Method for stabilizing well wall through cooperation of wall fixing agent for marine hydrate drilling fluid and temperature-pressure field and application of wall fixing agent and temperature-pressure field

Abstract

The invention relates to a method for stabilizing a well wall through cooperation of a wall fixing agent for marine hydrate drilling fluid and a temperature and pressure field and application of the wall fixing agent and the temperature and pressure field, and belongs to the technical field of natural gas hydrate development. A mud cake is embedded into an unsteady state mass and heat transfer model, a sea area natural gas hydrate drilling fluid-solid-heat-chemical multi-field coupling model is constructed, parameters such as the dosage of a drilling fluid wall fixing agent and the temperature and pressure of drilling fluid are dynamically adjusted, and the stable state of a well wall is judged in real time according to the improved hydrate reservoir Mohr-Coulomb criterion. And the borehole wall instability risk is rapidly reduced by dynamically adjusting drilling fluid parameters (the concentration of a wall fixing agent and the temperature or pressure of the drilling fluid), and the borehole wall stability of marine hydrate reservoir drilling is achieved.

Description

Technical Field

[0001] The invention relates to a method and application of a wall-fixing agent for marine hydrate drilling fluid and a temperature-pressure field coordinated well wall stabilization method, and belongs to the technical field of natural gas hydrate development. Background Art

[0002] Natural gas hydrates are ice-like cage-type crystalline substances formed by water molecules and natural gas molecules under low temperature and high pressure. They are also known as "combustible ice" and "solid gas". They are recognized by the world as an ideal alternative energy source in the 21st century due to their high energy density and low pollution. According to incomplete statistics, the carbon content of hydrates in the world can reach 15 trillion tons, accounting for more than 50% of the global carbon content; and the methane content can reach 700 trillion to 200 trillion cubic meters. The commercial production of methane from 15% of natural gas hydrates can meet the energy needs of the entire world in the next 200 years. More than 90% of natural gas hydrates are distributed in submarine strata. At present, countries around the world are competing fiercely for the research on natural gas hydrate mining technology. It is an urgent need and task to strengthen the theoretical and technical research on efficient mining of submarine natural gas hydrates and provide technical preparations for commercial mining.

[0003] During the drilling process of hydrate reservoirs, the reservoirs around the wellbore are extremely sensitive to temperature and pressure changes. The intrusion of drilling fluid into the hydrate reservoir is a non-steady-state heat and mass transfer process, involving the coupling of multiple physical fields such as fluid-solid-heat. When the drilling fluid invades the hydrate reservoir under the action of pressure difference, it reacts with the hydrate reservoir to transfer heat and mass, and affects the mechanical properties around the well wall through interactions such as heat conduction, fluid flow and hydrate phase change, causing well wall instability. Therefore, during the drilling process of deepwater hydrate reservoirs, a method of coordinated regulation of formation mechanical parameters and well wall stability by the drilling fluid and reservoir temperature and pressure field is urgently needed to solve the problem of well wall instability caused by hydrate phase change caused by drilling fluid invasion. Chinese patent document CN112347675B discloses a method for cooperatively regulating the phase state of natural gas hydrate in reservoirs by using drilling fluid additives and temperature and pressure fields. The particle swarm algorithm is used to obtain the optimal combination of drilling fluid additive concentration, injection temperature and displacement, so as to minimize the change in saturation of natural gas hydrate in reservoirs. However, the above method does not consider the mud cake parameters under the influence of the wall solidifier in the drilling fluid and the changes in the mechanical properties of the formation after the decomposition of the hydrate; Chinese patent document CN114965520A provides a device and method for evaluating the stability of the well wall of a hydrate formation during simulated drilling, and Chinese patent document CN115408956B provides a method for real-time acquisition of physical properties and mechanical parameters of the periphery of a hydrate reservoir during drilling, but neither of them considers the influence of the drilling fluid wall solidifier on the mass and heat transfer between the wellbore and the reservoir; Chinese patent document CN118627424A provides a method for calculating the safe density window of hydrate formations considering the mud cake, but does not consider the influence mechanism of drilling fluid invasion on the mechanical parameters of the reservoir. In summary, clarifying the influence of drilling fluid wall-fixing agents on the mechanical parameters of offshore natural gas hydrate drilling and designing a method for coupling the wall-fixing agent with the temperature and pressure field of the offshore hydrate reservoir to coordinately stabilize the wellbore is one of the key research directions in the field of natural gas hydrate development technology. Summary of the invention

[0004] In view of the deficiencies of the prior art, the present invention provides a method for stabilizing the wellbore by using a wall-fixing agent and a temperature and pressure field for drilling fluid in marine hydrate drilling. Considering the changes in reservoir mechanical parameters caused by hydrate phase change, formation creep, and the interaction between drilling fluid and hydrate reservoir, the mud cake is embedded in the non-steady-state mass transfer and heat transfer model, and a multi-field coupling model of fluid-solid-heat-chemical for offshore natural gas hydrate drilling is constructed. The amount of drilling fluid wall-fixing agent and parameters such as drilling fluid temperature and pressure are dynamically adjusted. The wellbore stability state is judged in real time according to the improved Mohr-Coulomb criterion of the hydrate reservoir, and the risk of wellbore instability is quickly reduced by dynamically adjusting the drilling fluid parameters (wall-fixing agent concentration, drilling fluid temperature or pressure), so as to achieve wellbore stability in offshore hydrate reservoir drilling.

[0005] The technical solution of the present invention is as follows: A method for stabilizing the well wall by using a wall-fixing agent for drilling fluid for marine hydrate drilling and a temperature-pressure field, comprising the following steps: Step S1, obtaining current drilling parameters and natural gas hydrate reservoir physical property data, and establishing a wellbore-hydrate reservoir unsteady-state mass transfer and heat transfer model through a wellbore-hydrate reservoir unsteady-state heat transfer model, a hydrate reservoir multiphase seepage model, and a hydrate intrinsic decomposition kinetic model.

[0006] Preferably, the unsteady-state heat transfer model of the wellbore-hydrate reservoir is calculated according to the following formula. According to the law of conservation of energy, the solid phase energy equation of the hydrate phase change is: (1) In the formula, ϕ wg is the limited porosity of gas-liquid flow in the hydrate reservoir, ϕ wg = ϕ ×(1- S h ), ϕ is the porosity of the sand body, S h is the saturation of hydrate; t is the time; is the density of the solid phase r and specific heat C The equivalent product of k eh is the equivalent thermal conductivity of the solid phase, and k eh It can be solved by weighting by volume fraction; T e is the solid phase temperature; ∆ E h is the heat of decomposition of the hydrate; h sf is the convective heat transfer coefficient between the solid phase and the fluid; A sf is the specific surface area in the porous medium; T f is the fluid temperature; is the decomposition rate of hydrate in porous media, which can be solved by the hydrate intrinsic decomposition kinetic model (KB model): (2) In the formula, M h is the molar mass of the hydrate, k d is the intrinsic reaction constant of hydrate, △ E is the hydrate activation energy, R is the gas constant, T is the thermodynamic temperature, Ah is the hydrate phase change mass transfer specific surface area, p eq and p e They are the equilibrium pressure of hydrate under phase equilibrium temperature and pressure conditions and the pore pressure during the formation process, respectively.

[0007] The flow of fluid in porous media involves five forms of heat transfer, namely, energy migration caused by fluid flow, heat conduction inside the fluid, convective heat transfer on the interface between fluid and solid, Joule-Thomson effect of gas, and energy decomposition of water and gas, as shown in equation (3). The term on the left side of the equation represents the change in internal energy, and the term on the right side of the equation represents the five forms of heat transfer in turn. (3) In the formula, k f is the thermal conductivity of the fluid; p is the fluid pressure; and are the rates of hydrate decomposition to produce free gas and water, respectively; C p,g and C p,w are the specific heat capacities of free gas and water at constant pressure respectively; S , r and v are saturation, density and flow velocity, respectively, and the subscripts g and w represent free gas and water, respectively; m JT is the Joule-Thomson effect coefficient; In the local non-equilibrium heat transfer process, the fluid and solid energy control equations are often closed by constructing the interface convection heat transfer mode, which is expressed as: (4) In the formula, N u is the Nusselt number, d p is the average diameter of sand particles, R e is the Reynolds number, P r is the Prandtl number.

[0008] Preferably, the multiphase seepage model of the hydrate reservoir is calculated according to the following formula. According to the law of conservation of mass, the continuity equation of free gas, water and hydrate in the porous medium can be expressed as: (5) (6) (7) In the formula, k is the effective permeability of the hydrate reservoir, which is exponentially related to the hydrate saturation. k = k 0×(1- S h ) N , k 0 is the effective initial permeability of the hydrate reservoir, N is a permeability reduction index related to the pore size and structure of hydrate sediments; r h is the density of the hydrate; k rw and k rg are the relative permeabilities of water and gas phases, respectively; m w and m g are the viscosities of the water phase and the gas phase, respectively; p w and p g are the pressures of water phase and gas phase in the pores, respectively; the subscript h represents hydrate, S h is the hydrate saturation; , and Represent the mass change rates of water, gas and hydrate respectively; g is the gravitational acceleration, m / s 2 ; ɸ is the porosity.

[0009] Assuming that the density of water is constant within the reservoir pressure range, the continuity equation of the water phase after conversion is: (8) In the formula, p c is the capillary force; According to the gas state equation, the gas phase continuity equation is finally expressed as: (9) In the formula, M g is the molar mass of the gas; Z is the compressibility factor of the gas.

[0010] By coupling the unsteady-state heat transfer model of wellbore-hydrate reservoir, the multiphase seepage model of hydrate reservoir and the intrinsic decomposition kinetic model of hydrate, the unsteady-state mass and heat transfer model of wellbore-hydrate reservoir is established as follows: (10).

[0011] Step S2: Considering the changes in reservoir mechanical parameters caused by hydrate phase change, formation creep and the interaction between drilling fluid and hydrate reservoir, the mud cake is embedded in the unsteady-state mass transfer and heat transfer model to construct a fluid-solid-heat-chemical multi-field coupling model for offshore natural gas hydrate drilling.

[0012] In the original state of the formation, hydrates act as effective cementing components of the formation and together with the rock skeleton support the overlying stress of the formation. When hydrates decompose, the phase change from solid to fluid will change the effective stress of the formation, thereby weakening the reservoir cementation strength and deteriorating the mechanical properties of the formation, which is very likely to cause formation instability and large amounts of sand production. Considering the changing mechanical properties of the hydrate reservoir, the elastic-plastic constitutive equation is used to describe the relationship between stress and strain, and its incremental form is as follows: (11) In the formula, d σij is the effective stress increment matrix; D ijkl is the elastic-plastic matrix tensor of the hydrate formation; d εkl is the reservoir skeleton strain increment matrix; The static equilibrium equation can be expressed in the tensor form of effective stress as: (12) In the formula, s ij is the reservoir skeleton stress tensor, Represents the stress tensor in j Divergence in direction, α B is the Biot coefficient; d ij is the Kronecker function; F i is the body load; The relationship between displacement and strain can be expressed in tensor form as: (13) In the formula, e ij is the reservoir skeleton strain tensor, w is the strain displacement, is the strain displacement along the coordinate i The rate of change of direction, is the strain displacement along the coordinate j rate of change of direction; The changes in elastic modulus and internal friction angle caused by hydrate decomposition will also cause wellbore instability. Preferably, the relationship between the formation internal friction angle and hydrate saturation is calculated and regressed according to the following formula: (14) In the formula, f is the internal friction angle of the hydrate reservoir.

[0013] Preferably, the relationship between formation cohesion and hydrate saturation is obtained by regression calculation according to the following formula: (15) In the formula, C ( S h ) is the cohesive force, C 0 is S h =0 when the cohesion is α , β Both are empirical coefficients that characterize the cohesion of formations.

[0014] Preferably, the relationship between the formation elastic modulus and the hydrate saturation is obtained by regression calculation according to the following formula: (16) In the formula, E ( S h ) is the elastic modulus of the hydrate reservoir, E 0 is S h =0 elastic modulus.

[0015] During the drilling process, mud cake, as a key product of the interaction between the wellbore and the drilling fluid, plays an important role in the stability of the wellbore. On the one hand, the porosity and permeability of the mud cake determine its barrier effect on fluid penetration, which directly affects the risk of hydrate decomposition and wellbore damage; on the other hand, the mechanical strength of the mud cake is the microscopic basis for supporting the stability of the wellbore. Therefore, it is necessary to introduce the mud cake parameters into the multi-field coupling model to further explore the dynamic correlation between the mud cake and the mechanical properties of the reservoir, so as to achieve a global analysis of the wellbore stability.

[0016] Preferably, the dynamic permeability of the mud cake is calculated according to the following formula: (17) In the formula, l is the pore permeability attenuation index, K mc0 is the minimum permeability of mud cake, K f is the formation permeability.

[0017] The dynamic porosity of the mud cake is calculated according to the following formula: (18) In the formula, ϕmc0 is the minimum porosity of the mud cake, ϕ f is the formation porosity.

[0018] Dynamic porosity and permeability are often interrelated. For example, a reduction in porosity (through compaction and consolidation) leads to a reduction in permeability. This interaction has a dual positive effect on the mechanical strength of the mud cake: a reduction in porosity increases the effective stress and enhances the mechanical strength; while a reduction in permeability reduces pore connectivity, enhances the cementation between particles, and further improves the mechanical strength. Therefore, the change in dynamic mechanical strength of the mud cake is calculated according to the following formula: (19) In the formula, s mc0 is the initial mechanical strength of the mud cake; m and n are the contribution constants of permeability and porosity to the mechanical strength of the mud cake.

[0019] By introducing the reservoir mechanical parameters (such as internal friction angle, cohesion and elastic modulus) and the changes in the porosity, permeability and dynamic mechanical strength parameters of the mud cake into the unsteady-state mass and heat transfer model of the wellbore-hydrate reservoir, the full coupling relationship between the thermal field, flow field and force field was established using the multi-physics field coupling software COMSOL; in the thermal field, the low porosity and low permeability of the mud cake change the heat transfer path near the wellbore by correcting the thermal conductivity and heat capacity of the local area of ​​the reservoir; in the flow field, the barrier effect of the mud cake affects the seepage behavior and pore pressure distribution of the fluid after hydrate decomposition through the dynamic correction of the effective permeability and porosity; in the force field, the dynamic mechanical strength of the mud cake, as an important source of wellbore support, works together with the changes in the reservoir mechanical parameters to affect the stress distribution around the wellbore and the evolution of the plastic zone. By comprehensively coupling the reservoir porosity, permeability, heat release caused by hydrate decomposition, fluid flow and mechanical evolution processes, a fluid-solid-heat-chemical multi-field coupling model integrating mass transfer, heat transfer, mechanical behavior and chemical reaction was finally formed, providing a theoretical basis for studying the mechanism of wellbore instability and stability regulation during offshore natural gas hydrate drilling.

[0020] Step S3, designing a marine hydrate drilling fluid system, adding different amounts of wall-fixing agents to the drilling fluid, analyzing the dynamic evolution of mud cake porosity, permeability, and mechanical strength, and clarifying the influence mechanism of the drilling fluid wall-fixing agent on the mechanical properties of the reservoir.

[0021] Obtain existing conventional marine hydrate drilling fluid wall solidifiers, and systematically construct a high-performance marine hydrate drilling fluid system with both well wall stability and reservoir protection by adding lubricants, inhibitors, viscosity-enhancing coating agents, viscosity-enhancing agents, glass beads, fluid loss reducers, and reservoir bridging agents. Determine the density and rheological parameters of the drilling fluid and conduct an API fluid loss test. Pour the drilling fluid into the fluid loss meter, install filter paper or filter membrane, turn on the equipment, and maintain operation under the set conditions for 30 minutes. For example, record the cumulative filtrate volume 𝑉 every 1 minute to calculate the fluid loss; turn off the equipment, slowly release the pressure, take out the mud cake, use a thickness gauge to measure the thickness at multiple points on the mud cake, and take the average value L ; Place the mud cake in an oven, set the temperature (e.g. 60°C), dry it to constant weight, and then use the density method to determine the porosity of the mud cake, that is, measure the dry weight of the mud cake ( m d ) and volume ( V ), calculate the dry density of the mud cake ( r d = m d / V ), through the density of the bentonite used in the slurry ( r s ), calculate the porosity for: (20) In the filtration test, the drilling fluid forms a mud cake through the filter paper or filter membrane under a certain pressure difference, and the filtrate flows out through the mud cake. The flow of the filtrate and the formation of the mud cake conform to Darcy's law and filtration theory. The permeability of the mud cake affects the passing speed of the filtrate. Conversely, the change of the filtrate volume over time also reflects the permeability characteristics of the mud cake.

[0022] Calculate the permeability of mud cake based on filtration theory and Darcy's law K for: (twenty one) Where: V is the volume of the filtrate, cm³; m is the plastic viscosity of drilling fluid, Pa·s; L is the mud cake thickness, m; t is the experimental time, s; A is the filter paper area, m 2 ; Δ P is the pressure difference, Pa; The mechanical strength of the mud cake is measured using the FCP Mud Cake Penetration Tester, which can accurately measure its compressive strength and other mechanical properties while maintaining the integrity of the mud cake. Install the mud cake sample to be tested on the test bench of the FCP instrument, ensure that the needle is vertically aligned with the sample surface, select the appropriate load range and calibrate the instrument according to the experimental requirements to ensure measurement accuracy. After starting the instrument, apply the preset load and record the relationship curve between the needle penetration depth and the applied force; further preferably, in order to improve the reliability of the data, each measuring point is tested at least three times and the average value is taken. Finally, the compressive strength of the mud cake is calculated by analyzing the load-needle penetration depth curve; The compressive strength reflects the bearing capacity of the mud cake under axial pressure. A higher compressive strength indicates that the mud cake forms a solid barrier on the well wall, which helps prevent accidents such as well collapse and well kick. s c The calculation formula is: (twenty two) Where: F max is the maximum load value applied, N; r is the needle radius, m; The concentration of the wall-fixing agent in the drilling fluid was adjusted, and filtration experiments, porosity determination, permeability tests and mechanical strength measurements were carried out under the same experimental conditions. By combining the experimental data with the reservoir mechanics theory and the fluid-solid-heat-chemical multi-field coupling model of offshore natural gas hydrate drilling, a systematic analysis was performed to obtain the dynamic evolution laws of the mud cake porosity, permeability and mechanical strength. This revealed how the wall-fixing agent affects the macroscopic mechanical properties of the reservoir by regulating the microstructural parameters of the mud cake during the optimization of the drilling fluid formula, thereby clarifying the influence mechanism of the wall-fixing agent on the mechanical properties of the reservoir.

[0023] Step S4, dynamically adjust the amount of drilling fluid wall solidifier and the temperature and pressure parameters of the drilling fluid, and judge the wellbore stability state in real time according to the improved Mohr-Coulomb criterion of the hydrate formation to achieve wellbore stability in the offshore hydrate reservoir drilling.

[0024] Preferably, after clarifying the regulation mechanism of the wall solidifier on the microstructure of the mud cake and the macroscopic mechanical properties of the reservoir, the concentration of the drilling fluid wall solidifier and the parameters such as the drilling fluid temperature and pressure are further adjusted dynamically, and the wellbore stability performance is evaluated in real time in combination with the multi-field coupling model of offshore natural gas hydrate drilling fluid-solid-heat-chemical. Based on the improved Mohr-Coulomb yield criterion and the wellbore yield expansion rate, the plastic yield range of the wellbore is quantified to achieve the optimization of the dynamic regulation scheme and the accurate judgment of the wellbore stability state. Wellbore yield expansion rate = plastic yield distance ∆ r / shaft radius r 0; The improved Mohr-Coulomb yield criterion of hydrate formations is embedded in the fluid-solid-heat-chemical multi-field coupling model of offshore natural gas hydrate drilling to determine the basis for wellbore stability: (twenty three) Where: t is the shear stress, MPa; s is the confining pressure, MPa; Under different stress states, the critical maximum principal stress expression of hydrate formation is: (twenty four) In the formula, s 1f is the critical maximum principal stress, s 3 is the minimum effective principal stress.

[0025] Calculation of the maximum effective principal stress from the reservoir stress distribution s 1: (25) In the formula, P mud is the wellbore drilling fluid pressure, MPa; P rock is the formation pore pressure, MPa; r 0 is the wellbore radius, m; r is the radial distance from the wellbore center, m.

[0026] Calculation of minimum effective principal stress from reservoir stress distribution s 3: (26) like s 1f > s 1, the formation in this area is in the stage of plastic deformation accumulation, and this point is the yield boundary. At this time, the radial distance from the center of the wellbore is ∆ r This is the plastic yield distance.

[0027] It can be seen from the Mohr-Coulomb yield criterion of the hydrate formation that the convective heat exchange between the wellbore and the reservoir under the action of the pressure difference causes the decomposition of hydrates in the near-wellbore zone, resulting in the degradation of the mechanical properties of the reservoir, that is, the reduction of the mechanical parameters around the wellbore, which makes the near-wellbore zone evolve from elastic strain to plastic yield, and the wellbore yield expansion rate (plastic yield distance ∆ r / shaft radius r 0) As hydrate decomposes, it gradually increases, causing wellbore instability.

[0028] The change of the concentration of the drilling fluid cementing agent can directly affect the porosity, permeability and mechanical strength of the mud cake. The mud cake parameters can be optimized by adding the cementing agent, thereby enhancing the plugging and bearing capacity of the near-wellbore area of ​​the reservoir. At the same time, the temperature and pressure parameters of the drilling fluid are changed to inhibit the hydrate decomposition rate and reduce the pressure difference between the wellbore and the reservoir, thereby reducing the range of plastic yield of the wellbore. Based on the multi-field coupling model of fluid-solid-heat-chemical drilling of offshore natural gas hydrates, combined with the temperature and pressure conditions of the reservoir and wellbore, the cementing agent concentration, the mud cake performance and other parameters, the wellbore yield expansion rate is calculated. When the yield expansion rate exceeds the set threshold (such as 0.3), the drilling fluid parameters (cementing agent concentration, drilling fluid temperature or pressure) are dynamically adjusted to quickly reduce the risk of wellbore instability and achieve wellbore stability in offshore hydrate drilling. The drilling fluid parameters include cementing agent concentration, drilling fluid temperature and drilling fluid pressure.

[0029] A method for coordinating the stabilization of the wellbore by using a wall-fixing agent and a temperature-pressure field for drilling fluid in marine hydrate drilling, comprising a data acquisition module, a data analysis module and a dynamic control module; the data acquisition module is used to collect key performance parameters of the hydrate reservoir, wellbore drilling fluid and wellbore mud cake; the data analysis module is used to execute the wall-fixing agent and the temperature-pressure field coordinated stabilization method, establish a fluid-solid-heat-chemical multi-field coupling model for offshore natural gas hydrate drilling, and calculate the wellbore yield expansion rate based on the improved Mohr-Coulomb yield criterion to quantify the wellbore stability state; the dynamic control module achieves precise control of the wellbore stability by adjusting the concentration of the drilling fluid wall-fixing agent and the temperature-pressure parameters of the drilling fluid, and provides theoretical support and technical guarantee for the prevention and dynamic control of wellbore instability during marine hydrate drilling.

[0030] The third aspect of the present invention provides a computer-readable storage medium having a program stored thereon, which, when executed by a processor, implements the steps in the method for stabilizing the well wall by coordinating a wall-fixing agent for drilling fluid for marine hydrate drilling with a temperature and pressure field as described above.

[0031] The fourth aspect of the present invention provides an electronic device, including a memory, a processor, and a program stored in the memory and executable on the processor. When the processor executes the program, the steps in the method for coordinating the well wall stabilization of a wall-solidifying agent and a temperature-pressure field for drilling fluid for marine hydrate drilling are implemented as described above.

[0032] The beneficial effects of the present invention are: The present invention establishes a multi-field coupling model of fluid-solid-heat-chemical for offshore natural gas hydrate drilling, comprehensively applies knowledge of rock elastoplastic mechanics, fluid mechanics, heat transfer and computational mathematics, combines the influence of drilling fluid wall solidifier concentration changes on mud cake performance, and the influence of wellbore-reservoir temperature and pressure conditions on wellbore mechanical parameters, and uses the improved Mohr-Coulomb yield criterion to accurately calculate the wellbore yield expansion rate and quantitatively evaluate the wellbore stability. By dynamically adjusting the amount of drilling fluid wall solidifier and temperature and pressure parameters, the wellbore stability is achieved, effectively solving the wellbore instability problem caused by hydrate decomposition, and providing a theoretical basis and technical support for the accurate judgment and dynamic regulation of wellbore stability in complex reservoirs of offshore natural gas hydrates. BRIEF DESCRIPTION OF THE DRAWINGS

[0033] The accompanying drawings are used to provide a further understanding of the present invention and constitute a part of the specification. Together with the embodiments of the present invention, they are used to explain the present invention and do not constitute a limitation of the present invention. In the accompanying drawings: Figure 1 A flow chart showing an embodiment of a method for stabilizing a well wall in coordination with a temperature and pressure field for a wall-fixing agent used in a drilling fluid for drilling marine hydrates according to the present invention; Figure 2 A schematic diagram showing horizontal well parameters and the effects of a wall-fixing agent in one embodiment of a method for coordinating a wall-fixing agent and a temperature-pressure field to stabilize a well wall for a marine hydrate drilling fluid of the present invention is shown; Figure 3 A graph showing the change of the yield area around the well over time in one embodiment of the method for stabilizing the well wall in coordination with the temperature and pressure field for the wall-fixing agent used in the drilling fluid for marine hydrate drilling of the present invention; Figure 4 A diagram showing the influence of the yield area on a wall-fixing agent according to an embodiment of a method for coordinating a wall-fixing agent and a temperature-pressure field to stabilize a wellbore for drilling fluid for marine hydrate drilling of the present invention is shown. DETAILED DESCRIPTION

[0034] The present invention will be further described below by way of embodiments in conjunction with the accompanying drawings, but is not limited thereto.

[0035] Embodiment 1: Take the drilling of hydrate reservoirs in a certain area as an example. Figure 1 As shown, a method for stabilizing the well wall by coordinating a wall solidifying agent and a temperature and pressure field for drilling fluid for marine hydrate drilling comprises the following steps: Step S1, obtaining current drilling parameters and natural gas hydrate reservoir physical property data, and establishing a wellbore-hydrate reservoir unsteady-state mass transfer and heat transfer model through a wellbore-hydrate reservoir unsteady-state heat transfer model, a hydrate reservoir multiphase seepage model, and a hydrate intrinsic decomposition kinetic model.

[0036] The unsteady-state heat transfer model of the wellbore-hydrate reservoir is calculated according to the following formula. According to the law of conservation of energy, the solid phase energy equation of the hydrate phase change is: (1) In the formula, ϕ wg is the limited porosity of gas-liquid flow in the hydrate reservoir, ϕ wg = ϕ ×(1- S h ), ϕ is the porosity of the sand body, S h is the saturation of hydrate; t is the time; is the density of the solid phase r and specific heat C The equivalent product of k eh is the equivalent thermal conductivity of the solid phase, and k eh It can be solved by weighting by volume fraction; T e is the solid phase temperature; ∆ E h is the heat of decomposition of the hydrate; h sf is the convective heat transfer coefficient between the solid phase and the fluid; A sf is the specific surface area in the porous medium; T f is the fluid temperature; is the decomposition rate of hydrate in porous media, which can be solved by the hydrate intrinsic decomposition kinetic model (KB model): (2) In the formula, M h is the molar mass of the hydrate, k d is the intrinsic reaction constant of hydrate, △ E is the hydrate activation energy, R is the gas constant, T is the thermodynamic temperature, A h is the hydrate phase change mass transfer specific surface area, p eq and p e They are the equilibrium pressure of hydrate under phase equilibrium temperature and pressure conditions and the pore pressure during the formation process, respectively.

[0037] The flow of fluid in porous media involves five forms of heat transfer, namely, energy migration caused by fluid flow, heat conduction inside the fluid, convective heat transfer on the interface between fluid and solid, Joule-Thomson effect of gas, and energy decomposition of water and gas, as shown in equation (3). The term on the left side of the equation represents the change in internal energy, and the term on the right side of the equation represents the five forms of heat transfer in turn.

[0038] (3) In the formula, k f is the thermal conductivity of the fluid; p is the fluid pressure; and are the rates of hydrate decomposition to produce free gas and water, respectively; C p,g and C p,w are the specific heat capacities of free gas and water at constant pressure respectively; S , r and v are saturation, density and flow velocity, respectively, and the subscripts g and w represent free gas and water, respectively; m JT is the Joule-Thomson effect coefficient.

[0039] In the local nonequilibrium heat transfer model, the fluid and solid energy control equations are often closed by constructing the interface convection heat transfer mode, which is expressed as: (4) In the formula, N u is the Nusselt number, d p is the average diameter of sand particles, R e is the Reynolds number, P r is the Prandtl number.

[0040] The multiphase seepage model of hydrate reservoir is calculated according to the following formula. According to the law of conservation of mass, the continuity equation of free gas, water and hydrate in porous media can be expressed as: (5) (6) (7) In the formula, k is the effective permeability of the hydrate reservoir, which is exponentially related to the hydrate saturation. k = k 0×(1- S h ) N, k 0 is the effective initial permeability of the hydrate reservoir, N is a permeability reduction index related to the pore size and structure of hydrate sediments; r h is the density of the hydrate; k rw and k rg are the relative permeabilities of water and gas phases, respectively; m w and m g are the viscosities of the water phase and the gas phase, respectively; p w and p g are the pressures of water phase and gas phase in the pores, respectively; the subscript h represents hydrate, S h is the hydrate saturation; , and Represent the mass change rates of water, gas and hydrate respectively; g is the gravitational acceleration, m / s 2 ; ɸ is the porosity.

[0041] Assuming that the density of water is constant within the reservoir pressure range, the continuity equation of the water phase is obtained after conversion: (8) In the formula, p c is the capillary force.

[0042] According to the gas state equation, the gas phase continuity equation is finally expressed as: (9) In the formula, M g is the molar mass of the gas; Z is the compressibility factor of the gas.

[0043] By coupling the unsteady-state heat transfer model of wellbore-hydrate reservoir, the multiphase seepage model of hydrate reservoir and the intrinsic decomposition kinetic model of hydrate, the unsteady-state mass and heat transfer model of wellbore-hydrate reservoir is established as follows: (10) Step S2: Considering the changes in reservoir mechanical parameters caused by hydrate phase change, formation creep and the interaction between drilling fluid and hydrate reservoir, the mud cake is embedded in the unsteady-state mass transfer and heat transfer model to construct a fluid-solid-heat-chemical multi-field coupling model for offshore natural gas hydrate drilling.

[0044] In the original state of the formation, hydrates, as effective cementing components of the formation, and the rock skeleton jointly support the overlying stress of the formation. When the hydrate decomposes, the phase change from solid to fluid will change the effective stress of the formation, thereby weakening the reservoir cementation strength and deteriorating the mechanical properties of the formation, which is very likely to cause formation instability and large-scale sand production. Considering the constantly changing mechanical properties of the hydrate reservoir, the elastic-plastic constitutive equation is used to describe the relationship between stress and strain. Its incremental form is as follows: (11) In the formula, d σij is the effective stress increment matrix; D ijkl is the elastic-plastic matrix tensor of the hydrate formation; d εkl is the reservoir skeleton strain increment matrix.

[0045] The static equilibrium equation can be expressed in the tensor form of effective stress as: (12) In the formula, s ij is the reservoir skeleton stress tensor, Represents the stress tensor in j Divergence in direction, α B is the Biot coefficient; d ij is the Kronecker function; F i For body load.

[0046] The relationship between displacement and strain can be expressed in tensor form as: (13) In the formula, e ij is the reservoir skeleton strain tensor, w is the strain displacement, is the strain displacement along the coordinate i The rate of change of direction, is the strain displacement along the coordinate j The rate of change of direction.

[0047] The changes in elastic modulus and internal friction angle caused by hydrate decomposition can also cause wellbore instability. The relationship between the formation internal friction angle and hydrate saturation is obtained by regression calculation based on the following formula: (14) In the formula, f is the internal friction angle of the hydrate reservoir.

[0048] The relationship between formation cohesion and hydrate saturation is obtained by regression calculation based on the following formula: (15) In the formula, C ( S h ) is the cohesive force, C 0 is S h =0 when the cohesion is α , β Both are empirical coefficients that characterize the cohesion of formations.

[0049] The relationship between the formation elastic modulus and hydrate saturation is obtained by regression calculation based on the following formula: (16) In the formula, E ( S h ) is the elastic modulus of the hydrate reservoir, E 0 is S h =0 elastic modulus.

[0050] During the drilling process, mud cake, as a key product of the interaction between the wellbore and the drilling fluid, plays an important role in the stability of the wellbore. On the one hand, the porosity and permeability of the mud cake determine its barrier effect on fluid penetration, which directly affects the risk of hydrate decomposition and wellbore damage; on the other hand, the mechanical strength of the mud cake is the microscopic basis for supporting the stability of the wellbore. Therefore, it is necessary to introduce the mud cake parameters into the multi-field coupling model to further explore the dynamic correlation between the mud cake and the mechanical properties of the reservoir, so as to achieve a global analysis of the wellbore stability.

[0051] The dynamic permeability of mud cake is calculated according to the following formula: (17) In the formula, l is the pore permeability attenuation index, K mc0 is the minimum permeability of mud cake, K f is the formation permeability.

[0052] The dynamic porosity of the mud cake is calculated according to the following formula: (18) In the formula, ϕ mc0 is the minimum porosity of the mud cake, ϕ f is the formation porosity.

[0053] Dynamic porosity and permeability are often interrelated. For example, a reduction in porosity (through compaction and consolidation) leads to a reduction in permeability. This interaction has a dual positive effect on the mechanical strength of the mud cake: a reduction in porosity increases the effective stress and enhances the mechanical strength; while a reduction in permeability reduces pore connectivity, enhances the cementation between particles, and further improves the mechanical strength. Therefore, the change in dynamic mechanical strength of the mud cake is calculated according to the following formula: (19) In the formula, s mc0 is the initial mechanical strength of the mud cake; m and n are the contribution constants of permeability and porosity to the mechanical strength of the mud cake.

[0054] By introducing the reservoir mechanical parameters (such as internal friction angle, cohesion and elastic modulus) and the changes in the porosity, permeability and dynamic mechanical strength parameters of the mud cake into the unsteady-state mass and heat transfer model of the wellbore-hydrate reservoir, the full coupling relationship between the thermal field, flow field and force field was established using the multi-physics field coupling software COMSOL; in the thermal field, the low porosity and low permeability of the mud cake change the heat transfer path near the wellbore by correcting the thermal conductivity and heat capacity of the local area of ​​the reservoir; in the flow field, the barrier effect of the mud cake affects the seepage behavior and pore pressure distribution of the fluid after hydrate decomposition through the dynamic correction of the effective permeability and porosity; in the force field, the dynamic mechanical strength of the mud cake, as an important source of wellbore support, works together with the changes in the reservoir mechanical parameters to affect the stress distribution around the wellbore and the evolution of the plastic zone. By comprehensively coupling the reservoir porosity, permeability, heat release caused by hydrate decomposition, fluid flow and mechanical evolution processes, a fluid-solid-heat-chemical multi-field coupling model integrating mass transfer, heat transfer, mechanical behavior and chemical reaction was finally formed, providing a theoretical basis for studying the mechanism of wellbore instability and stability regulation during offshore natural gas hydrate drilling.

[0055] Step S3, designing a marine hydrate drilling fluid system, adding different amounts of wall-fixing agents to the drilling fluid, analyzing the dynamic evolution of key parameters such as mud cake porosity, permeability, and mechanical strength, and clarifying the influence mechanism of the drilling fluid wall-fixing agent on the mechanical properties of the reservoir.

[0056] Obtain the existing conventional marine hydrate drilling fluid wall solidifier (the wall solidifier in this example is produced by Beijing Conojie Energy Environmental Protection Technology Co., Ltd.), and systematically construct a high-performance marine hydrate drilling fluid system with both wellbore stability and reservoir protection by adding lubricants, inhibitors, viscosity-enhancing coating agents, viscosity-enhancing agents, glass microbeads, fluid loss reducers, and reservoir bridging agents. By changing the concentration of the wall solidifier in the drilling fluid, the mechanism of the influence of the drilling fluid wall solidifier on the mechanical properties of the reservoir is clarified.

[0057] The system constructed in this embodiment is: seawater + 0.1% NaOH + 7% NaCl + 3% CaCl2 + 3% BLWZ (glass beads) + 2% PF-FLOTROL (fluid loss reducer) + 0.1% PF-XC (xanthan gum) + 2% PF-EZCARB (reservoir bridging agent) + 1% wall solidifier + 0.1% PF-PLUS (viscosity enhancing coating agent) + 3% PF-UHIB (polyamine) + 2% PF-HLUB (mud bag lubricant) + 2% PF-LUBE (lubricant) + 1% SYZ-2 (hydrate formation inhibitor).

[0058] Determine the density and rheological parameters of the drilling fluid and conduct an API filtration test. Pour the drilling fluid into the filtration tester, install filter paper or filter membrane, turn on the equipment, and run it for 30 minutes under the set conditions. For example, record the cumulative filtrate volume 𝑉 every 1 minute to calculate the filtration loss. Turn off the equipment, slowly release the pressure, remove the mud cake, use a thickness gauge to measure the thickness at multiple points on the mud cake, and take the average value. L .

[0059] Place the mud cake in an oven, set the temperature (e.g. 60°C), dry it to constant weight, and then use the density method to determine the porosity of the mud cake, that is, measure the dry weight of the mud cake ( m d ) and volume ( V ), calculate the dry density of the mud cake ( r d = m d / V ), through the density of the bentonite used in the slurry ( r s ), calculate the porosity for: (20) In the filtration test, the drilling fluid forms a mud cake through the filter paper or filter membrane under a certain pressure difference, and the filtrate flows out through the mud cake. The flow of the filtrate and the formation of the mud cake conform to Darcy's law and filtration theory. The permeability of the mud cake affects the passing speed of the filtrate. Conversely, the change of the filtrate volume over time also reflects the permeability characteristics of the mud cake.

[0060] Calculate the permeability of mud cake based on filtration theory and Darcy's law K for: (twenty one) Where: V is the volume of the filtrate, cm³; m is the plastic viscosity of drilling fluid, Pa·s; L is the mud cake thickness, m; t is the experimental time, s; A is the filter paper area, m 2; Δ P is the pressure difference, Pa.

[0061] The mechanical strength of the mud cake is measured using the FCP Mud Cake Penetration Tester, which can accurately measure its compressive strength and other mechanical properties while maintaining the integrity of the mud cake. Install the mud cake sample to be tested on the test bench of the FCP instrument, ensure that the needle is vertically aligned with the sample surface, select the appropriate load range and calibrate the instrument according to the experimental requirements to ensure measurement accuracy. After starting the instrument, slowly apply the preset load and record the relationship curve between the needle penetration depth and the applied force. To improve the reliability of the data, each measurement point is tested at least three times and the average value is taken. Finally, the compressive strength of the mud cake is calculated by analyzing the load-needle penetration depth curve.

[0062] The compressive strength reflects the bearing capacity of the mud cake under axial pressure. A higher compressive strength indicates that the mud cake forms a solid barrier on the well wall, which helps prevent accidents such as well collapse and well kick. s c The calculation formula is: (twenty two) Where: F max is the maximum load value applied, N; r is the needle radius, m.

[0063] The concentration of the wall-fixing agent in the drilling fluid was adjusted, and the filtration test, porosity determination, permeability test and mechanical strength measurement were carried out under the same experimental conditions. By combining the experimental data with the reservoir mechanics theory and the fluid-solid-heat-chemical multi-field coupling model of offshore natural gas hydrate drilling, the dynamic evolution of mud cake porosity, permeability and mechanical strength was systematically analyzed to reveal how the wall-fixing agent affects the macroscopic mechanical properties of the reservoir by regulating the microstructural parameters of the mud cake during the process of optimizing the drilling fluid formula, so as to clarify the influence mechanism of the wall-fixing agent on the mechanical properties of the reservoir. The experimental and calculation results are shown in Table 1.

[0064] Table 1 Experimental calculation results G` and G`` are two values ​​(initial cutting value and final cutting value) of the experiment for measuring the viscosity of drilling fluid.

[0065] Step S4, dynamically adjust the amount of drilling fluid wall solidifier and the temperature and pressure parameters of the drilling fluid, and judge the wellbore stability state in real time according to the improved Mohr-Coulomb criterion of the hydrate formation to achieve wellbore stability in the offshore hydrate reservoir drilling.

[0066] After clarifying the regulation mechanism of the wall solidifier on the microstructure of the mud cake and the macroscopic mechanical properties of the reservoir, the concentration of the drilling fluid wall solidifier and the parameters such as the drilling fluid temperature and pressure were further adjusted dynamically, and the wellbore stability performance was evaluated in real time in combination with the multi-field coupling model of offshore natural gas hydrate drilling. r / shaft radius r 0), quantify the plastic yield range of the wellbore to optimize the dynamic control scheme and accurately judge the stability of the wellbore.

[0067] The improved Mohr-Coulomb yield criterion of hydrate formations is embedded in the fluid-solid-heat-chemical multi-field coupling model of offshore natural gas hydrate drilling to determine the basis for wellbore stability: (twenty three) Where: t is the shear stress, MPa; s is the confining pressure, MPa; Under different stress states, the critical maximum principal stress expression of hydrate formation is: (twenty four) In the formula, s 1f is the critical maximum principal stress, s 3 is the minimum effective principal stress.

[0068] Calculation of the maximum effective principal stress from the reservoir stress distribution s 1: (25) In the formula, P mud is the wellbore drilling fluid pressure, MPa; P rock is the formation pore pressure, MPa; r 0 is the wellbore radius, m; r is the radial distance from the wellbore center, m.

[0069] Calculation of minimum effective principal stress from reservoir stress distribution s 3: (26) like s 1f > s 1, the formation in this area is in the stage of plastic deformation accumulation, and this point is the yield boundary. At this time, the radial distance from the center of the wellbore is ∆ r This is the plastic yield distance.

[0070] It can be seen from the Mohr-Coulomb yield criterion of the hydrate formation that the convective heat exchange between the wellbore and the reservoir under the action of the pressure difference causes the decomposition of hydrates in the near-wellbore zone, resulting in the degradation of the mechanical properties of the reservoir, that is, the reduction of the mechanical parameters around the wellbore, which makes the near-wellbore zone evolve from elastic strain to plastic yield, and the wellbore yield expansion rate (plastic yield distance ∆ r / shaft radius r 0) As hydrate decomposes, it gradually increases, causing wellbore instability.

[0071] Depend on Figure 2 It can be seen that the change of the concentration of the drilling fluid wall-fixing agent can directly affect the porosity, permeability and mechanical strength of the mud cake. The mud cake parameters can be optimized by adding the wall-fixing agent, thereby enhancing the plugging and bearing capacity of the near-wellbore area of ​​the reservoir. At the same time, the temperature and pressure parameters of the drilling fluid are changed to inhibit the hydrate decomposition rate and reduce the pressure difference between the wellbore and the reservoir, thereby reducing the range of plastic yield of the wellbore wall.

[0072] Based on the multi-field coupling model of fluid-solid-heat-chemical in offshore natural gas hydrate drilling, combined with reservoir and wellbore temperature and pressure conditions, wall-fixing agent concentration, mud cake performance and other parameters, the wellbore yield expansion rate is calculated. When the yield expansion rate exceeds the set threshold (such as 0.3), the risk of wellbore instability is quickly reduced by dynamically adjusting the drilling fluid parameters (wall-fixing agent concentration, drilling fluid temperature or pressure), thereby achieving wellbore stability in offshore hydrate drilling.

[0073] In this embodiment, if Figure 3 As shown in the figure, the yellow area is the unyielded area, and the blue area is the yielded area. When there is no wall cementing agent in the drilling fluid system, the formation does not plastically yield in the early stage of drilling fluid invasion (within 1 hour), and the hydrate saturation changes slightly. However, with the continuous invasion of the drilling fluid, the temperature and pressure disturbance range of the formation around the wellbore gradually expands, the hydrate continues to decompose, the formation cementation capacity gradually decreases, the reservoir begins to yield and the area continues to expand. After 20 hours, the wellbore yield expansion rate reached 90%, seriously endangering the well control safety of drilling. Figure 4 As shown in the figure, the increase of the concentration of the wall solidifier in the drilling fluid system can reduce the yield expansion rate of the wellbore and reduce the risk of wellbore instability. Of course, the final concentration addition still needs to consider the influence of the rheological loss performance parameters of the drilling fluid.

[0074] In summary, by fully considering the influence of drilling fluid system and performance parameters on wellbore mud cake, the established fluid-solid-heat-chemical multi-field coupling model for offshore natural gas hydrate drilling is more in line with reality, and the accurate judgment and dynamic control plan of wellbore stability in deepwater complex formations can be completed, which provides strong help for the flexible design of high-performance drilling fluid system and performance parameters on site.

[0075] Example 2 A method for coordinating the stabilization of the wellbore by using a wall-fixing agent and a temperature-pressure field for drilling fluid in marine hydrate drilling, comprising a data acquisition module, a data analysis module and a dynamic control module; the data acquisition module is used to collect key performance parameters of the hydrate reservoir, wellbore drilling fluid and wellbore mud cake; the data analysis module is used to execute the wall-fixing agent and the temperature-pressure field coordinated stabilization method, establish a fluid-solid-heat-chemical multi-field coupling model for offshore natural gas hydrate drilling, and calculate the wellbore yield expansion rate based on the improved Mohr-Coulomb yield criterion to quantify the wellbore stability state; the dynamic control module achieves precise control of the wellbore stability by adjusting the concentration of the drilling fluid wall-fixing agent and the temperature-pressure parameters of the drilling fluid, and provides theoretical support and technical guarantee for the prevention and dynamic control of wellbore instability during marine hydrate drilling.

[0076] Example 3 A computer-readable storage medium having a program stored thereon, which, when executed by a processor, implements the steps in a method for coordinating the wellbore stabilization of a wall-solidifying agent and a temperature-pressure field for a marine hydrate drilling fluid as described in Example 1.

[0077] Example 4 An electronic device comprises a memory, a processor and a program stored in the memory and executable on the processor, wherein when the processor executes the program, the steps in the method for cooperating with a wall-solidifying agent and a temperature-pressure field to stabilize the well wall for drilling fluid for marine hydrate drilling as described in Example 1 are implemented.

[0078] The above embodiments are merely illustrative of the principles and effects of the present invention, and are not intended to limit the present invention. Anyone familiar with the art may modify or alter the above embodiments without departing from the spirit and scope of the present invention. Therefore, all equivalent modifications or alterations made by a person of ordinary skill in the art without departing from the spirit and technical concept disclosed by the present invention shall still be covered by the claims of the present invention.

Claims

1. A method for stabilizing the well wall by using a wall-fixing agent for drilling fluid for marine hydrate drilling and a temperature and pressure field, characterized in that: The following steps are involved: Step S1, obtaining current drilling parameters and natural gas hydrate reservoir physical property data, and establishing a wellbore-hydrate reservoir unsteady-state mass transfer and heat transfer model through a wellbore-hydrate reservoir unsteady-state heat transfer model, a hydrate reservoir multiphase seepage model, and a hydrate intrinsic decomposition kinetic model; Step S2, considering the changes in reservoir mechanical parameters caused by hydrate phase change, formation creep and the interaction between drilling fluid and hydrate reservoir, embedding the mud cake into the unsteady mass transfer and heat transfer model, and constructing a fluid-solid-heat-chemical multi-field coupling model for offshore natural gas hydrate drilling; Step S3, designing a marine hydrate drilling fluid system, adding different amounts of a wall-fixing agent to the drilling fluid, analyzing the dynamic evolution of the mud cake porosity, permeability, and mechanical strength, and explaining the influence mechanism of the drilling fluid wall-fixing agent on the mechanical properties of the reservoir; Step S4, dynamically adjust the amount of drilling fluid wall solidifier and the temperature and pressure parameters of the drilling fluid, and judge the wellbore stability state in real time according to the improved Mohr-Coulomb criterion of the hydrate formation to achieve wellbore stability in the offshore hydrate reservoir drilling.

2. The method for stabilizing the well wall by using a wall-fixing agent for drilling fluid for marine hydrate drilling and a temperature-pressure field in coordination with each other according to claim 1, characterized in that: In step S1, the unsteady-state heat transfer model of the wellbore-hydrate reservoir is calculated according to the following formula. According to the law of conservation of energy, the solid phase energy equation of the hydrate phase change is: （1） In the formula, ϕ wg is the limited porosity of gas-liquid flow in the hydrate reservoir, ϕ wg = ϕ ×(1- S h ), ϕ is the porosity of the sand body, S h is the saturation of hydrate; t is the time; is the density of the solid phase ρ and specific heat C The equivalent product of k eh is the equivalent thermal conductivity of the solid phase, and k eh Solve by weighting by volume fraction; T e is the solid phase temperature; ∆ E h is the heat of decomposition of the hydrate; h sf is the convective heat transfer coefficient between the solid phase and the fluid; A sf is the specific surface area in the porous medium; T f is the fluid temperature; is the decomposition rate of hydrate in porous media, and the intrinsic decomposition kinetic model of hydrate is used to solve it: （2） In the formula, M h is the molar mass of the hydrate, k d is the intrinsic reaction constant of hydrate, △ E is the hydrate activation energy, R is the gas constant, T is the thermodynamic temperature, A h is the hydrate phase change mass transfer specific surface area, p eq and p e are the equilibrium pressure of hydrate under the phase equilibrium temperature and pressure conditions and the pore pressure during the formation process; The flow of fluid in porous media involves five forms of heat transfer, namely, energy migration caused by fluid flow, heat conduction inside the fluid, convective heat transfer on the interface between fluid and solid, Joule-Thomson effect of gas, and energy decomposition of water and gas, as shown in equation (3). The term on the left side of the equation represents the change in internal energy, and the term on the right side of the equation represents the five forms of heat transfer in turn. （3） In the formula, k f is the thermal conductivity of the fluid; p is the fluid pressure; and are the rates of hydrate decomposition to produce free gas and water, respectively; C p,g and C p,w are the specific heat capacities of free gas and water at constant pressure respectively; S , ρ and v are saturation, density and flow velocity, respectively, and the subscripts g and w represent free gas and water, respectively; μ JT is the Joule-Thomson effect coefficient; In the local non-equilibrium heat transfer process, the interface convection heat transfer mode is constructed to close the fluid and solid energy control equations, which are expressed as follows: （4） In the formula, N u is the Nusselt number, d p is the average diameter of sand particles, R e is the Reynolds number, P r is the Prandtl number.

3. The method for stabilizing the well wall by using a wall-fixing agent for drilling fluid for marine hydrate drilling and a temperature-pressure field in coordination with each other according to claim 2, characterized in that: In step S1, the multiphase seepage model of the hydrate reservoir is calculated according to the following formula. According to the law of conservation of mass, the continuity equation of free gas, water and hydrate in the porous medium can be expressed as: （5） （6） （7） In the formula, k is the effective permeability of the hydrate reservoir, which is exponentially related to the hydrate saturation. k = k 0×(1- S h ) N , k 0 is the effective initial permeability of the hydrate reservoir, N is a permeability reduction index related to the pore size and structure of hydrate sediments; ρ h is the density of the hydrate; k rw and k rg are the relative permeabilities of water and gas phases, respectively; μ w and μ g are the viscosities of the water phase and the gas phase, respectively; p w and p g are the pressures of water phase and gas phase in the pores, respectively; the subscript h represents hydrate, S h is the hydrate saturation; , and Represent the mass change rates of water, gas and hydrate respectively; g is the gravitational acceleration, m / s 2 ; ɸ is the porosity; Assuming that the density of water is constant within the reservoir pressure range, the continuity equation of the water phase after conversion is: （8） In the formula, p c is the capillary force; According to the gas state equation, the gas phase continuity equation is finally expressed as: （9） In the formula, M g is the molar mass of the gas; Z is the compressibility factor of the gas; By coupling the unsteady-state heat transfer model of wellbore-hydrate reservoir, the multiphase seepage model of hydrate reservoir and the intrinsic decomposition kinetic model of hydrate, the unsteady-state mass and heat transfer model of wellbore-hydrate reservoir is established as follows: （10）。 4. The method for stabilizing the well wall by using a wall-fixing agent for drilling fluid for marine hydrate drilling and a temperature-pressure field in coordination with each other according to claim 1, characterized in that: In step S2, considering the changing mechanical properties of the hydrate reservoir, the elastic-plastic constitutive equation is used to describe the relationship between stress and strain, and its incremental form is as follows: （11） In the formula, d σij is the effective stress increment matrix; D ijkl is the elastic-plastic matrix tensor of the hydrate formation; d εkl is the reservoir skeleton strain increment matrix; The static equilibrium equation is expressed in the tensor form of effective stress as: （12） In the formula, σ ij is the reservoir skeleton stress tensor, Represents the stress tensor in j Divergence in direction, α B is the Biot coefficient; δ ij is the Kronecker function; F i is the body load; The relationship between displacement and strain can be expressed in tensor form as: （13） In the formula, ε ij is the reservoir skeleton strain tensor, w is the strain displacement, is the strain displacement along the coordinate i The rate of change of direction, is the strain displacement along the coordinate j rate of change of direction; The relationship between the internal friction angle of the formation and the hydrate saturation is obtained by regression calculation based on the following formula: （14） In the formula, φ is the internal friction angle of the hydrate reservoir; The relationship between formation cohesion and hydrate saturation is obtained by regression calculation based on the following formula: （15） In the formula, C ( S h ) is the cohesive force, C 0 is S h =0 when the cohesion is α , β All are empirical coefficients that characterize the cohesion of formations; The relationship between the formation elastic modulus and hydrate saturation is obtained by regression calculation based on the following formula: （16） In the formula, E ( S h ) is the elastic modulus of the hydrate reservoir, E 0 is S h =0 when the elastic modulus; The dynamic permeability of mud cake is calculated according to the following formula: （17） In the formula, λ is the porosity attenuation index, K mc0 is the minimum permeability of mud cake, K f is the formation permeability; The dynamic porosity of the mud cake is calculated according to the following formula: （18） In the formula, ϕ mc0 is the minimum porosity of the mud cake, ϕ f is the formation porosity; The dynamic mechanical strength change of the mud cake is calculated according to the following formula: （19） In the formula, σ mc0 is the initial mechanical strength of the mud cake; m and n are the contribution constants of permeability and porosity to the mechanical strength of the mud cake; By introducing the internal friction angle, cohesion and elastic modulus as well as the changes in the porosity, permeability and dynamic mechanical strength of the mud cake into the unsteady-state mass and heat transfer model of the wellbore-hydrate reservoir, the full coupling relationship between the thermal field, flow field and force field is established using the multi-physics field coupling software COMSOL.

5. The method for stabilizing the well wall by using a wall-fixing agent for marine hydrate drilling fluid and a temperature-pressure field in coordination with each other according to claim 1, characterized in that: In step S3, obtain the existing conventional marine hydrate drilling fluid wall solidifying agent, add lubricant, inhibitor, viscosity enhancing coating agent, viscosity enhancer, glass beads, fluid loss reducer, reservoir bridging agent, systematically construct the marine hydrate drilling fluid system, measure the drilling fluid density and rheological parameters and conduct API fluid loss test, pour the drilling fluid into the fluid loss meter, install filter paper or filter membrane, start the equipment, maintain the set conditions for 30 minutes, such as recording the cumulative filtrate volume 𝑉 every 1 minute, and calculate the fluid loss; turn off the equipment, release the pressure, take out the mud cake, use a thickness gauge to measure the thickness at multiple points of the mud cake, and take the average value L ; Place the mud cake in an oven, set the temperature, dry it to constant weight, and then use the density method to determine the porosity of the mud cake, that is, measure the dry weight of the mud cake. m d and volume V , calculate the dry density of the mud cake ρ d = m d / V , through the density of bentonite in the slurry ρ s , calculate the porosity for: （20） Calculate the permeability of mud cake based on filtration theory and Darcy's law K for: （21） Where: V is the volume of the filtrate, cm³; μ is the plastic viscosity of drilling fluid, Pa·s; L is the mud cake thickness, m; t is the experimental time, s; A is the filter paper area, m 2 ; Δ P is the pressure difference, Pa; Use the FCP mud cake needle penetration instrument to measure the mechanical strength of the mud cake. Install the mud cake sample to be tested on the test bench of the FCP instrument, ensure that the needle is vertically aligned with the sample surface, select the load range and calibrate the instrument according to the experimental requirements, start the instrument, apply the preset load, and record the relationship curve between the needle penetration depth and the applied force; finally, calculate the compressive strength of the mud cake by analyzing the load-needle penetration depth curve; Compressive strength of mud cake σ c The calculation formula is: （22） Where: F max is the maximum load value applied, N; r is the needle radius, m; The concentration of the wall-fixing agent in the drilling fluid was adjusted, and filtration experiments, porosity determination, permeability tests and mechanical strength measurements were carried out under the same experimental conditions. By combining the experimental data with the reservoir mechanics theory and the fluid-solid-heat-chemical multi-field coupling model of offshore natural gas hydrate drilling, the dynamic evolution laws of the mud cake porosity, permeability and mechanical strength were systematically obtained, revealing how the wall-fixing agent affects the macroscopic mechanical properties of the reservoir by regulating the microstructural parameters of the mud cake during the optimization of the drilling fluid formula.

6. The method for stabilizing the well wall by using a wall-fixing agent for marine hydrate drilling fluid and a temperature-pressure field in coordination with each other according to claim 5, characterized in that: In step S3, when the mechanical strength of the mud cake is measured using the FCP mud cake penetrometer, each measuring point is tested at least three times and the average value is taken.

7. The method for stabilizing the well wall by using a wall-fixing agent for marine hydrate drilling fluid and a temperature-pressure field in coordination with each other according to claim 1, characterized in that: In step S4, the plastic yield range of the wellbore is quantified based on the improved Mohr-Coulomb yield criterion and the wellbore yield expansion rate. The wellbore yield expansion rate = plastic yield distance ∆ r / shaft radius r 0; The improved Mohr-Coulomb yield criterion of hydrate formations is embedded in the fluid-solid-heat-chemical multi-field coupling model of offshore natural gas hydrate drilling to determine the basis for wellbore stability: （23） Where: τ is the shear stress, MPa; σ is the confining pressure, MPa; Under different stress states, the critical maximum principal stress expression of hydrate formation is: （24） In the formula, σ 1f is the critical maximum principal stress, σ 3 is the minimum effective principal stress; Calculation of the maximum effective principal stress from the reservoir stress distribution σ 1: （25） In the formula, P mud is the wellbore drilling fluid pressure, MPa; P rock is the formation pore pressure, MPa; r 0 is the wellbore radius, m; r is the radial distance from the wellbore center, m; Calculation of minimum effective principal stress from reservoir stress distribution σ 3: （26） like σ 1f > σ 1, the formation in this area is in the stage of plastic deformation accumulation, and this point is the yield boundary. At this time, the radial distance from the center of the wellbore is ∆ r It is the plastic yield distance; According to the Mohr-Coulomb yield criterion of hydrate formations, the convective heat exchange between the wellbore and the reservoir under the action of the pressure difference causes the decomposition of hydrates in the near-wellbore area, resulting in the deterioration of the mechanical properties of the reservoir, that is, the reduction of the mechanical parameters around the wellbore, which makes the near-wellbore area evolve from elastic strain to plastic yield, and the wellbore yield expansion rate increases with the decomposition of hydrates, causing the wellbore instability; The mud cake parameters are optimized by adding the amount of cementing agent, thereby enhancing the plugging and bearing capacity of the near-wellbore area of ​​the reservoir; at the same time, the temperature and pressure parameters of the drilling fluid are changed to inhibit the hydrate decomposition rate and reduce the pressure difference between the wellbore and the reservoir, thereby reducing the range of plastic yield of the wellbore wall; based on the fluid-solid-heat-chemical multi-field coupling model of offshore natural gas hydrate drilling, combined with the temperature and pressure conditions of the reservoir and wellbore, the concentration of the cementing agent, and the mud cake performance parameters, the wellbore yield expansion rate is calculated. When the yield expansion rate exceeds the set threshold, the risk of wellbore instability is quickly reduced by dynamically adjusting the drilling fluid parameters, thereby achieving wellbore stability in offshore hydrate drilling. The drilling fluid parameters include cementing agent concentration, drilling fluid temperature, and drilling fluid pressure.

8. A system for stabilizing the well wall by using a wall solidifying agent and a temperature and pressure field for drilling fluid for marine hydrate drilling, characterized in that: It includes a data acquisition module, a data analysis module and a dynamic control module; the data acquisition module is used to collect key performance parameters of hydrate reservoirs, wellbore drilling fluid and wellbore mud cake; the data analysis module is used to execute the coordinated stabilization method of wall solidifier and temperature and pressure field, establish a multi-field coupling model of fluid-solid-heat-chemical for offshore natural gas hydrate drilling, and calculate the wellbore yield expansion rate based on the improved Mohr-Coulomb yield criterion to quantify the wellbore stability; the dynamic control module realizes the control of wellbore stability by adjusting the concentration of drilling fluid wall solidifier and the temperature and pressure parameters of drilling fluid.

9. A computer-readable storage medium, characterized in that: A program is stored thereon, and when the program is executed by the processor, the steps in the method for coordinating the well wall stabilization with a wall-fixing agent and a temperature-pressure field for drilling fluid for marine hydrate drilling as described in any one of claims 1 to 7 are implemented.

10. An electronic device comprising a memory, a processor, and a program stored in the memory and executable on the processor, wherein when the processor executes the program, the steps in the method for stabilizing the well wall by coordinating a wall-solidifying agent and a temperature-pressure field for drilling fluid for marine hydrate drilling are implemented as claimed in any one of claims 1 to 7.

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