Dynamic ECD prediction method for horizontal wells based on formation-wellbore transient temperature and pressure coupling

Abstract

The present invention discloses a dynamic ECD prediction method for horizontal wells based on formation-wellbore transient temperature and pressure coupling. The method includes measuring the thermophysical properties of core and cement stone, and the variation pattern of drilling fluid density with temperature and pressure. The transient temperature field inside the horizontal well drill string and the wellbore annulus is analyzed using the API RP 13D rheological drilling fluid circulation temperature field control equation during drilling. A dynamic ECD (wellbore annulus transient circulating pressure) prediction model coupled with annular temperature and pressure disturbances is established. This model provides theoretical and technical guidance for accurately controlling wellbore pressure during (ultra-) deep horizontal well drilling, and the evaluation results are highly credible.

Description

Technical Field

[0001] The invention relates to a horizontal well dynamic ECD prediction method based on formation-wellbore transient temperature and pressure coupling, and belongs to the technical field of (ultra) deep oil and gas drilling. Background Art

[0002] In deep well drilling, narrow safe density windows, multiple pressure systems, and pressure-sensitive formations can easily lead to complex downhole situations, such as lost circulation and kicks, often resulting in "coexistent leakage and spillage." Furthermore, improper drilling fluid density can lead to wellbore collapse (low wellbore density creates the risk of block loss and stuck pipe) and the formation of drilling-induced fractures in the wellbore (high wellbore density), extending non-drilling time and increasing drilling costs. Therefore, precisely controlling wellbore fluid injection pressure is crucial for effectively preventing complex downhole accidents. However, during drilling in deep formations, the wellhead drilling fluid is heated as it passes through the drillstring and reaches the bottomhole, gradually increasing its temperature above the wellhead temperature. As it flows through the drill bit and returns to the surface through the annulus, the drilling fluid at the bottom of the wellbore absorbs further formation heat, gradually increasing its temperature (but still below the original formation temperature). After returning above the critical wellbore depth, the drilling fluid temperature gradually rises above the original formation temperature. Therefore, drilling fluid density is subject to dynamic changes influenced by wellbore pressure and the circulating temperature field, and prediction of wellbore ECD should also incorporate time effects.

[0003] Currently, various methods exist for predicting circulating temperature fields and wellbore ECD. For example, Southwest Petroleum University's invention patent, publication number CN113935092A, discloses a dual-porosity thermoelastic coupling method for evaluating wellbore stability in fractured formations. However, this method's circulating temperature field prediction fails to consider the influence of the actual wellbore structure (casing and cement sheath) and is applicable only to vertical wells. Furthermore, a dynamic ECD (transient circulating pressure in the wellbore annulus) prediction model that couples annular temperature and pressure perturbations has not been established, making it impossible to accurately predict the dynamic changes in wellbore ECD in (ultra-)deep horizontal wells.

[0004] Southwest Petroleum University's invention patent, publication number CN103061753A, discloses a device for measuring downhole flow while drilling and monitoring early overflows. The device measures annular pressure and temperature through pressure and temperature sensors installed inside the annular fluid guide device. The sensors convert the physical signals of the annular pressure and temperature into electrical signals, which are then recorded, stored, and uploaded via a circuit board. The measuring device connects to the MWD via an MWD connector and uploads the measured data to the surface in real time. By comprehensively analyzing and processing the real-time uploaded downhole data and related ground data, it is possible to identify downhole overflows and other working conditions in real time. However, for drilling in deep formations, the service life of sensors and circuit boards is easily affected by high-temperature and high-pressure environments, reducing the accuracy of annular ECD predictions.

[0005] Although the above two patents and other existing technical solutions have achieved certain technical effects, they have not established a dynamic ECD (transient circulating pressure in the wellbore annulus) prediction model that couples the annular space temperature and pressure disturbance effects. The temperature field prediction is mostly solved by numerical methods, and on-site operations are limited. Summary of the Invention

[0006] The present invention mainly overcomes the deficiencies in the prior art and proposes a horizontal well dynamic ECD prediction method based on formation-wellbore transient temperature and pressure coupling.

[0007] The present invention provides a technical solution to solve the above technical problems: a horizontal well dynamic ECD prediction method based on formation-wellbore transient temperature and pressure coupling, comprising the following steps:

[0008] Step 1: Use a gas permeameter to test the porosity of the core;

[0009] Step 2: Use a thermal expansion coefficient meter and a Hot Disk thermal constant analyzer to test the thermal physical parameters of the core and cement paste;

[0010] Step 3: Using the API RP 13D rheological drilling fluid circulation temperature field governing equations during drilling and Laplace transform processing, derive the analytical solution for the transient temperature field inside the horizontal well drill string and the wellbore annulus;

[0011] Step 4: Using the coupled relationship between drilling fluid density, pressure and temperature measured by a high-temperature and high-pressure density meter, a dynamic ESD prediction model is established that couples the annular temperature and static liquid column pressure disturbance effects.

[0012] Step 5: Based on the dynamic ESD prediction model and combined with the annular pressure loss calculation method, a wellbore annulus dynamic ECD (wellbore annulus transient circulation pressure) prediction model is established.

[0013] A further technical solution is that the thermophysical parameters in step 2 include solid phase thermal expansion coefficient, liquid phase thermal expansion coefficient, thermal conductivity, and specific heat capacity.

[0014] A further technical solution is that the internal temperature of the horizontal well drill string and the wellbore annulus temperature in step 3 are further subdivided into a vertical well section, a deflection section and a horizontal section, and the expressions thereof include:

[0015] Vertical wellbore annulus and inside the drill string The analytical solution of the temperature field (in the Laplace space domain) is expressed as:

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[0018] Wellbore annulus in the deflection section and inside the drill string The analytical solution of the temperature field (in the Laplace space domain) is denoted as

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[0023] Horizontal wellbore annulus and inside the drill string The analytical solution of the temperature field (in the Laplace space domain) is denoted as

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[0026] Where A0 is the geothermal gradient, ℃ / m; B0 is the surface temperature, ℃; T0 is the initial formation temperature T0=A0z+B0, ℃; z j The range of variation is [0, H KOP ],z l The range of change is (H KOP , H i ],z h The range of change is (H i , H]. KOP is the well depth at the inclination point, m; H hv is the vertical depth of the horizontal section, m; H hl is the inclined depth at the end of the build-up section (beginning of the horizontal section), m; H is the actual well depth. KOP is the well inclination angle at the inclination point, °; α hv is the actual well inclination angle of the horizontal section, °; ​​K z is the slope rate, (°) / 30m; K0() is the modified second-kind 0th-order Bessel function; s is the complex frequency introduced by Laplace transform, which is related to time.

[0027] A further technical solution is that the dynamic ESD calculation formula coupled with the annular space temperature and the static liquid column pressure disturbance in step 4 is:

[0028]

[0029] Γ(P(z, t), T a (z, t)) = a(P(z, t) - P0) - b(T a (z, t)-T0)+c(T a(z, t)-T0) 2

[0030] Wherein, the computational node length Δh is defined as Δh = h / m, m; m is the number of computational nodes, dimensionless; h is the well depth at the study location, m; the wellhead pressure P0 is P(z = 0, t) = 0.1, MPa; the wellhead annulus temperature T0 is defined as T(h = 0, t) = T a ,℃;P i When (z, t) is the cycle time t, the depth z = Δh × i (i = 1, 2, ... n) in the well is affected by the annular temperature T a，i (z, t) is the wellbore hydrostatic column pressure, MPa; g is the acceleration due to gravity, 9.81 m / s 2 ρ m0 (P0, T0) is the density of the drilling fluid under the action of wellhead pressure P0 and temperature T0, kg / m 3 Γ(P i (z,t),T a，i (z, t)) is the density-pressure-temperature coupling function proposed by Wang Haige et al.

[0031] The annular static liquid column pressure P at the well depth h at the research location h (z=h, t) is:

[0032]

[0033] MPa; a, b, c: drilling fluid characteristic constants, 1 / MPa, 1 / ℃, 1 / (℃·℃).

[0034] A further technical solution is that the calculation formula of the wellbore annulus dynamic ECD (wellbore annulus transient cyclic pressure) in step 5 is:

[0035]

[0036] p m (z=h,t)=ECD(z=h,t)gh

[0037] Where, ECD(z=h, t) is the equivalent circulating density corresponding to the study depth h and drilling fluid circulation time t, kg / m 3 ;p m (z = h, t) is the transient circulating pressure in the wellbore annulus corresponding to the study depth h and the drilling fluid circulation time t, MPa; ΔP bed : annular pressure loss per unit length when there is a cuttings bed, Pa;

[0038] The present invention has the following beneficial effects: the horizontal well dynamic ECD prediction method based on formation-wellbore transient temperature and pressure coupling proposed in the present invention is simple to understand, easy to operate, and low-cost. It provides a scientific basis for the precise control of annular space ECD in (ultra) deep horizontal well drilling and can effectively prevent the occurrence of complex underground accidents. BRIEF DESCRIPTION OF THE DRAWINGS

[0039] Figure 1 It is a flowchart of the present invention. DETAILED DESCRIPTION

[0040] The technical solutions of the present invention will be described clearly and completely below with reference to the accompanying drawings. It is apparent that the embodiments described are only a portion of the embodiments of the present invention, not all of them. All other embodiments derived by persons of ordinary skill in the art based on the embodiments of the present invention without inventive effort are intended to fall within the scope of protection of the present invention.

[0041] like Figure 1 As shown, the present invention provides a horizontal well dynamic ECD prediction method based on formation-wellbore transient temperature and pressure coupling, comprising the following steps:

[0042] Step 1: Use a gas permeameter to test the porosity of the core;

[0043] Step 2: Use a thermal expansion coefficient meter and a Hot Disk thermal constant analyzer to test the thermal physical parameters of the core and cement paste;

[0044] Step 3: Using the API RP 13D rheological drilling fluid circulation temperature field governing equations during drilling and Laplace transform processing, derive the analytical solution for the transient temperature field inside the horizontal well drill string and the wellbore annulus;

[0045] The API RP 13D rheological type (double power law type) drilling fluid circulation temperature field control equations include: the heat transfer equation in the drill string, the heat transfer equation in the wellbore annulus, the heat flux continuity equation at the wellbore wall (the heat flux flowing from the formation into the wellbore is equal), and the formation heat conduction equation;

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[0050] The analytical solution of the transient temperature field of the horizontal well involved in this step (including the internal temperature of the drill string, the annular temperature of the wellbore, the wellbore wall temperature, and the radial diffusion temperature of the formation) is further subdivided into the vertical well section, the deflection section, and the horizontal section. Its expression includes:

[0051] Vertical wellbore annulus and inside the drill string The analytical solution of the temperature field (in the Laplace space domain) is expressed as:

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[0054] Wellbore annulus in the deflection section and inside the drill string The analytical solution of the temperature field (in the Laplace space domain) is denoted as

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[0059] Horizontal wellbore annulus and inside the drill string The analytical solution of the temperature field (in the Laplace space domain) is denoted as

[0060]

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[0062] Taking the shale gas well with 4 drilling runs as an example, the vertical well section was casing-sealed (3 drilling runs), and the deflection section and horizontal section were drilled in open hole.

[0063] Then the unknown number Q can be obtained from the equation group AQ=B

[0064] Q(Q 11 Q 12 Q 21 Q 22 Q 31 Q 32 Q′1 Q′2 Q″1 Q″2) T

[0065] B(B1 B2 B3 B4 B5 B6 B7 B8 B9 0) T

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[0067] The calculation formula of the transient temperature field analytical solution is:

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[0076] a 11 =Xx 1，1

[0077] a 12 =Xx 2，1

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[0121] Bx=0

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[0151] λ Tk =c rk / k rk

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[0157] The symbols in the above formulas mean:

[0158] A0 为 Geothermal gradient, ℃ / m; B0 is the surface temperature, ℃; T0 is the initial formation temperature T0=A0z+B0, ℃; z j The range of variation is [0, H KOP ],z l The range of change is (H KOP , H i ],z h The range of change is (H i , H]. KOP is the well depth at the inclination point, m; H hv is the vertical depth of the horizontal section, m; H hl is the inclined depth at the end of the build-up section (beginning of the horizontal section), m; H is the actual well depth. KOP is the well inclination angle at the inclination point, °; α hv is the actual well inclination angle of the horizontal section, °; ​​K z is the build rate, (°) / 30m; K0() is the modified second-order Bessel function of zero; s is the complex frequency introduced by Laplace transform, which is related to time; r is the radial distance from the wellbore center to a certain position inside the formation, m; r wk(k=j, l, h) is the wellbore radius of different drilling times, m; z is the well depth, m; t is the drilling fluid circulation time, s; is the Laplace operator in the r direction.

[0159] A annu , A dp，i are the wellbore annulus and the internal cross-sectional area of ​​the drill string, respectively. and m 2 ; Annulus diameter d annu Defined as m; r ci and r w are the inner radius of the casing in the cementing section and the wellbore radius in the open hole section, m; r dp，o is the outer diameter of the drill string, m; d dp，i is the inner diameter of the drill string d dp，i =2r dp，i ,m;r dp，i is the inner radius of the drill string, m; υ annu , v dp are the flow velocities in the wellbore annulus and inside the drill string, respectively and m / s; Q annu and Q dp are the drilling fluid displacement in the wellbore annulus and inside the drill string, m 3 / s;m;ρ m is the drilling fluid density kg / m 3 ;c m is the specific heat capacity of drilling fluid, J / (kg·K); c s , c f is the specific heat capacity of the solid and liquid phases inside the rock, J / (kg·K); ρ s ,ρ f is the density of the solid and liquid phases inside the rock, kg / m 3 ; φ is the porosity of the rock, dimensionless; c r is the total specific heat capacity of rock c r =(1-φ)ρ s c s +φρ s c s ,J / (kg·℃);k g , k f is the thermal conductivity of the solid and liquid phases inside the rock, W / (m·℃); k r is the total thermal conductivity of rock k r =(1-φ)k s +φk f , W / (m·℃); T a , T d , T w, T is the temperature of the wellbore annulus, inside the drill string, at the wellbore wall and the formation, ℃; h ad is the convective heat transfer coefficient between the inner and outer walls of the drill string W / (m 2 ℃); h dp，i is the convective heat transfer coefficient at the inner diameter of the drill string W / (m 2 ℃); h dp，o is the convective heat transfer coefficient at the outer diameter of the drill string W / (m 2 ℃); k d , drill string thermal conductivity, W / (m·℃); d dp，o is the outer diameter of the drill string d dp，o =2r dp，o , m; χ θ is the comprehensive heat transfer coefficient from the annular drilling fluid to the outer wall of the cement annulus W / (m 2 ·K).h θ is the heat transfer coefficient h at the well wall or the inner wall of the innermost casing θ =Nu annu k m / d cas，i , where the convection heat transfer coefficient at the open hole wall h w Defined as h w =Nu annu k m / d w ,W / (m 2 ·K);d w is the wellbore diameter d w =2r w ,m;r θ is the radius of the kth wellbore, r wk (or the inner radius of the innermost casing r casi，k ), m; M is the number of casing and cement sheath layers at a certain depth in the wellbore; is the outer diameter of the j-th layer casing or cement sheath, m; —No. Inner diameter of casing or cement sheath, m.

[0160] T surf is the wellhead injection temperature, °C; φ3 is 3 revolutions per minute, dimensionless; φ 100 is 100 revolutions per minute, dimensionless; φ 300 is 300 revolutions per minute, dimensionless; φ 600 is 600 revolutions per minute, dimensionless; is the power-law drilling fluid manifold index in the drill string dimensionless; is the power-law drilling fluid viscosity coefficient in the drill string Pa·sn ; R edp is the Reynolds number in the drill string dimensionless; is the effective viscosity of the power-law drilling fluid in the drill string Pa·s; is the power-law drilling fluid manifold index in the drill string dimensionless; is the annular power law drilling fluid viscosity coefficient Pa·s n ;Re annu，k is the annulus Reynolds number dimensionless; is the Reynolds number of laminar flow in the drill string or wellbore annulus dimensionless; is the Reynolds number of turbulent flow in the drill string or wellbore annulus dimensionless; Reynolds (Reynolds) for the transition zone within the drill string or the wellbore annulus dimensionless; The effective viscosity of the annular power law drilling fluid Pa·s;Pr dp is the Prandtl number in the drill string dimensionless; Pr annu，k is the wellbore annulus Prandtl number dimensionless; Nusselt number at the well wall or the inner wall of the innermost casing dimensionless; is the Nusselt number of turbulent flow in the drill string dimensionless; is the Nusselt number of laminar flow in the wellbore annulus dimensionless; is the Nusselt number of the wellbore annulus turbulence dimensionless; is the Nusselt number of laminar flow in the wellbore annulus Dimensionless; fitting coefficients c and β are defined as and dimensionless; is the ratio of the inner radius of the wellbore or casing to the outer radius of the drill string, is the Nusselt number of the transition flow satisfy It is related to the interior of the drill string and the annulus and is dimensionless;

[0161] The values ​​of k above, k=j, l, h, respectively, refer to the vertical well section (j), the inclined well section (l), and the horizontal well section (h). The superscript symbol "~" indicates that the Laplace transform is performed on the variable.

[0162] Step 4: Using the coupled relationship between drilling fluid density, pressure and temperature measured by a high-temperature and high-pressure density meter, a dynamic ESD prediction model is established that couples the annular temperature and static liquid column pressure disturbance effects.

[0163] The dynamic ESD prediction model at any well depth h is as follows:

[0164]

[0165] The bottom hole dynamic ESD prediction model is calculated as follows:

[0166]

[0167] Γ(P(z, t), T a (z, t)) = a(P(z, t) - P0) - b(T a (z, t)-T0)+c(T a (z, t)-T0) 2

[0168] In the above formula, the computational node lengths Δh and ΔH are defined as Δh = h / m and ΔH = H / n,m, respectively; m and n are the number of computational nodes, dimensionless; h is the well depth at the study location, m; H is the well depth, m; the wellhead pressure P0 is P(z = 0, t) = 0.1, MPa; the wellhead annulus temperature T0 is defined as T(h = 0, t) = T a ,℃;P i When (z, t) is the cycle time t, the depth z = Δh × i (i = 1, 2, ... n) in the well is affected by the annular temperature T a，i (z, t) is the wellbore hydrostatic column pressure, MPa; g is the acceleration due to gravity, 9.81 m / s 2 ρ m0 (P0, T0) is the density of the drilling fluid under the action of wellhead pressure P0 and temperature T0, kg / m 3 Γ(P i (z,t),T a，i (z, t)) is the density-pressure-temperature coupling function proposed by Wang Haige et al. The annular static liquid column pressure P at the well depth h at the research location h (z=h,t) is MPa; annular static liquid column pressure P at the bottom of the well H H (z=H,t) is MPa; a, b, c: drilling fluid characteristic constants, 1 / MPa, 1 / ℃, 1 / (℃·℃).

[0169] Step 5: Based on the dynamic ESD prediction model and combined with the annular pressure loss calculation principle proposed by Wang Haige and Ma Xianming, a wellbore annulus dynamic ECD (wellbore annulus transient circulation pressure) prediction model is established;

[0170] The wellbore annulus dynamic ECD (z, t) (wellbore annulus transient circulation pressure p m (z, t)) prediction includes

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[0172] p m (z=h,t)=ECD(z=h,t)gh

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[0186] ECD (z = h, t) is the equivalent circulating density corresponding to the study depth h and drilling fluid circulation time t, kg / m 3 ;p m (z = h, t) is the transient circulating pressure in the wellbore annulus corresponding to the study depth h and the drilling fluid circulation time t, MPa; ΔP bed : When there is a cuttings bed, the annular pressure loss per unit length, Pa; H Tcb: dimensionless cuttings bed height; ΔP nobed : Annular pressure loss per unit length when there is no cuttings bed, Pa; S: Ratio of cuttings to drilling fluid density, dimensionless; Critical annular return velocity V c is, m / s; T c is the height of the cuttings bed, m; the outer diameter of the annulus d is defined as d = d casi，k (or d w ); m; ε is the eccentricity, dimensionless; V c is the critical flow velocity, m / s; ρ s is the rock cuttings density, kg / m 3 ;d s is the average rock fragment size, m. γ b is the well inclination angle, °; k1 is the correction coefficient reflecting the effect of drill string rotation on ECD, 0.7≤k1≤1.3, dimensionless; is the ratio of the average pressure gradient of the concentric annulus to the average pressure gradient of the eccentric annulus; dimensionless; is the ratio of the annulus inner diameter to the annulus outer diameter; dimensionless; J represents the pressure gradient ratio and is related to laminar flow (lami), transition flow (trans) and turbulent flow (turb). Defined as: The Fanning coefficient f of the wellbore annulus is defined as (laminar flow) and (turbulent flow), where Dimensionless; annular debris volume content C s ,%;v s is the sliding velocity of rock debris particles, m / s; C e is the cuttings inlet concentration Dimensionless. ROP is the rate of penetration, m / h.

[0187] The present invention determines the core and cement stone thermophysical property parameters required for model calculation through indoor experiments, and uses the API RP 13D rheological drilling fluid circulation temperature field control equation during drilling to analyze the transient temperature field inside the horizontal well drill string and the wellbore annulus. A dynamic ECD (wellbore annulus transient circulating pressure) prediction model that couples the annular space temperature and pressure disturbances is comprehensively established. This provides a scientific basis for on-site construction personnel to accurately control the wellbore pressure during (ultra-) deep horizontal well drilling, thereby preventing complex downhole accidents.

[0188] The above description does not limit the present invention in any form. Although the present invention has been disclosed through the above embodiments, it is not intended to limit the present invention. Any technician familiar with the profession can use the technical content disclosed above to make changes or modifications to equivalent embodiments without departing from the scope of the technical solution of the present invention. However, 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 content of the technical solution of the present invention are still within the scope of the technical solution of the present invention.

Claims

1. A horizontal well dynamic ECD prediction method based on formation-wellbore transient temperature and pressure coupling is characterized by: The following steps are involved: Step 1: Use a gas permeameter to test the porosity of the core; Step 2: Use a thermal expansion coefficient meter and a Hot Disk thermal constant analyzer to test the thermal physical parameters of the core and cement paste; Step 3: Using the API RP 13D rheological drilling fluid circulation temperature field governing equations during drilling and Laplace transform processing, derive the analytical solution for the transient temperature field inside the horizontal well drill string and the wellbore annulus; The internal temperature of the drill string and the annular space of the horizontal well are further divided into the vertical well section, the deflection section and the horizontal section. The expressions include: Vertical wellbore annulus and inside the drill string The analytical solution of the temperature field is expressed as: Wellbore annulus in the deflection section and inside the drill string The analytical solution of the temperature field is expressed as: Horizontal wellbore annulus and inside the drill string The analytical solution of the temperature field is expressed as: Where A0 is the geothermal gradient, ℃ / m; B0 is the surface temperature, ℃; T0 is the initial formation temperature T0=A0z+B0, ℃; z j The range of variation is [0, H KOP ],z l The range of variation is (H KOP , H i ],z h The range of variation is (H i , H]; H KOP is the well depth at the inclination point, m; H hv is the vertical depth of the horizontal section, m; H hl is the inclined depth at the end of the build-up section (the beginning of the horizontal section), m; H is the actual well depth; α KOP is the well inclination angle at the inclination point, °; α hv is the actual well inclination angle of the horizontal section, °; ​​K z is the slope rate, (°) / 30m; K0() is the modified second-kind 0th-order Bessel function; s is the complex frequency introduced by Laplace transform, which is related to time; Step 4: Using the coupled relationship between drilling fluid density, pressure and temperature measured by a high-temperature and high-pressure density meter, a dynamic ESD prediction model is established that couples the annular temperature and static liquid column pressure disturbance effects. Step 5: Based on the dynamic ESD prediction model and combined with the annular pressure loss calculation method, a wellbore annulus dynamic ECD, that is, a wellbore annulus transient cyclic pressure prediction model, is established.

2. The horizontal well dynamic ECD prediction method based on formation-wellbore transient temperature and pressure coupling according to claim 1 is characterized in that: The thermal physical parameters in step 2 include solid phase thermal expansion coefficient, liquid phase thermal expansion coefficient, thermal conductivity, and specific heat capacity.

3. The horizontal well dynamic ECD prediction method based on formation-wellbore transient temperature and pressure coupling according to claim 1 is characterized in that: The dynamic ESD calculation formula for coupling the annular space temperature and the static liquid column pressure disturbance in step 4 is: Γ(P(z,t),T a (z,t))=a(P(z,t)-P0)-b(T a (z,t)-T0)+c(T a (z,t)-T0) 2 Where, the computational node length Δh is defined as Δh = h / m, m; m is the number of computational nodes, dimensionless; h is the well depth at the study location, m; the wellhead pressure P0 is P(z=0, t)=0.1, MPa; the wellhead annulus temperature T0 is defined as T(h=0, t)=T a ,℃;P i When (z, t) is the cycle time t, the depth z = Δh × i (i = 1, 2, ... n) in the well is affected by the annular temperature T a，i (z, t) is the wellbore hydrostatic column pressure, MPa; g is the acceleration due to gravity, 9.81 m / s 2 ; ρ m0 (P0, T0) is the density of the drilling fluid under the action of wellhead pressure P0 and temperature T0, kg / m 3 Γ(P i (z,t),T a，i (z, t)) is the density-pressure-temperature coupling function proposed by Wang Haige et al.; The static liquid column pressure P in the annulus at the well depth h at the research location h (z=h, t) is: MPa; a, b, c: drilling fluid characteristic constants, 1 / MPa, 1 / ℃, 1 / (℃·℃).

4. The horizontal well dynamic ECD prediction method based on formation-wellbore transient temperature and pressure coupling according to claim 1 is characterized in that: The calculation formula of the wellbore annulus dynamic ECD in step 5, i.e., the wellbore annulus transient circulating pressure, is: p m (z=h,t)=ECD(z=h,t)gh Where, ECD(z=h, t) is the equivalent circulating density corresponding to the study depth h and drilling fluid circulation time t, kg / m 3 ;p m (z = h, t) is the transient circulating pressure in the wellbore annulus corresponding to the study depth h and the drilling fluid circulation time t, MPa; ΔP bed : Annular pressure loss per unit length when there is a cuttings bed, Pa.

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