Quantitative control method for well wall stability of horizontal well in fractured formation under transient temperature and pressure coupling

Abstract

The invention discloses a fractured formation horizontal well wall stability quantitative control method under transient temperature and pressure coupling, and relates to the technical field of deep oil and gas drilling. The method comprises the following steps: analyzing the internal temperature of a drill column, the annulus temperature and the well wall temperature reflecting the transient temperature difference disturbance boundary effect by utilizing a drilling process API RP 13D rheological drilling fluid circulating temperature field control equation; establishing a dynamic ECD prediction model coupled with the annulus temperature and the pressure disturbance effect, and taking the transient temperature difference between the dynamic temperature of the well wall and the original temperature of the stratum, the transient pressure difference between the transient pressure of the well wall and the original pore pressure of the stratum and the transient stress difference between the transient pressure of the well wall and the original radial stress as dynamic disturbance boundary conditions; a pore pressure field and a stress field of rock around a well of the fractured formation under the heat-fluid-solid coupling effect under the non-uniform ground stress condition are analyzed in combination with a dual-pore thermoelasticity theory, a safe density window of the horizontal well of the fractured formation is determined, and well wall instability can be effectively prevented.

Description

Technical Field

[0001] The present invention relates to the technical field of (ultra) deep oil and gas drilling, and more specifically to a quantitative control method for the stability of a horizontal wellbore under the transient temperature and pressure coupling action of a fractured formation - wellbore. Background Art

[0002] Improper selection of drilling fluid density may lead to wellbore collapse (low wellbore density poses a risk of stuck pipe due to falling debris), fracturing of the formation or generation of drilling - induced fractures in the wellbore (high wellbore density), prolonging non - drilling time and increasing drilling costs. The reasonable safety density window designed before drilling to prevent downhole complications usually consists of an upper limit of fracture pressure equivalent density (to prevent the generation of drilling - induced fractures) and a lower limit of collapse pressure equivalent density (to prevent wellbore collapse). The in - situ stress field and pore pressure field around the well are the keys to wellbore stability evaluation. External loads (such as changes in stress difference and pressure difference) during the formation of the drilled wellbore cause deformation of the rock solid phase, inducing changes in rock permeability and porosity, which in turn affect the flow state of the fluid inside the pores of the formation rock. The pressure gradient reflecting the fluid flow state will act on the rock solid phase - resisting its deformation. This fluid - solid (fluid flow - solid deformation) coupling effect is particularly obvious in low - permeability formations. When an external load is instantaneously applied to the rock surface, due to the low - permeability characteristics, the pore fluid cannot be discharged in time from the current pores and will bear part of the external load, thereby inducing the generation of excess pore pressure, which is the non - drainage load effect or poro - elastic effect.

[0003] Analogously, the above - mentioned situation occurs when external loads act on (ultra) deep fractured rocks (such as shale, tight sandstone and hot dry rock). Since their matrix system and fracture system have their own hydraulic (permeability, porosity) and mechanical (elastic modulus, Poisson's ratio, Skempton pore pressure coefficient, etc.) characteristics, the two systems exhibit different poro - elastic responses. Therefore, the practice of regarding fractured rocks as single - porosity media (ignoring the existence of the fracture system or introducing bedding weak planes to replace the fracture system) will inevitably lead to incorrect predictions of the pre - drilling design safety density window for such formations.

[0004] In addition, during the deep formation drilling process, the wellbore drilling fluid reaches the bottom of the well through the inside of the drill string, which is a heating process, and its temperature gradually becomes higher than the wellhead temperature. During the process of flowing out of the ground through the annulus after passing through the drill bit, the drilling fluid at the bottom of the wellbore further absorbs the formation heat and its temperature gradually increases (but still lower than the original formation temperature, that is, cooling the formation). After flowing upward through the critical well depth, the temperature of the drilling fluid is higher than the original formation temperature and heats the upper formation. Considering that after the rock is heated, the pore fluid in the rock undertakes part of the load borne by the solid phase skeleton due to the expansion effect (note that the solid phase expansion of the rock is lower than that of the pore fluid), resulting in the phenomenon of excess pore pressure. The cooling of the rock in the lower formation causes the pore fluid to shrink and cannot "fill" the pore space, resulting in low pressure. On the other hand, the solid phase skeleton of the rock not only generates thermal stress due to thermal expansion and contraction, but the process of thermal expansion and contraction will also affect the formation degree of excess pressure or low pressure of the pore fluid and the seepage process - the thermo-hydro-mechanical coupling effect. Obviously, the conventional linear elastic model cannot reflect the influence of the thermo-hydro-mechanical coupling process on the stress field of the rock around the well and the safety density window.

[0005] The action of the wellbore circulation temperature field during the above deep formation drilling process makes the temperature at the wellbore wall in a dynamic change process. In addition, the density of the drilling fluid is also in a dynamic change under the influence of the wellbore pressure and the circulation temperature field. Therefore, the dynamic boundary effects before and after the wellbore is drilled (including the dynamic temperature difference between the drilling fluid and the formation fluid at the wellbore wall and the dynamic pressure difference between the transient circulation pressure in the wellbore annulus and the original pore pressure) make the assumptions of traditional constant temperature difference and pressure difference actions unable to correctly reflect the influence of the thermo-hydro-mechanical coupling effect on wellbore stability.

[0006] The invention patent with the publication number CN104806233A of China University of Petroleum (regarding the fracture system as a weak plane) discloses a method for predicting the collapse pressure equivalent density window of weak plane formations, including dividing the weak plane formations into dense sections and fracture sections according to the characteristics of the weak plane formations; using the rock triaxial compression test to test the strength of the rock matrix and the strength of the weak plane; using the fluid-solid coupling model to invert the stress distribution and pore pressure distribution of the rock around the well in the dense formation, and combining with the Mohr-Coulomb failure criterion to determine the lower limit of the collapse pressure equivalent density of the dense formation; using the rock weak plane failure criterion to analyze the failure state of the rock around the well in the weak plane formation, and determining the lower limit and upper limit of the collapse pressure equivalent density window of the fracture formation; comparing the collapse pressure equivalent density values (lower limit) of the dense section and the collapse pressure equivalent density values (lower limit and upper limit) of the fracture section, and the collapse pressure equivalent density window of the weak plane formation can be determined.

[0007] The invention patent with the publication number CN113935092A of Southwest Petroleum University discloses a dual-porosity thermo-elastic coupling evaluation method for wellbore stability in fractured formations. Although this method considers the influence of the fracture system and dynamic temperature difference on the equivalent density of collapse pressure, the prediction of the cyclic temperature field does not consider the influence of the actual wellbore structure (casing and cement sheath), and does not consider the influence of the dynamic pressure difference between the transient cyclic pressure in the wellbore annulus (related to dynamic ECD) and the original pore pressure combination on the stress field around the wellbore. Therefore, it cannot accurately design the pre-drilling safety density window for (ultra) deep fractured formations.

[0008] Although the above two patents and other existing technical solutions have achieved certain technical effects, they do not comprehensively predict the pre-drilling safety density window for (ultra) deep fractured formations under the action of thermo-hydro-mechanical coupling, thus restricting on-site operations. Summary of the Invention

[0009] In order to overcome the defects existing in the above-mentioned prior art, the present invention discloses a quantitative control method for wellbore stability of horizontal wells in fractured formations under transient temperature-pressure coupling. The present invention includes measuring the permeability, pore medium mechanical parameters and thermophysical properties of fractured cores and intact cores, the variation law of drilling fluid density with temperature and pressure, and using imaging logging data or a three-dimensional CT scanner to invert the fracture spacing and fracture width of the rocks in the fractured formation; using the control equation of the cyclic temperature field of API RP 13D rheological drilling fluid during the drilling process to analyze the temperature inside the drill string, the annulus temperature and the wellbore temperature reflecting the boundary effect of transient temperature difference disturbance; establishing a prediction model of dynamic ECD (transient cyclic pressure in the wellbore annulus) that couples the annulus temperature and pressure disturbance, taking the transient temperature difference between the dynamic temperature at the wellbore and the original formation temperature, the transient pressure difference between the transient pressure at the wellbore and the original pore pressure of the formation, and the transient stress difference between the transient pressure at the wellbore and the original radial stress as the dynamic disturbance boundary conditions, and combining the dual-porosity thermo-elastic theory to analyze the pore pressure field and stress field of the surrounding rock of the wellbore in the fractured formation under the action of thermo-hydro-mechanical coupling under non-uniform in-situ stress conditions, and determining the safety density window for horizontal wells in fractured formations. The present invention quantifies the relationship between the plugging ratio of fracture size and wellbore collapse-fracture, and provides theoretical and technical guidance for reasonably designing the "time-correlated safety density window" that couples the dynamic temperature-pressure disturbance boundary effect before drilling in (ultra) deep fractured formations.

[0010] In order to achieve the above object, the technical solution adopted by the present invention is:

[0011] A quantitative control method for wellbore stability of horizontal wells in fractured formations under transient temperature-pressure coupling, comprising the following steps:

[0012] Step 1: Use a gas permeability tester to measure the permeability of fractured cores and intact cores;

[0013] Step 2: Test the physical properties of the fractured core according to the three-dimensional CT scanner and logging data;

[0014] Step 3: Test the pore medium mechanical parameters of the fractured core and the intact core by using the rock triaxial compression test, and obtain the pore medium mechanical parameters corresponding to the fracture system in the fractured core and the rock strength parameters of the fractured core through the equivalent sequence model;

[0015] Step 6: Test the thermal physical properties of the fractured core and the intact core by using a thermal expansion coefficient measuring instrument and a Hot Disk thermal constant analyzer;

[0016] Step 9: Test the in-situ stress by using the acoustic emission test, and obtain the in-situ stress distribution by back-calculating the tectonic stress coefficient and combining with logging data;

[0017] Step 12: Invert the original formation pore pressure distribution by using logging parameters;

[0018] Step 15: Use the control equation of the API RP 13D rheological (double power-law type) drilling fluid circulation temperature field during the drilling process and Laplace transform processing to analyze four types of transient temperature field analytical solutions;

[0019] Step 18: Use the coupling relationship of drilling fluid density-pressure-temperature measured by a high-temperature and high-pressure densitometer to establish a dynamic ESD prediction model that couples the annulus temperature and the static liquid column pressure disturbance;

[0020] Step 21: Based on the dynamic ESD prediction model, combine the annulus pressure loss calculation principle proposed by Wang Haige and Ma Xianming et al. to establish a prediction model for the wellbore annulus dynamic ECD (wellbore annulus transient circulation pressure);

[0021] Step 24: Use the transient wellbore temperature field analytical solution, the constitutive equation and the mass conservation equation of the dual-porosity thermoelastic theory to analyze the pore pressure field and stress field of the wellbore surrounding rock in the fractured formation under the action of thermo-hydro-mechanical coupling under non-uniform in-situ stress conditions;

[0022] Step 27: Use the pore pressure field and stress field of the wellbore surrounding rock in the fractured formation under the action of thermo-hydro-mechanical coupling under non-uniform in-situ stress conditions, the Mogi-Coulomb criterion and the tensile fracture criterion to determine the safe density window SMWW = {ρ c ,ρ f};

[0023] A further technical solution is that the physical properties of the fractured core in Step 2 include the fracture spacing and the fracture width.

[0024] A further technical solution is that the mechanical parameters of the pore medium in step three include Young's modulus, Poisson's ratio, Skempton coefficient, and fluid bulk modulus; the rock strength parameters include cohesion, internal friction angle, and tensile strength.

[0025] A further technical solution is that the thermal physical properties parameters in step four include solid-phase thermal expansion coefficient, liquid-phase thermal expansion coefficient, thermal conductivity, and specific heat capacity.

[0026] A further technical solution is that the in-situ stresses in step five include overburden pressure, maximum horizontal in-situ stress, and minimum horizontal in-situ stress.

[0027] A further technical solution is that the four types of full transient temperature field analytical solutions in step seven include the analytical solution of the temperature field inside the drill string, the analytical solution of the temperature field in the wellbore annulus, the analytical solution of the temperature field at the wellbore wall, and the analytical solution of the formation radial diffusion temperature field;

[0028] The analytical solution of the horizontal well transient temperature field (including the temperature inside the drill string, the temperature in the wellbore annulus, the temperature at the wellbore wall, and the formation radial diffusion temperature) is further divided into the vertical section, the build section, and the horizontal section, and its expressions include:

[0029] Wellbore annulus in the vertical section Inside the drill string At the wellbore wall And the formation The analytical solution of the temperature field (in the Laplace space domain) is denoted as the formula:

[0030]

[0031]

[0032]

[0033]

[0034] Wellbore annulus in the build section Inside the drill string At the wellbore wall And the formation The analytical solution of the temperature field (in the Laplace space domain) is denoted as:

[0035]

[0036]

[0037]

[0038]

[0039]

[0040]

[0041] Horizontal section wellbore annulus Inside the drill string At the wellbore wall And the formation The analytical solution of the temperature field (in the Laplace spatial domain) is denoted as:

[0042]

[0043]

[0044]

[0045]

[0046] In the formula, A 0 Is the geothermal gradient, °C / m; B 0 Is the surface temperature, °C; T 0 Is the initial formation temperature T 0 = A 0 z + B 0 , °C; z j The range of change 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]; H KOP Is the depth of the kick-off 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 section (start of the horizontal section), m; H is the actual well depth; α KOP Is the well inclination angle at the kick-off point, °; α hv Is the actual well inclination angle of the horizontal section, °; K z Is the build rate, (°) / 30m; K 0 () is the modified Bessel function of the second kind of order zero; s is the complex frequency introduced by the Laplace transform, 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) are the wellbore radii of different opening times, m; z is the well depth, m.

[0047] A further technical solution is that the dynamic ESD calculation formula for coupling the annulus temperature and the static liquid column pressure disturbance in step eight is:

[0048]

[0049] Γ(P(z, t), T a (z, t)) = a(P(z, t) - P 0 ) - b(T a (z, t) - T 0 ) + c(T a (z, t) - T 0 ) 2

[0050] In the formula, the calculation node length Δh is defined as Δh = h / m, where m is the number of calculation nodes, dimensionless; h is the well depth at the research location, in m; the wellhead pressure P 0 is P(z = 0, t) = 0.1, in MPa; the wellhead annulus temperature T 0 is defined as T(h = 0, t) = T a , in °C; P i (z, t) is the static hydrostatic pressure of the wellbore at the well depth z = Δh × i (i = 1, 2,... n) affected by the annulus temperature T a，i (z, t) at the circulation time t, in MPa; g is the acceleration due to gravity, 9.81 m / s 2 ; ρ m0 (P 0 , T 0 ) is the density of the drilling fluid under the action of the wellhead pressure P 0 and the temperature T 0 , in kg / m 3 ; Γ(P i (z, t), T a，i (z, t)) is the density-pressure-temperature coupling function formula proposed by Wang Haige et al. The static hydrostatic pressure P h (z = h, t) at the well depth h of the research location is in MPa; a, b, c: characteristic constants of the drilling fluid, 1 / MPa, 1 / °C, 1 / (°C·°C).

[0051] A further technical solution is that the calculation formula for the dynamic ECD (wellbore annulus transient circulation pressure) in the wellbore annulus in step nine is:

[0052]

[0053] p m (z = h, t) = ECD(z = h, t)gh

[0054] In the formula, ECD(z = h, t) is the equivalent circulating density corresponding to the research depth h and the drilling fluid circulation time t, in kg / m 3 ; p m (z = h, t) is the transient circulation pressure of the wellbore annulus corresponding to the research depth h and the drilling fluid circulation time t, in MPa; ΔP bed:Annular pressure loss per unit length in the presence of cuttings bed, Pa.

[0055] A further technical solution is that the calculation formulas for the pore pressure field and stress field in Step Ten are as follows:

[0056]

[0057]

[0058]

[0059]

[0060]

[0061]

[0062] In the formula: p 0 is the initial pore pressure of the formation, MPa; p m is the transient circulation pressure in the wellbore annulus, MPa; σ r , σ θ , σ z and τ rθ are the in-plane radial stress, tangential stress, axial stress and shear stress of the rock distribution around the well, respectively, MPa; τ θz and τ zr are the out-of-plane shear stresses, MPa; P 0 and S o are the original average stress and shear stress of the formation, respectively, MPa; θ is the wellbore circumference angle, the included angle between the radius vector of the research position point and the azimuth of the maximum horizontal in-situ stress σ H , °; θ r is the intermediate quantity of the conversion angle, defined as .: and are the principal stress components and shear stress components in the wellbore coordinate system, respectively, MPa.

[0063] A further technical solution is that the Mohr-Coulomb criterion in Step Eleven is as follows:

[0064]

[0065]

[0066]

[0067] In the formula, τ oct is the octahedral shear stress, σ m is the mean effective stress; c and Correspond to the inherent cohesive force and internal friction angle of the rock respectively; the above maximum effective principal stress σ′ 1 , the intermediate effective principal stress σ′ 2 and the minimum effective principal stress σ′ 3 .

[0068] A further technical solution is that the tensile fracture criterion in step eleven is:

[0069] σ′ 3 =-S t

[0070] S t =σ c / ω

[0071]

[0072] In the formula: s t is the tensile strength of the fragmented rock; σ c is the uniaxial compressive strength; the coefficient ω can be taken as 12.

[0073] A further technical solution is that the process of determining the safety density window SMWW={ρ c , ρ f} in step eleven is:

[0074] First, by defining the well deviation angle γ bi =i°(i = 0:i:90), the azimuth angle Ω bj =j°(j = 0:j:360), the wellbore circumference angle θ k =k°(k = 0:k:360) and the pressure array to determine the final required collapse pressure value;

[0075] Among them, is set as the horizontal maximum principal in-situ stress σ H or a greater stress value; given the matrix (γ bi , Ω bj ), the pressure p ml increases from 0 to at intervals of 1. When the judgment condition is satisfied, the collapse pressure matrix corresponding to the wellbore circumference angle θ k can be obtained. Finally, the maximum value in the matrix is selected as the collapse pressure value corresponding to the given well deviation and azimuth angles (γ bi , Ω bj ); the equivalent density of the collapse pressure value is used as the lower limit of the safety density window SMWW={ρ c , ρ f} of the fragmented formation;

[0076] Then, by defining the well deviation angle γ bi = i° (i = 0:i:90), the azimuth angle Ω bj = j° (j = 0:j:360), the wellbore circumferential angle θ k = k° (k = 0:k:360) and the pressure array to determine the final required fracture pressure value;

[0077] Among them, is set to be greater than the maximum value of the three principal in-situ stresses (σ H , σ h , σ v ); given the matrix (γ bi , Ω bj ), the pressure p ml decreases from to 0 at an interval of l. When the judgment condition σ′ 3 + s t ≤ m is satisfied, the fracture pressure matrix corresponding to the wellbore circumferential angle θ k can be obtained. Finally, the minimum value in the matrix is selected as the fracture pressure value corresponding to the given well deviation and azimuth angles (γ bi , Ω bj ); the equivalent density of the fracture pressure value is used as the upper limit of the safety density window SMWW = {ρ c , ρ f} for the fractured formation.

[0078] Advantages of the present invention:

[0079] A method for quantitatively controlling the stability of the horizontal wellbore in a fractured formation under transient temperature and pressure coupling proposed by the present invention is simple, easy to understand, convenient to operate, and low in cost. It provides a scientific basis for designing a reasonable safety density window before drilling in (ultra) deep fractured formations, can effectively prevent wellbore instability, and prevent downhole complex accidents. BRIEF DESCRIPTION OF THE DRAWINGS

[0080] Figure 1 is a flowchart of the present invention. DETAILED DESCRIPTION OF THE INVENTION

[0081] The following will clearly and completely describe the concept, specific structure, and technical effects generated by the present invention in combination with embodiments and drawings to fully understand the purpose, features, and effects of the present invention.

[0082] As Figure 1 shown, the present invention provides a method for quantitatively controlling the stability of the horizontal wellbore in a fractured formation under transient temperature and pressure coupling, including the following steps:

[0083] Step 1: Use a gas permeability tester to measure the permeability of fractured cores and intact cores.

[0084] Step 2: Measure the physical properties of fractured cores based on 3D CT scanners and logging data, where the physical properties include fracture spacing and fracture width.

[0085] Step 3: Use a rock triaxial compression test to measure the pore medium mechanical parameters of fractured cores and intact cores. The mechanical parameters of the latter correspond to those of the matrix system in the fractured cores. The pore medium mechanical parameters corresponding to the fracture system in the fractured cores and the rock strength parameters of fragmented rocks are obtained through an equivalent sequence model (the matrix system and the fracture system are arranged in sequence). The rock strength parameters include cohesion, internal friction angle, and tensile strength, and the pore medium mechanical parameters include Young's modulus, Poisson's ratio, Skempton coefficient, fluid bulk modulus, etc.

[0086] Step 4: Use a thermal expansion coefficient measuring instrument and a Hot Disk thermal constant analyzer to measure the thermal physical properties of fractured cores and intact cores. The thermal physical properties include solid-phase thermal expansion coefficient, liquid-phase thermal expansion coefficient, thermal conductivity, specific heat capacity (thermal diffusivity).

[0087] Step 5: Use an acoustic emission test to measure in-situ stresses, including overburden pressure, maximum horizontal in-situ stress, and minimum horizontal in-situ stress. Obtain the in-situ stress distribution by back-calculating the tectonic stress coefficient and combining it with logging data.

[0088] Step 6: Invert the original formation pore pressure distribution using logging parameters.

[0089] Step 7: Use the API RP 13D rheological (double power-law type) drilling fluid circulation temperature field control equation during drilling and Laplace transform processing to analyze the analytical solution of the transient temperature field.

[0090] The API RP 13D rheological (double power-law type) drilling fluid circulation temperature field control equation includes: heat transfer equation inside the drill string, heat transfer equation in the wellbore annulus, heat flux continuity equation at the wellbore wall (the heat flux flowing from the formation into the wellbore is equal), and formation heat conduction equation.

[0091]

[0092]

[0093]

[0094]

[0095] The analytical solutions of the transient temperature field in horizontal wells involved in this step (including the temperature inside the drill string, the annulus temperature in the wellbore, the wellbore wall temperature, and the radial diffusion temperature in the formation) are further divided into the vertical section, the build section, and the horizontal section, and their expressions are as follows:

[0096] Annulus in the vertical section Inside the drill string At the wellbore wall And the formation The analytical solutions of the temperature field (in the Laplace space domain) are denoted as the formula:

[0097]

[0098]

[0099]

[0100]

[0101] Annulus in the build section Inside the drill string At the wellbore wall And the formation The analytical solutions of the temperature field (in the Laplace space domain) are denoted as:

[0102]

[0103]

[0104]

[0105]

[0106]

[0107]

[0108] Annulus in the horizontal section Inside the drill string At the wellbore wall And the formation The analytical solutions of the temperature field (in the Laplace space domain) are denoted as:

[0109]

[0110]

[0111]

[0112]

[0113] Taking the 4 - spud drilling of a shale gas well as an example, the casing seals the vertical section (3 - spud), and the build - up section and the horizontal section are drilled with open - hole.

[0114] Then the unknown Q can be obtained from the system of equations AQ = B:

[0115]

[0116]

[0117]

[0118]

[0119]

[0120] Annulus of the horizontal section wellbore Inside the drill string At the wellbore wall And the formation The analytical solution of the temperature field (in the Laplace spatial domain) is denoted as:

[0121]

[0122]

[0123]

[0124]

[0125] Taking the 4 - spud drilling of a shale gas well as an example, the casing seals the vertical section (3 - spud), and the build - up section and the horizontal section are drilled with open - hole. Then the unknown Q can be obtained from the system of equations AQ = B:

[0126] Q=(Q 11 Q 12 Q 21 Q 22 Q 31 Q 32 Q′ 1 Q′ 2 Q″ 1 Q″ 2 ) T

[0127] B=(B 1 B 2 B 3 B 4 B 5 B 6 B 7 B 8 B 9 0)T

[0128]

[0129] In the calculation formula of the analytical solution of the transient temperature field described above:

[0130]

[0131]

[0132]

[0133]

[0134]

[0135]

[0136]

[0137]

[0138] a 11 = Xx 1，1

[0139] a 12 = Xx 2，1

[0140]

[0141]

[0142]

[0143]

[0144]

[0145]

[0146]

[0147]

[0148]

[0149]

[0150]

[0151]

[0152]

[0153]

[0154]

[0155]

[0156]

[0157]

[0158]

[0159]

[0160]

[0161]

[0162]

[0163]

[0164]

[0165]

[0166]

[0167]

[0168]

[0169]

[0170]

[0171]

[0172]

[0173]

[0174]

[0175]

[0176]

[0177]

[0178]

[0179]

[0180]

[0181]

[0182]

[0183] B x ＝0

[0184]

[0185]

[0186]

[0187]

[0188]

[0189]

[0190]

[0191]

[0192]

[0193]

[0194]

[0195]

[0196]

[0197]

[0198]

[0199]

[0200]

[0201]

[0202]

[0203]

[0204]

[0205]

[0206]

[0207]

[0208]

[0209]

[0210]

[0211]

[0212]

[0213] λ Tk =c rk / k rk

[0214]

[0215]

[0216]

[0217]

[0218]

[0219] The meanings of the symbols in the above formulas include:

[0220] A 0 is the geothermal gradient, °C / m; B 0 is the surface temperature, °C; T0 is the initial formation temperature v = A o z + B 0 , °C; z j varies in the range of [0, H KOP , z l varies in the range of (H KOP , H i , z h varies in the range of (H i , H]. H KOP is the depth of the kick-off point, m; H hv is the vertical depth of the horizontal section, m; H hl is the measured depth at the end of the build section (start of the horizontal section), m; H is the actual well depth. αKOP is the inclination angle at the kick-off point, °; α hv is the actual inclination angle of the horizontal section, °; K z is the build rate, (°) / 30m; K 0 () is the modified Bessel function of the second kind of order zero; s is the complex frequency introduced by the Laplace transform, 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) are the wellbore radii of different opening orders, m; z is the well depth, m; t is the drilling fluid circulation time, s; is the Laplace operator in the r direction.

[0221] A annu , A dp，i are the cross-sectional areas of the wellbore annulus and the inside of the drill string respectively and m 2 ; the annulus diameter d annu is defined as m; r ci and r w are the inner radius of the casing in the cementing section and the radius of the wellbore wall in the open hole section respectively, 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; v annu , v dp are the flow velocities in the wellbore annulus and the inside of the drill string respectively and m / s; Q annu and Q dp are the drilling fluid displacements in the wellbore annulus and the inside of the drill string respectively, m 3 / s; m; ρ m is the drilling fluid density kg / m 3 ; c m is the specific heat capacity of the drilling fluid, J / (kg·K); c s , c f are the specific heat capacities of the solid and liquid phases inside the fragmented rock, J / (kg·K); ρ s , ρ f are the densities of the solid and liquid phases inside the fragmented rock, kg / m 3 ; v I , v II are the volume ratios of the matrix system and the fracture system in the fragmented rock respectively, dimensionless; φ I , φ II are the porosities of the matrix system and the fracture system respectively, dimensionless; c r is the total specific heat capacity of the fragmented rock (Unfilled type) and (Filled type), J / (kg·℃); k s , k f is the thermal conductivity of the solid and liquid phases inside the fractured rock, W / (m·℃); k r is the total thermal conductivity of the fractured rock (Unfilled type) and (Filled type), 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 in 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 , the thermal conductivity of the drill string, W / (m·℃); d dp，o is the outer diameter d of the drill string dp，o = 2r dp，o , m; χ θ is the overall heat transfer coefficient from the annulus drilling fluid to the outer wall of the cement sheath W / (m 2 ·K). h θ is the heat transfer coefficient h at the wellbore wall or the inner wall of the innermost casing θ = Nu annu k m / d cas，i , where the convective heat transfer coefficient h at the open-hole wellbore wall w is 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 wellbore radius r of the kth drilling interval wk (or the inner radius r of the innermost casing 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 jth casing or cement sheath, m; - the inner diameter of the jth casing or cement sheath, m.

[0222] Tsurf is the injection temperature at the wellhead, in °C; φ 3 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 flow behavior index in the drill string dimensionless; is the power-law drilling fluid consistency coefficient in the drill string Pa•s n ; Re dp 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 flow behavior index in the drill string dimensionless; is the power-law drilling fluid consistency coefficient in the annulus Pa·s n ; Re annu，k is the Reynolds number in the annulus dimensionless; is the laminar Reynolds number in the drill string or wellbore annulus dimensionless; is the turbulent Reynolds number in the drill string or wellbore annulus dimensionless; is the Reynolds number in the transition zone of the drill string or wellbore annulus dimensionless; is the effective viscosity of the power-law drilling fluid in the annulus Pa•s; Pr dp is the Prandtl number in the drill string dimensionless; Pr annu，k is the Prandtl number in the wellbore annulus dimensionless; is the Nusselt number at the wellbore wall or the inner wall of the innermost casing dimensionless; is the turbulent Nusselt number in the drill string dimensionless; is the laminar Nusselt number in the wellbore annulus dimensionless; is the turbulent Nusselt number in the wellbore annulus dimensionless; For the Nusselt number of laminar flow in the wellbore annulus Dimensionless; the fitting coefficients c and β are respectively defined and β = 1.013e -0.067l , dimensionless; l is the ratio of the inner radius of the wellbore or casing to the outer radius of the drill string For the Nusselt number of transitional flow Satisfy Related to the inside of the drill string and the annulus, dimensionless

[0223] The above k values involved in the subscript take k = j, l, h respectively, representing the straight well section (j), deviated well section (l) and horizontal section (h). The superscript symbol "~" represents the Laplace transform of the variable

[0224] Step eight: Use the density-pressure-temperature coupling relationship of the drilling fluid measured by the high-temperature and high-pressure densitometer to establish a dynamic ESD prediction model considering the coupling of annulus temperature and static liquid column pressure disturbance

[0225] The dynamic ESD prediction model at any well depth h is as follows

[0226]

[0227] The bottom-hole dynamic ESD prediction model is calculated as follows

[0228]

[0229] Γ(P(z, t), T a (z, t)) = a(P(z, t) - P 0 ) - b(T a (z, t) - T 0 ) + c(T a (z, t) - T 0 ) 2

[0230] In the above formula, the calculation node lengths Δh and ΔH are respectively defined as Δh = h / m and ΔH = H / n, where m; m and n are the number of calculation nodes, dimensionless; h is the well depth at the research position, m; H is the well depth, m; the wellhead pressure P 0 is P(z = 0, t) = 0.1, MPa; the wellhead annulus temperature T 0 is defined as T(h = 0, t) = T a , °C; P i (z, t) is the annulus temperature T at the well depth z = Δh × i (i = 1, 2,... n) in the well at the circulation time t a，iThe static hydrostatic pressure of the wellbore affected by (z, t), MPa; g is the acceleration due to gravity, 9.81 m / s 2 ; ρ m0 (P 0 , T 0 ) is the density of the drilling fluid affected by the wellhead pressure P 0 and the temperature T 0 , kg / m 3 ; Γ(P i (z, t), T a，i (z, t)) is the density-pressure-temperature coupling function formula proposed by Wang Haige et al. The annular static hydrostatic pressure P h (z = h, t) at the research location well depth h is MPa; the annular static hydrostatic pressure P H (z = H, t) at the bottom of the well H is MPa; a, b, c: characteristic constants of the drilling fluid, 1 / MPa, 1 / °C, 1 / (°C·°C).

[0231] Step Nine: Based on the dynamic ESD prediction model, combined with the annular pressure loss calculation principle proposed by Wang Haige and Ma Xianming et al., establish an annular dynamic ECD (annular transient circulating pressure) prediction model for the wellbore;

[0232] The prediction of the annular dynamic ECD(z, t) (annular transient circulating pressure p m (z, t)) includes:

[0233]

[0234] p m (z = h, t) = ECD(z = h, t)gh

[0235]

[0236]

[0237]

[0238]

[0239]

[0240]

[0241]

[0242]

[0243]

[0244]

[0245]

[0246]

[0247]

[0248] ECD(z = h, t) is the equivalent circulating density corresponding to the research depth h and the drilling fluid circulation time t, kg / m 3 ; p m (z = h, t) is the wellbore annulus transient circulation pressure corresponding to the research depth h and the drilling fluid circulation time t, MPa; ΔP bed : The annulus pressure loss per unit length in the presence of a cuttings bed, Pa; H Tcb : Dimensionless cuttings bed height; ΔP nobed : The annulus pressure loss per unit length without a cuttings bed, Pa; S: The ratio of the density of cuttings to the density of drilling fluid, dimensionless; Critical annulus return velocity V c is, m / s; T c is the cuttings bed height, 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 density of cuttings, kg / m 3 ; d s is the average cuttings particle diameter, m. γ b is the well deviation angle, °; k 1 is the correction coefficient reflecting the influence of drill string rotation on ECD, 0.7 ≤ k 1 ≤ 1.3, dimensionless; is the ratio of the average pressure gradient in a concentric annulus to the average pressure gradient in an eccentric annulus; dimensionless; is the ratio of the inner diameter of the annulus to the outer diameter of the annulus; dimensionless; J represents the pressure gradient ratio related to laminar (lami), transitional (trans), and turbulent (turb) flows respectively. The pressure gradient ratio for transitional flow is defined as: The Fanning friction factor f in the wellbore annulus is defined as (laminar flow) and (turbulent flow), where, dimensionless; The cuttings volume content C in the annulus s , %; v s is the cuttings particle sliding velocity, m / s; C e is the cuttings inlet concentration dimensionless. ROP is the rate of penetration, m / h.

[0249] Step 10. Analyze the pore pressure field and stress field of the wellbore surrounding rock in a fractured formation under non-uniform in-situ stress conditions due to the coupled thermo-hydro-mechanical effect by using the analytical solution of the transient wellbore temperature field, the constitutive equations of the dual-porosity thermo-elasticity theory, and the mass conservation equation;

[0250] The constitutive equations of the dual-porosity thermo-elasticity theory:

[0251]

[0252]

[0253]

[0254] and the mass conservation equation

[0255]

[0256] In the formulas

[0257]

[0258] where the superscripts I and II represent the matrix system and the fracture system, dimensionless; σ ij (i, j ∈ r, θ, z) is the stress tensor of the wellbore surrounding rock, MPa; ε ij (i, j ∈ r, θ, z) is the strain tensor of the wellbore surrounding rock, dimensionless; p I , p II are the pore pressures of the matrix system and the fracture system of the wellbore surrounding rock, MPa; is the bulk modulus of the fractured rock, MPa; is the shear modulus of the fractured rock, MPa; α I , α II are the Biot coefficients (effective stress coefficients) of the matrix system and the fracture system, dimensionless; B I , B II are the Skempton coefficients of the matrix system and the fracture system, dimensionless; M ij is the Biot modulus corresponding to the matrix system, the fracture system, and the matrix-fracture coupling system, MPa; K s and K f are the bulk moduli of the solid and liquid phases inside the fractured rock, MPa; α s and α f are the volumetric thermal expansion coefficients of the solid and liquid phases inside the fractured rock, 1 / K; ζ I , ζ II are the change amounts of the fluid content of the matrix system and the fracture system, dimensionless; w is the fracture width of the fractured rock, m; δ is the fractured rock

[0259] Fracture spacing of the rock, m; k I , k II are the permeabilities of the matrix system and the fracture system, m 2 , k II = 2 / 3 * 8.35 * (2w)4 / δ; μ I , μ II are the permeabilities of the matrix system and the fracture system, 10 -9 MPa·s; κ I , κ II is the permeability coefficient of the matrix system and the fracture system, κ = k / μ, 10 9 m 2 / (MPa·s); Γ is the mass flow (flux) transfer coefficient between the matrix system and the fracture system, 10

[0260] 1 / (MPa·s), Γ; 9 is the Laplace operator in the r-θ plane; δ is the Kronecker delta, δ ij = 1 (i = j), δ ij = 0, (i ≠ j); ij ;

[0261] Step Eleven: Determine the safe density window of the fractured formation, SMWW = {ρ c , ρ f}, by using the pore pressure field and stress field of the wellbore surrounding rock under the action of thermo-hydro-mechanical coupling in the fractured formation under non-uniform in-situ stress conditions, the Mohr-Coulomb criterion, and the tensile fracture criterion.

[0262] The calculation formulas for the stress field and pore pressure field of the wellbore surrounding rock are as follows:

[0263]

[0264]

[0265]

[0266]

[0267]

[0268]

[0269]

[0270] In the formula, p 0 is the initial pore pressure of the formation, MPa; p m is the transient circulating pressure in the wellbore annulus, MPa; the average formation stress P0 and shear stress S 0 are respectively denoted as:

[0271]

[0272]

[0273] In the above formula, the principal stress components and shear stress components are determined by . Among them, the in-situ stress matrix σ ics , the transformation matrix (I) from the in-situ stress coordinate system ICS(X i , Y i , Z i ) to the geodetic coordinate system GCS(X g , Y g , Z g ), and the transformation matrix (b) from GCS to the borehole coordinate system BCS(X b , Y b , Z b ) are respectively defined as:

[0274]

[0275]

[0276]

[0277] Among them, Ω i is the angle between the azimuth of the maximum horizontal in-situ stress and the true north azimuth, °; γ i is the angle between the overburden pressure and the vertical direction, °; Ω b is the borehole azimuth, °; γ b is the well deviation angle, °. σ H is the maximum horizontal in-situ stress, MPa; σ h is the minimum horizontal in-situ stress, MPa; σ v is the overburden pressure, MPa; the intermediate conversion angle θ r is defined as °.

[0278]

[0279]

[0280]

[0281]

[0282]

[0283] ξ 3 = ξ Tk β 3 = β Th

[0284]

[0285]

[0286]

[0287]

[0288]

[0289]

[0290]

[0291]

[0292]

[0293]

[0294]

[0295]

[0296]

[0297]

[0298]

[0299] Wherein, x takes ξ or β;

[0300]

[0301]

[0302]

[0303]

[0304]

[0305]

[0306]

[0307]

[0308] The Mogi-Coulomb strength criterion is often applied to the evaluation of borehole collapse failure. Its commonly used octahedral shear stress τ oct and mean effective stress σ′ m are expressed as:

[0309]

[0310]

[0311]

[0312] In the formula, τ oct is the octahedral shear stress, σ m is the mean effective stress; c and correspond to the inherent cohesive force and internal friction angle of the rock respectively. The above maximum effective principal stress σ′ 1 , intermediate effective principal stress σ′ 2 and minimum effective principal stress σ′ 3 correspond to the matrix tensor σ ccs [σ ij , i, j ∈ (r, θ, z)] eigenvalues σ n , which are determined by the following determinant.

[0313]

[0314] For borehole collapse (caving) caused by shear failure of the rock body, based on the above strength failure criterion and borehole stress, the calculation process of the collapse pressure for safe drilling (the lower limit is the larger value compared with the pore pressure) is as follows:

[0315] First, by defining the well deviation angle γ bi = i° (i = 0:i:90), azimuth angle Ω bj = j° (j = 0:j:360), borehole peripheral angle θ k = k° (k = 0:k:360) and the pressure array to determine the final required collapse pressure value;

[0316] Among them, is set as the horizontal maximum principal in-situ stress σ H or a larger stress value; given the matrix (γ bi , Ω bj ), the pressure p ml increases from 0 to at intervals of 1. When the judgment condition is satisfied, the collapse pressure matrix corresponding to the borehole peripheral angle θ k can be obtained The maximum value in the final screened matrix is used as the collapse pressure value corresponding to the given well deviation and azimuth angle (γ bi , Ω bj ); the equivalent density of the collapse pressure value is used as the lower limit of the safety density window SMWW = {ρ c , ρ f} for the fractured formation;

[0317] The tensile fracture formed from the wellbore when the minimum effective principal stress on the rock around the well reaches or exceeds the tensile strength of the porous rock is:

[0318] σ′ 3 = -s t

[0319] S t = σ c / ω

[0320]

[0321] In the formula: s t is the tensile strength of the fractured rock; σ c is the uniaxial compressive strength; the coefficient ω can be taken as 12.

[0322] Then, by defining the well deviation angle γ bi = i° (i = 0: i: 90), azimuth angle Ω bj = j° (j = 0: j: 360), wellbore perimeter angle θ k = k° (k = 0: k: 360) and the pressure array to determine the final required fracture pressure value;

[0323] Among them, is set to be greater than the maximum value of the three principal in-situ stresses (σ H , σ h , σ v ); for the given matrix (γ bi , Ω bj ), the pressure p ml decreases from to 0 at an interval of 1. When the judgment condition σ′ 3 + s t ≤ m is satisfied, the fracture pressure matrix corresponding to the wellbore perimeter angle θ k can be obtained The minimum value in the final screened matrix is used as the fracture pressure value corresponding to the given well deviation and azimuth angle (γ bi , Ω bj ); the equivalent density of the fracture pressure value is used as the upper limit of the safety density window SMWW = {ρ c , ρ f} for the fractured formation.

[0324] Note that the smaller the values of the positive real numbers i, j, k, and l, the higher the accuracy of the collapse pressure and fracture pressure values determined by the above method. In addition, the effective stress value mentioned in the present invention is defined as

[0325] The present invention determines the mechanical parameters and physical properties parameters (including thermal physical properties parameters) of the pore medium required for model calculation through laboratory tests and imaging logging data. By comprehensively considering the dual-porosity thermoelastic theory model and the rock failure (shear and tension) model that couple dynamic temperature and pressure perturbation boundary effects, the pre-drilling safety density window for (ultra) deep fractured formations is derived, and a time-dependent density window diagram affected by different fracture widths and fracture spacings (quantifying the plugging size) is drawn, so as to provide a scientific basis for on-site construction personnel to determine a reasonable drilling density window, effectively prevent wellbore instability problems, and prevent downhole complex accidents from occurring.

[0326] The above has specifically described the embodiments of the present invention, but the present invention is not limited to the described embodiments. Those skilled in the art can also make various equivalent variations or substitutions without departing from the spirit of the present invention, and these equivalents or substitutions are all included within the scope defined by the claims of the present invention.

Claims

1. A quantitative control method for the wellbore stability of a horizontal well in a fractured formation under transient temperature and pressure coupling, characterized in that: The following steps are involved: Step 1: Use a gas permeameter to test the permeability of fractured cores and intact cores; Step 2: Testing the physical parameters of fractured cores based on 3D CT scanner and logging data; Step 3: Test the porous medium mechanical parameters of the fractured core and the intact core by using the rock triaxial compression test, and obtain the porous medium mechanical parameters corresponding to the fracture system in the fractured core and the rock strength parameters of the fractured core by using the equivalent sequence model; Step 4: Use a thermal expansion coefficient tester and a Hot Disk thermal constant analyzer to test the thermal physical parameters of the fractured core and the intact core; Step 5: Use acoustic emission test to test the ground stress, and obtain the ground stress distribution by back-calculating the structural stress coefficient and combining it with the logging data; Step 6: Obtain the original pore pressure distribution of the formation by inversion using logging parameters; Step 7: Using the API RP 13D rheological drilling fluid circulation temperature field control equation and Laplace transform processing during the drilling process, four types of transient temperature field analytical solutions are analyzed; Step 8: Using the coupled relationship of drilling fluid density, pressure and temperature measured by a high-temperature and high-pressure density meter, a dynamic ESD prediction model coupling the annular temperature and static liquid column pressure disturbance is established; Step 9: Based on the dynamic ESD prediction model and the annular pressure loss calculation method, a wellbore annulus dynamic ECD prediction model is established; Step 10: Analyze the pore pressure field and stress field of the rock around the well in the fractured formation under the condition of non-uniform geostress under the action of thermal fluid-solid coupling using the analytical solution of the transient wellbore temperature field, the dynamic ECD prediction model of the wellbore annulus, the constitutive equation of the dual-porosity thermoelasticity theory and the mass conservation equation; Step 11: Determine the safe density window SMWW of the fractured formation by using the pore pressure field and stress field of the surrounding rock of the well in the fractured formation under the condition of non-uniform geostress under the action of thermal fluid-solid coupling, Mogi-Coulomb criterion and tensile fracture criterion. c , ρ f }.

2. The horizontal wellbore stability quantitative control method according to claim 1 is characterized in that: The physical property parameters of the fractured core in step 2 include fracture spacing and fracture width.

3. The horizontal wellbore stability quantitative control method according to claim 1, characterized in that: The porous medium mechanical parameters in step three include Young's modulus, Poisson's ratio, Skempton coefficient, and fluid bulk modulus; the rock strength parameters include cohesion, internal friction angle, and tensile strength.

4. The horizontal wellbore stability quantitative control method according to claim 1, characterized in that: The thermal physical property parameters in step 4 include solid phase thermal expansion coefficient, liquid phase thermal expansion coefficient, thermal conductivity, and specific heat capacity.

5. The horizontal wellbore stability quantitative control method according to claim 1, characterized in that: The geostress in step five includes overburden stratum pressure, horizontal maximum geostress and horizontal minimum geostress.

6. The horizontal wellbore stability quantitative control method according to claim 1, characterized in that: The four types of transient temperature field analytical solutions in step seven include the analytical solution of the temperature field inside the drill string, the analytical solution of the temperature field in the wellbore annulus, the analytical solution of the wellbore wall temperature field, and the analytical solution of the radial diffusion temperature field of the formation; The analytical solutions of the four types of transient temperature fields in horizontal wells are further divided into vertical well section, deflection section and horizontal section, and their expressions include: Vertical wellbore annulus Inside the drill string Well wall and strata The analytical solution of the temperature field is recorded as: Wellbore annulus in the deflection section Inside the drill string Well wall and strata The analytical solution of the temperature field is recorded as: Horizontal wellbore annulus Inside the drill string Well wall and strata The analytical solution of the temperature field is recorded 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 H is the well depth at the inclination point, m; hυ is the vertical depth of the horizontal section, m; H hl is the inclined depth at the end of the deflection section, m; H is the actual well depth; α KOP is the well inclination angle at the inclination point, °; α hυ is the actual well inclination angle of the horizontal section, °; ​​K z is the build-up rate, (°) / 30m; K0() is the modified second-order Bessel function of 0th order; s is the complex frequency introduced by Laplace transform, which is related to time; r is the radial distance from the center of the wellbore to a certain position inside the formation, m; r wk (k=j, l, h) is the wellbore radius of different opening times, m; z is the well depth, m.

7. The horizontal wellbore stability quantitative control method according to claim 1, characterized in that: The dynamic ESD of coupling the annular space temperature and the static liquid column pressure disturbance in step eight includes: 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 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 research 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 well depth z = Δh × i (i = 1, 2, ... n) is affected by the annular temperature T a，i (z, t) is the wellbore hydrostatic column pressure, MPa; g is the gravitational acceleration, 9.81 m / s 2 ρ m0 (P o , T0) is the drilling fluid density 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; the annular static liquid column pressure P at the well depth h of the research location h (z = h, t) is MPa; a, b, c: drilling fluid characteristic constants, 1 / MPa, 1 / ℃, 1 / (℃·℃).

8. The horizontal wellbore stability quantitative control method according to claim 1, characterized in that: The wellbore annulus dynamic ECD in step nine includes: p m (z=h,t)=ECD(z=h,t)gh Where, ECD(z=h, t) is the equivalent circulating density corresponding to the research depth h and the drilling fluid circulation time t, kg / m 3 ;p m (z = h, t) is the transient circulation pressure of the wellbore annulus corresponding to the research depth h and the drilling fluid circulation time t, MPa; ΔP bed : Annulus pressure loss per unit length when cuttings bed exists, Pa.

9. The horizontal wellbore stability quantitative control method according to claim 1, characterized in that: The pore pressure field and stress field in step 10 include: Where: p0 is the initial pore pressure of the formation, MPa; p m is the transient circulating pressure of the wellbore annulus, MPa; σ r , σ θ , σ z and τ rθ are the radial stress, tangential stress, axial stress and shear stress in the rock around the well, MPa; T θz and τ zr is the out-of-plane shear stress, MPa; P0 and S0 are the original average formation stress and shear stress, MPa; θ is the wellbore angle, the vector radius of the research location and the horizontal maximum ground stress σ H Angle of azimuth, °; θ r To convert the intermediate angle, define ° and are the principal stress component and shear stress component in the wellbore coordinate system, MPa.

10. The horizontal wellbore stability quantitative control method according to claim 1, characterized in that: The Mogi-Coulomb criterion in step 11 is: In the formula, τ oct is the octahedral shear stress, σ m is the mean effective stress; c and They correspond to the inherent cohesion and internal friction angle of the rock respectively; the above-mentioned maximum effective principal stress σ′1, the intermediate effective principal stress σ′2 and the minimum effective principal stress σ′3.

11. The horizontal wellbore stability quantitative control method according to claim 1, characterized in that: The tensile rupture criterion in step 11 is: σ′3=-S t S t =s c / h Where: S t is the tensile strength of crushed rock; c is the uniaxial compressive strength; the coefficient ω can be taken as 12.

12. The horizontal wellbore stability quantitative control method according to claim 1, characterized in that: In the step 11, the safety density window of the fractured stratum SMWW is determined as follows: c , ρ f The process includes: First, by defining the well inclination angle γ bi =i°(i=0:i:90), azimuth angle Ω bj =j°(j=0:j:360), well circumference angle θ k = k°(k=0:k:360) and pressure array To determine the final required collapse pressure value; in, Set as the maximum horizontal principal stress σ H or greater stress value; given the matrix (γ bi ,Ω bj ), pressure p ml Increment from 0 to When the judgment condition is met The wellbore angle θ can be obtained k The corresponding collapse pressure matrix Finally, the matrix is ​​selected The maximum value of the given well inclination and azimuth (γ bi ,Ω bj ) corresponding to the collapse pressure value; the collapse pressure value equivalent density is used as the safety density window of the fractured formation SMWW = {ρ c , ρ f }lower limit; Then, by defining the well inclination angle γ bi =i°(i=0:i:90), azimuth angle Ω bj =j°(j=0:j:360), well circumference angle θ k = k°(k=0:k:360) and pressure array To determine the final required burst pressure value; in, Set to be greater than the three principal in-situ stresses (σ H , σ h , σ υ ) maximum value; given the matrix (γ bi ,Ω bj ), pressure p ml At intervals of 1 from Decreases to 0, when the judgment condition σ′3+S is met t ≤m can obtain the wellbore angle θ k The corresponding fracture pressure matrix Finally, the matrix is ​​selected The minimum value of the given well inclination and azimuth (γ bi ,Ω bj ) corresponding to the fracture pressure value; the fracture pressure value equivalent density is used as the fracture formation safety density window SMWW = {ρ c , ρ f } upper limit.

Images