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

Abstract

The invention relates to the field of drilling in the petroleum industry, and discloses a composition for a microbial stabilizer, the microbial stabilizer and application thereof, and a water-based drilling fluid and application thereof. The composition contains a thermophilic strain, a nutrient solution for the thermophilic strain, urea and a calcium source, the preservation number of the thermophilic strain is 1K04190; the content mass ratio of the thermophilic strain to the nutrient solution for the thermophilic strain to the urea to the calcium source is 1: (2-10): (1-10): (1-4); the OD600 (optical density 600) of the thermophilic strain is 0.4 to 0.6. The microbial stabilizer obtained by adopting the composition for the microbial stabilizer can effectively generate CaCO3 precipitates with high mechanical strength, can play a role in adjusting the rheological property of drilling fluid after being applied to the drilling fluid, can reduce the leakage of the drilling fluid in the drilling work, plays a role in stabilizing a well wall, and has the advantages that the drilling fluid is prevented from being damaged, and the service life of the drilling fluid is prolonged. Meanwhile, the mechanical strength of the rock can be obviously improved.

Description

Technical Field

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

[0002] During the drilling process, broken formations are often encountered, which are prone to wellbore instability and induce complex accidents underground. Statistics from hundreds of wells at home and abroad show that mud shale formations account for 70% of the total number of formations drilled, and more than 90% of drilling wellbore collapses occur in mud shale formations, of which hard and brittle mud shale formations with developed microcracks account for about two-thirds. This type of formation has significant characteristics such as brokenness, incompleteness, poor cementation, developed cracks, and low formation strength. During drilling, the drilling fluid will enter the surrounding rock through the cracks in the wellbore wall. After fluid seepage and chemical action, the rock cohesion and internal friction angle slowly decrease, and the cracks and fissures gradually expand and penetrate, eventually causing the surrounding rock to break or the wellbore wall to collapse, and the wellbore wall to become unstable.

[0003] Existing drilling fluid and wellbore stabilization methods mainly include: inhibiting the hydration and expansion of wellbore clay; reasonably 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 and filter cake permeability of the drilling fluid, minimizing the amount of drilling fluid filtrate entering the formation, and plugging microcracks.

[0004] A large number of researchers have studied the mechanism of shale hydration dispersion and developed treatment agents to inhibit the hydration expansion of wellbore clay. This includes the use of low hydration energy ions K + NH 4+ ; Asphalt treatment agents with hydrophobic properties; Water-soluble polymer alcohol-coated inhibitors that bridge clay 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 crevices, and they have a high degree of difficulty in molecular design and synthesis.

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

[0007] The use of plugging agents can fill and plug rock cracks. While preventing drilling fluid from flowing into the formation, it can effectively fill the pores in the well wall rock, improve the mechanical properties of the well wall, and increase the pressure bearing capacity of the rock. Commonly used asphalt plugging agents can soften and flow at a specific temperature. After entering the cracks, they can solidify to form a plugging layer due to temperature changes. However, asphalt plugging agents have high requirements for environmental conditions; commonly used polymer plugging agents are soluble in water and have fluidity. They can precipitate into the cracks to form a plugging layer. However, polymer plugging agents with higher molecular weights have poor adaptability to formation cracks and cannot fully enter small cracks to play a plugging role.

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

[0009] CN109097007A discloses a microbial solid-free drilling fluid, characterized in that the microbial solid-free drilling fluid comprises a bacillus pasteurianus liquid, a solid-free drilling fluid and a nutrient solution. Although the drilling fluid has a good well wall stabilization effect, it has poor temperature resistance and cannot function underground for a long time. 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 in 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, wherein the water-based drilling fluid contains the following components:

[0016] Water, microbial stabilizers, inhibitors, plugging agents, 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 reducer 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 application 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 microbial stabilizer composition of the present invention can effectively generate CaCO3 precipitates 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, and play a role in stabilizing the well wall. At the same time, it can also 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 is a graph showing the growth of thermophilic strains of the water-based drilling fluid S1 provided by the present invention at different temperatures;

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

[0023] The endpoints and any values ​​of the ranges disclosed in this article 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 endpoint values ​​of each range, the endpoint values ​​of each range and the 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 as specifically disclosed in this article.

[0024] As mentioned above, 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;

[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 its average diameter is 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 exemplarily provide 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, and those skilled in the art should not understand it 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 content 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 found that under this preferred embodiment, the thermophilic strain can more effectively decompose urea to form an alkaline environment and then generate carbonate ions, which react with calcium ions to generate more calcium carbonate precipitation.

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

[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, 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 reducer 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 filtrate 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 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] Further 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 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 reducer is a combination of polyacrylamide and polyanionic cellulose.

[0049] Further preferably, 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 ≤40mpa·s; and the polyacrylamide is nonionic polyacrylamide. 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.

[0050] According to a preferred specific 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 montmorillonite used is 4-6 parts by weight; the amount of sodium carbonate used 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 by way of examples. In the following examples, unless otherwise specified, all reagents and instruments used are commercially available, and all reagents used are of analytical grade.

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

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

[0058] Resin Azure: Product number is R105538-100g; purchased from Beijing Inokai 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 strains of the present invention:

[0061] (1) 23 g of NaCl, 5 g of MgCl2·6H2O, 0.7 g of KCl, 0.5 g of (NH4)2SO4, 0.05 g of NaBr, 0.01 g of SrCl2, 3.3 g of piperazine-1,4-diethanesulfonic acid, 1 g of yeast extract, and 4 g of trypsin were dissolved in 1 L of deionized water, and 1 mL of 4 wt% resin azure solution was added, the pH value was adjusted to 6.8, and the mixture was sterilized at high temperature for later use;

[0062] (2) Add 1 mL of sterilized 5 wt% K2HPO4 solution, 1 mL of 5 wt% KH2PO4 solution, 1 mL of 2 wt% CaCl2·2H2O solution, 1 mL of 10 mM NaWO4 solution, 1 mL of 25 mM FeCl3 solution, and 1 mL of 10 g / L maltose solution to the above-mentioned solution to obtain a nutrient solution for the thermophilic strain.

[0063] Preparation Example B

[0064] This preparation example is used to illustrate that the thermophilic strain provided by the present invention is activated and cultured by the following activation method:

[0065] The purchased thermophilic strain (1 mL) was added to a culture dish containing 10 mL of the culture medium prepared in the above Preparation Example A, and the culture dish was placed in an oven at 85°C for 2 days, and then mixed with glycerol in a volume ratio of 1:1 and frozen at -80°C;

[0066] 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.

[0067] Preparation Example 1

[0068] This preparation example is used to illustrate that the microbial stabilizer of the present invention is prepared according to the following method:

[0069] The thermophilic strain nutrient solution, urea, calcium chloride and the thermophilic strain are mixed to obtain a microbial stabilizer Z-1; the OD600 of the thermophilic strain is 0.5; and the mixing temperature is 25° C.;

[0070] 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.

[0071] 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, as shown in Table 1 (Note: the parameters not listed in Table 1 are the same as the corresponding parameters in Preparation Example 1).

[0072] Table 1

[0073]

[0074] 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:

[0075] Nesler method: Take 2 ml of microbial stabilizer sample with different calcium ion concentrations and add it to a cuvette, add 100 μL of Nessler reagent, react for 1 minute, and read the sample at 425 nm using a spectrophotometer. This method determines the urea decomposition ability by measuring the ammonium ion concentration (OD600).

[0076] Conductivity method: Measure the conductivity 10 minutes after the microbial stabilizer is prepared. Then calculate the urease activity and express it in terms of the amount of decomposed urea.

[0077] The results are shown in Table 2.

[0078] Table 2

[0079] Decomposition of urea (mM) OD600 Preparation Example 1 214 1.55 Preparation Example 2 / 1.52 Preparation Example 3 / 1.49 Preparation Example 4 / 1.35 Preparation Example 5 / 1.03 Preparation Example 6 / 0.77 Preparation Example 7 / 0.43 Preparation Example 8 127 / Preparation Example 9 168 / Preparation Example 10 232 / Preparation Example 11 197 / Preparation Example 12 153 /

[0080] It can be seen from the results in Table 2 that the microbial stabilizer prepared from the microbial stabilizer composition 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.

[0081] Example 1

[0082] This example is used to illustrate that the water-based drilling fluid provided by the present invention is prepared by the following method:

[0083] The water, montmorillonite, sodium carbonate, microbial stabilizer, inhibitor, plugging agent and 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;

[0084] The contact mixing conditions are: temperature of 25°C, stirring speed of 2000r / min, and time of 20min;

[0085] Relative to 100 parts by weight of water, the amount of the montmorillonite used is 4 parts by weight; the amount of the sodium carbonate used is 1.6 parts by weight.

[0086] 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, as shown in Table 3 (Note: the parameters not listed in Table 3 are the same as the corresponding parameters in Example 1).

[0087] Table 3

[0088]

[0089] Example 7

[0090] This example is carried out using a process similar to that of Example 1, except that this example uses an equal mass of polyamine inhibitor (model: YZJ; manufacturer: Beijing Shidabocheng Technology Co., Ltd.) to replace the sodium humate in Example 1.

[0091] The rest are the same as in Example 1.

[0092] The water-based drilling fluid S7 was prepared.

[0093] Example 8

[0094] This example is carried out using a process similar to that of Example 1, except that guar gum (model: R096819; manufacturer: Inotech) of equal mass is used to replace the polyanionic cellulose (article number: P875546-500g; brand: McLean) in Example 1.

[0095] The rest are the same as in Example 1.

[0096] The water-based drilling fluid S8 was prepared.

[0097] Example 9

[0098] This embodiment is carried out using a process similar to that of Embodiment 1, except that this embodiment uses an equal mass of anionic polyacrylamide (anionic, model: 013631213; manufacturer: Shanghai Titan Technology Co., Ltd.) to replace the nonionic polyacrylamide (nonionic, model: 013631159; manufacturer: Shanghai Titan Technology Co., Ltd.) in Embodiment 1.

[0099] The rest are the same as in Example 1.

[0100] The water-based drilling fluid S9 was prepared.

[0101] Example 10

[0102] This example is carried out using a process similar to that of Example 1, except that this example uses an organosilicon of equal mass (model: GF1; manufacturer: Beijing Shidabocheng Technology Co., Ltd.) to replace the potassium humate in Example 1.

[0103] The rest are the same as in Example 1.

[0104] The water-based drilling fluid S10 was prepared.

[0105] Comparative Example 1

[0106] 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.

[0107] The rest are the same as in Example 1.

[0108] The water-based drilling fluid DS1 was prepared.

[0109] Test Example 1

[0110] 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 .

[0111] from Figure 1 It can be seen that at 25℃ and 60℃, the growth ability of the strain in the system is relatively poor. After 48h, 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℃, the strain growth activity is the best and can reach the peak growth concentration. The culture medium is completely consumed and satisfies the proportional relationship between the previous growth rate and the peak growth concentration. In the temperature range of 110-120℃, the growth ability of the strain begins to decline. As the growth rate decreases, the peak growth concentration also begins to decline. In summary, the optimal temperature range of the water-based drilling fluid is 70-120℃.

[0112] Test Example 2

[0113] This test example is used to illustrate the basic properties of the water-based drilling fluid such as filtration loss and rheology provided in the above examples. The test standard is GB / T 16782-1997;

[0114] After the water-based drilling fluid provided in the above example was stirred at a rotation speed of 12000 rpm for 20 min, the values ​​of Φ600 and Φ300 after aging at 120°C for 16 h were measured using a six-speed rotary viscometer, and the apparent viscosity (AV), plastic viscosity (PV) and dynamic shear force (YP) of the water-based drilling fluid were calculated using the following formula.

[0115] (1) Apparent viscosity AV (unit: mPa·s) = 1 / 2 × Φ600;

[0116] (2) Plastic viscosity PV (unit: mPa·s) = Φ600-Φ300;

[0117] (3) Dynamic shear force (unit: Pa) YP = AV-PV;

[0118] The results are shown in Table 4.

[0119] Table 4

[0120]

[0121] It can be seen from the results in Table 4 that the microbial stabilizer provided by the present invention is applied to the drilling fluid system to reduce the filtration loss performance of the drilling fluid.

[0122] Test Example 3

[0123] 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:

[0124] The inhibition performance of the system is evaluated through a linear expansion test. A dual-channel shale expansion instrument is used to compare the difference in swelling height of bentonite in the S1 system and deionized water over a period of time, which can intuitively measure the effect and ability of the treatment solution to inhibit clay hydration expansion. The specific process is as follows:

[0125] (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 10MPa for 5 minutes to make a rock block. (The purpose of placing the second filter paper is to prevent the bentonite from expanding unevenly after the solution is added).

[0126] (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 expansion instrument, and lock the edge of the pressure tank into the groove to reset the initial value of the expansion instrument to zero.

[0127] (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 begin recording the change in the expansion height of the bentonite block over time.

[0128] (4) Record the swelling height after 16 h and export all data measured by the software to a table for storage and processing.

[0129] Test results see Figure 2 .

[0130] 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.

[0131] Test Example 4

[0132] This test example is used to illustrate the uniaxial compressive strength performance of the core immersed in the water-based drilling fluid provided by the present invention;

[0133] The test method is:

[0134] Artificial cores (carbonate rock) were tested for wellbore stability;

[0135] Test system 1: blank control, no immersion treatment of the core;

[0136] Test system 2: using water to immerse the core;

[0137] 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;

[0138] 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 relative to 100 parts by weight of water;

[0139] 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 relative to 100 parts by weight of water;

[0140] 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 relative to 100 parts by weight of water;

[0141] 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 relative to 100 parts by weight of water;

[0142] Test system 8: the water-based drilling fluid S6 obtained in Example 6 of the present invention, with 320 parts by weight of barite added relative to 100 parts by weight of water;

[0143] Test system 9: the water-based drilling fluid S7 obtained in Example 7 of the present invention, with 320 parts by weight of barite added relative to 100 parts by weight of water;

[0144] Test system 10: the water-based drilling fluid S8 obtained in Example 8 of the present invention, with 320 parts by weight of barite added relative to 100 parts by weight of water;

[0145] Test system 11: the water-based drilling fluid S9 obtained in Example 9 of the present invention, with 320 parts by weight of barite added relative to 100 parts by weight of water;

[0146] Test system 12: the water-based drilling fluid S10 obtained in Example 10 of the present invention, with 320 parts by weight of barite added relative to 100 parts by weight of water;

[0147] Test system 13: the water-based drilling fluid DS1 obtained in Comparative Example 1 of the present invention, and 320 parts by weight of barite was added relative to 100 parts by weight of water;

[0148] Test system 14: Similar to test system 3, except that the composition of the biostabilizer does not contain urea and thermophilic strains;

[0149] Test system 15: Similar to test system 3, except that the composition of the biostabilizer does not contain thermophilic strains;

[0150] The test results are shown in Table 5.

[0151] Table 5 (Uniaxial compressive strength test results of artificial core)

[0152]

[0153]

[0154] From the results in Table 5, it can be seen that the microbial stabilizer provided by the present invention has stronger well wall stability and good core compressive strength after being applied to the drilling fluid system.

[0155] The preferred embodiments of the present invention are described in detail above, but the present invention is not limited thereto. Within the technical concept of the present invention, the technical solution of the present invention can be subjected to a variety of simple modifications, including the combination of various technical features in any other suitable manner, and these simple modifications and combinations should also be regarded as the contents disclosed by the present invention and belong to the protection scope 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 content 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; the OD600 of the thermophilic strain is 0.4-0.6; Preferably, the calcium source is selected from at least one of calcium chloride, calcium acetate, calcium acetate and calcium lactate.

2. The composition for microbial 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.

3. 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 claim 1 or 2.

4. Use of the composition for microbial stabilizer according to claim 1 or 2, or the microbial stabilizer according to claim 3 as a wellbore stabilizer in the field of drilling fluid.

5. A water-based drilling fluid, characterized in that: The water-based drilling fluid contains the following components: Water, microbial stabilizers, inhibitors, plugging agents, 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 reducer is 0.6-2.6 parts by weight; The microbial stabilizer is the microbial stabilizer according to claim 3.

6. The water-based drilling fluid according to claim 5, 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 filtrate reducer is 0.7-1.4 parts by weight.

7. The water-based drilling fluid according to claim 5 or 6, characterized in that: The inhibitor is selected from at least one of KCl and sodium humate; Preferably, the inhibitor is a combination of KCl and sodium humate; More preferably, the inhibitor is a combination of KCl and sodium humate in a mass ratio of 1:0.3-3.

8. The water-based drilling fluid according to any one of claims 5 to 7, characterized in that: The plugging agent is selected from at least one of white asphalt and potassium humate; Preferably, the plugging agent is a combination of white asphalt and potassium humate; More preferably, the plugging agent is a combination of white asphalt and potassium humate in a mass ratio of 1:0.125-0.

75.

9. The water-based drilling fluid according to any one of claims 5 to 8, characterized in that: The fluid loss reducer is selected from at least one of polyacrylamide and polyanionic cellulose; Preferably, the fluid loss reducer is a combination of polyacrylamide and polyanionic cellulose; More preferably, 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 ≤40mpa·s; and the polyacrylamide is non-ionic polyacrylamide.

10. Use of the water-based drilling fluid according to any one of claims 5 to 9 in the field of petroleum industry.

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