Intelligent throttled well-killing method and device for overflow in high-temperature and high-pressure deep drilling

Abstract

In view of the problems of complex downhole conditions, low control precision of bottomhole pressure, low one-time success rate of well-killing and the like during a high-temperature and high-pressure deep well-killing operation, a well-killing operation wellbore flowing model is established according to measured data during throttled well-killing. The fluid distribution and flowing states in a wellbore annulus are analyzed in real time, and during a measured standpipe pressure deviation design, a pressure control value is calculated accurately in consideration of the effects of a pressure wave propagation speed and a back pressure application delay, and a throttle valve is automatically adjusted and automatically controlled to actuate.

Claims

1. An intelligent throttled well-killing method for overflow in high-temperature and high-pressure deep drilling, comprising the following steps: S1: before well-killing starts, solving a formation pressure and a designed standpipe pressure by closing a blowout preventer; calculating a wellbore fluid distribution by using a wellbore flow parameter analysis and correction module; displaying data of a standpipe pressure of the designed standpipe pressure during well-killing on a designed standpipe pressure curve module in an intelligent throttled well-killing construction operation console; displaying data of a designed casing pressure on a designed casing pressure curve module in the intelligent throttled well-killing construction operation console; displaying data of a designed well-killing displacement on a measured/designed outlet and inlet displacement curve module in the intelligent throttled well-killing construction operation console; inspecting whether a switch position of each gate valve is normal, and the throttle manifold is in a standby condition; S2: opening a flat gate valve and starting a mud pump; injecting a well-killing fluid in a drilling fluid tank into a wellbore through a drill string; adjusting an automatic control throttle valve to make a measured value of a casing pressure gauge equal to a shut-in casing pressure and keep the measured value of the casing pressure gauge unchanged until a displacement of the well-killing fluid reaches the designed well-killing displacement, and during this period, updating and correcting the wellbore fluid distribution in real time through the wellbore flow parameter analysis and correction module; and S3: keeping the displacement of the well-killing fluid constant, and injecting the well-killing fluid in the drilling fluid tank into the wellbore through the drill string; gradually discharging an overflow above a drill bit from the wellbore through an annulus, and during this period, updating and correcting the wellbore fluid distribution in real time through the wellbore flow parameter analysis and correction module, wherein when a measured value of a standpipe pressure gauge deviates from the designed standpipe pressure, a bottomhole pressure has deviated from a designed bottomhole pressure; predicting and calculating a development trend of the bottomhole pressure by using the wellbore flow parameter analysis and correction module; determining a target pressure adjustment value; sending a target value to be adjusted to an automatic opening degree adjustment module for an automatic control throttle valve; sending a throttle valve adjustment instruction through the automatic opening degree adjustment module for the automatic control throttle valve; and adjusting the automatic control throttle valve to make the measured value of the standpipe pressure coincident with the designed standpipe pressure.

2. The intelligent throttled well-killing method for overflow in high-temperature and high-pressure deep drilling according to claim 1, wherein in step S1, a fluid distribution in a wellbore annulus comprises an overflow height in the wellbore annulus, a gas holdup rate in the wellbore annulus, a liquid holdup rate in the wellbore annulus, a pressure distribution in the wellbore annulus, a gas flow velocity in the wellbore annulus and a liquid flow velocity in the wellbore annulus.

3. The intelligent throttled well-killing method for overflow in high-temperature and high-pressure deep drilling according to claim 1, wherein in step S1, a method for calculating the wellbore fluid distribution through the wellbore flow parameter analysis and correction module is as follows: S101: after the overflow occurs and before a well is shut in, measuring data in real time through an inlet flowmeter, an outlet flowmeter, and a standpipe pressure gauge to obtain the fluid distribution in the wellbore annulus in combination with a wellbore transient multiphase fluid mechanics model, wherein the wellbore transient multiphase fluid mechanics model and an initial calculation condition and a calculation boundary condition are as follows: the wellbore transient multiphase fluid mechanics model: $\{\begin{array}{cc}\begin{array}{c}\mathrm{gas}\text{-}\mathrm{phase}\\ \mathrm{continuity}\mathrm{equation}\text{:}\end{array}& \frac{\partial }{\partial z}\left(A{\rho }_g{E}_g{v}_g\right)+\frac{\partial }{\partial t}\left(A{\rho }_g{E}_g\right)={\Gamma }_g\\ \begin{array}{c}\mathrm{liquid}\text{-}\mathrm{phase}\\ \mathrm{continuity}\mathrm{equation}\text{:}\end{array}& \frac{\partial }{\partial z}\left(A{\rho }_l{E}_l{v}_l\right)+\frac{\partial }{\partial t}\left(A{\rho }_l{E}_l\right)=0\\ \mathrm{motion}\mathrm{equation}\text{:}& \frac{\partial }{\partial t}\left(A{\rho }_l{E}_l{v}_l+A{\rho }_g{E}_g{v}_g\right)+\\ & \frac{\partial }{\partial z}\left(A{\rho }_l{E}_l{v}_l^2+A{\rho }_g{E}_g{v}_g^2\right)+\\ & A\frac{\partial P}{\partial z}+A{\rho }_{m}g+{A\left(\frac{\partial P}{\partial z}\right)}_{\mathrm{fr}}=0\end{array}\hspace{1em}\hspace{1em}$ the initial calculation condition: $\{\begin{array}{c}{E}_g\left(0,j\right)=0,E_l\left(0,j\right)=1\\ v_g\left(0,j\right)=0,v_l\left(0,j\right)=q_l\text{/}A\\ P\left(0,j\right)=\rho \mathrm{gj}+P_f\end{array}\hspace{1em}$ the calculation boundary calculation: $\{\begin{array}{c}{P}_b\left(t\right)=P_{d\_\mathrm{measured}}\left(t\right)+\rho \mathrm{gH}-P_{d\_f}\\ q_o\left(t\right)=q_{o\_\mathrm{measured}}\left(t\right)\end{array}\hspace{1em}$ wherein, A is a cross-sectional area of the wellbore annulus, m.sup.2; ρ.sub.g is a gas density, kg/m.sup.3; E.sub.g is a gas holdup rate, dimensionless; ν.sub.g is a gas flow rate, m/s; Γ.sub.g is a gas source term in the gas-phase continuity equation, kg/m/s; ρ.sub.l is a density of a drilling fluid, kg/m.sup.3; E.sub.l is a liquid holdup rate, E.sub.l+E.sub.g=1, dimensionless; ν.sub.l is a flow velocity of the drilling fluid, m/s; P is a pressure, Pa; ρ.sub.m is a density of a mixture, ρ.sub.m=ρ.sub.lE.sub.l+ρ.sub.gE.sub.g, kg/m.sup.3; ${\left(\frac{\partial P}{\partial z}\right)}_{\mathrm{fr}}\hspace{1em}$  is a friction pressure drop, MPa/m; j is a position, m; P.sub.f is an annulus pressure loss, MPa; H is a well depth where a gas invasion occurs, m; t is time, s; q.sub.l is an inlet displacement of the drilling fluid, L/s; P.sub.b(t) is a bottomhole pressure at time t, MPa; P.sub.d_measured(t) is a standpipe pressure measured at time t, MPa; P.sub.d_f is a pressure loss in a drill string, MPa; q.sub.o(t) is an outlet displacement of a wellhead annulus, L/s; q.sub.o_measured(t) is an outlet displacement of the wellhead annulus measured at time t, L/s; the wellbore transient multiphase fluid mechanics model is solved iteratively using an implicit difference method to obtain the fluid distribution in the wellbore annulus; and S102: during a period from shut-in to a stage before well-killing, measuring data by using the casing pressure gauge in real time; based on a state of the fluid distribution in the wellbore annulus before shut-in, obtaining the fluid distribution in the wellbore annulus by using a shut-in wellbore fluid mechanics model, wherein the shut-in wellbore fluid mechanics model takes into account shut-in after-flow and slippage effects, wherein, the shut-in wellbore fluid mechanics model is as follows: $\underset{i=1}{\overset{n}{.Math.}}{A}_a\left(t,i\right)E_g\left(t,i\right)h_g\left(t,i\right)-\underset{i=1}{\overset{n}{.Math.}}{A}_a\left(t-\Delta t,i\right)E_g\left(t-\Delta t,i\right)h_g\left(t-\Delta t,i\right)=\underset{x=1}{\overset{X}{.Math.}}{C}_l\frac{P_x\left(t\right)-P_x\left(t-\Delta t\right)}{2}{V}_{\mathrm{lx}}\left(t\right)+V_f\left(t\right)$ wherein, A.sub.a(t,i) is a cross-section area of the wellbore annulus, m.sup.2; E.sub.g(t,i) is a unit gas holdup rate, %; h.sub.g(t,i) is a unit length, m; P.sub.x(t) is a pressure at position x in the wellbore; V.sub.lx(t) is a volume of the drilling fluid in a wellbore unit, m.sup.3; V.sub.f(t) is a filtration loss of the drilling fluid per unit time step, m.sup.3; Δt is a time step, s; and the shut-in wellbore fluid mechanics model is solved by using a Gauss-Seidel iterative method to obtain the fluid distribution in the wellbore annulus.

4. The intelligent throttled well-killing method for overflow in high-temperature and high-pressure deep drilling according to claim 1, wherein in step S2, a method for adjusting the automatic control throttle valve is as follows: monitoring the measured value of the casing pressure gauge in real time, and comparing the measured value of the casing pressure gauge with a shut-in casing pressure value; when a deviation value occurs between the measured value of the casing pressure gauge and the shut-in casing pressure value, sending the deviation value to an automatic opening degree adjustment module of an automatic throttle valve; sending a control instruction to the automatic control throttle valve through the automatic opening degree adjustment module of the automatic throttle valve to adjust an opening degree of the automatic throttle valve and maintain a wellhead casing pressure equal to the shut-in casing pressure.

5. The intelligent throttled well-killing method for overflow in high-temperature and high-pressure deep drilling according to claim 1, wherein in step S2, a method for determining whether the displacement of the well-killing fluid reaches the designed well-killing displacement is as follows: determining whether the displacement of the well-killing fluid has reached the designed well-killing displacement based on a measured/designed displacement curve of the well-killing fluid in the measured/designed outlet and inlet displacement curve module in the intelligent throttled well-killing construction operation console.

6. The intelligent throttled well-killing method for overflow in high-temperature and high-pressure deep drilling according to claim 1, wherein in step S2, a method for updating and correcting the wellbore fluid distribution in real time comprises: measuring a well-killing fluid outlet displacement by an outlet flowmeter in real time, measuring a well-killing fluid inlet displacement by an inlet flowmeter in real time, measuring a standpipe pressure by a standpipe pressure gauge in real time, and measuring a casing pressure by a casing pressure gauge in real time; and updating and correcting the wellbore fluid distribution obtained in step S1 in real time in combination with a wellbore transient multiphase fluid mechanics model; and the wellbore transient multiphase fluid mechanics model, an initial calculation condition and a calculation boundary condition are as follows: the wellbore transient multiphase fluid mechanics model: $\{\begin{array}{cc}\begin{array}{c}\mathrm{gas}\text{-}\mathrm{phase}\\ \mathrm{continuity}\mathrm{equation}\text{:}\end{array}& \frac{\partial }{\partial z}\left(A{\rho }_g{E}_g{v}_g\right)+\frac{\partial }{\partial t}\left(A{\rho }_g{E}_g\right)={\Gamma }_g\\ \begin{array}{c}\mathrm{liquid}\text{-}\mathrm{phase}\\ \mathrm{continuity}\mathrm{equation}\text{:}\end{array}& \frac{\partial }{\partial z}\left(A{\rho }_l{E}_l{v}_l\right)+\frac{\partial }{\partial t}\left(A{\rho }_l{E}_l\right)=0\\ \mathrm{motion}\mathrm{equation}\text{:}& \frac{\partial }{\partial t}\left(A{\rho }_l{E}_l{v}_l+A{\rho }_g{E}_g{v}_g\right)+\\ & \frac{\partial }{\partial z}\left(A{\rho }_l{E}_l{v}_l^2+A{\rho }_g{E}_g{v}_g^2\right)+\\ & A\frac{\partial P}{\partial z}+A{\rho }_{m}g+{A\left(\frac{\partial P}{\partial z}\right)}_{\mathrm{fr}}=0\end{array}\hspace{1em}$ the initial calculation condition: $\{\begin{array}{c}{E}_g\left(S2\_0,j\right)=E_g\left(S1\mathrm{\_end},j\right),E_l\left(S2\_0,j\right)=1-E_g\left(S1\mathrm{\_end},j\right)\\ v_g\left(S2\_0,j\right)=v_g\left(S1\mathrm{\_end},j\right),v_l\left(S2\_0,j\right)=v_l\left(S1\mathrm{\_end},j\right)\\ P\left(S2\_0,j\right)=P\left(S1\mathrm{\_end},j\right)\end{array}\hspace{1em}$ the calculation boundary condition: $\{\begin{array}{c}{P}_b\left(t\right)=P_{d\_\mathrm{measured}}\left(t\right)+\rho \mathrm{gH}-P_{d\_f}\\ q_o\left(t\right)=q_{o\_\mathrm{measured}}\left(t\right),q_l\left(t\right)=q_{l\_\mathrm{measured}}\left(t\right)\\ P_c\left(t\right)=P_{c\_\mathrm{measured}}\left(t\right)\end{array}\hspace{1em}$ wherein, A is a cross-sectional area of the wellbore annulus, m.sup.2; ρ.sub.g is a gas density, kg/m.sup.3; E.sub.g is a gas holdup rate, dimensionless; ν.sub.g is a gas flow rate, m/s; Γ.sub.g is a gas source term in the gas-phase continuity equation, kg/m/s; ρ.sub.l is a density of a drilling fluid, kg/m.sup.3; E.sub.l is a liquid holdup rate, E.sub.l+E.sub.g=1, dimensionless; ν.sub.1 is a flow velocity of the drilling fluid, m/s; P is a pressure, Pa; ρ.sub.m is a density of a mixture, ρ.sub.m=ρ.sub.lE.sub.l+ρ.sub.gE.sub.g, kg/m.sup.3; ${\left(\frac{\partial P}{\partial z}\right)}_{\mathrm{fr}}$  is a friction pressure drop, MPa/m; j is a position, m; P.sub.f is an annulus pressure loss, MPa; H is a well depth where a gas invasion occurs, m; t is time, s; S2_0 is a start time of the step S2; S1_end is a n end time of the step S1; q.sub.l(t) is an inlet displacement of the drilling fluid, L/s; q.sub.l_measured(t) is an wellhead inlet displacement measured at time t, L/s; P.sub.b(t) is a bottomhole pressure at time t, MPa; P.sub.d_measured(t) is a standpipe pressure measured at time t, MPa; P.sub.d_f is a pressure loss in a drill string, MPa; q.sub.o(t) is an outlet displacement of a wellhead annulus, L/s; q.sub.o_measured(t) is an outlet displacement of the wellhead annulus measured at time t, L/s; P.sub.c(t) is a wellhead casing pressure, MPa; and P.sub.c_measured(t) is a wellhead casing pressure measured at time t, MPa; and the wellbore transient multiphase fluid mechanics model is solved iteratively using an implicit difference method.

7. The intelligent throttled well-killing method for overflow in high-temperature and high-pressure deep drilling according to claim 1, wherein in step S3, a method for updating and correcting the wellbore fluid distribution in real time comprises: measuring a well-killing fluid outlet placement by an inlet flowmeter in real time, measuring a well-killing fluid inlet displacement by an inlet flowmeter in real time, measuring a standpipe pressure by a standpipe pressure gauge in real time, and measuring a casing pressure by a casing pressure gauge in real time; and updating and correcting the wellbore fluid distribution obtained in step S2 in real time in combination with a wellbore transient multiphase fluid mechanics model; and the wellbore transient multiphase fluid mechanics model, the initial calculation condition and the calculation boundary condition are as follows: the wellbore transient multiphase fluid mechanics model: $\{\begin{array}{cc}\begin{array}{c}\mathrm{gas}\text{-}\mathrm{phase}\\ \mathrm{continuity}\mathrm{equation}\text{:}\end{array}& \frac{\partial }{\partial z}\left(A{\rho }_g{E}_g{v}_g\right)+\frac{\partial }{\partial t}\left(A{\rho }_g{E}_g\right)={\Gamma }_g\\ \begin{array}{c}\mathrm{liquid}\text{-}\mathrm{phase}\\ \mathrm{continuity}\mathrm{equation}\text{:}\end{array}& \frac{\partial }{\partial z}\left(A{\rho }_l{E}_l{v}_l\right)+\frac{\partial }{\partial t}\left(A{\rho }_l{E}_l\right)=0\\ \mathrm{motion}\mathrm{equation}\text{:}& \frac{\partial }{\partial t}\left(A{\rho }_l{E}_l{v}_l+A{\rho }_g{E}_g{v}_g\right)+\\ & \frac{\partial }{\partial z}\left(A{\rho }_l{E}_l{v}_l^2+A{\rho }_g{E}_g{v}_g^2\right)+\\ & A\frac{\partial P}{\partial z}+A{\rho }_{m}g+{A\left(\frac{\partial P}{\partial z}\right)}_{\mathrm{fr}}=0\end{array}\hspace{1em}$ the initial calculation condition: $\{\begin{array}{c}{E}_g\left(S3\_0,j\right)=E_g\left(S2\mathrm{\_end},j\right),E_l\left(S3\_0,j\right)=1-E_g\left(S2\mathrm{\_end},j\right)\\ v_g\left(S3\_0,j\right)=v_g\left(S2\mathrm{\_end},j\right),v_l\left(S3\_0,j\right)=v_l\left(S2\mathrm{\_end},j\right)\\ P\left(S3\_0,j\right)=P\left(S2\mathrm{\_end},j\right)\end{array}\hspace{1em}$ the calculation boundary condition: $\{\begin{array}{c}{P}_b\left(t\right)=P_{d\_\mathrm{measured}}\left(t\right)+\rho \mathrm{gH}-P_{d\_f}\\ q_o\left(t\right)=q_{o\_\mathrm{measured}}\left(t\right),q_l\left(t\right)=q_{l\_\mathrm{measured}}\left(t\right)\\ P_c\left(t\right)=P_{c\_\mathrm{measured}}\left(t\right)\end{array}\hspace{1em}$ wherein, A is a cross-sectional area of the wellbore annulus, m.sup.2; ρ.sub.g is a gas density, kg/m.sup.3; E.sub.g is a gas holdup rate, dimensionless; ν.sub.g is a gas flow rate, m/s; Γ.sub.g is a gas source term in the gas-phase continuity equation, kg/m/s; ρ.sub.l is a density of drilling fluid, kg/m.sup.3; E.sub.l is a liquid holdup rate, E.sub.l+E.sub.g=1, dimensionless; ν.sub.l is a flow velocity of the drilling fluid, m/s; P is a pressure, Pa; ρ.sub.m is a density of a mixture, ρ.sub.m=ρ.sub.lE.sub.l+ρ.sub.gE.sub.g, kg/m.sup.3; ${\left(\frac{\partial P}{\partial z}\right)}_{\mathrm{fr}}$ is friction pressure drop, MPa/m; j is a position, m; P.sub.f is an annulus pressure loss, MPa; H is a well depth where a gas invasion occurs, m; t is time, s; S3_0 is a start time in step S3; S2_end is a start time of the step S2; q.sub.l(t) is an inlet displacement of the drilling fluid, L/s; q.sub.l_measured(t) is a wellhead inlet displacement measured at time t, L/s; P.sub.b(t) is a bottomhole pressure at time t, MPa; P.sub.d_measured(t) is a standpipe pressure measured at time t, MPa; P.sub.d_f is a pressure loss in a drill string, MPa; q.sub.0(t) is an outlet displacement of a wellhead annulus, L/s; q.sub.o_measured(t) is an outlet displacement of the wellhead annulus measured at time t, L/s; P.sub.c(t) is a wellhead casing pressure measured at time t, MPa; P.sub.c_measured(t) is a wellhead casing pressure measured at time t, MPa; and the wellbore transient multiphase fluid mechanics model is solved iteratively using an implicit difference method.

8. The intelligent throttled well-killing method for overflow in high-temperature and high-pressure deep drilling according to claim 1, wherein in step S3, when the measured value of the standpipe pressure gauge deviates from the designed standpipe pressure, a development trend of the bottomhole pressure is predicated and calculated through the wellbore flow parameter analysis and correction module, and a method for determining the target pressure adjustment value is as follows: the target pressure adjustment value is: ΔP.sub.b=ΔP.sub.b1+ΔP.sub.b2+ΔP.sub.b3 wherein, ΔP.sub.b is the target pressure adjustment value, MPa; ΔP.sub.b1 is a deviation value at time (t1) when the measured value of the standpipe pressure gauge is monitored to deviate the designed standpipe pressure, MPa; ΔP.sub.b2 is a change value of the bottomhole pressure within a period (t0-t1) when bottomhole pressure waves are transmitted to the wellhead standpipe pressure gauge, MPa; ΔP.sub.b3 is a change in the bottomhole pressure within a period (t1-2) when a wellhead back pressure is transmitted to a bottomhole after a throttle valve is actuated, MPa; t0 is a time when the bottomhole pressure deviates from the designed bottomhole pressure, s; t1 is a time when the measured value of the standpipe pressure gauge deviates from the designed standpipe pressure, s; t2 is a time when the wellhead back pressure is applied to the bottomhole after the opening degree of the automatic throttle valve is adjusted, s; $\Delta t_{0-1}=t1-t0=\frac{H}{v_{w\_\mathrm{in}\_\mathrm{pipe}}}$  is a first time length from time t0 to time t1, and in the first time length, the bottomhole pressure waves are transmitted to the wellhead standpipe pressure gauge, s; H is a well depth, m; ν.sub.w_in_pipe is a pressure wave propagation velocity in the drill string, m/s; $\Delta t_{1-2}=t2-t1=\frac{H}{v_{w\_\mathrm{in}\_\mathrm{annulus}}}$  is a second time length from time t1 to time t2, and in the second time length, the pressure waves of the wellhead back pressure are transmitted to the bottomhole after the opening degree of the automatic throttle valve is adjusted, s; ν.sub.w_in_annulus is a pressure wave propagation velocity in the wellbore annulus, m/s; a calculation method of ΔF is ΔP.sub.b1=P.sub.d_measured−P.sub.d_designed; wherein, P.sub.d_measured is the measured value of the standpipe pressure gauge when the standpipe pressure deviates from the designed standpipe pressure, MPa; P.sub.d_designed is the designed standpipe pressure value, MPa; a calculation method of ΔP.sub.b2 is as follows: predicting a bottomhole pressure at time t1 after Δt.sub.0-1 by taking a parameter at time t0 as an initial state through a wellbore transient multiphase fluid mechanics model; the wellbore transient multiphase fluid mechanics model and a first initial calculation condition and a first calculation boundary condition are as follows: the wellbore transient multiphase fluid mechanics model: $\{\begin{array}{cc}\begin{array}{c}\mathrm{gas}\text{-}\mathrm{phase}\\ \mathrm{continuity}\mathrm{equation}\text{:}\end{array}& \frac{\partial }{\partial z}\left(A{\rho }_g{E}_g{v}_g\right)+\frac{\partial }{\partial t}\left(A{\rho }_g{E}_g\right)={\Gamma }_g\\ \begin{array}{c}\mathrm{liquid}\text{-}\mathrm{phase}\\ \mathrm{continuity}\mathrm{equation}\text{:}\end{array}& \frac{\partial }{\partial z}\left(A{\rho }_l{E}_l{v}_l\right)+\frac{\partial }{\partial t}\left(A{\rho }_l{E}_l\right)=0\\ \mathrm{motion}\mathrm{equation}\text{:}& \frac{\partial }{\partial t}\left(A{\rho }_l{E}_l{v}_l+A{\rho }_g{E}_g{v}_g\right)+\\ & \frac{\partial }{\partial z}\left(A{\rho }_l{E}_l{v}_l^2+A{\rho }_g{E}_g{v}_g^2\right)+\\ & A\frac{\partial P}{\partial z}+A{\rho }_{m}g+{A\left(\frac{\partial P}{\partial z}\right)}_{\mathrm{fr}}=0\end{array}\hspace{1em}$ the first initial calculation condition: $\{\begin{array}{c}{E}_g\left(0,j\right)=E_g\left(t0,j\right),E_l\left(0,j\right)=1-E_g\left(t0,j\right)\\ v_g\left(0,j\right)=v_g\left(t0,j\right),v_l\left(0,j\right)=v_l\left(t0,j\right)\\ P\left(0,j\right)=P\left(t0,j\right)\end{array}\hspace{1em}$ the first calculation boundary condition: $\{\begin{array}{c}{P}_b\left(t\right)=P_{d\_\mathrm{measured}}\left(t\right)+\rho \mathrm{gH}-P_{d\_f}\\ q_o\left(t\right)=q_{o\_\mathrm{measured}}\left(t\right),q_l\left(t\right)=q_{l\_\mathrm{measured}}\left(t\right)\\ P_c\left(t\right)=P_{c\_\mathrm{measured}}\left(t\right)\end{array}\hspace{1em}$ wherein, A is a cross-sectional area in the wellbore annulus, m.sup.2; ρ.sub.g is a gas density, kg/m.sup.3; E.sub.g is a gas holdup rate, dimensionless; ν.sub.g is a gas flow rate, m/s; Γ.sub.g is a gas source term in the gas-phase continuity equation, kg/m/s; ρ.sub.l is a density of the drilling fluid, kg/m.sup.3; E.sub.l is a liquid holdup rate, E.sub.l+E.sub.g=1, dimensionless; ν.sub.1 is a flow velocity of the drilling fluid, m/s; P is a pressure, Pa; ρ.sub.m is a density of a mixture, ρ.sub.m=ρ.sub.lE.sub.l+ρ.sub.gE.sub.g, kg/m.sup.3; ${\left(\frac{\partial P}{\partial z}\right)}_{\mathrm{fr}}$  is a friction pressure drop, MPa/m; j is a position, m; P.sub.f is an annulus pressure loss, MPa; H is a well depth where a gas invasion occurs, m; t is time, s; q.sub.l(t) is an inlet displacement of the drilling fluid, L/s; q.sub.l_measured (t0) is a wellhead inlet displacement measured at time t0 L/s; P.sub.b(t) is a bottomhole pressure at time t0, MPa; P.sub.d_measured(t0) is a standpipe pressure measured at time t0, MPa; P.sub.d_f is a pressure loss in the drill string, MPa; q.sub.o(t) is an outlet displacement of a wellhead annulus, L/s; q.sub.o_measured(t0) is an outlet displacement of the wellhead annulus measured at time t0, L/s; P.sub.c(t) is a wellhead casing pressure, MPa; P.sub.c_measured(t0) is a wellhead casing pressure measured at time t0, MPa; and a bottomhole pressure P.sub.b(t1) at time t1 is solved by the first wellbore transient multiphase fluid mechanics model iteratively through an implicit difference method; a calculation formula ΔP.sub.b2 is ΔP.sub.b2=P.sub.b(t1)−P.sub.d_measured; a calculation method of ΔP.sub.b3 is as follows: predicting a bottomhole pressure at time t2 after Δt.sub.1-2 by taking a parameter at time t1 as an initial state through the wellbore transient multiphase fluid mechanics model; the wellbore transient multiphase fluid mechanics model and a second initial calculation condition and a second calculation boundary are as follows: the wellbore transient multiphase fluid mechanics model: $\{\begin{array}{cc}\begin{array}{c}\mathrm{gas}\text{-}\mathrm{phase}\\ \mathrm{continuity}\mathrm{equation}\text{:}\end{array}& \frac{\partial }{\partial z}\left(A{\rho }_g{E}_g{v}_g\right)+\frac{\partial }{\partial t}\left(A{\rho }_g{E}_g\right)={\Gamma }_g\\ \begin{array}{c}\mathrm{liquid}\text{-}\mathrm{phase}\\ \mathrm{continuity}\mathrm{equation}\text{:}\end{array}& \frac{\partial }{\partial z}\left(A{\rho }_l{E}_l{v}_l\right)+\frac{\partial }{\partial t}\left(A{\rho }_l{E}_l\right)=0\\ \mathrm{motion}\mathrm{equation}\text{:}& \frac{\partial }{\partial t}\left(A{\rho }_l{E}_l{v}_l+A{\rho }_g{E}_g{v}_g\right)+\\ & \frac{\partial }{\partial z}\left(A{\rho }_l{E}_l{v}_l^2+A{\rho }_g{E}_g{v}_g^2\right)+\\ & A\frac{\partial P}{\partial z}+A{\rho }_{m}g+{A\left(\frac{\partial P}{\partial z}\right)}_{\mathrm{fr}}=0\end{array}\hspace{1em}$ the second initial calculation condition: $\{\begin{array}{c}{E}_g\left(0,j\right)=E_g\left(t1,j\right),E_l\left(0,j\right)=1-E_g\left(t1,j\right)\\ v_g\left(0,j\right)=v_g\left(t1,j\right),v_l\left(0,j\right)=v_l\left(t1,j\right)\\ P\left(0,j\right)=P\left(t1,j\right)\end{array}\hspace{1em}$ the second calculation boundary calculation condition: $\{\begin{array}{c}{P}_b\left(t\right)=P_{d\_\mathrm{measured}}\left(t1\right)+\rho \mathrm{gH}-P_{d\_f}\\ q_o\left(t\right)=q_{o\_\mathrm{measured}}\left(t1\right),q_l\left(t\right)=q_{l\_\mathrm{measured}}\left(t1\right)\\ P_c\left(t\right)=P_{c\_\mathrm{measured}}\left(t1\right)\end{array}\hspace{1em}$ wherein, A is a cross-sectional area of the wellbore annulus, m.sup.2; ρ.sub.g is a gas density, kg/m.sup.3; E.sub.g is a gas holdup rate, dimensionless; ν.sub.g is a gas flow rate, m/s; Γ.sub.g is a gas source term in the gas-phase continuity equation, kg/m/s; ρ.sub.l is a density of the drilling fluid, kg/m.sup.3; E.sub.l is a liquid holdup rate, E.sub.l+E.sub.g=1, dimensionless; ν.sub.l is a flow velocity of the drilling fluid, m/s; P is a pressure, Pa; ρ.sub.m is a density of a mixture, ρ.sub.m=ρ.sub.lE.sub.l+ρ.sub.gE.sub.g, kg/m.sup.3; ${\left(\frac{\partial P}{\partial z}\right)}_{\mathrm{fr}}$  is a friction pressure drop, MPa/m; j is a position, m; P.sub.f is an annulus pressure loss, MPa; H is a well depth where the gas invasion occurs, m; t is time, s; q.sub.l(t) is a drilling fluid inlet displacement, L/s; q.sub.l_measured(t1) is a wellhead inlet displacement measured at time t1, L/s; P.sub.b(t) is a bottomhole pressure at time t0, MPa; P.sub.d_measured(t1) is a standpipe pressure measured at time t1, MPa; P.sub.d_f is a pressure loss in the drill string, MPa; q.sub.o(t) is an outlet displacement of the wellhead annulus, L/s; q.sub.o_measured(n) is an outlet displacement of the wellhead annulus measured at time t1, L/s; P.sub.c(t) is a wellhead casing pressure, MPa; P.sub.c_measured(t1) is a wellhead casing pressure measured at time t1, MPa; and a bottomhole pressure P.sub.b(t2) at time t2 is solved by the wellbore transient multiphase fluid mechanics model iteratively through the implicit difference method; a calculation formula ΔP.sub.b3 of is ΔP.sub.b3=P.sub.b(t2)−P.sub.b(t1).

9. An intelligent throttled well-killing method for overflow in high-temperature and high-pressure deep drilling, comprising an inlet flowmeter, an outlet flowmeter, a standpipe pressure gauge, a casing pressure gauge, an automatic control throttle valve, a manual control throttle valve, flat gate valves, an intelligent throttled well-killing construction operation console and a data acquisition and control line, wherein the inlet flowmeter is installed at a well-killing fluid inlet and the inlet flowmeter is configured to measure an inlet flow in real time; the standpipe pressure gauge is installed at the well-killing fluid inlet and the standpipe pressure gauge is configured to measure a standpipe pressure in real time; the outlet flowmeter is installed at a well-killing fluid outlet and the outlet flowmeter is configured to measure an outlet flow in real time; the casing pressure gauge is installed at a throttle manifold and the casing pressure gauge is configured to measure a casing pressure in real time; the automatic control throttle valve is installed at the throttle manifold and the automatic control throttle valve is configured to adjust an opening degree of the automatic control throttle valve according to a first plurality of instructions, and the automatic control throttle valve has a working pressure of above 70 MPa; the manual control throttle valve is installed at the throttle manifold and the manual control throttle valve is configured to manually adjust the opening degree of the automatic control throttle valve according to a second plurality of instructions; the flat gate valves are installed on the throttle manifold, a blowout prevention pipeline and a relief pipeline, and the flat gate valves are opened and closed according to requirements to control a drilling fluid to flow; the data acquisition and control line connects the inlet flowmeter, the outlet flowmeter, the standpipe pressure gauge, the casing pressure gauge, the automatic control throttle and the intelligent throttled well-killing construction operation console, and the data acquisition and control line is configured to transmit the first plurality of instructions for measuring data in real time and controlling the opening degree of the automatic control throttle valve; the intelligent throttled well-killing construction operation console comprises a measurement parameter display module, a wellbore flow parameter analysis and correction module, an automatic opening degree adjustment module of the automatic control throttle valve, a measured casing pressure curve module, a measured standpipe pressure curve module, a designed standpipe pressure curve module, a designed casing pressure curve module, and a measured/designed inlet displacement curve module; the measurement parameter display module is configured to display inlet flowmeter readings, standpipe pressure gauge readings, outlet flowmeter readings, casing pressure gauge readings, opening degree readings of the automatic control throttle valve, and opening degree adjustment instruction parameters of the automatic control throttle valve, wherein, the inlet flowmeter readings, the standpipe pressure gauge readings, the outlet flowmeter readings, the casing pressure gauge readings, the opening degree readings of the automatic control throttle valve, and the opening degree adjustment instruction parameters of the automatic control throttle valve are currently collected in real time; the wellbore flow parameter analysis and correction module is configured to establish a wellbore flow parameter analysis and correction model based on a multiphase flow theory in combination with data measured by the inlet flowmeter, the standpipe pressure gauge, the outlet flowmeter and the casing pressure gauge, and calculate an overflow height in a wellbore annulus, a gas holdup rate in the wellbore annulus, a liquid holdup rate in the wellbore annulus, a pressure distribution in the wellbore annulus, a gas flow velocity in the wellbore annulus, a liquid flow velocity in the wellbore annulus, and other parameters; the automatic opening degree adjustment module of the automatic control throttle valve is configured to send the first plurality of instructions to the automatic control throttle valve by taking a prediction result of the wellbore flow parameter analysis and correction module as an adjustment basis to automatically control the opening degree of the automatic control throttle valve and control a bottomhole pressure within a design range; the measured/designed inlet displacement curve module is configured to draw data of an outlet displacement measured/designed by the outlet inlet flowmeter and data of an inlet displacement measured/designed by the inlet flowmeter into a first visual graph, wherein, the data of the outlet displacement and the data of the inlet displacement are distributed over time; the measured casing pressure curve module is configured to draw data of the casing pressure measured by the casing pressure gauge into a second visual graph, wherein the data of the casing pressure are distributed over time; the measured standpipe pressure curve module is configured to draw data of the standpipe pressure measured by the standpipe pressure gauge into a third visual graph, wherein, the data of the standpipe pressure are distributed over time; the designed standpipe pressure curve module is configured to draw data of a designed standpipe pressure into a fourth visual graph, wherein the data of the designed standpipe pressure are distributed over time; and the designed casing pressure curve module is configured to draw data of a designed casing pressure into a visual graph, wherein the data of the designed casing pressure are distributed over time.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

(1) FIG. 1 is a schematic diagram of an intelligent throttled well-killing device for overflow in high-temperature and high-pressure deep drilling according to the present invention; and

(2) FIG. 2 shows an intelligent throttled well-killing construction operation console of the intelligent throttled well-killing device for overflow in high-temperature and high-pressure deep drilling according to the present invention.

(3) In drawings, reference symbols represent the following components: 1—drilling fluid tank; 2—drilling pump; 3—intelligent throttled well—killing construction operation console; 4—data acquisition and control line; 5—blowout preventer; 6—throttle manifold; 7—well-killing manifold; 8—drill string; 9—annulus; 10—overflow; 11—drill bit; 12—measurement parameter display module; 13—wellbore flow parameter analysis and correction module; 14—automatic opening degree adjustment module of an automatic control throttle valve; 15—measured/designed inlet and outlet displacement curve module; 16—measured casing pressure curve module; 17—measured standpipe pressure curve module; 18—designed standpipe pressure curve module; 19—designed casing pressure curve module; F1—inlet flowmeter; F2—outlet flowmeter; G1—standpipe pressure gauge; G2—casing pressure gauge; J1—automatic control throttle valve; J4—manual control throttle valve; flat gate valves 1#, 2#, 3#, 4#, J2a, J2b, J3a, J3b, J5, J6a, J6b, J7, J8, J9, J10.

DETAILED DESCRIPTION OF THE EMBODIMENTS

(4) The technical solution of the present invention is described in further detail below with reference to the accompanying drawings, but the protection scope of the present invention is not limited to the followings.

(5) As shown in FIG. 1, an intelligent throttled well-killing device for overflow in high-temperature and high-pressure deep drilling comprises an inlet flowmeter F1, an outlet flowmeter F2, a standpipe pressure gauge G1, a casing pressure gauge G2, an automatic control throttle valve J1, a manual control throttle valve J4, flat gate valves (1#, 2#, 3#, 4#, J2a, J2b, J3a, J3b, J5, J6a, J6b, J7, J8, J9, J10), an intelligent throttled well-killing construction operation console 3, and a data acquisition and control line 4.

(6) The inlet flowmeter F1 is installed at a well-killing fluid inlet and configured to measure an inlet flow in real time; the standpipe pressure gauge G1 is installed at the well-killing fluid inlet and configured to measure a standpipe pressure in real time; the outlet flowmeter F2 is installed at a well-killing fluid outlet and configured to measure an outlet flow in real time; the casing pressure gauge G2 is installed at a throttle manifold and configured to measure a casing pressure in real time; the automatic control throttle valve J1 is installed at a throttle manifold 6 and configured to adjust an opening degree according to instructions, and has a working pressure of above 70 MPa; the data acquisition and control line 4 connects the inlet flowmeter F1, the outlet flowmeter F2, the standpipe pressure gauge G1, the casing pressure gauge G2, the automatic control throttle valve J1 and the intelligent throttled well-killing construction operation console 3, and configured to transmit instructions for measuring data measured by the inlet flowmeter F1, the outlet flowmeter F2, the standpipe pressure gauge G1 and the casing pressure gauge G2 and controlling the opening degree of the automatic control throttle valve J1; the manual control throttle valve J4 is installed at the throttle manifold and configured to manually adjust the opening degree according to instructions; the flat gate valves (1#, 2#, 3#, 4#, J2a, J2b, J3a, J3b, J5, J6a, J6b, J7, J8, J9, J10) are installed on the throttle manifold 6 and a well-killing manifold 7, can be opened and closed as needed and configured to control a flowing channel of drilling fluid; the intelligent throttled well-killing construction operation console 3 comprises a measurement parameter display module 12, a wellbore flow parameter analysis and correction module 13, an automatic opening degree adjustment module 14 of the automatic control throttle valve, a measured outlet and inlet displacement curve module 15, a measured casing pressure curve module 16, a measured standpipe pressure curve module 17, a designed standpipe pressure curve module 18, a designed casing pressure curve module 19; the measurement parameter display module 12 is configured to display inlet flowmeter F1 readings, a standpipe pressure gauge G1 readings, outlet flowmeter F2 readings, casing pressure gauge G2 readings, automatic control throttle valve J1 opening degree readings, and automatic control throttle value opening degree adjustment instruction parameters, which are currently collected in real time; the wellbore flow parameter analysis and correction module 13 is configured to establish a wellbore flow parameter analysis and correction model based on a multiphase flow theory in combination with data measured by the inlet flowmeter F1, the standpipe pressure gauge G1, the outlet flowmeter F2 and the casing pressure gauge G2; the automatic control throttle valve opening degree automatic adjustment module 14 is configured to send a control instruction to the automatic control throttle valve J1 by taking a prediction result of the wellbore flow parameter analysis and correction module as an adjustment basis so as to automatically control the opening degree, and control the bottomhole pressure within a design range; the measured/designed inlet displacement curve module 15 is configured to draw data of the outlet and inlet displacements measured by the inlet flowmeter F1 and the outlet flowmeter F2, which are distributed over time, into a visual graph; the measured casing pressure curve module 16 is configured to draw data of the casing pressure measured by the casing pressure gauge G2, which are distributed over time, into a visual graph; the measured standpipe pressure curve module 17 is configured to draw data of the standpipe pressure measured by the standpipe pressure gauge G1, which are distributed over time, into a visual graph; the designed standpipe pressure curve module 18 is configured to draw data of the designed standpipe pressure, which are distributed over time, into a visual graph; and the designed casing pressure curve module 19 is configured to draw data of the designed casing pressure, which are distributed over time, into a visual graph.

(7) An intelligent throttled well-killing method for overflow in high-temperature and high-pressure deep drilling comprises the following steps:

(8) S1. before well-killing starts, solving a formation pressure and a designed standpipe pressure by closing a blowout preventer 5; calculating a wellbore fluid distribution by using a wellbore flow parameter analysis and correction module 13; displaying designed standpipe pressure data during well-killing on a designed standpipe pressure curve module 18 in an intelligent throttled well-killing construction operation console 3; displaying designed casing pressure data on a designed casing pressure curve module 19 in the intelligent throttled well-killing construction operation console 3; displaying designed well-killing displacement data on a measured/designed outlet and inlet displacement curve module 15 in the intelligent throttled well-killing construction operation console 3; inspecting whether a switch position of each gate valve is normal, so that the throttle manifold is in a standby condition.

(9) In the step S1, the fluid distribution in a wellbore annulus comprises an overflow height in the wellbore annulus, a gas holdup rate and a liquid holdup rate in the wellbore annulus, a pressure distribution in the wellbore annulus, and a gas flow velocity and a liquid flow velocity in the wellbore annulus.

(10) In the step S1, the method for calculating the wellbore fluid distribution by the wellbore flow parameter analysis and correction module 13 is as follows:

(11) S101: during a period after the overflow occurs to the stage before shut-in, measuring data in real time through the inlet flowmeter F1, the outlet flowmeter F2, and the standpipe pressure gauge G1 to obtain the fluid distribution in the wellbore annulus in combination with the wellbore transient multiphase fluid mechanic model;

(12) the wellbore transient multiphase fluid mechanics model and an initial calculation condition and a calculation boundary condition are as follows:

(13) a calculation model:

(14) $\{\begin{array}{cc}\begin{array}{c}\mathrm{gas}\text{-}\mathrm{phase}\\ \mathrm{continuity}\mathrm{equation}\text{:}\end{array}& \frac{\partial }{\partial z}\left(A{\rho }_g{E}_g{v}_g\right)+\frac{\partial }{\partial t}\left(A{\rho }_g{E}_g\right)={\Gamma }_g\\ \begin{array}{c}\mathrm{liquid}\text{-}\mathrm{phase}\\ \mathrm{continuity}\mathrm{equation}\text{:}\end{array}& \frac{\partial }{\partial z}\left(A{\rho }_l{E}_l{v}_l\right)+\frac{\partial }{\partial t}\left(A{\rho }_l{E}_l\right)=0\\ \mathrm{motion}\mathrm{equation}\text{:}& \frac{\partial }{\partial t}\left(A{\rho }_l{E}_l{v}_l+A{\rho }_g{E}_g{v}_g\right)+\\ & \frac{\partial }{\partial z}\left(A{\rho }_l{E}_l{v}_l^2+A{\rho }_g{E}_g{v}_g^2\right)+\\ & A\frac{\partial P}{\partial z}+A{\rho }_{m}g+{A\left(\frac{\partial P}{\partial z}\right)}_{\mathrm{fr}}=0\end{array}\hspace{1em}\hspace{1em}$

(15) the initial calculation condition:

(16) $\{\begin{array}{c}{E}_g\left(0,j\right)=0,E_l\left(0,j\right)=1\\ v_g\left(0,j\right)=0,v_l\left(0,j\right)=q_l\text{/}A\\ P\left(0,j\right)=\rho \mathrm{gj}+P_f\end{array}$

(17) the calculation boundary condition:

(18) $\{\begin{array}{c}{P}_b\left(t\right)=P_{d\_\mathrm{measured}}\left(t\right)+\rho \mathrm{gH}-P_{d\_f}\\ q_o\left(t\right)=q_{o\_\mathrm{measured}}\left(t\right)\end{array}\hspace{1em}$

(19) wherein, A is a cross-sectional area of the annulus, m.sup.2; ρ.sub.g is a gas density, kg/m.sup.3; E.sub.g is a gas holdup rate, dimensionless; ν.sub.g is a gas flow rate, m/s; Γ.sub.g is a gas source term in a continuity equation, kg/m/s; ρ.sub.l is a density of drilling fluid, kg/m.sup.3; E.sub.l is a liquid holdup rate, E.sub.l+E.sub.g=1, dimensionless; ν.sub.l is a flow velocity of drilling fluid, m/s; P is a pressure, Pa; ρ.sub.m is a density of a mixture, ρ.sub.m=ρ.sub.lE.sub.l+ρ.sub.gE.sub.g, kg/m.sup.3;

(20) ${\left(\frac{\partial P}{\partial z}\right)}_{\mathrm{fr}}\hspace{1em}$
is a friction pressure drop, MPa/m; j is a position, m; P.sub.f is an annulus pressure loss, MPa; H is a well depth where gas invasion occurs, m; t is time, s; q.sub.l is an inlet displacement of the drilling fluid, L/s; P.sub.b(t) is a bottomhole pressure at time t, MPa; P.sub.d_measured(t) is a standpipe pressure measured at time t, MPa; P.sub.d_f is a pressure loss in a drill string, MPa; q.sub.o(t) is an outlet displacement of the wellhead annulus, L/s; q.sub.o_measured(t) is an outlet displacement of the wellhead annulus measured at time t, L/s.

(21) The wellbore transient multiphase fluid mechanics model is solved iteratively using an implicit difference method to obtain the wellbore annulus fluid distribution.

(22) S102: during a period after shut-in to a stage before well-killing, measuring data by using a casing pressure gauge G2 in real time; based on the fluid distribution state in the wellbore annulus before shut-in, obtaining the fluid distribution in the wellbore annulus by using a shut-in wellbore fluid mechanics model that takes into account shut-in after-flow and slippage effects.

(23) The shut-in wellbore fluid mechanics model that takes into account shut-in after-flow and slippage effects is as follows:

(24) $\underset{i=1}{\overset{n}{.Math.}}{A}_a\left(t,i\right)E_g\left(t,i\right)h_g\left(t,i\right)-\underset{i=1}{\overset{n}{.Math.}}{A}_1\left(t-\Delta t,i\right)E_g\left(t-\Delta t,i\right)h_g\left(t-\Delta t,i\right)=\underset{x=1}{\overset{X}{.Math.}}{C}_l\frac{P_x\left(t\right)-P_x\left(t-\Delta t\right)}{2}{V}_{\mathrm{lx}}\left(t\right)+V_f\left(t\right)$

(25) wherein, A.sub.a(t,i) is a cross-section area of the annulus, m.sup.2; E.sub.g(t,i) is a unit gas holdup rate, %; h.sub.g(t,i) is a unit length, m; P.sub.x(t) is a pressure at position x in the wellbore; V.sub.tx(t) is a volume of the drilling fluid in a wellbore unit, m.sup.3; V.sub.f(t) is a filtration loss of the drilling fluid per unit time step, m.sup.3; Δt is a time step, s.

(26) The shut-in wellbore fluid mechanics model that takes into account shut-in after-flow and slippage effects is solved by using a Gauss-Seidel iterative method to obtain the fluid distribution in the wellbore annulus.

(27) In the step S1, the normal positions of various gate valves when the throttle manifold is in the standby condition are as follows: a flat gate valve J.sub.2a, a flat gate valve J.sub.3b, a flat gate valve J.sub.3a, a flat gate valve J.sub.5, a flat gate valve J.sub.6a, a flat gate valve J.sub.7, a flat gate valve J.sub.8, a flat gate valve 2#, and a flat gate valve 3# are opened, and a flat gate valve J.sub.3b, a flat gate valve J.sub.9, a flat gate valve J.sub.11, a flat gate valve J.sub.6b, a flat gate valve J.sub.10, a flat gate valve 14, and a flat gate valve 4# are closed.

(28) S2. opening a flat gate valve 3# and slowly starting a mud pump 2; injecting well-killing fluid in a drilling fluid tank 1 into a wellbore through a drill string 8; adjusting an automatic control throttle valve J.sub.1 to make a measured value of a casing pressure gauge G2 equal to a shut-in casing pressure and keep it unchanged until the displacement reaches the designed well-killing displacement, and during this period, updating and correcting the wellbore fluid distribution in real time through the wellbore flow parameter analysis and correction module 13.

(29) In the step S2, the method for adjusting the automatic control throttle valve J.sub.1 is as follows: monitoring a measured value of the casing pressure gauge G2 in real time, and comparing the measured value with the shut-in casing pressure value; when there is a deviation between the two values, sending the deviation value of the two values to the automatic opening degree adjustment module 14 of the automatic throttle valve; sending a control instruction to the automatic control throttle valve J1 through the automatic opening degree adjustment module 14 of the automatic throttle valve; adjusting the opening degree of the throttle valve; and maintaining the wellhead casing pressure equal to the shut-in casing pressure.

(30) In the step S2, the method for determining whether the displacement reaches the designed well-killing displacement is as follows: determining whether the displacement has reached the designed well-killing displacement based on a measured/designed displacement curve of well-killing fluid in a measured/designed outlet and inlet displacement curve module 15 in the intelligent throttled well-killing construction operation console 3.

(31) In the step S2, the method for updating and correcting the wellbore fluid distribution in real time includes: measuring a well-killing fluid outlet displacement, a well-killing fluid inlet displacement, a standpipe pressure and a casing pressure by using the inlet flowmeter F.sub.1, the outlet flowmeter F.sub.2, the standpipe pressure gauge G.sub.1 and the casing pressure gauge G.sub.2 in real time; and updating and correcting the wellbore fluid distribution obtained in the step S1 in real time in combination with the wellbore transient multiphase fluid mechanics model;

(32) the wellbore transient multiphase fluid mechanics model and an initial calculation condition and a calculation boundary condition are as follows:

(33) $\{\begin{array}{cc}\begin{array}{c}\mathrm{gas}\text{-}\mathrm{phase}\\ \mathrm{continuity}\mathrm{equation}\text{:}\end{array}& \frac{\partial }{\partial z}\left(A{\rho }_g{E}_g{v}_g\right)+\frac{\partial }{\partial t}\left(A{\rho }_g{E}_g\right)={\Gamma }_g\\ \begin{array}{c}\mathrm{liquid}\text{-}\mathrm{phase}\\ \mathrm{continuity}\mathrm{equation}\text{:}\end{array}& \frac{\partial }{\partial z}\left(A{\rho }_l{E}_l{v}_l\right)+\frac{\partial }{\partial t}\left(A{\rho }_l{E}_l\right)=0\\ \mathrm{motion}\mathrm{equation}\text{:}& \frac{\partial }{\partial t}\left(A{\rho }_l{E}_l{v}_l+A{\rho }_g{E}_g{v}_g\right)+\\ & \frac{\partial }{\partial z}\left(A{\rho }_l{E}_l{v}_l^2+A{\rho }_g{E}_g{v}_g^2\right)+\\ & A\frac{\partial P}{\partial z}+A{\rho }_{m}g+{A\left(\frac{\partial P}{\partial z}\right)}_{\mathrm{fr}}=0\end{array}\hspace{1em}\hspace{1em}$

(34) the initial calculation condition:

(35) 0$\hspace{1em}\{\begin{array}{c}{E}_g\left(S2\_0,j\right)=E_g\left(S1\mathrm{\_end},j\right),E_l\left(S2\_0,j\right)=1-E_g\left(S1\mathrm{\_end},j\right)\\ v_g\left(S2\_0,j\right)=v_g\left(S1\mathrm{\_end},j\right),v_l\left(S2\_0,j\right)=v_l\left(S1\mathrm{\_end},j\right)\\ P\left(S2\_0,j\right)=P\left(S1\mathrm{\_end},j\right)\end{array}\hspace{1em}$

(36) the boundary calculation condition:

(37) $\{\begin{array}{c}{P}_b\left(t\right)=P_{d\_\mathrm{measured}}\left(t\right)+\rho \mathrm{gH}-P_{d\_f}\\ q_o\left(t\right)=q_{o\_\mathrm{measured}}\left(t\right),q_l\left(t\right)=q_{l\_\mathrm{measured}}\left(t\right)\\ P_c\left(t\right)=P_{c\_\mathrm{measured}}\left(t\right)\end{array}\hspace{1em}$

(38) wherein, A is a cross-sectional area of the annulus, m.sup.2; ρ.sub.g is a gas density, kg/m.sup.3; E.sub.g is a gas holdup rate, dimensionless; ν.sub.g is a gas flow rate, m/s; Γ.sub.g is a gas source term in a continuity equation, kg/m/s; ρ.sub.l is a density of drilling fluid, kg/m.sup.3; E.sub.l is a liquid holdup rate, E.sub.l+E.sub.g=1, dimensionless; ν.sub.l is a flow velocity of drilling fluid, m/s; P is a pressure, Pa; ρ.sub.m is a density of a mixture, ρ.sub.m=ρ.sub.lE.sub.l+ρ.sub.gE.sub.g, kg/m.sup.3;

(39) ${\left(\frac{\partial P}{\partial z}\right)}_{\mathrm{fr}}$
is a friction pressure drop, MPa/m; j is a position, m; P.sub.f is an annulus pressure loss, MPa; H is a well depth where gas invasion occurs, m; t is time, s; S2_0 is a start time of the step S2; S1_end is an end time of the step S1; q.sub.l(t) is an inlet displacement of the drilling fluid, L/s; q.sub.l_measured(t) is an wellhead inlet displacement measured at time t, L/s; P.sub.b(t) is a bottomhole pressure at time t, MPa; P.sub.d_measured(t) is a standpipe pressure measured at time t, MPa; P.sub.d_f is a pressure loss in a drill string, MPa; q.sub.o(t) is an outlet displacement of the wellhead annulus, L/s; q.sub.l_measured(t) is an outlet displacement of the wellhead annulus measured at time t, L/s; P.sub.c(t) is a wellhead casing pressure, MPa; and P.sub.c_measured(t) is a wellhead casing pressure measured at time t, MPa.

(40) The wellbore transient multiphase fluid mechanics model is solved iteratively using an implicit difference method to obtain the wellbore annulus fluid distribution.

(41) S3. keeping the displacement of the well-killing fluid constant, and injecting the well-killing fluid in the drilling fluid tank 1 into the wellbore through the drill string 8; gradually discharging overflow 10 above a drill bit 11 from the wellbore through the annulus 9, and during this period, updating and correcting the wellbore fluid distribution in real time through the wellbore flow parameter analysis and correction module 13, wherein when the measured value of the standpipe pressure gauge G.sub.1 deviates from the designed standpipe pressure, it is indicated that the bottomhole pressure has deviated from the designed bottomhole pressure; predicting and calculating a development trend of the bottomhole pressure by using the wellbore flow parameter analysis and correction module 13; determining a target pressure adjustment value ΔP.sub.b; sending a target value ΔP.sub.b to be adjusted to an automatic opening degree adjustment module 14 for an automatic control throttle valve; sending a throttle valve adjustment instruction; and adjusting the automatic control throttle valve J.sub.1 to make a measured value of the standpipe pressure coincident with a designed value.

(42) In the step S3, the method for updating and correcting the wellbore fluid distribution in real time includes: measuring a well-killing fluid outlet displacement, a well-killing fluid inlet displacement, a standpipe pressure and a casing pressure by using the inlet flowmeter F.sub.1, the outlet flowmeter F.sub.2, the standpipe pressure gauge G.sub.1 and the casing pressure gauge G.sub.2 in real time; and updating and correcting the wellbore fluid distribution obtained in the step S1 in real time in combination with the wellbore transient multiphase fluid mechanics model;

(43) the wellbore transient multiphase fluid mechanics model is as follows:

(44) $\{\begin{array}{cc}\begin{array}{c}\mathrm{gas}\text{-}\mathrm{phase}\\ \mathrm{continuity}\mathrm{equation}\text{:}\end{array}& \frac{\partial }{\partial z}\left(A{\rho }_g{E}_g{v}_g\right)+\frac{\partial }{\partial t}\left(A{\rho }_g{E}_g\right)={\Gamma }_g\\ \begin{array}{c}\mathrm{liquid}\text{-}\mathrm{phase}\\ \mathrm{continuity}\mathrm{equation}\text{:}\end{array}& \frac{\partial }{\partial z}\left(A{\rho }_l{E}_l{v}_l\right)+\frac{\partial }{\partial t}\left(A{\rho }_l{E}_l\right)=0\\ \mathrm{motion}\mathrm{equation}\text{:}& \frac{\partial }{\partial t}\left(A{\rho }_l{E}_l{v}_l+A{\rho }_g{E}_g{v}_g\right)+\\ & \frac{\partial }{\partial z}\left(A{\rho }_l{E}_l{v}_l^2+A{\rho }_g{E}_g{v}_g^2\right)+\\ & A\frac{\partial P}{\partial z}+A{\rho }_{m}g+{A\left(\frac{\partial P}{\partial z}\right)}_{\mathrm{fr}}=0\end{array}\hspace{1em}\hspace{1em}$

(45) the initial calculation condition:

(46) $\hspace{1em}\{\begin{array}{c}{E}_g\left(S3\_0,j\right)=E_g\left(S2\mathrm{\_end},j\right),E_l\left(S3\_0,j\right)=1-E_g\left(S2\mathrm{\_end},j\right)\\ v_g\left(S3\_0,j\right)=v_g\left(S2\mathrm{\_end},j\right),v_l\left(S3\_0,j\right)=v_l\left(S2\mathrm{\_end},j\right)\\ P\left(S3\_0,j\right)=P\left(S2\mathrm{\_end},j\right)\end{array}\hspace{1em}$

(47) the calculation boundary condition:

(48) $\{\begin{array}{c}{P}_b\left(t\right)=P_{d\_\mathrm{measured}}\left(t\right)+\rho \mathrm{gH}-P_{d\_f}\\ q_o\left(t\right)=q_{o\_\mathrm{measured}}\left(t\right),q_l\left(t\right)=q_{l\_\mathrm{measured}}\left(t\right)\\ P_c\left(t\right)=P_{c\_\mathrm{measured}}\left(t\right)\end{array}\hspace{1em}$

(49) wherein, A is a cross-sectional area of the annulus, m.sup.2; ρ.sub.g is a gas density, kg/m.sup.3; E.sub.g is a gas holdup rate, dimensionless; ν.sub.g is a gas flow rate, m/s; Γ.sub.g is a gas source term in a continuity equation, kg/m/s; ρ.sub.l is a density of drilling fluid, kg/m.sup.3; E.sub.l is a liquid holdup rate, E.sub.l+E.sub.g=1, dimensionless; ν.sub.l is a flow velocity of the drilling fluid, m/s; P is a pressure, Pa; ρ.sub.m is a density of a mixture, ρ.sub.m=ρ.sub.lE.sub.l+ρ.sub.gE.sub.g, kg/m.sup.3;

(50) ${\left(\frac{\partial P}{\partial z}\right)}_{\mathrm{fr}}$
is a friction pressure drop, MPa/m; j is a position, m; P.sub.f is an annulus pressure loss, MPa; H is a well depth where gas invasion occurs, m; t is time, s; S3_0 is a start time in the step S3; S2_end is a start time of the step S2; q.sub.l(t) is an inlet displacement of the drilling fluid, L/s; q.sub.l_measured(t) is a wellhead inlet displacement measured at time t, L/s; P.sub.b(t) is a bottomhole pressure at time t, MPa; P.sub.d_measured(t) is a standpipe pressure measured at time t, MPa; P.sub.d_f is a pressure loss in a drill string, MPa; q.sub.o(t) is an outlet displacement of the wellhead annulus, a L/s; q.sub.o_measured(t) is an outlet displacement of the wellhead annulus measured at time t, L/s; P.sub.c(t) is a wellhead casing pressure measured at time t, MPa; P.sub.c_measured(t) is a wellhead casing pressure measured at time t, MPa.

(51) The wellbore transient multiphase fluid mechanics model is solved iteratively using an implicit difference method.

(52) In the step S3, when the measured value of the standpipe pressure gauge F.sub.1 deviates from the designed standpipe pressure, a development trend of the bottomhole pressure is predicated and calculated through the wellbore flow parameter analysis and correction module 13, and the method for determining the target pressure adjustment value is as follows:

(53) the target pressure adjustment value is ΔP.sub.b=ΔP.sub.b1ΔP.sub.b2+ΔP.sub.b3;

(54) wherein, ΔP.sub.b is the target pressure adjustment value, MPa; ΔP.sub.b1 is a deviation value at time (t1) when the measured value of the standpipe pressure gauge F.sub.1 is monitored to deviate the designed standpipe pressure, MPa; ΔP.sub.b2 is a change value of the bottomhole pressure within a period (t0-t1) when bottomhole pressure waves are transmitted to the wellhead standpipe pressure gauge F.sub.1, MPa; ΔP.sub.b3 is a change in bottomhole pressure within a period (t1-t2) when a wellhead back pressure is transmitted to the bottomhole after the throttle valve is actuated, MPa; t0 is a time when the bottomhole pressure deviates from the design, s; t1 is a time when the measured value of the standpipe pressure gauge F.sub.1 deviates from the designed standpipe pressure, s; t2 is a time when the wellhead back pressure is applied to the bottomhole after the opening degree of the automatic throttle valve J.sub.1 is adjusted, s;

(55) $\Delta t_{0-1}=t1-t0=\frac{H}{v_{w\_\mathrm{in}\_\mathrm{pipe}}}$
is a time length from time t0 to time t1, that is, the time required for the bottomhole pressure waves being transmitted to the wellhead standpipe pressure gauge F.sub.1, s; H is a well depth, m; ν.sub.w_m_pipe is a pressure wave propagation velocity in the drill string, m/s;

(56) $\Delta t_{1-2}=t2-t1=\frac{H}{v_{w\_\mathrm{in}\_\mathrm{annulus}}}$
is a time length from time t1 to time t2, that is, the time length that pressure waves of the wellhead back pressure are transmitted to the bottomhole after the opening degree of the automatic throttle valve J.sub.1 is adjusted, s; ν.sub.w_in_annulus is a pressure wave propagation velocity in the annulus, m/s.

(57) The calculation method of ΔP.sub.b1 is Δ.sub.P1=P.sub.d_measured−P.sub.d_designed;

(58) wherein, P.sub.d_measured is a measured value of the standpipe pressure gauge F.sub.1 when the standpipe pressure deviates, MPa; P.sub.d_designed is a designed standpipe pressure value, MPa.

(59) The calculation method of ΔP.sub.b2 is as follows: predicting a bottomhole pressure at time t1 after Δt.sub.0-1 by taking a parameter at time t0 as an initial state by using the wellbore transient multiphase fluid mechanics model.

(60) The wellbore transient multiphase fluid mechanics model and an initial calculation condition and a calculation boundary condition are as follows:

(61) $\{\begin{array}{cc}\begin{array}{c}\mathrm{gas}\text{-}\mathrm{phase}\\ \mathrm{continuity}\mathrm{equation}\text{:}\end{array}& \frac{\partial }{\partial z}\left(A{\rho }_g{E}_g{v}_g\right)+\frac{\partial }{\partial t}\left(A{\rho }_g{E}_g\right)={\Gamma }_g\\ \begin{array}{c}\mathrm{liquid}\text{-}\mathrm{phase}\\ \mathrm{continuity}\mathrm{equation}\text{:}\end{array}& \frac{\partial }{\partial z}\left(A{\rho }_l{E}_l{v}_l\right)+\frac{\partial }{\partial t}\left(A{\rho }_l{E}_l\right)=0\\ \mathrm{motion}\mathrm{equation}\text{:}& \frac{\partial }{\partial t}\left(A{\rho }_l{E}_l{v}_l+A{\rho }_g{E}_g{v}_g\right)+\\ & \frac{\partial }{\partial z}\left(A{\rho }_l{E}_l{v}_l^2+A{\rho }_g{E}_g{v}_g^2\right)+\\ & A\frac{\partial P}{\partial z}+A{\rho }_{m}g+{A\left(\frac{\partial P}{\partial z}\right)}_{\mathrm{fr}}=0\end{array}\hspace{1em}\hspace{1em}$

(62) the initial calculation condition:

(63) 0$\{\begin{array}{c}{E}_g\left(0,j\right)=E_g\left(t0,j\right),E_l\left(0,j\right)=1-E_g\left(t0,j\right)\\ v_g\left(0,j\right)=v_g\left(t0,j\right),v_l\left(0,j\right)=v_l\left(t0,j\right)\\ P\left(0,j\right)=P\left(t0,j\right)\end{array}\hspace{1em}$

(64) the calculation boundary condition:

(65) $\{\begin{array}{c}{P}_b\left(t\right)=P_{d\_\mathrm{measured}}\left(t0\right)+\rho \mathrm{gH}-P_{d\_f}\\ q_o\left(t\right)=q_{o\_\mathrm{measured}}\left(t0\right),q_l\left(t\right)=q_{l\_\mathrm{measured}}\left(t0\right)\\ P_c\left(t\right)=P_{c\_\mathrm{measured}}\left(t0\right)\end{array}\hspace{1em}$

(66) wherein, A is a cross-sectional area in the annulus, m.sup.2; ρ.sub.g is a gas density, kg/m.sup.3; E.sub.g is a gas holdup rate, dimensionless; ν.sub.g is a gas flow rate, m/s; Γ.sub.g is a gas source term in a continuity equation, kg/m/s; ρ.sub.l is a density of the drilling fluid, kg/m.sup.3; E.sub.l is a liquid holdup rate, E.sub.l+E.sub.g=1, dimensionless; ν.sub.1 is a flow velocity of the drilling fluid, m/s; P is a pressure, Pa; ρ.sub.m is a density of a mixture, ρ.sub.m=ρ.sub.lE.sub.l+ρ.sub.gE.sub.g, kg/m.sup.3;

(67) ${\left(\frac{\partial P}{\partial z}\right)}_{\mathrm{fr}}$
is a friction pressure drop, MPa/m; j is a position, m; P.sub.f is an annulus pressure loss, MPa; H is a well depth where gas invasion occurs, m; t is time, s; q.sub.l(t) is an inlet displacement of the drilling fluid, L/s; q.sub.l_measured(t0) is a wellhead inlet displacement measured at time t0 L/s; P.sub.b(t) is a bottomhole pressure at time t0, MPa; P.sub.d_measured(t0) is a standpipe pressure measured at time t0, MPa; P.sub.d_f is a pressure loss in the drill string, MPa; q.sub.o(t) is an outlet displacement of the wellhead annulus, L/s; q.sub.o_measured(t0) is an outlet displacement of the wellhead annulus measured at time t0, L/s; P.sub.c(t) is a wellhead casing pressure, MPa; P.sub.c_measured(t0) is a wellhead casing pressure measured at time t0, MPa.

(68) A bottomhole pressure P.sub.b(t1) at time t1 is solved by the wellbore transient multiphase fluid mechanics model iteratively by using an implicit difference method;

(69) the calculation formula ΔP.sub.b2 is ΔP.sub.b2=P.sub.b(t1)−P.sub.d_measured;

(70) the calculation method of ΔP.sub.b3 is as follows: predicting a bottomhole pressure at time t2 after Δt.sub.1-2 by taking a parameter at time t1 as an initial state by using the wellbore transient multiphase fluid mechanics model.

(71) The wellbore transient multiphase fluid mechanics model and an initial calculation condition and a calculation boundary are as follows:

(72) $\{\begin{array}{cc}\begin{array}{c}\mathrm{gas}\text{-}\mathrm{phase}\\ \mathrm{continuity}\mathrm{equation}\text{:}\end{array}& \frac{\partial }{\partial z}\left(A{\rho }_g{E}_g{v}_g\right)+\frac{\partial }{\partial t}\left(A{\rho }_g{E}_g\right)={\Gamma }_g\\ \begin{array}{c}\mathrm{liquid}\text{-}\mathrm{phase}\\ \mathrm{continuity}\mathrm{equation}\text{:}\end{array}& \frac{\partial }{\partial z}\left(A{\rho }_l{E}_l{v}_l\right)+\frac{\partial }{\partial t}\left(A{\rho }_l{E}_l\right)=0\\ \mathrm{motion}\mathrm{equation}\text{:}& \frac{\partial }{\partial t}\left(A{\rho }_l{E}_l{v}_l+A{\rho }_g{E}_g{v}_g\right)+\\ & \frac{\partial }{\partial z}\left(A{\rho }_l{E}_l{v}_l^2+A{\rho }_g{E}_g{v}_g^2\right)+\\ & A\frac{\partial P}{\partial z}+A{\rho }_{m}g+{A\left(\frac{\partial P}{\partial z}\right)}_{\mathrm{fr}}=0\end{array}\hspace{1em}\hspace{1em}$

(73) the initial calculation condition:

(74) $\{\begin{array}{c}{E}_g\left(0,j\right)=E_g\left(t1,j\right),E_l\left(0,j\right)=1-E_g\left(t1,j\right)\\ v_g\left(0,j\right)=v_g\left(t1,j\right),v_l\left(0,j\right)=v_l\left(t1,j\right)\\ P\left(0,j\right)=P\left(t1,j\right)\end{array}\hspace{1em}$

(75) the calculation boundary calculation condition:

(76) $\{\begin{array}{c}{P}_b\left(t\right)=P_{d\_\mathrm{measured}}\left(t1\right)+\rho \mathrm{gH}-P_{d\_f}\\ q_o\left(t\right)=q_{o\_\mathrm{measured}}\left(t1\right),q_l\left(t\right)=q_{l\_\mathrm{measured}}\left(t1\right)\\ P_c\left(t\right)=P_{c\_\mathrm{measured}}\left(t1\right)\end{array}\hspace{1em}$