An oil displacement system and method for softening water pressure displacement

Abstract

The present application relates to the technical field of oil exploitation, in particular to a kind of oil displacement system and oil displacement method for softened water pressure flooding.The oil displacement system of the present application is composed of oil displacement agent and softened water;The oil displacement agent includes carboxyl betaine and fluorocarbon surfactant;The calcium and magnesium ion content in the softened water is ≤50mg / L, HCO3 – Ion concentration ≤300mg / L;The pH value of the softened water is 10-11.The softened water has synergistic effect with the surfactant of low interfacial tension, and the interfacial tension of the obtained oil displacement system is as low as 3.6×10 ‑3 mN / m.The total recovery rate of oil displacement using the oil displacement system of the present application can be as high as 85.23%.Using the oil displacement method of the present application, the oil displacement system for softened water pressure flooding does not scale in high-temperature (120-160℃) low-permeability reservoirs, and can effectively improve oil production.

Description

Technical Field

[0001] This invention relates to the field of petroleum extraction technology, specifically to a softened water pressure displacement system and method for oil displacement. Background Technology

[0002] The Shengli Oilfield has 880 million tons of exploitable reserves in its low-permeability reservoirs. Due to reservoir properties and water injection quality, these reservoirs generally suffer from high injection pressure and a high under-injection rate, preventing effective displacement in oil and water wells and leading to rapid production decline. To replenish formation energy, high-pressure water injection, pressure-driven water injection, and well-to-well percolation have been employed in recent years with good results. However, the large water consumption, averaging 2-7 × 10⁻⁶ tons per well for pressure-driven water injection and well-to-well percolation, remains a significant challenge. 4 m 3 Due to limitations in water source and water treatment technology, some high-temperature, low-permeability oil reservoirs still use unsoftened produced water for injection. This leads to problems such as incompatibility between the injected water and the formation, resulting in scaling and other reservoir damage. It is necessary to improve the evaluation and analysis methods for scale formation in injected water under high-temperature conditions and solve the problem of scale formation in high-temperature formations. Since 2003, Zhuangxi Oilfield has been applying a chemical softening water fine treatment process with a treatment capacity of 500m³. 3 / d, by 2010, a chemical softening water fine treatment process with a treatment capacity of 5000m³ was completed. 3 / d, actual processing capacity 3800m³ 3 / d(Annual water injection volume 140×10 4 m 3 After field application, it has shown good results in preventing corrosion and scaling of surface processes and downhole tubing, and avoiding formation scaling. However, there are still insufficient understandings regarding the accurate analysis of the scaling amount of softened water under formation conditions (high temperature 120-160℃, high pressure 35-70MPa), the effect of pH value on oil displacement efficiency, and the dissolution of reservoir minerals. This results in the need to adjust the pH value of the softened water after alkali addition from 10-11 to 8.5-9.5 with hydrochloric acid, leading to insufficient utilization of NaOH. At the same time, other high-temperature and low-permeability reservoirs in Shengli Oilfield have serious scaling problems with produced water and weakly alkaline (modified water pH=8.5), which severely restricts the application of pressure flooding, percolation, alkali flooding, and combined alkali and surfactant flooding in low-permeability reservoirs.

[0003] Chinese invention patent CN113880263A discloses a modified wastewater induced scaling device and treatment method, which includes an induced scaling pipe, a compensation pipe, a straight pipe, two curved pipes, two reducing joints, a corrugated expansion pipe, and valves. One end of the induced scaling pipe is sequentially connected to the first reducing joint, the corrugated expansion pipe, the first curved pipe, and the straight pipe; the other end of the induced scaling pipe is sequentially connected to the compensation pipe, the second reducing joint, the second curved pipe, and the straight pipe. A valve is provided at the connection between the first curved pipe and the corrugated expansion pipe, a valve is provided at the connection between the second curved pipe and the second reducing joint, and a valve is provided on the straight pipe. This invention induces the precipitation of scale-forming ions, fundamentally reducing the content of scale-forming ions and reducing the tendency of water to scale. However, its reduction in the number of scale-forming ions is limited, and it cannot significantly reduce the amount of scaling in the formation. Furthermore, frequent descaling treatment of the induced scaling device is required, which is not conducive to its application in large-scale wastewater treatment systems.

[0004] Chinese invention patent CN103224777B discloses a weak-base ternary composite oil displacement composition with a compound surfactant and its application. The ternary composite oil displacement composition includes: a compound surfactant, which is a mixture of petroleum sulfonate and heavy alkylbenzene sulfonate in a 3:1 weight ratio; 0.4% sodium carbonate and 0.6% sodium chloride; and a polymer. However, existing weak-base ternary composite systems suffer from severe scaling at the injection end and in the downhole tubing, significantly affecting the injection process and injection rate, increasing descaling costs, and causing scaling in the formation. Scaling is particularly severe in high-temperature, low-permeability reservoirs, leading to a certain degree of reduction in oil recovery.

[0005] CN115093351A discloses a modified betaine-type gemini surfactant. This modified betaine-type gemini surfactant molecule has two positively charged centers and four anionic groups, making it overall negatively charged. Therefore, it can effectively reduce formation adsorption. The product is easily soluble in water, exhibits good interfacial tension properties, and has a low critical micelle concentration, making it suitable for oil displacement in high-temperature, high-salinity reservoirs. However, the preparation process of this modified betaine-type gemini surfactant is complex, and the production cost is high.

[0006] The applicant's prior patent application, "A High-Hardness Oilfield Produced Water Softening Treatment System and Method," discloses a method for preparing softened water. This method produces softened water with low scaling rate and minimal formation damage. However, how to effectively apply this softened water to oilfield development remains a pressing issue. Summary of the Invention

[0007] To address the aforementioned problems, this invention provides a softened water pressure flooding system and method for oil displacement. The method of this invention can effectively utilize softened water for pressure flooding and significantly improve oil recovery.

[0008] To achieve the above objectives, the present invention adopts the following technical solution:

[0009] In a first aspect, this invention provides an oil displacement system for pressure-driven softened water, the system comprising an oil displacement agent and softened water; the oil displacement agent comprising carboxyl betaine and fluorocarbon surfactant; the softened water having a calcium and magnesium ion content ≤50 mg / L, and the softened water containing HCO3- – The ion concentration is ≤300mg / L; the pH value of the softened water is 10-11.

[0010] Furthermore, the calcium and magnesium ion content in the softened water is 10-50 mg / L.

[0011] Furthermore, the mass ratio of the carboxylated betaine to the fluorocarbon surfactant is 500-1000:0.3-5.

[0012] In a second aspect, the present invention provides a method for water-pressure water injection to displace oil using softened water, the method comprising the following steps:

[0013] At least two slugs are injected into the softened water pressure drive oil displacement system described in the first aspect above;

[0014] At least one slug is used to inject softened water, wherein the calcium and magnesium ion content in the softened water is ≤50 mg / L and the HCO3 content is ≤50 mg / L. – The ion concentration is ≤300mg / L; the pH value of the softened water is 10-11.

[0015] Compared with the prior art, the present invention has the following advantages:

[0016] This invention uses softened water in combination with the oil displacement agent and performs pressure-driven water injection. The softened water used has a calcium and magnesium ion content ≤50 mg / L and HCO3 content ≤50 mg / L. – The ion concentration is ≤300 mg / L; within this concentration range, the softened water exhibits good compatibility with the formation, low scaling rate, and minimal damage to core permeability; the pH value of the softened water is 10-11, and electron microscopy analysis of core samples before and after testing within this pH range shows significant dissolution of previously unseen formation minerals and the appearance of mineral erosion, separation, and migration; furthermore, utilizing the low concentration of alkali in the softened water for oil displacement not only saves the cost of hydrochloric acid neutralization in wastewater treatment but also improves oil displacement efficiency; this invention effectively utilizes a large amount of softened water after oilfield wastewater softening treatment, saving the cost of preparing pressure displacement solutions with clean water, and solving the production problem of scaling and corrosion of oilfield wastewater in high-temperature, low-permeability oilfields. On the other hand, this invention discovers a synergistic effect between the softened water and a low-interfacial-tension surfactant, resulting in an oil displacement system with an interfacial tension as low as 3.6 × 10⁻⁶. -3 mN / m. The total oil recovery rate using the oil displacement system described in this invention can reach up to 85.23%.

[0017] The oil recovery method described in this invention can effectively increase oil production, with a maximum increase of 6,254 tons per well group. Attached Figure Description

[0018] Figure 1 Experiment on the evaluation of soft water core volumetric flow rate at pH = 10⁻¹¹

[0019] Figure 2 The core clay minerals showed no obvious dissolution or particle migration after softening with water at pH 10 and 11: the left image corresponds to softened water at pH 10; the right image corresponds to softened water at pH 11.

[0020] Figure 3 Correspondence diagram of injection and production in well group 606-4 (slanted well);

[0021] Figure 4 Diagram showing the pressure drive construction parameters for Well 606-4 (Pile 606-Inclined 4);

[0022] Figure 5 Pile 606-Inclined 4-Pressure Drive Injection of Softened Sewage (40,000 cubic meters) and Oil Pipeline Diagram

[0023] Figure 6 Diagram showing scale buildup in the tubing after well 606-9 produced 52,000 cubic meters of water.

[0024] Figure 7 After injecting 83,000 cubic meters of water during the pressure drive of pile 74-9-7, scale formation occurred in the oil pipe.

[0025] Figure 8 Diagram showing the pressure drive construction parameters for well 59-44 (inclination).

[0026] Figure 9 Diagram showing the pressure drive construction parameters for Well 601-2 (Pile 601-Inclined 2);

[0027] Figure 10 Diagram showing the pressure drive construction parameters for well 74-12-2;

[0028] Figure 11 Diagram showing the pressure drive construction parameters for well 74-9-7;

[0029] Figure 12 Curve showing the change in surface tension of EAO aqueous solution with EAO concentration;

[0030] Figure 13 Determination of critical micelle concentration of EAO and fluorocarbon composite solution. Detailed Implementation

[0031] It should be noted that the following detailed descriptions are exemplary and intended to provide further illustration of the invention. Unless otherwise specified, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this invention pertains.

[0032] It should be noted that the terminology used herein is for the purpose of describing particular embodiments only and is not intended to limit the exemplary embodiments of the present invention. As used herein, unless the context clearly indicates otherwise, the singular form is also intended to include the plural form. Furthermore, it should be understood that when the terms "comprising" or "including" are used in this specification, they indicate the presence of features, steps, operations, and combinations thereof.

[0033] In a first aspect, this invention provides an oil displacement system for pressure-driven softened water, the system comprising an oil displacement agent and softened water; the oil displacement agent comprising carboxyl betaine and fluorocarbon surfactant; the softened water having a calcium and magnesium ion content ≤50 mg / L, and the softened water containing HCO3- – The concentration is ≤300mg / L, and the pH value of the softened water is 9-11.

[0034] This invention uses softened water with a calcium and magnesium ion content of 14 mg / L and pH values ​​of 10 and 11 to conduct core flow simulation experiments. After long-term injection of source water into the core, the permeability continuously decreased with increasing injection ratio, but the decrease was small. At 120 times injection, the permeability decreased by 29.2% and 22.8% respectively, with an average of 26%, as shown in Table 1 and 2. Figure 1 As shown.

[0035] Table 1 Evaluation results of softened water damage tests at pH=11 and pH=10

[0036]

[0037] The average permeability decreased by 17% after long-term injection of simulated formation water (120 times the pore volume). After deducting the effect of simulated formation water damage, the permeability damage caused by softened water with pH=10-11 was less than 9%, which is considered a weak damage to the reservoir rock.

[0038] Electron microscopy analysis was performed on feldspar, kaolinite, and montmorillonite in core samples before and after softening with water at pH 10 and pH 11. No significant dissolution, erosion, separation, or migration of the formation minerals was observed (see [link to analysis]). Figure 2 Therefore, when softened water and surfactants are used together for oil displacement, the pH value can be controlled to 10-11, making full use of the low concentration of alkali in the softened water for oil displacement.

[0039] In a preferred embodiment of the present invention, the calcium and magnesium ion content in the softened water is 10-50 mg / L.

[0040] In a preferred embodiment of the present invention, the mass ratio of the carboxylated betaine to the fluorocarbon surfactant is 500-1000:0.3-5.

[0041] The carboxylated betaine of the present invention includes, but is not limited to, any one or more of dodecylamidopropyl hydroxypropyl sulfobetaine, tetradecylamidopropyl hydroxypropyl sulfobetaine, hexadecylamidopropyl hydroxypropyl sulfobetaine, and erucamide hydroxypropyl sulfobetaine.

[0042] The fluorocarbon surfactants described in this invention include, but are not limited to, nonionic fluorocarbon surfactants Ee507T or Ee602T.

[0043] In a second aspect, the present invention provides a method for water-pressure water injection to displace oil using softened water, the method comprising the following steps:

[0044] At least two slugs are injected into the softened water pressure drive oil displacement system described in the first aspect above;

[0045] At least one slug is injected with softened water, wherein the concentration of calcium and magnesium ions in the softened water is ≤50 mg / L.

[0046] As a preferred embodiment of the present invention, at least four plugs are injected. The first plug is injected with an anti-swelling agent, the second and third plugs are injected with the softened water pressure drive oil displacement system described in the first aspect above, and the fourth plug is injected with softened water.

[0047] As a preferred embodiment of the present invention, at least five stages are injected. The first stage is injected with slow-release nitric acid, the second stage is injected with an anti-swelling agent, the third and fourth stages are injected with the softened water pressure drive oil displacement system described in the first aspect above, and the fifth stage is injected with softened water.

[0048] In a preferred embodiment of the present invention, the injection displacement of each plug segment is controlled at 0.8-1.5m. 3 / min.

[0049] In a preferred embodiment of the present invention, the cumulative injection volume of a single well via pressure drive is 30,000 m³. 3 -90000m 3 .

[0050] To enable those skilled in the art to better understand the technical solution of the present invention, the technical solution of the present invention will be described in detail below with reference to specific embodiments.

[0051] The slow-release nitric acid and anti-swelling agent used in the following embodiments of the present invention are all commercially available products. The preparation of the softened water can be carried out in accordance with the method described in the patent "A High-Hardness Oilfield Produced Water Wastewater Softening Treatment System and Treatment Method" (CN114455737A).

[0052] Example 1

[0053] A softened water oil displacement system for pressure drive, the system comprising an oil displacement agent and softened water.

[0054] The oil displacement agent is composed of hexadecylamidopropyl hydroxypropyl sulfobetaine and nonionic fluorocarbon surfactant Ee602T in a mass ratio of 1000:1. The softened water has a calcium and magnesium ion content of 20 mg / L and an HCO3 content of... – The concentration is 300 mg / L, and the pH value is 11.

[0055] Example 2

[0056] A softened water oil displacement system for pressure drive, the system comprising an oil displacement agent and softened water.

[0057] The oil displacement agent is composed of erucamide hydroxypropyl sulfobetaine and nonionic fluorocarbon surfactant Ee507T in a mass ratio of 900:0.3. The softened water has a calcium and magnesium ion content of 50 mg / L and an HCO3 content of... – The concentration is 300 mg / L, and the pH value is 10.

[0058] Example 3

[0059] A softened water oil displacement system for pressure drive, the system comprising an oil displacement agent and softened water.

[0060] The oil displacement agent is composed of erucamide hydroxypropyl sulfobetaine and nonionic fluorocarbon surfactant Ee507T in a mass ratio of 900:1. The softened water has a calcium and magnesium ion content of 32 mg / L and HCO3- content of... – The concentration was 235 mg / L, and the pH value was 10.5.

[0061] Example 4

[0062] A softened water oil displacement system for pressure drive, the system comprising an oil displacement agent and softened water.

[0063] The oil displacement agent is composed of tetradecylamidopropylhydroxypropylsulfobetaine and nonionic fluorocarbon surfactant Ee602T in a mass ratio of 1000:0.3. The softened water has a calcium and magnesium ion content of 40 mg / L and an HCO3 content of... – The concentration was 248 mg / L, and the pH value was 10.2.

[0064] Example 5

[0065] A softened water oil displacement system for pressure drive, the system comprising an oil displacement agent and softened water.

[0066] The oil displacement agent, dodecylamidopropyl hydroxypropyl sulfobetaine, is composed of a nonionic fluorocarbon surfactant, Ee602T, at a mass ratio of 1000:0.5. The softened water has a calcium and magnesium ion content of 43 mg / L and an HCO3 content of...– The concentration was 226 mg / L, and the pH value was 10.6.

[0067] Example 6

[0068] A softened water oil displacement system for pressure drive, the system comprising an oil displacement agent and softened water.

[0069] The oil displacement agent is composed of dodecylamidopropyl hydroxypropyl sulfobetaine and nonionic fluorocarbon surfactant Ee602T in a mass ratio of 1000:0.6. The softened water has a calcium and magnesium ion content of 39 mg / L and an HCO3 content of... – The concentration was 258 mg / L, and the pH value was 11.

[0070] Example 7

[0071] A method for water pressure-driven oil displacement using softened water, the method comprising the following steps:

[0072] The first plug is injected with an anti-swelling and anti-swelling agent, the second plug is injected with the softened water pressure drive oil displacement system described in Example 1, the third plug is injected with the softened water pressure drive oil displacement system described in Example 1, and the fourth and fifth plugs are injected with softened water respectively.

[0073] The following uses the pressure-driven water injection method of well 606-4 as an example to illustrate the method in detail:

[0074] Analysis of water injection situation in well 606-4: Due to poor reservoir properties and the inability to inject water into the well, the formation energy cannot be replenished. Flexible development is adopted. The energy in the near-wellbore zone is decreasing rapidly and significantly. The formation static pressure has dropped from 55.3 MPa at the beginning of development in 2004 to the current 20.1 MPa, resulting in a serious shortage of fluid supply to the oil well.

[0075] The production formation of Well 606-4 is S4, with perforated sections of 3723.0-3730.0m and 3731.0-3741.0m, a perforation thickness of 17m, a porosity of 12.5%, and a permeability of 6.5×10⁻⁶. -3 μm 2 The injection-production correspondence of well group 606-Xiang4 (see...) Figure 3 (This corresponds to 7 oil wells, and the average formation fracture pressure in this block is 72 MPa.)

[0076] Design pressure-driven water injection capacity: 4×10 4 m 3 Design displacement 0.2-1.5m³ 3 / min, designed with five slugs, using a variable displacement injection method, which easily forms wide short slits, is more conducive to balanced displacement and expands the affected area.

[0077] The first stage involves injecting 1500 m³ of 5% anti-swelling and shrinkage-inhibiting agent to pre-treat the formation and prevent clay expansion. A trial injection with increased discharge rate is then conducted to determine injection parameters such as formation water absorption capacity and formation fracturing pressure.

[0078] The second stage of the plug injection uses a 1% mass concentration oil displacement system for pressure drive as described in Example 1, with a capacity of 6000 m³ and a displacement of 1.5-0.2 m³. 3 At a rate of / min, the injection rate is reduced, and the pressure diffusion is observed. At the same time, wide and short fractures are formed in the formation, and a higher concentration of oil displacement agent is quickly delivered to the remaining oil-rich area through the fractures. While fracturing and creating fractures, the agent is filtered up and down along the process, and the oil displacement agent is quickly filled into the pores, reducing the contact time and contact distance between the chemical agent and the formation, and improving the oil displacement efficiency.

[0079] The third stage of the plug injection uses a 3000 m³ pressure drive oil displacement system described in Example 1, with a mass concentration of 0.5% and a displacement of 0.2-1.5 m³. 3 / min, increasing the injection rate increases fracture length and forms a three-dimensional network of fractures, while restoring formation energy and reducing the oil displacement system concentration to 0.5%, which is a relatively high concentration for the second-stage plug. The oil displacement system has effectively cleaned and stripped some of the crude oil in the pores, which can reduce the cost of the oil displacement system while ensuring oil displacement efficiency.

[0080] The fourth stage of the plug injection process involves injecting 18,000 m³ of softened water. 3 1.5m displacement 3 The high-volume, stable injection at a rate of / min further expands the fracture length and width, and rapidly restores formation energy. The softened water used is the same as that used in the oil displacement system of Example 1.

[0081] The fifth stage of the plug injects 11,500 m³ of softened water, with a discharge rate of 1.0-1.5 m³ / h. 3 / min, first inject at a large displacement, then inject at a variable displacement to expand the affected area and rapidly restore formation energy. The softened water used is the same as that used in the oil displacement system of Example 1. A total of 40,000 m³ was injected using the above five plug stages. 3 .

[0082] Construction of well 606-4 (inclined shaft) lasted 48 days. The pump pressure increased from 32.5 MPa to 45.9 MPa, with a cumulative injection of 40,096 m³. Construction parameter curves (see...) Figure 4 After injecting 40,000 cubic meters of softened wastewater into pile 606-4 via pressure drive, the 3,000-3,650m of tubing was pulled out without scaling, indicating that the formation was also free of scaling. This demonstrates that the pressure drive injection of softened water did not cause scaling or blockage in the formation (see...). Figure 5 ). Figure 6The image shows the scale buildup in the tubing after injecting 52,000 cubic meters of unsoftened water during normal production at well 606-9. The scale buildup in the tubing is 10-20 mm at a well depth of 3130-3580 m, indicating that there is also a serious scaling problem in the formation of this well.

[0083] from Figure 4 As can be seen, calculations indicate an injection displacement of 1.0-1.5 m³. 3 When the downhole pressure-driven tubing loss is 2 MPa and the surface pump pressure is 36.6 MPa, the bottomhole pressure = pump pressure - tubing loss + hydrostatic pressure = 36.6 - 2 + 37.4 = 72 MPa. The formation reaches the fracturing pressure, and pressure-driven injection reaches 500 m³. 3 Subsequently, the formation fracture pressure reached 72 MPa, and injections were subsequently carried out at pressures 5.4 MPa to 9.3 MPa higher than the fracture pressure.

[0084] After implementation, the 606-Xiang4 well group has a total of 7 oil wells, with a cumulative increase of 6,254 tons of oil, as shown in Table 2 below.

[0085] Table 2 shows the oil enhancement effect of pressure drive in the 606-4 well group.

[0086]

[0087]

[0088] Example 8

[0089] A method for water pressure-driven oil displacement using softened water, the method comprising the following steps:

[0090] The first plug injects an anti-swelling agent, the second plug injects the softened water pressure displacement system described in Example 4, the third plug injects the softened water pressure displacement system described in Example 4, and the fourth plug injects softened water. The softened water is the same as that used in the oil displacement system of Example 4.

[0091] The following uses the pressure-driven water injection method of well 59-44 as an example to illustrate the method in detail:

[0092] The production formation of well 59-44 is S-low II3-5. The perforated sections are 3643.8-3646.4m, 3654.0-3656.0m, 3658.0-3660.0m, 3669.2-3674.2m, 3678.2-3681.3m, 3683.5-3686.1m, and 3687.9-3694.6m. The perforation thickness is 24m, the porosity is 12.1%, and the permeability is 5.9×10⁻⁶. -3 μm 2 Well 59-44 corresponds to 6 oil wells, and the average formation fracture pressure in this block is 71 MPa.

[0093] The design pressure-driven water injection capacity is 4.0 × 10⁻⁶. 4 m 3 Design displacement 1.5m 3 / min, the design of the four-stage slug is adopted, and the injection is carried out in a constant displacement manner to form long cracks and expand the affected area.

[0094] The first stage involves injecting 500 m³ of a 7% (w / w) high-efficiency anti-swelling agent to pre-treat the formation and prevent clay expansion. The discharge rate is 1.5 m³. 3 / min, to determine injection parameters such as formation water absorption capacity and formation fracturing pressure.

[0095] The second stage of the plug injection uses a 2% mass concentration oil displacement system for pressure drive as described in Example 4, with a capacity of 4000 m³ and a displacement of 1.5 m³. 3 The high-concentration oil displacement agent is rapidly delivered to the remaining oil-rich area through the fracture at a rate of / min. While fracturing and creating fractures, it is filtered up and down along the process, quickly filling the pores with the oil displacement agent, reducing the contact time and contact distance between the chemical agent and the formation, and improving the oil displacement efficiency.

[0096] The third-stage plug injection concentration is 0.5% in the pressure drive oil displacement system described in Example 4, with a capacity of 4800 m³ and a displacement of 1.5 m³. 3 / min, constant flow rate injection, increases fracture length, restores formation energy, and reduces the oil displacement system concentration to 0.5%, which is a relatively high concentration for the second-stage plug. The oil displacement system has effectively cleaned and stripped some of the crude oil in the pores, which can reduce the cost of the oil displacement system while ensuring oil displacement efficiency.

[0097] The fourth stage of the plug injection involves 30,700 m³ of softened water. 3 1.5m displacement 3 / min, large-volume stable injection, further expands fracture length and width, and rapidly restores formation energy.

[0098] During the construction of pile 59-inclined well 44, the pump pressure increased from 35.3 MPa to 40.7 MPa, with a cumulative injection of 40,613 m³. Construction parameter curves (see...) Figure 8 ),from Figure 8 As can be seen from the calculations, the injection displacement is 1.5m³. 3 When the downhole pressure-driven tubing loss is 2 MPa and the surface pump pressure is 36.2 MPa, the bottomhole pressure = pump pressure - tubing loss + hydrostatic pressure = 36.2 - 2 + 36.8 = 71 MPa. The formation reaches the fracturing pressure. The injection rate during on-site construction is 1.4-1.6 m³ / min. 3 / min, pressure-driven injection 1050m 3 Subsequently, the formation fracturing pressure reached 71 MPa, and injections were subsequently carried out at pressures 1 MPa to 4.5 MPa higher than the formation fracturing pressure.

[0099] The peak oil production increased by 18.7 tons, with 6 wells becoming effective, resulting in a cumulative oil production increase of 1,722 tons.

[0100] Example 9

[0101] A method for water pressure-driven oil displacement using softened water, the method comprising the following steps:

[0102] The first stopper is injected with slow-release nitric acid; the second stopper is injected with an anti-swelling agent; the third stopper is injected with the softened water pressure displacement system described in Example 5; the fourth stopper is injected with the softened water pressure displacement system described in Example 5; and the fifth stopper is injected with softened water. The softened water used is the same as that used in the oil displacement system of Example 5.

[0103] The following uses the pressure-driven water injection method of well 601-2 as an example to explain the method in detail:

[0104] The production formation of Well 601-Slant 2 is located in Lower II of Formation S. The perforated sections are 3739.7-3744.0m, 3744.8-3751.6m, 3755.9-3758.2m, and 3759.6-3763.0m, with a perforation thickness of 16.8m, a porosity of 14.34%, and a permeability of 17.2 × 10⁻⁶ m. -3 μm 2 Well 601-2 corresponds to 6 oil wells. The average formation fracture pressure in this block is 72 MPa. The designed pressure-driven water injection volume is 5.84 × 10⁻⁶. 4 m3, designed displacement 1.5m 3 / min, the design of the five-stage slug is adopted, and the injection is carried out in a constant displacement manner to form long cracks and expand the affected area.

[0105] The first stage of injection involves 50 m³ of slow-release nitric acid with a mass concentration of 46%, with a discharge rate of 1.5 m³. 3 / min, to pre-treat blockages in the near-layer of the water well, reduce injection pressure, and improve injection capacity.

[0106] The second stage involves injecting 500 m³ of a 2.8% high-efficiency anti-swelling agent to pre-treat the formation and prevent clay expansion. The discharge rate is 1.5 m³. 3 / min, to determine injection parameters such as formation water absorption capacity and formation fracturing pressure.

[0107] The third-stage plug injection of the pressure-driven oil displacement system described in Example 5, with a mass concentration of 1.5%, resulted in a displacement of 4000 m³ and a displacement of 1.5 m³. 3 The high-concentration oil displacement agent is rapidly delivered to the remaining oil-rich area through the fracture at a rate of / min. While fracturing and creating fractures, it is filtered up and down along the process, quickly filling the pores with the oil displacement agent, reducing the contact time and contact distance between the chemical agent and the formation, and improving the oil displacement efficiency.

[0108] The fifth stage of the oil displacement system for pressure drive described in Example 5, with a mass concentration of 0.5%, has a displacement of 4600 m³ and a displacement of 1.5 m³. 3 / min, constant flow rate injection, increases fracture length, restores formation energy, and reduces the oil displacement system concentration to 0.5%, which is a relatively high concentration for the second-stage plug. The oil displacement system has effectively cleaned and stripped some of the crude oil in the pores, which can reduce the cost of the oil displacement system while ensuring oil displacement efficiency.

[0109] The fifth stage of the plug injected 49,250 m³ of softened water. 3 1.5m displacement 3 A high-volume, stable injection rate of [ / min] further expands the fracture length and width, and rapidly restores formation energy. The softened water used is the same as that used in the oil displacement system of Example 5.

[0110] During the construction of pile 601-inclined well 2, the construction pump pressure increased from 38.2 MPa to 47.9 MPa, with a cumulative injection of 58,412 m³. Construction parameter curves (see...) Figure 9 ),from Figure 9 As can be seen from the calculations, the injection displacement is 1.5m³. 3 When the downhole pressure-driven tubing loss is 2 MPa and the surface pump pressure is 36.4 MPa, the bottomhole pressure = pump pressure - tubing loss + hydrostatic pressure = 36.4 - 2 + 37.6 = 72 MPa. The formation reaches the fracturing pressure, and the injection rate is 1.3-1.6 m³ / min. 3 / min, pressure-driven injection 500m 3 Subsequently, the formation fracturing pressure reached 71 MPa, and injections were subsequently carried out at pressures 5.8 MPa to 11.5 MPa higher than the formation fracturing pressure.

[0111] Peak oil production increased by 7.99 tons, with 6 wells becoming effective, resulting in a cumulative oil production increase of 1,850 tons.

[0112] Example 10

[0113] A method for water pressure-driven oil displacement using softened water, the method comprising the following steps:

[0114] The first stopper is injected with slow-release nitric acid; the second stopper is injected with an anti-swelling agent; the third stopper is injected with the softened water pressure displacement system described in Example 6; the fourth stopper is injected with the softened water pressure displacement system described in Example 6; and the fifth stopper is injected with softened water. The softened water used is the same as that used in the oil displacement system of Example 6.

[0115] The following uses the pressure-driven water injection method of well 74-12-2 as an example to explain the method in detail:

[0116] Well 74-12-2 has a production formation in the lower S-II1-5 layer. The perforated sections are 3474.4-3483.0m, 3493.5-3496.3m, 3497.5-3505.5m, 3512.0-3527.9m, 3538.1-3540.1m, 3541.6-3543.6m, 3548.1-3550.8m, and 3580.0-3584.0m. The perforation thickness is 46m, the porosity is 14.35%, and the permeability is 32.6 × 10⁻⁶. -3 μm 2 Well 74-12-2 corresponds to 5 oil wells. The average formation fracture pressure in this block is 69 MPa. The designed pressure-driven water injection volume is 7.14 × 10⁻⁶. 4 m3, designed displacement 1.5m 3 / min, the design of the five-stage slug is adopted, and the injection is carried out in a constant displacement manner to form long cracks and expand the affected area.

[0117] The first stage of injection involves 50 m³ of slow-release nitric acid with a mass concentration of 46%, with a discharge rate of 1.5 m³. 3 / min, to pre-treat blockages in the near-layer of the water well, reduce injection pressure, and improve injection capacity.

[0118] The second stage involves injecting 500 m³ of a 2.8% anti-swelling agent to pre-treat the formation and prevent clay expansion. The discharge rate is 1.5 m³. 3 / min, to determine injection parameters such as formation water absorption capacity and formation fracturing pressure.

[0119] The third-stage plug injection of the pressure-driven oil displacement system described in Example 6, with a mass concentration of 1.5%, results in a displacement of 5500 m³ and a displacement of 1.5 m³. 3 The high-concentration oil displacement agent is rapidly delivered to the remaining oil-rich area through the fracture at a rate of / min. While fracturing and creating fractures, it is filtered up and down along the process, quickly filling the pores with the oil displacement agent, reducing the contact time and contact distance between the chemical agent and the formation, and improving the oil displacement efficiency.

[0120] The fourth stage of the plug injection uses a pressure-driven oil displacement system of 5600 m³ with a mass concentration of 0.5% and a displacement of 1.5 m³. 3 / min, constant flow rate injection, increases fracture length, restores formation energy, and reduces the oil displacement system concentration to 0.5%, which is a relatively high concentration for the second-stage plug. The oil displacement system has effectively cleaned and stripped some of the crude oil in the pores, which can reduce the cost of the oil displacement system while ensuring oil displacement efficiency.

[0121] The fifth stage of the plug injected 59,750 m³ of softened water. 3 1.5m displacement 3A high-volume, stable injection rate of [ / min] further expands the fracture length and width, and rapidly restores formation energy. The softened water used is the same as that used in the oil displacement system of Example 6.

[0122] During the construction of pile 74-12-2, the pump pressure increased from 36.3 MPa to 43.1 MPa, with a cumulative injection of 71,495 m³. 3 Construction parameter curves (see) Figure 10 ),from Figure 10 As can be seen from the calculations, the injection displacement is 1.5m³. 3 When the downhole pressure-driven tubing loss is 2 MPa and the surface pump pressure is 35.2 MPa, the bottomhole pressure = pump pressure - tubing loss + hydrostatic pressure = 35.2 - 2 + 35.8 = 69 MPa. The formation reaches the fracturing pressure, and the on-site injection rate is 1.0 m³ / min. 3 / min, pressure-driven injection 2600m 3 Subsequently, the formation fracturing pressure reached 69 MPa, and injections were subsequently carried out at pressures 1.0 MPa to 7.9 MPa higher than the formation fracturing pressure.

[0123] The peak oil production was 18.91 tons, with 5 wells becoming effective, resulting in a cumulative oil production increase of 1,864 tons.

[0124] Comparative Example 1

[0125] An oil displacement system using produced water (exported wastewater from the Zhuangxi Joint Station, unsoftened water) for pressure displacement, the system consisting of an oil displacement agent and produced water.

[0126] The oil displacement agent is composed of carboxylated betaine and fluorocarbon surfactant in a mass ratio of 1000:0.5. The produced water has a calcium and magnesium ion content of 245 mg / L and an HCO3 content of... – The concentration was 970 mg / L, and the pH value was 7.3.

[0127] A method for producing water pressure-driven water injection oil displacement, the method comprising the following steps:

[0128] The first stage of the plug injection involves slow-release nitric acid; the second stage involves injecting an anti-swelling agent; the third stage involves injecting the produced water into the pressure drive system; the fourth stage involves injecting the produced water into the pressure drive system; and the fifth stage involves injecting the produced water. The produced water has a calcium and magnesium ion content of 245 mg / L and an HCO3- concentration of... – The concentration was 970 mg / L, and the pH value was 7.3.

[0129] The following uses the pressure-driven water injection method of well 74-9-7 as an example to explain the method in detail:

[0130] Well 74-9-7 has a production formation in the lower S-II2-5 layer. The perforated sections are 3459.6-3466.8m, 3526.6-3532.0m, 3536.0-3539.0m, 3558.6-3568.4m, 3575.0-3579.0m, 3582.0-3584.0m, 3591.8-3596.0m, 3601.6-3606.0m, 3619.0-3621.0m, and 3623.0-3627.0m. The perforation thickness is 46m, the porosity is 14.9%, and the permeability is 39.4 × 10⁻⁶. -3 μm 2 Well 74-12-2 corresponds to 3 oil wells, and the average formation fracture pressure in this block is 70 MPa.

[0131] The designed pressure-driven water injection capacity is 8.27 × 10⁻⁶. 4 m 3 Design displacement 1.5m 3 / min, the design of the five-stage slug is adopted, and the injection is carried out in a constant displacement manner to form long cracks and expand the affected area.

[0132] The first stage of injection involves 65 m³ of slow-release nitric acid with a mass concentration of 46%, with a discharge rate of 1.5 m³. 3 / min, to pre-treat blockages in the near-layer of the water well, reduce injection pressure, and improve injection capacity.

[0133] The second stage involves injecting 500 m³ of a 2.8% anti-swelling agent to pre-treat the formation and prevent clay expansion. The discharge rate is 1.5 m³. 3 / min, to determine injection parameters such as formation water absorption capacity and formation fracturing pressure.

[0134] The third stage of the oil displacement system described in Comparative Example 1, with a mass concentration of 1.0%, was injected into a 6000 m³ oil displacement system with a displacement of 1.5 m³. 3 The high-concentration oil displacement agent is rapidly delivered to the remaining oil-rich area through the fracture at a rate of / min. While fracturing and creating fractures, it is filtered up and down along the process, quickly filling the pores with the oil displacement agent, reducing the contact time and contact distance between the chemical agent and the formation, and improving the oil displacement efficiency.

[0135] The fifth stage of the oil displacement system described in Comparative Example 1, with a mass concentration of 0.5%, was injected into a 5200 m³ displacement system with a displacement of 1.5 m³. 3 / min, constant flow rate injection, increases fracture length, restores formation energy, and reduces the oil displacement system concentration to 0.5%, which is a relatively high concentration for the second-stage plug. The oil displacement system has effectively cleaned and stripped some of the crude oil in the pores, which can reduce the cost of the oil displacement system while ensuring oil displacement efficiency.

[0136] The fifth stage of plug injection produced 70,935 m³ of water. 31.5m displacement 3 The high-volume, stable injection rate ( / min) further expands the fracture length and width, and rapidly restores formation energy. The produced water contains 245 mg / L of calcium and magnesium ions and HCO3-. – The concentration was 970 mg / L, and the pH value was 7.3.

[0137] During the construction of well 74-9-7, the pump pressure increased from 34.5 MPa to 38.5 MPa, with a cumulative injection of 83,000 m³. 3 Construction parameter curves (see) Figure 11 ),from Figure 11 As can be seen from the calculations, the injection displacement is 1.5m³. 3 When the downhole pressure-driven tubing loss is 2 MPa and the surface pump pressure is 35.7 MPa, the bottom hole pressure = pump pressure - tubing loss + hydrostatic pressure = 35.7 - 2 + 36.3 = 70 MPa. The formation reaches the fracturing pressure, and the on-site injection rate is 0.9-1.6 m³ / min. 3 / min, pressure-driven injection 45000m 3 Subsequently, the formation fracturing pressure reached 70 MPa, and injections were then carried out at pressures 1.0 MPa to 2.8 MPa higher than the formation fracturing pressure.

[0138] After draining a total of 83,000 cubic meters, the oil tubing was pulled out. Scale buildup of 2-5 mm was found on 3000-3650m of tubing, indicating a certain degree of scaling in the formation (see...). Figure 7 ).

[0139] The peak oil production was 10.1 tons, with 3 wells becoming effective, resulting in a cumulative oil production increase of 84.53 tons.

[0140] Figure 7 This image shows the tubing scaling after injecting 83,000 cubic meters of produced water (unsoftened water from the pile's western joint) during pressure drive of well 74-9-7. The scaling, ranging from 2-5 mm in length, is visible in the 3000-3650m tubing. This indicates significant scaling in the downhole tubing during the 45 days of pressure drive water injection. Analysis suggests that the use of unsoftened water from the pile's western joint during pressure drive resulted in some scaling and blockage in the formation, reducing the permeability of the fractures generated by the pressure drive. Subsequent injection of unsoftened water would also lead to scaling and blockage, further reducing injection capacity and affecting oil displacement. Simultaneously, it caused blockage in the downhole high-temperature stratified tubing packers and water distributors, severely impacting the implementation of the stratified water injection development process. Therefore, using softened water can effectively prevent scaling in the formation and tubing. Injecting softened water and the oil displacement system prepared with it causes less damage to the formation.

[0141] Table 3. Oil Increment Effect of Each Pressure-Drive Water Injection Well Group

[0142]

[0143]

[0144] Comparative Example 2

[0145] An oil displacement system comprising an oil displacement agent and softened water.

[0146] The oil displacement agent is composed of carboxylated betaine and isooctylphenol polyoxyethylene ether OP-10 in a mass ratio of 3:1. The softened water has a calcium and magnesium ion content of 32 mg / L and an HCO3 content of... – The concentration was 235 mg / L, and the pH value was 10.5.

[0147] Comparative Example 3

[0148] An oil displacement system comprising an oil displacement agent and softened water.

[0149] The oil displacement agent is composed of carboxylated betaine and octyl phenol polyoxyethylene ether TX-10 in a mass ratio of 3:1. The softened water has a calcium and magnesium ion content of 32 mg / L and an HCO3 content of... – The concentration was 235 mg / L, and the pH value was 10.4.

[0150] Comparative Example 4

[0151] An oil displacement system comprising an oil displacement agent and softened water.

[0152] The oil displacement agent is composed of carboxylated betaine and Tween 80 in a mass ratio of 3:1. The softened water has a calcium and magnesium ion content of 32 mg / L and an HCO3 content of... – The concentration was 235 mg / L, and the pH value was 10.5.

[0153] Comparative Example 5

[0154] An oil displacement system comprising an oil displacement agent and softened water.

[0155] The oil displacement agent is composed of carboxylated betaine and polyethylene glycol 600 in a mass ratio of 3:1. The softened water has a calcium and magnesium ion content of 32 mg / L and an HCO3 content of... – The concentration was 235 mg / L, and the pH value was 10.3.

[0156] Comparative Example 6

[0157] An oil displacement system comprising an oil displacement agent and softened water.

[0158] The oil displacement agent is composed of carboxylated betaine and dodecyl dimethyl benzyl ammonium chloride (1227) in a mass ratio of 3:1. The softened water has a calcium and magnesium ion content of 32 mg / L and an HCO3 content of... – The concentration was 235 mg / L, and the pH value was 10.7.

[0159] Comparative Example 7

[0160] An oil displacement system comprising an oil displacement agent and softened water.

[0161] The oil displacement agent is composed of carboxylated betaine and petroleum sulfonate (SAS) in a mass ratio of 3:1. The softened water has a calcium and magnesium ion content of 32 mg / L and an HCO3 content of... – The concentration was 235 mg / L, and the pH value was 10.5.

[0162] Comparative Example 8

[0163] An oil displacement system comprising an oil displacement agent and softened water.

[0164] The oil displacement agent is composed of carboxylated betaine and sodium fatty alcohol polyoxyethylene ether sulfate (AES) in a mass ratio of 3:1. The softened water has a calcium and magnesium ion content of 32 mg / L and an HCO3 content of... – The concentration was 235 mg / L, and the pH value was 10.5.

[0165] Comparative Example 9

[0166] The oil displacement agent is composed of carboxylated betaine and sodium dodecylbenzenesulfonate (LAS) in a mass ratio of 3:1. The softened water has a calcium and magnesium ion content of 32 mg / L and an HCO3 content of... – The concentration was 235 mg / L, and the pH value was 10.5.

[0167] Comparative Example 10

[0168] An oil displacement system comprising an oil displacement agent and unsoftened produced water.

[0169] The oil displacement agent is composed of carboxyl betaine and fluorocarbon surfactant at a mass ratio of 900:1. The produced water has a calcium and magnesium ion content of 245 mg / L and HCO3- content of... – The concentration was 970 mg / L, and the pH value was 7.3.

[0170] Test case

[0171] Critical micelle concentration: Critical micelle concentration reflects the activity of a surfactant. The lower the CMC value, the greater its surface activity, the stronger its ability to reduce surface tension, and the higher its economic value. Figure 12 The curves show the surface tension of EAO solutions of different concentrations as a function of EAO concentration at room temperature (25℃).

[0172] Depend on Figure 12 It can be concluded that the critical micelle concentration (CMC) of the EAO solution is 0.05%. The surface tension of the solution corresponding to the CMC point is 35.8 mN / m. This surfactant has a relatively low critical micelle concentration, and the surface tension of the solution is slightly higher above the critical micelle concentration.

[0173] EAO and fluorocarbon (1% by mass) were compounded at a ratio of 900:1, and their critical micelle concentration was determined. The results of the critical micelle concentration determination are shown below. Figure 13 .Depend on Figure 13 It can be seen that the CMC concentration of the compound system is 0.03%. That is, adding a small amount of fluorocarbon can reduce the critical micelle concentration of the main agent EAO and significantly reduce the surface tension of the solution at the critical micelle concentration.

[0174] The oil displacement agents described in Example 3 and Comparative Examples 2-9 were respectively prepared with softened water to form oil displacement systems with a mass concentration of 0.3%. The interfacial tension was measured, and the results are shown in Table 4 below.

[0175] Table 4. Results of interfacial tension measurements of the oil displacement systems described in Example 3 and Comparative Examples 2-9

[0176] Example 3 0.0016 Comparative Example 2 0.087 Comparative Example 3 0.17 Comparative Example 4 >1 Comparative Example 5 0.11 Comparative Example 6 0.071 Comparative Example 7 0.87 Comparative Example 8 0.78 Comparative Example 9 0.09

[0177] The interfacial tension of the oil displacement agents described in Example 3 and Comparative Example 1, prepared with softened water to form oil displacement systems with a mass concentration of 0.3%, was measured after aging at 40°C, 60°C, and 80°C for 48 hours. The results are shown in Table 5.

[0178] Table 5. Results of interfacial tension measurements of the oil displacement systems described in Example 3 and Comparative Example 1.

[0179]

[0180] The results above show that the temperature resistance of the oil displacement system described in Comparative Example 1 is worse than that of betaine alone; the oil displacement system described in Example 3 has better temperature resistance, and the interfacial tension can still reach 10 at 80℃. -3 With ultra-low interfacial tension on the order of mN / m, it exhibits good temperature resistance.

[0181] Displacement experiments were conducted using the oil displacement systems described in Example 3 and Comparative Example 3 to simulate on-site conditions. First, softened water as described in Example 3 was used for oil displacement until no more oil was produced. Then, an oil displacement agent was used. The oil displacement steps were as follows:

[0182] ①Saturated oil: Select a suitable core sample, establish bound water saturation, and displace the core sample saturated with brine using simulated oil until the produced fluid is water-free. Record the volume of oil and water in the produced fluid and the displacement pressure in real time;

[0183] ② Water drive: Fully drain the residual oil in the pipeline, and inject the softened water described in Example 3 at a flow rate of 0.2 mL / min until water comes out of the outlet.

[0184] ③ Immediately inject the oil displacement agent solution described in Example 3 at a flow rate of 0.2 mL / min to a certain void volume, and water drive the produced fluid to the core outlet with a water content of more than 98%, and record the produced oil and water volume and displacement pressure difference in real time;

[0185] ④ Calculate the oil displacement efficiency after water flooding and the oil displacement efficiency of the oil displacement agent solution, as shown in Tables 6 and 7 below.

[0186] Table 6. Oil displacement effect of the oil displacement agent system in Example 3

[0187]

[0188]

[0189] Table 7 shows the oil displacement effect of the oil displacement agent system in Comparative Example 10.

[0190]

[0191] The results above show that the oil recovery rate of the displacement system described in Example 3 is significantly improved, and the oil displacement effect is remarkable. In particular, when the system concentration is 0.3%, the oil recovery rate reaches 27%, and the total recovery rate is as high as 85.23%. The oil recovery rates of the displacement system described in Example 3 are all higher than those of Comparative Example 10, indicating that the oil displacement agent and softened water described in this invention have a synergistic effect.

[0192] 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 changes, modifications, substitutions, combinations, or simplifications made without departing from the spirit and principle of the present invention shall be considered equivalent substitutions and shall be included within the protection scope of the present invention.

Claims

1. An oil displacement system for softened water pressure drive, characterized in that, The oil displacement system includes an oil displacement agent and softened water; the oil displacement agent includes carboxyl betaine and fluorocarbon surfactants; the softened water contains ≤50 mg / L calcium and magnesium ions and HCO3-. – The ion concentration is ≤300mg / L; the pH value of the softened water is 10-11. The carboxylated betaine includes any one or more of dodecylamidopropyl hydroxypropyl sulfobetaine, tetradecylamidopropyl hydroxypropyl sulfobetaine, hexadecylamidopropyl hydroxypropyl sulfobetaine, and erucamide hydroxypropyl sulfobetaine; The mass ratio of the carboxylated betaine to the fluorocarbon surfactant is 500-1000:0.3-5; The fluorocarbon surfactant includes one of the nonionic fluorocarbon surfactant Ee507T and the nonionic fluorocarbon surfactant Ee602T.

2. The softened water pressure drive oil displacement system according to claim 1, characterized in that, The calcium and magnesium ion content in the softened water is 10-50 mg / L.

3. A method for oil displacement using softened water pressure displacement, characterized in that, Includes the following steps: At least two slugs are injected into the softened hydraulic displacement oil displacement system as described in any one of claims 1-2; At least one slug is used to inject softened water, wherein the calcium and magnesium ion content in the softened water is ≤50 mg / L, and the HCO3 content in the softened water is ≤50 mg / L. – The ion concentration is ≤300mg / L; the pH value of the softened water is 10-11.

4. The method according to claim 3, characterized in that, At least four plugs are injected. The first plug is injected with an anti-swelling agent, the second and third plugs are injected with the softened water pressure drive oil displacement system as described in any one of claims 1-2, and the fourth plug is injected with softened water.

5. The method according to claim 3, characterized in that, At least five plugs are injected. The first plug is injected with slow-release nitric acid, the second plug is injected with an anti-swelling agent, the third and fourth plugs are injected with the softened water pressure drive oil displacement system as described in any one of claims 1-2, and the fifth plug is injected with softened water.

6. The method according to any one of claims 3-5, characterized in that, The injection displacement for each plug segment should be controlled between 0.8 and 1.5 m³. 3 / min.

7. The method according to any one of claims 3-5, characterized in that, The cumulative injection volume of a single well under pressure drive is 30,000 m³. 3 -90000m 3 .

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