6, characterized in that, The formation temperature of the target well group is 60-70 °C, and the salinity is 50000-80000 mg / L.

9. The plugging method for multi-scale fractures in a fractured reservoir according to any one of claims 1-6, characterized in that, The acrylamide monomer is acrylamide and / or methacrylamide; the initiator is a water-soluble azo initiator; the crosslinking polymerization monomer is N,N'-methylenebisacrylamide; the polymer is an anionic partially hydrolyzed polyacrylamide, and the molecular weight of the anionic partially hydrolyzed polyacrylamide is 15 million to 18 million, and the hydrolysis degree is 10% to 12%; the active substance further includes an inhibitor, and in the active substance, the mass fraction of the inhibitor is not more than 0.05 parts; the mass fraction of water in the plugging agent used in each round of plugging operation is 91.2% to 94.52%; the displacement fluid is mainly composed of partially hydrolyzed polyacrylamide and water, and the mass fraction of the partially hydrolyzed polyacrylamide in the displacement fluid is 0.4% to 0.8%, and the number-average molecular weight of the partially hydrolyzed polyacrylamide is not more than 15 million, and the hydrolysis degree is 10% to 12%.

10. The plugging method for multi-scale fractures in a fractured reservoir according to any one of claims 1-6, characterized in that, During each round of plugging operation, the injection rate of the plugging agent is 1.5 - 2 m 3 / h, and the injection rate of the displacement fluid is 1.5 - 2 m 3 / h.

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