Method and system for calculating and controlling formation pressure of pressure-controlled drilling based on multi-field coupling

Abstract

The invention relates to a pressure-controlled drilling formation pressure calculation and control method and system based on multi-field coupling, and belongs to the field of oil exploration and development. The method comprises the steps that 1, an industrial personal computer is connected with a logging instrument, and basic data needed by calculation are obtained in real time; 2, shaft-stratum space domain grids are divided, and drill rod and annulus temperature distribution and stratum temperature distribution at different distances from a borehole are calculated; 3, considering the thermal-fluid-solid multi-field coupling influence, and calculating well circumference stresses at different well depth positions in elastic-plastic regions; 4, solving a real-time formation pore pressure profile after multi-factor coupling correction; 5, calculating real-time stratum fracture pressure profiles and collapse pressure profiles at the well walls at the different well depth positions after multi-factor coupling correction in the elastic-plastic areas; and 6, determining a bottom hole pressure control standard, calculating in real time based on a shaft hydraulic parameter calculation model, and controlling the wellhead back pressure in real time through an industrial personal computer. The method can effectively improve the calculation precision of the formation pressure during the pressure-controlled drilling period.

Description

Technical Field

[0001] The present invention belongs to the field of oil exploration and development, and specifically relates to a method and system for calculating and controlling formation pressure in managed pressure drilling based on multi-field coupling. Background Art

[0002] The oil and gas exploration and development have gradually entered the deep water and deep layer era, and it is of great significance to efficiently develop oil and gas energy under complex geological conditions. On the one hand, the long wellbore indicates that there are significant lithological differences in the vertical depth of the wellbore. Generally, salt gypsum layers and shallow deep water layers mostly show elastoplastic characteristics, and the lithology of deep shale layers mostly shows elastic characteristics. This characteristic leads to complex situations such as shallow wellbore wall collapse, deep wellbore fracture or overflow during deep water drilling. On the other hand, after the wellbore is drilled, affected by the multi-field coupling of heat-flow-solid in the lateral range, the formation pressure (including formation pore pressure, formation fracture pressure and formation collapse pressure) is not constant. Inaccurate calculation of formation pressure can easily lead to accidents such as wellbore instability, overflow and loss during drilling. Handling these accidents takes a long non-production time, causing huge personnel and economic losses to the oil and gas field development.

[0003] Managed pressure drilling technology is a drilling technology that has been widely applied in recent years. Its principle is based on accurate formation pressure boundary conditions. Through real-time calculation of wellbore hydraulic parameters, key hydraulic parameters such as wellhead back pressure, drilling fluid displacement and density are adjusted in real time to control the fluid pressure in the wellbore within the formation pressure safety window at all times, ensuring drilling safety. The formation pressure safety window is the safety interval between the minimum value of the formation pore pressure and the formation collapse pressure and the formation fracture pressure. Therefore, the real-time and accurate calculation of formation pressure is extremely important in the implementation of managed pressure drilling technology. It clarifies the key boundary of wellbore pressure control and determines the success or failure of managed pressure drilling.

[0004] However, for complex geological conditions in deep water and deep layers, the current bottom hole pressure control standard during managed pressure drilling is the fixed formation pressure predicted before drilling. There is no real-time calculation method and control system for formation pressure in managed pressure drilling that considers the influence of multi-field coupling of heat-flow-solid at home and abroad. On the one hand, due to different lithologies in the long wellbore formation and different wellbore fracture conditions, it is necessary to determine the wellbore fracture conditions in elastoplastic regions separately to obtain an accurate calculation method for formation pressure. On the other hand, after the wellbore is drilled, due to the flow disturbance of the drilling fluid, the original heat-flow-solid equilibrium system is broken, and the effective stress around the wellbore will be redistributed. It is necessary to use logging data to quantitatively analyze the formation pressure disturbance in real time and accurately determine the real-time control boundary of wellbore pressure. Summary of the Invention

[0005] Aiming at the deficiencies existing in the prior art, the present invention provides a method and system for calculating and controlling formation pressure in managed pressure drilling based on multi-field coupling. In view of the changes in the wellbore-formation coupled temperature field and the mass and heat transfer between fluid and solid, the dynamic changes of formation pressure during managed pressure drilling are calculated. This method can accurately calculate the formation pressure in real time, providing theoretical and technical support for managed pressure drilling in complex formation pressure systems.

[0006] Based on real-time logging data and considering the influence of multi-field coupling of heat-fluid-solid, the present invention calculates the formation pressure in real time. Through the hydraulic calculation results, the automatic choke device is controlled in real time to adjust the wellhead back pressure, so that the wellbore pressure is always within the formation pressure safety window, realizing safe and efficient managed pressure drilling in complex formations. The invention provides theoretical and technical support for the accurate real-time calculation of formation pressure during managed pressure drilling and ensuring drilling safety.

[0007] To solve the above technical problems, the technical solutions adopted by the present invention are as follows: A method for calculating and controlling formation pressure in managed pressure drilling based on multi-field coupling, comprising: Step 1: The industrial control computer is connected to the logging instrument to obtain in real time the basic data required for calculation, including: well depth, displacement, inlet and outlet density, inlet and outlet temperature, and rate of penetration; the industrial control computer is connected to the automatic choke device to control the wellhead back pressure in real time; Step 2: Divide the wellbore-formation spatial domain grid, input the initial conditions and boundary conditions of the wellbore and formation temperatures, and calculate the temperature distributions of the drill pipe and annulus and the formation temperature distribution at different distances from the wellbore; Step 3: Considering the influence of multi-field coupling of heat-fluid-solid, calculate the wellbore stress at different well depth positions in the elastic-plastic regions , , ; among them, the radius of the plastic zone is calculated from the stress continuity conditions at the wellbore and the interface in the elastic-plastic regions; Step 4: Based on the overburden pressure profile obtained from logging data and the formation pore pressure profile predicted before drilling, combine with the effective stress principle to obtain the real-time formation pore pressure profile corrected by multi-factor coupling; Step 5: Calculate the real-time formation fracture pressure profile and collapse pressure profile at the wellbore wall at different well depth positions corrected by multi-factor coupling in the elastic-plastic regions; Step 6: Determine the bottom hole pressure control standard, calculate in real time based on the wellbore hydraulic parameter calculation model, and control the wellhead back pressure in real time through the industrial control computer.

[0008] Furthermore, in Step 1, the communication mode between the industrial control computer and the mud logging instrument adopts the WITS protocol. The industrial control computer obtains mud logging measurement data in real time, including: current well depth, bit depth, inlet and outlet flow rates, inlet and outlet densities, inlet and outlet temperatures, total pit volume, mechanical drilling rate, weight on bit, and rotary speed. The communication between the industrial control computer and the automatic choke device adopts PLC electric control, and the industrial control computer realizes the functions of automatically and manually adjusting the choke valve opening to control the wellhead back pressure.

[0009] Furthermore, in Step 2, the initial conditions of the wellbore and formation temperatures are the original formation temperatures. At the wellhead boundary, the drill pipe injection temperature is the mud outlet temperature obtained by the mud logging instrument in real time. At the bottom hole boundary, the drill pipe temperature is equal to the annulus temperature. The formation temperature infinitely far from the wellbore is not disturbed by the wellbore temperature and remains the original formation temperature all the time.

[0010] Furthermore, the wellbore-formation spatial domain grids are, from the inside out, the drill pipe, annulus, cement sheath, and formation respectively. Heat exchange occurs between the fluid in the drill pipe and the fluid in the annulus; heat exchange occurs between the fluid in the annulus and the fluid in the drill pipe and the formation fluid; the wellbore unit includes the drill pipe, annulus, and cement sheath, and the formation includes several formation units. Heat exchange occurs between adjacent formation units and between the formation unit and the adjacent wellbore unit. The heat transfer equations in the drill pipe, annulus, and formation are shown in Equations (1) to (3) respectively.

[0011] (1); (2); (3); Among them, the heat transfer intermediate variables A and B are expressed as in Equation (4): (4); Among them, and are the mass flow rates of the drilling fluid in the drill pipe and annulus respectively, with the unit of kg / s, and are expressed as in Equation (5): (5); The comprehensive heat transfer coefficients of the drill pipe and annulus are expressed as in Equations (6) and (7): (6); (7); In the formula, , , are the drill pipe temperature, annulus temperature, and formation temperature respectively, in °C; is the formation temperature at the initial moment, in °C;, are the cross-sectional areas of the drill pipe and annulus respectively, in m 2 ; , are the flow rates of the drilling fluid inside the drill pipe and in the annulus, respectively, in m / s; , are the densities of the drilling fluid and the formation, in kg / m 3 ; , are the specific heat capacities of the formation and the drilling fluid, respectively, in J / (kg·°C); , , are the thermal conductivities of the drill pipe and the casing, the cement sheath and the formation, respectively, in W / (m·°C); , , , , are the inner diameter of the drill pipe, the inner diameter of the annulus, the outer diameter of the drill pipe, the outer diameter of the annulus and the wellbore diameter, respectively, in m; , are the total heat transfer coefficients between the drill pipe and the annulus, and between the annulus and the formation, respectively, in W / (m 2 ·°C); , , , are the convective heat transfer coefficients between the inner wall of the drill pipe, the outer wall of the drill pipe, the inner wall of the casing and the inner wall of the wellbore, respectively, in W / (m 2 ·°C); z is the distance from the wellhead, in m; r is the distance from the wellbore, in m; H shoe , H b are the casing shoe depth and the bottom hole depth, respectively, in m; h is the well depth, in m; t is the time, in s; The initial conditions of the wellbore and formation temperatures are as follows: Formation temperature at the initial moment: (8); The temperatures inside the drill pipe and in the annulus at the initial moment are equal to the formation temperature: (9); T 0 p,i 、 T 0 a,i are the temperatures inside the drill pipe and in the annulus at the initial moment, respectively; The boundary conditions of the wellbore and formation temperatures are as follows: The temperature of the drill pipe at the wellhead is always equal to the drilling fluid injection temperature: (10); The temperature of the drill pipe at the bottom of the well is always equal to the annulus temperature: (11); In formula (11), T n p,N represents the temperature of the drill pipe at the bottom of the well at the nth moment, T n a,N represents the annulus temperature at the bottom of the well at the nth moment; In the formula, is the seawater surface temperature, °C; is the drilling fluid injection temperature, °C; is the geothermal gradient, °C; H sea is the seawater depth, m; is the seabed temperature.

[0012] Furthermore, in step three, the wellbore stress includes in-situ stress, thermal stress caused by the wellbore-formation temperature change, seepage stress caused by fluid seepage in the open hole section, and wellbore fluid pressure; among them, the in-situ stress is the wellbore stress existing before the formation is drilled, the thermal stress is calculated in real time from the wellbore-formation coupled temperature field, the influence of seepage in the open hole section is generated by the diffusion effect of wellbore fluid and formation fluid, and the stress generated by wellbore fluid pressure is generated by the holding effect; the formation around the wellbore is divided into a plastic region and an elastic region from the inside to the outside in sequence; calculate the radius of the plastic region affected by thermodynamics, and thus calculate the wellbore stress in different regions.

[0013] Furthermore, in step three, considering the multi-factor coupling influence of heat-fluid-solid, calculate the wellbore stress at different well depths, including in-situ stress, thermal stress caused by the wellbore-formation temperature change, seepage stress caused by fluid seepage in the open hole section, and wellbore stress generated by wellbore fluid pressure; specifically including: The in-situ stress is expressed as: (12); (13); In the formula, , , are the original radial, tangential and vertical stresses, MPa; is the maximum horizontal principal stress, MPa; is the minimum horizontal principal stress, MPa; is the vertical stress, MPa; is the density of rock or seawater, kg / m 3 ; , are the overburden pressure and the predicted formation pore pressure before drilling, MPa; is the Poisson's ratio of the rock, dimensionless; , is the tectonic stress coefficient, dimensionless; is the effective stress coefficient, dimensionless; R p is the radius of the plastic zone, m; r is the distance from the wellbore, m; θ is the wellbore angle, rad; Calculate the thermal stress according to the wellbore - formation temperature field. The thermal stress generated by the difference between the current formation temperature and the initial formation temperature is expressed as: (14); (15); In the formula, , , are the radial, tangential and vertical thermal stresses, MPa; is the thermal expansion coefficient of the rock, °C -1 ; E is the elastic modulus of the rock, MPa; R is the wellbore radius, m; is the distance from the wellbore r at which the formation temperature can be obtained from Step 2, °C; is the initial formation temperature, °C; T f ( r ) is the temperature difference considering heat transfer and not considering heat transfer at different wellbore distances; The seepage stress is expressed as: (16); In the formula, , , are the radial, tangential and vertical seepage stresses caused by wellbore seepage, MPa; is the fluid column pressure in the wellbore, MPa; is the seepage coefficient, dimensionless; φ is the porosity; The fluid pressure in the wellbore is expressed as: (17); In the formula, and are the radial stress and tangential stress around the wellbore generated by the fluid pressure in the wellbore, Mpa; Considering the above thermo - hydro - mechanical coupling factors, the total stress around the wellbore is expressed as: (18); In the formula, , , are the radial stress, tangential stress and vertical stress around the wellbore, Mpa; Therefore, the vertical stress is expressed as: (19); The formation lithology is divided into an elastic region and a plastic region. The radial stress and tangential stress in the elastic region are expressed as: (20); When solving the radial stress and tangential stress in the plastic region, the wellbore model is simplified to an axisymmetric plane strain problem, and the equilibrium differential equation is: (21); In the formula, and are the radial stress and tangential stress in the plane strain problem, Mpa; The yield function satisfies: (22); In the formula, is the rock cohesion, MPa; is the friction angle, °; Therefore, the radial stress and tangential stress in the plastic region are expressed as in Equation (23): (23); According to the stress continuity condition at the interface between the elastic-plastic regions: (24); Substituting Equation (20) and Equation (23) into Equation (24), the radius constraint condition of the plastic zone affected by temperature is obtained: (25).

[0014] Furthermore, in Step 4, the overburden pressure and the predicted formation pore pressure before drilling are known conditions. The multi-field coupling factors directly affect the vertical effective stress. According to the effective stress principle, the formation pore pressure corrected by multi-field coupling is calculated.

[0015] Furthermore, in Step 4, combining the predicted formation pore pressure before drilling, the wellbore stress calculated in real time and the effective stress principle, i.e., Equation (26), the formation pore pressure corrected by thermo-hydro-mechanical coupling is calculated p p : (26); (27).

[0016] Further, in step five, according to the different failure conditions of the elastic region and the plastic region, combined with the real-time updated formation pore pressure and wellbore stress, the formation fracture pressure and collapse pressure of the elastic zone and the plastic zone are calculated respectively.

[0017] Further, in step five, the formation fracture pressure and collapse pressure are important boundaries that make up the formation pressure safety window. According to the stress failure conditions of the elastic region and the plastic region, the formation fracture pressure and collapse pressure of different regions are calculated. Specifically, it includes: (1) Formation fracture belongs to tensile failure. When the effective tangential stress at the wellbore is greater than the rock tensile strength, the wellbore fails. The failure condition is expressed as: (28); In the formula, is the tangential stress, MPa; St is the rock tensile strength, Mpa; ① Elastic region: Substitute the tangential stress of the elastic formation in formula (20) into the failure condition formula (28). Among them, Adopt the corrected formation pore pressure to obtain the real-time calculation model of the formation fracture pressure in the elastic zone: (29); In the formula, P fe is the formation fracture pressure in the elastic zone, Mpa; ② Plastic region: Substitute the tangential stress of the plastic zone formation in formula (23) into the failure condition (28), and the real-time calculation model of the formation fracture pressure at the wellbore in the plastic region is obtained: (30); In the formula, P fp is the formation fracture pressure in the plastic zone, Mpa; (2) For the different compaction degrees and rock strengths of the elastic region and the plastic region, the wellbore instability criteria are selected by region; ① Elastic region: The rock strength in the elastic zone is high. The classical Mohr-Coulomb yield criterion is applied to judge the instability condition in this region. The Mohr-Coulomb yield criterion expressed in terms of the stress at the wellbore is: (31); Among them, , are the tangential stress and radial stress respectively; is the rock cohesion, MPa; is the rock friction angle, °; K is an intermediate variable, dimensionless; Substitute the tangential stress and radial stress of the elastic zone formation in Equation (20) into Equation (31), and the real-time calculation model of the formation collapse pressure considering thermal stress at the wellbore in the elastic zone is as follows: (32); In the formula, P ce is the formation collapse pressure in the elastic zone, Mpa; ② Plastic region: Numerical simulation shows that when the radius of the plastic zone exceeds 1.6 times the wellbore radius, it is considered that the wellbore is unstable, and the hydrostatic pressure at this time is the formation collapse pressure; Equation (33) is used as the instability condition of the wellbore in the plastic zone, and substituting it into Equation (25), the real-time calculation model of the formation collapse pressure at the wellbore in the plastic zone is obtained, as shown in Equation (34): (33); (34); In the formula, A p , A w are the area of the plastic zone and the wellbore area respectively, m 2 ; P cp is the formation collapse pressure in the plastic zone, MPa.

[0018] Furthermore, in Step 6, determine the wellbore pressure control standard through the real-time calculation result of the formation pressure, that is, the formation pressure safety window: the safety interval between the minimum value of the formation pore pressure and the formation collapse pressure and the formation fracture pressure; based on the wellbore hydraulic parameter calculation model, calculate the change of the wellhead backpressure with time; adjust the throttle valve opening in real time through the industrial control computer, and then adjust the wellhead backpressure in real time.

[0019] Furthermore, the specific implementation process of Step 6 is as follows: After the formation pore pressure, fracture pressure and collapse pressure considering thermal-fluid-solid coupling are calculated in real time, the formation pressure safety window is shown in Equation (35): (35); Among them, p bzmin is the lower limit of the formation pressure safety window, MPa; p bzmax is the upper limit of the formation pressure safety window, MPa; p ci and p fi are the formation collapse pressure and formation fracture pressure in different regions, MPa; i represents the region, i = e represents the elastic zone,i = p represents the plastic zone; The bottom hole pressure control standard is shown in Equation (36): (36); where, p bz is the bottom hole pressure control standard, MPa; is the pressure safety margin, MPa; the function of the pressure safety margin is to characterize that the bottom hole pressure control standard is within the formation pressure safety window; After knowing the bottom hole pressure control standard, based on the wellbore flow model, the target wellhead back pressure is calculated in real time, as shown in Equation (37): (37); where, p Goal is the target wellhead back pressure, MPa; g is the acceleration of gravity, m / s 2 ; p f is the wellbore flow friction, MPa; p f is the wellbore flow friction.

[0020] The formation pressure calculation and control system for pressure control drilling based on multi-field coupling includes: Wellbore circulation system, industrial control computer, logging system and dual-channel automatic choke device system; The wellbore circulation system includes a mud pump, a standpipe pressure gauge, a rotating control blowout preventer group, a wellbore, a casing pressure gauge, a flowmeter, a gas-liquid separator, and a mud pit; the circulation path is: mud pump, standpipe pressure gauge, rotating control blowout preventer group, wellbore, casing pressure gauge, dual-channel automatic choke device system, flowmeter, gas-liquid separator, mud pit; The logging system includes a logging instrument and a communication device; The dual-channel automatic choke device system includes a back pressure pump, a first flat valve, a second flat valve, a first choke valve, and a second choke valve.

[0021] During the pressure-controlled drilling process, the drilling fluid in the mud pit is injected into the drill pipe through a mud pump and circulates out of the wellbore through the annulus; the logging instrument real-time obtains the current well depth, bit depth, inlet and outlet flow rates, inlet and outlet densities, inlet and outlet temperatures, total pit volume, rate of penetration, weight on bit, and rotary speed, and transmits them to the industrial control computer based on WITS communication. The industrial control computer calculates the wellbore pressure profile in real time; calculates the formation pressure in real time to obtain the bottomhole control boundary, and based on the bottomhole control boundary, calculates the target wellhead backpressure in real time; after the drilling fluid circulates out of the wellbore, the wellhead backpressure is characterized by a casing pressure gauge; immediately afterwards, the drilling fluid enters the dual-channel automatic choke device system; the industrial control computer transmits the target wellhead backpressure to the automatic choke device in real time, and controls the opening degrees of the first choke valve, the second choke valve, the first flat valve, and the second flat valve through PLC electric control; when the reading of the casing pressure gauge stabilizes to the target wellhead backpressure, it is considered that the bottomhole pressure in the wellbore has reached the control range, and the wellbore pressure control operation is completed; thereafter, after the drilling fluid flows out of the dual-channel automatic choke device system, it returns to the mud pit through a flowmeter and a gas-liquid separation device, thus completing one cycle of the drilling fluid circulation, and the wellhead backpressure is controlled in real time.

[0022] Compared with the prior art, the present invention has the following beneficial effects: 1. The present invention considers the multi-field coupling effects of heat-fluid-solid, and calculates the total stress around the wellbore during pressure-controlled drilling starting from the in-situ stress, thermal stress, seepage stress, and wellbore fluid pressure. Based on the effective stress principle and the wellbore fracture condition, a formation pressure calculation model for the elastic zone and the plastic zone is established. The present invention provides a calculation method for the formation pressure safety window, which can effectively improve the calculation accuracy of the formation pressure during pressure-controlled drilling.

[0023] 2. The present invention can calculate the radius of the plastic zone affected by thermodynamics, and accurately calculate the fracture pressure and collapse pressure of different lithology formations according to different wellbore fracture conditions in the elastic-plastic regions. The present invention distinguishes between elastic-plastic formations and elastic formations, and realizes the accurate calculation of the formation pressure safety window for different types of formations.

[0024] 3. The present invention claims an automatic control system for pressure-controlled drilling with multi-factor coupling. This system combines real-time logging data, can calculate the formation pressure during pressure-controlled drilling in real time, determine the bottomhole pressure control standard, determine the target wellhead backpressure in real time through the calculation of wellbore hydraulic parameters, and realizes the precise automatic control of the wellbore pressure according to the automatic choke device control system. Compared with the traditional pressure-controlled drilling technology, the wellbore pressure control boundary of the present invention is more accurate, which promotes the development of the pressure-controlled drilling technology in complex formations.

[0025] 4. The method of the present invention is scientific and meets the engineering accuracy requirements. Description of the Drawings

[0026] Figure 1 It is a flowchart for real-time calculation and control of the formation pressure during pressure-controlled drilling; Figure 2 Structural diagram of the formation pressure calculation and control system for managed pressure drilling based on multi-field coupling; In the figure: 1. Industrial control computer; 2. Logging instrument; 3. Wellbore; 4. WITS communication; 5. PLC; 6. Mud pump; 7. Standpipe pressure gauge; 8. Rotary control blowout preventer group; 9. Casing pressure gauge; 10. Back pressure pump; 11. First flat valve; 12. Second flat valve; 13. First throttle valve; 14. Second throttle valve; 15. Flowmeter; 16. Gas-liquid separation device; 17. Mud pit.

[0027] Figure 3 Schematic diagram of the wellbore-formation spatial domain grid division; Figure 4 Schematic diagram of the variation of the formation pressure window with the circulation time at different well depths; Figure 5 Schematic diagram of the variation of the formation pressure window with the circulation time at a well depth of 1100 m; Figure 6 Schematic diagram of the variation of the formation pressure window with the circulation time at a well depth of 4680 m. Detailed implementation manners

[0028] The present invention will be further described in detail below in conjunction with the accompanying drawings of the specification and specific embodiments.

[0029] Embodiment 1 The formation pressure calculation and control method for managed pressure drilling based on multi-field coupling, as Figure 1 shown, includes: Step 1: The industrial control computer 1 is connected to the logging instrument 2 to obtain in real time the basic data required for calculation, including: well depth, displacement, inlet and outlet density, inlet and outlet temperature, and mechanical drilling rate; the industrial control computer 1 is connected to the automatic throttling device to control the wellhead back pressure in real time; Step 2: Divide the wellbore-formation spatial domain grid, input the initial conditions and boundary conditions of the wellbore 3 and formation temperature, and calculate the temperature distributions of the drill pipe and annulus and the formation temperature distribution at different distances from the wellbore; Step 3: Considering the influence of multi-field coupling of heat-fluid-solid, calculate the wellbore stress at different well depth positions in the elastic-plastic regions , , ; among them, the radius of the plastic zone is calculated from the stress continuity conditions at the wellbore and the interface in the elastic-plastic regions; Step 4: Based on the overburden pressure profile obtained from well logging data and the formation pore pressure profile predicted before drilling, combine with the effective stress principle to obtain the real-time formation pore pressure profile corrected by multi-factor coupling; Step 5: Calculate the real-time formation fracture pressure profile and collapse pressure profile at the wellbore at different well depths after multi-factor coupling correction in the elastic-plastic regions respectively; Step 6: Determine the bottom-hole pressure control standard. Based on the wellbore hydraulic parameter calculation model, calculate in real time and control the wellhead back pressure in real time through the industrial control computer 1.

[0030] Embodiment 2 The pressure control drilling formation pressure calculation and control method based on multi-field coupling according to Embodiment 1 is characterized in that: In Step 1, the communication mode between the industrial control computer 1 and the logging instrument 2 adopts the WITS protocol. The industrial control computer 1 obtains the logging measurement data in real time, including: current well depth, bit depth, inlet and outlet flow rates, inlet and outlet densities, inlet and outlet temperatures, total pit volume, rate of penetration, weight on bit, and rotary speed; and is connected to the logging instrument 2 to read these data on the logging instrument 2 in real time. The communication between the industrial control computer 1 and the automatic choke device adopts PLC5 electric control. The industrial control computer 1 realizes the functions of automatically and manually adjusting the choke valve opening, and then controlling the wellhead back pressure. It is necessary to test whether the communication between the industrial control computer 1 and the logging instrument 2 and the automatic choke device is normal before construction.

[0031] In Step 2, the initial conditions of the wellbore 3 and the formation temperature are the original formation temperature; at the wellhead boundary, the drill pipe injection temperature is the drilling fluid outlet temperature obtained by the logging instrument 2 in real time; at the bottom-hole boundary, the drill pipe temperature is equal to the annulus temperature; the formation temperature infinitely far from the wellbore is not disturbed by the temperature of the wellbore 3 and is always the original formation temperature.

[0032] The grid division of the wellbore-formation spatial domain is as Figure 3 shown. The wellbore-formation spatial domain grid is, from the inside out, the drill pipe, the annulus, the cement sheath, and the formation. The horizontal direction represents the distance from the wellbore center, and the vertical direction represents the well depth domain. Among them, i represents the well depth node, N is the bottom-hole depth node, j represents the wellbore distance node, and r is the far-end wellbore distance node; heat exchange occurs between the fluid in the drill pipe and the fluid in the annulus; heat exchange occurs between the fluid in the annulus and the fluid in the drill pipe and the formation fluid; the wellbore unit includes the drill pipe, the annulus, and the cement sheath, and the formation includes several formation units. Heat exchange occurs between adjacent formation units and between the formation unit and the adjacent wellbore unit; therefore, the injection of low-temperature fluid in the wellbore 3 will cause changes in the formation temperature, thereby affecting the stress state of the rock around the wellbore, and further changing the safe pressure window. The heat transfer equations in the drill pipe, the annulus, and the formation are shown in Equations (1) to (3) respectively.

[0033] (1); (2); (3); Among them, the heat transfer intermediate variables A and B are expressed as in Equation (4): (4); Wherein, and are the mass flow rates of the drilling fluid in the drill pipe and the annulus respectively, with the unit of kg / s, as expressed by Equation (5): (5); The overall heat transfer coefficients of the drill pipe and the annulus are expressed by Equations (6) and (7): (6); (7); In the formula, , , are the drill pipe temperature, the annulus temperature and the formation temperature respectively, in °C; is the formation temperature at the initial moment, in °C; , are the cross-sectional areas of the drill pipe and the annulus respectively, in m 2 ; , are the flow velocities of the drilling fluid inside the drill pipe and inside the annulus respectively, in m / s; , are the densities of the drilling fluid and the formation, in kg / m 3 ; , are the specific heat capacities of the formation and the drilling fluid respectively, in J / (kg·°C); , , are the thermal conductivities of the drill pipe and the casing, the cement sheath and the formation respectively, in W / (m·°C); , , , , are the inner diameter of the drill pipe, the inner diameter of the annulus, the outer diameter of the drill pipe, the outer diameter of the annulus and the wellbore diameter respectively, in m; , are the total heat transfer coefficients between the drill pipe and the annulus, between the annulus and the formation respectively, in W / (m 2 ·°C); , , , are the convective heat transfer coefficients of the inner wall of the drill pipe, the outer wall of the drill pipe, the inner wall of the casing and the inner wall of the wellbore respectively, in W / (m 2 ·°C); z is the distance from the wellhead, in m; r is the distance from the wellbore, in m; H shoe , H bThey are the casing shoe depth and the bottom hole depth, in m; h is the well depth, in m; t is the time, in s; The initial conditions of the wellbore 3 and the formation temperature are as follows: Formation temperature at the initial moment: (8); The temperatures in the drill pipe and the annulus at the initial moment are equal to the formation temperature: (9); T 0 p,i and T 0 a,i are the temperatures in the drill pipe and the annulus at the initial moment, respectively; The boundary conditions of the wellbore 3 and the formation temperature are as follows: The temperature of the drill pipe at the wellhead is always equal to the drilling fluid injection temperature: (10); The temperature of the drill pipe at the bottom hole is always equal to the annulus temperature: (11); In formula (11), T n p,N represents the temperature of the drill pipe at the bottom hole at the nth moment, T n a,N represents the annulus temperature at the bottom hole at the nth moment; in addition, formula (10) represents the temperature of the drill pipe at the wellhead at the nth moment. The subscript at the lower right represents the well depth position. It can be seen from Figure 3 the grid division that the bottom hole is point N and the wellhead is 0.

[0034] In the formula, is the sea surface temperature, in °C; is the drilling fluid injection temperature, in °C; is the geothermal gradient, in °C; H sea is the sea water depth, in m; is the seabed temperature.

[0035] The drilling fluid injection temperature is obtained in real time from the logging data. Through the above solution, the temperature distributions of the drill pipe, the annulus, and the formation at different distances from the wellbore at different moments can be calculated, providing support for the thermal stress calculation.

[0036] In Step 3, the wellbore perimeter stress includes in-situ stress, thermal stress caused by the temperature change between the wellbore and the formation, seepage stress caused by the fluid seepage in the open hole section, and the fluid pressure of Wellbore 3; among them, the in-situ stress is the wellbore perimeter stress before the formation is drilled, the thermal stress is calculated in real time from the wellbore-formation coupled temperature field, the seepage effect in the open hole section is generated by the diffusion effect between the fluid in Wellbore 3 and the formation fluid, and the stress generated by the fluid pressure of Wellbore 3 is generated by the holding-down effect; due to different rock properties, the formation around the wellbore is divided into a plastic region and an elastic region from the inside to the outside in sequence; among them, deep formations are mostly elastic formations, and shallow deep water and gypsum layers are mostly plastic formations. Since the wellbore diameter is much smaller than the well depth, the wellbore model can be simplified to an axisymmetric plane strain problem. According to the stress continuity conditions at the wellbore wall and the interface of the equilibrium differential equation, the radius of the plastic region affected by thermodynamics is further calculated, so as to calculate the wellbore perimeter stress in different regions.

[0037] In Step 3, considering the coupling influence of multiple factors of heat-fluid-solid, calculate the wellbore perimeter stress at different well depth positions, including in-situ stress, thermal stress caused by the temperature change between the wellbore and the formation, seepage stress caused by the fluid seepage in the open hole section, and the wellbore perimeter stress generated by the fluid pressure of Wellbore 3; specifically including: The in-situ stress is expressed as: (12); (13); In the formula, , , are the original radial, tangential and vertical stresses, MPa; is the maximum horizontal principal stress, MPa; is the minimum horizontal principal stress, MPa; is the vertical stress, MPa; is the density of rock or seawater, kg / m 3 ; , are the overburden pressure and the predicted formation pore pressure before drilling, MPa; is the Poisson's ratio of the rock, dimensionless; , is the tectonic stress coefficient, dimensionless; Generally, the value is 0.74, Generally, the value is 0.38; is the effective stress coefficient, dimensionless; R p is the radius of the plastic zone, m; r is the distance from the wellbore, m; θ is the wellbore perimeter angle, rad; Calculate the thermal stress according to the wellbore-formation temperature field. The thermal stress generated by the temperature difference between the current formation temperature and the initial formation temperature is expressed as: (14); (15); Wherein, , , are the radial, tangential and vertical thermal stresses, MPa; is the thermal expansion coefficient of the rock, °C -1 ; E is the elastic modulus of the rock, MPa; R is the wellbore radius, m; is the formation temperature at a distance of r from the wellbore, which can be obtained from Step 2, °C; is the initial formation temperature, °C; T f ( r ) is the temperature difference considering heat transfer and not considering heat transfer at different wellbore distances; During managed pressure drilling, there is a diffusion effect between the fluid in the open hole section of the wellbore 3 and the formation fluid. This seepage effect has a great impact on the wellbore stress. The seepage stress is expressed as: (16); Wherein, , , are the radial, tangential and vertical seepage stresses caused by wellbore seepage, MPa; is the hydrostatic pressure in the wellbore 3, MPa; is the seepage coefficient, dimensionless; φ is the porosity; The fluid pressure in the wellbore 3 has a pressing effect on the wellbore wall, affecting the magnitude of the wellbore stress. The fluid pressure in the wellbore 3 is expressed as: (17); Wherein, and are the radial and tangential stresses around the wellbore generated by the fluid pressure in the wellbore 3, Mpa; Considering the above thermo-hydro-mechanical coupling factors, the total wellbore stress is expressed as: (18); Wherein, , , are the radial, tangential and vertical stresses around the wellbore, Mpa; Therefore, the vertical stress is expressed as: (19); The part above Equation (18) is the stress composition derived simply. Equation (19) is the vertical stress after substitution. The following Equation (20) is the radial and tangential stresses in the elastic zone, and Equation (23) is the radial and tangential stresses in the plastic zone. The purpose of calculating Equation (18) is to apply it to calculate the pore pressure in Equation (26);

[0038] The formation lithology is divided into an elastic zone and a plastic zone. Deep formations are mostly elastic formations, and shallow deepwater and gypsum-salt formations are mostly plastic formations. The radial stress and tangential stress in the elastic zone are expressed as: (20); When solving the radial stress and tangential stress in the plastic zone, the wellbore model is simplified to an axisymmetric plane strain problem, and the equilibrium differential equation is: (21); In the formula, and are the radial stress and tangential stress in the plane strain problem, Mpa; The yield function satisfies: (22); In the formula, is the rock cohesion, MPa; is the friction angle, °; N and are both intermediate variables for calculating ; Therefore, the radial stress and tangential stress in the plastic zone are expressed as in Equation (23): (23); According to the stress continuity condition at the interface between the elastic and plastic zones: (24); Substitute Equation (20) and Equation (23) into Equation (24) to obtain the radius constraint condition of the plastic zone affected by temperature: (25).

[0039] In Step 4, the overburden pressure and the predicted formation pore pressure before drilling are known conditions. The multi-field coupling factors directly affect the vertical effective stress. According to the effective stress principle, calculate the formation pore pressure corrected by multi-field coupling.

[0040] In Step 4, after the low-temperature fluid is injected into the wellbore 3, the formation temperature decreases, the formation rock mass relatively shrinks, and thermal stress (manifested as tensile stress) that inhibits its shrinkage is generated on the surface. There are slight changes in the fluid space within the formation, thereby affecting the pore fluid pressure within the microelement. Combining the formation pore pressure predicted before drilling, the wellbore stress calculated in real time, and the effective stress principle, i.e., Equation (26), the formation pore pressure corrected considering thermo-hydro-mechanical coupling is calculated. p p :

[0041] (26); (27).

[0042] In Step 5, according to the different failure conditions of the elastic region and the plastic region, combining the formation pore pressure and the wellbore stress updated in real time, the formation fracture pressure and collapse pressure of the elastic region and the plastic region are calculated respectively.

[0043] In Step 5, the formation fracture pressure and collapse pressure are important boundaries that make up the formation pressure safety window. Stress failure conditions in the elastic region and the plastic region are considered to calculate the formation fracture pressure and collapse pressure in different regions; specifically including: (1) Formation fracture belongs to tensile failure. When the effective tangential stress at the wellbore wall is greater than the rock tensile strength, the wellbore fails, and the failure condition is expressed as: (28); In the formula, is the tangential stress, MPa; St is the rock tensile strength, Mpa; ① Elastic region: Substitute the tangential stress of the elastic formation in Equation (20) into the failure condition Equation (28), where The corrected formation pore pressure is adopted to obtain the real-time calculation model of the formation fracture pressure in the elastic region: (29); In the formula, P fe is the formation fracture pressure in the elastic region, Mpa; ② Plastic region: Substitute the tangential stress of the plastic formation in Equation (23) into the failure condition (28), and the real-time calculation model of the formation fracture pressure at the wellbore wall in the plastic region is obtained: (30); In the formula, P fp is the formation fracture pressure in the plastic region, Mpa; (2) Wellbore collapse belongs to shear failure. When the stress on the rock at the wellbore wall is greater than the strength of the rock itself, the formation undergoes shear failure. According to the different compaction degrees and rock strengths in the elastic and plastic regions, the wellbore instability criterion is selected for different regions;

[0044] ① Elastic region: The rock strength in the elastic region is high. The classical Mohr-Coulomb yield criterion is used to judge the instability condition in this region. The Mohr-Coulomb yield criterion expressed in terms of the stress at the wellbore wall is: (31); Where, , are the tangential stress and radial stress respectively; is the cohesion of the rock, MPa; is the friction angle of the rock, °; K is an intermediate variable, dimensionless; Substitute the tangential stress and radial stress of the formation in the elastic region in Equation (20) into Equation (31), then the real-time calculation model of the formation collapse pressure considering thermal stress at the wellbore wall in the elastic region is: (32); In the formula, P ce is the formation collapse pressure in the elastic region, Mpa; ② Plastic region: Numerical simulation shows that when the radius of the plastic region exceeds 1.6 times the wellbore radius, it is considered that the wellbore is unstable. At this time, the hydrostatic pressure is the formation collapse pressure; Equation (33) is used as the wellbore instability condition in the plastic region and substituted into Equation (25). Equation (25) can be regarded as the formula for Rp, that is, substitute Rp into Equation (33); thus, the real-time calculation model of the formation collapse pressure at the wellbore wall in the plastic region is obtained, as shown in Equation (34): (33); (34); In the formula, A p , A w are the area of the plastic region and the wellbore area respectively, m 2 ; P cp is the formation collapse pressure in the plastic region, MPa.

[0045] Through the above real-time calculation process, it can be seen that the present invention considers the coupled influence of multi-factors of heat-fluid-solid, and calculates the changes of formation pore pressure, fracture pressure and collapse pressure in real time during controlled pressure drilling, providing the bottom hole boundary conditions for wellbore pressure control.

[0046] In Step 6, determine the pressure control standard for Wellbore 3 based on the real-time calculation results of formation pressure, i.e., the formation pressure safety window: the safety interval between the minimum of the formation pore pressure and the formation collapse pressure and the formation fracture pressure; calculate the variation of the wellhead backpressure over time based on the wellbore hydraulic parameter calculation model; and adjust the throttle valve opening in real time through the industrial control computer 1, thereby adjusting the wellhead backpressure in real time.

[0047] The specific implementation process of Step 6 is as follows: After the formation pore pressure, fracture pressure, and collapse pressure considering thermo-fluid-solid coupling are obtained through real-time calculation, the formation pressure safety window is shown in Equation (35): (35); where, p bzmin is the lower limit of the formation pressure safety window, MPa; p bzmax is the upper limit of the formation pressure safety window, MPa; p ci and p fi are the formation collapse pressure and formation fracture pressure in different regions, MPa; i represents the region, i = e represents the elastic zone, i = p represents the plastic zone; The bottomhole pressure control standard is shown in Equation (36): (36); where, p bz is the bottomhole pressure control standard, MPa; is the pressure safety margin, MPa; the role of the pressure safety margin is to characterize that the bottomhole pressure control standard is within the formation pressure safety window; After the bottomhole pressure control standard is known, based on the wellbore flow model, the target wellhead backpressure is calculated in real time, as shown in Equation (37): (37); where, p Goal is the target wellhead backpressure, MPa; g is the acceleration of gravity, m / s 2 ; p f is the flow friction of Wellbore 3, MPa; p f is the flow friction of Wellbore 3.

[0048] Transmit the real-time target wellhead backpressure to the dual-channel automatic choke device system, and electrically control the opening degrees of the choke valve and the flat valve through the PLC, so that the reading of the casing pressure gauge 9 is stabilized to the target wellhead backpressure. At this time, it is considered that the bottomhole pressure in the wellbore 3 has reached the control standard, the pressure control operation is completed, and the safe pressure control drilling is ensured, which has high value and significance for the safe and efficient development of complex oil and gas reservoirs.

[0049] To further prove the positive effects of the embodiments, the present invention conducts the following experiments based on the above technical solutions.

[0050] The method of the present invention is applied to calculate the real-time changes in formation pressure during deepwater pressure control drilling. Figure 4 It is the curve of the safety of formation pressure at the well depth from 3800 m to the bottom of the well at 4680 m with the drilling time. It can be seen that before the drilling fluid circulation, the safety window of the bottomhole formation pressure is 7.60 MPa. After 24 hours of drilling fluid circulation, affected by the thermal-fluid-solid coupling, both the pore pressure and the fracture pressure gradually decrease, and the corresponding safety window of the bottomhole formation pressure shrinks to 6.34 MPa. Figure 5 and Figure 6 They are respectively the changes in formation pressure at the well depths of 1100 m and 4680 m with the circulation time. It can be seen that in the plastic region (1100 m), since the temperature in the wellbore 3 is higher than the formation temperature, the formation rock mass relatively shrinks, and thermal stress (compressive stress) that inhibits its expansion is generated on the surface, and there are slight changes in the fluid space in the formation. Therefore, the formation pore pressure, collapse pressure, and fracture pressure all increase. In the elastic region (4680 m), the action of thermal stress is opposite, and the formation pore pressure, collapse pressure, and fracture pressure all decrease. Numerically, the safety window of the formation pressure at 1100 m decreases from 1.461 MPa to 1.418 MPa, and the safety window of the formation pressure at 4680 m decreases from 7.60 MPa to 6.34 MPa. Figure 5 and Figure 6 The multi-factor influence in and refers to considering the multi-field coupling influence of heat-fluid-solid, and considering the influence of in-situ stresses around the wellbore such as thermal stress, seepage stress, and wellbore 3 pressure. These stresses are the embodiment of the heat-fluid-solid multi-field coupling model. During pressure control drilling, it is necessary to determine the wellbore 3 pressure control boundary according to the formation pressure. The present invention can calculate the real-time changes in the safety window of formation pressure under the influence of heat-fluid-solid coupling, which is crucial for the safe implementation of pressure control drilling.

[0051] In summary, the formation pressure calculation method and control system for pressure control drilling based on multi-field coupling of the present invention can calculate the formation pressure under the influence of heat-fluid-solid coupling during pressure control drilling in real time, calculate through the wellbore 3 hydraulic parameters in real time, quickly control the automatic choke device to realize the automatic regulation of the wellhead backpressure, and ensure safe pressure control drilling.

[0052] Embodiment 3 Formation pressure calculation and control system for pressure control drilling based on multi-field coupling, comprising: Wellbore circulation system, industrial control computer 1, logging system and dual-channel automatic choke device system; The wellbore circulation system includes mud pump 6, standpipe pressure gauge 7, rotating control blowout preventer group 8, wellbore 3, casing pressure gauge 9, flowmeter 15, gas-liquid separator 16, mud pit 17; the circulation path is: mud pump 6, standpipe pressure gauge 7, rotating control blowout preventer group 8, wellbore 3, casing pressure gauge 9, dual-channel automatic choke device system, flowmeter 15, gas-liquid separator 16, mud pit 17; The industrial control computer 1 is installed with real-time calculation software for hydraulic parameters of pressure control drilling, automatic control software for choke devices, etc.; the logging system includes logging instrument 2 and communication device; The dual-channel automatic choke device system includes backpressure pump 10, first flat valve 11, second flat valve 12, first choke valve 13, second choke valve 14.

[0053] The specific working process of the formation pressure control system for pressure-controlled drilling based on multi-field coupling is as follows: During pressure-controlled drilling, the drilling fluid in the mud pit 17 is injected into the drill pipe through the mud pump 6, and circulates out of the wellbore 3 through the annulus; the logging instrument 2 obtains the current well depth, bit depth, inlet and outlet flow rates, inlet and outlet densities, inlet and outlet temperatures, total pit volume, rate of penetration, weight on bit, and rotary speed in real time, and transmits them to the industrial control computer 1 based on WITS communication 4. The real-time calculation software for hydraulic parameters of pressure-controlled drilling installed on the industrial control computer 1 calculates the pressure profile of the wellbore 3 in real time; during the circulation process, there is always heat transfer between the fluid in the wellbore 3 and the formation, which causes the temperature of the wellbore 3 to rise and the formation temperature to decrease. The thermal stress, seepage stress, in-situ stress, and the liquid column pressure in the wellbore 3 generated by the temperature difference before and after have unequal effects on the wellbore stress, thereby changing the formation pressure profile. Based on the formation pressure calculated in real time according to the present invention, an accurate bottomhole control boundary is obtained. Based on the bottomhole control boundary, the target wellhead backpressure is calculated in real time; after the drilling fluid circulates out of the wellbore 3, the wellhead backpressure is characterized by the casing pressure gauge 9; immediately afterwards, the drilling fluid enters the dual-channel automatic choke system; the industrial control computer 1 transmits the target wellhead backpressure to the automatic choke in real time, and electrically controls the opening degrees of the first choke valve 13, the second choke valve 14, the first flat valve 11, and the second flat valve 12 through the PLC 5; when the reading of the casing pressure gauge 9 stabilizes to the target wellhead backpressure, it is considered that the bottomhole pressure in the wellbore 3 has reached the control range, and the pressure control operation of the wellbore 3 is completed; thereafter, after the drilling fluid flows out of the dual-channel automatic choke system, it returns to the mud pit 17 through the flowmeter 15 and the gas-liquid separator 16, so that the drilling fluid circulates for one week, and the wellhead backpressure is controlled in real time. It should be noted that the backpressure pump 10 is used during the period of pressure-controlled pump shutdown for making a connection of drill pipes. During the period of pump shutdown for making a connection of drill pipes, the drilling fluid stops circulating, resulting in the abnormal operation of the automatic choke. During this period, the backpressure pump 10 is started and pumped into the wellbore 3 through the dual-channel automatic choke system. At this time, the wellhead backpressure can be controlled by controlling the opening degrees of the choke valve and the flat valve.

[0054] Based on the above working process, the system realizes the precise control of the pressure in the wellbore 3 during pressure-controlled drilling and during the period of pressure-controlled pump shutdown for making a connection of drill pipes by real-time monitoring of the inlet and outlet temperatures of the drilling fluid, etc., real-time calculation of the formation pressure and the pressure in the wellbore 3, and then real-time control of the opening degrees of the valve positions of the dual-channel automatic choke.

[0055] The above is only a relatively preferred specific embodiment of the present invention, but the protection scope of the present invention is not limited thereto. Any modification, equivalent replacement, and improvement made by those skilled in the art within the technical scope disclosed by the present invention and within the spirit and principle of the present invention should be covered by the protection scope of the present invention.

Claims

1. A formation pressure calculation and control method for managed pressure drilling based on multi-field coupling, characterized in that Including: Step 1: Connect the industrial control computer with the logging instrument to obtain in real time the basic data required for calculation, including: well depth, displacement, inlet and outlet density, inlet and outlet temperature, and mechanical drilling rate; connect the industrial control computer with the automatic choke device to control the wellhead back pressure in real time. Step 2: Divide the wellbore - formation spatial domain grid, input the initial conditions and boundary conditions of the wellbore and formation temperatures, and calculate the temperature distributions of the drill pipe and annulus, as well as the formation temperature distribution at different distances from the wellbore. Step 3: Considering the influence of thermal-fluid-solid multi-field coupling, calculate the wellbore stress at different well depths in the elastic-plastic regions , , ; among them, the radius of the plastic zone is calculated from the stress continuity conditions at the wellbore and the interface in the elastic-plastic regions Step 4: Based on the overburden pressure profile obtained from logging data and the formation pore pressure profile predicted before drilling, combine with the effective stress principle to obtain the real - time formation pore pressure profile corrected by multi - factor coupling. Step 5: Calculate the real - time formation fracture pressure profile and collapse pressure profile at the wellbore wall at different well depths corrected by multi - factor coupling in elastic - plastic regions. Step 6: Determine the bottom - hole pressure control standard, based on the wellbore hydraulic parameter calculation model, calculate in real time and control the wellhead back pressure in real time through the industrial control computer.

2. The formation pressure calculation and control method for pressure-controlled drilling based on multi-field coupling according to claim 1, characterized in that In the said Step 1, the communication method between the industrial control computer and the logging instrument adopts the WITS protocol, and the industrial control computer obtains the logging measurement data in real time, including: current well depth, bit depth, inlet and outlet flow rate, inlet and outlet density, inlet and outlet temperature, total pit volume, mechanical drilling rate, weight on bit, and rotary speed; the communication between the industrial control computer and the automatic choke device adopts PLC electric control, and the industrial control computer realizes the functions of automatically and manually adjusting the throttle valve opening to control the wellhead back pressure.

3. The method for calculating and controlling formation pressure in pressure-controlled drilling based on multi-field coupling according to claim 1, characterized in that, In Step 2, the initial conditions of the wellbore and formation temperatures are the original formation temperatures; at the wellhead boundary, the drill pipe injection temperature is the drilling fluid outlet temperature obtained by the logging instrument in real time; at the bottom - hole boundary, the drill pipe temperature is equal to the annulus temperature; the formation temperature at an infinite distance from the wellbore is not disturbed by the wellbore temperature and is always the original formation temperature; the wellbore - formation spatial domain grid consists of the drill pipe, annulus, cement sheath, and formation from the inside out. Heat exchange occurs between the fluid in the drill pipe and the fluid in the annulus; heat exchange occurs between the fluid in the annulus and the fluid in the drill pipe and the formation fluid; the wellbore unit includes the drill pipe, annulus, and cement sheath, and the formation includes several formation units. Heat exchange occurs between adjacent formation units and between the formation units and adjacent wellbore units. The heat transfer equations in the drill pipe, annulus, and formation are shown in Equations (1) - (3) respectively: (1)； (2)； (3)； Among them, the heat transfer intermediate variables A and B are expressed as in Equation (4): （4）； wherein, and are the mass flow rates of the drilling fluid in the drill pipe and the annulus respectively, with the unit of kg / s, as expressed in Equation (5): （5）； The comprehensive heat transfer coefficients of the drill pipe and annulus are expressed as in Equations (6) and (7): (6)； (7)； In the formula, , , are the drill pipe temperature, the annulus temperature, and the formation temperature, respectively, in °C; is the formation temperature at the initial time, in °C; , are the cross-sectional areas of the drill pipe and the annulus, respectively, in m 2 ; , are the flow velocities of the drilling fluid inside the drill pipe and inside the annulus, respectively, in m / s; , are the densities of the drilling fluid and the formation, in kg / m 3 ; , are the specific heat capacities of the formation and the drilling fluid, respectively, in J / (kg·°C); , , are the thermal conductivities of the drill pipe and the casing, the cement sheath and the formation, respectively, in W / (m·°C); , , , , are the inner diameter of the drill pipe, the inner diameter of the annulus, the outer diameter of the drill pipe, the outer diameter of the annulus, and the wellbore diameter, respectively, in m; , are the total heat transfer coefficients between the drill pipe and the annulus, and between the annulus and the formation, respectively, in W / (m 2 ·°C); , , , are the convective heat transfer coefficients of the inner wall of the drill pipe, the outer wall of the drill pipe, the inner wall of the casing and the inner wall of the wellbore, respectively, in W / (m 2 ·°C); z is the distance from the wellhead, in m; r is the distance from the wellbore, in m; H shoe , H b are the depths of the casing shoe and the bottom of the well, respectively, in m; h is the well depth, in m; t is the time, in s; The initial conditions of the wellbore and formation temperatures are as follows: Formation temperature at the initial moment: (8)； The temperatures in the drill pipe and annulus at the initial moment are equal to the formation temperature: (9)； T 0 p,i , T 0 a,i are the temperatures in the drill pipe and the annulus at the initial moment, respectively; The boundary conditions of the wellbore and formation temperatures are as follows: The drill pipe temperature at the wellhead is always equal to the drilling fluid injection temperature: (10)； The drill pipe temperature at the bottom - hole is always equal to the annulus temperature: (11)； In formula (11), T n p,N represents the temperature of the drill pipe at the bottom of the well at the nth moment, T n a,N represents the annulus temperature at the bottom of the well at the nth moment; in the formula, is the seawater surface temperature, °C; is the drilling fluid injection temperature, °C; is the geothermal gradient, °C; H sea is the seawater depth, m; is the seabed temperature.

4. The method for calculating and controlling formation pressure in managed pressure drilling based on multi-field coupling according to claim 1, characterized in that, In Step 3, the wellbore stress includes in-situ stress, thermal stress caused by the temperature change between the wellbore and the formation, seepage stress caused by fluid seepage in the open-hole section, and wellbore fluid pressure. Among them, the in-situ stress is the wellbore stress existing before the formation is drilled. The thermal stress is calculated in real time from the wellbore-formation coupled temperature field. The seepage effect in the open-hole section is generated by the diffusion effect between the wellbore fluid and the formation fluid. The stress generated by the wellbore fluid pressure is generated by the holding-down effect. The formation around the wellbore is divided into a plastic zone and an elastic zone from the inside out in sequence. Calculate the radius of the plastic zone affected by thermodynamics, and then calculate the wellbore stress by region. In Step 3, considering the coupling influence of multiple factors of heat, fluid flow, and solid, calculate the wellbore stress at different well depths, including in-situ stress, thermal stress caused by the temperature change between the wellbore and the formation, seepage stress caused by fluid seepage in the open-hole section, and wellbore stress generated by wellbore fluid pressure. Specifically, it includes: The in-situ stress is expressed as: (12)； (13)； In the formula, , , are the original radial, tangential and vertical stresses, in MPa; is the maximum horizontal principal stress, in MPa; is the minimum horizontal principal stress, in MPa; is the vertical stress, in MPa; is the density of rock or sea water, in kg / m 3 ; , are the overburden pressure and the predicted formation pore pressure before drilling, respectively, in MPa; is the Poisson's ratio of rock, dimensionless; , are the tectonic stress coefficients, dimensionless; is the effective stress coefficient, dimensionless; R p is the radius of the plastic zone, in m; r is the distance from the wellbore, in m; θ is the wellbore angle, in rad; Calculate the thermal stress according to the wellbore-formation temperature field. The thermal stress generated by the temperature difference between the current formation temperature and the initial formation temperature is expressed as: (14)； (15)； In the formula, , , are the radial, tangential and vertical thermal stresses, in MPa; is the thermal expansion coefficient of the rock, in °C -1 ; E is the elastic modulus of the rock, in MPa; R is the wellbore radius, in m; is the formation temperature at a distance of r from the wellbore, which can be obtained from Step 2, in °C; is the initial formation temperature, in °C; T f ( r ) is the temperature difference considering heat transfer and not considering heat transfer at different wellbore distances; The seepage stress is expressed as: (16)； In the formula, , , are the radial, tangential and vertical seepage stresses caused by seepage around the well, MPa; is the liquid column pressure in the wellbore, MPa; is the seepage coefficient, dimensionless; φ is the porosity; The fluid pressure in the wellbore is expressed as: （17）； In the formula, and are the radial stress and tangential stress around the wellbore generated by the wellbore fluid pressure, Mpa; Considering the above coupling factors of heat, fluid flow, and solid, the total wellbore stress is expressed as: (18)； In the formula, , , are the radial stress, tangential stress and vertical stress around the wellbore, in Mpa; Therefore, the vertical stress is expressed as: (19)； The formation lithology is divided into an elastic zone and a plastic zone. The radial stress and tangential stress in the elastic zone are expressed as: (20)； When solving the radial stress and tangential stress in the plastic zone, simplify the wellbore model into an axisymmetric plane strain problem. The equilibrium differential equation is: (21)； In the formula, and are the radial stress and tangential stress in the plane strain problem, Mpa; The yield function satisfies: (22)； In the formula, is the cohesive force of the rock, MPa; is the friction angle, °; Therefore, the radial stress and tangential stress in the plastic zone are expressed as in Equation (23): (23)； According to the stress continuity condition at the interface between the elastic and plastic zones: (24)； Substitute Equations (20) and (23) into Equation (24) to obtain the constraint condition for the radius of the plastic zone affected by temperature: (25)。 5. The formation pressure calculation and control method based on multi-field coupling according to claim 1, characterized in that In Step 4, the overburden pressure and the formation pore pressure predicted before drilling are known conditions. The multiple-field coupling factors directly affect the vertical effective stress. According to the effective stress principle, calculate the formation pore pressure corrected by multiple-field coupling. In Step 4, combining the formation pore pressure predicted before drilling, the wellbore stress calculated in real time, and the effective stress principle, i.e., Equation (26), the formation pore pressure after thermal-fluid-solid coupling correction is calculated. p p : （26）； (27)。 6. The formation pressure calculation and control method based on multi-field coupling according to claim 1, characterized in that In Step 5, according to the different failure conditions of the elastic zone and the plastic zone, combined with the real-time updated formation pore pressure and wellbore stress, calculate the formation fracture pressure and collapse pressure in the elastic zone and the plastic zone respectively.

7. The formation pressure calculation and control method based on multi-field coupling according to claim 1, characterized in that, In Step 5, the formation fracture pressure and collapse pressure are important boundaries that make up the formation pressure safety window. Divide the stress failure conditions of the elastic zone and the plastic zone, and calculate the formation fracture pressure and collapse pressure in different regions. Specifically, it includes: (1) Formation fracture belongs to tensile failure. When the effective tangential stress at the wellbore wall is greater than the rock tensile strength, the wellbore fails. The failure condition is expressed as: （28）； wherein is the tangential stress, MPa; St is the tensile strength of the rock, Mpa; ① Elastic region: Substitute the tangential stress of the elastic formation in Equation (20) into the failure condition Equation (28), where Using the corrected formation pore pressure, a real-time calculation model for the formation fracture pressure in the elastic region is obtained: (29)； In the formula, P fe is the formation fracture pressure in the elastic zone, Mpa; ② Plastic zone: Substitute the tangential stress of the formation in the plastic zone in Equation (23) into the failure condition (28), and the real-time calculation model for the formation fracture pressure at the wellbore wall in the plastic zone can be obtained: (30)； In the formula, P fp is the formation fracture pressure in the plastic zone, Mpa; (2) Considering the different compaction degrees and rock strengths of the elastic zone and the plastic zone, select the wellbore instability criterion by region. ① Elastic zone: The rock strength in the elastic zone is high. Apply the classical Mohr-Coulomb yield criterion to judge the instability condition in this region. The Mohr-Coulomb yield criterion expressed in terms of the stress at the wellbore wall is: (31)； Among them, , are the tangential stress and the radial stress respectively; is the cohesive force of the rock, MPa; is the friction angle of the rock, °; K is an intermediate variable, dimensionless; Substitute the tangential stress and radial stress of the formation in the elastic zone in Equation (20) into Equation (31), and the real-time calculation model of the formation collapse pressure considering thermal stress at the wellbore in the elastic zone is as follows: (32)； In the formula, P ce is the collapse pressure of the elastic zone formation, Mpa; ② Plastic region: Numerical simulation shows that when the radius of the plastic zone exceeds 1.6 times the wellbore radius, it is considered that the wellbore is unstable, and the hydrostatic pressure at this time is the formation collapse pressure; Equation (33) is used as the instability condition of the wellbore in the plastic zone, and substituting it into Equation (25), the real-time calculation model of the formation collapse pressure at the wellbore in the plastic zone is obtained, as shown in Equation (34): (33)； (34)； In the formula, A p , A w are the plastic zone area and the wellbore area respectively, in m 2 ; P cp is the formation collapse pressure in the plastic zone, in MPa.

8. The method for calculating and controlling formation pressure in managed pressure drilling based on multi-field coupling according to any one of claims 1-7, characterized in that In Step 6, determine the wellbore pressure control standard through the real-time calculation results of the formation pressure, that is, the formation pressure safety window: the safety interval between the minimum value of the formation pore pressure and the formation collapse pressure and the formation fracture pressure; based on the wellbore hydraulic parameter calculation model, calculate the change of the wellhead backpressure over time; adjust the opening of the throttle valve in real time through the industrial control computer, and then adjust the wellhead backpressure in real time.

9. The method for calculating and controlling formation pressure in pressure-controlled drilling based on multi-field coupling according to claim 8, characterized in that, The specific implementation process of Step 6 is as follows: After the formation pore pressure, fracture pressure, and collapse pressure considering thermal-fluid-solid coupling are calculated in real time, the formation pressure safety window is as shown in Equation (35): (35)； Among them, p bzmin is the lower limit of the formation pressure safety window, MPa; p bzmax is the upper limit of the formation pressure safety window, MPa; p ci and p fi are the formation collapse pressure and formation fracture pressure in different regions, MPa; i represents the region, i = e represents the elastic zone, i = p represents the plastic zone; The bottom hole pressure control standard is as shown in Equation (36): (36)； Among them, p bz is the bottom hole pressure control standard, MPa; is the pressure safety margin, MPa; the function of the pressure safety margin is to characterize that the bottom hole pressure control standard is within the formation pressure safety window; After knowing the bottom hole pressure control standard, based on the wellbore flow model, calculate the target wellhead backpressure in real time, as shown in Equation (37): (37)； Among them, p Goal is the target wellhead back pressure, MPa; g is the acceleration due to gravity, m / s 2 ; p f is the wellbore flow friction, MPa; p f is the wellbore flow friction.

10. The formation pressure calculation and control system for pressure-controlled drilling based on multi-field coupling is used to implement the formation pressure calculation and control method for pressure-controlled drilling based on multi-field coupling according to any one of claims 1-9, and is characterized in that Including: Wellbore circulation system, industrial control computer, mud logging system, and dual-channel automatic choke device system; The wellbore circulation system includes a mud pump, standpipe pressure gauge, rotating control blowout preventer group, wellbore, casing pressure gauge, flowmeter, gas-liquid separator, and mud pit; the circulation path is: mud pump, standpipe pressure gauge, rotating control blowout preventer group, wellbore, casing pressure gauge, dual-channel automatic choke device system, flowmeter, gas-liquid separator, mud pit; The mud logging system includes a mud logging instrument and a communication device; The dual-channel automatic choke device system includes a backpressure pump, first flat valve, second flat valve, first choke valve, and second choke valve; During the pressure control drilling process, the drilling fluid in the mud pit is injected into the drill pipe through the mud pump and circulates out of the wellbore through the annulus; the mud logging instrument real-time obtains the current well depth, bit depth, inlet and outlet flow rates, inlet and outlet densities, inlet and outlet temperatures, total pit volume, mechanical drilling rate, drilling pressure, and rotary speed, and transmits them to the industrial control computer based on WITS communication. The industrial control computer calculates the wellbore pressure profile in real time; calculates the formation pressure in real time to obtain the bottom hole control boundary, and based on the bottom hole control boundary, calculates the target wellhead backpressure in real time; after the drilling fluid circulates out of the wellbore, the wellhead backpressure is characterized by the casing pressure gauge; then, the drilling fluid enters the dual-channel automatic choke device system; the industrial control computer transmits the target wellhead backpressure to the automatic choke device in real time, and controls the opening of the first choke valve, second choke valve, first flat valve, and second flat valve through PLC electric control; when the reading of the casing pressure gauge stabilizes to the target wellhead backpressure, it is considered that the bottom hole pressure in the wellbore reaches the control interval, and the wellbore pressure control operation is completed; thereafter, after the drilling fluid flows out of the dual-channel automatic choke device system, it returns to the mud pit through the flowmeter and gas-liquid separator, and thus the drilling fluid circulates for one week, and the wellhead backpressure is controlled in real time.

Images