Mining method for improving recovery efficiency through conglomerate oil reservoir middle-phase microemulsion flooding

Abstract

The invention belongs to the field of oilfield exploitation, and particularly relates to an exploitation method for improving the recovery efficiency through conglomerate oil reservoir middle-phase microemulsion flooding. The method comprises the following steps: firstly, establishing a matching relation chart of a middle-phase microemulsion oil displacement system and a reservoir, measuring the porosity, permeability and oil saturation of the reservoir, and selecting the molecular weight and concentration of a polymer and the concentration of a surfactant in the polymer during injection according to the chart; and then injecting the saline water 1, the polymer, the middle-phase microemulsion and the saline water 2 into the reservoir to displace oil so as to finish exploitation. According to the mining method, the overall development effect of middle-phase microemulsion flooding can be obviously improved, and the oil displacement rate of the mining method is obviously superior to that of other mining methods.

Description

Technical Field

[0001] The invention belongs to the field of oilfield exploitation, and in particular relates to an exploitation method for improving the recovery rate of a medium-phase microemulsion flooding in a conglomerate oil reservoir. Background Art

[0002] At present, the development of most domestic oil fields has entered the late stage of medium-high water content, with a water content of nearly 90%, and the water flooding method can basically not further improve the recovery rate. Therefore, it is necessary to find a replacement technology after water flooding. In recent years, my country's chemical flooding technology has developed rapidly. Field practice has shown that chemical flooding can effectively slow down the decline in production, inhibit the increase in water content, improve the recovery rate, and increase economic benefits. However, polymer flooding, binary and ternary composite flooding cannot achieve the requirements of significantly improving the recovery rate, and cannot meet the development needs of low permeability oil fields and high-temperature and high-mineralization oil fields. Microemulsion flooding can effectively solve the above problems. Microemulsion is a transparent or translucent emulsion with thermodynamic stability formed by surfactants, additives, oil and water or electrolyte aqueous solution in appropriate proportions, with a particle size between 10-200nm. The microemulsion system has ultra-low interfacial tension, which can effectively reduce the capillary force of oil droplets at the pore throat, reduce the resistance to oil droplet movement, and improve the wettability of the interface, making the oil droplets easier to flow, thereby reducing the starting pressure and water injection pressure. The middle phase microemulsion is the most ideal microemulsion system, with high surface activity and solubilization ability. It can solubilize both oil and water, making the displacement fluid and the displaced fluid miscible, improving the flow ratio, and greatly increasing the recovery rate. At present, the main research directions for the middle phase microemulsion flooding are concentrated on the development of oil displacement system, phase behavior and synergistic solubilization performance mechanism.

[0003] The conglomerate reservoirs in Xinjiang Oilfield have a typical complex modal pore structure, which not only includes structures composed of various particle sizes such as gravel, sand, and mud, but also includes a pore-fracture system composed of primary pores and secondary pores. The gravel edge fractures and intra-grain fractures are obviously developed, resulting in the conglomerate reservoirs having complex pore structures, poor connectivity, development of dominant channels, and strong heterogeneity. During the middle phase microemulsion flooding process, the oil displacement system tends to flow along the high permeability layer, resulting in the inability of the injected part of the oil displacement system to effectively affect the medium and low permeability layers, forming an inefficient and ineffective cycle. Therefore, it is necessary to study the mining method of improving the recovery rate of the middle phase microemulsion flooding, clarify the injection parameters and injection methods of the oil displacement system, and timely regulate the site to ensure the implementation effect on site. The application value is relatively large, but no relevant literature reports have been found. Summary of the invention

[0004] In view of the above-mentioned shortcomings, the present invention provides a method for improving the recovery rate of medium-phase microemulsion flooding in conglomerate reservoirs, which can improve the overall development effect of medium-phase microemulsion flooding.

[0005] To solve the above technical problems, the technical solution adopted by the present invention is:

[0006] The mining method comprises the following steps:

[0007] A method for improving oil recovery by microemulsion flooding in a conglomerate reservoir, comprising the following steps:

[0008] (1) establishing a matching relationship chart of the medium-phase microemulsion flooding system and the reservoir, measuring the porosity, permeability and oil saturation of the reservoir, and selecting the polymer molecular weight, polymer concentration and surfactant concentration in the polymer during injection according to the chart;

[0009] (2) Injecting brine 1, polymer, middle phase microemulsion, and brine 2 into the reservoir to drive oil and complete the production.

[0010] Preferably, the porosity test method in step (1) comprises saturating the core with a 20000 mg / L-40000 mg / L brine solution for 8-15 hours under vacuum filtration, weighing the wet weight of the core, and calculating the porosity;

[0011] Preferably, the permeability test method comprises placing the core into a core holder, water flooding with a 20000mg / L-40000mg / L brine solution, recording the stable pressure difference, and calculating the permeability;

[0012] Preferably, the method for testing the stable water flooding pressure difference comprises performing water flooding with a 20000mg / L-40000mg / L saline solution at an injection rate of 0.1-0.3mL / min, and recording the stable water flooding pressure difference.

[0013] Preferably, the method for establishing a matching relationship chart of the middle phase microemulsion flooding system and the reservoir in step (1) comprises:

[0014] A. Dry the core and test the core's porosity, permeability, and stable water drive pressure difference;

[0015] B. injecting a middle phase microemulsion flooding system at an injection rate of 0.10 mL / min to obtain a resistance coefficient, injecting brine at an injection rate of 0.10 mL / min until the pressure and flow rate are stable, and calculating a residual resistance coefficient; the components of the middle phase microemulsion include a hydrophobic associating polymer, a surfactant and NaCl;

[0016] C. When the resistance coefficient is <30 and the residual resistance coefficient is <10, it indicates good injectability; when the resistance coefficient is between 30-70 and the residual resistance coefficient is between 10-20, it indicates that injection is difficult; when the resistance coefficient is >70 and the residual resistance coefficient is >20, it indicates that injection is impossible; a compatibility relationship chart between the difficulty of injection and the polymer molecular weight, polymer concentration, surfactant concentration, permeability and porosity is established.

[0017] Preferably, step C further includes step D: drawing a viscosity-concentration curve, drying the core, testing the length, porosity and permeability of the core, setting two pressure measuring points on the core, with an interval of 5-7.5 cm between each section, and also setting a pressure measuring point at the entrance; injecting the oil and middle phase microemulsion flooding system into the core with multiple pressure measuring points according to different oil-water ratios, comparing the changes in migration pressure of each section under oil saturation, calculating the pressure difference, resistance coefficient, and residual resistance coefficient / effective viscosity at both ends of the core during migration, and then finding the concentration corresponding to the effective viscosity through the viscosity-concentration curve, and correcting the chart according to the resistance change of the system under different oil saturations to obtain a reservoir matching relationship chart.

[0018] Preferably, in step (1), when the permeability of the reservoir is 50 mD and the porosity is 10-15%, the molecular weight of the polymer selected for injection is 6 million, the concentration of the polymer is 800-1500 mg / L, and the mass concentration of the surfactant in the middle phase microemulsion is 0.5%; when the permeability of the reservoir is 100-200 mD and the porosity is 10-20%, the molecular weight of the polymer selected for injection is 6 million-10 million, the concentration of the polymer is 800-2000 mg / L, and the mass concentration of the surfactant in the middle phase microemulsion is 0.5-0.7%.

[0019] Preferably, the injection rate in step (2) is 0.3-0.7 mL / min, and the concentration of the brine 1 is 20000 mg / L-40000 mg / L.

[0020] Preferably, the injection of the polymer in step (2) comprises first injecting 1500-2000 mg / L polymer plugs to drive oil, and then injecting 1000-1500 mg / L polymer plugs, wherein the polymer is a hydrophobic associating polymer with a solid content of 88.65% and a hydrophobic group content of 0.2%.

[0021] Preferably, the injection of the middle phase microemulsion in step (2) comprises first injecting a main slug of the middle phase microemulsion, wherein the surfactant concentration is 5000-7000 mg / L; and then injecting a secondary slug of the middle phase microemulsion, wherein the surfactant concentration is 3000-5000 mg / L; the components of the middle phase microemulsion include a hydrophobic associating polymer, a surfactant and NaCl, and the surfactant is selected from coconut oil fatty acid diethanolamide.

[0022] Preferably, the mining method further comprises on-site injection regulation of step (2).

[0023] Preferably, the on-site regulation method includes: when the injection well pressure increase is less than 18-22% of the average pressure, increasing the concentration of surfactant in the middle phase microemulsion by 500-1000 mg / L. Preferably, the on-site regulation method includes: when the oil well output liquid volume decreases by more than 18-22%, increasing the concentration of surfactant in the middle phase microemulsion by 500-1000 mg / L.

[0024] Preferably, the on-site regulation method comprises: when the concentration of polymer solution 1 and / or polymer solution 2 in the oil well production fluid is greater than 100 mg / L or the concentration of surfactant therein is greater than 50 mg / L, increasing the concentration of brine 1 and brine 2 by 300-1000 mg / L for regulation.

[0025] Preferably, the on-site control method comprises: when the concentration of the polymer solution 1 and / or the polymer solution 2 in the oil well production fluid is greater than 300 mg / L or the concentration of the surfactant therein is greater than 100 mg / L, carrying out profile control, the injection amount of the profile control agent is 0.03-0.07PV, the raw materials of the profile control agent are hydrophobic associating polymer, cross-linking agent, coagulant and auxiliary agent, the cross-linking agent is urotropine, and the auxiliary agent is a mixture of phenol, thiourea, sodium chloride and sodium bicarbonate in a mass ratio of 3:2:1:1; the gelling viscosity of the profile control agent is 2000-6000 mPa·s.

[0026] Another object of the present invention is to provide an application of the above production method in improving the production rate of conglomerate oil reservoirs.

[0027] Compared with the prior art, the present invention has the following positive and beneficial effects:

[0028] The production method of the present invention can significantly improve the overall development effect of medium-phase microemulsion flooding, and its oil displacement rate is significantly better than other production methods. DETAILED DESCRIPTION

[0029] The present invention will be further described in detail below in conjunction with specific examples. The following examples are not intended to limit the present invention, but are only intended to illustrate the present invention. The experimental methods used in the following examples are generally conventional, unless otherwise specified, and the materials, reagents, etc. used in the following examples are commercially available, unless otherwise specified.

[0030] In the following examples, the polymer is a hydrophobically associating polymer with a solid content of 88.65% and a hydrophobic group content of 0.2%, and the supplier is Beijing Hengju Chemical Group Co., Ltd.;

[0031] The components of the middle phase microemulsion are hydrophobic associating polymer, surfactant and NaCl, the surfactant is coconut oil fatty acid diethanolamide, and the supplier is Noco (Shanghai) Chemical Co., Ltd.;

[0032] The raw materials of the profile control agent are polymer, cross-linking agent, coagulant and additives. The polymer is a hydrophobic associating polymer with a solid content of 88.65% and a hydrophobic group content of 0.2%. The supplier is Beijing Hengju Chemical Group Co., Ltd. The cross-linking agent is hexamethylenetetramine and the additives are phenol, thiourea, sodium chloride and sodium bicarbonate in a mass ratio of 3:2:1:1.

[0033] Example 1: Diagram of the relationship between the medium-phase microemulsion flooding system and the reservoir matching

[0034] The method for establishing the relationship chart of the middle phase microemulsion flooding system and the reservoir matching is as follows:

[0035] A. Dry the core and test the core's porosity, permeability, and stable water drive pressure difference;

[0036] B. Inject the medium-phase microemulsion flooding system at an injection rate of 0.10 mL / min, measure the core pressure and flow rate until the pressure tends to be stable, obtain the resistance coefficient, and measure the viscosity of the output fluid at the same time. Inject salt water at an injection rate of 0.10 mL / min until the pressure and flow rate are stable, and calculate the residual resistance coefficient.

[0037] C. When the resistance coefficient is <30, the residual resistance coefficient is <10, indicating good injectability; when the resistance coefficient is between 30-70 and the residual resistance coefficient is between 10-20, it indicates that injection is difficult; when the resistance coefficient is >70 and the residual resistance coefficient is >20, it indicates that injection is impossible. This method is used to establish the compatibility relationship chart between the two polymer molecular weights (6 million and 10 million), four polymer concentrations (800 mg / L, 1500 mg / L, 1800 mg / L, 2000 mg / L), three surfactant concentrations (0.5%, 0.6%, 0.7%), three permeabilities (50 mD, 100 mD and 200 mD) and three porosities (10%, 15%, 20%) in Table 1.

[0038] D. Draw a viscosity-concentration curve, take another core, dry the core, test the length, porosity, and permeability of the core, set up 2 pressure measuring points on the core, each section is 5-7.5cm apart, plus the pressure measuring point at the entrance, a total of 3 pressure measuring points. Inject the oil and middle phase microemulsion flooding system into the core with multiple pressure measuring points according to different oil-water ratios, compare the changes in migration pressure of each section under oil saturation, calculate the pressure difference, resistance coefficient, residual resistance coefficient, and effective viscosity at both ends of the core during migration. Then find the concentration corresponding to the effective viscosity through the viscosity-concentration curve, and correct the above compatibility chart according to the resistance change of the system under different oil saturations. As shown in Tables 1 to 3.

[0039] Table 1 Compatibility chart of artificial conglomerate core with a permeability of 50 mD

[0040]

[0041] Table 2 Compatibility chart of artificial conglomerate core with a permeability of 100 mD

[0042]

[0043] Table 3 Compatibility chart of artificial conglomerate core with a permeability of 200 mD

[0044]

[0045] Example 2

[0046] The mining method is as follows:

[0047] (1) Dry the core in an oven, weigh the dry weight, saturate the core with brine (concentration of 30,000 mg / L) under vacuum filtration, weigh the wet weight of the core, and calculate the pore volume and porosity of the core. Place the core in a core holder, use brine (concentration of 30,000 mg / L) for water flooding, record the stable pressure difference, and calculate the water permeability; use brine (concentration of 30,000 mg / L) for water flooding at an injection rate of 0.5 mL / min, and record the water flooding oil recovery efficiency;

[0048] (2) Inject a high-concentration polymer plug at an injection rate of 0.5 mL / min, with a polymer concentration of 1800 mg / L, and record the oil recovery efficiency;

[0049] (3) Inject a low-concentration polymer plug at an injection rate of 0.5 mL / min, with a polymer concentration of 1200 mg / L, and record the oil displacement efficiency;

[0050] (4) Inject the middle phase microemulsion main slug at an injection rate of 0.5 mL / min with a surfactant concentration of 50,000 mg / L, and record the oil displacement efficiency;

[0051] (5) The secondary slug of the microemulsion in the middle phase was injected at a rate of 0.5 mL / min and the surfactant concentration was 3000 mg / L, and the oil displacement efficiency was recorded;

[0052] (6) The slug was flooded with brine (concentration 30000 mg / L) at an injection rate of 0.5 mL / min and the oil displacement efficiency was recorded. The results are shown in Table 4.

[0053] Table 4 Oil displacement efficiency of medium phase microemulsion flooding under water flooding + polymer flooding + medium phase microemulsion flooding + subsequent water flooding

[0054]

[0055]

[0056] Example 3

[0057] The mining method is as follows:

[0058] (1) Dry the core in an oven, weigh the dry weight, saturate the core with brine (concentration of 30,000 mg / L) under vacuum filtration, weigh the wet weight of the core, and calculate the pore volume and porosity of the core. Place the core in a core holder, use brine (concentration of 30,000 mg / L) for water flooding, record the stable pressure difference, and calculate the water permeability; use brine (concentration of 30,000 mg / L) for water flooding at an injection rate of 0.5 mL / min, and record the water flooding oil recovery efficiency;

[0059] (2) Inject a high-concentration polymer plug at an injection rate of 0.5 mL / min, with a polymer concentration of 1500 mg / L, and record the oil displacement efficiency;

[0060] (3) Inject the middle phase microemulsion main slug at an injection rate of 0.5 mL / min with a surfactant concentration of 5000 mg / L, and record the oil displacement efficiency;

[0061] (4) The secondary slug of the microemulsion in the middle phase was injected at a rate of 0.5 mL / min and the surfactant concentration was 3000 mg / L, and the oil displacement efficiency was recorded;

[0062] (5) The slug was flooded with brine (concentration 30000 mg / L) at an injection rate of 0.5 mL / min and the oil displacement efficiency was recorded. The results are shown in Table 5.

[0063] Table 5 Effect of different main segment plug injection methods on the recovery of medium phase microemulsion flooding

[0064]

[0065] Compared with the oil displacement experiment of water flooding + high concentration polymer flooding + low concentration polymer flooding + middle phase microemulsion flooding + subsequent water flooding in Example 2, as shown in Table 5, it can be seen that the oil displacement efficiency of water flooding + high concentration polymer flooding + low concentration polymer flooding + middle phase microemulsion flooding + subsequent water flooding is higher than the oil displacement efficiency of water flooding + single concentration polymer flooding + middle phase microemulsion flooding + subsequent water flooding.

[0066] Comparative Example 1

[0067] The difference between the method of this comparative example and that of Example 2 is that the front slug is different.

[0068] (1) Dry the core in an oven, weigh the dry weight, saturate the core with brine (concentration of 30,000 mg / L) under vacuum filtration, weigh the wet weight of the core, and calculate the pore volume and porosity of the core. Place the core in a core holder, use brine (concentration of 30,000 mg / L) for water flooding, record the stable pressure difference, and calculate the water permeability; use brine (concentration of 30,000 mg / L) for water flooding at an injection rate of 0.5 mL / min, and record the water flooding oil recovery efficiency;

[0069] (2) Inject the middle phase microemulsion main slug at an injection rate of 0.5 mL / min with a surfactant concentration of 5000 mg / L, and record the oil displacement efficiency;

[0070] (3) The secondary slug of the microemulsion in the middle phase was injected at a rate of 0.5 mL / min and the surfactant concentration was 3000 mg / L, and the oil displacement efficiency was recorded;

[0071] (4) Brine (concentration 30,000 mg / L) was injected at a rate of 0.5 mL / min to drive the plug and record the oil recovery efficiency.

[0072] The water flooding + middle phase microemulsion flooding + subsequent water flooding experiment is shown in core number 1# in Table 6. It can be seen that the oil displacement efficiency of the present invention is higher than that of water flooding + middle phase microemulsion flooding + subsequent water flooding.

[0073] Comparative Example 2: Investigating the effects of different main segment injection methods on the recovery enhancement of medium phase microemulsion flooding (this comparative example uses water flooding + single concentration medium phase microemulsion flooding + subsequent water flooding)

[0074] (1) Dry the core in an oven, weigh the dry weight, saturate the core with brine (concentration of 30,000 mg / L) under vacuum filtration, weigh the wet weight of the core, and calculate the pore volume and porosity of the core. Place the core in a core holder, use brine (concentration of 30,000 mg / L) for water flooding, record the stable pressure difference, and calculate the water permeability; use brine (concentration of 30,000 mg / L) for water flooding at an injection rate of 0.5 mL / min, and record the water flooding oil recovery efficiency;

[0075] (2) Inject the middle phase microemulsion main slug at an injection rate of 0.5 mL / min with a surfactant concentration of 3000 mg / L, and record the oil displacement efficiency;

[0076] (3) The secondary slug of the microemulsion in the middle phase was injected at a rate of 0.5 mL / min and the surfactant concentration was 3000 mg / L, and the oil displacement efficiency was recorded;

[0077] (4) The slug was flooded with brine (concentration 30000 mg / L) at an injection rate of 0.5 mL / min, and the oil displacement efficiency was recorded. The results are shown in Table 6 for core number 2#.

[0078] Table 6 Oil displacement efficiency of medium phase microemulsion flooding under water flooding + medium phase microemulsion flooding + subsequent water flooding

[0079]

[0080]

[0081] Comparative Example 3 Effect of different main segment plug injection methods on the recovery of medium phase microemulsion flooding (this comparative example adopts water flooding + high concentration medium phase microemulsion flooding + low concentration medium phase microemulsion flooding + subsequent water flooding)

[0082] (1) Dry the core in an oven, weigh the dry weight, saturate the core with brine (concentration of 30,000 mg / L) under vacuum filtration, weigh the wet weight of the core, and calculate the pore volume and porosity of the core. Place the core in a core holder, use brine (concentration of 30,000 mg / L) for water flooding, record the stable pressure difference, and calculate the water permeability; use brine (concentration of 30,000 mg / L) for water flooding at an injection rate of 0.5 mL / min, and record the water flooding oil recovery efficiency;

[0083] (2) Inject the middle phase microemulsion main slug at an injection rate of 0.5 mL / min with a surfactant concentration of 6000 mg / L, and record the oil displacement efficiency;

[0084] (3) The secondary slug of the microemulsion in the middle phase was injected at a rate of 0.5 mL / min and the surfactant concentration was 4000 mg / L, and the oil displacement efficiency was recorded;

[0085] (4) Brine (concentration 30,000 mg / L) was injected at a rate of 0.5 mL / min to drive the plug and record the oil recovery efficiency.

[0086] The results are shown in Table 7.

[0087] The oil displacement experiments of water flooding + single-concentration middle phase microemulsion flooding + subsequent water flooding and water flooding + high-concentration middle phase microemulsion flooding + low-concentration middle phase microemulsion flooding + subsequent water flooding were compared, as shown in Table 7. It can be seen that the oil displacement efficiency of water flooding + polymer flooding + middle phase microemulsion flooding + subsequent water flooding is higher than that of water flooding + middle phase microemulsion flooding + subsequent water flooding.

[0088] Table 7 Effects of different main segment injection methods on enhanced oil recovery in medium phase microemulsion flooding

[0089]

[0090] Example 3: Medium-phase microemulsion flooding injection regulation

[0091] ① Based on the original polymer concentration of 1500 mg / L, experiments were carried out to increase the polymer concentration to test the pressure increase, as shown in Table 8. It can be seen that as the polymer concentration increases, the pressure increase also increases. When the polymer concentration increases to 600 mg / L, the pressure increase tends to be stable.

[0092] Table 8 Comparison of pressure rise range with increasing polymer concentration

[0093]

[0094] ② Screening and evaluation of profile control system

[0095] The profile control system selected phenolic gel crosslinker, the preparation water was 30000 mg / L saline, the polymer molecular weight was 10 million, the crosslinker concentration was 4000 mg / L, the additive concentration was 5000 mg / L, and under the same conditions, the effects of different polymer concentrations on the viscosity of the profile control agent were compared, as shown in Table 9. As the polymer concentration continued to increase, the viscosity of the profile control agent also continued to increase. When the polymer concentration was 3000 mg / L, the viscosity of the profile control agent was optimal.

[0096] Table 9 Effect of polymer concentration on gel viscosity at different times

[0097]

[0098] The polymer molecular weight is 10 million, the polymer concentration is 3000 mg / L, and the additive concentration is 5000 mg / L. Under the same conditions, the effects of different concentrations of cross-linking agent on the viscosity of the profile control agent are compared, as shown in Table 10. When the cross-linking agent concentration is 4000 mg / L, the viscosity of the profile control agent is optimal.

[0099] Table 10 Effect of crosslinker concentration on gel viscosity at different times

[0100]

[0101]

[0102] The polymer molecular weight is 10 million, the polymer concentration is 3000 mg / L, the cross-linking agent concentration is 4000 mg / L, the additives are phenol, thiourea, sodium chloride and sodium bicarbonate, and the mass ratio is 3:2:1:1. Under the same conditions, the effects of different concentrations of cross-linking agents on the viscosity of the profile control agent are compared, as shown in Table 11. When the additive concentration is 5000 mg / L, the viscosity of the profile control agent is optimal.

[0103] Table 11 Effect of polymer concentration on gel viscosity at different times

[0104]

[0105] The effects of profile control slug size and slug combination on the enhanced oil recovery of medium-phase microemulsion flooding were studied, as shown in Table 12. It can be seen that when the profile control slug size is 0.05PV and the high viscosity-low viscosity-high viscosity slug combination is adopted, the enhanced oil recovery of medium-phase microemulsion flooding is the highest.

[0106] Table 12 Effect of different profile control plug sizes on the recovery of medium-phase microemulsion flooding

[0107]

[0108]

[0109] The above-mentioned embodiments only express several implementation methods of the present invention, and the description thereof is relatively specific and detailed, but it cannot be understood as limiting the scope of the patent of the present invention. It should be pointed out that, for ordinary technicians in this field, several variations and improvements can be made without departing from the concept of the present invention, which all belong to the protection scope of the present invention. Therefore, the protection scope of the patent of the present invention shall be subject to the attached claims.

Claims

1. A method for improving oil recovery by microemulsion flooding in conglomerate reservoirs, characterized in that: The steps include: (1) establishing a matching relationship chart of the medium-phase microemulsion flooding system and the reservoir, measuring the porosity, permeability and oil saturation of the reservoir, and selecting the polymer molecular weight, polymer concentration and surfactant concentration in the polymer during injection according to the chart; (2) Injecting brine 1, polymer, middle phase microemulsion, and brine 2 into the reservoir to drive oil and complete the production.

2. The mining method according to claim 1, characterized in that: The porosity test method in step (1) comprises saturating the core with a 20000 mg / L-40000 mg / L brine solution for 8-15 hours under vacuum filtration, weighing the wet weight of the core, and calculating the porosity; The permeability test method includes placing a core in a core holder, water flooding with a 20000mg / L-40000mg / L brine solution, recording a stable pressure difference, and calculating the permeability; The test method of the water flooding stable pressure difference comprises performing water flooding with a 20000mg / L-40000mg / L salt water solution at an injection rate of 0.1-0.3mL / min, and recording the water flooding stable pressure difference.

3. The mining method according to claim 1, characterized in that: The method for establishing a matching relationship chart of the medium-phase microemulsion flooding system and the reservoir in step (1) comprises: A. Dry the core and test the core's porosity, permeability, and stable water drive pressure difference; B. injecting a middle phase microemulsion flooding system at an injection rate of 0.10 mL / min to obtain a resistance coefficient, injecting brine at an injection rate of 0.10 mL / min until the pressure and flow rate are stable, and calculating a residual resistance coefficient; the components of the middle phase microemulsion include a hydrophobic associating polymer, a surfactant and NaCl; C. When the resistance coefficient is <30 and the residual resistance coefficient is <10, it indicates good injectability; when the resistance coefficient is between 30-70 and the residual resistance coefficient is between 10-20, it indicates that injection is difficult; when the resistance coefficient is >70 and the residual resistance coefficient is >20, it indicates that injection is impossible; a compatibility relationship chart between the difficulty of injection and the polymer molecular weight, polymer concentration, surfactant concentration, permeability and porosity is established.

4. The mining method according to claim 3, characterized in that: The method further includes step D after step C: drawing a viscosity-concentration curve, drying the core, testing the length, porosity and permeability of the core, setting two pressure measuring points on the core, with an interval of 5-7.5 cm between each section, and also setting a pressure measuring point at the entrance; injecting the oil and the middle phase microemulsion flooding system into the core with multiple pressure measuring points according to different oil-water ratios, comparing the changes in the migration pressure of each section under the oil saturation, calculating the pressure difference at both ends of the core during migration, the resistance coefficient, the residual resistance coefficient, and the effective viscosity, and then finding the concentration corresponding to the effective viscosity through the viscosity-concentration curve, and correcting the chart according to the resistance change of the system under different oil saturations to obtain the reservoir matching relationship chart.

5. The mining method according to claim 1, characterized in that: In step (1), when the permeability of the reservoir is 50 mD and the porosity is 10-15%, the molecular weight of the polymer selected for injection is 6 million, the concentration of the polymer is 800-1500 mg / L, and the mass concentration of the surfactant in the middle phase microemulsion is 0.5%; when the permeability of the reservoir is 100-200 mD and the porosity is 10-20%, the molecular weight of the polymer selected for injection is 6 million-10 million, the concentration of the polymer is 800-2000 mg / L, and the mass concentration of the surfactant in the middle phase microemulsion is 0.5-0.7%.

6. The mining method according to claim 1, characterized in that: The injection speed in step (2) is 0.3-0.7 mL / min, and the concentration of the brine 1 is 20000 mg / L-40000 mg / L.

7. The mining method according to claim 1, characterized in that: The injection of the polymer in step (2) includes first injecting 1500-2000 mg / L polymer plugs to drive oil, and then injecting 1000-1500 mg / L polymer plugs. The polymer is a hydrophobic associating polymer with a solid content of 88.65% and a hydrophobic group content of 0.2%.

8. The mining method according to claim 1, characterized in that: The injection of the middle phase microemulsion in step (2) comprises first injecting a main segment of the middle phase microemulsion, wherein the surfactant concentration is 5000-7000 mg / L; and then injecting a secondary segment of the middle phase microemulsion, wherein the surfactant concentration is 3000-5000 mg / L; the components of the middle phase microemulsion include a hydrophobic associating polymer, a surfactant and NaCl, and the surfactant is selected from coconut oil fatty acid diethanolamide.

9. The mining method according to any one of claims 1 to 8, characterized in that: The mining method further comprises performing on-site injection regulation on step (2).

10. The mining method according to claim 9, characterized in that: The on-site regulation method comprises: when the injection well pressure increase is less than 18-22% of the average pressure, increasing the polymer concentration by 300-1000 mg / L.

11. The mining method according to claim 9, characterized in that: The on-site control method comprises: when the liquid volume of the oil well output decreases by more than 18-22%, the surfactant concentration in the middle phase microemulsion is increased by 500-1000 mg / L.

12. The mining method according to claim 9, characterized in that: The on-site control method includes: when the concentration of polymer solution 1 and / or polymer solution 2 in the oil well production fluid is greater than 100 mg / L or the concentration of surfactant therein is greater than 50 mg / L, increasing the concentration of brine 1 and brine 2 by 300-1000 mg / L for control.

13. The mining method according to claim 9, characterized in that: The on-site control method comprises: when the concentration of the polymer solution 1 and / or the polymer solution 2 in the oil well output fluid is greater than 300 mg / L or the concentration of the surfactant therein is greater than 100 mg / L, carrying out profile control, the injection amount of the profile control agent is 0.03-0.07 PV, the raw materials of the profile control agent are hydrophobic associating polymer, cross-linking agent, coagulant and auxiliary agent, the cross-linking agent is hexamethylenetetramine, and the auxiliary agent is a mixture of phenol, thiourea, sodium chloride and sodium bicarbonate in a mass ratio of 3:2:1:1; the gelling viscosity of the profile control agent is 2000-6000 mPa·s.

14. Use of the production method according to any one of claims 1 to 13 in improving the production rate of conglomerate oil reservoirs.

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