Microbial wetting control method and wetting system injection process for medium and low permeability reservoirs

Abstract

The present invention belongs to the field of microbial oil recovery technology, and specifically relates to a microbial wetting control method and a wetting system injection process for medium- and low-permeability oil reservoirs. The microbial wetting control method for medium- and low-permeability oil reservoirs comprises the following steps: (1) screening of test oil reservoirs; (2) analysis of the mineral composition of the natural rock core of the test oil reservoir, and then secondary screening of the test oil reservoir screened in step (1); (3) evaluation of the microbial wetting system. The microbial wetting system injection process for medium- and low-permeability oil reservoirs is characterized by comprising the following steps: S1, determining whether the clay content in the natural rock of the test oil reservoir is less than 10%. If so, injecting the screened wetting system by a single round of pressure drive; otherwise, injecting the screened wetting system by multiple rounds of pressure drive; S2, field testing and evaluation of the field test results.

Description

Technical Field

[0001] The invention belongs to the technical field of microbial oil recovery, and in particular relates to a microbial wetting control method for medium and low permeability oil reservoirs and a wetting system injection process. Background Art

[0002] Microbial oil recovery technology involves injecting exogenous microbial culture isolated and cultured on the surface into the oil reservoir, or injecting nutrient solution to activate endogenous microorganisms in the reservoir. This activates their growth and metabolic activity, producing metabolites that enhance oil recovery, thereby altering the interfacial properties of the reservoir and improving oil displacement efficiency. This technology offers advantages such as low construction cost, simple process, long-lasting effects, wide application range, and minimal environmental pollution. It has demonstrated promising results in field trials.

[0003] my country's low- to medium-permeability oil reservoirs hold enormous potential, accounting for two-thirds of proven reserves. Developing efficient low- to medium-permeability reservoirs has become a crucial path to stabilizing future production capacity. The development of low- to medium-permeability reservoirs is hampered by multiple factors, including low permeability and wettability, leading to the phenomenon of "no injection, no production" during development. Due to the fine pore channels of low- to medium-permeability reservoirs, imbibition is more pronounced than in conventional reservoirs. Therefore, imbibition is considered a key mechanism for improving the performance of low- to medium-permeability reservoirs. However, the most significant factor influencing spontaneous imbibition is wettability, which determines whether capillary force acts as a driving force or a resistance to imbibition.

[0004] Currently, the main method for enhancing oil recovery in low- to medium-permeability reservoirs is to inject chemical surfactants during conventional water flooding, which alter the wettability of the rock through adsorption, thereby increasing oil recovery. However, existing processes suffer from drawbacks such as high surfactant usage, high costs, limited specificity in wettability control, and poor wettability modification effects deep within the reservoir.

[0005] The Chinese patent application "A biological wettability reversal agent for high-temperature, high-salinity heavy oil reservoirs and its preparation method" (application number: 201911011026.5) discloses a biological wettability reversal agent for high-temperature, high-salinity heavy oil reservoirs and its preparation method, which specifically includes a biological wettability reversal agent composed of rhamnolipid fermentation broth, sophorolipid fermentation broth, alkyl polyglycoside, alcohol additive and water. The preparation method includes adding the above components in sequence into a reactor, and specifies the time, method and preparation method of adding. However, it still has the following shortcomings: (1) This method is mainly aimed at high-temperature, high-salinity heavy oil reservoirs, and does not involve the application of medium and low permeability reservoirs; (2) This method does not formulate a control system for reservoirs with different wettability, and the reservoir adaptability of the wettability reversal agent is unclear; (3) This method does not adjust the system formula according to the rock mineral composition of the reservoir, and has weak permeability.

[0006] The Chinese patent application "A Wettability Reversal Agent, Wettability Reversal Fluid and Pressure-Drive Water Injection Method" (Application No.: 202110157344.3) discloses a wettability reversal agent, a wettability reversal fluid and a pressure-drive water injection method, specifically comprising a wettability reversal agent comprising an anionic surfactant, nanoparticles and water, a wettability reversal fluid comprising a wettability reversal agent, a synergist, an anionic surfactant, a nonionic surfactant and water, and a pressure-drive water injection method comprising (1) pumping fracturing fluid into the reservoir formation; (2) injecting the wettability reversal fluid into the fracture network; (3) pumping injection water into the fracture network to displace crude oil. However, there are still the following deficiencies: (1) This method mainly uses chemical surfactants for wetting control, which has the problems of large chemical dosage and high cost; (2) This method uses the contact angle method to evaluate wettability, which is quite different from the actual reservoir situation; (3) This method only describes the pressure-drive method and injection steps, but does not optimize the pressure-drive parameters for reservoirs with different mineral compositions. Summary of the Invention

[0007] Purpose of the invention: The present invention aims to address the problems of large amount of chemical agents used and poor targeting of the wetting system in existing technologies for improving the recovery rate of medium and low permeability oil reservoirs, and provides a method for controlling microbial wetting and a wetting system injection process for medium and low permeability oil reservoirs. For oil reservoirs with different mineral compositions, a wetting system mainly composed of microbial cells and biosurfactants is constructed. In addition, according to the different clay content in the oil reservoir, the optimized wetting system is injected into the water well using single-round and multi-round pressure-driven water injection technology, so that it acts on the oil-wetting surface to achieve wetting reversal and improve the efficiency of water drive development. This method has the characteristics of strong targeting, wide adaptability, strong operability, low cost and obvious oil-increasing effect.

[0008] Therefore, the present invention uses microbial cells and biosurfactants as the main wetting control subjects, establishes a wetting system for medium and low permeability oil reservoirs with different mineral compositions, and injects the optimized wetting system into the oil reservoir in the form of pressure drive, ultimately achieving spontaneous imbibition and achieving the purpose of improving the oil recovery effect of medium and low permeability oil reservoirs.

[0009] Technical solution: A method for microbial wetting control in medium and low permeability reservoirs, comprising the following steps:

[0010] (1) Screening of test reservoirs;

[0011] (2) analyzing the mineral composition of the natural core of the test reservoir, and then performing a secondary screening on the test reservoir screened in step (1);

[0012] (3) Evaluation of microbial wetting system.

[0013] Furthermore, the screening criteria for the test reservoir in step (1) are: reservoir temperature <90°C, formation crude oil viscosity <3000 mPa·s, formation water salinity <30000 mg / L, permeability <100×10 -3 μm 2 , sandstone reservoirs.

[0014] Furthermore, the mineral composition of the natural core in step (2) includes one or more of clay, quartz, plagioclase, potassium feldspar, calcite, dolomite, and pyrite.

[0015] Furthermore, in step (2), the secondary screening criteria for the test reservoirs screened in step (1) are:

[0016] The clay content is 1-20%, the quartz content is 30-50%, the potassium feldspar content is 5-20%, the plagioclase content is 5-20%, the calcite content is 1-10%, the dolomite content is 1-10%, and the pyrite content is 0-0.5%.

[0017] Furthermore, the microbial wetting system evaluation in step (3) includes:

[0018] (31) A microbial fermentation liquid with a hydrophobicity greater than 40% and less than 70% is compounded with a biosurfactant aqueous solution with a mass concentration of 1 to 30% in a mass ratio of 1:1 to 10 to obtain a wetting system, and then wetting control is performed;

[0019] (32) Characterization of wettability and surface roughness of natural cores before and after the action of the wetting system;

[0020] (33) Selection criteria for microbial wetting system: the wetting range is [-0.2, 0.5], and the surface roughness range is 100 nm to 1 μm.

[0021] Furthermore, in step (31), the microbial cells having a hydrophobicity greater than 40% and less than 70% under reservoir conditions are one or more of Bacillus subtilis, Pseudomonas aeruginosa, Candida albicans, Lactobacillus acidophilus, Micrococcus, Acinetobacter, Rhodococcus, Geobacillus, Oleobacter, and Enterobacter.

[0022] Furthermore, in step (31), the biosurfactant is at least one of lipopeptide, rhamnolipid, and sophorolipid.

[0023] The microbial wetting system injection process for medium and low permeability reservoirs includes the following steps:

[0024] S1. Determine whether the clay content in the natural rock of the test reservoir is less than 10%. If so, inject the selected wetting system through a single round of pressure flooding. Otherwise, inject the selected wetting system through multiple rounds of pressure flooding.

[0025] S2. Field test and evaluation of field test results.

[0026] Furthermore, the single-round pressure drive injection of the screened wetting system includes the following steps:

[0027] First, the selected wetting system is configured using the injection water of the test reservoir;

[0028] Then the prepared wetting system is injected from the injection well of the test reservoir in a single round of pressure drive with an injection pressure of 40-50 MPa and an injection speed of 0.5-2.0 m 3 / min, injection volume is 10000~30000m 3 ; Water injection was resumed 10 days after the well was shut down.

[0029] Furthermore, the wetting system selected by multiple rounds of pressure injection includes the following steps:

[0030] First, the selected wetting system is configured using the injection water of the test reservoir;

[0031] Then the prepared wetting system is injected from the injection well of the test reservoir in a single round of pressure drive with an injection pressure of 40-50 MPa and an injection speed of 0.5-2.0 m 3 / min, injection volume is 10000~30000m 3 ; Shut down the well for 10 days;

[0032] After that, the second round of pressure drive was carried out with an injection pressure of 40-50 MPa and an injection speed of 0.5-2.0 m 3 / min, injection volume is 10000~30000m 3 , water injection was resumed after the well was shut down for 7 days.

[0033] Furthermore, the evaluation indicators for the field test results described in step S2 include injection pressure, injection volume, average daily oil production per well, effective period, and input-output ratio. Low- to medium-permeability reservoirs are generally characterized by difficulty in water injection and low recovery. Low permeability leads to high injection pressure and low injection volume, resulting in poor water flooding results. Injecting the wetting system can reduce the injection pressure in the well and increase the injection volume.

[0034] The present invention utilizes the characteristics of microbial cells adsorbing on the rock surface to form a biofilm to reduce surface roughness, thereby changing the wettability of the rock; and biosurfactants adsorbing on the rock surface through electrostatic force, thereby changing the wettability of the rock by desorbing crude oil from the rock surface through competitive adsorption. Targeted wetting systems are constructed based on the different mineral compositions of medium and low permeability oil reservoirs.

[0035] Because low- to medium-permeability reservoirs have low permeability, greater capillary forces than ordinary reservoirs, and contain more clay minerals and impurities, the clay minerals are highly water-sensitive and have a high degree of swelling. Water phases easily form bound water near the wellbore, resulting in ineffective displacement of oil and water wells and suboptimal oil recovery efficiency. Therefore, to increase the effective volume of the wetting system, pressure flooding technology is used to effectively change the rock wettability in the residual oil-rich areas deep within the reservoir and improve recovery.

[0036] Because clay minerals have a large specific surface area and their crystal edges are charged, they have strong adsorption capacity. To ensure the scope and efficiency of the wetting system, the present invention also adopts single-round and multi-round pressure flooding technologies based on the clay content in the reservoir to further improve the recovery rate.

[0037] Compared with the prior art, the microbial wetting control method and wetting system injection process for medium and low permeability oil reservoirs disclosed in the present invention have the following beneficial effects:

[0038] (1) The wetting system constructed by the present invention for medium and low permeability reservoirs with different mineral compositions can effectively reduce the surface roughness of rocks from 2 μm to 500 nm, effectively changing the wettability of the rock surface, and increasing the wettability index from -0.16 to 0.24;

[0039] (2) The present invention adopts single-round and multi-round pressure-driven injection processes for different clay contents, effectively ensuring the scope and efficiency of the wetting system;

[0040] (3) The present invention has the advantages of wide applicability to oil reservoirs, strong pertinence, and good field test results. The effective period is greater than 12 months, the daily oil increase per well is greater than 6.8 tons, and the input-output ratio is greater than 1:8. BRIEF DESCRIPTION OF THE DRAWINGS

[0041] Figure 1 The present invention discloses a flow chart of a method for controlling microbial wetting in medium and low permeability oil reservoirs. DETAILED DESCRIPTION

[0042] The specific embodiments of the present invention are described in detail below.

[0043] Example 1

[0044] A medium-low permeability reservoir A in Shengli Oilfield has a water content of >90%, a crude oil viscosity of 2080 mPa·s, a reservoir temperature of 60°C, and a permeability of 60×10 -8 μm 2 , the mineralization of formation water is 2556mg / L. Before the test, the injection pressure was 28MPa and the injection volume was 12m 3 / d, and the average daily oil production of a single well is 1.4t / d.

[0045] The steps of implementing the present invention are as follows:

[0046] (1) Screening of test reservoirs

[0047] The test well temperature is 60℃, the formation crude oil viscosity is 2080mPa·s, the formation water salinity is 2556mg / L, and the permeability is 60×10 -8 μm 2 , the block is a sandstone reservoir, which meets the screening criteria of the present invention.

[0048] (2) Analyze the mineral composition of the natural core, and then conduct a secondary screening of the test reservoir after the screening in step (1)

[0049] The composition of the natural core of the oil reservoir in this block was analyzed using an X-ray diffractometer, and the results are shown in Table 1.

[0050] Table 1 Analysis of mineral composition of natural core

[0051] Mineral composition type Mineral composition content clay 18.5％ quartz 47.7％ plagioclase 9.2％ Potassium feldspar 16.4％ calcite 3.6％ dolomite 4.1％ pyrite 0.3％

[0052] It can be seen from Table 1 that a low to medium permeability reservoir A in Shengli Oilfield meets the secondary screening criteria of the present invention.

[0053] (3) Evaluation of microbial wetting system

[0054] The BATH method was used to evaluate the hydrophobicity of different microbial cells under the reservoir conditions. Microbial cells with a hydrophobicity greater than 40% and less than 70% were selected and atomic force microscopy was used to characterize the surface roughness of the natural core before and after treatment. The results are shown in Table 2.

[0055] Table 2 Hydrophobicity of microbial cells under reservoir conditions

[0056]

[0057]

[0058] Candida, Acinetobacter, and Geobacillus were selected and compounded with 5% lipopeptide, 10% rhamnolipid, and 15% sophorolipid, respectively. The wetting degree was measured using the Amott method to construct the wetting system for this block. The results are shown in Table 3.

[0059] Table 3 Microbial wetting system

[0060]

[0061] In the above steps, it was found that the 5% lipopeptide and Acinetobacter complex and the 15% sophorolipid and Candida complex could both meet the wettability modification requirements, and further characterization of the roughness of the composite system was required. The results are shown in Table 4.

[0062] Table 4 Characterization of the roughness of microbial wetting systems

[0063] Wetting system Roughness 5% Lipopeptide & Acinetobacter 1.03μm 15% Sophorolipids & Candida 579nm

[0064] Finally, after characterizing the roughness of the wetting system and measuring the wetting index, Candida albicans combined with 15% sophorolipids was selected as the wetting system for this block.

[0065] (1) Microbial wetting system selected by multiple rounds of pressure injection

[0066] Since the clay content in the oil reservoir of this block is 18.5%, which is greater than 10%, a multi-round pressure drive injection process is directly adopted.

[0067] First, the optimized wetting system was configured using the injection water of the experimental reservoir, Candida albicans combined with 15% sophorolipids;

[0068] Secondly, it was injected from the injection well of the test block by multiple rounds of pressure drive method, with an injection pressure of 44MPa and an injection speed of 0.75m 3 / min, injection volume is 12000m 3 , shut down the well for 10 days;

[0069] After that, the second round of pressure drive was carried out with an injection pressure of 44 MPa and an injection speed of 0.75 m 3 / min, injection volume is 12000m 3 , water injection was resumed after the well was shut down for 7 days.

[0070] (5) Field test and evaluation of field test results

[0071] Field test results: The optimized wetting system was injected into the formation by multiple rounds of pressure drive and then the well was started for production. The injection pressure was 23MPa and the injection volume was 21m 3 / d, the average daily oil production of a single well is 7.5t / d, the effective period is 18 months, and the input-output ratio is 1:9.5.

[0072] Example 2

[0073] A medium-low permeability reservoir B in Shengli Oilfield has a water content of >90%, a crude oil viscosity of 756 mPa·s, a reservoir temperature of 70°C, and a permeability of 40×10-8 μm 2 , the mineralization of formation water is 420mg / L. Before the test, the injection pressure was 32MPa and the injection volume was 8m 3 / d, and the average daily oil production of a single well is 0.8t / d.

[0074] The steps of implementing the present invention are as follows:

[0075] (1) Screening of test reservoirs

[0076] The test well temperature is 70℃, the formation crude oil viscosity is 756mPa·s, the formation water salinity is 420mg / L, and the permeability is 40×10 -8 μm 2 , the block is a sandstone reservoir, which meets the reservoir screening criteria of the present invention.

[0077] (2) Analyze the mineral composition of the natural core, and then conduct a secondary screening of the test reservoir after the screening in step (1)

[0078] The composition of the natural core of the oil reservoir in this block was analyzed using an X-ray diffractometer, and the results are shown in Table 5.

[0079] Table 5 Analysis of mineral composition of natural core

[0080] Mineral composition type Mineral composition content clay 7.9％ quartz 47.0％ plagioclase 16.7％ Potassium feldspar 18.8％ calcite 4.7％ dolomite 4.5％ pyrite 0.4％

[0081] As can be seen from Table 5, a low to medium permeability reservoir B in Shengli Oilfield meets the secondary screening criteria for the reservoirs of the present invention.

[0082] (3) Evaluation of microbial wetting system

[0083] The BATH method was used to evaluate the hydrophobicity of different microbial cells under the reservoir conditions. Microbial cells with a hydrophobicity greater than 40% and less than 70% were selected and the surface roughness of the natural cores before and after treatment was characterized using atomic force microscopy. The results are shown in Table 6.

[0084] Table 6 Hydrophobicity of microbial cells under reservoir conditions

[0085] Microbial cell types hydrophobicity Roughness blank - 6.08μm Bacillus subtilis 51％ 570μm Pseudomonas aeruginosa 45％ 653nm Candida 80％ 237nm Lactobacillus acidophilus 24％ 4.42μm Micrococcus 17％ 5.55μm Acinetobacter 33％ 1.85μm Rhodococcus 38％ 1.37μm Geobacillus 49％ 603nm Oil Bacillus 63％ 333nm Enterobacteriaceae 32％ 1.79μm

[0086] Candida, Acinetobacter, and Geobacillus were selected and compounded with 10% lipopeptide, 20% rhamnolipid, and 5% sophorolipid, respectively. The wetting degree was measured using the Amott method to construct the wetting system for this block. The results are shown in Table 7.

[0087] Table 7 Microbial wetting system

[0088]

[0089]

[0090] In the above steps, it was found that the complex of Pseudomonas aeruginosa and 20% rhamnolipid could meet the wettability modification requirements, and then the roughness of the system was characterized. The results are shown in Table 8.

[0091] Table 8 Characterization of the roughness of microbial wetting systems

[0092] Wetting system Roughness Pseudomonas aeruginosa with 20% rhamnolipid 727μm

[0093] Finally, after characterizing the roughness of the wetting system and measuring the wetting index, it was determined that Pseudomonas aeruginosa combined with 20% rhamnolipid was the wetting system for this block.

[0094] (4) Single-round pressure injection of the optimal microbial wetting system

[0095] Since the clay content in the oil reservoir of this block is 7.9%, which is less than 10%, a single-round pressure drive injection process is adopted.

[0096] First, the optimized wetting system was configured using the injection water of the test block, and Pseudomonas aeruginosa was combined with 20% rhamnolipid;

[0097] Then, it was injected from the injection well of the test reservoir in a single round of pressure drive with an injection pressure of 47 MPa and an injection speed of 1.5 m 3 / min, injection volume is 20000m 3 , water injection was resumed after the well was shut down for 10 days.

[0098] (5) Field test and evaluation of field test results

[0099] Field test results: After the optimized wetting system was injected into the formation by a single-round pressure drive method, the well was shut down for 10 days. After the well was opened for production, the injection pressure was 25MPa and the injection volume was 16m 3 / d, the average daily oil production of a single well is 8.6t / d, the effective period is 24 months, and the input-output ratio is 1:11.4.

[0100] Example 3

[0101] A medium-low permeability reservoir C in Shengli Oilfield has a water content of >90%, a crude oil viscosity of 1423 mPa·s, a reservoir temperature of 55°C, and a permeability of 90×10 -8 μm 2 , the formation water salinity is 1850mg / L. Before the test, the injection pressure was 22MPa and the injection volume was 15m 3 / d, and the average daily oil production of a single well is 2.6t / d.

[0102] The steps of implementing the present invention are as follows:

[0103] (1) Screening of test reservoirs

[0104] The test well temperature is 55°C, the formation crude oil viscosity is 1423 mPa·s, the formation water salinity is 1850 mg / L, and the permeability is 90×10 -8 μm 2 , the block is a sandstone reservoir, which meets the reservoir screening criteria of the present invention.

[0105] (2) Analyze the mineral composition of the natural core, and then conduct a secondary screening of the test reservoir after the screening in step (1)

[0106] The composition of the natural core of the oil reservoir in this block was analyzed using an X-ray diffractometer, and the results are shown in Table 9.

[0107] Table 9 Mineral composition analysis of natural core

[0108]

[0109]

[0110] As can be seen from Table 9, a low to medium permeability reservoir C in Shengli Oilfield meets the secondary screening criteria for the reservoirs of the present invention.

[0111] (3) Evaluation of microbial wetting system

[0112] The BATH method was used to evaluate the hydrophobicity of different microbial cells under the reservoir conditions. Microbial cells with a hydrophobicity greater than 40% and less than 70% were selected and the surface roughness of the natural cores before and after treatment was characterized using atomic force microscopy. The results are shown in Table 10.

[0113] Table 10 Hydrophobicity of microbial cells under reservoir conditions

[0114] Microbial cell types hydrophobicity Roughness blank - 5.38μm Bacillus subtilis 27％ 3.82μm Pseudomonas aeruginosa 22％ 4.26μm Candida 45％ 714nm Lactobacillus acidophilus 33％ 2.85μm Micrococcus 40％ 956nm Acinetobacter 55％ 505μm Rhodococcus 30％ 3.07μm Geobacillus 19％ 4.32μm Oil Bacillus 76％ 233nm Enterobacteriaceae 38％ 1.19μm

[0115] Candida, Acinetobacter, and Geobacillus were selected and compounded with 30% lipopeptide, 5% rhamnolipid, and 10% sophorolipid. The wetting degree was measured using the Amott method to construct the wetting system for this block. The results are shown in Table 11.

[0116] Table 11 Microbial wetting system

[0117]

[0118] In the above steps, it was found that the complexation of Candida and 20% lipopeptide and the complexation of Acinetobacter and 20% lipopeptide both met the wettability modification requirements, and the roughness of the two systems was characterized. The results are shown in Table 12.

[0119] Table 12 Characterization of the roughness of microbial wetting systems

[0120] Wetting system Roughness Candida with 30% lipopeptides 1.23μm Acinetobacter with 20% lipopeptide 543nm

[0121] Finally, after characterizing the roughness of the wetting system and measuring the wetting index, it was determined that Acinetobacter complexed with 20% lipopeptide was the wetting system for this block.

[0122] (4) Multiple rounds of pressure injection to select the optimal microbial wetting system

[0123] Since the clay content in the oil reservoir of this block is 12.9%, which is greater than 10%, a multi-round pressure drive injection process is adopted.

[0124] Firstly, the optimized wetting system of injection water of the experimental reservoir was configured, and Acinetobacter was combined with 20% lipopeptide;

[0125] Secondly, it was injected from the injection well of the test reservoir by multiple rounds of pressure drive, with an injection pressure of 40MPa and an injection speed of 0.5m 3 / min, injection volume is 10000m 3 , shut down the well for 10 days;

[0126] After that, the second round of pressure drive was carried out with an injection pressure of 40 MPa and an injection speed of 0.5 m 3 / min, injection volume is 10000m 3 , water injection was resumed after the well was shut down for 7 days.

[0127] (5) Field test and evaluation of field test results

[0128] Field test results: The optimized wetting system was injected into the formation by multiple rounds of pressure drive. After the well was put into production, the injection pressure was 16MPa and the injection volume was 25m 3 / d, the average daily oil production of a single well is 9.2t / d, the effective period is 30 months, and the input-output ratio is 1:12.3.

[0129] The embodiments of the present invention have been described in detail above, but the present invention is not limited to the above embodiments, and various modifications can be made within the scope of knowledge possessed by those skilled in the art without departing from the spirit of the present invention.

Claims

1. A method for controlling microbial wetting in medium and low permeability oil reservoirs, characterized in that: The following steps are involved: (1) Screening of test reservoirs; (2) analyzing the mineral composition of the natural core of the test reservoir, and then performing a secondary screening on the test reservoir screened in step (1); (3) Evaluation of microbial wetting systems, including: In step (2), the secondary screening criteria for the test reservoirs screened in step (1) are: Clay content is 1-20%, quartz content is 30-50%, potassium feldspar content is 5-20%, plagioclase content is 5-20%, calcite content is 1-10%, dolomite content is 1-10%, and pyrite content is 0-0.5%; The microbial wetting system evaluation described in step (3) includes the following steps: (31) A microbial fermentation liquid with a hydrophobicity greater than 40% and less than 70% is compounded with a biosurfactant aqueous solution with a mass concentration of 1 to 30% in a mass ratio of 1:1 to 10 to obtain a wetting system, and then wetting control is performed; (32) Characterization of wettability and surface roughness of natural cores before and after the action of the wetting system; (33) Selection criteria for microbial wetting system: the wetting range is [-0.2, 0.5], and the surface roughness range is 100 nm to 1 μm.

2. The method for controlling microbial wetting in medium and low permeability oil reservoirs according to claim 1, wherein: The screening criteria for the test reservoir in step (1) are: reservoir temperature < 90 °C, formation crude oil viscosity < 3000 mPa·s, formation water salinity < 30000 mg / L, permeability < 100×10 -3 μm 2 , sandstone reservoirs.

3. The method for controlling microbial wetting in medium and low permeability oil reservoirs according to claim 1, wherein: The mineral composition of the natural core described in step (2) includes one or more of clay, quartz, plagioclase, potassium feldspar, calcite, dolomite, and pyrite.

4. The method for controlling microbial wetting in low to medium permeability oil reservoirs according to claim 1, wherein: In step (31), the microbial cells having a hydrophobicity greater than 40% and less than 70% under reservoir conditions are one or more of Bacillus subtilis, Pseudomonas aeruginosa, Candida albicans, Lactobacillus acidophilus, Micrococcus, Acinetobacter, Rhodococcus, Geobacillus, Oleobacter, and Enterobacter.

5. The method for controlling microbial wetting in medium and low permeability oil reservoirs according to claim 1, wherein: In step (31), the biosurfactant is at least one of lipopeptide, rhamnolipid and sophorolipid.

6. Microbial wetting system injection process for medium and low permeability oil reservoirs, characterized by: The following steps are involved: S1. Determine whether the clay content in the natural rock of the test reservoir is less than 10%. If so, inject the wetting system that meets the selection criteria in the method for microbial wetting control in medium- and low-permeability oil reservoirs according to any one of claims 1 to 5 through a single round of pressure flooding. Otherwise, inject the wetting system that meets the selection criteria in the method for microbial wetting control in medium- and low-permeability oil reservoirs according to any one of claims 1 to 5 through multiple rounds of pressure flooding. S2. Field test and evaluation of field test results.

7. The microbial wetting system injection process for low to medium permeability oil reservoirs according to claim 6, characterized in that: The single-pass pressure injection of the selected wetting system includes the following steps: First, the selected wetting system is configured using the injection water of the test reservoir; Then the prepared wetting system is injected from the injection well of the test reservoir in a single round of pressure drive with an injection pressure of 40-50 MPa and an injection speed of 0.5-2.0 m 3 / min, injection volume is 10000~30000m 3 ; Water injection was resumed 10 days after the well was shut down.

8. The microbial wetting system injection process for low to medium permeability oil reservoirs according to claim 6, characterized in that: The wetting system selected by multiple rounds of pressure injection includes the following steps: First, the selected wetting system is configured using the injection water of the test reservoir; Then the prepared wetting system is injected from the injection well of the test reservoir in the first round of pressure drive, with an injection pressure of 40-50 MPa and an injection speed of 0.5-2.0 m 3 / min, injection volume is 10000~30000m 3 ; Shut down the well for 10 days; After that, the second round of pressure drive was carried out with an injection pressure of 40-50 MPa and an injection speed of 0.5-2.0 m 3 / min, injection volume is 10000~30000m 3 , water injection was resumed after the well was shut down for 7 days.

9. The microbial wetting system injection process for low to medium permeability oil reservoirs according to claim 6, characterized in that: The evaluation indicators of the field test effect described in step S2 include water injection pressure, water injection volume, average daily oil production increase per well, validity period and input-output ratio.

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