A method of fast killing a well without a bit at the bottom of the well

Abstract

The application discloses a quick well killing method without drill bit at well bottom, and relates to the technical field of well control of oil drilling. First, basic data is collected, initial state calculation of well killing is carried out according to the collected basic data, then suitable well killing fluid density is designed according to the initial state, casing pressure is adjusted so that the well killing fluid is divided at the drill bit, well killing parameters are designed through the well state, well killing progress is judged through the standpipe pressure and the casing pressure, and well killing is finished after the contaminated drilling fluid is completely discharged through circulation of the well killing fluid. The application proposes the quick well killing method without drill bit at well bottom, which has certain guiding significance for well killing in the case that the drill bit is not at the well bottom.

Description

Technical Field

[0001] This invention relates to the field of well control technology in oil drilling, and more specifically to a rapid well control method when the drill bit is not at the bottom of the well. Background Technology

[0002] As my country's oil and gas development continues to expand, the difficulty of drilling is increasing, and the working conditions encountered during drilling are becoming more complex, with drilling fluid overflows occurring frequently. How to take timely measures to control overflows and balance formation pressure is a key aspect of well control technology.

[0003] Traditional and commonly used well control methods are mainly the driller's method and the engineer's method. These two methods are relatively mature and widely used. However, they are difficult to handle in certain complex situations, such as during tripping out of the well, where overflow is prone to occur due to the suction principle, and the drill bit is not at the bottom of the well. Conventional well control methods are insufficient to address such situations. Therefore, in order to cope with complex conditions, safely and efficiently implement rapid drilling, and simultaneously meet national requirements for oil and gas reservoir protection, well control technology must be a key area of ​​research and development.

[0004] In situations where the drill bit is not at the bottom of the well, formation fluids infiltrate the wellbore below the drill bit, and drilling fluid circulation is required above the drill bit. Traditional driller's and engineer's methods primarily achieve well control by changing the drilling fluid density in the wellbore through circulation. However, in this condition, there is a high possibility that formation fluids cannot be forced back into the formation. The key focus and challenge lies in how to both force formation fluids back into the formation and meet the requirements for drilling fluid circulation and waste removal. Precisely controlling the pressure to divert the kill fluid at the drill bit, and accurately judging the well control progress, are the technical difficulties that the well control methods used in this situation must overcome. Summary of the Invention

[0005] To overcome the defects and shortcomings of the existing technology, this invention provides a rapid well control method when the drill bit is not at the bottom of the well. This invention is used for well control operations when the drill bit is not at the bottom of the well, improving the safety and speed of well control under such conditions, and providing a reference for further research on well control technology. This invention first performs basic data acquisition, calculates the initial state of well control based on the acquired basic data, then designs a suitable well control fluid density based on the initial state, adjusts the casing pressure to cause the well control fluid to split at the drill bit, designs well control parameters based on the well state, and judges the well control progress by using standpipe pressure and casing pressure. Well control ends after all the well control fluid is circulated upwards to discharge all contaminated drilling fluid. This invention proposes a rapid well control method for this condition where the drill bit is not at the bottom of the well, which has certain guiding significance for well control operations when the drill bit is not at the bottom of the well.

[0006] To address the problems existing in the prior art, the present invention is achieved through the following technical solution.

[0007] This invention discloses a rapid well control method when the drill bit is not at the bottom of the well, the method comprising the following steps:

[0008] S1. Basic data acquisition steps: Collect overflow reservoir parameters, overflow fluid properties, shut-in pressure, casing pressure, well structure, drill string assembly, drilling fluid and kill fluid rheological parameters through geological logging data and adjacent well data.

[0009] S2, Initial state calculation steps for well control: Based on the basic data collected in step S1, calculate the relevant parameters of the miscible section and the initial wellbore pressure distribution;

[0010] S3, Calculation steps for well control fluid diversion during well control process: Based on the initial state of well control obtained in step S2, design a suitable well control fluid density and adjust the casing pressure to divert the well control fluid at the drill bit. Part of the fluid is discharged upwards to the annulus where the contaminated drilling fluid is discharged, and part of the fluid is pushed downwards to push the overflow material below the drill bit into the formation.

[0011] S4. Well control process design steps: Design well control parameters based on the well state, and judge the well control process based on the standpipe pressure and casing pressure. When all the formation fluid is pushed back to the formation, adjust the casing pressure to make the well control fluid circulate upward at the drill bit.

[0012] S5. Circulate and discharge the contaminated drilling fluid. All the kill fluid is discharged upwards through circulation, and the kill operation ends.

[0013] More preferably, in step S1, the overflow reservoir parameters include formation porosity, permeability, formation pore pressure, and formation fracture pressure.

[0014] More preferably, in step S1, the fluid properties of the overflow layer include fluid density and fluid viscosity.

[0015] In a further preferred embodiment, in step S2, the relevant parameters of the miscible section include the miscible section pressure, which is calculated by inverting the wellbore pressure calculation formula and solving it using known shut-in parameters, including shut-in casing pressure, shut-in stand pressure, and mud pit increment; and performing differential iterative calculation on the miscible section to calculate the wellbore pressure distribution.

[0016] A further preferred formula for calculating wellbore pressure is as follows:

[0017]

[0018] When the well depth is at the bottom of the well (i.e., H = H), b When the pressure is calculated, it is the bottom hole pressure (P = P).b From this, we can obtain the following formula for calculating C:

[0019]

[0020] In the formula, P is the pressure at well depth H, in Pa; b Z is the bottom hole pressure, in Pa; C is the indefinite integral constant term, dimensionless; H T is the gas compressibility coefficient at well depth H, dimensionless; H Temperature at well depth H, in Kelvin; n H R is the number of moles of control gas at well depth H, in mol; R is the ideal gas constant, in Pa·m. 3 / mol·K; M is the relative molecular weight of the gas, in kg / mol; ρ l Density of drilling fluid, unit: g / cm³ 3 .

[0021] Furthermore, the fluid temperature T at well depth H is preferred. H The calculation formula is T H =T0+T a H; where T0 represents the ground temperature, in K; T a This represents the geothermal gradient, in Kelvin (K).

[0022] Furthermore, the compressibility coefficient Z at well depth H is further optimized. H The calculation formula is

[0023]

[0024] In the formula, A1=0.3265; A2=1.0700; A3=-0.5339; A4=0.01569; A5=-0.05165; A6=0.5475; A7=-0.7361; A8=0.1844; A9=0.1056; A 10 =0.6134; A 11 =0.7210; ρ pr For the gas pseudo-contrast density; ρ pr For the gas-paired relative temperature; ρ pr =0.27p pr / (ZT pr In the formula, p pr The relative pressure is the pressure of the gas.

[0025] A further preferred formula is used to calculate the total number of gas moles in the overflow miscible section:

[0026]

[0027] in,

[0028] In the formula, V g0 This represents the initial total overflow, in meters (m). 3 M represents the relative molecular weight of the gas, in kg / mol; H s H represents the depth measured at the upper end of the mixed-phase section of the overflow, in meters. b Depth measurement at the lower end of the overflow miscible section, unit: m; P s P b Well depth H s H b Pressure, unit MPa; Z s Z b Well depth H s H b The gas compressibility coefficient is dimensionless; T s T b Well depth H s H b Temperature, in Kelvin (K).

[0029] In a further preferred embodiment, the inversion method in step S2 is as follows: First, the length of the miscible section is set by the overflow flow rate, and the total number of gas moles in the overflow section is calculated; the miscible section is divided into infinitesimal elements, and iterative calculations are performed from the bottom to the top of the miscible section; finally, the pressure at the top of the miscible section obtained from the overflow is compared with the sum of the shut-in casing pressure and the drilling fluid column pressure above the miscible section. If they are not equal, the length of the miscible section is adjusted and the calculation is repeated; if they are equal, the length of the miscible section is determined, and then the relevant parameters of the miscible section are determined.

[0030] More preferably, the parameters related to the mixed phase section include gas phase volume, gas holdup, and mixed phase section pressure.

[0031] In a further preferred embodiment, in step S3, a suitable kill fluid density is designed. Specifically, based on the wellbore pressure calculated in step S2 and combined with the shut-in and stand-up pressure, the equivalent drilling fluid density ρ2 at the drill bit is obtained. This value is the upper limit of the kill fluid density design. The kill fluid density corresponding to the maximum pressure that the formation and wellbore can withstand is ρ1; the original drilling fluid density is ρ0. By adjusting the casing pressure, the kill fluid is diverted at the drill bit. Part of the fluid circulates upward to discharge the contaminated drilling fluid, and part of the fluid is pushed downward back to the formation fluid, thereby increasing the length of the fluid column below the drill bit and achieving the purpose of balancing the formation pressure.

[0032] Furthermore, in step S3, when designing a suitable kill fluid density, the initial kill fluid density ρ m Satisfying ρ0<ρ m <ρ1<ρ2; where ρ0 is the original drilling fluid density, in kg / m³ 3 ρ1 is the kill fluid density corresponding to the maximum pressure that the formation and wellbore can withstand, in kg / m³.3 ρ2 is the drilling fluid density at the shut-in bit, in kg / m³. 3 ;ρ m Initial kill fluid density, unit kg / m³ 3 .

[0033] Furthermore, under the condition that other factors remain constant, the functional relationship between the kill fluid discharge rate and the riser pressure is expressed as P. t (Q); Adjustment is achieved by changing the sleeve pressure value; specifically,

[0034] Assume the kill fluid displacement is Q, the upward circulation displacement at the drill bit is Q1, and the downward circulation displacement is Q2;

[0035] The pressure P at the drill bit can be calculated based on the initial state obtained in step S2. bit The hydraulic column pressure P below the drill bit b ; Calculate the flow friction P below the drill bit using the Fanning-Darcy formula bf The Fanning friction coefficient f b It is a function of the fluid Reynolds number and the pipe wall roughness; the lower limits of the values ​​of Q1 and Q2 are calculated by combining the reservoir seepage resistance.

[0036] Furthermore, the formulas for calculating Q1 and Q2 are as follows:

[0037]

[0038] in,

[0039] In the formula, Q represents the kill fluid displacement, in m³. 3 / d; Q1 represents the upward flow rate of kill fluid at the drill bit, in meters. 3 / d; Q2 represents the flow rate of kill fluid flowing downwards at the drill bit, in meters. 3 / d;P bit ΔP represents the initial pressure at the drill bit, in MPa. c P represents the additional wellhead casing pressure, in MPa. b P represents the pressure of the fluid column below the drill bit, in MPa. bf P represents the frictional resistance below the drill bit, measured in MPa. s P represents reservoir seepage resistance, in MPa. p This represents formation pressure, measured in MPa. This represents the formation fluid flow coefficient, in μm. 2 μ i The fluid viscosity is expressed in mPa·s; r e The outer radius of the well control is represented in meters (m); r w The wellbore radius is expressed in meters (m); h rf represents reservoir thickness in meters (m). b ρ represents the Fanning friction coefficient of the fluid, which is dimensionless; b This indicates the fluid density below the drill bit, in kg / m³. 3 ; v represents the fluid velocity below the drill bit, in m / s; D w D indicates the inner diameter of the casing, in mm. z Indicates the outer diameter of the drill pipe, in mm; L b This indicates the distance from the drill bit to the bottom of the well, in meters (m).

[0040] More preferably, the Fanning friction coefficient is obtained by determining the flow state using the Reynolds number, which is calculated as follows:

[0041]

[0042] When the flow state is laminar,

[0043] When the flow state is turbulent,

[0044] In the formula, Re b ε represents the fluid Reynolds number, which is dimensionless; ε represents the absolute roughness of the pipe wall, in mm.

[0045] More preferably, in step S3, when designing the kill fluid discharge rate, the on-site equipment load and boundary pressures must also be considered. The boundary pressures include formation fracturing pressure, casing shoe fracturing pressure, or casing internal pressure resistance. The maximum kill fluid discharge rate is calculated as follows: Q < min(Q3, Q4, Q5, Q6); where Q3 represents the maximum allowable kill fluid discharge rate at the wellhead, in meters. 3 / s; Q4 represents the maximum allowable kill fluid discharge rate under formation fracture pressure, in m³ / s. 3 / s; Q5 represents the maximum allowable kill fluid discharge rate at the casing shoe fracture pressure, in meters. 3 / s; Q6 represents the maximum allowable kill fluid discharge rate under internal pressure resistance of the casing, in meters. 3 / s.

[0046] In a further optimized step S4, the well control process design specifically refers to...

[0047] Initially, the well is shut in, with no circulating friction. As the kill fluid travels from the wellhead through the drill pipe to the drill bit, the standpipe pressure and casing pressure gradually decrease due to the increased pressure of the fluid column inside the drill pipe. When the kill fluid reaches the drill bit, the standpipe pressure is P. t1 =P t0 +P tf In the formula, P t1 P represents the standpipe pressure when the kill fluid reaches the drill bit, in MPa. t0P represents the initial riser pressure, in MPa. tf This indicates the circulating friction within the drill pipe when the discharge rate is selected using kill fluid, in MPa.

[0048] When the kill fluid exits the drill bit, the casing pressure needs to be adjusted so that the downward flow of the kill fluid can push the formation fluid back into the formation. At this time, the riser pressure is P. t2 =P t1 +ΔP c In the formula, P t2 ΔP represents the standpipe pressure when the kill fluid exits the drill bit, in MPa. c This represents the pressure increase required to force back formation fluids, in MPa.

[0049] During the formation fluid pressure-back process, the well conditions continuously change. It is necessary to promptly obtain new casing pressure and kill fluid discharge parameters based on the current conditions and the flow diversion calculation in step S3. The specific calculation method is as follows:

[0050] Based on the amount of kill fluid injected into the well in the previous time period, the stand pressure, and the casing pressure, the current stand pressure P′ is calculated using step S2. t2 Pressure P′ at the drill bit bit Design a new additional bushing pressure ΔP′ c Similarly, calculate the well state parameters during the formation fluid pressure-back process and design new well control parameters. The shorter the time interval, the more accurate the well control calculation.

[0051] When all formation fluid is forced back into the formation, the seepage resistance of the kill fluid entering the formation is relatively high, and the riser pressure will rise rapidly. At this point, based on the riser pressure change point, it is determined that all formation fluid has been forced back. Therefore, the casing pressure is adjusted to allow all kill fluid to circulate upwards. The total riser pressure at this time is P″. t2 Additional sleeve pressure is ΔP″ c The pressure at the drill bit is P″ bit ;

[0052] After all the formation fluids are forced back into the formation, maintain the pressure P″ at the drill bit. bit Without changing the additional casing pressure, all the kill fluid is circulated upwards to discharge the contaminated drilling fluid until all the contaminated drilling fluid returns to the wellhead. The total riser pressure at the start of the flushing operation is P. t3 =P″ t2 -ΔP″ c .

[0053] Furthermore, during the circulating sewage discharge process, the well conditions continue to change. The casing pressure is continuously updated according to the method for pressurizing back the formation fluid in step S4, maintaining the drill bit pressure P″ during circulation. bit Unchanged; well control ends when all contaminated drilling fluid is discharged.

[0054] Compared with the prior art, the beneficial technical effects of the present invention are as follows:

[0055] 1. The rapid well control method of the present invention is used for well control operations when the drill bit is not at the bottom of the well, improving the safety and speed of well control under such conditions, and providing a reference for further research on well control technology.

[0056] 2. In step S2 of the present invention, the initial state of well control is calculated as the initial value for the start of well control. At the same time, the initial state calculation method can also be used to calculate the wellbore pressure during the well control process, and to calculate the wellbore pressure at each moment of well control.

[0057] 3. Regarding the well control process well control fluid diversion calculation in step S3 of the present invention, there is little research and application of well control calculation in diversion calculation. This step is the key technical point of the present invention. By controlling the pressure, the well control fluid is diverted, so that the contaminated well control fluid is removed at the same time as well control.

[0058] 4. The well control process design in step S4 of this invention is based on the well pressure change law caused by the well control fluid diversion in step S3. The well control progress is judged by the pressure change during the well control process. Attached Figure Description

[0059] Figure 1 This is a flowchart of the rapid well-killing method of the present invention where the drill bit is not at the bottom of the well;

[0060] Figure 2 This is a schematic diagram of wellbore overflow.

[0061] Figure 3 This is the algorithm iteration diagram for the initial state of well control. Detailed Implementation

[0062] To make the objectives, technical solutions, and advantages of this invention clearer, the technical solutions of this invention are described clearly and completely below. Obviously, the described embodiments are only some embodiments of this invention, not all embodiments. Based on the embodiments of this invention, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of this invention.

[0063] Example 1

[0064] As a preferred embodiment of the present invention, please refer to the appendix to the specification. Figure 1 As shown in the figure, this embodiment discloses a rapid well control method when the drill bit is not at the bottom of the well. The method includes the following steps:

[0065] S1. Basic data acquisition steps: Collect overflow reservoir parameters, overflow fluid properties, shut-in stand-up pressure and casing pressure, well structure, drill string assembly, drilling fluid and kill fluid rheological parameters through geological logging data and adjacent well data.

[0066] S2, Initial state calculation steps for well control: Based on the basic data collected in step S1, calculate the relevant parameters of the miscible section and the initial wellbore pressure distribution;

[0067] S3, Calculation steps for well control fluid diversion during well control process: Based on the initial state of well control obtained in step S2, design a suitable well control fluid density and adjust the casing pressure to divert the well control fluid at the drill bit. Part of the fluid is discharged upwards to the annulus where the contaminated drilling fluid is discharged, and part of the fluid is pushed downwards to push the overflow material below the drill bit into the formation.

[0068] S4. Well control process design steps: Design well control parameters based on the well state, and judge the well control process based on the standpipe pressure and casing pressure. When all the formation fluid is pushed back to the formation, adjust the casing pressure to make the well control fluid circulate upward at the drill bit.

[0069] S5. Circulate and discharge the contaminated drilling fluid. All the kill fluid is discharged upwards through circulation, and the kill operation ends.

[0070] Example 2

[0071] As another preferred embodiment of the present invention, this embodiment further elaborates and supplements the technical solution of the present invention based on the above-described embodiment 1. In this embodiment, in step S1, the overflow reservoir parameters include formation porosity, permeability, formation pore pressure, and formation fracture pressure. The overflow fluid properties include fluid density and fluid viscosity.

[0072] In step S2, the relevant parameters of the miscible section include the miscible section pressure, which is calculated by inverting the wellbore pressure calculation formula. This is done using known shut-in parameters, including shut-in casing pressure, shut-in standpipe pressure, and mud pit increment. Differential iterative calculations are then performed on the miscible section to invert the wellbore pressure distribution.

[0073] A further preferred formula for calculating wellbore pressure is as follows:

[0074]

[0075] When the well depth is at the bottom of the well (i.e., H = H), b When the pressure is calculated, it is the bottom hole pressure (P = P). b From this, we can obtain the following formula for calculating C:

[0076]

[0077] In the formula, P is the pressure at well depth H, in Pa; b Z is the bottom hole pressure, in Pa; C is the indefinite integral constant term, dimensionless; H T is the gas compressibility coefficient at well depth H, dimensionless; H Temperature at well depth H, in Kelvin; n H R is the number of moles of control gas at well depth H, in mol; R is the ideal gas constant, in Pa·m. 3 / mol·K; M is the relative molecular weight of the gas, in kg / mol; ρ l Density of drilling fluid, unit: g / cm³ 3 .

[0078] Furthermore, the fluid temperature T at well depth H H The calculation formula is T H =T0+T a H; where T0 represents the ground temperature, in K; T a This represents the geothermal gradient, in Kelvin (K).

[0079] The compressibility coefficient Z at well depth H H The calculation formula is

[0080]

[0081] In the formula, A1=0.3265; A2=1.0700; A3=-0.5339; A4=0.01569; A5=-0.05165; A6=0.5475; A7=-0.7361; A8=0.1844; A9=0.1056; A 10 =0.6134; A 11 =0.7210; ρ pr For the gas pseudo-contrast density; ρ pr For the gas-paired relative temperature; ρ pr =0.27p pr / (ZT pr In the formula, p pr Indicates the relative pressure of the gas;

[0082] The formula for calculating the total number of gas moles in the miscible section of the overflow is as follows:

[0083]

[0084] in,

[0085] In the formula, V g0 This represents the initial total overflow, in meters (m). 3 M represents the relative molecular weight of the gas, in kg / mol; H sH represents the depth measured at the upper end of the mixed-phase section of the overflow, in meters. b Depth measurement at the lower end of the overflow miscible section, unit: m; P s P b Well depth H s H b Pressure, unit MPa; Z s Z b Well depth H s H b The gas compressibility coefficient is dimensionless; T s T b Well depth H s H b Temperature, in Kelvin (K).

[0086] The inversion method in step S2 is as follows: First, the length of the miscible section is set by the overflow volume, and the total number of gas moles in the overflow section is calculated. The miscible section is then divided into infinitesimal elements, and iterative calculations are performed from the bottom to the top of the miscible section. Finally, the calculated pressure at the top of the miscible section is compared with the sum of the shut-in casing pressure and the drilling fluid column pressure above the miscible section. If they are not equal, the length of the miscible section is adjusted and the calculation is repeated. If they are equal, the length of the miscible section is determined, and then the relevant parameters of the miscible section are determined. These parameters include gas volume, gas holdup, and miscible section pressure.

[0087] Example 3

[0088] As another preferred embodiment of the present invention, this embodiment further supplements and elaborates on the technical solution of the present invention based on the above-described embodiment 1 or embodiment 2. In this embodiment, in step S3, designing a suitable kill fluid density specifically refers to obtaining the equivalent drilling fluid density ρ2 at the drill bit based on the wellbore pressure calculated in step S2 and the shut-in pressure. This value is the upper limit of the kill fluid density design. The kill fluid density corresponding to the maximum pressure borne by the formation and wellbore is ρ1; the original drilling fluid density is ρ0. By adjusting the casing pressure, the kill fluid is diverted at the drill bit. Part of the fluid circulates upward to discharge the contaminated drilling fluid, and part of the fluid is pushed downward back to the formation fluid, thereby increasing the length of the fluid column below the drill bit and achieving the purpose of balancing the formation pressure.

[0089] Furthermore, when designing a suitable kill fluid density, the initial kill fluid density ρ m Satisfying ρ0<ρ m <ρ1<ρ2; where ρ0 is the original drilling fluid density, in kg / m³ 3 ρ1 is the density at the boundary between the formation and the wellbore, in kg / m³. 3 ρ2 is the drilling fluid density at the shut-in bit, in kg / m³. 3 ;ρ mInitial kill fluid density, unit kg / m³ 3 .

[0090] Under otherwise constant conditions, the functional relationship between kill fluid discharge rate and riser pressure is expressed as P t (Q); Adjustment is achieved by changing the sleeve pressure value; specifically,

[0091] Assume the kill fluid displacement is Q, the upward circulation displacement at the drill bit is Q1, and the downward circulation displacement is Q2;

[0092] The pressure P at the drill bit can be calculated based on the initial state obtained in step S2. bit The hydraulic column pressure P below the drill bit b ; Calculate the flow friction P below the drill bit using the Fanning-Darcy formula bf The Fanning friction coefficient f b It is a function of the fluid Reynolds number and the pipe wall roughness; the lower limits of the values ​​of Q1 and Q2 are calculated by combining the reservoir seepage resistance.

[0093] As an example of this embodiment, the calculation formulas for Q1 and Q2 are as follows:

[0094]

[0095] in,

[0096] In the formula, Q represents the kill fluid displacement, in m³. 3 / d; Q1 represents the upward flow rate of kill fluid at the drill bit, in meters. 3 / d; Q2 represents the flow rate of kill fluid flowing downwards at the drill bit, in meters. 3 / d;P bit ΔP represents the initial pressure at the drill bit, in MPa. c P represents the additional wellhead casing pressure, in MPa. b P represents the pressure of the fluid column below the drill bit, in MPa. bf P represents the frictional resistance below the drill bit, measured in MPa. s P represents reservoir seepage resistance, in MPa. p This represents formation pressure, measured in MPa. This represents the formation fluid flow coefficient, in μm. 2 μ i The fluid viscosity is expressed in mPa·s; r e The outer radius of the well control is represented in meters (m); r w The wellbore radius is expressed in meters (m); h r f represents reservoir thickness in meters (m). b ρ represents the Fanning friction coefficient of the fluid, which is dimensionless; bThis indicates the fluid density below the drill bit, in kg / m³. 3 ; v represents the fluid velocity below the drill bit, in m / s; D w D indicates the inner diameter of the casing, in mm. z Indicates the outer diameter of the drill pipe, in mm; L b This indicates the distance from the drill bit to the bottom of the well, in meters (m).

[0097] The Fanning friction coefficient is obtained by determining the flow state using the Reynolds number, which is calculated as follows:

[0098]

[0099] When the flow state is laminar,

[0100] When the flow state is turbulent,

[0101] In the formula, Re b ε represents the fluid Reynolds number, which is dimensionless; ε represents the absolute roughness of the pipe wall, in mm.

[0102] Furthermore, when designing the kill fluid discharge rate, the on-site equipment load and boundary pressures must also be considered. These boundary pressures include formation fracturing pressure, casing shoe fracturing pressure, or casing internal pressure resistance. The maximum kill fluid discharge rate is calculated as follows: Q < min(Q3, Q4, Q5, Q6); where Q3 represents the maximum allowable kill fluid discharge rate at the wellhead, in meters. 3 / s; Q4 represents the maximum allowable kill fluid discharge rate under formation fracture pressure, in m³ / s. 3 / s; Q5 represents the maximum allowable kill fluid discharge rate at the casing shoe fracture pressure, in meters. 3 / s; Q6 represents the maximum allowable kill fluid discharge rate under internal pressure resistance of the casing, in meters. 3 / s.

[0103] Example 4

[0104] As another preferred embodiment of the present invention, this embodiment further supplements and elaborates on the technical solution of the present invention based on the above-described embodiments 1, 2, or 3. In this embodiment, the well control process design in step S4 specifically refers to...

[0105] Initially, the well is shut in, with no circulating friction. As the kill fluid travels from the wellhead through the drill pipe to the drill bit, the standpipe pressure and casing pressure gradually decrease due to the increased pressure of the fluid column inside the drill pipe. When the kill fluid reaches the drill bit, the standpipe pressure is P. t1 =P t0 +P tf In the formula, P t1P represents the standpipe pressure when the kill fluid reaches the drill bit, in MPa. t0 P represents the initial riser pressure, in MPa. tf This indicates the circulating friction within the drill pipe when the discharge rate is selected using kill fluid, in MPa.

[0106] When the kill fluid exits the drill bit, the casing pressure needs to be adjusted so that the downward flow of the kill fluid can push the formation fluid back into the formation. At this time, the riser pressure is P. t2 =P t1 +ΔP c In the formula, P t2 ΔP represents the standpipe pressure when the kill fluid exits the drill bit, in MPa. c This represents the pressure increase required to force back formation fluids, in MPa.

[0107] During the formation fluid pressure-back process, the well conditions continuously change. It is necessary to promptly obtain new casing pressure and kill fluid discharge parameters based on the current conditions and the flow diversion calculation in step S3. The specific calculation method is as follows:

[0108] Based on the amount of kill fluid injected into the well in the previous time period, the stand pressure, and the casing pressure, the current stand pressure P′ is calculated using step S2. t2 Pressure P′ at the drill bit bit Design a new additional bushing pressure ΔP′ c Similarly, calculate the well state parameters during the formation fluid pressure-back process and design new well control parameters. The shorter the time interval, the more accurate the well control calculation.

[0109] When all formation fluid is forced back into the formation, the seepage resistance of the kill fluid entering the formation is relatively high, and the riser pressure will rise rapidly. At this point, based on the riser pressure change point, it is determined that all formation fluid has been forced back. Therefore, the casing pressure is adjusted to allow all kill fluid to circulate upwards. The total riser pressure at this time is P″. t2 Additional sleeve pressure is ΔP″ c The pressure at the drill bit is P″ bit ;

[0110] After all the formation fluids are forced back into the formation, maintain the pressure P″ at the drill bit. bit Without changing the additional casing pressure, all the kill fluid is circulated upwards to discharge the contaminated drilling fluid until all the contaminated drilling fluid returns to the wellhead. The total riser pressure at the start of the flushing operation is P. t3 =P″ t2 -ΔP″ c .

[0111] During the circulation and descaling process, the well conditions continue to change. Calculations are performed according to the method for pressurizing back the formation fluid in step S4, and the casing pressure is continuously updated to maintain the drill bit pressure P″ during circulation. bitUnchanged; well control ends when all contaminated drilling fluid is discharged.

[0112] Example 5

[0113] As another preferred embodiment of the present invention, please refer to the appendix to the specification. Figure 1 As shown in the figure, this embodiment discloses a rapid well control method when the drill bit is not at the bottom of the well, including the following steps.

[0114] S1, Basic Data Collection

[0115] Basic data acquisition involves collecting overflow reservoir parameters (formation porosity, permeability, formation pore pressure, formation fracture pressure), overflow fluid properties (density, viscosity, etc.), shut-in stand-up pressure, casing pressure, wellbore structure, drill string assembly, and rheological parameters of drilling fluid and kill fluid through geological logging data and adjacent well data.

[0116] S2, Calculation of Initial State for Well Control

[0117] Calculate relevant parameters for the miscible section, including the initial wellbore fluid distribution and initial wellbore pressure distribution. The pressure calculation method for the miscible section involves inverting the wellbore pressure calculation formula using known shut-in parameters, including shut-in casing pressure, shut-in standpipe pressure, and mud pit increment. Differential iterative calculations are then performed on the miscible section to invert the wellbore pressure distribution. The wellbore pressure calculation formula is as follows:

[0118]

[0119] When the well depth is at the bottom of the well (i.e., H = H), b When the pressure is calculated, it is the bottom hole pressure (P = P). b From this, we can obtain the following formula for calculating C:

[0120]

[0121] P is the pressure at well depth H, in Pa; b Z is the bottom hole pressure, in Pa; C is the indefinite integral constant term, dimensionless; H T is the gas compressibility coefficient at well depth H, dimensionless; H Temperature at well depth H, in Kelvin; n H R is the number of moles of control gas at well depth H, in mol; R is the ideal gas constant, in Pa·m. 3 / mol·K; M is the relative molecular weight of the gas, in kg / mol; ρ l Density of drilling fluid, unit: g / cm³ 3 .

[0122] The above equation has five unknowns: P, H, n H T H ZH Therefore, the following three auxiliary equations are needed to solve the mathematical model:

[0123] 1) Fluid temperature T at well depth H H The calculation formula is T H =T0+T a H(2); where T0 represents the ground temperature in K; T a This represents the geothermal gradient, in Kelvin (K).

[0124] 2) Compression coefficient Z at well depth H H The calculation formula is

[0125]

[0126] In the formula, A1=0.3265; A2=1.0700; A3=-0.5339; A4=0.01569; A5=-0.05165; A6=0.5475; A7=-0.7361; A8=0.1844; A9=0.1056; A 10 =0.6134; A 11 =0.7210; ρ pr T represents the pseudo-contrast density of the gas. pr p represents the gas's relative temperature; pr For the gas relative pressure; ρ pr =0.27p pr / (ZT pr (4);

[0127] 3) The formula for calculating the total number of gas moles in the miscible section of the overflow is as follows:

[0128]

[0129] in,

[0130] In the formula, V g0 This represents the initial total overflow, in meters (m). 3 M represents the relative molecular weight of the gas, in kg / mol; H s H represents the depth measured at the upper end of the mixed-phase section of the overflow, in meters. b Depth measurement at the lower end of the overflow miscible section, unit: m; P s P b Well depth H s H b Pressure, unit MPa; Z s Z b Well depth H s H b The gas compressibility coefficient is dimensionless; T sT b Well depth H s H b Temperature, in Kelvin (K).

[0131] The inversion method using equations (1)-(6) above is as follows: First, the length of the miscible section is set by the overflow flow rate, and the total number of gas moles in the overflow section is calculated. The miscible section is divided into infinitesimal elements, and iterative calculations are performed from the bottom to the top of the miscible section. Finally, the pressure at the top of the overflow miscible section obtained by the solution is compared with the sum of the shut-in casing pressure and the drilling hydrostatic pressure at the top of the miscible section. If they are not equal, the length of the overflow miscible section is adjusted and the calculation is repeated; if they are equal, the length of the miscible section is determined, and then the relevant parameters of the miscible section can be determined, including the gas volume, gas holdup, and pressure of the miscible section.

[0132] S3, Calculation of well control fluid diversion during well control process

[0133] 1) Design a suitable kill fluid density based on the initial state.

[0134] The drilling fluid density ρ2 at the drill bit is calculated by shutting in the well and establishing pressure. This value is typically high and may exceed the formation and wellbore pressure boundary ρ1. The original drilling fluid density is ρ0. By adjusting the casing pressure, the kill fluid is diverted at the drill bit. Part of it circulates upwards to expel contaminated drilling fluid, while the other part is pushed downwards back into the formation fluid, thereby increasing the fluid column length and achieving formation pressure balance. The initial kill fluid density ρ m The following is confirmed:

[0135] ρ0<ρ m <ρ1<ρ2(7); where ρ0 is the original drilling fluid density, in kg / m³ 3 ρ1 is the density at the boundary between the formation and the wellbore, in kg / m³. 3 ρ2 is the drilling fluid density at the shut-in bit, in kg / m³. 3 ;ρ m Initial kill fluid density, unit kg / m³ 3 .

[0136] 2) Adjust the casing pressure to divert the kill fluid at the drill bit.

[0137] When the kill fluid reaches the drill bit position through the drill string, the casing pressure is adjusted to increase so that a portion of the kill fluid is forced back down to the formation fluid at the drill bit, while the other portion circulates upward to discharge the contaminated drilling fluid. The flow rate of the kill fluid is the result of multiple factors.

[0138] Under otherwise constant conditions, the kill fluid discharge rate is a function of the riser pressure P. t(Q) can be adjusted by changing the casing pressure. Assume the kill fluid displacement is Q, the upward circulation displacement at the drill bit is Q1, and the downward circulation displacement is Q2. Step S2, the initial state calculation, yields the drill bit pressure P. bit The pressure P of the hydraulic column below the drill bit b The flow friction P below the drill bit is calculated using the Fanning-Darcy formula. bf The Fanning friction coefficient f b It is a function of the fluid Reynolds number and the pipe wall roughness. The lower limits of Q1 and Q2 are calculated by combining them with the reservoir seepage resistance. The calculation formulas are as follows:

[0139]

[0140] in,

[0141] In the formula, Q represents the kill fluid displacement, in m³. 3 / d; Q1 represents the upward flow rate of kill fluid at the drill bit, in meters. 3 / d; Q2 represents the flow rate of kill fluid flowing downwards at the drill bit, in meters. 3 / d;P bit ΔP represents the initial pressure at the drill bit, in MPa. c P represents the additional wellhead casing pressure, in MPa. b P represents the pressure of the fluid column below the drill bit, in MPa. bf P represents the frictional resistance below the drill bit, measured in MPa. s P represents reservoir seepage resistance, in MPa. p This represents formation pressure, measured in MPa. This represents the formation fluid flow coefficient, in μm. 2 μ i The fluid viscosity is expressed in mPa·s; r e The outer radius of the well control is represented in meters (m); r w The wellbore radius is expressed in meters (m); h r f represents reservoir thickness in meters (m). b ρ represents the Fanning friction coefficient of the fluid, which is dimensionless; b This indicates the fluid density below the drill bit, in kg / m³. 3 ; v represents the fluid velocity below the drill bit, in m / s; D w D indicates the inner diameter of the casing, in mm. z Indicates the outer diameter of the drill pipe, in mm; L b This indicates the distance from the drill bit to the bottom of the well, in meters (m).

[0142] The Fanning friction coefficient is obtained by determining the flow state using the Reynolds number. The Reynolds number is calculated as follows:

[0143]

[0144] When the flow state is laminar,

[0145] When the flow state is turbulent,

[0146] In the formula, Re b ε represents the fluid Reynolds number, which is dimensionless; ε represents the absolute roughness of the pipe wall, in mm.

[0147] When designing the kill fluid discharge rate, the on-site equipment load and boundary pressures must also be considered. These boundary pressures include formation fracturing pressure, casing shoe fracturing pressure, or casing internal pressure resistance. The maximum kill fluid discharge rate is calculated as follows: Q < min(Q3, Q4, Q5, Q6) (13); where Q3 represents the maximum allowable kill fluid discharge rate at the wellhead, in meters. 3 / s; Q4 represents the maximum allowable kill fluid discharge rate under formation fracture pressure, in m³ / s. 3 / s; Q5 represents the maximum allowable kill fluid discharge rate at the casing shoe fracture pressure, in meters. 3 / s; Q6 represents the maximum allowable kill fluid discharge rate under internal pressure resistance of the casing, in meters. 3 / s.

[0148] S4, Well Control Process Design

[0149] 1) Initially, the well is shut in, with no circulating friction. As the kill fluid travels from the wellhead through the drill pipe to the drill bit, the standpipe pressure and casing pressure gradually decrease due to the increased pressure of the fluid column within the drill pipe. When the kill fluid reaches the drill bit, the standpipe pressure is P. t1 =P t0 +P tf (14); where P t1 P represents the standpipe pressure when the kill fluid reaches the drill bit, in MPa. t0 P represents the initial riser pressure, in MPa. tf This indicates the circulating friction within the drill pipe when the discharge rate is selected using kill fluid, in MPa.

[0150] 2) When the kill fluid exits the drill bit, the casing pressure needs to be adjusted so that the downward flow of the kill fluid can push the formation fluid back into the formation. At this time, the riser pressure is P. t2 =P t1 +ΔP c (15); where P t2 ΔP represents the standpipe pressure when the kill fluid exits the drill bit, in MPa. c This represents the pressure increase required to force back formation fluids, in MPa.

[0151] 3) During the formation fluid pressure-back process, the standpipe pressure and casing pressure gradually decrease due to the increased fluid column pressure below the drill bit. As the formation fluid is pressured back, the well conditions continuously change, requiring timely calculation of new parameters such as casing pressure and discharge rate based on the current conditions and the S3 flow split. The calculation method is as follows: based on the amount of kill fluid injected into the well in the previous time period, the standpipe pressure, and the casing pressure, calculate the current standpipe pressure P′ using step S2. t2 Pressure P′ at the drill bit bit Design a new additional bushing pressure ΔP′ c Similarly, calculate the well state parameters during the formation fluid pressure return process and design new well control parameters. The shorter the time interval, the more accurate the well control calculation.

[0152] When all formation fluid is forced back into the formation, the riser pressure will rise rapidly due to the high flow resistance of the kill fluid entering the formation. This pressure change point can be used to determine if all formation fluid has been forced back. Adjusting the casing pressure then allows all the kill fluid to circulate upwards; the total riser pressure at this point is P″. t2 Additional sleeve pressure is ΔP″ c The pressure at the drill bit is P″ bit .

[0153] 4) After all the formation fluids have been forced back into the formation, the pressure P″ at the drill bit must be maintained. bit Unchanged. The additional casing pressure is removed, allowing all the kill fluid to circulate upwards and discharge the contaminated drilling fluid until all the contaminated drilling fluid returns to the wellhead. The total riser pressure at the start of the flushing operation is P. t3 =P″ t2 -ΔP″ c (16).

[0154] S5. Circulate and discharge contaminated drilling fluid.

[0155] During the circulation and descaling process, the well conditions continue to change. Calculations can be performed using the method of pressurizing back formation fluid, continuously updating the casing pressure to maintain a constant pressure at the drill bit during circulation. Well control ends when all contaminated drilling fluid has been discharged.

[0156] The above description is not intended to limit the present invention in any way. Although the present invention has been disclosed through the above examples, it is not intended to limit the present invention. Any person skilled in the art can make changes or modifications to the above-disclosed technical content to create equivalent embodiments without departing from the technical scope of the present invention. Any simple modifications, equivalent changes and modifications made to the above embodiments based on the technical essence of the present invention without departing from the technical solution of the present invention shall still fall within the technical solution of the present invention.

Claims

1. A rapid well-killing method with the drill bit not at the bottom of the well, characterized in that: The method includes the following steps: S1. Basic data acquisition steps: Collect overflow reservoir parameters, overflow fluid properties, shut-in pressure, casing pressure, well structure, drill string assembly, drilling fluid and kill fluid rheological parameters through geological logging data and adjacent well data. S2, Initial state calculation steps for well control: Based on the basic data collected in step S1, calculate the relevant parameters of the miscible section and the initial wellbore pressure distribution; S3, Calculation steps for well control fluid diversion during well control process: Based on the initial state of well control obtained in step S2, design a suitable well control fluid density and adjust the casing pressure to divert the well control fluid at the drill bit. Part of the fluid is discharged upwards to the annulus where the contaminated drilling fluid is discharged, and part of the fluid is pushed downwards to push the overflow material below the drill bit into the formation. S4. Well control process design steps: Design well control parameters based on the well state, and judge the well control process based on the standpipe pressure and casing pressure. When all the formation fluid is pushed back to the formation, adjust the casing pressure to make the well control fluid circulate upward at the drill bit. S5. Circulate and discharge the contaminated drilling fluid. All the kill fluid is discharged upwards through circulation, and the kill operation ends.

2. The rapid well-killing method with the drill bit not at the bottom of the well as described in claim 1, characterized in that: In step S1, the overflow reservoir parameters include formation porosity, permeability, formation pore pressure, and formation fracture pressure.

3. A rapid well-killing method with the drill bit not at the bottom of the well as described in claim 1 or 2, characterized in that: In step S1, the fluid properties of the overflow layer include fluid density and fluid viscosity.

4. The rapid well-killing method with the drill bit not at the bottom of the well as described in claim 1, characterized in that: In step S2, the relevant parameters of the miscible section include the miscible section pressure, which is calculated by inverting the wellbore pressure calculation formula. The wellbore pressure distribution is inverted by performing differential iterative calculation on the miscible section based on the known shut-in parameters, including shut-in casing pressure, shut-in stand pressure, and mud pit increment.

5. The rapid well-killing method with the drill bit not at the bottom of the well as described in claim 4, characterized in that: The formula for calculating wellbore pressure is as follows: When the well depth is at the bottom of the well (i.e., H = H), b When the pressure is calculated, it is the bottom hole pressure (P = P). b From this, we can obtain the following formula for calculating C: In the formula, P is the pressure at well depth H, in Pa; b Bottom hole pressure, in Pa; C is the constant term of the indefinite integral, dimensionless; Z H T is the gas compressibility coefficient at well depth H, dimensionless; H Temperature at well depth H, in Kelvin; n H R is the number of moles of control gas at well depth H, in mol; R is the ideal gas constant, in Pa·m. 3 / mol·K; M is the relative molecular weight of the gas, in kg / mol; ρ l Density of drilling fluid, unit: g / cm³ 3 .

6. The rapid well-killing method when the drill bit is not at the bottom of the well as described in claim 5, characterized in that: Fluid temperature T at well depth H H The calculation formula is T H =T0+T a H; where T0 represents the ground temperature, in K; T a This represents the geothermal gradient, in Kelvin (K).

7. A rapid well-killing method when the drill bit is not at the bottom of the well, as described in claim 5, characterized in that: The compressibility coefficient Z at well depth H H The calculation formula is In the formula, A1=0.3265; A2=1.0700; A3=-0.5339; A4=0.01569; A5=-0.05165; A6=0.5475; A7=-0.7361; A8=0.1844; A9=0.1056; A 10 =0.6134; A 11 =0.7210; ρ pr T represents the pseudo-contrast density of the gas. pr p represents the gas's relative temperature; pr For the gas-specific pressure ρ pr =0.27p pr / (ZT pr In the formula, p pr The relative pressure is the pressure of the gas.

8. The rapid well-killing method when the drill bit is not at the bottom of the well as described in claim 5, characterized in that: The formula for calculating the total number of gas moles in the miscible section of the overflow is as follows: in, In the formula, V g0 This represents the initial total overflow, in meters (m). 3 M represents the relative molecular weight of the gas, in kg / mol; H s H represents the depth measured at the upper end of the mixed-phase section of the overflow, in meters. b Depth measurement at the lower end of the overflow miscible section, unit: m; P s P b Well depth H s H b Pressure, unit MPa; Z s Z b Well depth H s H b The gas compressibility coefficient is dimensionless; T s T b Well depth H s H b Temperature, in Kelvin (K).

9. A rapid well-killing method with the drill bit not at the bottom of the well as described in any one of claims 1, 2, or 4-8, characterized in that: The inversion method in step S2 is as follows: First, the length of the miscible section is set by the overflow flow rate, and the total number of gas moles in the overflow section is calculated. The miscible section is divided into infinitesimal elements, and iterative calculations are performed from the bottom to the top of the miscible section. Finally, the pressure at the top of the miscible section obtained by the solution is compared with the sum of the shut-in casing pressure and the drilling fluid column pressure above the miscible section. If they are not equal, the length of the miscible section is adjusted and the calculation is repeated. If they are equal, the length of the miscible section is determined, and then the relevant parameters of the miscible section are determined.

10. A rapid well-killing method with the drill bit not at the bottom of the well as described in any one of claims 1, 2, or 4-8, characterized in that: The parameters related to the mixed phase section include gas volume, gas holdup, and mixed phase section pressure.

11. The rapid well-killing method with the drill bit not at the bottom of the well as described in claim 1, characterized in that: In step S3, a suitable kill fluid density is designed. Specifically, based on the wellbore pressure calculated in step S2 and combined with the shut-in and stand-up pressure, the equivalent drilling fluid density ρ2 at the drill bit is obtained. This value is the upper limit of the kill fluid density design. The kill fluid density corresponding to the maximum pressure that the formation and wellbore can withstand is ρ1; the original drilling fluid density is ρ0. By adjusting the casing pressure, the kill fluid is diverted at the drill bit. Part of the fluid circulates upward to discharge the contaminated drilling fluid, and part of the fluid is pushed downward back to the formation fluid, thereby increasing the length of the fluid column below the drill bit and achieving the purpose of balancing the formation pressure.

12. The rapid well-killing method with the drill bit not at the bottom of the well as described in claim 11, characterized in that: In step S3, when designing a suitable kill fluid density, the initial kill fluid density ρ... m Satisfying ρ0<ρ m <ρ1<ρ2; where ρ0 is the original drilling fluid density, in kg / m³. 3 ; ρ1 is the density of the kill fluid corresponding to the maximum pressure that the formation and wellbore can withstand, in kg / m³. 3 ; ρ2 is the drilling fluid density at the shut-in bit, in kg / m³. 3 ; ρ m Initial kill fluid density, unit kg / m³ 3 .

13. A rapid well-killing method with the drill bit not at the bottom of the well as described in claim 12, characterized in that: Under otherwise constant conditions, the functional relationship between kill fluid discharge rate and riser pressure is expressed as P t (Q); Adjustment is achieved by changing the sleeve pressure value; specifically, Assume the kill fluid displacement is Q, the upward circulation displacement at the drill bit is Q1, and the downward circulation displacement is Q2; The pressure P at the drill bit can be calculated based on the initial state obtained in step S2. bit The hydraulic column pressure P below the drill bit b ; Calculate the flow friction P below the drill bit using the Fanning-Darcy formula bf The Fanning friction coefficient f b It is a function of the fluid Reynolds number and the pipe wall roughness; the lower limits of the values ​​of Q1 and Q2 are calculated by combining the reservoir seepage resistance.

14. The rapid well-killing method with the drill bit not at the bottom of the well as described in claim 13, characterized in that: The formulas for calculating Q1 and Q2 are as follows: in, In the formula, Q represents the kill fluid displacement, in m³. 3 / d; Q1 represents the upward flow rate of kill fluid at the drill bit, in meters. 3 / d; Q2 represents the flow rate of kill fluid flowing downwards at the drill bit, in meters. 3 / d;P bit ΔP represents the initial pressure at the drill bit, in MPa. c P represents the additional wellhead casing pressure, in MPa. b P represents the pressure of the fluid column below the drill bit, in MPa. bf P represents the frictional resistance below the drill bit, measured in MPa. s P represents reservoir seepage resistance, in MPa. p This represents formation pressure, measured in MPa. This represents the formation fluid flow coefficient, in μm. 2 μ i The fluid viscosity is expressed in mPa·s; r e The outer radius of the well control is represented in meters (m); r w The wellbore radius is expressed in meters (m); h r f represents reservoir thickness in meters (m). b ρ represents the Fanning friction coefficient of the fluid, which is dimensionless; b This indicates the fluid density below the drill bit, in kg / m³. 3 ; v represents the fluid velocity below the drill bit, in m / s; D w D indicates the inner diameter of the casing, in mm. z Indicates the outer diameter of the drill pipe, in mm; L b This indicates the distance from the drill bit to the bottom of the well, in meters (m).

15. A rapid well-killing method with the drill bit not at the bottom of the well as described in claim 14, characterized in that: The Fanning friction coefficient is obtained by determining the flow state using the Reynolds number, which is calculated as follows: When the flow state is laminar, When the flow state is turbulent, In the formula, Re b ε represents the fluid Reynolds number, which is dimensionless; ε represents the absolute roughness of the pipe wall, in mm.

16. A rapid well-killing method with the drill bit not at the bottom of the well as described in claim 1 or any one of 11-15, characterized in that: In step S3, when designing the displacement of the kill fluid, the on-site equipment load and the boundary pressure need to be considered. The boundary pressure includes the formation fracture pressure, the fracture pressure at the casing shoe or the internal pressure resistance of the casing. The design calculation of the maximum displacement of the kill fluid is as follows: Q < min(Q3, Q4, Q5, Q6); where Q3 represents the maximum displacement of the kill fluid allowed by the wellhead device, in m 3 / s; Q4 represents the maximum displacement of the kill fluid allowed by the formation fracture pressure, in m 3 / s; Q5 represents the maximum displacement of the kill fluid allowed by the fracture pressure at the casing shoe, in m 3 / s; Q6 represents the maximum displacement of the kill fluid allowed by the internal pressure resistance of the casing, in m 3 / s.

17. A rapid well-killing method with the drill bit not at the bottom of the well as described in any one of claims 1, 2, 4-8, or 11-15, characterized in that: In step S4, the well control process design specifically refers to... Initially, the well is shut in, with no circulating friction. As the kill fluid travels from the wellhead through the drill pipe to the drill bit, the standpipe pressure and casing pressure gradually decrease due to the increased pressure of the fluid column inside the drill pipe. When the kill fluid reaches the drill bit, the standpipe pressure is P. t1 =P t0 +P tf In the formula, P t1 P represents the standpipe pressure when the kill fluid reaches the drill bit, in MPa. t0 P represents the initial riser pressure, in MPa. tf This indicates the circulating friction within the drill pipe when the discharge rate is selected using kill fluid, in MPa. When the kill fluid exits the drill bit, the casing pressure needs to be adjusted so that the downward flow of the kill fluid can push the formation fluid back into the formation. At this time, the riser pressure is P. t2 =P t1 +ΔP c In the formula, P t2 ΔP represents the standpipe pressure when the kill fluid exits the drill bit, in MPa. c This represents the pressure increase required to force back formation fluids, in MPa. During the formation fluid pressure-back process, the well conditions continuously change. It is necessary to promptly obtain new casing pressure and kill fluid discharge parameters based on the current conditions and the flow diversion calculation in step S3. The specific calculation method is as follows: Based on the amount of kill fluid injected into the well in the previous time period, the stand pressure, and the casing pressure, the current stand pressure P′ is calculated using step S2. t2 Pressure P′ at the drill bit bit Design a new additional bushing pressure ΔP′ c Similarly, calculate the well state parameters during the formation fluid pressure-back process and design new well control parameters. The shorter the time interval, the more accurate the well control calculation. When all formation fluid is forced back into the formation, the seepage resistance of the kill fluid entering the formation is relatively high, and the riser pressure will rise rapidly. At this point, based on the riser pressure change point, it is determined that all formation fluid has been forced back. Therefore, the casing pressure is adjusted to allow all kill fluid to circulate upwards. The total riser pressure at this time is P″. t2 Additional sleeve pressure is ΔP″ c The pressure at the drill bit is P″ bit ; After all the formation fluids are forced back into the formation, maintain the pressure P″ at the drill bit. bit Without changing the additional casing pressure, all the kill fluid is circulated upwards to discharge the contaminated drilling fluid until all the contaminated drilling fluid returns to the wellhead. The total riser pressure at the start of the flushing operation is P. t3 =P″ t2 -ΔP″ c .

18. A rapid well-killing method with the drill bit not at the bottom of the well as described in claim 17, characterized in that: During the circulation and descaling process, the well conditions continue to change. Calculations are performed according to the method for pressurizing back the formation fluid in step S4, and the casing pressure is continuously updated to maintain the drill bit pressure P″ during circulation. bit Unchanged; well control ends when all contaminated drilling fluid is discharged.

Images