Method and system for calculating and controlling formation pressure in managed pressure drilling based on multi-field coupling

Abstract

The present invention relates to a method and system for calculating and controlling formation pressure in pressure-controlled drilling based on multi-field coupling, which belongs to the field of petroleum exploration and development, and includes the following steps: Step 1: connecting an industrial computer to a mud logger to obtain basic data required for calculation in real time; Step 2: dividing the wellbore-formation space domain into grids, calculating the temperature distribution of the drill pipe, annulus, and formation temperature distribution at different distances from the wellbore; Step 3: considering the influence of heat-fluid-solid multi-field coupling, calculating the wellbore stress at different well depths in the elastic-plastic region; Step 4: obtaining the real-time formation pore pressure profile after multi-factor coupling correction; Step 5: calculating the real-time formation fracture pressure profile and collapse pressure profile at the wellbore wall at different well depths after multi-factor coupling correction in the elastic-plastic region; Step 6: determining the bottom hole pressure control standard, and calculating and controlling the wellhead back pressure in real time based on the wellbore hydraulic parameter calculation model. The present invention can effectively improve the accuracy of formation pressure calculation during pressure-controlled drilling.

Description

Technical Field

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

[0002] Oil and gas exploration and development are gradually entering the era of deepwater and deep-strata exploration. Efficiently developing oil and gas resources in complex geological conditions is crucial. Long wellbores, on the one hand, demonstrate significant lithologic variation across the borehole depth. Generally, salt-gypsum layers and shallow, deepwater layers exhibit elasto-plastic characteristics, while deep shale layers exhibit elastic characteristics. This characteristic often leads to complex situations during deepwater drilling, such as shallow wellbore collapse, deep wellbore fractures, or overflows. On the other hand, after the wellbore is drilled, formation pressure (including pore pressure, fracture pressure, and collapse pressure) varies due to the lateral coupling of thermal, fluid, and solid fields. Inaccurate formation pressure calculations can easily lead to drilling accidents such as wellbore instability, overflows, and lost circulation. These incidents consume significant non-productive time, resulting in significant human and economic losses to oil and gas field development.

[0003] Managed pressure drilling (MPD) is a drilling technology that has become increasingly popular in recent years. Its principle is based on precise formation pressure boundary conditions. Through real-time calculation of wellbore hydraulic parameters, key hydraulic parameters such as wellhead back pressure, drilling fluid flow rate, and density are controlled in real time to maintain wellbore fluid pressure within the formation pressure safety window, ensuring drilling safety. The formation pressure safety window is the safe interval between the minimum of the formation pore pressure and the formation collapse pressure, and the formation fracture pressure. Therefore, accurate and real-time calculation of formation pressure is extremely important in the implementation of MPD. It defines the critical boundaries of wellbore pressure control and determines the success or failure of MPD.

[0004] However, due to the complex geological conditions of deepwater formations, the current standard for bottomhole pressure control during managed pressure drilling (MPD) is based on a fixed pre-drilling prediction of formation pressure. A real-time calculation method and control system for formation pressure during managed pressure drilling that considers the effects of thermal-fluid-solid multi-field coupling has yet to be developed. On the one hand, the varying lithology of formations along long wellbores creates varying wellbore failure conditions, necessitating the determination of these conditions within the elastic-plastic region to accurately calculate formation pressure. On the other hand, once the wellbore is drilled, the flow of drilling fluid disrupts the original thermal-fluid-solid equilibrium system, redistributing the effective stress around the wellbore. This requires the use of logging data to quantify formation pressure disturbances in real time and accurately determine the real-time control boundary for wellbore pressure. Summary of the Invention

[0005] To address the shortcomings of existing technologies, the present invention provides a method and system for calculating and controlling formation pressure during managed pressure drilling (MPD) based on multi-field coupling. This method calculates the dynamic changes in formation pressure during MPD, taking into account changes in the wellbore-formation coupled temperature field and the fluid-solid mass and heat transfer. This method accurately calculates formation pressure in real time, providing theoretical and technical support for MPD in formations with complex formation pressure systems.

[0006] This invention calculates formation pressure in real time based on real-time logging data, taking into account the effects of thermal-fluid-solid multi-field coupling. Using the hydraulic calculation results, it controls the automatic throttling device in real time to adjust the wellhead back pressure, ensuring that the wellbore pressure remains within the formation pressure safety window, enabling safe and efficient managed pressure drilling in complex formations. This invention provides theoretical and technical support for accurate and real-time calculation of formation pressure during managed pressure drilling, ensuring drilling safety.

[0007] In order to solve the above technical problems, the technical solutions adopted by the present invention are as follows:

[0008] The formation pressure calculation and control method for managed pressure drilling based on multi-field coupling includes:

[0009] Step 1: Connect the industrial computer to the mud logger to obtain the basic data required for calculation in real time, including: well depth, displacement, inlet and outlet density, inlet and outlet temperature, and mechanical drilling speed; connect the industrial computer to the automatic throttling device to control the wellhead back pressure in real time;

[0010] Step 2: Divide the wellbore-formation spatial domain into a grid, input the initial and boundary conditions of the wellbore and formation temperatures, and calculate the drill pipe and annulus temperature distributions and the formation temperature distributions at different distances from the wellbore.

[0011] Step 3: Considering the influence of thermal-fluid-solid multi-field coupling, calculate the stress around the well at different well depths in the elastic-plastic region , , ; Among them, the radius of the plastic zone is calculated by the stress continuity conditions at the wellbore wall and the interface in the elastic-plastic region;

[0012] Step 4: Based on the overburden pressure profile obtained from logging data and the formation pore pressure profile predicted before drilling, the real-time formation pore pressure profile after multi-factor coupling correction is obtained by combining the effective stress principle;

[0013] Step 5: Calculate the real-time formation fracture pressure profile and collapse pressure profile at the wellbore wall at different well depths after multi-factor coupling correction in the elastic-plastic region;

[0014] Step 6: Determine the bottom hole pressure control standard, calculate and control the wellhead back pressure in real time through the industrial computer based on the wellbore hydraulic parameter calculation model.

[0015] Furthermore, in step one, the communication method between the industrial computer and the mud logging instrument adopts the WITS protocol, and the industrial computer obtains the mud logging measurement data in real time, including: current well depth, drill bit depth, inlet and outlet flow, inlet and outlet density, inlet and outlet temperature, total pool volume, mechanical drilling speed, drilling pressure and rotation speed; the communication between the industrial computer and the automatic throttling device adopts PLC electric control, and the industrial computer realizes automatic and manual adjustment of the throttle valve opening, thereby controlling the wellhead back pressure.

[0016] Furthermore, in step 2, the initial conditions of the wellbore and formation temperatures are the original formation temperature; at the wellhead boundary, the drill pipe injection temperature is the drilling fluid outlet temperature obtained in real time by the logging instrument; at the bottom hole boundary, the drill pipe temperature is equal to the annulus temperature; and the formation temperature at an infinite distance from the wellbore is not disturbed by the wellbore temperature and is always the original formation temperature.

[0017] Furthermore, the grids of the wellbore-formation space domain are drill pipe, annulus, cement sheath, and formation from the inside out. The fluid in the drill pipe exchanges heat with the fluid in the annulus; the fluid in the annulus exchanges heat with 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 formation units and adjacent wellbore units; the heat transfer equations in the drill pipe, annulus, and formation are shown in Equations (1) to (3), respectively.

[0018] (1);

[0019] (2);

[0020] (3);

[0021] Among them, the heat transfer intermediate variables A and B are expressed as formula (4):

[0022] (4);

[0023] in, and are the drilling fluid mass flow rates in the drill pipe and annulus, respectively, in kg / s, as expressed in formula (5):

[0024] (5);

[0025] The comprehensive heat transfer coefficient of the drill pipe and annulus is expressed as follows:

[0026] (6);

[0027] (7);

[0028] Where, , , are the drill pipe temperature, annulus temperature and formation temperature, °C; is the formation temperature at the initial moment, °C; are the cross-sectional areas of the drill pipe and annulus, m 2 ; , are the drilling fluid velocity in the drill pipe and annulus, m / s; , is the density of drilling fluid and formation, kg / m 3 ; , are the specific heat capacities of the formation and drilling fluid, J / (kg·℃); , , are the thermal conductivity of drill pipe and casing, cement sheath and formation, W / (m·℃); , , , , are the drill pipe inner diameter, annulus inner diameter, drill pipe outer diameter, annulus outer diameter and wellbore diameter, m; , are the total heat transfer coefficients between the drill pipe and the annulus, and between the annulus and the formation, W / (m 2 ℃); , , , are the convection 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, W / (m 2 ℃); z is the distance from the wellhead, m; r is the distance from the wellbore, m; H shoe , H b are casing shoe depth and bottom hole depth, m, respectively; h is the well depth, m; t is time, s;

[0029] The initial conditions for wellbore and formation temperatures are as follows:

[0030] Initial formation temperature:

[0031] (8);

[0032] At the initial moment, the temperature in the drill pipe and annulus is equal to the formation temperature:

[0033] (9);

[0034] T 0 p,i 、 T 0 a,i are the temperatures in the drill pipe and annulus at the initial moment, respectively;

[0035] The boundary conditions for wellbore and formation temperatures are as follows:

[0036] The drill pipe temperature at the wellhead is always equal to the drilling fluid injection temperature:

[0037] (10);

[0038] The drill pipe temperature at the bottom of the hole is always equal to the annulus temperature:

[0039] (11);

[0040] In formula (11) T n p,N represents the drill pipe temperature at the bottom of the well at time n, T n a,N represents the annular temperature at the bottom of the well at time n;

[0041] Where, is the sea surface temperature, °C; is the drilling fluid injection temperature, °C; is the geothermal gradient, °C; H sea is the depth of seawater, m; is the seafloor temperature.

[0042] Furthermore, in step three, the wellbore stress includes in situ stress, thermal stress caused by wellbore-formation temperature changes, seepage stress caused by fluid seepage in the open hole section, and wellbore fluid pressure; wherein, the in situ stress is the wellbore stress before the formation is drilled, the thermal stress is calculated in real time by the wellbore-formation coupled temperature field, the seepage effect of the open hole section is caused by the diffusion effect of the wellbore fluid and the formation fluid, and the stress caused by the wellbore fluid pressure is caused by the pressure holding effect; the formation around the wellbore is divided into plastic area and elastic area from the inside to the outside; the radius of the plastic area affected by thermodynamics is calculated, and the wellbore stress is calculated by region.

[0043] Furthermore, in step 3, the coupling effects of thermal, fluid, and solid factors are considered to calculate the wellbore stress at different well depths, including in situ stress, thermal stress caused by wellbore-formation temperature changes, seepage stress caused by fluid seepage in the open hole, and wellbore stress caused by wellbore fluid pressure. Specifically, the following are included:

[0044] The in-situ stress is expressed as:

[0045] (12);

[0046] (13);

[0047] Where, , , 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 formation pore pressure predicted before drilling, MPa; is the Poisson's ratio of 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 well circumference angle, rad;

[0048] The thermal stress is calculated based on 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:

[0049] (14);

[0050] (15);

[0051] Where, , , are radial, tangential and vertical thermal stresses, MPa; is the thermal expansion coefficient of rock, °C -1 ; E is the rock elastic modulus, MPa; R is the wellbore radius, m; The distance from the wellbore r The formation temperature at can be obtained from step 2, ℃; is the initial formation temperature, °C; T f ( r ) is the temperature difference between considering heat transfer and not considering heat transfer at different wellbore distances;

[0052] The seepage stress is expressed as:

[0053] (16);

[0054] Where, , , is the radial, tangential and vertical seepage stress caused by the seepage around the well, MPa; is the liquid column pressure in the wellbore, MPa; is the seepage coefficient, dimensionless; φ is the porosity;

[0055] The fluid pressure in the wellbore is expressed as:

[0056] (17);

[0057] Where, and is the radial stress and tangential stress around the well generated by the wellbore fluid pressure, MPa;

[0058] Considering the above thermal-fluid-solid coupling factors, the total stress around the well can be expressed as:

[0059] (18);

[0060] Where, , , is the radial stress, tangential stress and vertical stress around the well, MPa;

[0061] Therefore, the vertical stress is expressed as:

[0062] (19);

[0063] The lithology of the formation is divided into elastic and plastic regions. The radial stress and tangential stress in the elastic region are expressed as:

[0064] (20);

[0065] 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:

[0066] (twenty one);

[0067] Where, and are the radial stress and tangential stress in the plane strain problem, MPa;

[0068] The yield function satisfies:

[0069] (twenty two);

[0070] Where, is the rock cohesion, MPa; is the friction angle, °;

[0071] Therefore, the radial stress and tangential stress in the plastic region are expressed as follows:

[0072] (twenty three);

[0073] According to the stress continuity condition at the interface between elastic and plastic regions:

[0074] (twenty four);

[0075] Substituting Equations (20) and (23) into Equation (24), we obtain the plastic zone radius constraint condition affected by temperature:

[0076] (25).

[0077] Furthermore, in step 4, the overburden pressure and the formation pore pressure predicted before drilling are known conditions. The multi-field coupling factor directly affects the vertical effective stress. According to the effective stress principle, the formation pore pressure after multi-field coupling correction is calculated.

[0078] Furthermore, in step 4, the formation pore pressure predicted before drilling, the real-time calculated wellbore stress and the effective stress principle (Equation (26)) are combined to calculate the formation pore pressure after considering the thermal-fluid-solid coupling correction. p p :

[0079] (26);

[0080] (27).

[0081] Furthermore, in step five, based on the different failure conditions of the elastic and plastic regions, the formation fracture pressure and collapse pressure of the elastic and plastic regions are calculated respectively in combination with the real-time updated formation pore pressure and wellbore stress.

[0082] Furthermore, in step five, the formation fracture pressure and collapse pressure are important boundaries of the formation pressure safety window. The stress failure conditions of the elastic region and the plastic region are divided, and the formation fracture pressure and collapse pressure of different regions are calculated. Specifically, the following steps are included:

[0083] (1) Formation failure is a tensile failure. When the effective tangential stress at the wellbore wall is greater than the tensile strength of the rock, the wellbore will fail. The failure condition is expressed as:

[0084] (28);

[0085] Where, is the tangential stress, MPa; St is the tensile strength of rock, MPa;

[0086] 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 elastic zone formation fracture pressure is obtained:

[0087] (29);

[0088] Where, P fe is the formation fracture pressure in the elastic zone, MPa;

[0089] ② Plastic zone: Substitute the tangential stress of the plastic zone 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 zone is obtained:

[0090] (30);

[0091] Where, P fp is the fracture pressure of the plastic zone formation, MPa;

[0092] (2) Based on the differences in compaction degree and rock strength between the elastic and plastic regions, the wellbore instability criteria are selected by region;

[0093] ① Elastic region: The rock strength in the elastic region is high. The classic Mohr-Coulomb yield criterion is used to determine the instability conditions in this region. The Mohr-Coulomb yield criterion is expressed in the form of stress at the wellbore wall as:

[0094] (31);

[0095] in, , are the tangential stress and radial stress, respectively; is the rock cohesion, MPa; is the rock friction angle, °; K is an intermediate variable, dimensionless;

[0096] Substituting the tangential stress and radial stress of the elastic zone formation in formula (20) into formula (31), the real-time calculation model of the formation collapse pressure considering the thermal stress at the wellbore wall in the elastic zone is:

[0097] (32);

[0098] Where, P ceis the collapse pressure of the formation in the elastic zone, MPa;

[0099] ② Plastic zone: Numerical simulation shows that when the radius of the plastic zone exceeds 1.6 times the wellbore radius, the wellbore is considered unstable, and the liquid column pressure at this time is the formation collapse pressure. Using Equation (33) as the wellbore instability condition in the plastic zone, substituting it into Equation (25), we can obtain a real-time calculation model for the formation collapse pressure at the wellbore in the plastic zone, as expressed in Equation (34):

[0100] (33);

[0101] (34);

[0102] Where, A p , A w are the plastic zone area and the wellbore area, m 2 ; P cp is the collapse pressure of the formation in the plastic zone, MPa.

[0103] Furthermore, in step six, the wellbore pressure control standard is determined through the real-time calculation results of the formation pressure, namely, 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, the change of the wellhead back pressure over time is calculated; the throttle valve opening is adjusted in real time through the industrial control computer, and then the wellhead back pressure is adjusted in real time.

[0104] Furthermore, the specific implementation process of step six is as follows:

[0105] After the formation pore pressure, fracture pressure, and collapse pressure are calculated in real time considering the thermal-fluid-solid coupling, the formation pressure safety window is shown in Equation (35):

[0106] (35);

[0107] in, 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 is the formation collapse pressure and formation fracture pressure in different areas, MPa; i Indicates the area, i = e represents the elastic zone, i = p represents the plastic zone;

[0108] The bottom hole pressure control standard is shown in formula (36):

[0109] (36);

[0110] in, 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 indicate that the bottom hole pressure control standard is within the formation pressure safety window;

[0111] After the bottom hole pressure control standard is known, the target wellhead back pressure is calculated in real time based on the wellbore flow model, as shown in Equation (37):

[0112] (37);

[0113] in, 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 The friction resistance of wellbore flow.

[0114] The formation pressure calculation and control system for managed pressure drilling based on multi-field coupling includes:

[0115] Wellbore circulation system, industrial computer, mud logging system and dual-channel automatic throttling device system;

[0116] The wellbore circulation system includes a mud pump, a standpipe pressure gauge, a rotary control blowout preventer group, a wellbore, a casing pressure gauge, a flow meter, a gas-liquid separator, and a mud pool. The circulation path is: a mud pump, a standpipe pressure gauge, a rotary control blowout preventer group, a wellbore, a casing pressure gauge, a dual-channel automatic throttling device system, a flow meter, a gas-liquid separator, and a mud pool.

[0117] The logging system includes a logging unit and a communication device;

[0118] The dual-channel automatic throttling device system comprises a back pressure pump, a first flat valve, a second flat valve, a first throttling valve, and a second throttling valve.

[0119] During the pressure-controlled drilling process, the drilling fluid in the mud pool is injected into the drill pipe through the mud pump and circulates out of the wellbore through the annulus; the mud logging instrument obtains the current well depth, drill bit depth, inlet and outlet flow rate, inlet and outlet density, inlet and outlet temperature, total pool volume, mechanical penetration rate, drilling pressure and rotation speed in real time, and transmits them to the industrial computer based on WITS communication. The industrial computer calculates the wellbore pressure profile in real time; the formation pressure calculated in real time is used to obtain the bottom hole control boundary, and based on the bottom hole control boundary, the target wellhead back pressure is calculated in real time; after the drilling fluid circulates out of the wellbore, the wellhead back pressure is represented by the casing pressure gauge; then, the drilling fluid enters the dual-channel automatic throttling device system; the industrial computer transmits the target wellhead back pressure to the automatic throttling device in real time, and the PLC The openings of the first throttle valve, the second throttle valve, the first flat valve, and the second flat valve are electrically controlled. When the reading of the casing pressure gauge stabilizes at the target wellhead back pressure, it is considered that the bottomhole pressure in the wellbore has reached the control range, and the wellbore pressure control operation is completed. Thereafter, the drilling fluid flows out of the dual-channel automatic throttling device system and returns to the mud pool through the flow meter and the gas-liquid separation device. The drilling fluid thus circulates once, and the wellhead back pressure is controlled in real time.

[0120] Compared with the prior art, the present invention has the following beneficial effects:

[0121] 1. This invention considers the effects of thermal-fluid-solid multi-field coupling and calculates the total stress around the wellbore during managed pressure drilling (MPD) based on in situ stress, thermal stress, seepage stress, and wellbore fluid pressure. Based on the effective stress principle and wellbore failure conditions, a model for calculating formation pressure in the elastic and plastic zones is established. This invention provides a method for calculating the formation pressure safety window, effectively improving the accuracy of formation pressure calculations during managed pressure drilling.

[0122] 2. This invention can calculate the radius of the plastic zone, which is influenced by thermodynamics, and accurately calculate the fracture and collapse pressures of different lithologic formations based on the different wellbore fracture conditions in the elastic-plastic region. This invention distinguishes between elastic-plastic and elastic formations, enabling precise calculation of the formation pressure safety window for different formation types.

[0123] 3. This invention discloses a multi-factor coupled managed pressure drilling (MPD) automatic control system. This system, combined with real-time logging data, can calculate formation pressure during MPD in real time, determine bottomhole pressure control standards, and determine target wellhead backpressure in real time by calculating wellbore hydraulic parameters. Based on the automatic throttling device control system, this system achieves precise automatic control of wellbore pressure. Compared to traditional MPD technology, this invention provides more precise wellbore pressure control boundaries, promoting the development of MPD technology in complex formations.

[0124] 4. The method of the present invention is scientific and meets the requirements of engineering precision. BRIEF DESCRIPTION OF THE DRAWINGS

[0125] Figure 1Real-time calculation and control flow chart of formation pressure in managed pressure drilling;

[0126] Figure 2 This is a structural diagram of the formation pressure calculation and control system for managed pressure drilling based on multi-field coupling;

[0127] In the figure: 1. Industrial computer; 2. Mud logging unit; 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 plate valve; 12. Second flat plate valve; 13. First throttle valve; 14. Second throttle valve; 15. Flow meter; 16. Gas-liquid separation device; 17. Mud tank.

[0128] Figure 3 This is a schematic diagram of the grid division of the wellbore-formation space domain;

[0129] Figure 4 Schematic diagram of the change of formation pressure window with circulation time at different well depths;

[0130] Figure 5 This is a schematic diagram of the change of formation pressure window with circulation time at a well depth of 1100 meters;

[0131] Figure 6 This is a schematic diagram of the change of formation pressure window with circulation time at a well depth of 4680 meters. DETAILED DESCRIPTION

[0132] The present invention will be described in further detail below with reference to the accompanying drawings and specific embodiments.

[0133] Example 1

[0134] Formation pressure calculation and control method of managed pressure drilling based on multi-field coupling, such as Figure 1 Shown, including:

[0135] Step 1: The industrial computer 1 is connected to the mud logger 2 to obtain the basic data required for calculation in real time, including: well depth, displacement, inlet and outlet density, inlet and outlet temperature, and mechanical drilling speed; the industrial computer 1 is connected to the automatic throttling device to control the wellhead back pressure in real time;

[0136] Step 2: Divide the wellbore-formation space domain into a grid, input the initial conditions and boundary conditions of the wellbore and formation temperatures, and calculate the drill pipe, annulus temperature distribution, and formation temperature distribution at different distances from the wellbore;

[0137] Step 3: Considering the influence of thermal-fluid-solid multi-field coupling, calculate the stress around the well at different well depths in the elastic-plastic region , , ; Among them, the radius of the plastic zone is calculated by the stress continuity conditions at the wellbore wall and the interface in the elastic-plastic region;

[0138] Step 4: Based on the overburden pressure profile obtained from logging data and the formation pore pressure profile predicted before drilling, the real-time formation pore pressure profile after multi-factor coupling correction is obtained by combining the effective stress principle;

[0139] Step 5: Calculate the real-time formation fracture pressure profile and collapse pressure profile at the wellbore wall at different well depths after multi-factor coupling correction in the elastic-plastic region;

[0140] 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 1.

[0141] Example 2

[0142] The difference between the method for calculating and controlling formation pressure in managed pressure drilling based on multi-field coupling described in Example 1 is that:

[0143] In step 1, industrial computer 1 communicates with mud logger 2 using the WITS protocol. Industrial computer 1 acquires real-time mud logging data, including current well depth, drill bit depth, inlet and outlet flow rates, inlet and outlet density, inlet and outlet temperature, total pool volume, mechanical penetration rate, weight on bit, and rotational speed. Industrial computer 1 connects to mud logger 2 to read this data in real time. Communication between industrial computer 1 and the automatic throttling device is electronically controlled using a PLC5. Industrial computer 1 enables automatic and manual adjustment of the throttle valve opening, thereby controlling wellhead backpressure. Before construction, proper communication between industrial computer 1, mud logger 2, and the automatic throttling device must be tested.

[0144] 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 in real time by the logging instrument 2; 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 3 temperature and is always the original formation temperature.

[0145] The grid division of wellbore-stratum space domain is as follows Figure 3As shown in the figure, the wellbore-formation spatial domain grids are drill pipe, annulus, cement sheath, and formation from the inside out. 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 remote wellbore distance node. The fluid in the drill pipe exchanges heat with the fluid in the annulus; the fluid in the annulus exchanges heat with the fluid in the drill pipe and the formation fluid. The wellbore unit includes the drill pipe, annulus, and cement sheath. The formation includes several formation units. Heat exchange occurs between adjacent formation units and between formation units and adjacent wellbore units. Therefore, the injection of low-temperature fluid in the wellbore 3 will cause the formation temperature to change, thereby affecting the stress state of the rock around the well and changing the safety pressure window. The heat transfer equations in the drill pipe, annulus, and formation are shown in Equations (1) to (3), respectively.

[0146] (1);

[0147] (2);

[0148] (3);

[0149] Among them, the heat transfer intermediate variables A and B are expressed as formula (4):

[0150] (4);

[0151] in, and are the drilling fluid mass flow rates in the drill pipe and annulus, respectively, in kg / s, as expressed in formula (5):

[0152] (5);

[0153] The comprehensive heat transfer coefficient of the drill pipe and annulus is expressed as follows:

[0154] (6);

[0155] (7);

[0156] Where, , , are the drill pipe temperature, annulus temperature and formation temperature, °C; is the formation temperature at the initial moment, °C; , are the cross-sectional areas of the drill pipe and annulus, m 2 ; , are the drilling fluid velocity in the drill pipe and annulus, m / s; , is the density of drilling fluid and formation, kg / m 3 ; , are the specific heat capacities of the formation and drilling fluid, J / (kg·℃); , , are the thermal conductivity of drill pipe and casing, cement sheath and formation, W / (m·℃); , , , , are the drill pipe inner diameter, annulus inner diameter, drill pipe outer diameter, annulus outer diameter and wellbore diameter, m; , are the total heat transfer coefficients between the drill pipe and the annulus, and between the annulus and the formation, W / (m 2 ℃); , , , are the convection 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, W / (m 2 ℃); z is the distance from the wellhead, m; r is the distance from the wellbore, m; H shoe , H b are casing shoe depth and bottom hole depth, m, respectively; h is the well depth, m; t is time, s;

[0157] The initial conditions for wellbore 3 and formation temperature are as follows:

[0158] Initial formation temperature:

[0159] (8);

[0160] At the initial moment, the temperature in the drill pipe and annulus is equal to the formation temperature:

[0161] (9);

[0162] T 0 p,i 、 T 0 a,i are the temperatures in the drill pipe and annulus at the initial moment, respectively;

[0163] The boundary conditions for wellbore 3 and formation temperature are as follows:

[0164] The drill pipe temperature at the wellhead is always equal to the drilling fluid injection temperature:

[0165] (10);

[0166] The drill pipe temperature at the bottom of the hole is always equal to the annulus temperature:

[0167] (11);

[0168] In formula (11) T n p,N represents the drill pipe temperature at the bottom of the well at time n, T n a,N represents the annular temperature at the bottom of the well at the nth moment; in addition, formula (10) represents the drill pipe temperature at the wellhead at the nth moment. The lower right corner represents the well depth position, from Figure 3 From the grid division, we can see that the bottom of the well is point N and the wellhead is point 0.

[0169] Where, is the sea surface temperature, °C; is the drilling fluid injection temperature, °C; is the geothermal gradient, °C; H sea is the depth of seawater, m; is the seafloor temperature.

[0170] The drilling fluid injection temperature is obtained in real time from the logging data. Through the above solution, the temperature distribution of the drill pipe, annulus and formation at different distances from the wellbore at different times can be calculated, providing support for thermal stress calculation.

[0171] In step three, the wellbore stress includes the in-situ stress, the thermal stress caused by the change of wellbore-formation temperature, the seepage stress caused by the seepage of the open hole section fluid and the fluid pressure of the wellbore 3; among them, the in-situ stress is the wellbore stress before the formation is drilled, the thermal stress is calculated in real time by the wellbore-formation coupled temperature field, the seepage effect of the open hole section is caused by the diffusion effect of the wellbore 3 fluid and the formation fluid, and the stress generated by the wellbore 3 fluid pressure is caused by the pressure holding effect; due to the different rock properties, the formations around the wellbore are divided into plastic areas and elastic areas from the inside to the outside; among them, the deep formations are mostly elastic formations, and the deep-water shallow layers and salt-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. The stress continuity conditions of the equilibrium differential equation at the wellbore wall and the interface are used to further calculate the radius of the plastic area affected by thermodynamics, thereby calculating the wellbore stress in different regions.

[0172] In step 3, considering the influence of thermal-fluid-solid multi-factor coupling, the wellbore stress at different well depths is calculated, including in situ stress, thermal stress caused by wellbore-formation temperature changes, seepage stress caused by fluid seepage in the open hole section, and wellbore stress caused by fluid pressure in the wellbore 3. Specifically, it includes:

[0173] The in-situ stress is expressed as:

[0174] (12);

[0175] (13);

[0176] Where, , , 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 formation pore pressure predicted before drilling, MPa; is the Poisson's ratio of rock, dimensionless; , is the tectonic stress coefficient, dimensionless; The general value is 0.74. The general 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 well circumference angle, rad;

[0177] The thermal stress is calculated based on 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:

[0178] (14);

[0179] (15);

[0180] Where, , , are radial, tangential and vertical thermal stresses, MPa; is the thermal expansion coefficient of rock, °C -1 ; E is the rock elastic modulus, MPa; R is the wellbore radius, m; The distance from the wellbore r The formation temperature at can be obtained from step 2, ℃; is the initial formation temperature, °C; T f ( r ) is the temperature difference between considering heat transfer and not considering heat transfer at different wellbore distances;

[0181] During managed pressure drilling, there is a diffusion effect between the fluid in the open hole section of wellbore 3 and the formation fluid. This seepage effect has a significant impact on the stress around the wellbore. The seepage stress is expressed as:

[0182] (16);

[0183] Where, , , is the radial, tangential and vertical seepage stress caused by the seepage around the well, MPa; is the liquid column pressure in wellbore 3, MPa; is the seepage coefficient, dimensionless; φ is the porosity;

[0184] The fluid pressure in the wellbore 3 exerts a holding effect on the wellbore wall, affecting the stress around the wellbore. The fluid pressure in the wellbore 3 is expressed as:

[0185] (17);

[0186] Where, and is the radial stress and tangential stress around the well generated by the fluid pressure in the wellbore 3, MPa;

[0187] Considering the above thermal-fluid-solid coupling factors, the total stress around the well can be expressed as:

[0188] (18);

[0189] Where, , , is the radial stress, tangential stress and vertical stress around the well, MPa;

[0190] Therefore, the vertical stress is expressed as:

[0191] (19);

[0192] The part above formula (18) is a simple derivation of the stress components. Formula (19) is the vertical stress after the input. The following formula (20) is the radial and tangential stress in the elastic zone, and formula (23) is the radial and tangential stress in the plastic zone. The purpose of calculating formula (18) is to apply it to formula (26) to calculate the pore pressure;

[0193] The lithology of the formation is divided into elastic and plastic regions. Deep formations are mostly elastic formations, while deep-water shallow formations and salt-gypsum layers are mostly plastic formations. The radial stress and tangential stress in the elastic region are expressed as:

[0194] (20);

[0195] 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:

[0196] (twenty one);

[0197] Where, and are the radial stress and tangential stress in the plane strain problem, MPa;

[0198] The yield function satisfies:

[0199] (twenty two);

[0200] Where, is the rock cohesion, MPa; is the friction angle, °; N and It's all calculation The intermediate variable of

[0201] Therefore, the radial stress and tangential stress in the plastic region are expressed as follows:

[0202] (twenty three);

[0203] According to the stress continuity condition at the interface between elastic and plastic regions:

[0204] (twenty four);

[0205] Substituting Equations (20) and (23) into Equation (24), we obtain the plastic zone radius constraint condition affected by temperature:

[0206] (25).

[0207] In step 4, the overburden pressure and the formation pore pressure predicted before drilling are known conditions. The multi-field coupling factor directly affects the vertical effective stress. According to the effective stress principle, the formation pore pressure after multi-field coupling correction is calculated.

[0208] In step 4, after the low-temperature fluid is injected into the wellbore 3, the formation temperature decreases, the formation rock mass shrinks relatively, and thermal stress (manifested as tensile stress) is generated on the surface to inhibit its shrinkage. The fluid space in the formation changes slightly, thereby affecting the pore fluid pressure in the microelement. Combining the formation pore pressure predicted before drilling, the real-time calculated wellbore stress, and the effective stress principle (Equation (26)), the formation pore pressure after considering the thermal-fluid-solid coupling correction is calculated. p p :

[0209] (26);

[0210] (27).

[0211] In step five, based on the different failure conditions of the elastic and plastic regions, combined with the real-time updated formation pore pressure and wellbore stress, the formation fracture pressure and collapse pressure of the elastic and plastic regions are calculated respectively.

[0212] In step 5, the formation fracture pressure and collapse pressure are important boundaries of the formation pressure safety window. The stress failure conditions in the elastic region and the plastic region are divided, and the formation fracture pressure and collapse pressure in different regions are calculated. Specifically, it includes:

[0213] (1) Formation failure is a tensile failure. When the effective tangential stress at the wellbore wall is greater than the tensile strength of the rock, the wellbore will fail. The failure condition is expressed as:

[0214] (28);

[0215] Where, is the tangential stress, MPa; St is the tensile strength of rock, MPa;

[0216] 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 elastic zone formation fracture pressure is obtained:

[0217] (29);

[0218] Where, P fe is the formation fracture pressure in the elastic zone, MPa;

[0219] ② Plastic zone: Substitute the tangential stress of the plastic zone 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 zone is obtained:

[0220] (30);

[0221] Where, P fp is the fracture pressure of the plastic zone formation, MPa;

[0222] (2) Borehole collapse is a shear failure. When the stress on the rock at the wellbore wall is greater than the strength of the rock itself, shear failure occurs in the formation. Based on the different compaction degrees and rock strengths in the elastic and plastic regions, the wellbore instability criteria are selected by region.

[0223] ① Elastic region: The rock strength in the elastic region is high. The classic Mohr-Coulomb yield criterion is used to determine the instability conditions in this region. The Mohr-Coulomb yield criterion is expressed in the form of stress at the wellbore wall as:

[0224] (31);

[0225] in, , are the tangential stress and radial stress, respectively; is the rock cohesion, MPa; is the rock friction angle, °; K is an intermediate variable, dimensionless;

[0226] Substituting the tangential stress and radial stress of the elastic zone formation in formula (20) into formula (31), the real-time calculation model of the formation collapse pressure considering the thermal stress at the wellbore wall in the elastic zone is:

[0227] (32);

[0228] Where, P ce is the collapse pressure of the formation in the elastic zone, MPa;

[0229] ② Plastic zone: Numerical simulation shows that when the radius of the plastic zone exceeds 1.6 times the wellbore radius, the wellbore is considered unstable, and the liquid column pressure at this time is the formation collapse pressure. Formula (33) is used as the wellbore instability condition in the plastic zone and substituted into formula (25). Formula (25) can be regarded as the formula of Rp, that is, Rp is substituted into formula (33); thus, a real-time calculation model of the formation collapse pressure at the wellbore in the plastic zone is obtained, as expressed in formula (34):

[0230] (33);

[0231] (34);

[0232] Where, A p , A w are the plastic zone area and the wellbore area, m 2 ; P cp is the collapse pressure of the formation in the plastic zone, MPa.

[0233] The above-mentioned real-time calculation process shows that the present invention considers the coupled effects of multiple factors, namely, heat, fluid, and solid, and calculates the changes in formation pore pressure, fracture pressure, and collapse pressure in real time during managed pressure drilling, thereby providing bottom hole boundary conditions for wellbore 3 pressure control.

[0234] In step six, the pressure control standard of wellbore 3 is determined based on the real-time calculation results of formation pressure, namely, the formation pressure safety window: the safety interval between the minimum value of formation pore pressure and formation collapse pressure and the formation fracture pressure; based on the wellbore hydraulic parameter calculation model, the change of wellhead back pressure over time is calculated; the throttle valve opening is adjusted in real time by industrial control computer 1, thereby adjusting the wellhead back pressure in real time.

[0235] The specific implementation process of step six is as follows:

[0236] After the formation pore pressure, fracture pressure, and collapse pressure are calculated in real time considering the thermal-fluid-solid coupling, the formation pressure safety window is shown in Equation (35):

[0237] (35);

[0238] in, 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 is the formation collapse pressure and formation fracture pressure in different areas, MPa; i Indicates the area, i = e represents the elastic zone, i = p represents the plastic zone;

[0239] The bottom hole pressure control standard is shown in formula (36):

[0240] (36);

[0241] in, 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 indicate that the bottom hole pressure control standard is within the formation pressure safety window;

[0242] After the bottom hole pressure control standard is known, the target wellhead back pressure is calculated in real time based on the wellbore flow model, as shown in Equation (37):

[0243] (37);

[0244] in, p Goal is the target wellhead back pressure, MPa; g is the acceleration due to gravity, m / s 2 ; p f is the flow friction of wellbore 3, MPa; p f is the flow friction in wellbore 3.

[0245] The real-time target wellhead backpressure is transmitted to the dual-channel automatic throttling device system. The PLC electronically controls the opening of the throttle valve and the plate valve until the reading of the casing pressure gauge 9 stabilizes at the target wellhead backpressure. At this point, the bottomhole pressure in the wellbore 3 is considered to have reached the control standard, completing the pressure control operation and ensuring safe pressure-controlled drilling. This is of great value and significance for the safe and efficient development of complex oil and gas reservoirs.

[0246] In order to further demonstrate the positive effects of the embodiment, the present invention conducted the following experiments based on the above technical solution.

[0247] The method of the present invention is used to calculate the real-time changes in formation pressure during deepwater managed pressure drilling. Figure 4 The following curve shows the change in formation pressure safety over drilling time from a well depth of 3,800 meters to 4,680 meters. It shows that before drilling fluid circulation, the bottomhole formation pressure safety window was 7.60 MPa. After 24 hours of drilling fluid circulation, the pore pressure and fracture pressure gradually decreased due to the influence of thermal-fluid-solid coupling, and the corresponding bottomhole formation pressure safety window narrowed to 6.34 MPa. Figure 5 and Figure 6The following diagrams show the evolution of formation pressure with circulation time at well depths of 1100 meters and 4680 meters, respectively. It can be seen that in the plastic zone (1100 meters), due to the higher temperature of wellbore 3 than the formation temperature, the formation rock mass contracts relatively, generating thermal stress (compressive stress) on the surface that inhibits its expansion, leading to slight changes in the fluid space within the formation. Consequently, the formation pore pressure, collapse pressure, and fracture pressure all increase. In the elastic zone (4680 meters), the thermal stress acts in the opposite way, resulting in a decrease in formation pore pressure, collapse pressure, and fracture pressure. Numerically, the formation pressure safety window at 1100 meters decreases from 1.461 MPa to 1.418 MPa, and the formation pressure safety window at 4680 meters decreases from 7.60 MPa to 6.34 MPa. Figure 5 and Figure 6 The multi-factor influence mentioned here refers to the consideration of the multi-field coupling of heat, fluid, and solid, taking into account the effects of surrounding ground stresses such as thermal stress, seepage stress, and wellbore pressure. These stresses are the model embodiment of the multi-field coupling of heat, fluid, and solid. During managed pressure drilling, the wellbore pressure control boundary must be determined based on the formation pressure. This invention can calculate the real-time changes in the formation pressure safety window under the influence of heat, fluid, and solid, which is crucial for the safe implementation of managed pressure drilling.

[0248] In summary, the formation pressure calculation method and control system for pressure-controlled drilling based on multi-field coupling of the present invention can calculate the formation pressure under the influence of thermal-fluid-solid coupling during pressure-controlled drilling in real time, calculate the hydraulic parameters of the wellbore 3 in real time, and quickly control the automatic throttling device to achieve automatic regulation of the wellhead back pressure, thereby ensuring safe pressure-controlled drilling.

[0249] Example 3

[0250] The formation pressure calculation and control system for managed pressure drilling based on multi-field coupling includes:

[0251] Wellbore circulation system, industrial computer 1, mud logging system and dual-channel automatic throttling device system;

[0252] The wellbore circulation system includes a mud pump 6, a standpipe pressure gauge 7, a rotary control blowout preventer group 8, a wellbore 3, a casing pressure gauge 9, a flow meter 15, a gas-liquid separator 16, and a mud pool 17. The circulation path is: mud pump 6, standpipe pressure gauge 7, a rotary control blowout preventer group 8, a wellbore 3, a casing pressure gauge 9, a dual-channel automatic throttling device system, a flow meter 15, a gas-liquid separator 16, and a mud pool 17.

[0253] The industrial computer 1 is equipped with real-time calculation software for hydraulic parameters of pressure-controlled drilling, automatic control software for throttling devices, etc. The logging system includes a logging instrument 2 and a communication device;

[0254] The dual-channel automatic throttling device system includes a back pressure pump 10 , a first flat valve 11 , a second flat valve 12 , a first throttle valve 13 , and a second throttle valve 14 .

[0255] The specific working process of the pressure-managed drilling formation pressure control system based on multi-field coupling is as follows: during the pressure-managed drilling process, the drilling fluid in the mud pool 17 is injected into the drill pipe through the mud pump 6 and circulates out of the wellbore 3 through the annulus; the mud logging instrument 2 obtains the current well depth, drill bit depth, inlet and outlet flow rate, inlet and outlet density, inlet and outlet temperature, total pool volume, mechanical penetration rate, drilling pressure and rotation speed in real time, and transmits them to the industrial control computer 1 based on the WITS communication 4. The pressure-managed drilling hydraulic parameter real-time calculation software installed in 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 increase and the formation temperature to decrease. The thermal stress, seepage stress, in-situ stress and liquid column pressure of the wellbore 3 generated by the temperature difference have different effects on the stress around the wellbore, thereby changing the formation pressure profile. Based on the formation pressure calculated in real time by the present invention, a precise 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 indicated by the casing pressure gauge 9. Next, the drilling fluid enters the dual-channel automatic throttling device system. The industrial control computer 1 transmits the target wellhead backpressure to the automatic throttling device in real time, and the PLC 5 electrically controls the openings of the first throttle valve 13, the second throttle valve 14, the first flat valve 11, and the second flat valve 12. When the reading of the casing pressure gauge 9 stabilizes at the target wellhead backpressure, the bottomhole pressure in the wellbore 3 is considered to have reached the control range, completing the wellbore 3 pressure control operation. Thereafter, after the drilling fluid flows out of the dual-channel automatic throttling device system, it returns to the mud pool 17 through the flowmeter 15 and the gas-liquid separator 16. Thus, the drilling fluid circulates once, and the wellhead backpressure is controlled in real time. It is worth noting that the backpressure pump 10 is used to control pressure during the pump shutdown period for single-root connection. During the pump stop period, the drilling fluid stops circulating, causing the automatic throttling device to malfunction. During this period, the back pressure pump 10 is started and pumped into the wellbore 3 through the dual-channel automatic throttling device system. At this time, the wellhead back pressure can be controlled by controlling the opening of the throttle valve and the plate valve.

[0256] Based on the above workflow, the system monitors the inlet and outlet temperatures of the drilling fluid in real time, calculates the formation pressure and the wellbore 3 pressure in real time, and then controls the valve position opening of the dual-channel automatic throttling device in real time, thereby achieving precise control of the wellbore 3 pressure during pressure-controlled drilling and pressure-controlled pump shutdown and single-root connection.

[0257] The above description is only a preferred specific implementation method of the present invention, but the scope of protection of the present invention is not limited thereto. Any modifications, equivalent substitutions and improvements made by any technician familiar with this technical field within the technical scope disclosed by the present invention and within the spirit and principles of the present invention should be covered by the scope of protection of the present invention.

Claims

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

2. 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 the step 1, the industrial computer communicates with the mud logging instrument using the WITS protocol, and the industrial computer obtains mud logging measurement data in real time, including: current well depth, drill bit depth, inlet and outlet flow rates, inlet and outlet density, inlet and outlet temperature, total pool volume, mechanical drilling speed, drilling pressure and rotational speed; the communication between the industrial computer and the automatic throttling device adopts PLC electric control, and the industrial computer realizes automatic and manual adjustment of the throttle valve opening, thereby controlling the wellhead back pressure.

3. 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 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 in real time by the logging instrument; at the bottomhole boundary, the drill pipe temperature is equal to the annular 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 grids are drill pipe, annulus, cement sheath, and formation from the inside out, and the fluid in the drill pipe exchanges heat with the fluid in the annulus; the fluid in the annulus exchanges heat with 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 formation units and adjacent wellbore units; the heat transfer equations in the drill pipe, annulus, and formation are shown in Equations (1) to (3), respectively: (1)； (2)； (3)； Among them, the heat transfer intermediate variables A and B are expressed as formula (4): （4）； in, and are the drilling fluid mass flow rates in the drill pipe and annulus, respectively, in kg / s, as expressed in formula (5): （5）； The comprehensive heat transfer coefficient of the drill pipe and annulus is expressed as follows: (6)； (7)； Where, , , are the drill pipe temperature, annulus temperature and formation temperature, °C; is the formation temperature at the initial moment, °C; , are the cross-sectional areas of the drill pipe and annulus, m 2 ; , are the drilling fluid velocity in the drill pipe and annulus, m / s; , is the density of drilling fluid and formation, kg / m 3 ; , are the specific heat capacities of the formation and drilling fluid, J / (kg·℃); , , are the thermal conductivity of drill pipe and casing, cement sheath and formation, W / (m·℃); , , , , are the drill pipe inner diameter, annulus inner diameter, drill pipe outer diameter, annulus outer diameter and wellbore diameter, m; , are the total heat transfer coefficients between the drill pipe and the annulus, and between the annulus and the formation, W / (m 2 ℃); , , , are the convection 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, W / (m 2 ℃); z is the distance from the wellhead, m; r is the distance from the wellbore, m; H shoe , H b are casing shoe depth and bottom hole depth, m, respectively; h is the well depth, m; t is time, s; The initial conditions for wellbore and formation temperatures are as follows: Initial formation temperature: (8)； At the initial moment, the temperature in the drill pipe and annulus is equal to the formation temperature: (9)； T 0 p,i 、 T 0 a,i are the temperatures in the drill pipe and annulus at the initial moment, respectively; The boundary conditions for 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 of the hole is always equal to the annulus temperature: (11)； In formula (11) T n p,N represents the drill pipe temperature at the bottom of the well at time n, T n a,N represents the annular temperature at the bottom of the well at the nth moment; where, is the sea surface temperature, °C; is the drilling fluid injection temperature, °C; is the geothermal gradient, °C; H sea is the depth of seawater, m; is the seafloor 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 three, the wellbore stress includes in-situ stress, thermal stress caused by wellbore-formation temperature changes, seepage stress caused by openhole fluid seepage, and wellbore fluid pressure. Among them, the in-situ stress is the wellbore stress before the formation is drilled, the thermal stress is calculated in real time by the wellbore-formation coupled temperature field, the openhole seepage effect is caused by the diffusion effect of wellbore fluid and formation fluid, and the stress caused by wellbore fluid pressure is caused by the pressure holding effect. The formation around the wellbore is divided into plastic and elastic regions from the inside to the outside. The radius of the plastic region affected by thermodynamics is calculated, and the wellbore stress is calculated by region. In step 3, considering the influence of thermal-fluid-solid multi-factor coupling, the wellbore stress at different well depths is calculated, including in situ stress, thermal stress caused by wellbore-formation temperature changes, seepage stress caused by fluid seepage in the open hole, and wellbore stress caused by wellbore fluid pressure. Specifically, it includes: The in-situ stress is expressed as: (12)； (13)； Where, , , 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 formation pore pressure predicted before drilling, MPa; is the Poisson's ratio of 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 well circumference angle, rad; The thermal stress is calculated based on 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)； Where, , , are radial, tangential and vertical thermal stresses, MPa; is the thermal expansion coefficient of rock, °C -1 ; E is the rock elastic modulus, MPa; R is the wellbore radius, m; The distance from the wellbore r The formation temperature at can be obtained from step 2, ℃; is the initial formation temperature, °C; T f ( r ) is the temperature difference between considering heat transfer and not considering heat transfer at different wellbore distances; The seepage stress is expressed as: (16)； Where, , , is the radial, tangential and vertical seepage stress caused by the 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）； Where, and is the radial stress and tangential stress around the well generated by the wellbore fluid pressure, MPa; Considering the above thermal-fluid-solid coupling factors, the total stress around the well can be expressed as: (18)； Where, , , is the radial stress, tangential stress and vertical stress around the well, MPa; Therefore, the vertical stress is expressed as: (19)； The lithology of the formation is divided into elastic and plastic regions. 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)； Where, and are the radial stress and tangential stress in the plane strain problem, MPa; The yield function satisfies: (22)； Where, is the rock cohesion, MPa; is the friction angle, °; Therefore, the radial stress and tangential stress in the plastic region are expressed as follows: (23)； According to the stress continuity condition at the interface between elastic and plastic regions: (24)； Substituting Equations (20) and (23) into Equation (24), we obtain the plastic zone radius constraint condition affected by temperature: (25)。 5. 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 4, the overburden pressure and the formation pore pressure predicted before drilling are known conditions. The multi-field coupling factor directly affects the vertical effective stress. According to the effective stress principle, the formation pore pressure after multi-field coupling correction is calculated; In step 4, the formation pore pressure after considering the thermal-fluid-solid coupling correction is calculated by combining the formation pore pressure predicted before drilling, the real-time calculated wellbore stress and the effective stress principle (Equation (26)). p p : （26）； (27)。 6. 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 five, based on the different failure conditions of the elastic and plastic regions, combined with the real-time updated formation pore pressure and wellbore stress, the formation fracture pressure and collapse pressure of the elastic and plastic regions are calculated respectively.

7. 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 5, the formation fracture pressure and collapse pressure are important boundaries of the formation pressure safety window. The stress failure conditions in the elastic region and the plastic region are divided to calculate the formation fracture pressure and collapse pressure in different regions. Specifically include: (1) Formation failure is a tensile failure. When the effective tangential stress at the wellbore wall is greater than the tensile strength of the rock, the wellbore will fail. The failure condition is expressed as: （28）； Where, is the tangential stress, MPa; St is the tensile strength of 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 elastic zone formation fracture pressure is obtained: (29)； Where, P fe is the formation fracture pressure in the elastic zone, MPa; ② Plastic zone: Substitute the tangential stress of the plastic zone 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 zone is obtained: (30)； Where, P fp is the fracture pressure of the plastic zone formation, MPa; (2) Based on the differences in compaction degree and rock strength between the elastic and plastic regions, the wellbore instability criteria are selected by region; ① Elastic region: The rock strength in the elastic region is high. The classic Mohr-Coulomb yield criterion is used to determine the instability conditions in this region. The Mohr-Coulomb yield criterion is expressed in the form of stress at the wellbore wall as: (31)； in, , are the tangential stress and radial stress, respectively; is the rock cohesion, MPa; is the rock friction angle, °; K is an intermediate variable, dimensionless; Substituting the tangential stress and radial stress of the elastic zone formation in formula (20) into formula (31), the real-time calculation model of the formation collapse pressure considering the thermal stress at the wellbore wall in the elastic zone is: (32)； Where, P ce is the collapse pressure of the formation in the elastic zone, MPa; ② Plastic zone: Numerical simulation shows that when the radius of the plastic zone exceeds 1.6 times the wellbore radius, the wellbore is considered unstable, and the liquid column pressure at this time is the formation collapse pressure. Using Equation (33) as the wellbore instability condition in the plastic zone, substituting it into Equation (25), we can obtain a real-time calculation model for the formation collapse pressure at the wellbore in the plastic zone, as expressed in Equation (34): (33)； (34)； Where, A p , A w are the plastic zone area and the wellbore area, m 2 ; P cp is the collapse pressure of the formation in the plastic zone, 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 to 7, characterized in that: In step six, the wellbore pressure control standard, i.e., the formation pressure safety window, is determined based on the real-time calculation results of the formation pressure: 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, the change of the wellhead back pressure over time is calculated; the throttle valve opening is adjusted in real time through the industrial control computer, thereby adjusting the wellhead back pressure in real time.

9. The method for calculating and controlling formation pressure in managed pressure drilling based on multi-field coupling according to claim 8, characterized in that: The specific implementation process of step six is as follows: After the formation pore pressure, fracture pressure, and collapse pressure are calculated in real time considering the thermal-fluid-solid coupling, the formation pressure safety window is shown in Equation (35): (35)； in, 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 is the formation collapse pressure and formation fracture pressure in different areas, MPa; i Indicates the area, i = e represents the elastic zone, i = p represents the plastic zone; The bottom hole pressure control standard is shown in formula (36): (36)； in, 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 indicate that the bottom hole pressure control standard is within the formation pressure safety window; After the bottom hole pressure control standard is known, the target wellhead back pressure is calculated in real time based on the wellbore flow model, as shown in Equation (37): (37)； in, 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 The friction resistance of wellbore flow.

10. A formation pressure calculation and control system for managed pressure drilling based on multi-field coupling, used to implement the formation pressure calculation and control method for managed pressure drilling based on multi-field coupling according to any one of claims 1 to 9, characterized in that: include: Wellbore circulation system, industrial computer, mud logging system and dual-channel automatic throttling device system; The wellbore circulation system includes a mud pump, a standpipe pressure gauge, a rotary control blowout preventer group, a wellbore, a casing pressure gauge, a flow meter, a gas-liquid separator, and a mud pool. The circulation path is: a mud pump, a standpipe pressure gauge, a rotary control blowout preventer group, a wellbore, a casing pressure gauge, a dual-channel automatic throttling device system, a flow meter, a gas-liquid separator, and a mud pool. The logging system includes a logging unit and a communication device; The dual-channel automatic throttling device system includes a back pressure pump, a first flat valve, a second flat valve, a first throttle valve, and a second throttle valve; During the pressure-controlled drilling process, the drilling fluid in the mud pool is injected into the drill pipe through the mud pump and circulates out of the wellbore through the annulus; the mud logging instrument obtains the current well depth, drill bit depth, inlet and outlet flow rate, inlet and outlet density, inlet and outlet temperature, total pool volume, mechanical penetration rate, drilling pressure and rotation speed in real time, and transmits them to the industrial computer based on WITS communication. The industrial computer calculates the wellbore pressure profile in real time; the formation pressure calculated in real time is used to obtain the bottom hole control boundary, and based on the bottom hole control boundary, the target wellhead back pressure is calculated in real time; after the drilling fluid circulates out of the wellbore, the wellhead back pressure is represented by the casing pressure gauge; then, the drilling fluid enters the dual-channel automatic throttling device system; the industrial computer transmits the target wellhead back pressure to the automatic throttling device in real time, and the PLC The openings of the first throttle valve, the second throttle valve, the first flat valve, and the second flat valve are electrically controlled. When the reading of the casing pressure gauge stabilizes at the target wellhead back pressure, it is considered that the bottomhole pressure in the wellbore has reached the control range, and the wellbore pressure control operation is completed. Thereafter, the drilling fluid flows out of the dual-channel automatic throttling device system and returns to the mud pool through the flow meter and the gas-liquid separation device. The drilling fluid thus circulates once, and the wellhead back pressure is controlled in real time.

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