Deepwater under-salt drilling wellbore pressure fine regulation and control system and method

Abstract

The invention relates to a deep-water under-salt drilling wellbore pressure fine regulation and control system and method, and belongs to the technical field of oil and gas development drilling and completion engineering. The system comprises a wellbore inlet which is sequentially connected with an inlet displacement meter, a drilling fluid pump and a drilling fluid tank outwards, and a wellhead outlet is sequentially connected with a wellbore pressure regulation and control device, a slurry pump, an outlet flow meter and a slurry pool; the inlet displacement meter, the outlet displacement meter and the shaft pressure regulation and control device are all connected to the fine pressure control drilling system, the safety equivalent drilling fluid density of salt bed open hole sections of different depths can be obtained by accurately calculating the shaft temperature field and the equivalent circulation density and considering the influence of rock stratum creep characteristics on the drilling fluid density and the creep diameter shrinkage rate, and the drilling fluid density of the salt bed open hole sections of different depths can be obtained. And the wellhead return pressure is adjusted in real time, so that the precise regulation and control of the wellbore pressure are realized.

Description

Technical Field

[0001] The present invention relates to a fine control system and method for wellbore pressure in deep - water sub - salt drilling, belonging to the technical field of oil and gas development drilling and completion engineering. Background Art

[0002] With the continuous growth of global energy demand, deep - water sub - salt oilfields have become an important direction for the future development of the petroleum industry. However, the drilling and development of thick salt layers face huge technical challenges. In particular, the complex geological structure and unstable formation pressure conditions below the salt layer lead to high - risk accidents such as well kicks, losses, and pipe sticking during drilling operations. These problems have greatly restricted the exploration and development process of sub - salt oil and gas reservoirs.

[0003] Deep - water salt layers have special creep characteristics. Their unique physical properties cause the salt layer to undergo continuous plastic flow during drilling, resulting in deformation. The creep of the salt layer not only affects the stability of the wellbore wall during drilling but also easily causes the shrinkage of the wellbore and the expansion of cracks, further increasing the loss risk of fractured formations below the salt layer. This creep characteristic makes the fractured formations below the salt layer more prone to losses, further increasing the difficulty of controlling wellbore pressure during drilling.

[0004] Currently, the deep - water salt - layer drilling technology in China is not yet fully mature. Many projects have led to early termination of drilling or accidents due to the inability to effectively control wellbore pressure, resulting in a large amount of wasted resources. Especially due to the complex influence of salt - layer creep on wellbore pressure, the existing technologies are difficult to cope with the challenges it brings. Summary of the Invention

[0005] Aiming at the deficiencies of the existing technology, the present invention provides a fine control system and method for wellbore pressure in deep - water sub - salt drilling. This application considers the creep influence of thick salt layers, and the established model can predict the safety equivalent drilling fluid density window for salt - layer creep hole shrinkage.

[0006] The technical solution of the present invention is as follows:

[0007] A fine control system for the pressure of a deep - water sub - salt drilling wellbore includes a wellbore. A derrick is set above the wellbore, and a blowout preventer is set at the wellhead. The wellhead inlet is sequentially connected to an inlet displacement meter, a drilling fluid pump, and a drilling fluid tank outward. The inlet displacement meter is used to measure the displacement of the injected drilling fluid in real - time. The drilling fluid pump provides power for injecting the drilling fluid into the wellbore and adjusts the displacement during the injection process. The drilling fluid tank is used to store the drilling fluid. The wellhead outlet is connected to a wellbore pressure control device, and the wellhead backpressure is dynamically adjusted by adjusting the opening of the throttle valve inside it, thereby controlling the internal pressure of the wellbore. The wellbore pressure control device is sequentially connected to a mud pump, an outlet flowmeter, and a mud pit. The mud pump provides power for the drilling fluid circulated out of the wellbore. The outlet flowmeter is used to measure the flow rate of the outlet drilling fluid in real - time. The mud pit is used to store the drilling fluid circulated out of the wellbore. The inlet displacement meter, the outlet displacement meter, and the wellbore pressure control device are all connected to a fine pressure - controlled drilling system.

[0008] A control method for a fine control system for the pressure of a deep - water sub - salt drilling wellbore includes the following steps:

[0009] 1). Obtain the basic data of the operation well, including: wellbore structure, salt layer depth, geothermal gradient, circulation displacement, formation triple - pressure profile, and record the designed density of the drilling fluid as ρ 0 ;

[0010] 2). Connect the fine control system for the pressure of the deep - water sub - salt drilling wellbore:

[0011] (1) Place the derrick at the upper part of the center of the wellbore to provide an operating platform for drilling workers;

[0012] (2) Install a blowout preventer at the wellhead, which can be used to close the wellbore in case of emergency;

[0013] (3) The wellhead inlet is sequentially connected to an inlet displacement meter, a drilling fluid pump, and a drilling fluid tank. The inlet displacement meter can be used to measure the displacement of the injected drilling fluid in real - time. The drilling fluid pump provides power for injecting the drilling fluid into the wellbore and can adjust the displacement during the injection process. The drilling fluid tank is used to store the drilling fluid;

[0014] (4) The wellhead outlet is connected to a wellbore pressure control device, and the wellhead backpressure can be dynamically adjusted by adjusting the opening of the throttle valve inside it, thereby controlling the internal pressure of the wellbore;

[0015] (5) The wellbore pressure control device is sequentially connected to a mud pump, an outlet flowmeter, and a mud pit. The mud pump provides power for the drilling fluid circulated out of the wellbore. The outlet flowmeter can measure the flow rate of the outlet drilling fluid in real - time. The mud pit is used to store the drilling fluid circulated out of the wellbore;

[0016] (6) The inlet displacement meter, the outlet displacement meter, and the wellbore pressure control device are all connected to a fine pressure - controlled drilling system, which can read the inlet and outlet flow rates recorded by the inlet flowmeter and the outlet flowmeter in real - time.

[0017] 3) Calculation of wellbore temperature field:

[0018] (1) Below the seabed, significant heat exchange occurs between the wellbore wall and the formation, and the temperature distribution of the fluid in the annulus is described by the following formula:

[0019]

[0020] Where: T ei is the formation temperature, °C; T a is the annulus fluid temperature, °C; T t is the fluid temperature in the drill pipe, °C;

[0021]

[0022] Where: c f is the specific heat capacity of the drilling fluid, J / (kg·°C); w is the volume flow rate of the drilling fluid, kg / s; r ci is the inner diameter of the casing, m; U a is the total convective heat transfer coefficient between the annulus and the wellbore wall, w / (m 2 ·°C);

[0023]

[0024] Where: r pi is the inner diameter of the drill pipe, m; U p is the convective heat transfer coefficient between the drill pipe and the annulus, w / (m 2 ·°C);

[0025] (2) The calculation formula for the wellbore wall temperature T wb is:

[0026]

[0027] Where: q f is the heat transferred from the formation to the annulus, J·s -1 ; k e is the formation thermal conductivity, W·m -1 ·°C -1 ; T D is the transient heat transfer function, dimensionless;

[0028] (3) The temperature of the fluid in the drill pipe is affected by heat conduction and hydrodynamics, and the distribution formula is:

[0029]

[0030] 4) Calculation of equivalent circulating density in the wellbore:

[0031] The equivalent circulating density ECD further takes into account the circulation pressure loss and cuttings effect, and its expression is:

[0032] ECD = ESD + P f / g + Δρ c (6)

[0033] Where: ESD is the drilling fluid density, g / cm 3 ; P f is the annulus circulation pressure loss per unit distance, Pa·m -1 ; Δρ c is the increase in the equivalent density of the drilling fluid caused by the cuttings concentration, kg·m -3 ;

[0034] 5), The calculation formula for the drilling fluid density considering formation creep:

[0035]

[0036] Where: P 0 is the surface pressure, MPa; r 0 is the wellbore radius, m; N is the drill pipe rotation speed, r·min -1 ; H is the current well depth of the operation, m; a 0 is the initial wellbore radius, i.e., the bit radius, m; a is the actual wellbore radius at the current moment, m; n is the wellbore shrinkage rate, h -1 ;

[0037] As long as the initial wellbore radius a 0 , i.e., the bit radius, the required wellbore shrinkage rate n to be controlled, and the actual wellbore radius a at the current moment are given, substituting into formula (7) can obtain the lower limit value of the equivalent drilling fluid density required to maintain the required wellbore shrinkage rate, i.e., the shrinkage pressure;

[0038] 6), The calculation formula for the safety creep shrinkage rate that needs to be controlled at the target position of the drilled salt layer section at any depth is:

[0039]

[0040] Where: N i is the creep shrinkage rate required for the target position of the drilled salt layer section, h -1 ; ψ is the current shrinkage rate at the target position of the drilled salt layer section; H t is the salt top depth, m; Ψ is the engineering required safety shrinkage rate, taking a certain value, such as taking 15%; D is the required operation time, day; H b is the salt bottom depth, m; H is the current well depth of the operation, m; k i is the dissolution and expansion rate at the target position of the drilled salt layer section, h -1 ;

[0041] 7), after drilling into the salt layer, calculate the creep and diameter reduction rate of the salt layer through the fine pressure control drilling system, and select the corresponding construction conditions; preferably, the selected construction conditions include drilling conditions, pump shutdown conditions, circulation conditions, tripping conditions, and running-in conditions.

[0042] 8), through the fine pressure control drilling system, the equivalent drilling fluid density requirements at each position of the open hole section of the salt layer at any depth can be obtained, that is, the calculation result of formula (7), and the lower limit of the safe equivalent drilling fluid density for inhibiting creep and diameter reduction when drilling through the salt layer can be obtained;

[0043] 9), update the wellhead backpressure target value according to the drilling fluid density, and use the wellbore pressure control device to adjust the wellhead backpressure to the target value;

[0044] 10), according to the depth of drilling through the salt layer, obtain the drilling fluid density at different depths, and then obtain the real-time updated density distribution in the wellbore, and return to step 8) to update the drilling fluid density and the wellhead backpressure value until the drilling is completed.

[0045] The beneficial effects of the present invention are as follows:

[0046] By accurately calculating the wellbore temperature field and equivalent circulating density, and considering the influence of the creep characteristics of the rock formation on the drilling fluid density and creep and diameter reduction rate, the present invention can obtain the safe equivalent drilling fluid density of the open hole section of the salt layer at different depths, and adjust the wellhead backpressure in real time, so as to achieve precise control of the wellbore pressure. This method not only effectively prevents the occurrence of complex accidents such as well kicks and losses, but also makes up for the deficiencies of traditional drilling technologies. Especially when facing the challenges brought by salt layer creep, it provides a more reliable solution. Description of the Drawings

[0047] Figure 1 Schematic diagram of the lower limit of the safe equivalent drilling fluid density considering salt layer creep;

[0048] Figure 2 Schematic diagram of the fine wellbore pressure control system for deep water drilling below the salt layer;

[0049] Figure 3 Flow chart of the fine wellbore pressure control for deep water drilling below the salt layer;

[0050] Figure 2 In the figure: 1, derrick; 2, blowout preventer; 3, wellbore; 4, drill pipe; 5, bit; 6, inlet flowmeter; 7, drilling fluid pump; 8, drilling fluid tank; 9, wellbore pressure control device; 10, mud pump; 11, outlet flowmeter; 12, mud pit; 13, fine pressure control drilling system. Detailed Embodiments

[0051] The present invention will be further described below through embodiments in conjunction with the accompanying drawings, but is not limited thereto.

[0052] Embodiment 1:

[0053] A fine control system for the pressure of a deep - water sub - salt drilling wellbore, as Figure 2 shown, includes a wellbore 3, a derrick 1 is arranged above the wellbore, drill pipes 4 and a drill bit 5 are placed in the wellbore; a blowout preventer 2 is arranged at the wellhead, and an inlet displacement meter 6, a drilling fluid pump 7 and a drilling fluid tank 8 are sequentially connected outward from the wellhead inlet. The inlet displacement meter is used to measure the displacement of the injected drilling fluid in real time. The drilling fluid pump provides power for injecting the drilling fluid into the wellbore and adjusts the displacement during the injection process. The drilling fluid tank is used to store the drilling fluid; the wellhead outlet is connected to a wellbore pressure control device 9, and the wellhead back pressure is dynamically adjusted by adjusting the opening of the throttle valve inside it, thereby controlling the internal pressure of the wellbore. The wellbore pressure control device is sequentially connected with a mud pump 10, an outlet flowmeter 11 and a mud pit 12. The mud pump provides power for the drilling fluid circulated out of the wellbore, the outlet flowmeter is used to measure the flow rate of the outlet drilling fluid in real time, and the mud pit is used to store the drilling fluid circulated out of the wellbore; the inlet displacement meter, the outlet displacement meter and the wellbore pressure control device are all connected to a fine pressure control drilling system 13.

[0054] Embodiment 2:

[0055] A control method for a fine control system of the pressure of a deep - water sub - salt drilling wellbore includes the following steps:

[0056] 1) Obtain the basic data of the operating well, including: wellbore structure, salt layer depth, geothermal gradient, circulation displacement, formation triple - pressure profile, and record the designed density of the drilling fluid as ρ 0 .

[0057] 2) Connect the fine control system for the pressure of the deep - water sub - salt drilling wellbore described in Embodiment 1:

[0058] (1) The derrick 1 is placed at the upper center of the wellbore 3 to provide an operating platform for drilling workers; drill pipes 4 and a drill bit 5 are placed in the wellbore;

[0059] (2) Install a blowout preventer 2 at the wellhead, which can be used to close the wellbore in case of emergency;

[0060] (3) The wellhead inlet is sequentially connected to an inlet displacement meter 6, a drilling fluid pump 7 and a drilling fluid tank 8. The inlet displacement meter can be used to measure the displacement of the injected drilling fluid in real time. The drilling fluid pump provides power for injecting the drilling fluid into the wellbore and can adjust the displacement during the injection process. The drilling fluid tank is used to store the drilling fluid;

[0061] (4) The wellhead outlet is connected to a wellbore pressure control device 9, and the wellhead back pressure can be dynamically adjusted by adjusting the opening of the throttle valve inside it, thereby controlling the internal pressure of the wellbore;

[0062] (5) The wellbore pressure control device is successively connected to a mud pump 10, an outlet flowmeter 11, and a mud pit 12. The mud pump provides power for the drilling fluid circulated out of the wellbore. The outlet flowmeter can measure the flow rate of the outlet drilling fluid in real time. The mud pit is used to store the drilling fluid circulated out of the wellbore.

[0063] (6) The inlet displacement meter, the outlet displacement meter, and the wellbore pressure control device are all connected to the fine pressure control drilling system 13, and can read the inlet and outlet flow rates recorded by the inlet flowmeter and the outlet flowmeter in real time.

[0064] 3) Calculation of wellbore temperature field:

[0065] (1) Below the seabed, significant heat exchange occurs between the wellbore wall and the formation, and the temperature distribution of the fluid in the annulus is described by the following formula:

[0066]

[0067] In the formula: T ei is the formation temperature, °C; T a is the temperature of the annulus fluid, °C; T t is the temperature of the fluid in the drill pipe, °C;

[0068]

[0069] In the formula: c f is the specific heat capacity of the drilling fluid, J / (kg·°C); w is the volume flow rate of the drilling fluid, kg / s; r ci is the inner diameter of the casing, m; U a is the total convective heat transfer coefficient between the annulus and the wellbore wall, w / (m 2 ·°C);

[0070]

[0071] In the formula: r pi is the inner diameter of the drill pipe, m; U p is the convective heat transfer coefficient between the drill pipe and the annulus, w / (m 2 ·°C);

[0072] (2) The wellbore wall temperature T wb The calculation formula is:

[0073]

[0074] In the formula: q f is the heat transferred from the formation to the annulus, J·s -1 ; k e is the formation thermal conductivity, W·m -1 ·°C -1 ; T Dis the transient heat transfer function, dimensionless;

[0075] (3) The temperature of the fluid inside the drill pipe is affected by heat conduction and hydrodynamics, and its distribution formula is:

[0076]

[0077] 4) Calculation of the equivalent circulating density in the wellbore:

[0078] The equivalent circulating density ECD further considers the circulation pressure loss and cuttings influence, and its expression is:

[0079] ECD = ESD + P f / g + Δρ c (6)

[0080] In the formula: ESD is the density of the drilling fluid, g / cm 3 ; P f is the annular circulation pressure loss per unit distance, Pa·m -1 ; Δρ c is the increase in the equivalent density of the drilling fluid caused by the cuttings concentration, kg·m -3 .

[0081] 5) Calculation formula for the density of the drilling fluid considering formation creep:

[0082]

[0083] In the formula: P 0 is the surface pressure, MPa; r 0 is the wellbore radius, m; N is the rotational speed of the drill pipe, r·min -1 ; H is the current depth of the well being drilled, m; a 0 is the initial radius of the wellbore, i.e., the bit radius, m; a is the actual wellbore radius at the current moment, m; n is the wellbore shrinkage rate, h -1 ;

[0084] As long as the initial radius of the wellbore a 0 , i.e., the bit radius, the required wellbore shrinkage rate n to be controlled, and the actual wellbore radius a at the current moment are given, substituting into formula (7) can obtain the lower limit value of the equivalent drilling fluid density required to maintain the required wellbore shrinkage rate, i.e., the shrinkage pressure.

[0085] 6) Calculation formula for the safe creep shrinkage rate that needs to be controlled at the target position of the drilled salt layer section when drilling to any depth:

[0086]

[0087] In the formula: N i is the creep shrinkage rate required at the target position of the drilled salt layer section, h-1 ; ψ is the current diameter reduction rate of the target position in the drilled salt layer section; H t is the depth of the salt top, m; Ψ is the safe diameter reduction rate required by the project, taking a certain value, such as 15%; D is the required operation time, day; H b is the depth of the salt bottom, m; H is the current well depth of the operation, m; k i is the dissolution and diameter expansion rate of the target position in the drilled salt layer section, h -1 .

[0088] 7), After drilling into the salt layer, calculate the creep and diameter reduction rate of the salt layer through the fine pressure control drilling system, and select the corresponding construction conditions.

[0089] 8), Through the fine pressure control drilling system, the equivalent drilling fluid density requirements at each position in the open hole section of the salt layer at any depth can be obtained, that is, the calculation result of formula (7), and the lower limit of the safe equivalent drilling fluid density for inhibiting creep and diameter reduction when drilling through the salt layer can be obtained, such as Figure 1 shown; Figure 1 The red line and the blue line in are the data obtained through on-site construction, and the yellow line is calculated through the fine pressure control drilling system. When drilling through the salt layer, the drilling fluid density should be controlled between the yellow line and the red line.

[0090] 9), Update the target value of the wellhead backpressure according to the drilling fluid density, and use the wellbore pressure control device to adjust the wellhead backpressure to the target value. The specific process is as Figure 3 shown.

[0091] 10), According to the depth of drilling through the salt layer, obtain the drilling fluid density at different depths, and then obtain the real-time updated density distribution in the wellbore. Return to step 8) to update the drilling fluid density and the wellhead backpressure value until the drilling is completed.

Claims

1. A deepwater subsalt drilling wellbore pressure fine control system, characterized in that: It includes a wellbore, a derrick is arranged above the wellbore, a blowout preventer is arranged at the wellhead, the wellhead inlet is connected to an inlet displacement meter, a drilling fluid pump and a drilling fluid tank in sequence, the inlet displacement meter is used to measure the displacement of the injected drilling fluid in real time, the drilling fluid pump provides power for the drilling fluid to be injected into the wellbore and adjusts the displacement during the injection process, and the drilling fluid tank is used to store the drilling fluid; the wellhead outlet is connected to the wellbore pressure control device, the wellbore pressure control device is connected to a mud pump, an outlet flow meter, and a mud pool in sequence, the mud pump provides power for the drilling fluid circulating out of the wellbore, the outlet flow meter is used to measure the outlet drilling fluid flow in real time, and the mud pool is used to store the drilling fluid circulating out of the wellbore; the inlet displacement meter, the outlet displacement meter and the wellbore pressure control device are all connected to the fine pressure controlled drilling system.

2. A control method for a deepwater subsalt drilling wellbore pressure fine control system, characterized in that: The steps include: 1) Obtain basic data of operating wells; 2) Connect to the deepwater subsalt drilling wellbore pressure fine control system: 3) Calculation of wellbore temperature field: (1) Below the seabed, significant heat exchange occurs between the wellbore wall and the formation. The temperature distribution of the fluid in the annulus is described by the following formula: Where: T ei is the formation temperature, °C; T a is the annular fluid temperature, °C; T t is the fluid temperature in the drill pipe, °C; Where: c f is the specific heat capacity of the drilling fluid, J / (kg℃); w is the volume flow rate of the drilling fluid, kg / s; r ci is the inner diameter of the casing, m; U a is the total convective heat transfer coefficient between the annulus and the wellbore wall, w / (m 2 ℃); Where: r pi is the inner diameter of the drill pipe, m; U p is the convective heat transfer coefficient between the drill pipe and the annulus, w / (m 2 ℃); (2) Well wall temperature T wb The calculation formula is: Where: q f is the heat transferred from the formation to the annulus, J·s -1 ;k e is the formation thermal conductivity, W·m -1 ℃ -1 ; T D is the transient heat transfer function, dimensionless; (3) The temperature of the fluid in the drill pipe is affected by heat conduction and fluid dynamics, and the distribution formula is: 4) Calculation of wellbore equivalent circulating density: The expression of equivalent circulation density ECD is: ECD=ESD+P f / g+Dr c (6) Where: ESD is the drilling fluid density, g / cm 3 ;P f is the annular circulation pressure loss per unit distance, Pa·m -1 ; Δρ c is the increase in drilling fluid equivalent density due to cuttings concentration, kg·m -3 ; 5) Calculation formula of drilling fluid density considering rock formation creep: Where: P0 is the surface pressure, MPa; r0 is the wellbore radius, m; N is the drill pipe speed, r·min -1 ; H is the current operating well depth, m; a0 is the starting radius of the wellbore, that is, the drill bit radius, m; a is the actual wellbore radius at the current moment, m; n is the wellbore shrinkage rate, h -1 ; As long as the starting radius of the wellbore a0, i.e. the drill bit radius, is known, the wellbore shrinkage rate n required to be controlled is given, and the actual wellbore radius a at the current moment is substituted into formula (7), the lower limit of the equivalent drilling fluid density required to maintain the required wellbore shrinkage rate, i.e. the shrinkage pressure, can be obtained; 6) When drilling to any depth, the calculation formula for the safe creep shrinkage rate corresponding to the target position of the drilled salt layer section is: Where: N i is the creep shrinkage rate required at the target location of the drilled salt layer, h -1 ψ is the current shrinkage rate of the target position of the drilled salt layer segment; H t is the depth of the salt top, m; Ψ is the safety reduction ratio required by the project, which takes a certain value; D is the required operation time, day; H b is the salt bottom depth, m; H is the current operating well depth, m; k i is the dissolution expansion rate at the target position of the drilled salt layer, h -1 ; 7) After drilling to the salt layer, the creep shrinkage rate of the salt layer is calculated by the fine pressure-controlled drilling system, and the corresponding construction conditions are selected; 8) Obtain the equivalent drilling fluid density requirement at each position of the salt layer open hole section when drilling to any depth through the fine pressure controlled drilling system, and obtain the lower limit of the safe equivalent drilling fluid density to inhibit creep shrinkage when drilling into the salt layer; 9) Update the wellhead back pressure target value according to the drilling fluid density, and adjust the wellhead back pressure to the target value using the wellbore pressure control device; 10) According to the depth of drilling through the salt layer, the density of the drilling fluid at different depths is obtained, and then the density distribution in the wellbore is updated in real time, and the process returns to step 8) to update the density of the drilling fluid and the wellhead back pressure value until the drilling is completed.

3. The control method of the deepwater subsalt drilling wellbore pressure fine control system according to claim 2 is characterized in that: In step 1), the basic data include wellbore structure, salt layer depth, geothermal gradient, circulation displacement, and three-pressure planing surface of the formation, and the drilling fluid design density is recorded as ρ0.

4. The control method of the deepwater subsalt drilling wellbore pressure fine control system according to claim 2 is characterized in that: In step 2), the connecting step includes: (1) The derrick is placed at the upper center of the wellbore; (2) Install a blowout preventer at the wellhead; (3) The wellhead inlet is connected in sequence to the inlet displacement meter, the drilling fluid pump and the drilling fluid tank; (4) The wellhead outlet is connected to the wellbore pressure control device; (5) The wellbore pressure control device is connected in sequence to a mud pump, an outlet flow meter, and a mud tank; (6) The inlet displacement meter, outlet displacement meter, and wellbore pressure control device are all connected to the precision pressure controlled drilling system, which can read the inlet and outlet flow recorded by the inlet flow meter and outlet flow meter in real time.

5. The control method of the deepwater subsalt drilling wellbore pressure fine control system according to claim 2, characterized in that: In step 6), Ψ is the safety reduction ratio required by the project, which is 15%.

6. The control method of the deepwater subsalt drilling wellbore pressure fine control system according to claim 2, characterized in that: In step 7), the construction working condition selection includes drilling working condition, pump stop working condition, circulation working condition, drilling out working condition, and drilling down working condition.

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