Marine natural gas hydrate multi-gas commingling production drilling well shaft temperature field calculation method

Abstract

The invention discloses a marine natural gas hydrate multi-gas commingling production drilling shaft temperature field calculation method which comprises the following steps: S1, establishing a marine natural gas hydrate multi-gas commingling production drilling shaft temperature model according to the law of conservation of energy; s2, on the basis of the marine natural gas hydrate multi-gas commingling well drilling shaft temperature model, an energy conservation equation of an infinitesimal body of each area in a shaft is analyzed by utilizing the energy conservation law, the heat transfer theory basic theory and the fluid mechanics basic theory, and a marine natural gas hydrate multi-gas commingling well drilling shaft temperature field calculation method is obtained; the infinitesimal body includes one or more of a drill string internal fluid, a drill string, an annulus internal fluid, a casing, a cement sheath, and a wellbore surrounding formation. The temperature distribution mathematical model in the shaft circulation period is established, and the temperature of the marine natural gas hydrate multi-gas commingling well drilling shaft can be accurately calculated.

Description

Technical Field

[0001] This invention relates to the field of drilling technology for multi-gas combined production of marine natural gas hydrates, and in particular to a method for calculating the wellbore temperature field in drilling for multi-gas combined production of marine natural gas hydrates. Background Technology

[0002] Drilling for multi-gas co-production of marine natural gas hydrates is more challenging than onshore drilling. Existing research has confirmed that the formation mechanisms of marine hydrates, shallow gas, and deep oil and gas are interconnected, with most exhibiting regional symbiosis and spatial coexistence, primarily manifested in their three-dimensional vertical distribution. Given the occurrence characteristics and economic viability of marine hydrates, commercializing hydrate extraction in isolation is difficult. Therefore, leveraging existing offshore oil and gas development platforms to conduct integrated exploration and three-dimensional development of multiple natural gas resources, including marine hydrates, shallow gas, and deep gas, represents a promising direction for the industrialization of marine hydrate development.

[0003] The variable marine environment, complex wave loads, hydrate formation and decomposition, and deep, high-temperature, high-pressure gas layers all pose higher technical requirements for the combined extraction of gas from marine hydrates. The environmental temperature changes drastically between offshore and onshore drilling; seawater temperatures continuously decrease, while formation temperatures continuously rise. Therefore, offshore drilling differs significantly from onshore drilling in aspects such as drilling fluid selection, cementing method determination, and drilling tool selection. When drilling through hydrate layers, changes in the external environment can easily trigger the decomposition of natural gas hydrates, leading to gas production. Hydrate decomposition also reduces the cohesiveness between formation particles, causing rapid changes in seabed formation pressure, resulting in structural damage and severe deformation of the formation. The decomposition gas from hydrates also leads to a sharp increase in the content of hazardous gases in the drilling area, posing a significant threat to the marine environment.

[0004] Therefore, to safely and smoothly implement the design for multi-gas combined production drilling of marine natural gas hydrates, we need a more detailed understanding of various data during the drilling process. Among them, wellbore temperature is one of the most important parameters in the drilling process. Understanding the temperature changes during drilling is of great significance for safe and efficient multi-gas combined production drilling of marine natural gas hydrates. However, current technology lacks a method for accurately calculating the wellbore temperature of marine natural gas hydrates. Summary of the Invention

[0005] The purpose of this invention is to provide a method for calculating the temperature field of the wellbore in marine natural gas hydrate multi-gas combined production drilling, so as to solve the technical problem of how to accurately calculate the temperature of marine drilling wellbore.

[0006] This invention is achieved using the following technical solution: a method for calculating the wellbore temperature field in marine natural gas hydrate multi-gas combined production drilling, comprising the following steps: S1: Based on the law of conservation of energy, establish a wellbore temperature model for multi-gas combined production of marine natural gas hydrates; S2: Based on the wellbore temperature model of marine multi-gas combined production drilling of marine natural gas hydrate, and using the law of conservation of energy, the basic theory of heat transfer and the basic theory of fluid mechanics, the energy conservation equation of the micro-element in each region of the wellbore is analyzed, and the calculation method of the wellbore temperature field of marine multi-gas combined production drilling is obtained. The micro-element includes one or more of the following: fluid inside the drill string, drill string, fluid inside the annulus, casing, cement sheath, and formation surrounding the wellbore.

[0007] Furthermore, the wellbore temperature model for multi-gas combined production drilling of marine natural gas hydrates sets the actual marine drilling process as a complete system. This actual process involves drilling fluid being pumped into the wellbore, circulating through the drill bit and out of the wellbore annulus. The system satisfies the following equations: ; In the formula, Energy entering the system; The total work done by the external system; This represents the total amount of change in the system.

[0008] Furthermore, the method for calculating the wellbore temperature field in multi-gas combined production wells for marine natural gas hydrates includes a method for calculating the temperature change of drilling fluid within the drill string: ; In the formula, This represents the power of the heat source within the drill string per unit length. Density of drilling fluid; Specific heat capacity of drilling fluid; This refers to the temperature of the drilling fluid inside the drill string. This refers to the temperature of the drill string's inner wall. The convective heat transfer coefficient of the inner surface of the drill string; This refers to the drilling fluid discharge rate; This is the inner diameter of the drill string.

[0009] Furthermore, the method for calculating the wellbore temperature field in marine natural gas hydrate multi-gas combined production drilling includes a method for calculating the temperature change of the drill string within the wellbore: ; In the formula, The density of the drill string; This refers to the specific heat capacity of the drill string; The thermal conductivity of the drill string; This refers to the temperature of the drilling fluid inside the drill string. This refers to the temperature of the drill string's inner wall. The annular fluid temperature; The convective heat transfer coefficient of the drill string surface; This is the outer diameter of the drill string.

[0010] Furthermore, the method for calculating the wellbore temperature field in marine natural gas hydrate multi-gas combined production wells includes a method for calculating the temperature change of the fluid within the wellbore annulus: ; In the formula, The fluid density within the wellbore annulus; The specific heat capacity of the fluid inside the wellbore annulus; The annular fluid temperature; This refers to the temperature of the inner wall of the wellbore. The convective heat transfer coefficient of the wellbore inner wall; This refers to the fluid discharge rate within the wellbore annulus. The work done by the external environment on the annular fluid; This refers to the inner diameter of the wellbore.

[0011] Furthermore, the method for calculating the wellbore temperature field in marine natural gas hydrate multi-gas combined production drilling includes a method for calculating the temperature change of the riser: ; In the formula, Density of the riser pipe; The specific heat capacity of the riser pipe; The thermal conductivity of the riser pipe; Temperature of the riser pipe; Seawater temperature; The convective heat transfer coefficient of the inner wall of the riser pipe; The convective heat transfer coefficient of the outer surface of the riser tube; This refers to the outer diameter of the riser pipe.

[0012] Furthermore, the method for calculating the wellbore temperature field in marine natural gas hydrate multi-gas combined production drilling includes a method for calculating the temperature change of the casing: ; In the formula, For casing density; The specific heat capacity of the casing; The thermal conductivity of the sleeve; The combined thermal conductivity of the sleeve and cement ring; For the sleeve temperature; Temperature of the cement ring; The convective heat transfer coefficient of the inner wall of the casing; The inner diameter of the casing; This refers to the outer diameter of the casing.

[0013] Furthermore, the method for calculating the wellbore temperature field in marine natural gas hydrate multi-gas combined production drilling includes a method for calculating the temperature of the cement sheath: ; In the formula, Density of cement rings; The relative heat capacity of cement; The thermal conductivity of the cement ring; Temperature of the cement ring; This refers to the outer diameter of the cement ring.

[0014] Furthermore, the method for calculating the wellbore temperature field in marine natural gas hydrate multi-gas combined production wells includes a method for calculating formation temperature changes: ; In the formula, Formation density; Specific heat capacity of the formation; The thermal conductivity of the formation; This refers to the formation temperature.

[0015] The beneficial effects of this invention are as follows: Based on the actual drilling conditions and wellbore structure at the marine site, this invention utilizes the law of conservation of energy, combines the heat transfer mode and energy changes of each heat transfer micro-element in the wellbore, and considers changes in marine temperature, the influence of heat source terms, and changes in thermophysical parameters to establish a mathematical model of temperature distribution during wellbore circulation. This model can accurately calculate the temperature of the wellbore in marine natural gas hydrate multi-gas combined production drilling. Attached Figure Description

[0016] To more clearly illustrate the technical solutions in the embodiments of the present invention or the prior art, the drawings used in the description of the embodiments or the prior art will be briefly introduced below. Obviously, the drawings described below are only some embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on the structures shown in these drawings without creative effort.

[0017] Figure 1 Schematic diagram of a wellbore temperature model for hydrate formations in marine drilling; Figure 2 A schematic diagram of heat transfer in the drilling fluid micro-element within the drill string; Figure 3 This is a schematic diagram of heat transfer in a drill string micro-element. Figure 4 Schematic diagram of heat transfer in the fluid micro-element within the wellbore annulus: Figure 5 This is a schematic diagram of heat transfer in a water-jacking pipe micro-element. Figure 6 This is a schematic diagram of heat transfer in the first layer of the sleeve micro-element; Figure 7 This is a schematic diagram of heat transfer in a cement ring micro-element. In the diagram, 1-drilling platform, 2-drill string, 3-seawater, 4-blowout preventer, 5-formation, 6-wellbore annulus, 7-hydrate layer, 8-cement sheath, 9-shallow gas layer, 10-drill bit, 11-deep gas layer, 12-formation. Detailed Implementation

[0018] To make the objectives, technical solutions, and advantages of the embodiments of the present invention clearer, the technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. The components of the embodiments of the present invention described and shown in the accompanying drawings can generally be arranged and designed in various different configurations.

[0019] It should be noted that similar labels and letters in the following figures indicate similar items. Therefore, once an item is defined in one figure, it does not need to be further defined and explained in subsequent figures.

[0020] The following detailed description of some embodiments of the present invention is provided in conjunction with the accompanying drawings. Unless otherwise specified, the following embodiments and features can be combined with each other.

[0021] A method for calculating the wellbore temperature field in marine natural gas hydrate multi-gas combined production drilling includes the following steps: S1: Based on the law of conservation of energy, establish a wellbore temperature model for multi-gas combined production of marine natural gas hydrates; S2: Based on the wellbore temperature model of multi-gas combined production of marine natural gas hydrates, and using the law of conservation of energy, the basic theory of heat transfer and the basic theory of fluid mechanics, the energy conservation equation of the micro-element in each region of the wellbore is analyzed, and the calculation method of the wellbore temperature field of multi-gas combined production of marine natural gas hydrates is obtained. The micro-element includes one or more of the following: fluid inside the drill string, drill string, fluid inside the annulus, casing, cement sheath, and formation surrounding the wellbore.

[0022] Existing studies have confirmed that the formation mechanisms of marine hydrates, shallow gas, and deep oil and gas are interconnected, and most exhibit regional symbiosis and spatial coexistence, primarily manifested in their three-dimensional vertical distribution. Given the occurrence characteristics and economic viability of marine hydrates, commercialization is difficult with hydrate extraction alone. Therefore, leveraging existing offshore oil and gas development platforms to conduct comprehensive exploration and three-dimensional development of multiple natural gas resources, including marine hydrates, shallow gas, and deep gas, represents a promising direction for the industrialization of marine hydrate development.

[0023] This invention, based on the fundamental theory of heat transfer and combined with actual working conditions in marine drilling processes, establishes a wellbore temperature model for hydrate formations in marine drilling according to the law of conservation of energy. The specific structure of this model is shown in [link to model description]. Figure 1 The system includes: 1. Drilling platform; 2. Drill string; 3. Seawater; 4. Blowout preventer; 5. Formation; 6. Wellbore annulus; 7. Hydrate layer; 8. Cement sheath; 9. Shallow gas layer; 10. Drill bit; 11. Deep gas layer; and 12. Formation. For ease of study, the following basic assumptions are made: (1) The drilling fluid and other liquids in the wellbore are single-phase incompressible fluids; (2) Only radial and axial heat conduction exists in and around the wellbore, and heat convection in formation pores is not considered; (3) The decomposition rates of natural gas hydrates in the annulus are equal under the same environmental conditions (temperature, pressure and migration rate); (4) The fluid inside the wellbore is considered to be affected by the heat source term and the forced heat convection heat transfer in the axial and radial directions; (5) Both the geothermal gradient and the seawater temperature are constant and remain stable throughout the drilling process.

[0024] In actual offshore drilling operations, drilling fluid is pumped into the wellbore, circulates through the drill bit and exits from the annulus, and this process is considered a complete system. Taking the wellbore and surrounding formation system as a whole, and focusing on the fluid within the wellbore as the primary research objective, this system satisfies the law of conservation of energy, meaning that the change in energy within the system over a given time period is equal to the difference between the energy entering and leaving the system. The following equation is established: In the formula, —Energy entering the system; —The total work done on the system by external forces; —Total changes in the system.

[0025] Using the law of conservation of energy, fundamental theories of heat transfer, and basic theories of fluid mechanics, this study analyzes the micro-elements within the wellbore, including: the fluid inside the drill string, the drill string itself, the fluid inside the annulus, the casing, the cement sheath, and the surrounding formation. Energy conservation equations for these micro-elements are derived, resulting in a temperature and heat transfer model for the offshore drilling wellbore. However, due to the unique characteristics of offshore drilling, the temperature variations of seawater and formation are opposite, and their physical properties differ significantly. The heat transfer mechanism above the mudline differs from that below the mudline, necessitating separate wellbore temperature models for the seawater and formation sections.

[0026] Taking a certain seawater area as an example, the seawater temperature can be divided into three layers in the vertical direction: (1) The mixing layer is a layer of water with a certain thickness and uniform temperature that is generated near the surface of the ocean due to convection and wind and wave stirring. In low latitude areas, its thickness is generally less than 100 meters. (2) The thermocline is located between the mixing layer and the isothermal layer. The seawater temperature drops rapidly with the change of depth. The seawater temperature changes greatly in the thermocline. Its thickness is generally less than 200 meters. (3) The isothermal layer is the area between the thermocline and the seabed mudline. The seawater temperature changes very little in this area. The temperature is usually between 2 and 6℃. In areas below 2000 meters, the water temperature is usually maintained at around 2℃.

[0027] Water temperature data (taking the steady-state layer as an example) can be obtained from the Levitus database. The sea temperature equation fitted to the data is as follows: h>200m; where a=39.398, b=37.091, c=130.137, d=402.732; —Seawater temperature, °C; h—Seawater depth, m.

[0028] Methods for calculating the wellbore temperature field in multi-gas combined production wells for marine natural gas hydrates include methods for calculating the temperature changes of drilling fluid within the drill string.

[0029] See Figure 2 Analysis of the heated micro-element of drilling fluid inside the drill string reveals that it is mainly affected by four factors: 1) the heat carried by the drilling fluid as it moves downward along the wellbore in the axial direction; 2) the heat transferred by convective heat exchange between the drilling fluid and the inner wall of the drill string; 3) the heat generated by the change in the energy of the drilling fluid itself; and 4) the work done on the drilling fluid micro-element by other factors, including frictional heat generation and the heat generated by the drilling fluid through the drill bit nozzle at the drill bit.

[0030] Based on the principle of conservation of energy, the following equation is established: In unit time The heat carried by the drilling fluid as it moves downwards along the wellbore within the drill string from the inner axis upwards: ; In unit time Heat transferred between the drilling fluid and the inner wall of the drill pipe via convective heat exchange: ; In unit time Work done on the infinitesimal element by other internal and external factors: ; In unit time Heat generated by the change in the energy of the internal drilling fluid: ; The numerical model for the temperature change of drilling fluid inside the drill string is obtained by reorganizing the above formulas as follows: ; Right now: ; In the formula, —Drilling fluid density, kg / m³ 3 ; —Specific heat capacity of drilling fluid, J / (kg·℃); —Temperature of drilling fluid inside the drill string, °C; —Temperature of the drill string inner wall, °C; — Convection heat transfer coefficient of the drill string inner surface, J / (m²) 2 ·s·℃); —Drilling fluid displacement (m³) 3 / s; —Power of the heat source per unit length inside the drill string, J / s; — Drill string inner diameter, m.

[0031] E1 is in unit time The heat carried by the drilling fluid as it moves downwards along the wellbore within the drill string, E x、 E x+dx E2 is the heat contained in a micro-element of drilling fluid at different axial positions, and E2 is the heat contained in a micro-element of drilling fluid per unit time. The heat transferred between the drilling fluid and the inner wall of the drill pipe via convective heat exchange.

[0032] Methods for calculating the wellbore temperature field in multi-gas combined production wells for marine natural gas hydrates include methods for calculating the temperature changes of the drill string within the wellbore. See also... Figure 3 Analysis of the heated micro-element of the drill string reveals that it is mainly affected by three factors: 1) the heat conducted by the drill string along the axial direction; 2) the heat transferred by convection between the inner and outer walls of the drill string and the drilling fluid and the annular fluid; and 3) the change in the energy of the drill string itself.

[0033] Based on the principle of conservation of energy, the following equation is established: In unit time Heat transferred upwards from the inner axis of the drill string: ; In unit time Heat transferred by convection between the inner and outer walls of the drill string and the drilling fluid and annulus fluid: ; In unit time Changes in the energy of the internal drill string itself: ; The numerical model of temperature change in the drill string inside the wellbore is obtained by rearranging the above formulas as follows: ; Right now: ; In the formula, —Drill string density, kg / m 3 ; —Specific heat capacity of drill string, J / (kg·℃); — Thermal conductivity of the drill string, W / m·℃; —Temperature of drilling fluid inside the drill string, °C; —Drill string temperature, °C; —Flat-flow heat transfer coefficient of drill string surface, J / (m²) 2 ·s·℃); —Outer diameter of drill string, m.

[0034] Methods for calculating the wellbore temperature field in multi-gas combined production wells for marine natural gas hydrates include methods for calculating the temperature changes of the fluid within the wellbore annulus. (Participants...) Figure 4 The thermal analysis of the fluid micro-element inside the riser annulus is mainly affected by four factors: 1) the heat carried by the annular fluid as it moves upward along the annulus in the axial direction; 2) the heat transferred by convective heat exchange between the annular fluid and the outer wall of the drill string and the inner wall of the wellbore; 3) the heat generated by the energy change of the annular fluid itself; and 4) the work done on the drilling fluid micro-element by other factors, including frictional heat generation, the heat generated by the drilling fluid through the drill bit nozzle at the drill bit, and the heat absorbed by the decomposition of hydrates.

[0035] Based on the principle of conservation of energy, the following equation is established: In unit time The heat carried by the fluid moving upward along the wellbore annulus in the inner axis: ; In unit time The heat transferred between the fluid inside the annulus of the wellbore and the convective heat exchange between the outer wall of the drill string and the inner wall of the wellbore: ; In unit time Work done on the infinitesimal element by other internal and external factors: ; In unit time Heat generated by the change in the energy of the fluid within the annulus of the wellbore: ; The numerical model of temperature change of fluid in the wellbore annulus is obtained by rearranging the above formulas as follows: ; Right now: ; In the formula, —Fluid density in the wellbore annulus, kg / m 3 ; —Specific heat capacity of fluid in the wellbore annulus, J / (kg·℃); — Annular fluid temperature, °C; —Wellbore inner wall temperature, °C; — Convective heat transfer coefficient of the wellbore inner wall (J / (m)) 2 ·s·℃); —Fluid displacement in the wellbore annulus (m³) 3 / s; —Work done by the external environment on the annular fluid (J / s); —Wellbore inner diameter, m.

[0036] Methods for calculating the wellbore temperature field in multi-gas combined production wells for marine natural gas hydrates include methods for calculating the temperature change of the riser. See also... Figure 5 Analysis of the heated micro-element of the riser reveals that it is mainly affected by three factors: 1) the heat conducted by the riser along the axial direction; 2) the heat transferred between the outer wall of the riser and the seawater through convection; and 3) the change in the riser's own energy.

[0037] Based on the principle of conservation of energy, the following equation is established: In unit time Heat transferred upwards through the inner axial diaphragm: ; In unit time The heat transferred between the inner and outer walls of the internal drill string and the convection heat exchange between the annular fluid and the seawater: ; In unit time Changes in the energy of the inner diaphragm pipe itself: ; The numerical model of temperature change in the riser is obtained by rearranging the above formulas as follows: ; Right now: ; In the formula, —Density of riser pipe, kg / m 3 ; —Specific heat capacity of the riser, J / (kg·℃); — Thermal conductivity of the riser pipe, W / m·℃; —Temperature of the riser pipe, °C; —Seawater temperature, °C; — Convection heat transfer coefficient of the inner wall of the baffle pipe, J / (m²) 2 ·s·℃); — Convection heat transfer coefficient of the outer surface of the baffle, J / (m²) 2 ·s·℃); —Outer diameter of the riser pipe, in meters.

[0038] The heat transfer processes of drilling fluid, drill string, and annular fluid in the wellbore below the mudline are basically the same. The factors affecting heat transfer and the heat transfer methods are the same. Therefore, the mathematical model of the temperature of drilling fluid, drill string, and annular fluid in the wellbore below the mudline can be obtained from the above.

[0039] Methods for calculating the wellbore temperature field in multi-gas combined production wells for marine natural gas hydrates include methods for calculating casing temperature variations. See also... Figure 6 The factors affecting the temperature distribution of the first layer of casing are: 1) the heat conducted by the casing in the axial direction; 2) the heat conduction between the casing and the inner cement ring and the convective heat transfer with the annular fluid in the radial direction; 3) the change of the internal energy of the casing itself.

[0040] The mathematical model for analyzing each factor is as follows: In unit time Heat transferred upwards through the inner axial sleeve: ; In unit time Heat transfer generated between the inner sleeve and the inner cement ring: ; In unit time Changes in the energy of the inner diaphragm pipe itself: ; The numerical model of temperature change in the bushing is obtained by rearranging the above formulas as follows: ; Right now: ; In the formula, —Casing density, kg / m 3 ; —Specific heat capacity of the casing, J / (kg·℃); — Thermal conductivity of the sleeve, W / m·℃; —Combined thermal conductivity of the sleeve and cement ring, W / m·℃; —Casing temperature, °C; —Cement ring temperature, °C; — Convective heat transfer coefficient of the inner wall of the casing, J / (m²) 2 ·s·℃); —Inner diameter of the casing, in meters; —Outer diameter of the casing, in meters.

[0041] Methods for calculating the wellbore temperature field in multi-gas combined production wells for marine natural gas hydrates include methods for calculating the temperature of the cement sheath. See also... Figure 7 The heat conduction phenomenon between the cement ring and the sleeve can be regarded as the heat conduction phenomenon between multiple cylindrical walls, with only axial and radial heat transfer.

[0042] By analyzing the heated infinitesimal element of the cement ring, and based on the laws of conservation of energy and heat conduction, the differential equation for the thermal conductivity of the cement ring is derived. The mathematical model is expressed as follows: ; The wellbore and its internal regions can be represented using cylindrical coordinates. The representation method is the same as in rectangular coordinates. Analyzing the heat transfer process of the infinitesimal element in cylindrical coordinates, a mathematical model of heat conduction in the wellbore in cylindrical coordinates is established, yielding the following equations: ; Assuming the thermal conductivity is constant, the above equation can be simplified to: ; When heat transfer within the wellbore occurs only along the radial and axial directions, and there is no internal heat source term, the above equation can be simplified to: ; The mathematical model for the temperature of the cement ring can be obtained from the above formula: ; In the formula, — Density of cement ring, kg / m³3 ; —Ring-relative heat capacity of cement, J / (kg·℃); — Thermal conductivity of cement ring, W / m·℃; —Cement ring temperature, °C; —Outer diameter of the cement ring, in meters.

[0043] The calculation method for the wellbore temperature field in multi-gas combined production wells for marine natural gas hydrates includes the calculation method for formation temperature changes. Heat conduction in the formation surrounding the wellbore is due to the single cylindrical wall, and the heat transfer direction is only radial and axial. The mathematical model for formation temperature transfer is as follows: ; In the formula, — Formation density, kg / m³ 3 ; —Specific heat capacity of the formation, J / (kg·℃); — Thermal conductivity of the formation, W / m·℃; — Formation temperature, °C.

[0044] Furthermore, initial and boundary conditions are essential for solving the mathematical model of wellbore temperature. The specific conditions are as follows: The initial temperature of the fluid inside the drill string and the drill string itself is the initial injection temperature. The initial temperature of the fluid in the annulus is the wellbore outlet temperature, and their temperature change trend follows the ambient temperature trend. The initial temperature of the riser is the seawater temperature, and its temperature change is the same as that of the seawater temperature. Meanwhile, the initial temperatures of the casing, cement sheath, and formation within the formation are the seafloor mudline temperature, and their temperature gradients are all the original formation temperature gradients. ; In the formula, , , , , , , —Temperature of drilling fluid, drill string, annular fluid, riser, casing, cement sheath, and formation near the wellbore; , , , —Temperature at the wellhead, outlet, sea surface, and seabed mudline; , , —Drilling fluid temperature gradient, seawater temperature, and formation temperature gradient.

[0045] At the interface between the formation and the annular fluid in the wellbore, the energy flowing in and out through the interface is equal: ; At a sufficient distance from the Earth's surface, the geothermal gradient remains constant. ; The formation temperature at a certain location at the bottom of the well remains unchanged, unaffected by the drilling process. .

[0046] This invention, based on actual drilling conditions and wellbore structure in marine environments, utilizes the law of conservation of energy, combined with the heat transfer methods and energy changes of various heat transfer micro-elements within the wellbore, and considers changes in ocean temperature, the influence of heat source terms, and variations in thermophysical parameters to establish a mathematical model of temperature distribution during wellbore circulation. Simultaneously, based on the actual offshore drilling process, initial and boundary conditions for a mathematical model of wellbore temperature in multi-gas combined production drilling of marine natural gas hydrates are established, providing a foundation for solving the mathematical model.

[0047] For the foregoing embodiments, in order to simplify the description, they are all described as a series of actions. However, those skilled in the art should understand that this application is not limited to the described order of actions, because according to this application, some steps can be performed in other orders or simultaneously. Furthermore, those skilled in the art should also understand that the embodiments described in the specification are preferred embodiments, and the actions involved are not necessarily essential to this application.

[0048] The above embodiments describe the basic principles, main features, and advantages of the present invention. Those skilled in the art should understand that the present invention is not limited to the above embodiments. The embodiments and descriptions in the specification are merely illustrative of the principles of the invention. Modifications and variations made by those skilled in the art without departing from the spirit and scope of the invention should be within the protection scope of the appended claims.

Claims

1. A method for calculating the wellbore temperature field in multi-gas combined production wells for marine natural gas hydrates, characterized in that, Includes the following steps: S1: Based on the law of conservation of energy, establish a wellbore temperature model for multi-gas combined production of marine natural gas hydrates; S2: Based on the wellbore temperature model of multi-gas combined production of marine natural gas hydrates, and using the law of conservation of energy, the basic theory of heat transfer and the basic theory of fluid mechanics, the energy conservation equation of the micro-element in each region of the wellbore is analyzed, and the calculation method of the wellbore temperature field of multi-gas combined production of marine natural gas hydrates is obtained. The micro-element includes one or more of the following: fluid inside the drill string, drill string, fluid inside the annulus, casing, cement sheath, and formation surrounding the wellbore.

2. The method for calculating the wellbore temperature field of marine natural gas hydrate multi-gas combined production wells as described in claim 1, characterized in that, The marine natural gas hydrate multi-gas combined production wellbore temperature model sets the actual marine drilling process as a complete system. This actual process involves drilling fluid being pumped into the wellbore and circulating out of the wellbore through the drill bit and annulus. The system satisfies the following equations: ； In the formula, Energy entering the system; The total work done by the external system; This represents the total amount of change in the system.

3. The method for calculating the wellbore temperature field of marine natural gas hydrate multi-gas combined production wells as described in claim 1, characterized in that, The method for calculating the wellbore temperature field in multi-gas combined production wells for marine natural gas hydrates includes a method for calculating the temperature change of drilling fluid within the drill string. ； In the formula, This represents the power of the heat source within the drill string per unit length. Density of drilling fluid; Specific heat capacity of drilling fluid; This refers to the temperature of the drilling fluid inside the drill string. This refers to the temperature of the drill string's inner wall. The convective heat transfer coefficient of the inner surface of the drill string; This refers to the drilling fluid discharge rate; This is the inner diameter of the drill string.

4. The method for calculating the wellbore temperature field of marine natural gas hydrate multi-gas combined production wells as described in claim 1, characterized in that, The method for calculating the wellbore temperature field in multi-gas combined production wells for marine natural gas hydrates includes a method for calculating the temperature change of the drill string within the wellbore. ； In the formula, The density of the drill string; This refers to the specific heat capacity of the drill string; The thermal conductivity of the drill string; This refers to the temperature of the drilling fluid inside the drill string. This refers to the temperature of the drill string's inner wall. The annular fluid temperature; The convective heat transfer coefficient of the drill string surface; This is the outer diameter of the drill string.

5. The method for calculating the wellbore temperature field of marine natural gas hydrate multi-gas combined production wells as described in claim 1, characterized in that, The method for calculating the wellbore temperature field in multi-gas combined production wells for marine natural gas hydrates includes a method for calculating the temperature changes of the fluid within the wellbore annulus. ； In the formula, The fluid density within the wellbore annulus; The specific heat capacity of the fluid inside the wellbore annulus; The annular fluid temperature; This refers to the temperature of the inner wall of the wellbore. The convective heat transfer coefficient of the wellbore inner wall; This refers to the fluid discharge rate within the wellbore annulus. The work done by the external environment on the annular fluid; This refers to the inner diameter of the wellbore.

6. The method for calculating the wellbore temperature field of marine natural gas hydrate multi-gas combined production wells as described in claim 1, characterized in that, The method for calculating the wellbore temperature field in marine natural gas hydrate multi-gas combined production wells includes a method for calculating the temperature change of the riser: ； In the formula, Density of the riser pipe; The specific heat capacity of the riser pipe; The thermal conductivity of the riser pipe; Temperature of the riser pipe; Seawater temperature; The convective heat transfer coefficient of the inner wall of the riser pipe; The convective heat transfer coefficient of the outer surface of the riser tube; This refers to the outer diameter of the riser pipe.

7. The method for calculating the wellbore temperature field of marine natural gas hydrate multi-gas combined production wells as described in claim 1, characterized in that, The method for calculating the wellbore temperature field in multi-gas combined production wells for marine natural gas hydrates includes a method for calculating the temperature change of the casing: ； In the formula, For casing density; The specific heat capacity of the casing; The thermal conductivity of the sleeve; The combined thermal conductivity of the sleeve and cement ring; For the sleeve temperature; Temperature of the cement ring; The convective heat transfer coefficient of the inner wall of the casing; The inner diameter of the casing; This refers to the outer diameter of the casing.

8. The method for calculating the wellbore temperature field of marine natural gas hydrate multi-gas combined production wells as described in claim 1, characterized in that, The method for calculating the wellbore temperature field in marine natural gas hydrate multi-gas combined production drilling includes a method for calculating the temperature of the cement sheath: ； In the formula, Density of cement rings; The relative heat capacity of cement; The thermal conductivity of the cement ring; Temperature of the cement ring; This refers to the outer diameter of the cement ring.

9. The method for calculating the wellbore temperature field of marine natural gas hydrate multi-gas combined production wells as described in claim 1, characterized in that, The method for calculating the wellbore temperature field in multi-gas combined production wells for marine natural gas hydrates includes a method for calculating formation temperature variations. ； In the formula, Formation density; Specific heat capacity of the formation; The thermal conductivity of the formation; This refers to the formation temperature.

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