Drilling fluids and their applications

Abstract

This invention relates to the field of oil and gas well development technology, and discloses a drilling fluid and its application. The drilling fluid comprises the following components in parts by weight: 0.5-1 parts viscosifier, 1.5-3 parts filtration reducer, 0.8-1.5 parts inhibitor, 2-5 parts temporary plugging agent, 0.5-1.2 parts waterproofing and unblocking agent, and 100 parts water. The drilling fluid provided by this invention has excellent plugging effect, with a plugging rate >95%, a core gas permeability recovery value >90%, and the mud cake has self-degradation ability, eliminating the need for professional acidizing operations. During well completion, testing, and reverse flow, it self-unblocks and clears natural gas seepage channels, avoiding damage to the reservoir, making the drilling process more efficient, simpler, more economical, and increasing production capacity.

Description

Technical Field

[0001] This invention relates to the field of oil and gas well development technology, specifically to a drilling fluid and its application. Background Technology

[0002] Tight sandstone gas reservoirs have poor physical properties and low matrix permeability, constituting discontinuous, low-porosity, and low-permeability natural gas reservoirs with well-developed microfractures in their natural structures. Currently used pre-hydrated clay slurry drilling and completion fluids contain a large number of fine solid particles, resulting in high filtrate loss, high surface tension, and weak plugging ability. During current drilling processes, drilling fluid filtrate and solid particles easily infiltrate the natural pores and fractures near the wellbore, causing irreversible damage such as water lock, water sensitivity, and solid blockage. This is especially true in the current development of such reservoirs, where directional or horizontal well drilling is often used to increase single-well productivity, leading to a larger contact area and longer contact time between the drilling and completion fluid and the reservoir, resulting in greater reservoir damage. Therefore, protecting the reservoir from damage is a crucial technical measure in the development process. This requires drilling fluids to not only have excellent plugging properties, forming a good mud cake to reduce filtrate and solid intrusion, but also to completely remove the mud cake and particles that have entered the reservoir pores and fractures after completion, restoring the original seepage channels and permeability as much as possible. In recent years, in order to eliminate the damage caused by drilling fluid, conventional unblocking techniques such as chemical methods, physical methods, microbial methods and composite unblocking methods have been used in the well completion process. However, due to the complexity of the unblocking process, improper handling can often lead to new chemical and mechanical blockages. Summary of the Invention

[0003] The purpose of this invention is to overcome the problems of weak sealing ability of existing drilling fluids and the easy intrusion of drilling fluid filtrate and solid particles into natural pores and fissures near the wellbore during drilling, causing irreversible damage such as reservoir water lock, water sensitivity, and solid blockage. This invention provides a drilling fluid and its application. This drilling fluid is free of clay phase, not only has excellent sealing properties and can form a good mud cake to reduce filtrate and solid intrusion, but it is also self-degradable after well completion. The mud cake and particles entering the reservoir pores and fissures can be completely removed, allowing it to self-unblock and clear gas reservoir seepage channels without the need for specialized acidizing operations, thereby reducing extraction costs and improving production efficiency.

[0004] To achieve the above objectives, the first aspect of the present invention provides a drilling fluid comprising the following components in parts by weight: 0.5-1 parts of a viscosity improver, 1.5-3 parts of a filtration reducer, 0.8-1.5 parts of an inhibitor, 2-5 parts of a temporary plugging agent, 0.5-1.2 parts of a waterproofing and unblocking agent, and 100 parts of water.

[0005] A second aspect of the present invention provides an application of the drilling fluid provided by the present invention in the protection of tight sandstone gas reservoirs.

[0006] The beneficial effects that can be obtained by the present invention through the above technical solution include:

[0007] The drilling fluid provided by this invention is suitable for bottom hole temperatures of 80-120℃, exhibits excellent overall performance, and its components work synergistically to produce a drilling fluid with high degradability, plugging properties, and good rheological properties. This drilling fluid has a mud cake degradation rate ≥95%, a temporary plugging rate ≥95%, and a core gas permeability recovery value ≥90%. Furthermore, during the backflow process in the later stages of drilling completion, it possesses self-cleaning ability through hydration decomposition, removing blockages in reservoir pores and restoring the original permeability. While meeting drilling requirements, it effectively protects the reservoir by reducing damage. The mud cake is completely self-degraded and self-cleaned in the bottom hole environment, eliminating the need for specialized acid washing or acidizing to remove the mud cake, thus avoiding secondary reservoir damage, reducing overall operating costs, increasing oil and gas production, and simplifying maintenance. Detailed Implementation

[0008] The endpoints and any values ​​of the ranges 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 endpoint values ​​of the various ranges, the endpoint values ​​of the various ranges and individual point values, and individual point values ​​can be combined with each other to obtain one or more new numerical ranges, which should be considered as specifically disclosed herein.

[0009] The first aspect of this invention provides a drilling fluid comprising the following components in parts by weight: 0.5-1 parts of a viscosifier, 1.5-3 parts of a filtration reducer, 0.8-1.5 parts of an inhibitor, 2-5 parts of a temporary plugging agent, 0.5-1.2 parts of a waterproofing and unblocking agent, and 100 parts of water. The components, in this weight ratio, work synergistically to achieve a good working effect.

[0010] According to the present invention, preferably, the thickener is selected from at least one of xanthan gum, modified guar gum, modified cellulose, and acrylamide polymers.

[0011] According to a specific embodiment of the present invention, preferably, the thickener is xanthan gum. Xanthan gum is an extracellular acidic heteropolysaccharide produced by the fermentation of Xanthomonas auricula-judae. Its secondary structure consists of side chains that wrap around the main chain backbone in reverse, forming a rod-shaped double helix structure maintained by hydrogen bonds, thus playing a role in flow pattern regulation. At the same time, it replaces bentonite used in drilling fluids, reducing the invasion and blockage damage of solids into reservoir pores and fractures, and meeting the requirements of drilling operations.

[0012] According to the present invention, preferably, the filtration loss reducing agent is selected from at least one of carboxymethyl cellulose, modified starch, humic acid, resin-based filtration loss reducing agents, and acrylamide polymers.

[0013] According to a specific embodiment of the present invention, preferably, the filtration loss reducing agent is selected from carboxymethyl cellulose and / or modified starch;

[0014] Preferably, the viscosity of the carboxymethyl cellulose is 100-300 mPa·s.

[0015] The present invention does not limit the selection of modified starch. Pregelatinized starch obtained by acid hydrolysis or alkaline hydrolysis can be used; etherified starch, such as carboxymethyl starch, hydroxypropyl starch, etc., can be used; and graft copolymerized starch, such as graft copolymerized starch initiated by cerium salt initiator, potassium permanganate initiator, manganese pyrophosphate initiator, etc., can be used.

[0016] According to a specific embodiment of the present invention, preferably, the modified starch is carboxymethyl starch. Both carboxymethyl starch and carboxymethyl cellulose can be obtained by purchase, and the present invention will not elaborate further on this.

[0017] According to the present invention, preferably, the inhibitor is selected from at least one of polyamine, pitch, polyol, silicate and ionic inorganic salt;

[0018] Preferably, the inhibitor is a polyamine.

[0019] According to a specific embodiment of the present invention, preferably, the inhibitor is an oligoamine (total amine value ≥ 2 mmol / g, weight-average molecular weight ≤ 10000 g / mol). Polyamine inhibitors can be prepared in-house or purchased. The polyamine inhibitor of the present invention was purchased from Renqiu Chengfa Petroleum Technology Co., Ltd., brand number CFY-01 (total amine value 4.5 mmol / g).

[0020] According to the present invention, preferably, the temporary plugging agent is a biodegradable temporary plugging agent;

[0021] Preferably, the temporary plugging agent is an aliphatic polyester;

[0022] More preferably, the temporary plugging agent is selected from polyglycolic acid and / or polylactic acid and / or glycolic acid-lactic acid copolymer.

[0023] According to a specific embodiment of the present invention, preferably, the temporary plugging agent is polyglycolic acid and polylactic acid, wherein the weight ratio of the polyglycolic acid and the polylactic acid is (3-5):(5-7), and within this weight ratio range, the self-degradation time of the temporary plugging agent is 5-15 days.

[0024] Preferably, the polyglycolic acid has a weight-average molecular weight of 25,000-100,000 g / mol, and the polylactic acid has a weight-average molecular weight of 45,000-80,000 g / mol.

[0025] Preferably, the polyglycolic acid is microspheres with a particle size of 800-2500 mesh and / or fibrous particles with a length of 0.05-1.5 mm and a diameter of 5-20 μm; the polylactic acid is microspheres with a particle size of 800-2500 mesh and / or fibrous particles with a length of 0.02-1.0 mm and a diameter of 10-30 μm.

[0026] According to the present invention, the temporary plugging agent is a water-insoluble solid at low temperatures. As a major component of drilling fluid mud cake, it works synergistically with filtration loss reducers to reduce filtration loss, protect the wellbore, provide rapid and efficient temporary plugging, and control the large-scale intrusion of liquid and solid phases into the reservoir, thus preventing damage. At high temperatures at the bottom of the well, it undergoes a hydrolysis reaction and gradually decomposes into small molecules through chemical transformation, eventually converting into CO2 or H2O or transforming into liquid. During well completion and testing, it achieves complete self-degradation and self-unblocking, eliminating the need for professional acidizing operations. It breaks down the mud cake barrier between oil and gas and the wellbore, clears natural gas seepage channels, avoids damage to the reservoir, and is highly efficient, simple, economical, and environmentally friendly, thereby increasing natural production capacity and reducing the overall cost of oil and gas extraction.

[0027] According to the present invention, preferably, the waterproofing and unblocking agent comprises at least one of a surfactant, a drainage aid, a demulsifier, and a miscible solvent;

[0028] Preferably, the waterproofing and unblocking agent comprises a surfactant, a drainage aid, and a mutual solvent;

[0029] Preferably, the surfactant comprises at least one of cationic surfactants, anionic surfactants, and nonionic surfactants;

[0030] Preferably, the cationic surfactant is selected from at least one of hexadecyltrimethylammonium bromide, dodecyldimethylbenzylammonium chloride, hexadecyltrimethylammonium chloride, methyl ditaurate ethyl-2-hydroxyethyl ammonium sulfate, and polyquaternium-16;

[0031] Preferably, the anionic surfactant is selected from at least one of sulfate ester surfactants, N-acylaminocarboxylate surfactants, phosphate ester surfactants, carboxylic acid derivative surfactants, sulfate surfactants, and sulfonate surfactants;

[0032] Preferably, the nonionic surfactant is selected from at least one of alkylphenol polyoxyethylene ether, fatty alcohol polyoxyethylene ether, fatty acid polyoxyethylene ester, coconut oil fatty acid monoethanolamide, ethylene glycol monostearate, propylene glycol monostearate and sorbitan fatty acid ester.

[0033] Preferably, the surfactant is a cationic surfactant and / or a nonionic surfactant;

[0034] Preferably, the surfactant is a cationic surfactant or a nonionic surfactant; wherein the weight ratio of the cationic surfactant to the nonionic surfactant is (2-5):1.

[0035] According to a specific embodiment of the present invention, preferably, the cationic surfactant is hexadecyltrimethylammonium bromide, and the nonionic surfactant is sorbitan fatty acid ester.

[0036] This invention does not impose any particular restrictions on the selection of drainage aids, as long as they meet the following requirements: interfacial tension ≤ 8 mN / m, surface tension ≤ 25 mN / m, and density (20℃) 0.9-1.02 g / cm³. 3 The pH should be between 5 and 8. The drainage aid of this invention was purchased from Shanghai Yandi New Material Technology Co., Ltd., brand number YD-3078.

[0037] This invention does not impose any particular restrictions on the selection of mutual solvents, as long as they meet the following requirements: surface tension ≤35mN / m and density (20℃) 0.86-0.92g / cm³. 3 When added to water with other components, it should not separate into layers, form flocculent precipitates, or produce floating matter. The miscible solvent of this invention was purchased from Shandong Dongying Guangmao Petroleum Technology Service Co., Ltd., brand name GMH-4.

[0038] According to a specific embodiment of the present invention, preferably, the weight ratio of the surfactant, the drainage aid, and the mutual solvent is (3-6):1:(2-3). At this weight ratio, the water-locking and unblocking agent can significantly reduce the backflow pressure of filtrate that has invaded deep into the reservoir, reduce the water-locking effect, and effectively prevent liquid phase damage caused by filtrate intrusion into the reservoir.

[0039] According to the present invention, preferably, the drilling fluid further comprises 0.1-0.2 parts by weight of an acidity adjuster to adjust the pH of the drilling fluid to 8.5-10;

[0040] Preferably, the pH adjuster is caustic soda, which makes the drilling fluid present an alkaline environment, effectively improving the efficiency of other treatment agents, etc.

[0041] According to the present invention, preferably, a density regulator may be added to the drilling fluid according to drilling requirements.

[0042] Preferably, the density regulator is 1250-2500 mesh ultrafine calcium carbonate.

[0043] According to the present invention, the density of the drilling fluid is 1.02-1.08 g / cm³. 3 .

[0044] According to the present invention, the apparent viscosity of the drilling fluid is 23-27.5 mPa·s, and the plastic viscosity is 16.5-19.5 mPa·s.

[0045] According to the present invention, the dynamic shear force of the drilling fluid is 5.5-8 Pa, and the static shear force is (1.5-2.5) / (3-6) Pa / Pa.

[0046] A second aspect of the present invention provides an application of the drilling fluid provided by the present invention in the protection of tight sandstone gas reservoirs.

[0047] Example 1

[0048] Take 100 parts by weight of clean water, add 0.2 parts of caustic soda, 0.8 parts of thickener (xanthan gum), 2 parts of filtration loss reducer (carboxymethyl cellulose), 1.0 part of polyamine inhibitor CFY-01, 3 parts of temporary plugging agent (1 part of polyglycolic acid and 2 parts of polylactic acid), and 0.8 parts of waterproofing and unblocking agent (0.3 parts of cetyltrimethylammonium bromide, 0.1 parts of sorbitan fatty acid ester, 0.1 parts of drainage aid YD-3078, and 0.3 parts of miscible solvent GMH-4). Add these ingredients sequentially, stir well, and prepare the drilling fluid.

[0049] Example 2

[0050] Take 100 parts by weight of clean water, add 0.2 parts of caustic soda, 1.0 part of xanthan gum thickener, 2.5 parts of filtration loss reducer (modified starch), 1.2 parts of polyamine inhibitor CFY-01, 4 parts of temporary plugging agent (2 parts of polyglycolic acid and 2 parts of polylactic acid), and 1.0 part of waterproofing and unblocking agent (0.5 parts of cetyltrimethylammonium bromide, 0.1 parts of sorbitan fatty acid ester, 0.1 parts of drainage aid YD-3078, and 0.3 parts of miscible solvent GMH-4). Add these ingredients sequentially, stir well, and prepare the drilling fluid.

[0051] Example 3

[0052] Take 100 parts by weight of clean water, add 0.2 parts of caustic soda, 1.0 part of thickener (xanthan gum), 3 parts of filtration reducer (carboxymethyl cellulose), 1.5 parts of polyamine inhibitor CFY-01, 5 parts of temporary plugging agent (2 parts of polyglycolic acid and 3 parts of polylactic acid), and 1.2 parts of waterproofing and unblocking agent (0.5 parts of cetyltrimethylammonium bromide, 0.1 parts of sorbitan fatty acid ester, 0.2 parts of drainage aid YD-3078, and 0.4 parts of miscible solvent GMH-4). Add these ingredients sequentially, stir well, and prepare the drilling fluid.

[0053] Example 4

[0054] The method is the same as in Example 1, except that the weight proportions of polyglycolic acid and polylactic acid in the temporary plugging agent are different. The specific implementation method is as follows:

[0055] Take 100 parts by weight of clean water, add 0.2 parts of caustic soda, 0.8 parts of thickener (xanthan gum), 2 parts of filtration reducer (carboxymethyl cellulose), 1.0 part of polyamine inhibitor CFY-01, 3 parts of temporary plugging agent (2 parts of polyglycolic acid and 1 part of polylactic acid), and 0.8 parts of waterproofing and unblocking agent (0.3 parts of cetyltrimethylammonium bromide, 0.1 parts of sorbitan fatty acid ester, 0.1 parts of drainage aid YD-3078, and 0.3 parts of miscible solvent GMH-4). Add these ingredients sequentially, stir well, and prepare the drilling fluid.

[0056] Example 5

[0057] The method is the same as in Example 1, except that the weight proportions of surfactant, drainage aid, and mutual solvent in the waterproofing sealant are different. The specific implementation method is as follows:

[0058] Take 100 parts by weight of clean water, add 0.2 parts of caustic soda, 0.8 parts of thickener (xanthan gum), 2 parts of filtration reducer (carboxymethyl cellulose), 1.0 part of polyamine inhibitor CFY-01, 3 parts of temporary plugging agent (1 part of polyglycolic acid and 2 parts of polylactic acid), and 0.8 parts of waterproofing and unblocking agent (0.3 parts of cetyltrimethylammonium bromide, 0.1 parts of sorbitan fatty acid ester, 0.3 parts of drainage aid YD-3078, and 0.1 parts of miscible solvent GMH-4). Add these ingredients sequentially, stir well, and prepare the drilling fluid.

[0059] Example 6

[0060] The method is the same as in Example 1, except that the composition of the surfactant in the waterproofing agent is different. The specific implementation method is as follows:

[0061] Take 100 parts by weight of clean water, add 0.2 parts of caustic soda, 0.8 parts of thickener (xanthan gum), 2 parts of filtration reducer (carboxymethyl cellulose), 1.0 part of polyamine inhibitor CFY-01, 3 parts of temporary plugging agent (1 part of polyglycolic acid and 2 parts of polylactic acid), and 0.8 parts of waterproofing and unblocking agent (0.1 part of cetyltrimethylammonium bromide, 0.3 parts of sorbitan fatty acid ester, 0.1 parts of drainage aid YD-3078, and 0.3 parts of miscible solvent GMH-4). Add these ingredients sequentially, stir well, and prepare the drilling fluid.

[0062] Comparative Example 1

[0063] The method is the same as in Example 1, except that the weight proportions of each component are different. The specific implementation method is as follows:

[0064] Take 100 parts by weight of clean water, add 0.2 parts of caustic soda, 0.2 parts of thickener (xanthan gum), 3 parts of filtration reducer (carboxymethyl cellulose), 2 parts of polyamine inhibitor CFY-01, 2 parts of temporary plugging agent (1 part of polyglycolic acid and 2 parts of polylactic acid), and 0.4 parts of waterproofing and unblocking agent (0.15 parts of cetyltrimethylammonium bromide, 0.05 parts of sorbitan fatty acid ester, 0.05 parts of drainage aid YD-3078, and 0.15 parts of miscible solvent GMH-4). Add these ingredients sequentially, stir well, and prepare the drilling fluid.

[0065] Test Example 1: Drilling Fluid Performance Test

[0066] Test method: The performance of the prepared drilling fluid was determined in accordance with GB / T 29170-2012 "Laboratory Testing of Drilling Fluids for Petroleum and Natural Gas Industry" standard to evaluate whether it can meet the requirements of on-site construction.

[0067] The drilling fluid performance test results are shown in Table 1 below:

[0068] Table 1

[0069]

[0070] As shown in Table 1, the drilling fluids in each embodiment have moderate viscosity and shear stress, low API water loss, and effectively prevent drilling fluid filtrate from entering the reservoir. They also exhibit high rolling recovery rates and good drilling fluid performance, meeting the requirements of on-site construction. Compared to Example 1, Examples 4-6 show a slight increase in water loss and a slight decrease in rolling recovery rates. In Comparative Example 1, different weight percentages of drilling fluid components significantly reduce viscosity and shear stress, increase water loss, and significantly decrease rolling recovery rates.

[0071] Test Example 2: Drilling Fluid Cake Degradation Rate

[0072] Test method: The API loss-in-weight mud cake from drilling fluid was dried to constant weight in a vacuum drying oven at 60℃, and then placed in a sealed container containing simulated formation water (500ml water with 8.5g sodium chloride, 0.14g anhydrous calcium chloride, 0.04g barium chloride, and 0.04g magnesium chloride added, and the pH adjusted to 8 with sodium hydroxide). The container was kept at a constant temperature of 90℃ and allowed to stand for 10 days. After washing with distilled water, it was dried to constant weight in a vacuum drying oven at 60℃. The mass of the remaining mud cake was measured, and its degradation rate was calculated. The calculation method is as follows:

[0073] J = (W1 - W2) / W1 × 100%

[0074] In the formula: J is the degradation rate, %; W1 is the mass of the mud cake before degradation, g; W2 is the mass of the mud cake after degradation, g.

[0075] The degradation rate of drilling fluid cake is shown in Table 2:

[0076] Table 2

[0077] sample Example 1 Example 2 Example 3 Example 4 Example 5 Example 6 Comparative Example 1 Degradation rate (%) 96.82 95.78 95.26 95.11 96.67 96.58 69.32

[0078] Table 2 shows that after 10 days, the drilling fluid cake degradation rate of Examples 1-6 was all above 95%, which can effectively reduce damage to the reservoir. Compared with Example 1, the cake degradation rate of Example 4 was slightly lower due to the change in the amount of degradable plugging agent. In Comparative Example 1, the different weight parts of the drilling fluid components, especially the reduction in the amount of degradable plugging agent, led to a significant decrease in the drilling fluid cake degradation rate.

[0079] Test Example 3: Drilling Fluid Performance Test for Reservoir Protection

[0080] Test method: Refer to SY / T6540-2021 "Indoor Evaluation Method for Damage to Oil Reservoir by Drilling Fluid and Completion Fluid" standard.

[0081] The test results of the drilling fluid's reservoir protection performance are shown in Table 3:

[0082] Table 3

[0083] sample Core permeability (mD) Blocking rate (%) Recovery rate of reflux after 10 days (%) Example 1 1.28 96.28 92.66 Example 2 1.22 97.33 93.18 Example 3 1.36 97.86 93.89 Example 4 1.27 95.32 92.08 Example 5 1.31 95.87 91.12 Example 6 1.29 96.02 91.83 Comparative Example 1 1.38 78.22 67.12

[0084] Table 3 shows that the drilling fluids in Examples 1-6 achieved a plugging rate of >95% in tight sandstone cores and a flowback permeability recovery rate of >90% after 10 days, indicating that the drilling fluids have excellent plugging capabilities. The high flowback permeability recovery rate after mud cake self-degradation is beneficial for unblocking the gas flow channels from the reservoir to the wellbore, demonstrating a significant reservoir protection effect. Compared with Example 1, Examples 4-6 showed slightly lower plugging rates and flowback permeability recovery rates after 10 days. The difference in the weight fractions of the drilling and completion fluid components in Comparative Example 1 resulted in a significantly lower plugging rate and flowback permeability recovery rate after 10 days.

[0085] The preferred embodiments of the present invention have been described in detail above; however, the present invention is not limited thereto. Within the scope of the inventive concept, various simple modifications can be made to the technical solutions of the present invention, including combinations of various technical features in any other suitable manner. These simple modifications and combinations should also be considered as the content disclosed in the present invention and are all within the protection scope of the present invention.

Claims

1. A drilling fluid, characterized by, The drilling fluid comprises the following components in parts by weight: 0.5-1 parts of a viscosity increasing agent, 1.5-3 parts of a fluid loss reducer, 0.8-1.5 parts of an inhibitor, 2-5 parts of a temporary plugging agent, 0.5-1.2 parts of a water lock prevention and plugging removal agent, and 100 parts of water; The temporary plugging agent is polyglycolic acid and polylactic acid, and the weight ratio of the polyglycolic acid to the polylactic acid is (3-5):(5-7). The weight average molecular weight of the polyglycolic acid is 25-100 thousand g / mol, and the weight average molecular weight of the polylactic acid is 45-80 thousand g / mol. The water lock prevention and plugging removal agent comprises a surfactant, a cleanup agent, and a mutual solvent. The weight ratio of the surfactant, the cleanup agent, and the mutual solvent is (3-6):1:(2-3). The surfactant is cetyltrimethylammonium bromide and sorbitan fatty acid ester, and the weight ratio of the cetyltrimethylammonium bromide to the sorbitan fatty acid ester is (2-5):

1.

2. The drilling fluid of claim 1, wherein, The viscosity increasing agent is at least one selected from xanthan gum, modified guar gum, modified cellulose, and acrylamide polymers.

3. The drilling fluid of claim 2, wherein, The viscosity increasing agent is xanthan gum.

4. The drilling fluid of claim 1, wherein, The fluid loss reducer is at least one selected from carboxymethyl cellulose, modified starch, humic acid, resin-based fluid loss reducers, and acrylamide polymers.

5. The drilling fluid of claim 4, wherein, The fluid loss reducer is carboxymethyl cellulose and / or modified starch.

6. The drilling fluid of claim 5, wherein, The viscosity of the carboxymethyl cellulose is 100-300 mPa·s.

7. The drilling fluid of any of claims 1-6, wherein, The inhibitor is at least one selected from polyamines, bitumen, polymeric alcohols, silicates, and ionic inorganic salts.

8. The drilling fluid of claim 7, wherein, The inhibitor is a polyamine.

9. The drilling fluid of any of claims 1-6, wherein, The drilling fluid further comprises a density regulator.

10. The drilling fluid of any of claims 1-6, wherein, The drilling fluid has a density of 1.02-1.08 g / cm 3 .

11. The drilling fluid of any of claims 1-6, wherein, The drilling fluid further comprises an acidity regulator in parts by weight of 0.1-0.

2.

12. The drilling fluid of any of claims 1-6, wherein, The pH value of the drilling fluid is 8.5-10.

13. The drilling fluid of any of claims 1-6, wherein, The apparent viscosity of the drilling fluid is 23-27.5 mPa·s, and the plastic viscosity is 16.5-19.5 mPa·s.

14. The drilling fluid of any of claims 1-6, wherein, The dynamic shear force of the drilling fluid is 5.5-8 Pa, and the static shear force is (1.5-2.5) / (3-6) Pa / Pa.

15. Use of the drilling fluid according to any one of claims 1-14 in the protection of tight sandstone gas reservoirs.

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