Fractured oil reservoir recovery method through cooperation of targeted water shutoff and directional fracturing

Abstract

The invention relates to the technical field of oil exploitation, in particular to a fractured oil reservoir recovery method through cooperation of targeted water plugging and directional fracturing. Comprising the following steps that S1, cement paste is injected into a stratum, and after injection is completed, a well is closed to wait for setting; s2, active water is injected into the oil well for trial squeezing, and the shaft sealing condition is inspected; s3, nitrogen, a water plugging agent and fracturing fluid are injected into the stratum; and S4, after fracturing is completed, oil extraction production is conducted. The water plugging agent and the fracturing fluid are jointly pressed into the stratum through nitrogen, the plugging strength is guaranteed through the combined action of the water plugging agent and the fracturing fluid, a new crack is generated through the fracturing fluid, oil gas can be released through the crack, and through the synergistic effect of targeted water plugging and directional fracturing, water reducing and oil increasing are achieved, and the recovery efficiency is improved.

Description

Technical Field

[0001] The invention relates to the technical field of petroleum extraction, and in particular to a fractured oil reservoir extraction method utilizing the coordinated effects of targeted water plugging and directional fracturing. Background Art

[0002] As the development of major oil and gas fields enters the middle and late stages, large-scale water injection is carried out to make up for the lack of formation energy. Due to reasons such as formation heterogeneity, water injection is uneven, and fingering is serious, resulting in increasingly serious water breakthrough problems in oil and gas wells, and even serious conditions such as water flooding and water channeling, which cause oil and gas wells to stop production, directly affecting the production and benefits of oil and gas fields. In addition, due to the reduction of formation energy, formation pollution and blockage, the production of oil and gas wells has decreased. In order to meet the production requirements, major oil and gas fields need to take measures to increase production such as repeated fracturing. Since the conventional repeated fracturing process only extends and extends on the basis of the original fractures, with the increase in the number of fracturing, the fractures are very likely to extend to the water area, resulting in water breakthrough in oil and gas wells and high water production or even complete water production, especially in oil and gas wells adjacent to water injection wells, edge water, and bottom water. The probability of water breakthrough caused by measures is higher; in addition, once water is seen in oil and gas wells, the fingering phenomenon of water injection will be rapidly intensified, resulting in other high-oil-containing areas being unable to be affected by the injected water, reducing the efficiency of water injection and the recovery rate of formation crude oil. Summary of the invention

[0003] In order to solve the above problems, the present invention provides a fractured oil reservoir recovery method using targeted water plugging and directional fracturing in coordination.

[0004] The technical solution of the present invention is: a fractured oil reservoir recovery method using targeted water plugging and directional fracturing, comprising the following steps:

[0005] S1. Inject cement slurry into the formation at a rate of 2-4 L / min for 1-2 hours. After the injection is completed, shut down the well and wait for 20-24 hours for setting.

[0006] S2. Inject active water into the oil well for test squeezing to check the sealing condition of the wellbore;

[0007] S3.1. Inject nitrogen and water plugging agent into the formation. The initial nitrogen injection rate is 1-1.5 L / min, and the nitrogen injection rate is increased at a rate of 0.5-1 L / min. The water plugging agent injection rate is 2-4 L / min.

[0008] S3.2. When the injection rate of nitrogen reaches 6-8 L / min, water plugging agent and fracturing fluid are injected into the formation at the same time, and the nitrogen injection rate is kept unchanged for 5-10 minutes; wherein, water plugging agent and fracturing fluid are injected into the formation at the same time, the injection rate of water plugging agent is 0.5-1.5 L / min, and the injection rate of fracturing fluid is 2-3 L / min;

[0009] S3.3, the nitrogen injection rate is then reduced at a rate of 0.5-1 L / min, and only fracturing fluid is injected into the formation at a rate of 1-2 L / min, until the nitrogen injection rate is reduced to 0, and the injection of fracturing fluid is stopped at the same time, completing the fracturing;

[0010] S4. After fracturing is completed, oil production is carried out.

[0011] Description: The above method uses nitrogen to press the water plugging agent and fracturing fluid into the formation together, so that the nitrogen pressure sends the water plugging agent into the reservoir pores, and the water plugging agent and fracturing fluid work together to ensure the plugging strength, and create new cracks through the fracturing fluid, so that oil and gas can be released through the cracks. Through the synergistic effect of targeted water plugging and directional fracturing, water reduction and oil increase are achieved, and the recovery rate is improved.

[0012] Furthermore, the ingredients of the cement slurry include, by weight, 50-60 parts of G-grade cement, 1-5 parts of retarder, 2-4 parts of drag reducer, and 20-30 parts of water.

[0013] Note: The above-mentioned cement slurry can sink into the bottom water, effectively block the bottom water, avoid the dilution of the fracturing fluid by the formation water, and ensure the fracturing effect of the fracturing fluid.

[0014] Furthermore, the ingredients of the water plugging agent include, by weight: 5-15 parts of magnesium silicate / chitosan composite nanoparticles, 20-30 parts of acrylamide, 3-6 parts of sodium dodecyl sulfate, 4-8 parts of initiator, and 40-60 parts of water.

[0015] Description: The above-mentioned water plugging agent can undergo a polymerization reaction under the action of an initiator to form a gel structure to plug the reservoir pores in the formation, and the fracturing fluid can promote the decomposition of chitosan on the magnesium silicate / chitosan composite nanoparticles, so that the magnesium silicate particles can further form a cross-linked structure to improve the plugging strength of the water plugging agent and ensure the fracturing effect during the fracturing process.

[0016] Furthermore, the initiator is a mixture of any one or more of potassium persulfate and ammonium persulfate in any ratio.

[0017] Note: The above-mentioned initiator can provide free radicals to initiate the self-polymerization reaction of the water plugging agent, thereby ensuring that the water plugging agent can fully exert its plugging effect.

[0018] Furthermore, the components of the fracturing fluid include, by weight, 10 to 20 parts of quartz sand, 5 to 10 parts of potassium chloride, 1 to 2 parts of hydroxyethyl cellulose, 5 to 8 parts of alkylphenol polyoxyethylene ether, 2 to 5 parts of hydrogen peroxide, and 60 to 65 parts of water.

[0019] Description: The above-mentioned fracturing fluid can fracture cracks in the formation and promote the decomposition of chitosan, so that the magnesium silicate / chitosan composite nanoparticles undergo polymerization reaction again, thereby improving the plugging effect and preventing the fracturing fluid from overflowing from the plugged pores.

[0020] Furthermore, the preparation method of the magnesium silicate / chitosan composite nanoparticles comprises the following steps:

[0021] 1) Add nano magnesium silicate into dimethyl sulfoxide, ultrasonically disperse for 5 to 10 minutes, add diisobutylnitrile to the dimethyl sulfoxide under stirring, then heat the dimethyl sulfoxide to 40 to 50° C., keep warm for 30 to 40 minutes, and then filter to obtain magnesium silicate loaded with diisobutylnitrile; wherein the mass ratio of nano magnesium silicate, diisobutylnitrile, and dimethyl sulfoxide is 1:0.2 to 0.4:5 to 7;

[0022] 2) adding magnesium silicate loaded with azobisisobutylnitrile into deionized water, and ultrasonically dispersing for 5 to 10 minutes to obtain a magnesium silicate dispersion; wherein the mass ratio of magnesium silicate loaded with azobisisobutylnitrile to deionized water is 1:4 to 5;

[0023] 3) dissolving chitosan in an acetic acid solution having a mass concentration of 3% to 6%, then adding ammonium persulfate to the acetic acid solution, stirring for 10 to 20 minutes, and then adding acrylonitrile monomer to the acetic acid solution to obtain a mixed solution; wherein the mass ratio of chitosan, ammonium persulfate, acrylonitrile monomer, and acetic acid solution is 1:0.1 to 0.2:0.4 to 0.6:3 to 4;

[0024] 4) The mixed solution is heated to 30-40° C., kept warm for 8-15 minutes, and then the magnesium silicate dispersion at 0-5° C. is slowly added to the mixed solution. During the addition of the magnesium silicate dispersion, after the temperature of the mixed solution drops by 10-15° C., the addition of the magnesium silicate dispersion is stopped, and glutaraldehyde is added to the mixed solution once, and then the mixed solution is reheated to 30-40° C.; wherein the amount of glutaraldehyde added accounts for 0.6% to 1% of the current mass of the mixed solution:

[0025] 5) Repeat step 4) until the magnesium silicate dispersion is completely added to the mixed solution, let stand for 1 to 2 hours, then filter and wash to obtain magnesium silicate / chitosan composite nanoparticles; wherein the total mass ratio of the mixed solution to the magnesium silicate dispersion is 1:0.7 to 0.9.

[0026] Description: The above preparation method loads azobisisobutylnitrile on the surface of magnesium silicate, and then modifies chitosan with acrylonitrile to coat the magnesium silicate with chitosan. After the fracturing fluid is injected, the chitosan will decompose, and the azobisisobutylnitrile loaded on the surface of magnesium silicate will induce acrylonitrile to polymerize, so that the magnesium silicate forms a cross-linked structure to further block the reservoir pores and improve the blocking strength.

[0027] Furthermore, the addition rate of the magnesium silicate dispersion is 70 to 90 ml / min.

[0028] Note: Limiting the addition rate of magnesium silicate dispersion can ensure that chitosan can fully coat magnesium silicate and avoid affecting the effect of the water plugging agent.

[0029] The beneficial effects of the present invention are:

[0030] (1) The present invention uses nitrogen to pressurize the water plugging agent and the fracturing fluid into the formation, so that the nitrogen pressure sends the water plugging agent into the reservoir pores, and the water plugging agent and the fracturing fluid work together to ensure the plugging strength, and the fracturing fluid creates new cracks so that oil and gas can be released through the cracks. Through the synergistic effect of targeted water plugging and directional fracturing, water reduction and oil increase are achieved, thereby improving the recovery rate.

[0031] (2) The present invention loads azobisisobutylnitrile on the surface of magnesium silicate and then modifies chitosan with acrylonitrile so that chitosan is coated on the magnesium silicate. After the fracturing fluid is injected, the chitosan decomposes, and the azobisisobutylnitrile loaded on the surface of the magnesium silicate triggers the polymerization of acrylonitrile, so that the magnesium silicate forms a cross-linked structure to further block the reservoir pores and improve the blocking strength. DETAILED DESCRIPTION

[0032] In order to further illustrate the method adopted by the present invention and the effect achieved, the technical solution of the present invention will be clearly and completely described in combination with experiments below.

[0033] Example 1: A fractured oil reservoir recovery method using targeted water plugging and directional fracturing, comprising the following steps:

[0034] S1. Inject cement slurry into the formation at an injection rate of 3L / min for 1.5h. After the injection is completed, shut down the well and wait for 22h for setting. Among them, 55 parts of G-grade cement, 3 parts of retarder, 3 parts of drag reducer, and 25 parts of water are used. The retarder is sodium phosphate and the drag reducer is polyvinyl alcohol.

[0035] S2. Inject active water into the oil well for test squeezing to check the sealing condition of the wellbore;

[0036] S3.1. Inject nitrogen and water plugging agent into the formation. The initial injection rate of nitrogen is 1.25 L / min, and the injection rate of nitrogen is increased at a rate of 0.8 L / min. The injection rate of water plugging agent is 3 L / min. The ingredients of water plugging agent are calculated by weight: 10 parts of magnesium silicate / chitosan composite nanoparticles, 25 parts of acrylamide, 5 parts of sodium dodecyl sulfate, 6 parts of initiator, and 50 parts of water. The initiator is potassium persulfate. The ingredients of fracturing fluid are calculated by weight: 15 parts of quartz sand, 8 parts of potassium chloride, 1.5 parts of hydroxyethyl cellulose, 6 parts of alkylphenol polyoxyethylene ether, 4 parts of hydrogen peroxide, and 63 parts of water.

[0037] S3.2. When the injection rate of nitrogen reaches 7L / min, water plugging agent and fracturing fluid are injected into the formation at the same time, and the nitrogen injection rate is kept unchanged for 8 minutes; among which, the injection rate of water plugging agent is 1L / min, and the injection rate of fracturing fluid is 2.5L / min;

[0038] S3.3, the nitrogen injection rate is then reduced at a rate of 0.8 L / min, and only fracturing fluid is injected into the formation at a rate of 1.5 L / min, until the nitrogen injection rate is reduced to 0, and the injection of fracturing fluid is stopped at the same time, completing the fracturing;

[0039] S4. After the fracturing is completed, oil production is carried out;

[0040] The preparation method of magnesium silicate / chitosan composite nanoparticles comprises the following steps:

[0041] 1) Add nano magnesium silicate into dimethyl sulfoxide, and after ultrasonic dispersion for 8 minutes, add diisobutylnitrile to the dimethyl sulfoxide under stirring, and then heat the dimethyl sulfoxide to 45°C, keep warm for 5 minutes, and then filter to obtain magnesium silicate loaded with diisobutylnitrile; wherein the mass ratio of nano magnesium silicate, diisobutylnitrile, and dimethyl sulfoxide is 1:0.3:6;

[0042] 2) adding magnesium silicate loaded with azobisisobutylnitrile into deionized water, and performing ultrasonic dispersion for 5 to 10 minutes to obtain a magnesium silicate dispersion; wherein the mass ratio of magnesium silicate loaded with azobisisobutylnitrile to deionized water is 1:4.5;

[0043] 3) dissolving chitosan in an acetic acid solution having a mass concentration of 3% to 6%, then adding ammonium persulfate to the acetic acid solution, stirring for 10 to 20 minutes, and then adding acrylonitrile monomer to the acetic acid solution to obtain a mixed solution; wherein the mass ratio of chitosan, ammonium persulfate, acrylonitrile monomer, and acetic acid solution is 1:0.15:0.5:3.5;

[0044] 4) heating the mixed solution to 35° C., keeping the temperature for 12 minutes, slowly adding the magnesium silicate dispersion at 3° C. into the mixed solution, and when the temperature of the mixed solution drops by 12° C. during the addition of the magnesium silicate dispersion, stopping the addition of the magnesium silicate dispersion, adding glutaraldehyde once into the mixed solution, and then reheating the mixed solution to 35° C.; wherein the amount of glutaraldehyde added accounts for 0.8% of the current mass of the mixed solution; and the addition rate of the magnesium silicate dispersion is 80 ml / min;

[0045] 5) Repeat step 4) until the magnesium silicate dispersion is completely added to the mixed solution, let stand for 1.5 hours, then filter and wash to obtain magnesium silicate / chitosan composite nanoparticles; wherein the total mass ratio of the mixed solution to the magnesium silicate dispersion is 1:0.8.

[0046] Example 2: This example is basically the same as Example 1, except that the ingredients of the water plugging agent, by weight, include: 5 parts of magnesium silicate / chitosan composite nanoparticles, 20 parts of acrylamide, 3 parts of sodium dodecyl sulfate, 4 parts of initiator, and 40 parts of water.

[0047] Example 3: This example is basically the same as Example 1, except that the ingredients of the water plugging agent, by weight, include: 15 parts of magnesium silicate / chitosan composite nanoparticles, 30 parts of acrylamide, 6 parts of sodium dodecyl sulfate, 8 parts of initiator, and 60 parts of water.

[0048] Example 4: This example is basically the same as Example 1, except that the components of the fracturing fluid, by weight, include: 10 parts of quartz sand, 5 parts of potassium chloride, 1 part of hydroxyethyl cellulose, 5 parts of alkylphenol polyoxyethylene ether, 2 parts of hydrogen peroxide, and 60 parts of water.

[0049] Example 5: This example is basically the same as Example 1, except that the components of the fracturing fluid, by weight, include: 20 parts of quartz sand, 10 parts of potassium chloride, 2 parts of hydroxyethyl cellulose, 8 parts of alkylphenol polyoxyethylene ether, 5 parts of hydrogen peroxide, and 65 parts of water.

[0050] Example 6: This example is basically the same as Example 1, except that the initial injection amount of nitrogen is 1 L / min, and the nitrogen injection amount is increased at a rate of 0.5 L / min.

[0051] Example 7: This example is basically the same as Example 1, except that the initial injection amount of nitrogen is 1.5 L / min, and the nitrogen injection amount is increased at a rate of 1 L / min.

[0052] Example 8: This example is basically the same as Example 1, except that when the nitrogen injection rate reaches 6 L / min, the nitrogen injection rate remains unchanged for 8 minutes.

[0053] Example 9: This example is basically the same as Example 1, except that when the injection amount of nitrogen reaches 8 L / min, the nitrogen injection amount remains unchanged for 8 minutes.

[0054] Example 10: This example is basically the same as Example 1, except that the injection rate of the water plugging agent is 0.5 L / min.

[0055] Example 11: This example is basically the same as Example 1, except that the injection rate of the water plugging agent is 1.5 L / min.

[0056] Example 12: This example is basically the same as Example 1, except that the injection rate of the fracturing fluid is 2 L / min.

[0057] Example 13: This example is basically the same as Example 1, except that the injection rate of the fracturing fluid is 3 L / min.

[0058] Example 14: This example is basically the same as Example 1, except that a magnesium silicate dispersion at 0°C is slowly added to the mixed solution, and during the addition of the magnesium silicate dispersion, the addition of the magnesium silicate dispersion is stopped after the temperature of the mixed solution drops by 10°C.

[0059] Example 15: This example is basically the same as Example 1, except that a 5°C magnesium silicate dispersion is slowly added to the mixed solution, and during the addition of the magnesium silicate dispersion, the addition of the magnesium silicate dispersion is stopped after the temperature of the mixed solution drops by 15°C.

[0060] Example 16: This example is basically the same as Example 1, except that the amount of glutaraldehyde added is 0.6% of the current mass of the mixed solution.

[0061] Example 17: This example is basically the same as Example 1, except that the amount of glutaraldehyde added is 1% of the current mass of the mixed solution.

[0062] Comparative Example 1: Taking Example 1 as a reference, the magnesium silicate / chitosan composite nanoparticles were replaced with magnesium silicate particles and chitosan particles.

[0063] Comparative Example 2: Taking Example 1 as a reference, the hydrogen peroxide in the fracturing fluid was replaced by water.

[0064] Comparative Example 3: Taking Example 1 as a reference, the initial injection amount of nitrogen was kept at 7 L / min without change.

[0065] Comparative Example 4: Taking Example 1 as a reference, the magnesium silicate dispersion was added into the mixed solution at one time.

[0066] Experimental Example: In order to explore the influence of the parameters of each embodiment on the oil recovery rate of the oil field, the methods of each embodiment are used to recover the oil wells in the same area, and the daily increase in oil production of each oil well is obtained. The specific exploration is as follows:

[0067] Experimental Example 1: Investigating the effects of water plugging agent and fracturing fluid composition on daily oil production

[0068] Using Examples 1 to 5 and Comparative Examples 1 to 2 as experimental comparisons, the daily oil production increases under different compositions of water plugging agents and fracturing fluids are shown in Table 1 below:

[0069] Table 1 Daily oil production under different components of water plugging agent and fracturing fluid

[0070] Group Daily oil increase t / d Example 1 12.7 Example 2 11.5 Example 3 10.8 Example 4 10.4 Example 5 10.9 Comparative Example 1 6.3 Comparative Example 2 7.8

[0071] It can be seen from the data in Table 1 that, compared with Examples 1 to 5, the components of the water plugging agent and the fracturing fluid will affect the daily oil increase, among which the daily oil increase in Example 1 is the highest. This may be because the plugging strength of Example 1 is higher, the fracturing effect is better, and the oil and gas release is more sufficient. Therefore, the water plugging agent and fracturing fluid components selected in Example 1 are better;

[0072] In Example 1, compared with Comparative Examples 1 to 2, after replacing the magnesium silicate / chitosan composite nanoparticles with magnesium silicate particles and chitosan particles, or replacing the hydrogen peroxide in the fracturing fluid with water, the daily oil production of the oil field decreased significantly. This may be because the plugging effect is deteriorated and the fracturing fluid cannot fully act on the formation during fracturing. Therefore, the water plugging agent and fracturing fluid components selected in Example 1 are better.

[0073] Experimental Example 2: Investigating the effect of nitrogen injection on daily oil production

[0074] Taking Example 1, Examples 6 to 9, and Comparative Example 3 as experimental comparisons, the daily oil production increase under different nitrogen injection amounts is shown in Table 2 below:

[0075] Table 2 Daily oil production increase under different nitrogen injection rates

[0076] Group Daily oil increase t / d Example 1 12.7 Example 6 11.3 Example 7 11.6 Example 8 10.8 Example 9 11.9 Comparative Example 3 8.8

[0077] It can be seen from the data in Table 2 that, compared with Example 1 and Examples 6 to 8, too high or too low initial injection amount of nitrogen, or too high or too low maximum injection amount will lead to a decrease in daily oil increase. This may be because too low nitrogen injection amount will lead to poor fracturing effect, and too high nitrogen injection amount will affect the plugging effect of the water plugging agent. Among them, the daily oil increase of Example 1 is the highest, so the nitrogen injection amount selected in Example 1 is the best;

[0078] Compared with Comparative Example 3, Example 1 shows that when the initial injection amount of nitrogen does not change, the daily oil increase rate is significantly reduced. This may be because the injection amount of nitrogen remains unchanged, which will cause the water plugging agent to fail to properly plug the reservoir pores. Therefore, the nitrogen injection method selected in Example 1 is the best.

[0079] Experimental Example 3: Investigating the effect of injection volume of water plugging agent and fracturing fluid on daily oil production

[0080] Taking Example 1 and Examples 10 to 13 as experimental comparison, the daily oil increase under different injection amounts of water plugging agent and fracturing fluid is shown in Table 3 below:

[0081] Table 3 Daily oil increase at different injection rates of water plugging agent and fracturing fluid

[0082]

[0083]

[0084] It can be seen from the data in Table 3 that, compared with Example 1 and Examples 10 to 13, too high or too low injection amount of the water plugging agent, or too high or too low injection amount of the fracturing fluid will lead to a decrease in the daily oil increase. This may be because the injection amount of the water plugging agent and the fracturing fluid will affect the plugging strength of the water plugging agent. Among them, the daily oil increase in Example 1 is the highest, so the injection amount of the water plugging agent and the fracturing fluid selected in Example 1 is optimal.

[0085] Experimental Example 4: Investigating the effect of preparation parameters of magnesium silicate / chitosan composite nanoparticles on daily oil yield

[0086] Using Example 1, Examples 14 to 17, and Comparative Examples 4 to 5 as experimental comparisons, the daily oil yield of magnesium silicate / chitosan composite nanoparticles under different preparation parameters is shown in Table 4 below:

[0087] Table 4 Daily oil production under different preparation parameters of magnesium silicate / chitosan composite nanoparticles

[0088] Group Daily oil increase t / d Example 1 12.7 Embodiment 14 10.6 Embodiment 15 10.2 Example 16 11.4 Embodiment 17 11.5 Comparative Example 4 8.4

[0089] It can be seen from the data in Table 4 that, compared with Example 1 and Examples 14 to 17, the temperature of the magnesium silicate dispersion is too high or too low, and the addition amount of glutaraldehyde is too high or too low, which will lead to a reduction in the daily oil increase. This may be because the temperature of the magnesium silicate dispersion is too high or too low, which will affect the modification effect of chitosan, and the addition amount of glutaraldehyde is too high or too low, which will affect the bonding strength of the magnesium silicate / chitosan composite nanoparticles. Among them, the daily oil increase of Example 1 is the highest, so the preparation parameters of the magnesium silicate / chitosan composite nanoparticles selected in Example 1 are optimal;

[0090] Compared with Comparative Example 4, Example 1 shows that when the magnesium silicate dispersion is added to the mixed solution at one time, the daily oil increase is significantly reduced. This may be because after the magnesium silicate dispersion is added to the mixed solution at one time, chitosan cannot fully coat the magnesium silicate loaded with azobisisobutylnitrile. Therefore, the preparation parameters of the magnesium silicate / chitosan composite nanoparticles selected in Example 1 are optimal.

Claims

1. A fractured oil reservoir recovery method using targeted water plugging and directional fracturing, characterized in that: The following steps are involved: S1. Inject cement slurry into the formation at a rate of 2-4 L / min for 1-2 hours. After the injection is completed, shut down the well and wait for 20-24 hours for setting. S2. Inject active water into the oil well for test squeezing to check the sealing condition of the wellbore; S3.

1. Inject nitrogen and water plugging agent into the formation. The initial nitrogen injection rate is 1-1.5 L / min, and the nitrogen injection rate is increased at a rate of 0.5-1 L / min. The water plugging agent injection rate is 2-4 L / min. S3.

2. When the injection rate of nitrogen reaches 6-8 L / min, water plugging agent and fracturing fluid are injected into the formation at the same time, and the nitrogen injection rate is kept unchanged for 5-10 minutes; the injection rate of water plugging agent is 0.5-1.5 L / min, and the injection rate of fracturing fluid is 2-3 L / min; S3.3, the nitrogen injection rate is then reduced at a rate of 0.5-1 L / min, and only fracturing fluid is injected into the formation at a rate of 1-2 L / min, until the nitrogen injection rate is reduced to 0, and the injection of fracturing fluid is stopped at the same time, completing the fracturing; S4. After fracturing is completed, oil production is carried out.

2. The method for recovering oil from fractured reservoirs by coordinated targeted water plugging and directional fracturing according to claim 1, characterized in that: The components of the cement slurry include, by weight, 50-60 parts of G-grade cement, 1-5 parts of retarder, 2-4 parts of drag reducer, and 20-30 parts of water.

3. The method for recovering oil from fractured reservoirs by coordinated targeted water plugging and directional fracturing according to claim 1, characterized in that: The components of the water plugging agent include, by weight: 5-15 parts of magnesium silicate / chitosan composite nanoparticles, 20-30 parts of acrylamide, 3-6 parts of sodium dodecyl sulfate, 4-8 parts of initiator, and 40-60 parts of water.

4. The method for recovering oil from fractured reservoirs by coordinated targeted water plugging and directional fracturing according to claim 1, characterized in that: The initiator is a mixture of any one or more of potassium persulfate and ammonium persulfate in any ratio.

5. The method for recovering oil from fractured reservoirs by coordinated targeted water plugging and directional fracturing according to claim 1, characterized in that: The components of the fracturing fluid include, by weight, 10 to 20 parts of quartz sand, 5 to 10 parts of potassium chloride, 1 to 2 parts of hydroxyethyl cellulose, 5 to 8 parts of alkylphenol polyoxyethylene ether, 2 to 5 parts of hydrogen peroxide, and 60 to 65 parts of water.

6. The method for recovering oil from fractured reservoirs by coordinated targeted water plugging and directional fracturing according to claim 3, characterized in that: The preparation method of the magnesium silicate / chitosan composite nanoparticles comprises the following steps: 1) Add nano magnesium silicate into dimethyl sulfoxide, ultrasonically disperse for 5 to 10 minutes, add diisobutylnitrile to the dimethyl sulfoxide under stirring, then heat the dimethyl sulfoxide to 40 to 50° C., keep warm for 30 to 40 minutes, and then filter to obtain magnesium silicate loaded with diisobutylnitrile; wherein the mass ratio of nano magnesium silicate, diisobutylnitrile, and dimethyl sulfoxide is 1:0.2 to 0.4:5 to 7; 2) adding magnesium silicate loaded with azobisisobutylnitrile into deionized water, and ultrasonically dispersing for 5 to 10 minutes to obtain a magnesium silicate dispersion; wherein the mass ratio of magnesium silicate loaded with azobisisobutylnitrile to deionized water is 1:4 to 5; 3) dissolving chitosan in an acetic acid solution having a mass concentration of 3% to 6%, then adding ammonium persulfate to the acetic acid solution, stirring for 10 to 20 minutes, and then adding acrylonitrile monomer to the acetic acid solution to obtain a mixed solution; wherein the mass ratio of chitosan, ammonium persulfate, acrylonitrile monomer, and acetic acid solution is 1:0.1 to 0.2:0.4 to 0.6:3 to 4; 4) The mixed solution is heated to 30-40° C., kept warm for 8-15 minutes, and then the magnesium silicate dispersion at 0-5° C. is slowly added to the mixed solution. During the addition of the magnesium silicate dispersion, after the temperature of the mixed solution drops by 10-15° C., the addition of the magnesium silicate dispersion is stopped, and glutaraldehyde is added to the mixed solution once, and then the mixed solution is reheated to 30-40° C.; wherein the amount of glutaraldehyde added accounts for 0.6% to 1% of the current mass of the mixed solution: 5) Repeat step 4) until the magnesium silicate dispersion is completely added to the mixed solution, let stand for 1 to 2 hours, then filter and wash to obtain magnesium silicate / chitosan composite nanoparticles; wherein the total mass ratio of the mixed solution to the magnesium silicate dispersion is 1:0.7 to 0.

9.

7. A fractured oil reservoir recovery method using targeted water plugging and directional fracturing in coordination according to claim 6, characterized in that: The addition rate of the magnesium silicate dispersion is 70-90 ml / min.

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