A sea area natural gas hydrate wellbore flow guarantee and reservoir protection drilling fluid system, and a preparation method and application thereof

Abstract

The present application relates to a kind of sea natural gas hydrate wellbore flow security and reservoir protection drilling fluid system and its preparation method and application, belong to deepwater shallow natural gas hydrate exploitation technical field.The drilling fluid system includes the following components: natural seawater, NaCl, KCl, plugging agent, clay hydration inhibitor, filtrate reducer, flow pattern regulator, density control agent, hydrate double-effect inhibitor, hydrate formation inhibitor and hydrate decomposition inhibitor.The drilling fluid system provided by the present application has good rheological filtration performance at room temperature, and the rheological ability meets the production needs at low temperature, while having good clay hydration inhibition performance, which can effectively inhibit reservoir hydrate decomposition and prevent wellbore hydrate secondary generation, prevent well leakage, reduce well control risk and improve work efficiency.

Description

Technical Field

[0001] The present invention relates to a drilling fluid system for ensuring flow in a marine natural gas hydrate wellbore and protecting a reservoir, and a preparation method and application thereof, belonging to the technical field of deepwater shallow natural gas hydrate exploitation. Background Art

[0002] Marine natural gas hydrate reservoirs face technical difficulties such as shallow burial depth, weak cementation, poor diagenesis, narrow drilling fluid density window, low formation pressure coefficient, and easy collapse and leakage of drilling wellbores. The existing natural gas hydrate drilling fluid system adds a large amount of sodium chloride (NaCl) or monoethylene glycol (MEG) to inhibit hydrate formation, causing the system density to exceed the standard, and easily promotes the decomposition of reservoir hydrates, leading to well wall instability.

[0003] For example, Chinese patent document CN105505346A discloses a water-based drilling fluid for low-temperature formation drilling. The technical solution comprises the following components by weight: 100 parts water, 0-4 parts slurry mix, 0.1-5 parts flow pattern modifier, 1-8 parts shale inhibitor, 0.05-0.5 parts coated inhibitor, 3-10 parts fluid loss additive, 10-40 parts hydrate inhibitor, 1-2 parts lubricant, and 0-100 parts barite; the hydrate inhibitor is at least one of sodium chloride and ethylene glycol.

[0004] For example, Chinese patent document CN114426814A discloses a water-based drilling fluid comprising 3 parts bentonite or modified bentonite, 100 parts water, 0.1-0.4 parts viscosity enhancer, 3-5 parts fluid loss control agent, 1-4 parts inhibitor, and optionally 15-25 parts natural gas hydrate inhibitor. The inhibitor is one or more of a salt inhibitor, a nanomaterial inhibitor, and an amine inhibitor. The natural gas hydrate inhibitor is one or more of a salt inhibitor and an alcohol inhibitor.

[0005] The above drilling fluid systems all contain a large amount of NaCl or MEG to inhibit hydrate formation, causing the system density to exceed the standard. This also easily promotes the decomposition of reservoir hydrates, which can easily lead to wellbore instability and poor wellbore fluidity assurance. In addition, Chinese patent document CN114426814A is only suitable for natural gas hydrate drilling in permafrost areas and cannot be used for deepwater shallow drilling. Summary of the Invention

[0006] In view of the deficiencies of the existing technology, the present invention provides a drilling fluid system for ensuring flow and protecting reservoirs of natural gas hydrates in offshore areas, as well as a preparation method and application thereof.

[0007] The present invention addresses technical difficulties such as shallow burial depth, weak cementation, poor diagenesis of natural gas hydrate reservoirs, narrow drilling fluid density window, low formation pressure coefficient, secondary hydrate blockage in the wellbore, and easy collapse and leakage of the drilling wellbore. In addition to traditional thermodynamic inhibitors (NaCl) and first-generation kinetic inhibitors (PVP), the present invention adds a specially prepared hydrate formation inhibitor SYZ-3 and a hydrate decomposition inhibitor PTC-1. By adopting a specific component ratio and adjusting the system density, the present invention achieves a low-density, strong inhibition effect. While reducing the amount of hydrate thermodynamic inhibitor in the system, the present invention effectively inhibits reservoir hydrate decomposition and prevents secondary hydrate formation in the wellbore, thereby avoiding complex downhole situations, controlling wellbore stability, preventing wellbore collapse, and ensuring drilling continuity. The present invention has a high wellbore fluidity assurance capability, reduces production costs and non-productive time, and improves development efficiency and economic benefits.

[0008] The technical solutions of the present invention are as follows:

[0009] A drilling fluid system for ensuring wellbore flow and protecting reservoirs of marine natural gas hydrates, the drilling fluid system comprising the following components:

[0010] Natural seawater, NaCl, KCl, plugging agents, clay hydration inhibitors, fluid loss additives, flow pattern regulators, density control agents, dual-effect hydrate inhibitors, hydrate formation inhibitors, and hydrate decomposition inhibitors;

[0011] wherein, relative to 100 parts by weight of natural seawater, the content of NaCl is 5-10 parts by weight, the content of KCl is 2-6 parts by weight, the content of the plugging agent is 2-6 parts by weight, the content of the clay hydration inhibitor is 0.1-1 parts by weight, the content of the fluid loss reducer is 0.5-3 parts by weight, the content of the flow pattern regulator is 0.1-0.5 parts by weight, the content of the density control agent is 0.5-3 parts by weight, the content of the dual-effect hydrate inhibitor is 0.5-3 parts by weight, the content of the hydrate formation inhibitor is 0.5-3 parts by weight, and the content of the hydrate decomposition inhibitor is 1-6 parts by weight;

[0012] The hydrate formation inhibitor is the hydrate formation inhibitor SYZ-3, and the hydrate decomposition inhibitor is the hydrate decomposition inhibitor PTC-1.

[0013] According to the present invention, the plugging agent is preferably nano anti-collapse plugging agent NF-1.

[0014] According to the present invention, preferably, the clay hydration inhibitor is a polyamine inhibitor PF-UHIB.

[0015] According to the present invention, preferably, the fluid loss control agent is a fluid loss control agent PF-FLOTROL.

[0016] According to the present invention, preferably, the flow pattern regulator is the flow pattern regulator PF-XC.

[0017] According to the present invention, preferably, the density control agent is density control agent PDC.

[0018] According to the present invention, the dual-action hydrate inhibitor is preferably polyvinylpyrrolidone (PVP).

[0019] According to the present invention, the hydrate formation inhibitor SYZ-3 is preferably prepared according to the following method:

[0020] N, N-dimethylacrylamide and N-vinylcaprolactam were added to the reaction solvent and stirred continuously, while nitrogen was introduced to maintain anaerobic conditions until they were completely dissolved. The temperature was raised to 60-85°C, and an initiator was added dropwise to carry out a free radical polymerization reaction. The product was purified to obtain the hydrate formation inhibitor SYZ-3.

[0021] More preferably, the reaction solvent is dimethylformamide, and the initiator is recrystallized azobisisobutyronitrile.

[0022] More preferably, the mass ratio of N-vinylcaprolactam, N, N-dimethylacrylamide, initiator and reaction solvent is (10-15): (2-8): (0.1-5): (70-90).

[0023] Most preferably, the mass ratio of N-vinylcaprolactam, N, N-dimethylacrylamide, initiator and reaction solvent is 14:6:0.24:75.

[0024] More preferably, the continuous stirring is stirring at 15-25 r / min for 15-25 min.

[0025] More preferably, the free radical polymerization reaction time is 6 to 8 hours.

[0026] According to the present invention, the hydrate decomposition inhibitor PTC-1 is preferably prepared according to the following method:

[0027] The n-tetradecane and n-hexadecane are mixed evenly to obtain an oil phase solution; sodium alginate is dissolved in pure water to obtain an aqueous phase solution; the mixture of the aqueous phase solution and the oil phase solution is emulsified using a high-speed homogenizer to obtain a phase change emulsion; the phase change emulsion is sprayed into a calcium chloride solution using the electrostatic spraying function of an electrospinning machine to obtain the hydrate decomposition inhibitor PTC-1.

[0028] More preferably, the mass ratio of n-tetradecane, n-hexadecane, sodium alginate and calcium chloride is (1-4): (4-8): (0.5-5): (2-6).

[0029] Most preferably, the mass ratio of n-tetradecane, n-hexadecane, sodium alginate and calcium chloride is 1:4:0.625:2.

[0030] Further preferably, the mass concentration of sodium alginate in the aqueous solution is 1-3wt%.

[0031] Further preferably, the mass concentration of the calcium chloride solution is 1-5wt%.

[0032] Further preferably, the rotation speed of the high-speed homogenizing emulsifier is 500-70000r / min, and the emulsification time is 20-30min.

[0033] Further preferably, the electrostatic spraying voltage is 8-12kV, and the spraying rate is 1-3mL / min.

[0034] A preferred technical solution of the present application is:

[0035] In the drilling fluid system, relative to 100 parts by weight of natural seawater, the content of NaCl is 5-10 parts by weight, the content of KCl is 5 parts by weight, the content of nano anti-sloughing plugging agent NF-1 is 2-5 parts by weight, the content of polyamine inhibitor PF-UHIB is 0.5 parts by weight, the content of fluid loss reducer PF-FLOTROL is 1-2 parts by weight, the content of flow pattern regulator PF-XC is 0.15-0.3 parts by weight, the content of density control agent PDC is 1-3 parts by weight, the content of PVP is 1 part by weight, the content of SYZ-3 is 1 part by weight, and the content of PTC-1 is 3 parts by weight.

[0036] A most preferred technical solution of the present application is:

[0037] In the drilling fluid system, relative to 100 parts by weight of natural seawater, the content of NaCl is 9 parts by weight, the content of KCl is 5 parts by weight, the content of nano anti-sloughing plugging agent NF-1 is 5 parts by weight, the content of polyamine inhibitor PF-UHIB is 0.5 parts by weight, the content of fluid loss reducer PF-FLOTROL is 1 part by weight, the content of flow pattern regulator PF-XC is 0.25 parts by weight, the content of density control agent PDC is 1 part by weight, the content of PVP is 1 part by weight, the content of hydrate formation inhibitor SYZ-3 of Example 1 is 1 part by weight, and the content of hydrate decomposition inhibitor PTC-1 of Example 2 is 3 parts by weight.

[0038] The drilling fluid system of the present application is aimed at the technical problems of shallow burial, poor cementation, poor diagenesis, narrow drilling fluid density window, low formation pressure coefficient, easy collapse and easy leakage of the drilling wellbore in the natural gas hydrate reservoir, and on the basis of the traditional thermodynamic inhibitor (NaCl) and the first generation of kinetic inhibitor (PVP), the specially prepared hydrate formation inhibitor SYZ-3 and hydrate decomposition inhibitor PTC-1 are added, the density of the system is adjusted by the density control agent through a specific component ratio, and the effect of low density and strong inhibition is achieved.

[0039] The present application also provides a preparation method of the above-mentioned drilling fluid system for ensuring wellbore flow and protecting reservoir in the marine natural gas hydrate.

[0040] The preparation method of the above-mentioned drilling fluid system for ensuring wellbore flow and protecting reservoir in the marine natural gas hydrate comprises the following steps:

[0041] The density control agent, the hydrate formation inhibitor, the hydrate decomposition inhibitor, the flow type regulator, the filtrate reducer, the hydrate double-effect inhibitor, the plugging agent, the clay hydration inhibitor, KCl and NaCl are sequentially and slowly added to the natural seawater, and after the addition of each kind of substance is completed, high-speed stirring is carried out, and then the next kind of substance is added;

[0042] The rotating speed of the high-speed stirring is 8000-12000r / min, and the stirring time is 5-25min.

[0043] According to the present application, the density control agent is added, high-speed stirring is carried out for 10-20min, the hydrate formation inhibitor is slowly added, high-speed stirring is carried out for 20min, the hydrate decomposition inhibitor is slowly added, high-speed stirring is carried out for 15min, the flow type regulator is slowly added, high-speed stirring is carried out for 20min, the filtrate reducer is slowly added, high-speed stirring is carried out for 15min, the hydrate double-effect inhibitor is slowly added, high-speed stirring is carried out for 15min, the plugging agent is slowly added, high-speed stirring is carried out for 10min, the clay hydration inhibitor is slowly added, high-speed stirring is carried out for 10min, KCl is slowly added, high-speed stirring is carried out for 5min, and NaCl is slowly added, high-speed stirring is carried out for 5min.

[0044] The above-mentioned drilling fluid system for ensuring wellbore flow and protecting reservoir in the marine natural gas hydrate is mainly applied to flow assurance and reservoir protection in the drilling process. In the drilling process, the reservoir depth is matched, the hydrate formation risk is calculated, the amount of hydrate thermodynamic inhibitor is adjusted, the hydrate formation risk near the mud line is reduced, the flowability of the drilling fluid in the wellbore is ensured, at the same time, the low amount of thermodynamic inhibitor makes the hydrate in the reservoir in the left area of the phase equilibrium, the hydrate decomposition is limited, the low damage of the drilling fluid to the reservoir hydrate is realized, and then the hydrate reservoir is stabilized.

[0045] The technical features and beneficial effects of the present application are as follows:

[0046] 1. In view of the problem that the density of the existing natural gas hydrate drilling fluid system is over-standard due to the addition of a large amount of NaCl or MEG to inhibit the generation of hydrates, the application adds a specially prepared hydrate generation inhibitor SYZ-3 and a hydrate decomposition inhibitor PTC-1 on the basis of the traditional thermodynamic inhibitor (NaCl) and the first generation of kinetic inhibitor (PVP), effectively inhibits the decomposition of reservoir hydrates and prevents the secondary generation of hydrates in the wellbore by adjusting the density of the system, protects the reservoir, improves the wellbore flowability guarantee capacity, successfully achieves the effect of low-density strong inhibition, and reduces the amount of hydrate inhibitors in the system, which is the greatest innovation of the application.

[0047] 2. In view of the technical problems of narrow drilling fluid density window and low formation pressure coefficient, the addition amount of the density control agent is controlled to accurately control the drilling fluid density, effectively balance the formation pressure, prevent excessive damage to the formation, control the wellbore stability, prevent wellbore collapse, and ensure the continuity of drilling.

[0048] 3. The drilling fluid system provided by the application has good rheological filtration performance under room temperature conditions, the rheological capacity under low temperature conditions meets the production needs, and the system has good clay hydration inhibition performance, can effectively inhibit the decomposition of reservoir hydrates and prevent the secondary generation of hydrates in the wellbore, can prevent well leakage, reduce well control risk, and improve work efficiency.

[0049] 4. The drilling fluid system provided by the application has a wide access to the required components, a simple preparation method and low cost, and has important significance for deep water shallow natural gas hydrate exploitation, and is worth popularization and application. BRIEF DESCRIPTION OF DRAWINGS

[0050] Figure 1 It is the infrared spectrum of the hydrate generation inhibitor SYZ-3.

[0051] Figure 2 It is the scanning electron microscope image of the hydrate decomposition inhibitor phase change microsphere PTC-1.

[0052] Figure 3 It is the physical picture of the sea natural gas hydrate wellbore flow guarantee and reservoir protection drilling fluid system of Example 3.

[0053] Figure 4 It is the linear expansion rate test result of the artificial core in different drilling fluids.

[0054] Figure 5 It is the hydrate generation inhibition evaluation temperature-pressure curve diagram under the action of the drilling fluid LH-1.

[0055] Figure 6 It is the methane release amount curve under the action of different drilling fluids. DETAILED DESCRIPTION

[0056] The present invention will be further described below with reference to specific examples, but is not limited thereto. Unless otherwise specified, the raw materials used in the examples are conventional raw materials and can be obtained commercially; unless otherwise specified, the methods described are all based on prior art.

[0057] Example 1. Preparation of Hydrate Inhibitor SYZ-3

[0058] The three-necked flask was placed in a constant temperature heating magnetic stirrer at 80°C, and nitrogen was passed through the air for 3 times to ensure that the three-necked flask was oxygen-free and dry. 75 g of dimethylformamide (DMF) solution was weighed and added to the beaker, and then 14 g of N-vinylcaprolactam (NVCL) and 6 g of N,N-dimethylacrylamide (DMAA) were added. The mixture was stirred at 20 r / min for 20 min using a constant speed strong electric stirrer and nitrogen was continuously passed through to completely dissolve and disperse NVCL and DMAA in DMF to obtain a monomer mixed solution. 6 Add 0.24 g of recrystallized azobisisobutyronitrile (AIBN) into a clean, dry beaker, and then weigh 0.24 g of recrystallized azobisisobutyronitrile (AIBN) and add it to the beaker. Use a constant-speed, powerful electric stirrer to stir at 20 r / min for 15 min to completely dissolve and disperse AIBN in DMF to obtain an initiator solution. Slowly add the initiator solution dropwise to the monomer mixed solution for 10 min. After the addition is completed, react for 7 h. Dry the product solution in a constant-temperature oven at 75 °C for 24 h to obtain the hydrate formation inhibitor SYZ-3.

[0059] The infrared spectrum of the hydrate formation inhibitor SYZ-3 prepared in this example is as follows Figure 1 shown.

[0060] Depend on Figure 1 It can be seen that at 3548cm -1 The absorption peak generated at 2927cm is the stretching absorption peak of -NH-R. -1 The stretching absorption peak of -CH is at 1685cm -1 The absorption peak at 1501 cm is the stretching vibration peak of the carbonyl C=O in the amide. -1 The absorption peak at 40° is the stretching absorption peak of CN. The results of infrared spectroscopy analysis show that the hydrate inhibitor SYZ-3 contains the characteristic functional groups of each monomer in the molecular structure design, which indicates that the hydrate formation inhibitor SYZ-3 was successfully prepared.

[0061] Example 2: Preparation of Hydrate Decomposition Inhibitor Phase Change Microspheres PTC-1

[0062] Add 1 g of n-tetradecane (C 14 H 30 ) and 4 g n-hexadecane (C16 H 36 ) and mix thoroughly to prepare an oil phase solution. Weigh 0.625 g of sodium alginate (SA) and add it to 45 g of pure water. Disperse and dissolve it using a high-speed blender (6000 rpm) to prepare an aqueous phase solution. Place the oil and aqueous phase solutions into the same beaker and emulsify them at 6000 rpm for 25 minutes using a high-speed homogenizer. Weigh 2 g of anhydrous calcium chloride (CaCl2) and add it to 98 g of pure water. Stir until completely dissolved, then cool to room temperature. Use a syringe to draw out the phase change emulsion and connect it to an electrospinning machine. Using its electrostatic spray function, spray the phase change emulsion into a 2 wt% calcium chloride solution at a rate of 2 mL / min at a voltage of 10 kV to form phase change microcapsules. Let it sit for 10 minutes until the capsule shell is fully solidified. After filtration, the microcapsules were rinsed three times with pure water and ethanol respectively to remove the residual oil phase and solution on the surface of the microcapsules. The microcapsules were then dried in a drying oven at 40 °C for 12 h to obtain the hydrate decomposition inhibitor PTC-1 with a hardened shell.

[0063] The scanning electron microscope image of the hydrate decomposition inhibitor PTC-1 prepared in this example is as follows: Figure 2 shown.

[0064] Depend on Figure 2 It can be seen that the surface of the hydrate decomposition inhibitor PTC-1 is smooth and has a granular structure, which corresponds well to the expected core-shell structure. At the same time, no core material is seen to flow out in the form of liquid, which indicates that the hydrate decomposition inhibitor PTC-1 was successfully prepared.

[0065] Example 3

[0066] A drilling fluid system for ensuring wellbore flow and protecting reservoirs of natural gas hydrates in offshore areas. In the drilling fluid system, relative to 100 parts by weight of natural seawater, the content of NaCl is 9 parts by weight, the content of KCl is 5 parts by weight, the content of nano-anti-collapse plugging agent NF-1 is 5 parts by weight, the content of polyamine inhibitor PF-UHIB is 0.5 parts by weight, the content of fluid loss reducer PF-FLOTROL is 1 part by weight, the content of flow pattern regulator PF-XC is 0.25 parts by weight, the content of density control agent PDC is 1 part by weight, the content of PVP is 1 part by weight, the content of hydrate formation inhibitor SYZ-3 in Example 1 is 1 part by weight, and the content of hydrate decomposition inhibitor PTC-1 in Example 2 is 3 parts by weight.

[0067] Preparation method:

[0068] According to the above ratio, natural seawater was placed in a slurry cup, PDC was slowly added, and the mixture was stirred at high speed for 15 minutes. SYZ-3 was slowly added, and the mixture was stirred at high speed for 20 minutes. PTC-1 was slowly added, and the mixture was stirred at high speed for 15 minutes. PF-XC was slowly added, and the mixture was stirred at high speed for 20 minutes. PF-FLOTROL was slowly added, and the mixture was stirred at high speed for 15 minutes. PVP was slowly added, and the mixture was stirred at high speed for 15 minutes. NF-1 was slowly added, and the mixture was stirred at high speed for 10 minutes. PF-UHIB was slowly added, and the mixture was stirred at high speed for 10 minutes. KCl was slowly added, and the mixture was stirred at high speed for 5 minutes. NaCl was slowly added, and the mixture was stirred at high speed for 5 minutes. The speed of the high-speed stirring was 10,000 r / min. The offshore natural gas hydrate wellbore flow assurance and reservoir protection drilling fluid system LH-1 was prepared.

[0069] The actual photo of the offshore natural gas hydrate wellbore flow assurance and reservoir protection drilling fluid system LH-1 prepared in this example is as follows: Figure 3 shown.

[0070] Depend on Figure 3 It can be seen that the offshore natural gas hydrate wellbore flow assurance and reservoir protection drilling fluid system LH-1 described in this embodiment was successfully prepared.

[0071] Example 4

[0072] A drilling fluid system for ensuring wellbore flow and protecting reservoirs of natural gas hydrates in offshore areas. In the drilling fluid system, relative to 100 parts by weight of natural seawater, the content of NaCl is 6.5 parts by weight, the content of KCl is 5 parts by weight, the content of nano-anti-collapse plugging agent NF-1 is 5 parts by weight, the content of polyamine inhibitor PF-UHIB is 0.5 parts by weight, the content of fluid loss reducer PF-FLOTROL is 1 part by weight, the content of flow pattern regulator PF-XC is 0.3 parts by weight, the content of density control agent PDC is 0.5 parts by weight, the content of PVP is 1 part by weight, the content of hydrate formation inhibitor SYZ-3 in Example 1 is 1 part by weight, and the content of hydrate decomposition inhibitor PTC-1 in Example 2 is 3 parts by weight.

[0073] The preparation method was carried out according to Example 3 to prepare the offshore natural gas hydrate wellbore flow assurance and reservoir protection drilling fluid system LH-2.

[0074] Example 5

[0075] A drilling fluid system for ensuring wellbore flow and protecting reservoirs of natural gas hydrates in offshore areas. In the drilling fluid system, relative to 100 parts by weight of natural seawater, the content of NaCl is 9 parts by weight, the content of KCl is 5 parts by weight, the content of nano-anti-collapse plugging agent NF-1 is 5 parts by weight, the content of polyamine inhibitor PF-UHIB is 0.5 parts by weight, the content of fluid loss reducer PF-FLOTROL is 1 part by weight, the content of flow pattern regulator PF-XC is 0.3 parts by weight, the content of density control agent PDC is 1 part by weight, the content of PVP is 1 part by weight, the content of hydrate formation inhibitor SYZ-3 in Example 1 is 1 part by weight, and the content of hydrate decomposition inhibitor PTC-1 in Example 2 is 3 parts by weight.

[0076] The preparation method was carried out according to Example 3 to prepare the offshore natural gas hydrate wellbore flow assurance and reservoir protection drilling fluid system LH-3.

[0077] Example 6

[0078] A drilling fluid system for ensuring wellbore flow and protecting reservoirs of natural gas hydrates in offshore areas. In the drilling fluid system, relative to 100 parts by weight of natural seawater, the content of NaCl is 9 parts by weight, the content of KCl is 5 parts by weight, the content of nano-anti-collapse plugging agent NF-1 is 5 parts by weight, the content of polyamine inhibitor PF-UHIB is 0.5 parts by weight, the content of fluid loss reducer PF-FLOTROL is 1 part by weight, the content of flow pattern regulator PF-XC is 0.25 parts by weight, the content of density control agent PDC is 1 part by weight, the content of PVP is 1 part by weight, the content of hydrate formation inhibitor SYZ-3 in Example 1 is 1.5 parts by weight, and the content of hydrate decomposition inhibitor PTC-1 in Example 2 is 2.5 parts by weight.

[0079] The preparation method was carried out according to Example 3 to prepare the offshore natural gas hydrate wellbore flow assurance and reservoir protection drilling fluid system LH-4.

[0080] Comparative Example 1

[0081] A drilling fluid system, wherein, relative to 100 parts by weight of natural seawater, the content of NaCl is 10 parts by weight, the content of KCl is 5 parts by weight, the content of nano anti-collapse plugging agent NF-1 is 2 parts by weight, the content of polyamine inhibitor PF-UHIB is 0.5 parts by weight, the content of fluid loss reducer PF-FLOTROL is 1 part by weight, the content of flow pattern regulator PF-XC is 0.3 parts by weight, and the content of PVP is 1 part by weight.

[0082] The preparation method was carried out according to Example 3 to prepare drilling fluid DH-1.

[0083] Comparative Example 2

[0084] A drilling fluid system, wherein, relative to 100 parts by weight of natural seawater, the content of NaCl is 6.5 parts by weight, the content of KCl is 5 parts by weight, the content of nano anti-collapse plugging agent NF-1 is 2 parts by weight, the content of polyamine inhibitor PF-UHIB is 0.5 parts by weight, the content of fluid loss reducer PF-FLOTROL is 1 part by weight, the content of flow pattern regulator PF-XC is 0.3 parts by weight, the content of density control agent PDC is 0.5 parts by weight, and the content of PVP is 1 part by weight.

[0085] The preparation method was carried out according to Example 3 to prepare drilling fluid DH-2.

[0086] Comparative Example 3

[0087] A drilling fluid system, wherein, relative to 100 parts by weight of natural seawater, the content of NaCl is 6.5 parts by weight, the content of KCl is 5 parts by weight, the content of nano anti-collapse plugging agent NF-1 is 2 parts by weight, the content of polyamine inhibitor PF-UHIB is 0.5 parts by weight, the content of fluid loss reducer PF-FLOTROL is 2 parts by weight, the content of flow pattern regulator PF-XC is 0.3 parts by weight, the content of density control agent PDC is 0.5 parts by weight, the content of PVP is 1 part by weight, and the content of hydrate formation inhibitor SYZ-3 of Example 1 is 1 part by weight.

[0088] The preparation method was carried out according to Example 3 to prepare drilling fluid DH-3.

[0089] Comparative Example 4

[0090] A drilling fluid system, wherein, relative to 100 parts by weight of natural seawater, the content of NaCl is 6.5 parts by weight, the content of KCl is 5 parts by weight, the content of nano anti-collapse plugging agent NF-1 is 5 parts by weight, the content of polyamine inhibitor PF-UHIB is 0.5 parts by weight, the content of fluid loss reducer PF-FLOTROL is 2 parts by weight, the content of flow pattern regulator PF-XC is 0.3 parts by weight, the content of density control agent PDC is 0.5 parts by weight, the content of PVP is 1 part by weight, and the content of hydrate decomposition inhibitor PTC-1 of Example 2 is 3 parts by weight.

[0091] The preparation method was carried out according to Example 3 to prepare drilling fluid DH-4.

[0092] Comparative Example 5

[0093] A conventional deepwater water-based drilling fluid (HEM drilling fluid) comprises the following raw materials in parts by weight: 100 parts of natural seawater, 0.1 parts of NaOH, 12 parts of NaCl, 5 parts of KCl, 6 parts of MEG, 1 part of fluid loss reducer PF-FLOTROL, 0.3 parts of fluid loss reducer PF-PAC-LV, 0.1 parts of flow pattern regulator PF-XC, 2 parts of reservoir bridging agent PF-EZCARB, 2 parts of modified resin PF-LSF, 0.2 parts of flow pattern regulator PF-PLUS, 3 parts of polyamine inhibitor PF-UHIB, 3 parts of anti-mud balling lubricant PF-HLUB, and 2 parts of lubricant PF-LUBE;

[0094] The preparation method of the above-mentioned deepwater water-based drilling fluid comprises the following steps:

[0095] According to the above ratio, seawater is placed in a slurry cup, PF-XC is slowly added, and the mixture is stirred at high speed for 20 minutes. MEG is slowly added, and the mixture is stirred at high speed for 15 minutes. PF-PAC-LV is slowly added, and the mixture is stirred at high speed for 15 minutes. PF-FLOTROL is slowly added, and the mixture is stirred at high speed for 15 minutes. PF-EZCARB is slowly added, and the mixture is stirred at high speed for 15 minutes. PF-LSF is slowly added, and the mixture is stirred at high speed for 10 minutes. PF-PLUS is slowly added, and the mixture is stirred at high speed for 10 minutes. PF-UHIB is slowly added, and the mixture is stirred at high speed for 10 minutes. PF-HLUB is slowly added, and the mixture is stirred at high speed for 10 minutes. PF-LUBE is slowly added, and the mixture is stirred at high speed for 10 minutes. NaOH is slowly added, and the mixture is stirred at high speed for 10 minutes. KCl is slowly added, and the mixture is stirred at high speed for 5 minutes. NaCl is slowly added, and the mixture is stirred at high speed for 5 minutes. The speed of the high-speed stirring is 10,000 r / min to prepare a deepwater water-based drilling fluid HEM.

[0096] Comparative Example 6

[0097] A conventional deepwater water-based drilling fluid (semi-proof drilling fluid) comprises the following raw materials in parts by weight: 100 parts of natural seawater, 0.1 parts of NaOH, 20 parts of MEG, 2 parts of filtration reducer PF-FLOTROL, 2 parts of reservoir bridging agent PF-EZCARB, 1 part of drilling pressure enhancer PF-STRH, 0.1 parts of flow pattern regulator PF-XC, 5 parts of polyamine inhibitor PF-UHIB, 5 parts of anti-mud balling lubricant PF-HLUB, 5 parts of lubricant PF-LUBE, and 0.2 parts of flow pattern regulator PF-PLUS;

[0098] The preparation method of the above-mentioned deepwater water-based drilling fluid comprises the following steps:

[0099] According to the above ratio, seawater was placed in a slurry cup, PF-XC was slowly added, and stirred at high speed for 20 minutes. PF-FLOTROL was slowly added, and stirred at high speed for 15 minutes. PF-EZCARB was slowly added, and stirred at high speed for 15 minutes. PF-STRH was slowly added, and stirred at high speed for 10 minutes. PF-UHIB was slowly added, and stirred at high speed for 10 minutes. PF-HLUB was slowly added, and stirred at high speed for 10 minutes. PF-LUBE was slowly added, and stirred at high speed for 10 minutes. MEG was slowly added, and stirred at high speed for 10 minutes. NaOH was slowly added, and stirred at high speed for 10 minutes. KCl was slowly added, and stirred at high speed for 5 minutes. NaCl was slowly added, and stirred at high speed for 5 minutes. The speed of the high-speed stirring was 10,000 r / min to prepare a deepwater water-based drilling fluid BF.

[0100] Comparative Example 7

[0101] A conventional deepwater water-based drilling fluid (full-proof drilling fluid) comprises the following raw materials in parts by weight: 100 parts of natural seawater, 0.1 parts of NaOH, 50 parts of MEG, 2 parts of filtration reducer PF-FLOTROL, 2 parts of reservoir bridging agent PF-EZCARB, 1 part of while-drilling pressure enhancer PF-STRH, 0.1 parts of flow pattern regulator PF-XC, 5 parts of PF-UHIB, 5 parts of polyamine inhibitor PF-HLUB, 5 parts of anti-mud balling lubricant PF-LUBE, and 0.2 parts of flow pattern regulator PF-PLUS;

[0102] The preparation method of the above-mentioned deepwater water-based drilling fluid is as described in Comparative Example 2, and deepwater water-based drilling fluid QF is prepared.

[0103] Experimental Example 1

[0104] The drilling fluids LH-1~4, DH-1~4 and HEM, QF and BF were tested for room temperature rheological filtration performance and low temperature rheological performance.

[0105] The specific method is as follows: 400 mL of drilling fluids LH-1~4, DH-1~4 and HEM, QF, and BF are respectively taken into a slurry cup, stirred evenly, and then the room temperature rheological filtration loss properties and low temperature rheological filtration loss properties of the above drilling fluids are respectively measured according to the method described in GB / T16783.1-2006. The performance test results are shown in Table 1 below.

[0106] Table 1. Test results of rheological filtration performance at room temperature

[0107]

[0108] Table 2. Low temperature rheological filtration performance test results

[0109]

[0110] As can be seen from Tables 1 and 2, a large amount of salt inhibitors were added to the drilling fluid HEM to inhibit the formation of hydrates, resulting in a maximum density of 1.12 g / cm 3 , which is higher than the hydrate drilling fluid operating density window. Drilling fluids BF and QF use ethylene glycol as a hydrate inhibitor, and the drilling fluid density is lower, but close to the upper and lower limits of the hydrate drilling fluid operating density window. Drilling fluid LH-1 uses PDC to adjust the density to meet the hydrate drilling fluid operating density window. The apparent viscosity ratio (AV 2℃ / AV 25℃ ) are 1.55, 1.50, 1.62 and 1.448 respectively, which means that all four drilling fluids have good low-temperature rheology.

[0111] Experimental Example 2

[0112] The plugging performance tests were conducted on drilling fluids LH-1, HEM, QF and BF.

[0113] The plugging performance was measured by a sand bed filtration test. The instrument used in the sand bed filtration test was a visual medium-pressure sand bed plugging instrument. The sand particle size used was 100-120 mesh. The test results are shown in Table 3 below.

[0114] Table 3. Plugging performance test results

[0115]

[0116] Table 3 shows that the sand bed invasion depth of drilling fluid LH-1 is 2.4 cm, only slightly greater than the 2.5 cm of drilling fluid BF, and weaker than the 2.0 cm of drilling fluid QF and the 1.4 cm of drilling fluid HEM. This is due to the removal of a significant amount of bridging agents from drilling fluid LH-1, as well as the fact that LH-1 is a solids-free drilling fluid.

[0117] Experimental Example 3

[0118] The clay hydration inhibition performance of drilling fluids LH-1, HEM, QF and BF was tested.

[0119] Based on the analysis results of deepwater shallow hydrate reservoir rock samples, artificial hydrate reservoir rock samples were prepared. The core linear expansion rate under the action of drilling fluids LH-1, HEM, QF and BF was investigated using a core linear expansion instrument. The experimental results are as follows: Figure 4 shown.

[0120] Depend on Figure 4The results show that the linear expansion rate of hydrate deposits in the artificial core in pure water reached 18.07%, while the expansion rate in drilling fluid LH-1 was 2.16%, which is between that in drilling fluids HEM and QF. Drilling fluid LH-1 exhibits excellent clay hydration inhibition. In drilling fluids HEM and LH-1, the primary agents inhibiting clay hydration in hydrate deposits are KCl and PF-UHIB, but in different ratios. In drilling fluids BF and QF, PF-UHIB is the primary agent inhibiting clay hydration. The large amount of MEG used also reduces the water content in the system, thereby enhancing the hydration inhibition effect of hydrate deposits.

[0121] Experimental Example 4

[0122] The hydrate formation inhibition performance of drilling fluids LH-1, HEM, QF and BF was tested, and the results are shown in Table 4 and Figure 5 shown.

[0123] The evaluation of hydrate formation inhibition is based on the constant cooling method. The experimental steps are as follows:

[0124] (1) Reactor preparation: After opening the high-pressure window hydrate reactor and cleaning the inner wall, inject 370 mL of the test solution into the reactor, then install the reactor, tighten the screws on the retaining ring, and turn on the water bath to keep the reactor in a steady state at 18 °C;

[0125] (2) Air tightness test: After ensuring that all pipelines are connected, turn on the vacuum pump to evacuate the air. When the pressure in the kettle remains stable at -0.09 MPa for more than 15 minutes, the air tightness is considered good.

[0126] (3) Adding methane gas: Close the vacuum inlet valve, open the high-pressure gas injection valve, and inject 14 MPa of methane gas into the high-pressure window hydrate reactor. The injection of methane gas is considered complete when the pressure in the reactor remains less than 0.01 MPa for 30 minutes;

[0127] (4) Evaluation of hydrate formation inhibition: Start the temperature control program and camera capture program of the experimental device, stabilize the reactor at 18 °C for 30 min, and then cool the reactor from 18 °C to 0 °C at a cooling rate of 3 °C / h within 6 h to conduct the hydrate formation inhibition evaluation experiment.

[0128] (5) Result observation: Hydrate formation is considered complete when the temperature and pressure in the reactor remain stable within 30 minutes.

[0129] Table 4. Temperature and pressure parameters of hydrate formation under the influence of different drilling fluids

[0130]

[0131] Table 4 shows that when hydrates formed in drilling fluid HEM, the jacket temperature was 0.66°C and the kettle liquid temperature was 2.75°C, both below the mudline temperature (2.9°C) of the South China Sea hydrate reservoir. Furthermore, the initial torque increased slightly when the well was reopened after shutting in. However, to reduce the density of drilling fluid HEM and enable its application in drilling in the South China Sea hydrate reservoir, the use of hydrate thermodynamic inhibitors must be reduced, which in turn leads to a decrease in its hydrate inhibition performance. Drilling fluid QF did not form hydrates throughout the entire process, and its initial torque did not change significantly when the well was reopened after shutting in. Compared to drilling fluid QF, when hydrates formed in drilling fluid BF, the jacket temperature was 3.53°C and the kettle liquid temperature was 4.74°C. This indicates that the hydrate inhibition failure temperature of drilling fluid BF is higher than the mudline temperature of the hydrate reservoir, and the density of drilling fluid BF is within the lower limit of the density window for reservoir drilling fluid systems.

[0132] Depend on Figure 5 It can be seen that the time for drilling fluid LH-1 to completely inhibit hydrate formation at -0.45℃ / 0.28℃ conditions exceeds 6.26 hours. At the same time, the step-cooling experiment tested the failure temperature of the hydrate drilling fluid system to be -0.66℃ / -2.07℃, and the hydrate formation inhibition performance of drilling fluid LH-1 was excellent.

[0133] Experimental Example 5

[0134] The thermal conductivity and hydrate decomposition inhibition performance tests of the drilling fluids LH-1, HEM, QF and BF were carried out. The results are shown in Table 5 and Figure 6 shown.

[0135] The hydrate decomposition inhibition performance test steps are as follows:

[0136] (1) Reactor preparation: After opening the high-pressure hydrate reactor and cleaning the inner wall, inject 500 mL of pure water solution into the reactor, then install the reactor, tighten the screws on the retaining ring, and turn on the water bath to keep the reactor in a steady state at 18 °C;

[0137] (2) Air tightness test: After ensuring that all pipelines are connected, turn on the vacuum pump to evacuate the air. When the pressure in the kettle remains stable at -0.09 MPa for more than 15 minutes, the air tightness is considered good.

[0138] (3) Adding methane gas: Close the vacuum inlet valve, open the high-pressure gas injection valve, and inject 10 MPa of methane gas into the high-pressure window hydrate reactor. The injection of methane gas is considered complete when the pressure in the reactor remains less than 0.01 MPa for 30 minutes;

[0139] (4) Initial hydrate formation: Start the temperature control program of the experimental device and rapidly reduce the jacket temperature of the reactor from 18 °C to 0 °C to perform initial hydrate formation. When the temperature and pressure in the reactor remain unchanged for a period of time, the hydrate formation is considered to be complete.

[0140] (5) Evaluation of decomposition inhibition performance: Turn on the constant flow injection pump and inject the test solution into the reactor within 10 minutes. After the injection is completed, turn on the high-temperature water bath to 25 °C to simulate the heating process of the drill pipe;

[0141] (6) Result observation: When the temperature and pressure in the reactor remain stable within 30 minutes, the hydrate decomposition is considered complete.

[0142] Table 5 Thermal conductivity test results of different drilling fluid systems

[0143]

[0144] From Table 5 and Figure 6 It can be seen that under the influence of the four drilling fluid systems, the reduced thermal conductivity of the systems slows heat transfer to the reservoir, slowing the rate of hydrate decomposition. A comparison of the methane release curves reveals that the hydrate decomposition rates of drilling fluids HEM and QF are similar in the first 40 minutes, reaching 76%. Thereafter, the hydrate decomposition rate of drilling fluid QF is lower than that of drilling fluid HEM. Compared to drilling fluids QF and HEM, drilling fluid BF has a hydrate decomposition rate of only 66% in the first 40 minutes. This suggests that the addition of large amounts of thermodynamic inhibitors, such as MEG, to the drilling fluid accelerates reservoir hydrate decomposition. Drilling fluid LH-1, on the other hand, releases 0.51 mol of methane at 40 minutes, lower than the 0.68 mol of drilling fluid BF. Drilling fluid BF is nearly completely decomposed at 88 minutes, with the decomposition rate of drilling fluid LH-1 reaching 75%, demonstrating excellent decomposition inhibition and minimal reservoir damage.

Claims

1. A drilling fluid system for ensuring flow and protecting reservoirs of natural gas hydrates in offshore areas, characterized in that: The drilling fluid system includes the following components: Natural seawater, NaCl, KCl, plugging agents, clay hydration inhibitors, fluid loss additives, flow pattern regulators, density control agents, dual-effect hydrate inhibitors, hydrate formation inhibitors, and hydrate decomposition inhibitors; wherein, relative to 100 parts by weight of natural seawater, the content of NaCl is 5-10 parts by weight, the content of KCl is 2-6 parts by weight, the content of the plugging agent is 2-6 parts by weight, the content of the clay hydration inhibitor is 0.1-1 parts by weight, the content of the fluid loss reducer is 0.5-3 parts by weight, the content of the flow pattern regulator is 0.1-0.5 parts by weight, the content of the density control agent is 0.5-3 parts by weight, the content of the dual-effect hydrate inhibitor is 0.5-3 parts by weight, the content of the hydrate formation inhibitor is 0.5-3 parts by weight, and the content of the hydrate decomposition inhibitor is 1-6 parts by weight; The plugging agent is nano anti-collapse plugging agent NF-1; the clay hydration inhibitor is polyamine inhibitor PF-UHIB; the fluid loss reducer is fluid loss reducer PF-FLOTROL; the flow pattern regulator is flow pattern regulator PF-XC; the density control agent is density control agent PDC; the dual-effect hydrate inhibitor is polyvinyl pyrrolidone; the hydrate formation inhibitor is hydrate formation inhibitor SYZ-3; the hydrate decomposition inhibitor is hydrate decomposition inhibitor PTC-1; The hydrate formation inhibitor SYZ-3 is prepared according to the following method: N, N-dimethylacrylamide and N-vinylcaprolactam were added to the reaction solvent, stirred continuously, and nitrogen was introduced to maintain oxygen-free conditions until they were completely dissolved; the temperature was raised to 60-85°C, an initiator was added dropwise to carry out a free radical polymerization reaction, and the product was purified to obtain the hydrate formation inhibitor SYZ-3; The reaction solvent is dimethylformamide, and the initiator is recrystallized azobisisobutyronitrile; the mass ratio of N-vinylcaprolactam, N, N-dimethylacrylamide, initiator, and reaction solvent is (10-15): (2-8): (0.1-5): (70-90); the continuous stirring is stirring at 15-25 r / min for 15-25 minutes; the free radical polymerization reaction time is 6-8 hours; The hydrate decomposition inhibitor PTC-1 is prepared according to the following method: n-tetradecane and n-hexadecane are uniformly mixed to obtain an oil phase solution; sodium alginate is dissolved in pure water to obtain an aqueous phase solution; the mixture of the aqueous phase solution and the oil phase solution is emulsified using a high-speed homogenizer to obtain a phase change emulsion; the phase change emulsion is sprayed into a calcium chloride solution using the electrostatic spraying function of an electrospinning machine to obtain the hydrate decomposition inhibitor PTC-1; The mass ratio of n-tetradecane, n-hexadecane, sodium alginate and calcium chloride is (1-4): (4-8): (0.5-5): (2-6); the mass concentration of sodium alginate in the aqueous phase solution is 1-3wt%; the mass concentration of the calcium chloride solution is 1-5wt%. The speed of the high-speed homogenizing emulsifier is 500-70000 r / min, the emulsification time is 20-30 min, the electrostatic spraying voltage is 8-12 kV, and the spraying rate is 1-3 mL / min.

2. The offshore natural gas hydrate wellbore flow assurance and reservoir protection drilling fluid system according to claim 1, characterized in that: The drilling fluid system comprises the following components: relative to 100 parts by weight of natural seawater, 5-10 parts by weight of NaCl, 5 parts by weight of KCl, 2-5 parts by weight of a nano-anti-collapse plugging agent NF-1, 0.5 parts by weight of a polyamine inhibitor PF-UHIB, 1-2 parts by weight of a fluid loss reducer PF-FLOTROL, 0.15-0.3 parts by weight of a flow pattern regulator PF-XC, 1-3 parts by weight of a density control agent PDC, 1 part by weight of PVP, 1 part by weight of a hydrate formation inhibitor SYZ-3, and 3 parts by weight of a hydrate decomposition inhibitor PTC-1.

3. The offshore natural gas hydrate wellbore flow assurance and reservoir protection drilling fluid system according to claim 1, characterized in that: The drilling fluid system includes the following components: relative to 100 parts by weight of natural seawater, 9 parts by weight of NaCl, 5 parts by weight of KCl, 5 parts by weight of nano anti-collapse plugging agent NF-1, 0.5 parts by weight of polyamine inhibitor PF-UHIB, 1 part by weight of fluid loss reducer PF-FLOTROL, 0.25 parts by weight of flow pattern regulator PF-XC, 1 part by weight of density control agent PDC, 1 part by weight of PVP, 1 part by weight of hydrate formation inhibitor SYZ-3 according to Example 1, and 3 parts by weight of hydrate decomposition inhibitor PTC-1 according to Example 2.

4. The method for preparing the offshore natural gas hydrate wellbore flow assurance and reservoir protection drilling fluid system according to any one of claims 1 to 3, characterized in that: The steps are as follows: Slowly add density control agent, hydrate formation inhibitor, hydrate decomposition inhibitor, flow pattern regulator, fluid loss additive, hydrate dual-effect inhibitor, plugging agent, clay hydration inhibitor, KCl, and NaCl to natural seawater in order. Stir at high speed after adding each substance, and then add the next substance. The rotation speed of the high-speed stirring is 8000-12000 r / min, and the stirring time is 5-25 min.

5. Application of the offshore natural gas hydrate wellbore flow assurance and reservoir protection drilling fluid system according to any one of claims 1 to 3 in a drilling process, characterized in that: For flow assurance and reservoir protection.

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