Composition for microbial stabilizer, microbial stabilizer, and water-based drilling fluid

Abstract

The present invention relates to the field of oil industry drilling, and discloses a composition for a microbial stabilizer, a microbial stabilizer and its application, a water-based drilling fluid and its application. The composition contains a thermophilic bacterial strain, a nutrient solution for the thermophilic bacterial strain, urea, and a calcium source; the deposit number of the thermophilic bacterial strain is 1K04190; the content mass ratio of the thermophilic bacterial strain, the nutrient solution for the thermophilic bacterial strain, the urea, and the calcium source is 1:2-10:1-10:1-4; the OD600 of the thermophilic bacterial strain is 0.4-0.6. The microbial stabilizer obtained by using the composition for the microbial stabilizer of the present invention can effectively generate a CaCO3 precipitate with high mechanical strength. After being applied to the drilling fluid, it can regulate the rheology of the drilling fluid, reduce the leakage of the drilling fluid during drilling work, play a role in stabilizing the well wall, and also significantly improve the mechanical strength of the rock.

Description

Technical Field

[0001] The present invention relates to the field of oil industry drilling, and in particular to a composition for a microbial stabilizer, a microbial stabilizer and application thereof, and a water-based drilling fluid and application thereof. Background Art

[0002] During drilling, fractured formations are often encountered, making wellbore instability a potential risk, leading to complex downhole accidents. Statistics from hundreds of wells domestically and internationally indicate that shale formations account for 70% of all drilled formations, and over 90% of wellbore collapses occur in shale formations. Approximately two-thirds of these are hard, brittle shale formations with well-developed microcracks. These formations are characterized by fragmentation, incompleteness, poor cementation, well-developed fractures, and low formation strength. During drilling, drilling fluid enters the surrounding rock through fractures in the wellbore. Through fluid seepage and chemical reactions, the rock's cohesion and internal friction angle slowly decrease, and fissures and cracks gradually expand and connect, ultimately causing the surrounding rock to fracture or the wellbore to collapse, resulting in wellbore instability.

[0003] Existing drilling fluid and wellbore stabilization methods mainly include: inhibiting the hydration and expansion of wellbore clay; rationally selecting the drilling fluid density to slow down or prevent the transmission of rock formation pressure; reducing the high-temperature and high-pressure filtration loss of drilling fluid and the filter cake permeability, minimizing the amount of drilling fluid filtrate entering the formation, and sealing micro-cracks.

[0004] A large number of researchers have studied the hydration and dispersion mechanism of shale and developed treatment agents to inhibit the hydration and expansion of clay in the wellbore. + NH 4+ ; Asphalt treatment agents with hydrophobic properties; Water-soluble polyol-coated inhibitors that bridge clays and prevent hydration and dispersion of rock formations, etc.

[0005] However, the low hydration energy ion K + NH 4+ A very high ion concentration is required to have a significant effect in inhibiting hydration; asphalt treatment agents have the characteristics of softening at a fixed temperature and flowing under pressure differential conditions, so they need to meet specific temperature and pressure differential conditions before they can be used, and have high application requirements; the molecular weight of polymer alcohol treatment agents cannot be too large during molecular design to facilitate their entry into rock cracks, and they have a high degree of difficulty in molecular design and synthesis.

[0006] Using fluid loss reducers to increase the viscosity of drilling fluid filtrate, reduce the high-temperature and high-pressure fluid loss and filter cake permeability of drilling fluid, and minimize the amount of drilling fluid filtrate entering the formation can effectively maintain wellbore stability. However, the limitation of this method is that it cannot improve the mechanical properties of the wellbore itself.

[0007] Plugging agents can be used to fill and seal cracks in rock formations. While preventing drilling fluid from flowing into the formation, they can effectively fill the pores and cracks in the wellbore rock, improving the mechanical properties of the wellbore and increasing the rock's pressure-bearing capacity. Commonly used asphalt plugging agents can soften and flow at specific temperatures. Once they enter the cracks, they can solidify due to temperature changes to form a plugging layer. However, asphalt plugging agents have high requirements for environmental conditions. Commonly used polymer plugging agents are soluble in water and have fluidity. After entering the cracks, they can precipitate and form a plugging layer. However, higher molecular weight polymer plugging agents have poor adaptability to formation cracks and cannot fully penetrate small cracks to exert their plugging effect.

[0008] Therefore, there is an urgent need to explore a drilling fluid technology that can inhibit clay hydration, seal well wall cracks, cement rocks, and improve rock mechanical properties to meet the well wall stability requirements of broken and fractured formations.

[0009] CN109097007A discloses a microbial solid-free drilling fluid, characterized by comprising a Bacillus pasteurianus bacterial solution, a solid-free drilling fluid, and a nutrient solution. While this drilling fluid exhibits good wellbore stabilization, it suffers from poor temperature resistance and cannot be used for extended periods of time underground. Summary of the Invention

[0010] The purpose of the present invention is to solve the problem that the drilling fluid in the prior art cannot improve the instability of the well wall in the fractured formation and the mechanical properties of the rock formation decrease.

[0011] In order to achieve the above object, the first aspect of the present invention provides a composition for a microbial stabilizer, the composition comprising a thermophilic strain, a nutrient solution for the thermophilic strain, urea, and a calcium source; the thermophilic strain has a deposit number of 1K04190;

[0012] The mass ratio of the thermophilic strain, the nutrient solution for the thermophilic strain, the urea and the calcium source is 1:2-10:1-10:1-4; and the OD600 of the thermophilic strain is 0.4-0.6.

[0013] The second aspect of the present invention provides a microbial stabilizer, which is obtained by mixing the components of a composition for a microbial stabilizer; the composition for a microbial stabilizer is the composition for a microbial stabilizer described in the first aspect.

[0014] The third aspect of the present invention provides the use of the composition for microbial stabilizer described in the first aspect and the microbial stabilizer described in the second aspect as a wellbore stabilizer in the field of drilling fluid.

[0015] A fourth aspect of the present invention provides a water-based drilling fluid, which contains the following components:

[0016] Water, microbial stabilizers, inhibitors, plugging agents, and fluid loss reducers;

[0017] Relative to 100 parts by weight of water, the content of the microbial stabilizer is 4.5-25.5 parts by weight, the content of the inhibitor is 2-6 parts by weight, the amount of the plugging agent is 5-11 parts by weight, and the amount of the fluid loss additive is 0.6-2.6 parts by weight;

[0018] The microbial stabilizer is the microbial stabilizer described in the second aspect.

[0019] The fifth aspect of the present invention provides the use of the water-based drilling fluid described in the fourth aspect in the field of petroleum industry.

[0020] The microbial stabilizer obtained by using the composition for microbial stabilizer of the present invention can effectively generate CaCO3 precipitate with high mechanical strength. After being applied to drilling fluid, it can regulate the rheological properties of the drilling fluid, improve the viscosity of the drilling fluid, effectively reduce the filtration loss, reduce the leakage of the drilling fluid during drilling work, play a role in stabilizing the well wall, and at the same time can significantly improve the mechanical strength of the rock, reduce the occurrence of complex accidents underground, and bring about improved economic benefits. BRIEF DESCRIPTION OF THE DRAWINGS

[0021] Figure 1 This is a graph showing the growth of thermophilic bacteria at different temperatures using the water-based drilling fluid S1 provided by the present invention;

[0022] Figure 2 This is a test chart of the inhibition performance of the water-based drilling fluid S1 provided in Example 1 of the present invention. DETAILED DESCRIPTION

[0023] The endpoints of the ranges and any values ​​disclosed herein are not limited to the precise ranges or values, and these ranges or values ​​should be understood to include values ​​close to these ranges or values. For numerical ranges, the endpoints of each range, the endpoints of each range and individual point values, and the individual point values ​​can be combined with each other to obtain one or more new numerical ranges, which should be considered to be specifically disclosed herein.

[0024] As mentioned above, the first aspect of the present invention provides a composition for a microbial stabilizer, which contains a thermophilic strain, a nutrient solution for the thermophilic strain, urea, and a calcium source; the thermophilic strain has a deposit number of 1K04190;

[0025] The mass ratio of the thermophilic strain, the nutrient solution for the thermophilic strain, the urea and the calcium source is 1:2-10:1-10:1-4; and the OD600 of the thermophilic strain is 0.4-0.6.

[0026] Preferably, the growth temperature of the thermophilic strain is 60-120° C., and the growth pH range is 4-9.

[0027] In the present invention, the thermophilic strain has the ability of autonomous movement and has an average diameter of 0.8-2.4 μm.

[0028] Preferably, the thermophilic strain is cultured using an anaerobic static culture method.

[0029] Preferably, in the present invention, the nutrient solution for thermophilic strains contains the following components in effective doses for the growth of thermophilic strains:

[0030] Sodium chloride, ammonium sulfate, sodium bromide, strontium chloride, yeast extract, tryptone, potassium hydrogen phosphate, potassium dihydrogen phosphate, calcium chloride dihydrate, sodium tungstate, ferric chloride, maltose, resin azure, 1,4-piperazine diethanesulfonic acid, magnesium chloride hexahydrate, potassium chloride.

[0031] It should be noted that, in the present invention, there are no special requirements for the dosage ratio of each component in the nutrient solution for thermophilic strains, as long as the growth requirements of thermophilic strains are met. Those skilled in the art can make routine adjustments based on the properties of each component and the growth requirements of thermophilic strains. The present invention will exemplify the preparation steps of the nutrient solution for thermophilic strains under the preferred embodiment in the following examples, which will not be described one by one here. Those skilled in the art should not understand this as a limitation of the present invention.

[0032] Preferably, the calcium source is selected from at least one of calcium chloride, calcium acetate, calcium acetate, and calcium lactate.

[0033] More preferably, the mass ratio of the thermophilic strain, the nutrient solution for the thermophilic strain, the urea, and the calcium source is 1:5-10:4-8:1-2. The inventors have found that under this preferred embodiment, the thermophilic strain can more effectively decompose urea to form an alkaline environment, thereby generating carbonate ions, which react with calcium ions to produce more calcium carbonate precipitate.

[0034] As mentioned above, the second aspect of the present invention provides a microbial stabilizer, which is obtained by mixing the components of the composition for microbial stabilizer; the composition for microbial stabilizer is the composition for microbial stabilizer described in the first aspect.

[0035] As mentioned above, the third aspect of the present invention provides the use of the composition for microbial stabilizer described in the first aspect and the microbial stabilizer described in the second aspect as a wellbore stabilizer in the field of drilling fluid.

[0036] As mentioned above, the fourth aspect of the present invention provides a water-based drilling fluid, which contains the following components:

[0037] Water, microbial stabilizers, inhibitors, plugging agents, and fluid loss reducers;

[0038] Relative to 100 parts by weight of water, the content of the microbial stabilizer is 4.5-25.5 parts by weight, the content of the inhibitor is 2-6 parts by weight, the amount of the plugging agent is 5-11 parts by weight, and the amount of the fluid loss additive is 0.6-2.6 parts by weight;

[0039] The microbial stabilizer is the microbial stabilizer described in the second aspect above.

[0040] Preferably, relative to 100 parts by weight of water, the content of the microbial stabilizer is 10.5-21.5 parts by weight, the content of the inhibitor is 3.5-5 parts by weight, the amount of the plugging agent is 5-8 parts by weight, and the amount of the fluid loss reducer is 0.7-1.4 parts by weight.

[0041] Preferably, the inhibitor is selected from at least one of KCl and sodium humate.

[0042] More preferably, the inhibitor is a combination of KCl and sodium humate. The inventors have found that under this preferred embodiment, the water-based drilling fluid obtained by the present invention has better rheological properties and fluid loss reduction performance.

[0043] Further preferably, the inhibitor is a combination of KCl and sodium humate in a mass ratio of 1:0.3-3.

[0044] Preferably, the plugging agent is selected from at least one of white asphalt and potassium humate.

[0045] More preferably, the plugging agent is a combination of white asphalt and potassium humate.

[0046] More preferably, the plugging agent is a combination of white asphalt and potassium humate in a mass ratio of 1:0.125-0.75. The inventors have found that under this preferred embodiment, the water-based drilling fluid obtained by the present invention has better rheological properties and fluid loss reduction performance.

[0047] Preferably, the fluid loss reducer is selected from at least one of polyacrylamide and polyanionic cellulose.

[0048] More preferably, the fluid loss additive is a combination of polyacrylamide and polyanionic cellulose.

[0049] Further preferably, the fluid loss additive is a combination of polyacrylamide and polyanionic cellulose in a mass ratio of 1:0.8-20; the polyanionic cellulose has a viscosity of ≤40 mPa·s at 25°C; and the polyacrylamide is nonionic. The inventors have discovered that, under this preferred embodiment, the water-based drilling fluid obtained by the present invention exhibits improved rheological properties and fluid loss reduction performance.

[0050] According to a preferred embodiment, the preparation steps of the water-based drilling fluid include:

[0051] Water, montmorillonite, sodium carbonate, microbial stabilizer, inhibitor, plugging agent, fluid loss reducer and weighting agent are contacted and mixed, and the pH value of the obtained product is adjusted to 7-10 with NaOH to obtain the water-based drilling fluid.

[0052] Preferably, relative to 100 parts by weight of water, the amount of the montmorillonite is 4-6 parts by weight; the amount of the sodium carbonate is 1.6-2.4 parts by weight.

[0053] In order to meet the needs of drilling in different complex formations, in the present invention, a weighting agent of appropriate weight can be selected to obtain drilling fluids of different densities; preferably, the weighting agent is selected from at least one of barite and iron ore.

[0054] As mentioned above, the fifth aspect of the present invention provides the use of the water-based drilling fluid described in the fourth aspect in the field of petroleum industry.

[0055] The present invention will be described in detail below through examples. In the following examples, unless otherwise specified, all reagents and instruments used are commercially available and all reagents are analytically pure.

[0056] Thermophilic strain: The deposit number is 1K04190, and the deposit center is: China Marine Microbial Culture Collection Center, the Third Institute of Oceanography;

[0057] Yeast extract: Product No. 84106D; purchased from Shanghai Titan Technology Co., Ltd.

[0058] Resin Azure: Product No. R105538-100g; purchased from Beijing Yinuokai Technology Co., Ltd.

[0059] Preparation Example A

[0060] This preparation example is used to illustrate the preparation steps of a preferred embodiment of the nutrient solution for thermophilic bacterial strains of the present invention:

[0061]

[0062] Preparation Example B

[0063] This preparation example is used to illustrate that the thermophilic strain provided by the present invention is activated and cultured in the following activation manner:

[0064] The purchased thermophilic strain (1 mL) was added to a 10 mL culture dish containing the culture medium prepared in Preparation Example A above. The dish was placed in an 85°C oven and cultured for 2 days. The mixture was then mixed with glycerol at a 1:1 volume ratio and frozen at -80°C.

[0065] The frozen bacterial solution was thawed, and 1 mL of the thawed bacterial solution was taken to repeat the above steps of culturing, freezing, thawing, and culturing 6 times to obtain the thermophilic strain required for the experiment.

[0066] Preparation Example 1

[0067] This preparation example is used to illustrate that the microbial stabilizer of the present invention is prepared as follows:

[0068] The thermophilic strain was mixed with a nutrient solution, urea, calcium chloride, and the thermophilic strain to obtain a microbial stabilizer Z-1; the OD600 of the thermophilic strain was 0.5; and the mixing temperature was 25° C.;

[0069] The mass ratio of the thermophilic strain, the nutrient solution for the thermophilic strain, the urea and the calcium chloride is 1:5:4:1.

[0070] Unless otherwise specified, the remaining preparation examples were carried out using a process similar to that of Preparation Example 1, except that the formulas used in each preparation example were different. Please refer to Table 1 for details (Note: the parameters not listed in Table 1 are the same as the corresponding parameters in Preparation Example 1).

[0071] Table 1

[0072]

[0073] The urea decomposition ability of the microbial stabilizers obtained in Preparation Examples 1-7 was tested by the Nesler method, and the urea decomposition ability of the microbial stabilizers obtained in Preparation Examples 8-12 was tested by the conductivity method. The test method is as follows:

[0074] Nesler method: Take 2 ml of microbial stabilizer samples with different calcium ion concentrations and add them to a cuvette, add 100 μL of Nessler reagent, react for 1 min, and read the sample with a spectrophotometer at 425 nm. This method determines the urea decomposition ability by measuring the ammonium ion concentration (OD600).

[0075] Conductivity method: Measure the conductivity 10 minutes after the microbial stabilizer is prepared. Then calculate the urease activity, expressed as the amount of urea decomposed.

[0076] The results are shown in Table 2.

[0077] Table 2

[0078]

[0079] It can be seen from the results in Table 2 that the microbial stabilizer prepared from the composition for microbial stabilizer provided by the present invention has a strong ability to induce microorganisms to produce calcium, and can improve the performance of the microbial stabilizer in solidifying rocks.

[0080] Example 1

[0081] This example is used to illustrate that the water-based drilling fluid provided by the present invention is prepared by the following method:

[0082] water, montmorillonite, sodium carbonate, a microbial stabilizer, an inhibitor, a plugging agent, and a fluid loss reducer are contacted and mixed, and the pH value of the obtained product is adjusted to 8 with NaOH to obtain the water-based drilling fluid;

[0083] The contact mixing conditions are: temperature of 25°C, stirring speed of 2000 r / min, and time of 20 min;

[0084] Relative to 100 parts by weight of water, the amount of the montmorillonite is 4 parts by weight; the amount of the sodium carbonate is 1.6 parts by weight.

[0085] Unless otherwise specified, the remaining examples were carried out using a process similar to that of Example 1, except that the formulations used in each example were different. For details, see Table 3 (Note: the parameters not listed in Table 3 are the same as the corresponding parameters in Example 1).

[0086] Table 3

[0087]

[0088] Example 7

[0089] This example was carried out using a process similar to that of Example 1, except that the sodium humate in Example 1 was replaced by a polyamine inhibitor (model: YZJ; manufacturer: Beijing Shidabocheng Technology Co., Ltd.) of equal mass.

[0090] The rest are the same as in Example 1.

[0091] Water-based drilling fluid S7 was prepared.

[0092] Example 8

[0093] This example was carried out using a process similar to that of Example 1, except that guar gum (model: R096819; manufacturer: Inokai) of equal mass was used to replace the polyanionic cellulose (item number: P875546-500g; brand: McLean) in Example 1.

[0094] The rest are the same as in Example 1.

[0095] Water-based drilling fluid S8 was prepared.

[0096] Example 9

[0097] This example is carried out using a process similar to that of Example 1, except that an equal mass of anionic polyacrylamide (anionic, model: 013631213; manufacturer: Shanghai Titan Technology Co., Ltd.) is used to replace the nonionic polyacrylamide (nonionic, model: 013631159; manufacturer: Shanghai Titan Technology Co., Ltd.) in Example 1.

[0098] The rest are the same as in Example 1.

[0099] Water-based drilling fluid S9 was prepared.

[0100] Example 10

[0101] This example was carried out using a process similar to that of Example 1, except that the potassium humate in Example 1 was replaced by organosilicon (model: GF1; manufacturer: Beijing Shida Bocheng Technology Co., Ltd.) of equal mass.

[0102] The rest are the same as in Example 1.

[0103] A water-based drilling fluid S10 was prepared.

[0104] Comparative Example 1

[0105] This comparative example was carried out using a process similar to that of Example 1, except that the microbial stabilizer Z-1 was not used in this comparative example.

[0106] The rest are the same as in Example 1.

[0107] Water-based drilling fluid DS1 was prepared.

[0108] Test Example 1

[0109] This test example is used to illustrate the growth of thermophilic bacteria in the water-based drilling fluid S1 provided by the present invention at different temperatures. Figure 1 .

[0110] from Figure 1As can be seen from the figure, at 25°C and 60°C, the strain's growth ability in the system is relatively poor. Even after 48 hours, the culture medium is still not completely consumed, and the strain is still in a state of continuous growth. In the temperature range of 70-100°C, the strain's growth activity is the best, and it can reach the peak growth concentration. The culture medium is completely consumed, and the proportional relationship between the initial growth rate and the peak growth concentration is satisfied. In the temperature range of 110-120°C, the strain's growth ability begins to decline, and the growth rate decreases, and the peak growth concentration also begins to decrease. In summary, the optimal temperature range for this water-based drilling fluid is 70-120°C.

[0111] Test Example 2

[0112]

[0113] The results are shown in Table 4.

[0114] Table 4

[0115]

[0116] From the results in Table 4, it can be seen that the microbial stabilizer provided by the present invention is applied to the drilling fluid system to reduce the fluid loss performance of the drilling fluid.

[0117] Test Example 3

[0118] This test example is used to illustrate the inhibition performance of the water-based drilling fluid (S1) provided in Example 1 of the present invention. The test method is as follows:

[0119] The system's inhibition performance was evaluated through a linear expansion test. Using a dual-channel shale dilatometer, the difference in swelling height of bentonite in the S1 system and deionized water over a period of time was measured. This allowed for a direct measurement of the treatment solution's ability to inhibit clay hydration expansion. The specific process is as follows:

[0120] (1) Cut a circular filter paper of appropriate size and place it at the bottom of the pressure tank. Weigh 5g of bentonite and pour it into the pressure tank. Place another circular filter paper and press it with a hydraulic press at a pressure of 10 MPa for 5 minutes to form a rock block. (The purpose of placing the second filter paper is to prevent uneven expansion of the compressed bentonite after adding the solution).

[0121] (2) Start the linear expansion measurement software in the computer, install the pressure tank containing the compressed bentonite rock block on the measurement channel of the dual-channel shale dilatometer, and lock the edge of the pressure tank into the groove to reset the initial value of the dilatometer to zero.

[0122] (3) Use a dropper to slowly add the system solution along the inner wall of the pressure tank until a convex liquid surface appears above the pressure tank. Click the start button to start recording the change of the expansion height of the bentonite block over time.

[0123] (4) Record the expansion height after 16 hours and export all data measured by the software to a table for storage and processing.

[0124] Test results see Figure 2 .

[0125] from Figure 2 It can be seen that the test results show that the water-based drilling fluid system formula provided by the present invention has good inhibition performance, and the linear expansion height of the system is reduced by 89.4% compared with water.

[0126] Test Example 4

[0127] This test example is used to illustrate the uniaxial compressive strength performance of the core soaked in the water-based drilling fluid provided by the present invention;

[0128] The test method is:

[0129] Artificial cores (carbonate rock) were tested for wellbore stability;

[0130] Test system 1: blank control, no core immersion treatment;

[0131] Test system 2: using water-immersed cores;

[0132] Test system 3: the water-based drilling fluid S1 obtained in Example 1 of the present invention, with 320 parts by weight of barite added to 100 parts by weight of water;

[0133] Test system 4: the water-based drilling fluid S2 obtained in Example 2 of the present invention, with 320 parts by weight of barite added to 100 parts by weight of water;

[0134] Test system 5: the water-based drilling fluid S3 obtained in Example 3 of the present invention, with 320 parts by weight of barite added to 100 parts by weight of water;

[0135] Test system 6: the water-based drilling fluid S4 obtained in Example 4 of the present invention, with 320 parts by weight of barite added to 100 parts by weight of water;

[0136] Test system 7: the water-based drilling fluid S5 obtained in Example 5 of the present invention, with 320 parts by weight of barite added to 100 parts by weight of water;

[0137] Test system 8: water-based drilling fluid S6 obtained in Example 6 of the present invention, with 320 parts by weight of barite added to 100 parts by weight of water;

[0138] Test system 9: water-based drilling fluid S7 obtained in Example 7 of the present invention, with 320 parts by weight of barite added to 100 parts by weight of water;

[0139] Test system 10: water-based drilling fluid S8 obtained in Example 8 of the present invention, with 320 parts by weight of barite added to 100 parts by weight of water;

[0140] Test system 11: water-based drilling fluid S9 obtained in Example 9 of the present invention, with 320 parts by weight of barite added to 100 parts by weight of water;

[0141] Test system 12: water-based drilling fluid S10 obtained in Example 10 of the present invention, with 320 parts by weight of barite added to 100 parts by weight of water;

[0142] Test system 13: the water-based drilling fluid DS1 obtained in Comparative Example 1 of the present invention, with 320 parts by weight of barite added to 100 parts by weight of water;

[0143] Test System 14: Similar to Test System 3, except that the biostabilizer composition does not contain urea and thermophilic strains;

[0144] Test System 15: Similar to Test System 3, except that the biostabilizer does not contain thermophilic strains;

[0145] The test results are shown in Table 5.

[0146] Table 5 (Uniaxial compressive strength test results of artificial cores)

[0147]

[0148] From the results in Table 5, it can be seen that the microbial stabilizer provided by the present invention has stronger wellbore stability and good core compressive strength after being applied to the drilling fluid system.

[0149] The preferred embodiments of the present invention have been described in detail above, but the present invention is not limited thereto. Within the technical concept of the present invention, various simple variations of the technical solution of the present invention may be made, including combining the various technical features in any other appropriate manner. These simple variations and combinations should also be regarded as disclosed in the present invention and fall within the scope of protection of the present invention.

Claims

1. A composition for a microbial stabilizer, characterized in that The composition contains a thermophilic strain, a nutrient solution for the thermophilic strain, urea, and a calcium source; the thermophilic strain has a deposit number of 1K04190; The mass ratio of the thermophilic strain, the nutrient solution for the thermophilic strain, the urea and the calcium source is 1:2-10:1-10:1-4; and the OD600 of the thermophilic strain is 0.4-0.

6.

2. The composition for microorganism stabilizer according to claim 1, characterized in that The calcium source is selected from at least one of calcium chloride, calcium acetate and calcium lactate.

3. The composition for microorganism stabilizer according to claim 1, characterized in that The mass ratio of the thermophilic strain, the nutrient solution for the thermophilic strain, the urea and the calcium source is 1:5-10:4-8:1-2.

4. A microbial stabilizer, characterized in that The microbial stabilizer is obtained by mixing various components in a composition for a microbial stabilizer; the composition for a microbial stabilizer is the composition for a microbial stabilizer according to any one of claims 1 to 3.

5. Use of the composition for microbial stabilizer according to any one of claims 1 to 3 and the microbial stabilizer according to claim 4 as a wellbore stabilizer in the field of drilling fluid.

6. A water-based drilling fluid, characterized in that: The water-based drilling fluid contains the following components: Water, microbial stabilizers, inhibitors, plugging agents, and fluid loss reducers; Relative to 100 parts by weight of water, the content of the microbial stabilizer is 4.5-25.5 parts by weight, the content of the inhibitor is 2-6 parts by weight, the amount of the plugging agent is 5-11 parts by weight, and the amount of the fluid loss additive is 0.6-2.6 parts by weight; The microbial stabilizer is the microbial stabilizer according to claim 4.

7. The water-based drilling fluid according to claim 6, characterized in that: Relative to 100 parts by weight of water, the content of the microbial stabilizer is 10.5-21.5 parts by weight, the content of the inhibitor is 3.5-5 parts by weight, the amount of the plugging agent is 5-8 parts by weight, and the amount of the fluid loss reducer is 0.7-1.4 parts by weight.

8. The water-based drilling fluid according to claim 6 or 7, characterized in that: The inhibitor is selected from at least one of KCl and sodium humate.

9. The water-based drilling fluid according to claim 8, characterized in that: The inhibitor is a combination of KCl and sodium humate.

10. The water-based drilling fluid according to claim 9, characterized in that: The inhibitor is a combination of KCl and sodium humate in a mass ratio of 1:0.3-3.

11. The water-based drilling fluid according to claim 6 or 7, characterized in that: The plugging agent is selected from at least one of white asphalt and potassium humate.

12. The water-based drilling fluid according to claim 11, characterized in that: The plugging agent is a combination of white asphalt and potassium humate.

13. The water-based drilling fluid according to claim 12, characterized in that: The plugging agent is a combination of white asphalt and potassium humate in a mass ratio of 1:0.125-0.

75.

14. The water-based drilling fluid according to claim 6 or 7, characterized in that: The fluid loss reducer is selected from at least one of polyacrylamide and polyanionic cellulose.

15. The water-based drilling fluid according to claim 14, characterized in that: The fluid loss additive is a combination of polyacrylamide and polyanionic cellulose.

16. The water-based drilling fluid according to claim 15, characterized in that The fluid loss reducer is a combination of polyacrylamide and polyanionic cellulose in a mass ratio of 1:0.8-20; the viscosity of the polyanionic cellulose at 25° C. is ≤40 mPa·s; and the polyacrylamide is nonionic polyacrylamide.

17. Use of the water-based drilling fluid according to any one of claims 6 to 16 in the field of petroleum industry.

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