Method and device for constructing a non-steady-state temperature-pressure coupling model of a supercritical steam huff and puff injection wellbore

Abstract

The present application relates to the technical field of heavy oil thermal recovery, and discloses a method for constructing a non-steady-state temperature-pressure coupling model of a supercritical steam injection wellbore, which comprises the following steps: S1, discretizing and gridding a parameter region, assigning values, loading boundary conditions and initial temperature, and presetting a first wellbore temperature, a first annular natural convection heat transfer coefficient, a first fluid flow rate and first thermal physical property parameters; S2, solving a motion equation and updating; S3, solving a continuity equation to obtain a second fluid flow rate and comparing; if the error is not allowed, executing step S2; otherwise, executing step S4; S4, obtaining a second wellbore temperature and a second annular natural convection heat transfer coefficient and comparing; if the error is allowed, completing the calculation. The present application adopts a staggered grid full-implicit discrete model for cyclic iteration and solving, accurately calculates the temperature and pressure distribution of the injection wellbore, describes the change law of the bottom hole dryness with the injection time, and guides the supercritical steam injection process.

Description

Technical Field

[0001] This invention relates to the field of heavy oil thermal recovery technology, specifically to a method and apparatus for constructing an unsteady temperature-pressure coupling model for supercritical steam injection wellbore. Background Technology

[0002] Currently, in heavy oil thermal recovery, the fitting models for wellbore temperature, pressure, and dryness during traditional steam injection are relatively mature, meeting the conventional steam injection requirements of pressure < 22.064 MPa and temperature < 373.946 °C. However, for supercritical steam, the properties of the injected medium change significantly, with drastically different flow properties such as density, viscosity, and compressibility. Therefore, it is necessary to re-examine the variation law of its physical property parameters and establish a temperature and pressure calculation model.

[0003] Currently, research on supercritical steam huff and puff is in its early stages. Parameters such as steam injection intensity, tubing type, insulation method, and well shut-in time are all in the exploratory stage, lacking theoretical basis and optimization design methods. Under different steam injection parameters, the steam state in the wellbore and formation is unclear, and data support cannot be provided for evaluating the effectiveness of measures. There is an urgent need to carry out relevant research on key technologies of supercritical steam huff and puff to further improve the development effect of supercritical steam huff and puff research blocks.

[0004] In view of this, improvements should be made to the existing technology. Summary of the Invention

[0005] To address existing technical problems, this invention proposes a method and apparatus for constructing an unsteady temperature-pressure coupled model for supercritical steam huff and puff injection wellbore. A temperature-pressure coupled mathematical model for the injection wellbore is established, and a staggered grid fully implicit discrete model is used for iterative solution. This accurately calculates the temperature and pressure distribution in the injection wellbore, describes the variation of bottom hole dryness with injection time, and guides the surface injection process of supercritical steam huff and puff.

[0006] According to one aspect of the present invention, a method for constructing an unsteady temperature-pressure coupling model for supercritical steam huff-and-puff injection wellbore is provided, comprising: S1. Discretize the temperature node, pressure node and velocity node regions into a grid and assign values ​​to each grid cell. Load boundary conditions and initial temperature, and preset the first wellbore temperature, the first annular natural convection heat transfer coefficient, the first fluid velocity and the first thermophysical property parameter. S2. Based on the initial and boundary conditions, solve the motion equations to obtain the pressure values ​​of the wellbore pressure distribution, and use the first wellbore temperature and the pressure values ​​to update the second thermophysical parameters; S3. Solve the continuity equation to calculate the second fluid velocity and compare it with the first fluid velocity; if the error is not within the allowable range, use the second fluid velocity as the new preset value and execute step S2; otherwise, execute step S4. S4. Solve the energy conservation equation using the second fluid velocity to obtain the second wellbore temperature and the second annulus natural convection heat transfer coefficient, and compare them with the first wellbore temperature and the first annulus natural convection heat transfer coefficient; if the error is within the allowable range, the calculation is completed; otherwise, the second wellbore temperature is used as the new preset value, and step S2 is executed until the result converges.

[0007] According to an embodiment of the present invention, step S1 further includes establishing a physical model for solving wellbore parameters and establishing a mathematical model for calculating the temperature field and pressure field of the supercritical steam injection wellbore section based on the physical model.

[0008] According to one embodiment of the present invention, the mathematical model for calculating the temperature field and pressure field of the supercritical steam injection wellbore section includes a heat transfer model inside the tubing, a heat transfer model inside the tubing wall, a heat transfer model in the annulus, a heat transfer model in the composite layer, a continuity condition, the convective heat transfer coefficient inside the tubing, the convective heat transfer coefficient in the annulus, a pressure drop model, and a frictional heat source.

[0009] According to one embodiment of the present invention, in step S1, discretizing the temperature node and pressure node regions includes using a fully implicit discretization format with staggered grids when discretizing the injection wellbore.

[0010] According to one embodiment of the present invention, temperature nodes and pressure nodes are arranged at the center of the regional grid, and velocity nodes are arranged at the interface of the regional grid.

[0011] According to one embodiment of the present invention, step S2 further includes determining the phase state, which includes pure gas phase, pure liquid phase, and coexistence of gas and liquid phases.

[0012] According to one embodiment of the present invention, determining the phase state includes determining it through a phase diagram and / or a phase state equation.

[0013] According to one embodiment of the present invention, the heat transfer model inside the oil pipe is expressed as follows:

[0014] In the formula: Q m —Heat generated per unit length within the oil pipe, W / m; ρ1—Supercritical steam density, kg / m³ 3 ; v1—Supercritical steam velocity, m / s; T1—Supercritical steam temperature, K; T2—Tube wall temperature, K; — Convection heat transfer coefficient of the inner wall of the oil pipe, W / (m²) 2 ·K); z—depth, m; t—time, s.

[0015] According to one embodiment of the present invention, the heat transfer model of the oil pipe wall is expressed as follows:

[0016] In the formula: T3—annular fluid temperature, K; — Convection heat transfer coefficient of the outer wall of the oil pipe, W / m 2 ·K; ρ2 — oil pipe density, kg / m 3 ; c2—Specific heat capacity of the oil pipe, J / kg·K; λ2 — Thermal conductivity of the oil pipe, W / (m·K).

[0017] According to one embodiment of the present invention, the annular heat transfer model is expressed as follows:

[0018] In the formula: T4—Bucket temperature, K; — Convection heat transfer coefficient of the inner wall of the casing, W / (m²) 2 ·K); ρ3—Density of the tubing, kg / m 3 ; c3 — Specific heat capacity of the annular fluid, J / kg·K.

[0019] According to one embodiment of the present invention, the composite layer heat transfer model is expressed as follows:

[0020] In the formula: λ i — Thermal conductivity at different locations, W / (m·K); T i —Temperature at different locations, in K; r i —Radius at different locations, in meters; ρ i —Fluid density at different locations, kg / m³ 3 ; c i —Specific heat capacity of fluid at different locations, J / kg·K; N i —Maximum number of radial subdivisions; i=4 represents casing, i=5 represents cement sheath, and i≥6 represents formation.

[0021] According to one embodiment of the present invention, the continuity condition includes: At the interface between the inner wall of the casing and the annular fluid, the heat transferred by convection between the casing wall and the fluid is equal to the heat transferred by conduction through the casing wall, i.e.:

[0022] At the interface between different heat-conducting media, the heat introduced is equal to the heat dissipated, that is: .

[0023] According to one embodiment of the present invention, the convective heat transfer coefficient inside the oil pipe includes: The heat exchange between the fluid inside the oil pipe and the inner wall of the pipe is forced convection heat transfer, which is represented as: .

[0024] According to one embodiment of the present invention, the annular convective heat transfer coefficient includes: The heat transfer coefficient of natural convection between vertical flat plates is used as an approximation, expressed as: .

[0025] According to one embodiment of the present invention, the voltage drop model is expressed as follows:

[0026] In the formula: p1—Fluid pressure inside the tubing, MPa; d1—Inner diameter of the oil pipe, in meters; g—acceleration due to gravity, g = 9.8 m / s² 2 ; f—the coefficient of frictional resistance, dimensionless.

[0027] According to one embodiment of the present invention, the frictional heat source is represented as:

[0028] In the formula: Δp i — represents the frictional pressure drop gradient, Pa / m; q — volumetric flow rate, m 3 / s.

[0029] According to one embodiment of the present invention, step S4 further includes determining whether the second wellbore temperature, the second annular natural convection heat transfer coefficient, the second fluid velocity, and the second thermophysical parameter are corresponding data at the bottom of the well.

[0030] According to one embodiment of the present invention, the method further includes performing a reasonableness check and outlier handling on the input data through a data preprocessing module.

[0031] According to one embodiment of the invention, the method further includes automatically adjusting the discrete grid and calculation parameters based on the wellbore diameter and / or wellbore length and / or reduced diameter section and / or expanded diameter section and / or branch wellbore.

[0032] According to another aspect of the present invention, a device for constructing an unsteady temperature-pressure coupling model of a supercritical steam huff-and-puff injection wellbore is provided, comprising: The first module is used to discretize and mesh the temperature node, pressure node and velocity node regions and assign values ​​to each mesh element, load boundary conditions and initial temperature, and preset the first wellbore temperature, the first annular natural convection heat transfer coefficient, the first fluid velocity and the first thermophysical property parameter. The second module is used to solve the motion equations based on the initial and boundary conditions to obtain the pressure values ​​of the wellbore pressure distribution, and to update the second thermophysical parameters using the first wellbore temperature and pressure values. The third module is used to solve the continuity equation to calculate the second fluid velocity and compare it with the first fluid velocity. If the error is not within the allowable range, the second fluid velocity is used as a new preset value and provided to the second module; otherwise, the second fluid velocity is provided to the fourth module. The fourth module is used to solve the energy conservation equation using the second fluid velocity to obtain the second wellbore temperature and the second annulus natural convection heat transfer coefficient, and compare them with the first wellbore temperature and the first annulus natural convection heat transfer coefficient; if the error is within the allowable range, the calculation is completed; otherwise, the second wellbore temperature is provided as a new preset value to the second module until the result converges.

[0033] By adopting the above technical solutions, the present invention has the following advantages compared with the prior art: it establishes a temperature-pressure coupling model for the injection wellbore, uses a discrete model for iterative solution, accurately calculates the temperature and pressure distribution of the injection wellbore, describes the change law of bottom hole dryness with injection time, and guides the supercritical steam huff and puff surface injection process. Attached Figure Description

[0034] To more clearly illustrate the technical solutions of the embodiments of the present invention, the accompanying drawings used in the embodiments will be briefly introduced below. Obviously, the drawings described below are only some implementation examples of the present invention. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0035] Figure 1 A flowchart illustrating the numerical calculation of the temperature and pressure field in the supercritical steam injection wellbore section according to an embodiment of the present invention is shown. Figure 2 A physical model of the temperature and pressure field of the supercritical steam injection wellbore section according to an embodiment of the present invention is shown; Figure 3A schematic diagram of numerical calculation of temperature and pressure field in supercritical steam injection wellbore section under intelligent control according to an embodiment of the present invention is shown; Figure 4 A temperature distribution diagram of the injection wellbore at different injection times is shown according to an embodiment of the present invention; Figure 5 A diagram showing the injection wellbore pressure distribution at different injection times according to an embodiment of the present invention is provided. Detailed Implementation

[0036] The following detailed description of the embodiments is intended to exemplify the principles of the present invention, but should not be construed as limiting the scope of the invention. The present invention can be implemented in many different forms and is not limited to the specific embodiments disclosed herein, but includes all technical solutions falling within the scope of the claims.

[0037] These embodiments are provided to make this disclosure thorough and complete, and to fully express the scope of the invention to those skilled in the art. It should be noted that, unless otherwise specifically stated, the relative arrangement of components and steps, material composition, numerical expressions, and values ​​set forth in these embodiments should be interpreted as merely exemplary and not as limiting.

[0038] It should be noted that, in the description of this invention, unless otherwise stated, "a plurality of" means two or more; the terms "upper," "lower," "left," "right," "inner," and "outer," etc., indicating orientation or positional relationships, are only for the convenience of describing this invention and simplifying the description, and do not indicate or imply that the device or element referred to must have a specific orientation, or be constructed and operated in a specific orientation, and therefore should not be construed as a limitation of this invention. When the absolute position of the described object changes, the relative positional relationship may also change accordingly.

[0039] It should also be noted that, in the description of this invention, unless otherwise explicitly specified and limited, the terms "installation," "connection," and "joining" should be interpreted broadly. For example, they can refer to a fixed connection, a detachable connection, or an integral connection; they can refer to a direct connection or an indirect connection through an intermediate medium. Those skilled in the art can understand the specific meaning of the above terms in this invention depending on the specific circumstances. When a specific device is described as being located between a first device and a second device, an intermediary device may or may not be present between the specific device and the first or second device.

[0040] All terms used in this invention have the same meaning as understood by one of ordinary skill in the art to which this disclosure pertains, unless otherwise specifically defined. It should also be understood that terms defined in general dictionaries should be interpreted as having meanings consistent with their meanings in the context of the relevant art, and not as idealized or highly formalized, unless expressly defined herein.

[0041] Techniques, methods, and equipment known to those skilled in the art may not be discussed in detail, but where appropriate, such techniques, methods, and equipment should be considered part of the specification.

[0042] This invention provides a method for constructing an unsteady temperature-pressure coupling model for supercritical steam injection wellbore. Figure 1 An exemplary method for constructing an unsteady temperature-pressure coupling model of a supercritical steam huff-and-puff injection wellbore according to the present invention is shown, comprising the following steps: S1. Discretize the temperature node, pressure node and velocity node regions into a grid and assign values ​​to each grid cell. Load boundary conditions and initial temperature, and preset the first wellbore temperature, the first annular natural convection heat transfer coefficient, the first fluid velocity and the first thermophysical property parameter. S2. Based on the initial and boundary conditions, solve the motion equations to obtain the pressure values ​​of the wellbore pressure distribution, and use the first wellbore temperature and pressure values ​​to update and obtain the second thermophysical parameters; S3. Solve the continuity equation to calculate the second fluid velocity and compare it with the first fluid velocity; if the error is not within the allowable range, use the second fluid velocity as the new preset value and execute step S2; otherwise, execute step S4. S4. Solve the energy conservation equation using the second fluid velocity to obtain the second wellbore temperature and the second annulus natural convection heat transfer coefficient, and compare them with the first wellbore temperature and the first annulus natural convection heat transfer coefficient; if the error is within the allowable range, the calculation is completed; otherwise, the second wellbore temperature is used as the new preset value, and step S2 is executed until the result converges.

[0043] The model assumes that the heat transfer media are axisymmetrically distributed around the center of the oil pipe, and that the thermophysical parameters of each heat transfer medium are isotropic. A model is established as follows: Figure 2 The physical model shown considers carbon dioxide injection from the tubing, with the annulus being a quiescent fluid. Since the critical pressure of carbon dioxide is much lower than the fracturing operation pressure, its phase transition enthalpy is zero, meaning there is no latent heat in the transformation from liquid carbon dioxide to supercritical carbon dioxide.

[0044] In some specific embodiments, step S1 further includes establishing a physical model for solving wellbore parameters and establishing a mathematical model for calculating the temperature and pressure fields of the supercritical steam injection wellbore section based on the physical model.

[0045] In some specific embodiments, the mathematical models for calculating the temperature and pressure fields of the supercritical steam injection wellbore section include the heat transfer model inside the tubing, the heat transfer model inside the tubing wall, the heat transfer model in the annulus, the heat transfer model of the composite layer, the continuity condition, the convective heat transfer coefficient inside the tubing, the convective heat transfer coefficient in the annulus, the pressure drop model, and the frictional heat source.

[0046] In some specific embodiments, step S1, discretizing the temperature node and pressure node regions, includes using a fully implicit discretization scheme with staggered grids when discretizing the injection wellbore.

[0047] like Figure 3 As shown, in some specific embodiments, temperature and pressure nodes are arranged at the center of the regional grid, and velocity nodes are arranged at the interface of the regional grid. The model is meshed accordingly. To accurately couple temperature and pressure, a fully implicit discretization scheme with staggered meshes is used when discretizing the tubing elements. That is, temperature and pressure nodes are arranged at the center of the control volume, and velocity nodes are arranged at the interface of the control volume. Intermediate differences are performed on the spatial terms and forward differences are performed on the time terms in the differential equations. Since temperature, pressure, physical properties, and heat transfer coefficients are mutually coupled and influence each other, each time step requires the calculation results of the previous time step as initial conditions. Therefore, the temperature, pressure, carbon dioxide physical properties, and annular natural convection heat transfer coefficient are solved iteratively until a convergent solution for that time step is obtained. Here, M is the maximum number of elements in the vertical partition; the superscript "*" indicates a node at the interface.

[0048] Based on the above embodiments, step S2 further includes determining the phase state, which includes pure gas phase, pure liquid phase, and coexistence of gas and liquid phases.

[0049] In some specific embodiments, phase determination includes using phase diagrams and / or phase equations. Phase diagrams visually display the phase distribution boundaries of a substance under different temperatures, pressures, and other conditions, while phase equations mathematically describe the laws and conditions governing phase transitions. Combining these two methods allows for extremely precise determination of the phase state of a substance, whether it is a gaseous, liquid, solid, or multiphase mixture, providing a clear and accurate assessment.

[0050] Based on the above embodiments, the heat transfer model inside the oil pipe is expressed as follows:

[0051] In the formula: Q m —Heat generated per unit length within the oil pipe, W / m; ρ1—Supercritical steam density, kg / m³ 3 ; v1—Supercritical steam velocity, m / s; T1—Supercritical steam temperature, K; T2—Tube wall temperature, K; — Convection heat transfer coefficient of the inner wall of the oil pipe, W / (m²) 2 ·K); z—depth, m; t—time, s.

[0052] In some specific embodiments, the heat transfer model of the tubing wall is represented as follows:

[0053] In the formula: T3—annular fluid temperature, K; — Convection heat transfer coefficient of the outer wall of the oil pipe, W / m 2 ·K; ρ2 — oil pipe density, kg / m 3 ; c2—Specific heat capacity of the oil pipe, J / kg·K; λ2 — Thermal conductivity of the oil pipe, W / (m·K).

[0054] In some specific embodiments, the annular heat transfer model is represented as:

[0055] In the formula: T4—Bucket temperature, K; — Convection heat transfer coefficient of the inner wall of the casing, W / (m²) 2 ·K); ρ3—Density of the tubing, kg / m 3 ; c3 — Specific heat capacity of the annular fluid, J / kg·K.

[0056] Based on the above embodiments, the composite layer heat transfer model is expressed as follows:

[0057] In the formula: λ i — Thermal conductivity at different locations, W / (m·K); T i —Temperature at different locations, in K; r i —Radius at different locations, in meters; ρ i —Fluid density at different locations, kg / m³ 3 ; c i —Specific heat capacity of fluid at different locations, J / kg·K; N i—Maximum number of radial subdivisions; i=4 represents casing, i=5 represents cement sheath, and i≥6 represents formation.

[0058] In some specific embodiments, the continuity conditions include: At the interface between the inner wall of the casing and the annular fluid, the heat transferred by convection between the casing wall and the fluid is equal to the heat transferred by conduction through the casing wall, i.e.:

[0059] At the interface between different heat-conducting media, the heat introduced is equal to the heat dissipated, that is: .

[0060] Based on the above embodiments, the convective heat transfer coefficient inside the oil pipe includes: The heat exchange between the fluid inside the oil pipe and the inner wall of the pipe is forced convection heat transfer, which is represented as:

[0061] In some specific embodiments, the annular convective heat transfer coefficient includes: The heat transfer coefficient of natural convection between vertical flat plates is used as an approximation, expressed as: .

[0062] In some specific embodiments, the voltage drop model is expressed as:

[0063] In the formula: p1—Fluid pressure inside the tubing, MPa; d1—Inner diameter of the oil pipe, in meters; g—acceleration due to gravity, g = 9.8 m / s² 2 ; f—the coefficient of frictional resistance, dimensionless.

[0064] Based on the above embodiments, the frictional heat source is represented as follows:

[0065] In the formula: Δp i — represents the frictional pressure drop gradient, Pa / m; q — volumetric flow rate, m 3 / s.

[0066] In some specific embodiments, step S4 further includes determining whether the second wellbore temperature, the second annular natural convection heat transfer coefficient, the second fluid velocity, and the second thermophysical parameter are corresponding data at the bottom of the well.

[0067] Building upon the above embodiments, the method further includes a data preprocessing module to perform reasonableness checks and outlier handling on the input data. If the input data contains unreasonable or abnormal conditions, it may cause deviations, divergences, or even crashes during model training, simulation, or prediction. The data preprocessing module, by removing or correcting outliers, makes the input data to the model more standardized and stable, which helps the model converge better and improves the accuracy of model parameter estimation.

[0068] In some specific embodiments, the method further includes automatically adjusting the discrete mesh and computational parameters based on the wellbore diameter and / or wellbore length and / or the reduced diameter section and / or the expanded diameter section and / or the branch wellbore. This adaptive adjustment can greatly enhance the model's ability to describe the complex structure of the wellbore. For different wellbore diameters, whether it is a large-diameter main wellbore used for large-scale fluid transport or a small-diameter branch wellbore, the model can reasonably allocate the discrete mesh, making the calculation of physical quantities such as temperature and pressure in different pipe diameter regions more accurate. In the reduced diameter and expanded diameter sections, fine mesh adjustment can accurately capture the changes in fluid flow characteristics and heat exchange processes caused by abrupt changes in pipe diameter, accurately reflecting local pressure changes, flow velocity fluctuations, and heat accumulation or dissipation, thereby providing high-resolution, high-precision simulation results for the thermal-hydraulic analysis of the entire wellbore system, effectively reducing numerical errors caused by unreasonable mesh division, and making the simulation data closer to the real physical process.

[0069] This invention also provides a device for constructing an unsteady temperature-pressure coupling model for supercritical steam huff and puff injection wellbore, comprising: The first module is used to discretize and mesh the temperature node, pressure node and velocity node regions and assign values ​​to each mesh element, load boundary conditions and initial temperature, and preset the first wellbore temperature, the first annular natural convection heat transfer coefficient, the first fluid velocity and the first thermophysical property parameter. The second module is used to solve the motion equations based on the initial and boundary conditions to obtain the pressure values ​​of the wellbore pressure distribution, and to update the second thermophysical parameters using the first wellbore temperature and pressure values. The third module is used to solve the continuity equation to calculate the second fluid velocity and compare it with the first fluid velocity. If the error is not within the allowable range, the second fluid velocity is used as a new preset value and provided to the second module; otherwise, the second fluid velocity is provided to the fourth module. The fourth module is used to solve the energy conservation equation using the second fluid velocity to obtain the second wellbore temperature and the second annulus natural convection heat transfer coefficient, and compare them with the first wellbore temperature and the first annulus natural convection heat transfer coefficient; if the error is within the allowable range, the calculation is completed; otherwise, the second wellbore temperature is provided as a new preset value to the second module until the result converges.

[0070] The present application will be described below through specific embodiments.

[0071] As shown in Table 1, taking the injection of supercritical steam into the insulated tubing as an example, the variation law of temperature and pressure field in the injected wellbore is analyzed.

[0072] Table 1. Basic Data for Numerical Calculation

[0073] like Figure 4 and 5 As shown, during the injection process, at the initial injection depth of 20m, the wellbore temperature remained constant at 10℃. As the supercritical steam continuously heated the air inside the wellbore, the temperature gradually increased. At 5 and 10 days after injection, the supercritical steam inside the wellbore gradually dissipated heat from the injection temperature of 380℃ to the formation, and the temperature showed a decreasing trend. Meanwhile, the wellbore pressure showed an increasing trend during supercritical steam injection.

[0074] Compared with existing technologies, this invention achieves many significant beneficial effects by establishing a coupled mathematical model of injection wellbore temperature and pressure and using an interlaced grid fully implicit discrete model to carry out iterative solutions.

[0075] This model demonstrates exceptional accuracy in calculating the temperature and pressure distribution within the injection wellbore. It meticulously simulates and analyzes the complex heat transfer and fluid flow processes inside the wellbore, accurately capturing the dynamic changes in temperature and pressure at various locations and depths within the wellbore over time. Whether near the high-temperature, high-pressure wellhead, or in the gradually varying temperature and pressure regions of the wellbore and near the bottom, it provides highly accurate numerical solutions, offering a solid data foundation for a deeper understanding of the thermal-hydraulic characteristics inside the wellbore.

[0076] The model also performs exceptionally well in describing the variation of bottom-hole dryness with injection time. It accurately tracks the continuous changes in bottom-hole dryness over time during supercritical steam injection. This helps to clearly understand the quality state transformation process of steam at the bottom of the well, clarifying how steam dryness gradually changes at different injection time points, thus providing crucial information for optimizing steam injection strategies. For example, based on the variation pattern of bottom-hole dryness, parameters such as steam injection rate, temperature, and pressure can be rationally adjusted to achieve more efficient heat transfer and reservoir displacement effects.

[0077] From the perspective of its guiding significance for supercritical steam huff and puff surface injection technology, its value is immeasurable. Based on the accurately calculated temperature and pressure distribution and wellbore dryness variation patterns, it can provide comprehensive technical support for the design and optimization of surface injection processes. Regarding the selection and parameter setting of injection equipment, appropriate steam generator power, pipeline delivery pressure, and flow rate can be determined based on model results, ensuring the stability and efficiency of steam generation and delivery on the surface. Simultaneously, the formulation of process parameters such as injection time, injection volume, and intermittent cycles can also be scientifically and rationally planned using model predictions, thereby maximizing the recovery rate of supercritical steam huff and puff technology in reservoir development, reducing energy consumption and production costs, and ensuring the safe, stable, and sustainable development of the entire reservoir extraction operation.

[0078] Those skilled in the art should understand that the discussion of any of the above embodiments is merely exemplary and is not intended to imply that the scope of the invention (including the claims) is limited to these examples. Within the framework of the invention, technical features of the above embodiments or different embodiments can be combined, and many other variations of different aspects of the invention exist, which are not provided in the details for the sake of brevity. Therefore, any omissions, modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the invention should be included within the protection scope of the invention.

Claims

1. A method for constructing an unsteady temperature-pressure coupling model for supercritical steam huff and puff injection wellbore, characterized in that, Includes the following steps: S1. Discretize the temperature node, pressure node and velocity node regions into a grid and assign values ​​to each grid cell. Load boundary conditions and initial temperature, and preset the first wellbore temperature, the first annular natural convection heat transfer coefficient, the first fluid velocity and the first thermophysical property parameter. S2. Based on the initial and boundary conditions, solve the motion equations to obtain the pressure values ​​of the wellbore pressure distribution, and use the first wellbore temperature and the pressure values ​​to update the second thermophysical parameters; S3. Solve the continuity equation to calculate the second fluid velocity and compare it with the first fluid velocity; if the error is not within the allowable range, use the second fluid velocity as the new preset value and execute step S2; otherwise, execute step S4. S4. Solve the energy conservation equation using the second fluid velocity to obtain the second wellbore temperature and the second annulus natural convection heat transfer coefficient, and compare them with the first wellbore temperature and the first annulus natural convection heat transfer coefficient; if the error is within the allowable range, the calculation is completed; otherwise, the second wellbore temperature is used as the new preset value, and step S2 is executed until the result converges.

2. The method for constructing an unsteady temperature-pressure coupling model for supercritical steam injection wellbore according to claim 1, characterized in that, Step S1 further includes establishing a physical model for solving wellbore parameters and establishing a mathematical model for calculating the temperature and pressure fields of the supercritical steam injection wellbore section based on the physical model.

3. The method for constructing an unsteady temperature-pressure coupling model for supercritical steam injection wellbore according to claim 2, characterized in that, The mathematical models for calculating the temperature and pressure fields of the supercritical steam injection wellbore section include the heat transfer model inside the tubing, the heat transfer model inside the tubing wall, the heat transfer model in the annulus, the heat transfer model of the composite layer, the continuity condition, the convective heat transfer coefficient inside the tubing, the convective heat transfer coefficient in the annulus, the pressure drop model, and the frictional heat source.

4. The method for constructing an unsteady temperature-pressure coupling model for supercritical steam injection wellbore according to claim 1, characterized in that, In step S1, discretizing the temperature node and pressure node regions includes using a fully implicit discretization format with staggered grids when discretizing the injection wellbore.

5. The method for constructing an unsteady temperature-pressure coupling model for supercritical steam injection wellbore according to claim 4, characterized in that, The temperature and pressure nodes are placed at the center of the regional grid, and the velocity nodes are placed at the interface of the regional grid.

6. The method for constructing an unsteady temperature-pressure coupling model for supercritical steam injection wellbore according to claim 1, characterized in that, Step S2 also includes determining the phase state, which includes pure gas phase, pure liquid phase, and coexistence of gas and liquid phases.

7. The method for constructing an unsteady temperature-pressure coupling model for supercritical steam injection wellbore according to claim 6, characterized in that, The determination of phase state includes making a determination through phase diagrams and / or phase state equations.

8. The method for constructing an unsteady temperature-pressure coupling model for supercritical steam injection wellbore according to claim 3, characterized in that, The heat transfer model inside the oil pipe is expressed as follows: In the formula: Q m —Heat generated per unit length within the oil pipe, W / m; ρ1—Supercritical steam density, kg / m³ 3 ; v1—Supercritical steam velocity, m / s; T1—Supercritical steam temperature, K; T2—Tube wall temperature, K; — Convection heat transfer coefficient of the inner wall of the oil pipe, W / (m²) 2 ·K); z—depth, m; t—time, s.

9. The method for constructing an unsteady temperature-pressure coupling model for supercritical steam injection wellbore according to claim 3, characterized in that, The heat transfer model of the oil pipe wall is expressed as follows: In the formula: T3—annular fluid temperature, K; — Convection heat transfer coefficient of the outer wall of the oil pipe, W / m 2 ·K; ρ2 — oil pipe density, kg / m 3 ; c2—Specific heat capacity of the oil pipe, J / kg·K; λ2 — Thermal conductivity of the oil pipe, W / (m·K).

10. The method for constructing an unsteady temperature-pressure coupling model for supercritical steam injection wellbore according to claim 3, characterized in that, The annular heat transfer model is expressed as follows: In the formula: T4—Bucket temperature, K; — Convection heat transfer coefficient of the inner wall of the casing, W / (m²) 2 ·K); ρ3—Density of the tubing, kg / m 3 ; c3 — Specific heat capacity of the annular fluid, J / kg·K.

11. The method for constructing an unsteady temperature-pressure coupling model for supercritical steam injection wellbore according to claim 3, characterized in that, The heat transfer model of the composite layer is expressed as follows: In the formula: λ i — Thermal conductivity at different locations, W / (m·K); T i —Temperature at different locations, in K; r i —Radius at different locations, in meters; ρ i —Fluid density at different locations, kg / m³ 3 ; c i —Specific heat capacity of fluid at different locations, J / kg·K; N i —Maximum number of radial subdivisions; i=4 represents casing, i=5 represents cement sheath, and i≥6 represents formation.

12. The method for constructing an unsteady temperature-pressure coupling model for supercritical steam injection wellbore according to claim 3, characterized in that, The continuity conditions include: At the interface between the inner wall of the casing and the annular fluid, the heat transferred by convection between the casing wall and the fluid is equal to the heat transferred by conduction through the casing wall, i.e.: At the interface between different heat-conducting media, the heat introduced is equal to the heat dissipated, that is: 。 13. The method for constructing an unsteady temperature-pressure coupling model for supercritical steam injection wellbore according to claim 3, characterized in that, The convective heat transfer coefficient inside the oil pipe includes: The heat exchange between the fluid inside the oil pipe and the inner wall of the pipe is forced convection heat transfer, which is represented as: 。 14. The method for constructing an unsteady temperature-pressure coupling model for supercritical steam injection wellbore according to claim 3, characterized in that, The annular convective heat transfer coefficient includes: The heat transfer coefficient of natural convection between vertical flat plates is used as an approximation, expressed as: 。 15. The method for constructing an unsteady temperature-pressure coupling model for supercritical steam injection wellbore according to claim 3, characterized in that, The pressure drop model is expressed as follows: In the formula: p1—Fluid pressure inside the tubing, MPa; d1—Inner diameter of the oil pipe, in meters; g—acceleration due to gravity, g = 9.8 m / s² 2 ; f—the coefficient of frictional resistance, dimensionless.

16. The method for constructing an unsteady temperature-pressure coupling model for supercritical steam injection wellbore according to claim 3, characterized in that, The frictional heat source is represented as: In the formula: Δp i — represents the frictional pressure drop gradient, Pa / m; q — volumetric flow rate, m 3 / s.

17. The method for constructing an unsteady temperature-pressure coupling model for supercritical steam injection wellbore according to claim 1, characterized in that, Step S4 further includes determining whether the second wellbore temperature, the second annular natural convection heat transfer coefficient, the second fluid velocity, and the second thermophysical parameter are corresponding data at the bottom of the well.

18. The method for constructing an unsteady temperature-pressure coupling model for supercritical steam injection wellbore according to claim 1, characterized in that, The method also includes performing reasonableness checks and outlier handling on the input data through a data preprocessing module.

19. The method for constructing an unsteady temperature-pressure coupling model for supercritical steam injection wellbore according to claim 1, characterized in that, The method also includes automatically adjusting the discrete grid and calculation parameters based on the wellbore diameter and / or wellbore length and / or reduced diameter section and / or expanded diameter section and / or branch wellbore.

20. A device for constructing an unsteady temperature-pressure coupling model of supercritical steam huff and puff injection wellbore, characterized in that, The device includes: The first module is used to discretize and mesh the temperature node, pressure node and velocity node regions and assign values ​​to each mesh element, load boundary conditions and initial temperature, and preset the first wellbore temperature, the first annular natural convection heat transfer coefficient, the first fluid velocity and the first thermophysical property parameter. The second module is used to solve the motion equations based on the initial conditions and boundary conditions to obtain the pressure values ​​of the wellbore pressure distribution, and to update the second thermophysical parameters using the first wellbore temperature and the pressure values. The third module is used to solve the continuity equation to calculate the second fluid velocity and compare it with the first fluid velocity. If the error is not within the allowable range, the second fluid velocity is used as a new preset value and provided to the second module; otherwise, the second fluid velocity is provided to the fourth module. The fourth module is used to solve the energy conservation equation using the second fluid velocity to obtain the second wellbore temperature and the second annulus natural convection heat transfer coefficient, and compare them with the first wellbore temperature and the first annulus natural convection heat transfer coefficient; if the error is within the allowable range, the calculation is completed; otherwise, the second wellbore temperature is provided as a new preset value to the second module until the result converges.

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