A method for constant pressure of leakage layer position of overflow and leakage coexistence in ultra-deep well

Abstract

This invention relates to a method for controlling wells with constant pressure at the location of the leaking zone in ultra-deep wells when both overflow and leakage occur, belonging to the field of well control technology for oil drilling. The method disclosed in this invention includes: obtaining the wellbore fluid state before well control based on drilling data at the time of overflow, overflow formation parameters, and a transient multiphase flow model of the wellbore-formation coupling; determining the constant annular pressure value at the location of the leaking zone based on data from the current well or adjacent wells; determining the final well control fluid density based on a static fluid column pressure calculation model of the annular fluid column at the location of the leaking zone; and finding the well control fluid density and displacement that can achieve dynamic pressure stabilization of the formation through well control simulation analysis based on the constant annular pressure value at the location of the leaking zone and the wellbore fluid state before well control. The well control method for maintaining constant pressure at the location of the leaking zone proposed in this invention considers the wellbore / formation coupling problem and establishes a well control analysis model for maintaining constant pressure at the location of the leaking zone using a drift flow model, providing a new technical means for handling overflows in ultra-deep wells.

Description

Technical Field

[0001] This invention relates to a method for controlling wells with constant pressure at the location of the leaking layer when both overflow and leakage occur in ultra-deep wells, belonging to the field of well control technology for oil drilling. Background Technology

[0002] As drilling progresses into deeper and ultra-deep formations, well control becomes increasingly challenging. These areas typically present problems such as multiple pressure systems in the open hole, narrow safety density windows, and difficulties in handling blowouts. Current well control designs primarily focus on maintaining constant bottomhole pressure to prevent secondary blowouts. However, this method lacks consideration for the risk of leakage in weak formations, and improper handling can easily lead to complex risks of both leakage and blowout. Therefore, to improve the success rate of blowout control in ultra-deep wells, a new method for well control design based on constant lost circulation zone pressure is proposed. Constant lost circulation zone pressure well control refers to maintaining a constant annular pressure at the location of the lost circulation zone, lower than the fracture / leakage pressure of that zone. The annulus can be divided into upper and lower parts by the lost circulation zone. As gas migrates upwards and expands, it replaces the drilling fluid. To maintain a constant annular pressure at the lost circulation zone, the wellhead choke pressure needs to be controlled according to the fluid and pressure evolution patterns in the annulus above the lost circulation zone. In the initial stage of well control, gas may still be present at the bottom of the well. As the kill fluid replaces the contaminated drilling fluid in the annulus below the leaking formation, the bottom pressure gradually recovers to the equilibrium formation pressure. Finally, without compromising the weak formation, the overflow material is safely discharged from the wellbore.

[0003] In multiphase flow simulation of oil and gas wells, drift flow models are commonly used for transient multiphase flow simulations coupled to the wellbore and formation due to their continuous differentiability and fast computation speed. For example, drift flow relationships based on flow pattern discrimination classify gas-liquid two-phase flows in the wellbore into bubbly flow, slug flow, agitated flow, and annular flow according to the porosity from low to high. However, due to the discontinuity at the flow pattern transition, these models are not suitable for multiphase flow simulations of oil and gas wells. Therefore, some drift flow relationships independent of flow pattern discrimination have been gradually developed. These new relationships do not require flow pattern discrimination and are applicable to a wider range of pipe diameters, well inclination angles, phase flow rates, fluid properties, and porosities, and are widely used in transient multiphase flow simulations coupled to the wellbore and formation. Summary of the Invention

[0004] In order to overcome the defects in the existing technology, the present invention aims to provide a method for controlling wells with constant pressure at the location of the leakage layer when leakage and overflow coexist in ultra-deep wells.

[0005] The technical solution provided by this invention to solve the above-mentioned technical problems is: a method for controlling wells with constant pressure at the location of the leakage layer when both overflow and leakage occur in ultra-deep wells, comprising the following steps:

[0006] S1. Obtain drilling data and formation parameters at the time of the overflow;

[0007] S2. Based on the drilling data at the time of overflow, the overflow formation parameters, and the wellbore-formation coupled transient multiphase flow model, obtain the wellbore fluid state before well control;

[0008] S3. Determine the constant annular pressure value at the location of the leaking layer based on data from the current well or adjacent wells;

[0009] S4. Determine the final kill fluid density based on the annular hydrostatic column pressure calculation model at the location of the lost circulation zone.

[0010] S5. Based on the constant annular pressure value at the location of the leaking formation and the fluid state in the wellbore before well control, the well control fluid density and discharge rate that can achieve dynamic pressure stabilization of the formation are determined through well control simulation analysis.

[0011] A further technical solution is that the drilling data includes wellbore trajectory, wellbore structure, drill string assembly, wellbore temperature, drilling fluid properties, inlet displacement, and mechanical drilling rate.

[0012] A further technical solution is to include the overflow formation parameters as wellhead casing pressure, formation pressure, and gas invasion index.

[0013] A further technical solution is that the wellbore-formation coupled transient multiphase flow model includes:

[0014] Governing equations:

[0015]

[0016]

[0017]

[0018] f g +f l =1

[0019] In the formula: A is the cross-sectional area of ​​the annulus, m 2 ;f g f is the volume fraction of the gas phase; l ρ is the volume fraction of the liquid phase; g ρ is the density of the gas phase, kg / m³; l The density of the liquid phase is kg / m³. 3 ;ρ m The density of the gas-liquid mixture is kg / m³. 3 ;v l v is the actual velocity of the liquid phase, in m / s; g θ is the actual velocity of the gas phase, m / s; θ is the wellbore inclination angle, rad; x is the spatial step size, m; t is the time step size, s; P is the pressure, Pa; F m The frictional resistance of the gas-liquid mixture is expressed in Pa.

[0020] Drift flow relation:

[0021] v g =C0v m +v d

[0022]

[0023]

[0024]

[0025]

[0026] In the formula: C0 is the distribution coefficient; vd is the drift velocity, m / s; K(f g ) represents the critical Kutateladze number; vc represents the characteristic velocity, m / s; m(φ) represents the effect of the wellbore inclination angle on the drift velocity; v sgf The minimum gas phase velocity (m / s) to prevent liquid film backflow; A and B are profile parameters; F v γ is a velocity-sensitive parameter for gas-liquid two-phase flow; γ and β are limiting terms for profile parameters.

[0027]

[0028]

[0029]

[0030]

[0031]

[0032]

[0033] In the formula: σ gl ρ is the surface tension of the gas and liquid, N / m; g is the acceleration due to gravity, m / s². 2 ;K u C is the Kutateladze number; ku and C w N is the fitted number; B d is the number of bonds; c Let d be the outer diameter of the annulus, in meters (m); t m is the inner diameter of the annulus; m0, n1, and n2 are fitting parameters; φ is the well inclination angle, rad.

[0034] Boundary conditions:

[0035]

[0036] P h(t) = const <P loss

[0037] In the formula: P a (t) represents the wellhead casing pressure, MPa; Q g Let m be the gas intrusion rate. 3 / s; K is the air intrusion index, m 3 / (MPa·m·d); P p P represents reservoir pressure, in MPa; wf ρ is the bottom hole pressure in the annulus, MPa; h is the reservoir opening thickness, m; P loss The leakage pressure of the leaking layer is expressed in MPa.

[0038] A further technical solution is that the calculation formula in step S3 is:

[0039] P h =P loss -P s

[0040] In the formula: P h The constant annular pressure at the location of the leak is expressed in MPa; P loss P represents the leakage pressure of the leakage layer, in MPa. s This represents the safety margin for leakage protection, expressed in MPa.

[0041] A further technical solution is that the calculation model for the annular hydrostatic column pressure at the leakage layer location in step S4 includes:

[0042]

[0043]

[0044]

[0045]

[0046] P H =9.81×10 -6 ρ(P,T)H

[0047] In the formula: ρ(P,T) is the density of water-based drilling fluid at a certain temperature and pressure, kg / m³ 3 ;T r Reference temperature, °C; T is the downhole drilling fluid temperature, °C; P r The reference pressure is MPa; P is the pressure of the downhole drilling fluid, MPa; ρ i Density of water-based drilling fluid at reference temperature, kg / m³ 3 ;ρ wi The density of water at the reference temperature, in kg / m³ 3 ;ρw The density of water at a certain temperature and pressure in the well, in kg / m³ 3 ;ρ s f is the density of the solid phase material in the drilling fluid; vw P represents the water fraction of the drilling fluid. H H represents the hydrostatic pressure at the location of the lost circulation zone when the kill fluid density fills the wellbore, in MPa; H represents the vertical depth of the lost circulation zone, in meters.

[0048] A further technical solution is that, in step S5, with the wellbore pressure at the constant leakage zone location as the target, a well control simulation analysis is conducted using different discharge rates and different well control fluid densities to verify whether the bottom hole pressure meets the requirements for balancing formation pressure.

[0049] If the conditions are met, the design is successful. At this time, the kill fluid density is the intermediate kill fluid density. Using this kill fluid density and discharge rate can meet the requirements of dynamic pressure stabilization of the formation.

[0050] If the balance requirements are not met, the constant annular pressure, discharge rate, and kill fluid density at the location of the leaking layer need to be adjusted, and the analysis needs to be repeated until the requirements are met.

[0051] If the required design parameters cannot be found, it means that the well control method is not applicable.

[0052] The present invention has the following beneficial effects: The well control method with constant pressure in the lost circulation zone proposed in this invention takes into account the wellbore / formation coupling problem and establishes a well control analysis model with constant pressure in the lost circulation zone using a drift flow model, providing a new technical means for handling overflows in ultra-deep wells. Attached Figure Description

[0053] Figure 1 Schematic diagram of annular pressure kill at constant leakage zone location;

[0054] Figure 2 The distribution of fluid in the wellbore before well control;

[0055] Figure 3 The static pressure distribution when the annulus is filled with the final kill fluid;

[0056] Figure 4 The change of wellbore pressure over time under different displacements;

[0057] Figure 5 The wellbore pressure varies with time under different kill fluid densities. Detailed Implementation

[0058] The technical solution of the present invention will now be clearly and completely described with reference to the accompanying drawings. Obviously, the described embodiments are only some, not all, of the embodiments of the present invention. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of the present invention.

[0059] A method for controlling wells with constant pressure at the location of the leaking formation when both overflow and leakage occur in an ultra-deep well, as described in this invention, includes the following steps:

[0060] S1. Obtain drilling data and formation parameters at the time of the overflow;

[0061] Specifically, this includes wellbore trajectory, wellbore structure, drill string assembly, wellbore temperature, drilling fluid properties, inlet displacement, mechanical drilling rate, wellhead casing pressure, formation pressure, and gas invasion index, etc.

[0062] S2. Based on the drilling data at the time of the overflow, the overflow formation parameters, and the wellbore-formation coupled transient multiphase flow model, obtain the wellbore fluid state before well control, and provide the initial state of the wellbore fluid for subsequent well control simulation;

[0063] The wellbore-formation coupled transient multiphase flow model is as follows:

[0064] (1) Governing equations:

[0065]

[0066]

[0067]

[0068] f g +f l =1 (4)

[0069] In the formula: A is the cross-sectional area of ​​the annulus, m 2 ;f g f is the volume fraction of the gas phase; l ρ is the volume fraction of the liquid phase; g The density of the gas phase is kg / m³. 3 ;ρ l The density of the liquid phase is kg / m³. 3 ;ρ m The density of the gas-liquid mixture is kg / m³. 3 ;v l v is the actual velocity of the liquid phase, in m / s; g θ is the actual velocity of the gas phase, m / s; θ is the wellbore inclination angle, rad; x is the spatial step size, m; t is the time step size, s; P is the pressure, Pa; F m The frictional resistance of the gas-liquid mixture is expressed in Pa.

[0070] (2) Drift flow relationship:

[0071] v g =C0v m +v d (5)

[0072]

[0073]

[0074]

[0075]

[0076] In the formula: C0 is the distribution coefficient; vd is the drift velocity, m / s; K(f g ) represents the critical Kutateladze number; vc represents the characteristic velocity, in m / s; m(φ) characterizes the effect of the wellbore inclination angle on the drift velocity; v sgf Characterized by the minimum gas phase velocity required to prevent backflow of the liquid film, in m / s; A and B are profile parameters, initially set to 1.2 and 0.3, respectively; F v γ is a velocity-sensitive parameter for gas-liquid two-phase flow; γ and β are profile parameter constraints, note that γ should be between 0 and 1.

[0077]

[0078]

[0079]

[0080]

[0081]

[0082]

[0083] In the formula: σ gl ρ is the surface tension of the gas and liquid, N / m; g is the acceleration due to gravity, m / s². 2 ;K u C is the Kutateladze number; ku and C w The fitted numbers were initially set to 142 and 0.008, respectively; N B d is the number of bonds; c Let d be the outer diameter of the annulus, in meters (m); tφ is the annular inner diameter, in meters; for vertical wells, a1 and a2 are set to 0.2 and 0.4 respectively; for inclined wells, a1 and a2 are set to 0.06 and 0.21 respectively; m0, n1 and n2 are fitting parameters, set to 1.27, 0.24 and 1.08 respectively; φ is the well inclination angle, in rad.

[0084] (3) Boundary conditions:

[0085] During the overflow phase, the pressure at the wellhead should be equal to the back pressure applied at the wellhead at any given time, and the bottomhole gas flow rate should be equal to the formation gas production rate. During the kill phase, the boundary is defined by the annular pressure at the location of the lost circulation zone being constant and lower than the leakage pressure of the lost circulation zone.

[0086]

[0087] P h (t) = const <P loss (17)

[0088] In the formula: joutlet represents the wellhead grid node; P(t,j outlet P represents the pressure at a specific time point below the wellhead grid node; a (t) represents the wellhead casing pressure, MPa; Q g Let m be the gas intrusion rate. 3 / s; K is the gas invasion index (downhole conditions), m 3 / (MPa·m·d); P p P represents reservoir pressure, in MPa; wf ρ is the bottom pressure of the annulus well, MPa; h is the reservoir opening thickness, m.

[0089] (4) Solution method:

[0090] The gas-liquid mass conservation equations are solved using a grid differencing method. Spatially, a finite difference method is employed, while temporally an explicit approach is used, with an assumption-correction method. In the difference of variables, the properties of the uppermost nodes of the grid represent the entire grid, resulting in a passive term grid differencing scheme:

[0091]

[0092]

[0093] In the formula: j is the current computation space node.

[0094] By rearranging the difference equation of the mass conservation equation for the gas-liquid two-phase system, we obtain expressions for the miscibility velocity, gas-liquid two-phase velocity, and volume fraction at the node to be determined:

[0095] Intermediate variables:

[0096] Mixing speed:

[0097] Gas velocity:

[0098] Gas volume fraction:

[0099] Liquid volume fraction:

[0100] Liquid velocity:

[0101] The momentum conservation equation for the mixture is rearranged and subjected to grid difference. The right-hand side of the equation consists of gravity, cyclic friction, and inertia terms, with the inertia term accounting for a relatively small proportion and can be ignored.

[0102]

[0103] To simulate the dynamic process of air intrusion at any two nodes j-1 in the annulus from time t-1 to t, the calculation steps are as follows:

[0104] ① Calculate the single-phase flow of drilling fluid in the wellbore before gas invasion occurs, and obtain the initial conditions at the time of gas invasion, including the wellbore annular pressure P(t,j), temperature T(t,j), and liquid density ρ. l (t,j) and volume fraction f l (t,j) etc.;

[0105] ② After gas intrusion occurs, calculate from the bottom of the well to the wellhead, assuming the pressure P at time t at each node. * (t,j)=P(t-1,j), and the physical properties of gas and drilling fluid, such as density, viscosity and gas-liquid surface tension, are initially calculated based on the auxiliary equation;

[0106] ③ Calculate the gas-liquid mixing velocity v at the node based on the mass conservation equation. m (t,j);

[0107] ④ Assuming the porosity of the nodes Substitute the values ​​into the drift flow model and perform iterative calculations until the condition is met. ε represents the allowable error;

[0108] ⑤ Calculate the gas-liquid mixture properties and pressure drop of the grid based on the porosity, and calculate the nodal pressure P(t,j) based on the momentum equation. If |P(t,j)-P * If (t,j)|<ε, then the calculation of node j ends, and the result at node j is used as the known condition for node j+1. Otherwise, return to step ② and recalculate;

[0109] ⑥ When calculating up to the wellhead, determine whether the calculated wellhead pressure value and the actual value satisfy |P(t,j outlet)-P a If (t)|<ε, proceed to the calculation of the next time step t+1; otherwise, re-assume the bottom hole pressure and calculate.

[0110] When simulating well control with constant annular pressure at a constant leaky zone location, the annulus is divided into upper and lower parts based on the leaky zone location (see...). Figure 1 For the annulus below the leaky zone, the calculation steps are the same as the gas intrusion dynamic process described above. Assuming the bottom hole pressure is calculated from the bottom hole towards the leaky zone location, verify whether |P(t,j loss )-P loss |<ε; For the annulus above the leaking layer, the location of the leaking layer is the inlet. The pressure at the inlet is constant and known, so we directly calculate forward to the wellhead. If the wellhead casing pressure drops to atmospheric pressure, the annulus pressure at the leaking layer location is no longer constant. The wellhead pressure is the boundary, and we assume that the annulus pressure at the leaking layer location is calculated iteratively.

[0111] S3. Determine the constant annular pressure value at the location of the leaking layer based on data from the current well or adjacent wells;

[0112] Based on data from current wells or adjacent wells, the leakage pressure or pressure-bearing capacity of the target formation is statistically analyzed to determine the leakage pressure of the target leaking layer. The constant pressure value is designed to not exceed the formation leakage pressure, with an additional safety margin for the leaking layer.

[0113] P h =P loss -P s (27)

[0114] In the formula: P h The constant annular pressure at the location of the leak is expressed in MPa; P loss P represents the leakage pressure of the leakage layer, in MPa. s This represents the safety margin for leakage protection, expressed in MPa.

[0115] S4. Considering the influence of temperature and pressure on the annular pressure at the location of the lost circulation zone, determine the final kill fluid density. This final kill fluid density is the kill fluid density that achieves static pressure stabilization of the formation (the hydrostatic pressure of the kill fluid in a static state after pump shutdown is greater than the overflow formation pressure). Calculate the hydrostatic pressure after the wellbore is filled with the final kill fluid. If the wellbore pressure at the lost circulation zone location is greater than the formation loss pressure at this point, then this method is not applicable.

[0116] The calculation model for the annular hydrostatic pressure at the location of the leakage layer is as follows:

[0117]

[0118]

[0119]

[0120]

[0121] P H =9.81×10 -6 ρ(P,T)H (32)

[0122] In the formula: ρ(P,T) is the density of water-based drilling fluid at a certain temperature and pressure, kg / m³ 3 ;T r Reference temperature, °C; T is the downhole drilling fluid temperature, °C; P r The reference pressure is MPa; P is the pressure of the downhole drilling fluid, MPa; ρ i Density of water-based drilling fluid at reference temperature, kg / m³ 3 ;ρ wi The density of water at the reference temperature, in kg / m³ 3 ;ρ w The density of water at a certain temperature and pressure in the well, in kg / m³ 3 ;ρ s This refers to the density of the solid phase material in the drilling fluid, typically barite, which can be taken as 4200 kg / m³. 3 ;f vw P represents the water fraction of the drilling fluid. H H represents the hydrostatic pressure at the location of the lost circulation zone when the kill fluid density fills the wellbore, in MPa; H represents the vertical depth of the lost circulation zone, in meters.

[0123] S5. Based on the constant annular pressure value at the location of the leaking layer and the fluid state in the wellbore before well control, the well control fluid density and displacement that can achieve dynamic pressure stabilization of the formation are determined through well control simulation analysis.

[0124] Using a constant wellbore pressure at the location of the lost circulation zone as the target, well control simulation analysis is conducted with different kill fluid densities and flow rates to verify whether the bottomhole pressure meets the formation pressure equilibrium requirements. If the conditions are met, the design is successful; the kill fluid density at this point is the intermediate kill fluid density, and this kill fluid density and flow rate can achieve the requirement of dynamic pressure stabilization of the formation (the fluid column pressure of the kill fluid in circulation is greater than the overflow formation pressure). If the equilibrium requirements are not met, the pressure value at the lost circulation zone location, the kill fluid density, and the flow rate need to be adjusted, and the analysis needs to be repeated until the requirements are met. If no design parameters that meet the requirements can be found, it indicates that the well control method is not applicable.

[0125] Example 1

[0126] Case 1: The density used in the 190.5mm wellbore is 2.16g / cm³. 3 The drilling fluid was precisely controlled during drilling to a depth of 5906.16m, with a controlled casing pressure of 2.7MPa, resulting in a fluid level rise of 1.7m. 3Drilling was immediately stopped and the well shut in. The standpipe pressure increased from 0 to 6.1 MPa, and the casing pressure increased from 0 to 8.3 MPa. After determining the formation pressure, the pressure was gradually controlled and circulated with increasing weight until it reached 2.35 g / cm³. 3 This resulted in well leakage at a weak formation at 4769m in the upper Feixianguan Formation.

[0127] Case 1 well was designed with bottomhole pressure as the target, but failed to consider the weak upper formation, resulting in both overflow and leakage. The following design will focus on the weak formation at 4769m in the Feixianguan Formation as the target leakage zone, and conduct a constant annular pressure well control design at the leakage zone location.

[0128] S1. Obtain the wellbore fluid status before well control;

[0129] (1) In Case 1, the standpipe pressure during well shut-in after a blowout was 6.1 MPa, and the drilling fluid density in the drill string was 2.16 g / cm³. 3 The estimated formation pressure equivalent density is approximately 2.27 g / cm³. 3 Based on the total increase in pool volume, drilling fluid outlet discharge rate, and riser pressure, the gas intrusion index is estimated to be approximately 180 m³. 3 / (MPa·m·d);

[0130] (2) Data at the time of the overflow in Case 1: Mechanical drilling rate 2.5 m / h, drilling fluid inlet discharge 16 L / s, wellhead casing pressure 2.7 MPa. Well structure: 273.05 mm casing 0-4018 m, 219.08 mm casing 4018-4729 m, 190.5 mm borehole 4729-5906 m; Drill string assembly for the current drilling session: 190.5 mm drill bit + mating joint + 18 152.4 mm drill collars + mating joint + 15 101.4 mm weighted drill pipes + 279 101.4 mm drill pipes + mating joint + 309 127 mm drill pipes. Surface temperature 20℃, geothermal gradient approximately 0.025℃ / m.

[0131] (3) The above data are imported into the wellbore-formation coupled transient multiphase flow model for calculation. The changes in annular gas distribution and bottom hole pressure in the wellbore before well control in Case 1 are as follows: Figure 2 As shown.

[0132] S2. Determine the constant annular pressure value at the location of the leak;

[0133] Based on the experience of plugging leaks in the Feixianguan Formation in Case 1, the pressure-bearing capacity of the Feixianguan Formation had been increased to an equivalent density of 2.30 g / cm³ before the overflow formation was encountered. 3 The leakage pressure of the target leak layer is approximately 107.60 MPa. Considering a safety margin of 0.5 MPa for the leak layer pressure, the constant annular pressure at the leak layer location is initially determined to be approximately 107.10 MPa.

[0134] S3. Determine the final kill fluid density;

[0135] The known equivalent density of the overflow formation pressure is approximately 2.27 g / cm³. 3 The equivalent density of the leakage pressure in the target leakage layer is approximately 2.30 g / cm³. 3 To achieve static pressure control of the stabilizing formation while preventing leakage from the target leaking formation, three kill fluids, mud1, mud2, and mud3, were initially proposed. Their densities, measured at a reference temperature of 16℃, were 2.27 g / cm³. 3 2.28 g / cm 3 and 2.29 g / cm 3 The annular pressure distribution after the wellbore is filled with the three types of final kill fluids is calculated according to equations (28)-(32), such as... Figure 3 As shown, while maintaining static pressure to stabilize the overflow formation in mud2, sufficient safety margin of leakage pressure was left in the annulus at the location of the leak. Therefore, the final kill fluid density was determined to be 2.28 g / cm³. 3 .

[0136] S4. Well control simulation analysis;

[0137] First, the well control displacement rate was determined. With a constant annular pressure of 107.10 MPa at the lost circulation zone location, three inlet displacement rates of 12, 16, and 18 L / s were designed. Well control simulations were conducted using drilling fluid of the original density, and the bottom hole pressure variation curves under different displacement rates were obtained, as shown below. Figure 4 As shown, the bottom hole pressure increases with increasing discharge rate during circulating venting. When the discharge rate increases to 18 L / s, the bottom hole pressure gradually rises to meet the formation pressure requirements for balancing the overflow. Therefore, the kill discharge rate during circulating venting is determined to be 18 L / s.

[0138] Then, the intermediate kill fluid density was determined. With a constant annular pressure of 107.10 MPa at the lost circulation location, three sets of intermediate kill fluid densities were designed: 2.20, 2.25, and 2.28 g / cm³. 3 A well control simulation was conducted with an inlet displacement of 18 L / s to obtain the bottom hole pressure variation curves under different well control fluid densities, as shown below. Figure 5 As shown in the figure, it can be seen that after the kill fluid enters the annulus, the higher the density of the kill fluid, the higher the bottom hole pressure, and the larger the dynamic pressure safety window compared to the formation pressure. After approximately 65 minutes of kill fluid operation, the annulus below the lost circulation zone is completely replaced by the kill fluid, and the bottom hole pressure tends to stabilize. The kill fluid densities are 2.20, 2.25, and 2.28 g / cm³. 3 The dynamic pressure safety windows at the bottom of the well were 1.78, 2.33, and 3.02 MPa, respectively. However, at 154.3 min, when the kill fluid density was 2.28 g / cm³, the safety window was lower. 3At that time, the wellhead casing pressure had dropped to 0, and the annular pressure at the lost circulation zone could not be maintained constant. As the kill fluid further replaced the original drilling fluid and gas in the annulus above the lost circulation zone, the annular pressure at the lost circulation zone continued to rise, approaching the fracture pressure at 158.5 minutes (see...). Figure 5 b) It may cause formation leakage. The kill fluid density is 2.25 g / cm³. 3 At that time, the requirement of bottom hole pressure balancing formation pressure was met, and the weak upper formation was not damaged.

[0139] In summary, the annular constant pressure at the location of the lost circulation zone is determined to be 107.10 MPa, the kill fluid flow rate during circulation is 18 L / s, and the kill fluid density is 2.25 g / cm³. 3 Once all overflow material in the annulus has been discharged, the kill fluid density should be gradually increased until a final kill fluid density of 2.28 g / cm³ is reached. 3 The well was controlled using a smaller displacement. The well control design for the constant leakage zone location pressure in Case 1 was completed.

[0140] The above description is not intended to limit the present invention in any way. Although the present invention has been disclosed through the above embodiments, it is not intended to limit the present invention. Any person skilled in the art can make some changes or modifications to the above-disclosed technical content to create equivalent embodiments without departing from the 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 scope of the present invention shall fall within the scope of the present invention.

Claims

1. A method for killing a well with constant position of a leaky layer in case of overflow and leakage of a superdeep well, characterized by Includes the following steps: S1. Obtain drilling data and formation parameters at the time of the overflow; S2. Based on the drilling data at the time of overflow, the overflow formation parameters, and the wellbore-formation coupled transient multiphase flow model, obtain the wellbore fluid state before well control; The wellbore-formation coupled transient multiphase flow model includes: Governing equations: In the formula: A Let m be the cross-sectional area of ​​the annulus. 2 ; This represents the volume fraction of the gas phase. This represents the volume fraction of the liquid phase. Where is the density of the gas phase, kg / m³; ρ is the density of the liquid phase, kg / m³; ρ is the density of the gas-liquid mixture, kg / m³; The actual velocity of the liquid phase is in m / s; The actual velocity of the gas phase is in m / s; The inclination angle is expressed in rad. x Let m be the spatial step size. t is the time step, s; P is the pressure, Pa; is the gas-liquid miscible friction, Pa; Boundary conditions: In the formula: Wellhead casing pressure, MPa; For gas intrusion rate, ; K The air intrusion index, ; The reservoir pressure is expressed in MPa. The pressure at the bottom of the annulus well is MPa. The reservoir opening thickness is in meters (m). The leakage pressure of the leaking layer, in MPa; The pressure at a wellhead grid node at a certain point in time; S3. Determine the constant annular pressure value at the location of the leaking layer based on data from the current well or adjacent wells; The formula for calculating the constant annular pressure value at the location of the leak is: In the formula: The constant annular pressure at the location of the leak, in MPa; The leakage pressure of the leaking layer, in MPa; This represents the safety margin for leakage protection, in MPa. S4. Determine the final kill fluid density based on the annular hydrostatic column pressure calculation model at the location of the lost circulation zone. S5. Based on the constant annular pressure value at the location of the leaking layer and the fluid state in the wellbore before well control, the well control fluid density and displacement that can achieve dynamic pressure stabilization of the formation are determined through well control simulation analysis. In step S5, with the wellbore pressure at the constant lost circulation zone location as the target, a well control simulation analysis is conducted using different discharge rates and different well control fluid densities to verify whether the bottom hole pressure meets the requirements for balancing formation pressure. If the conditions are met, the design is successful. At this time, the kill fluid density is the intermediate kill fluid density. Using this kill fluid density and discharge rate can meet the requirements of dynamic pressure stabilization of the formation. If the balance requirements are not met, the constant annular pressure, discharge rate, and kill fluid density at the location of the leaking layer need to be adjusted, and the analysis needs to be repeated until the requirements are met. If the required design parameters cannot be found, it means that the well control method is not applicable.

2. The method of claim 1, wherein the method is characterized by, The drilling data includes wellbore trajectory, wellbore structure, drill string assembly, wellbore temperature, drilling fluid properties, inlet displacement, and mechanical drilling rate.

3. The method of claim 1, wherein the method is characterized by, The overflow formation parameters are wellhead casing pressure, formation pressure, and gas invasion index.

4. The method of claim 1, wherein the method is characterized by, The wellbore-formation coupled transient multiphase flow model includes: Drift flow relation: In the formula: The distribution coefficient; The drift velocity is in m / s; The critical Kutateladze number; Characteristic velocity, ; The effect of well inclination angle on drift velocity; The minimum gas phase velocity required to prevent liquid film backflow. ; and These are the profile parameters; This is a velocity-sensitive parameter for gas-liquid two-phase flow. and These are the constraints for profile parameters; In the formula: For gas-liquid surface tension, ; It is the acceleration due to gravity. ; For Kutateladze numbers; and The fitted number; The number of Bonds; Let the outer diameter of the annulus be m; Let the inner diameter of the annulus be m; , and These are the fitting parameters; The inclination angle is rad.

5. The method of claim 1, wherein the method is characterized by, The calculation model for the annular hydrostatic column pressure at the location of the leakage layer in step S4 includes: In the formula: The density of water-based drilling fluid at a certain temperature and pressure. ; For reference temperature, ; downhole drilling fluid temperature ; Reference pressure, MPa; The pressure exerted on the downhole drilling fluid, in MPa; The density of water-based drilling fluid at the reference temperature. ; The density of water at the reference temperature, ; The density of water at a certain temperature and pressure in the well. ; The density of the solid phase material in the drilling fluid; The percentage of drilling fluid occupied by water; The hydrostatic pressure at the location of the leaking formation, expressed in MPa, when the final kill fluid density fills the wellbore. The vertical depth of the leak location is in meters (m).

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