A method and apparatus for determining cement performance parameters for in situ conversion production wells

Abstract

The application relates to the field of oil and gas drilling, and discloses a method and device for determining cement performance parameters of an in-situ conversion production well. The method comprises the following steps: determining wellbore parameters, original formation parameters, operation parameters and ground stress parameters of the in-situ conversion production well; calculating a wellbore temperature field of the production well based on the wellbore parameters, the original formation parameters and the operation parameters; calculating a wellbore cement annulus stress distribution field based on the wellbore temperature field and the ground stress parameters; and determining cement performance parameters based on the wellbore cement annulus stress distribution field and the wellbore temperature field. The method calculates the in-situ conversion wellbore temperature field and the wellbore cement annulus stress distribution field based on the in-situ conversion wellbore parameters, the production operation parameters and the like, accurately determines the cement performance parameters of corresponding well sections according to the temperature distribution field and the cement annulus stress distribution field, and thus improves the design pertinence of the cementing slurry system and reduces the drilling operation cost.

Description

Technical Field

[0001] This invention relates to the field of oil and gas drilling, and specifically to a method and apparatus for determining the performance parameters of cement stone in in-situ conversion production wells. Background Technology

[0002] Medium- and low-maturity shale oil represents a class of unconventional oil and gas resources with enormous potential. Its resource scale far exceeds that of medium- and high-maturity shale oil, with a wide distribution area and numerous formations, making it a crucial area for future oil and gas reserve and production increases. However, due to factors such as underdeveloped organic pores in shale, high oil viscosity, low gas-oil ratio, and the fact that most organic matter exists in solid form, current technologies cannot achieve large-scale commercial development of medium- and low-maturity shale oil. Therefore, horizontal well electric heating and lightweighting technology is needed. This involves directly inserting an electric heater into the horizontal well section to continuously heat the shale formation at ultra-high temperatures, causing various organic materials in the formation to undergo physicochemical changes similar to lightweighting transformations or improved flow characteristics, thereby achieving oil and gas production.

[0003] In this production process, the oil and gas heating temperature exceeds 500℃ or even higher, and the fluid medium temperature can exceed 300℃. This ultra-high temperature heating process places extremely high demands on the integrity of the in-situ conversion wellbore, especially the design of the cement sheath used to seal the annulus between the casing and the formation. Its sealing effect needs to meet the strength change requirements under abnormally high temperature conditions, while also taking into account the strength of the casing and the stress conditions of the formation. A suitable cementing slurry system, excellent temperature resistance, and good mechanical strength properties are crucial.

[0004] In existing technologies, the selection of cement slurry systems for electrically heated in-situ conversion wells and the design of cement sheath strength are generally based on the requirements of heavy oil thermal recovery wells. This is combined with technologies such as prestressed cementing, thermal compensator casing, and thermal recovery casing heads to achieve effective isolation between the casing and the formation annulus. However, this method has a temperature resistance rating below 350℃, with higher temperature resistance requirements in the upper section and lower requirements in the lower section. This is incompatible with the production conditions of electrically heated in-situ conversion wells, which directly heat the target formation to above 500℃, with lower temperatures in the upper section and higher temperatures in the lower section.

[0005] Patent CN 118622207A discloses a cementing method for underground in-situ conversion production wells. This method divides the in-situ conversion wellbore into conventional temperature cementing sections, ultra-high temperature cementing sections, and high temperature cementing sections, and sets the cementing slurry system and temperature resistance performance for different sections according to the approximate temperature distribution range. This method solves the problem of optimizing the cementing slurry for different sections to a certain extent, but it lacks accurate selection and design basis for cement stone performance parameters.

[0006] Therefore, there is an urgent need in this field to study a more precise and accurate method for determining the performance parameters of cement stone in in-situ conversion production wells. Summary of the Invention

[0007] In view of the above-mentioned problems in the existing technology, the main objective of the present invention is to provide a method and apparatus for determining the performance parameters of cement stone in in-situ conversion production wells.

[0008] According to the present invention, a method for determining the performance parameters of cement stone in in-situ conversion production wells is provided, the method comprising the following steps: Determine the wellbore parameters, original formation parameters, in-situ conversion production operation parameters, and geostress parameters of the in-situ conversion production well; The wellbore temperature field of the production well is calculated based on the wellbore parameters, the original formation parameters, and the operating parameters. Based on the wellbore temperature field and the geostress parameters, the stress distribution field of the cement sheath in the production well is calculated. The performance parameters of the cement stone are determined based on the stress distribution field of the cement ring in the wellbore and the temperature field in the wellbore.

[0009] According to one embodiment of the present invention, calculating the wellbore temperature field of a production well based on the wellbore parameters, the original formation parameters, and the operating parameters includes: Based on the wellbore parameters, the production well is divided into four sections: the guide section, the surface casing section, the technical casing section, and the production casing section. The total heat transfer coefficient per unit length of the wellbore perimeter in different well sections is calculated based on the wellbore parameters. Based on the overall heat transfer coefficient around the wellbore, the original formation parameters, and the operating parameters, the wellbore temperature at different depths is calculated sequentially from the bottom of the well to the wellhead.

[0010] According to one embodiment of the present invention, calculating the total heat transfer coefficient per unit length of the wellbore perimeter for different well sections based on the wellbore parameters includes: calculating the total thermal resistance per unit length of each component according to the radial composition of each well section in the guide section, the surface casing section, the technical casing section, and the production casing section and the wellbore parameters, and then determining the total heat transfer coefficient per unit length of the wellbore perimeter based on the total thermal resistance per unit length.

[0011] According to one embodiment of the present invention, the wellbore temperature includes the fluid temperature inside the wellbore, the casing temperature of adjacent formations in each well section, the cement sheath first interface temperature, and the cement sheath second interface temperature.

[0012] According to one embodiment of the present invention, calculating the wellbore temperature at different depths sequentially from the bottom of the well to the wellhead based on the overall heat transfer coefficient around the wellbore, the original formation parameters, and the operating parameters includes: In the radial direction of the wellbore, based on the steady-state heat transfer equation from the wellbore to the cement sheath interface per unit length, the unsteady-state heat transfer equation from the outer edge of the cement sheath to the formation per unit length, and the continuity condition that the heat is equal in the steady-state and unsteady-state heat transfer stages, the relationship between the temperature of the cement sheath interface and the temperature of the fluid inside the wellbore is determined. Based on the principle of energy conservation, a differential equation for the axial temperature field of the wellbore is established. The temperature of the cement sheath interface is substituted into the differential equation for the axial temperature field. Combined with the bottom boundary conditions, the fluid temperature inside the wellbore at the outlet end of each well section is calculated segment by segment. The fluid temperature inside the wellbore at the outlet end of the lower well section is taken as the fluid temperature inside the wellbore at the inlet end of the upper well section connected to it, and the fluid temperature inside the wellbore at each depth in each well section is calculated. In the radial direction of the wellbore, the temperature of the cement sheath interface is calculated based on the relationship between the temperature of the fluid inside the wellbore and the temperature of the cement sheath interface with the temperature of the fluid inside the wellbore. Based on the fluid temperature inside the wellbore and the interface temperature of the cement sheath, the casing temperature and the interface temperature of the cement sheath in each well section are calculated using interpolation or steady-state heat transfer equations.

[0013] According to one embodiment of the present invention, calculating the stress distribution field of the wellbore cement sheath of the production well based on the wellbore temperature field and the geostress parameters includes: using the wellbore temperature field as the thermal load input condition for the stress distribution field of the wellbore cement sheath, and combining the geostress parameters to establish a model of the stress distribution field of the wellbore cement sheath of the production well using the finite element method.

[0014] According to one embodiment of the present invention, the geostress parameters include the horizontal maximum principal stress and the vertical geostress. The temperature parameter used to construct the stress distribution field model of the wellbore cement sheath of the production well is the highest temperature of the section to be cemented. The highest temperature is obtained by solving the temperature field of the wellbore corresponding to the section to be cemented.

[0015] According to one embodiment of the present invention, the method further includes using the wellbore cement sheath stress distribution field model to calculate the cement sheath stress field under different combinations of geostress, extracting the average stress on the cement sheath, and drawing the average stress map of the cement sheath under temperature field conditions.

[0016] According to one embodiment of the present invention, determining the cement stone performance parameters based on the wellbore cement sheath stress distribution field and the wellbore temperature field includes: obtaining the predicted stress magnitude of the cement sheath at the actual cementing layer through a stress map based on the actual cementing layer temperature, the maximum horizontal principal stress and the vertical ground stress, and selecting a cement slurry system with a compressive strength higher than the predicted stress of the cement sheath and a temperature resistance greater than the wellbore temperature of the corresponding well section.

[0017] According to another aspect of the present invention, an apparatus for determining the performance parameters of cement stone in in-situ conversion production wells is provided, the apparatus comprising: The basic parameter determination unit is configured to determine the wellbore parameters, original formation parameters, in-situ conversion production operation parameters, and geostress parameters of the in-situ conversion production well. The wellbore temperature field determination unit is configured to calculate the wellbore temperature field of the production well based on the wellbore parameters, the original formation parameters, and the operating parameters. The wellbore cement sheath stress distribution field determination unit is configured to calculate the wellbore cement sheath stress distribution field of the production well based on the wellbore temperature field and the geostress parameters. The cement stone performance parameter determination unit is configured to determine the cement stone performance parameters based on the stress distribution field of the wellbore cement sheath and the temperature field of the wellbore.

[0018] Compared with existing technologies, the method and apparatus of this invention have at least the following advantages: This invention calculates the temperature field and cement sheath stress distribution field of the in-situ conversion wellbore based on in-situ conversion wellbore parameters and in-situ conversion production operation parameters. Based on these temperature and cement sheath stress distribution fields, it accurately determines the cement stone performance parameters for the corresponding well section, thereby improving the design specificity of the cement slurry system and avoiding excessively high strength and temperature designs. This enhances the performance design and operational specificity of in-situ conversion cement slurry for medium- and low-maturity shale oil horizontal wells, while simultaneously reducing drilling operation costs. Furthermore, this invention employs a graphical prediction method, making the prediction results more intuitive and facilitating quick and accurate identification of prediction results by on-site construction personnel. The graphical prediction method is also more universally applicable, capable of being used simultaneously for multiple conversion wells with similar production environments. Attached Figure Description

[0019] 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 these drawings without creative effort.

[0020] Figure 1 A schematic diagram of the in-situ electrothermal conversion technology is shown. Figure 2 A schematic diagram illustrating the integrity requirements of the in-situ conversion wellbore is shown. Figure 3 A general flowchart of a method for determining the performance parameters of cement stone in in-situ conversion production wells according to an embodiment of the present invention is shown; Figure 4 A schematic diagram of the wellbore structure for in-situ conversion production wells according to an embodiment of the present invention is shown; Figure 5 A schematic flowchart illustrating the calculation of the temperature field of an in-situ conversion production wellbore according to an embodiment of the present invention is shown. Figure 6 A schematic diagram of the temperature field in the wellbore of an in-situ conversion production well according to an embodiment of the present invention is shown; Figure 7 A schematic diagram of the finite element calculation model for different well sections according to an embodiment of the present invention is shown; Figure 8 A schematic diagram of the stress field distribution of the cement sheath in the wellbore of an in-situ conversion production well according to an embodiment of the present invention is shown. Figure 9 A schematic diagram of the stress distribution of a cement ring according to an embodiment of the present invention is shown. Detailed Implementation

[0021] To make the objectives, technical solutions, and advantages of this invention clearer, the invention will be further described in detail below with reference to specific embodiments. It should be understood that the specific embodiments described herein are merely illustrative and not intended to limit the invention.

[0022] The terms "comprising" and "having," and any variations thereof, used in the specification and accompanying drawings of this invention are intended to cover non-exclusive inclusion; the terms "first," "second," etc., used in the specification and accompanying drawings of this invention are used to distinguish different objects, not to describe a particular order. "A plurality of" means two or more, unless otherwise explicitly specified.

[0023] Furthermore, the reference to "embodiment" herein means that a particular feature, structure, or characteristic described in connection with an embodiment may be included in at least one embodiment of the invention. The appearance of this phrase in various places throughout the specification does not necessarily refer to the same embodiment, nor is it a separate or alternative embodiment mutually exclusive with other embodiments. It will be explicitly and implicitly understood by those skilled in the art that the embodiments described herein can be combined with other embodiments.

[0024] like Figure 1 As shown, the medium-to-low maturity shale oil 2 is unsuitable for large-scale commercial development due to factors such as underdeveloped organic pores in the shale formation 21, high oil viscosity, low gas-oil ratio, and the presence of most organic matter in solid form. Therefore, existing technologies cannot achieve this. Horizontal well electric heating and lightening technology is required. An electric heater is directly inserted into the horizontal section of the heating well 3 to continuously heat the shale formation 21 at ultra-high temperatures. This causes various organic materials in the formation to undergo physicochemical changes similar to lightening or improved flow characteristics. The resulting oil and gas are then extracted through a production well 1 near the heating well 3, thus achieving oil and gas production.

[0025] like Figure 2As shown, the heating temperature in heating zone 22 during oil and gas production exceeds 500℃, or even higher, and the fluid medium temperature may exceed 300℃. This ultra-high temperature heating process places extremely high demands on the integrity of the in-situ conversion wellbore, especially the design of the cement sheath 4 used to seal the annulus between the casing 41 and the formation 42. Its sealing effect needs to meet the strength change requirements under abnormally high temperature conditions, while also taking into account the strength of the casing and the stress conditions of the formation. A suitable cementing slurry system, excellent temperature resistance, and good mechanical strength performance design are crucial.

[0026] As mentioned above, existing technologies generally select the cement slurry system for electrically heated in-situ conversion wells and design the strength of the cement sheath according to the requirements of heavy oil thermal recovery wells. This is combined with prestressed cementing, thermal compensator casing, and thermal recovery casing heads to achieve effective isolation between the casing and the formation annulus. However, this method has a temperature resistance level below 350℃, with higher temperature resistance requirements in the upper section and lower requirements in the lower section. In contrast, electrically heated in-situ conversion wells directly heat the target formation to over 500℃. The upper section, being farther from the electric heater, has a lower temperature, while the lower section, being closer to the heater, has a higher temperature. Therefore, electrically heated in-situ conversion wells are incompatible with the production conditions of heavy oil thermal recovery wells. Designing them according to the cementing methods for heavy oil thermal recovery wells makes it difficult to meet the sealing performance and mechanical integrity requirements of the cement sheath under ultra-high temperature and reverse temperature gradient conditions, posing a risk of wellbore failure.

[0027] Therefore, there is a need to establish a method for accurately determining the performance parameters of cement stone in in-situ conversion wells that takes wellbore temperature into account. To address the above problem, this invention provides a method and apparatus for determining the performance parameters of cement stone in in-situ conversion production wells. This method solves or partially solves the problem of accurately considering wellbore temperature when determining the performance parameters of cement stone in in-situ conversion of medium- and low-maturity shale oil horizontal wells. Its aim is to determine the performance parameters of the cement stone used to seal the annulus between the casing and the formation.

[0028] A first aspect of this invention provides a method for determining the performance parameters of cement stone in in-situ conversion production wells, such as... Figure 3 As shown, the method for determining the performance parameters of cement stone in in-situ conversion production wells generally includes the following steps: Step S100: Determine the wellbore parameters, original formation parameters, in-situ conversion production operation parameters, and geostress parameters of the in-situ conversion production well; Step S200: Calculate the wellbore temperature field of the production well based on wellbore parameters, original formation parameters, and operational parameters; Step S300: Calculate the stress distribution field of the cement sheath in the production well based on the wellbore temperature field and geostress parameters; Step S400: Determine the cement stone performance parameters for the corresponding well section based on the cement sheath stress distribution field and the wellbore temperature field.

[0029] This invention calculates the temperature field and cement sheath stress distribution field of the in-situ conversion wellbore based on in-situ conversion wellbore parameters and in-situ conversion production operation parameters. Based on the temperature distribution field and cement sheath stress distribution field, it accurately determines the cement stone performance parameters of the corresponding well section, thereby improving the design targeting of the cement slurry system, avoiding excessively high strength and temperature designs, improving the performance design and operation targeting of in-situ conversion cement slurry in medium and low maturity shale oil horizontal wells, and reducing drilling operation costs.

[0030] The following is a detailed description of each step of the method for determining the performance parameters of cement stone in in-situ conversion production wells according to the present invention.

[0031] In step S100, the wellbore parameters, original formation parameters, in-situ conversion production operation parameters, and geostress parameters of the in-situ conversion production well are determined.

[0032] In some embodiments, wellbore parameters may specifically include wellbore structural parameters, wellbore trajectory parameters, production tubing parameters, etc.

[0033] Furthermore, such as Figure 4 As shown, the wellbore structural parameters may include the dimensions of the drill bit 32 and the depth reached for each drilling operation, the corresponding outer diameter, wall thickness, material, and running depth of the casing 41, the return height requirements of the cement 33 for each drilling operation, and the cement slurry system. The dimensions of the drill bit 32 and the depth reached for each drilling operation can be used to determine the wellbore diameter and drilling depth, providing geometric and depth basis for subsequently determining the filling space of the cement slurry and dividing different well sections. The corresponding casing outer diameter, wall thickness, and running depth, combined with the drill bit dimensions, can further determine the actual space of the casing annulus. The outer diameter and wall thickness are used to calculate the thermal resistance per unit length of the casing and its radial heat transfer characteristics, while the running depth is used for well section division. The casing thermal conductivity λ can be determined based on the material of the casing 41. t The size of the casing annulus and the space for cement slurry can be determined based on the dimensions of drill bit 32 and the outer diameter of casing 41; the thermal conductivity λ of cement stone can be determined based on the cement slurry system. c .

[0034] Wellbore trajectory parameters can include the well depth, inclination, and azimuth values ​​along the wellbore axis 34 at predetermined intervals from the wellhead to the bottom. Well depth can be used to divide the wellbore into axial segments and as the basis for locating the inlet and outlet depths of each segment in temperature and stress field calculations. Combining well depth and inclination, the vertical depth of each measurement point can be calculated, and then, based on the original geothermal gradient g... T Calculate the formation temperature T at this depth. eWell inclination and azimuth are used to determine the spatial shape of the wellbore trajectory. In finite element stress analysis, the geostress field needs to be transformed from the geodetic coordinate system to the wellbore coordinate system in order to correctly load the far-field stress acting on the casing-cement sheath-formation assembly, thereby accurately calculating the stress distribution of the cement sheath.

[0035] Production tubing parameters may include the material, outer diameter and wall thickness or inner diameter of the production tubing, and the annular medium between the production tubing and the production casing. The production tubing may include tubing. The thermal conductivity λ of the production tubing can be determined based on its material. o The thermal conductivity λ of the annular medium between the production tubing and the production casing can be determined based on this information. a .

[0036] In some embodiments, the original formation parameters may include the original bottom hole temperature T. y and the original geothermal gradient g T The original bottom hole temperature T can be obtained based on the geological reservoir design of the research area. y and the original geothermal gradient g T It can also be obtained through oil and gas well testing. Alternatively, it can be based on the original geothermal gradient g. T The original bottom hole temperature T at the corresponding vertical well depth is calculated from the vertical well depth. y When calculating the in-situ conversion wellbore temperature field, it is necessary to base it on the original bottom hole temperature T. y and the original geothermal gradient g T Determine formation temperature T e .

[0037] In some embodiments, the operational parameters for in-situ conversion production include: the depth and thickness of the target formation, the temperature and yield of the production fluid, and the heating temperature and heating distribution interval of the heating well. The depth and thickness of the target formation are used to determine the vertical depth and longitudinal range of the heating well interval, thereby clarifying the initial formation temperature and geothermal gradient application range of the target formation. The temperature T of the hot fluid inside the production wellbore can be determined based on the temperature of the production fluid. f The mass flow rate w of the hot fluid in the production wellbore can be determined based on the production fluid output. t The heating temperature of a heating well is the temperature provided by the heat medium. The heating distribution section of a heating well is the section heated by the heat medium in the well, generally a horizontal section, but it can also be a partially directional section or a partially vertical section. The heating temperature is determined based on the depth and thickness of the target layer in the in-situ conversion, the heating temperature of the heating well, and the heating distribution section, combined with the original bottom hole temperature T. y and the original geothermal gradient g T The wellbore temperature field of a heated well can be constructed. Based on the wellbore temperature field of the heated well and the position of the production well relative to the heated well, the formation temperature T at various depths around the production well can be determined.e Alternatively, other methods known in the art can be used to determine the formation temperature T at various depths surrounding the production well. e .

[0038] In some embodiments of the present invention, the geostress parameters mainly refer to the geostress parameters of the drilled formations at different well depths, including the maximum horizontal principal stress, the minimum horizontal principal stress, and the vertical stress. The maximum horizontal principal stress, the minimum horizontal principal stress, and the vertical stress can be real data obtained through other testing or analysis, or they can be preset combinations of horizontal principal stresses under different conditions.

[0039] In step S200, the wellbore temperature field of the production well is calculated based on the wellbore parameters, the original formation parameters, and the operating parameters.

[0040] like Figure 5 As shown, calculating the wellbore temperature field of an in-situ conversion production well can include: Step S210: Divide the production well into four sections based on the wellbore parameters: the guide pipe section, the surface casing section, the technical casing section, and the production casing section. Step S220: Calculate the total radial heat transfer coefficient per unit length of the wellbore perimeter for different well sections based on wellbore parameters; Step S230: Based on the total heat transfer coefficient around the wellbore, the original formation parameters, and the operating parameters, calculate the wellbore temperature at different depths from the bottom of the well to the wellhead.

[0041] In step S210, as Figure 4 As shown, the production well is divided into four sections based on wellbore parameters: guide section 51, surface casing section 52, technical casing section 53, and production casing section 54. The technical casing section 53 can be further subdivided according to the layers of the technical casing. For example, if there is only one layer of technical casing, it is divided into one section; if there are multiple layers of technical casing, it can be divided into multiple sections.

[0042] like Figure 4 As shown, the guide pipe section 51 is the section from the wellhead to the guide shoe. From the wellbore axis radially outward, it generally includes the tubing hole 601, tubing 602, oil casing annulus 603, oil layer casing 604, oil casing and technical casing annulus 605, nth technical casing 6061, n-1th technical casing annulus 6062, n-1th technical casing 6063, n-2th technical casing annulus 6064, ..., 1st technical casing 606, technical and surface casing annulus 607, surface casing 608, surface casing and guide pipe annulus 609, guide pipe 610, cement sheath 611, and formation 612.

[0043] like Figure 4As shown, the surface casing section 52 is the well section between the guide shoe and the bottom of the surface casing. From the wellbore axis outward, it generally includes the tubing hole 601, tubing 602, oil casing annulus 603, oil layer casing 604, oil casing and technical casing annulus 605, nth technical casing 6061, n-1th technical casing annulus 6062, n-1th technical casing 6063, n-2th technical casing annulus 6064, ..., 1st technical casing 606, technical and surface casing annulus 607, surface casing 608, cement sheath 611, and formation 612.

[0044] like Figure 4 As shown, the technical casing section 53 can be divided into n sub-segments according to the number of technical casings n. The i-th technical casing section is the well section from the bottom end of the (i-1)-th layer of technical casing to the bottom end of the i-th layer of technical casing. From the wellbore axis outward, it generally includes the tubing hole 601, tubing 602, oil-casing annulus 603, oil layer casing 604, oil-casing and technical casing annulus 605, n-th layer of technical casing 6061, (n-1)-th layer of technical casing annulus 6062, (n-1)-th layer of technical casing 6063, (n-2)-th layer of technical casing annulus 6064, ..., i-th layer of technical casing 606, cement sheath 611, and formation 612. i is a positive integer, and i≤n. When i=1, the 0th layer of technical casing is actually represented as the surface casing 608.

[0045] like Figure 4 As shown, the production section 54 is the well section from the bottom of the innermost technical casing to the lowest position of the oil layer casing 604. From the wellbore axis outward, it generally includes the tubing hole 601, tubing 602, oil-casing annulus 603, oil layer casing 604, cement sheath 611, and formation 612.

[0046] The value of n is generally between 0 and 6.

[0047] During oil and gas production operations, the tubing hole 601 typically contains the produced oil and gas heat medium. The annulus 603 (oil casing and casing), 605 (oil casing and technical casing), 6062 and 6064 (technical casing and casing), 607 (technical casing and surface casing), and 609 (surface casing and guide pipe annulus) typically contain cementing sheaths, but may also contain other media such as protective fluid, completion fluid, protective gas, or air.

[0048] In step S220, the total heat transfer coefficient per unit length of the wellbore perimeter in the radial direction of the guide pipe section 51, the surface casing section 52, the technical casing section 53, and the production casing section 54 is calculated. Specifically, the total thermal resistance and total heat transfer coefficient per unit length of each component are calculated based on the radial composition of different well sections of the guide pipe section 51, the surface casing section 52, the technical casing section 53, and the production casing section 54.

[0049] The convective heat transfer resistance R between the hot fluid and the oil pipe per unit length of the oil pipe hole 601 c The calculation method is as follows: Formula (1), where, h1 represents the convective heat transfer coefficient, with the unit of W / (m 2 ·℃), and it can be obtained by querying the corresponding heat transfer coefficient according to the production fluid output of the in-situ conversion production well, the inner diameter of the tubing, and the production fluid components; r oilin represents the inner diameter of the tubing, with the unit of m, and it can be obtained according to the wellbore parameters of the in-situ conversion production well.

[0050] The thermal resistance R of the tubing per unit length 602 o is calculated as follows: Formula (2), where, λ o represents the thermal conductivity of the tubing, with the unit of W / (m·℃), and it can be obtained by querying the corresponding thermal conductivity according to the tubing material of the in-situ conversion production well; r oilout represents the outer diameter of the tubing, with the unit of m, and it can be obtained according to the wellbore parameters of the in-situ conversion production well.

[0051] The calculation method of the thermal resistance R1 of the annulus between the tubing and the casing per unit length 603 is as follows: Formula (3), where, λ a represents the thermal conductivity of the annulus medium, with the unit of W / (m·℃), and it is specifically obtained by querying the corresponding thermal conductivity according to the type of the medium; r pin represents the inner diameter of the production casing, with the unit of m, and it can be obtained according to the wellbore parameters of the in-situ conversion production well.

[0052] The calculation method of the thermal resistance R2 of the production casing per unit length 604 is as follows: Formula (4), where, λ1 represents the thermal conductivity of the production casing, with the unit of W / (m·℃), and it can be specifically obtained by querying the corresponding thermal conductivity according to the production casing material of the in-situ conversion well; r pout represents the outer diameter of the production casing, with the unit of m, and it can be obtained according to the wellbore parameters of the in-situ conversion production well.

[0053] The thermal resistance R of the annulus of the i-th layer of technical casing per unit length 3i is calculated as follows: Formula (5), where, λ 2ia represents the thermal conductivity of the medium in the annulus of the i-th layer of technical casing, with the unit of W / (m·℃), i < n, and it can be obtained by querying the corresponding thermal conductivity according to the type of the medium; rin i represents the inner diameter of the i-th layer of technical casing, with the unit of m, and it can be obtained according to the wellbore parameters of the in-situ conversion production well; rout i+1This represents the outer diameter of the (i+1)th layer of technical casing, in meters (m). It can be obtained by in-situ conversion of the wellbore parameters of the production well. When i is n, rout i+1 This is the outer diameter of the oil layer casing.

[0054] The thermal resistance R of the i-th layer of technical sleeve per unit length is 606. 4i The calculation method is as follows: Formula (6), In the formula, λ 3i This represents the thermal conductivity of the i-th layer of technical casing, expressed in W / (m·℃), where i ≤ n. The thermal conductivity can be obtained by looking up the corresponding thermal conductivity based on the material of the technical casing in the in-situ conversion production well. i This represents the inner diameter of the i-th layer of technical casing, in meters (m), and can be obtained from the wellbore parameters of the production well converted in situ; rout i This represents the outer diameter of the i-th layer of technical casing, in meters, which can be obtained based on the wellbore parameters of the production well converted in situ.

[0055] The calculation method for the thermal resistance R5 of the 607 gauge ring per unit length is as follows: Formula (7), In the formula, λ4 represents the thermal conductivity of the medium in the annulus between the technical casing and the surface casing, in units of W / (m·℃), which can be obtained by looking up the corresponding thermal conductivity according to the type of medium; r5 represents the inner diameter of the surface casing, in units of m, which can be obtained according to the wellbore parameters of the in-situ conversion production well; r4 represents the outer diameter of the first layer of technical casing, in units of m, which can be obtained according to the wellbore parameters of the in-situ conversion production well.

[0056] The calculation method for the thermal resistance R6 per unit length of 608 surface sleeve is as follows: Formula (8), In the formula, λ3 represents the thermal conductivity of the surface casing, in units of W / (m·℃), which can be obtained by looking up the corresponding thermal conductivity based on the surface casing material of the in-situ conversion production well; r5 represents the inner diameter of the surface casing, in units of m, which can be obtained based on the wellbore parameters of the in-situ conversion production well; r6 represents the outer diameter of the surface casing, in units of m, which can be obtained based on the wellbore parameters of the in-situ conversion production well.

[0057] The calculation method for the thermal resistance R7 of the unit length gauge sleeve and the annulus 609 of the conduit is as follows: Formula (9), In the formula, λ5 represents the thermal conductivity of the annulus medium between the casing and the conduit, in units of W / (m·℃), which can be obtained by looking up the corresponding thermal conductivity according to the type of medium; r6 represents the outer diameter of the surface casing, in units of m, which can be obtained according to the wellbore parameters of the in-situ conversion production well; r7 represents the inner diameter of the conduit, in units of m, which can be obtained according to the wellbore parameters of the in-situ conversion production well.

[0058] The calculation method for the thermal resistance R8 per unit length of a 610 conduit is as follows: Formula (10), In the formula, λ6 represents the thermal conductivity of the conduit, in units of W / (m·℃), which can be obtained by looking up the corresponding thermal conductivity based on the conduit material of the in-situ conversion production well; r7 represents the inner diameter of the conduit, in units of m, which can be obtained based on the wellbore parameters of the in-situ conversion production well; r8 represents the outer diameter of the conduit, in units of m, which can be obtained based on the wellbore parameters of the in-situ conversion production well.

[0059] The calculation method for the thermal resistance R9 per unit length of a 611 cement ring is as follows: Formula (11), In the formula, λ7 represents the thermal conductivity of the cement sheath, in W / (m·℃), which can be obtained by looking up the corresponding thermal conductivity according to the type of cement slurry system; r9 represents the outer diameter of the interface between the cement sheath and the formation (cementing interface), in meters, which is approximately the same as the formation well diameter corresponding to the cement sheath, and can be obtained based on the wellbore parameters of the in-situ converted production well; r 10 This represents the inner diameter of the interface between the cement sheath and the guide pipe (cementing-conducting interface), expressed in meters (m). It is approximately the same as the outer diameter of the guide pipe corresponding to the cement sheath and can be obtained by in-situ conversion of the wellbore parameters of the production well.

[0060] Taking the outer diameter r2 of the 604 casing of the oil layer as the reference, then: The total thermal resistance R per unit length of the guide pipe section 51 around the wellbore C The calculation method is as follows:

[0061] Formula (12).

[0062] The total thermal resistance R of the wellbore perimeter per unit length of section 52 is shown in the table. s The calculation method is as follows:

[0063] Formula (13).

[0064] The total thermal resistance R of the wellbore perimeter of the 53 unit length section of the i-th layer is... i The calculation method is as follows:

[0065] Formula (14).

[0066] Total thermal resistance R of 54 unit length wellbore in the production section p The calculation method is as follows:

[0067] Formula (15).

[0068] Next, the total heat transfer coefficient U per unit length of the wellbore is calculated based on the total thermal resistance R around the wellbore per unit length of each well section.

[0069] The overall heat transfer coefficient U per unit length of the guide pipe section is 51. c The calculation method is as follows:

[0070] Formula (16).

[0071] The total heat transfer coefficient U of the wellbore perimeter per unit length of section 52 is... s The calculation method is as follows:

[0072] Formula (17).

[0073] The total heat transfer coefficient U of the 53 unit length wellbore perimeter in the i-th layer technical section i The calculation method is as follows:

[0074] Formula (18).

[0075] The overall heat transfer coefficient U of the wellbore perimeter in the production section is 54 units. p The calculation method is as follows:

[0076] Formula (19).

[0077] In step S230, the wellbore temperature at different depths is calculated sequentially from the bottom of the well to the wellhead based on the overall heat transfer coefficient around the wellbore, the original formation parameters, and the operating parameters. The wellbore temperature at different depths mainly includes the fluid temperature inside the wellbore, the casing temperature (the "casing" refers to the casing closest to the formation in each well section, also referred to as the "casing adjacent to the formation" in this paper), the cement sheath first interface temperature, and the cement sheath second interface temperature. Based on the bottom-of-well boundary conditions, the temperature field of the wellbore is obtained by calculating sequentially from the bottom of the well. The relevant calculations involve three main parts: steady-state heat transfer radially from the wellbore to the cement sheath second interface, unsteady-state heat transfer from the cement sheath second interface to the deep formation, and axial heat transfer in the wellbore.

[0078] The steady-state heat transfer calculation method per unit length of wellbore to the cement sheath interface is as follows: Formula (20), In the formula, T f T represents the temperature of the fluid inside the wellbore, in °C. h U represents the temperature at the interface, in °C; U represents the overall heat transfer coefficient per unit length of the wellbore, in W / (m²). 2 ℃), select the appropriate calculation formula based on the well section corresponding to the well depth z (i.e., U above). c U s U i or U p The overall heat transfer coefficient U per unit length of wellbore (i.e., U mentioned above) is calculated using the formula. c U s U i or U p (Determined based on the well section).

[0079] In the radial direction of the wellbore, the unsteady heat transfer equation from the outer edge of the cement sheath 611 per unit length to the formation 612 is as follows: Formula (21), In the formula, λ e This represents the thermal conductivity of the formation, expressed in W / (m²). (℃), obtained by consulting relevant parameters based on stratigraphic lithology; T e The formation temperature, expressed in °C, is calculated based on original formation parameters and operational parameters; f(t) represents the formation heat conduction time function and is calculated using the following formula: Formula (22), Where α represents the formation thermal diffusivity, m 2 / s; t represents time, in seconds.

[0080] Due to the continuity condition, the amount of heat transferred in the steady-state heat transfer stage is equal to that in the unsteady-state heat transfer stage, thus T is obtained. h As shown below: Formula (23).

[0081] Regarding the axial temperature field of the wellbore, with the wellhead as the origin, the heat flowing into the infinitesimal element dz per unit time at well depth z is Q(z), the heat flowing out of the infinitesimal element is Q(z-dz), and the heat loss within the infinitesimal element is dQ. The following relationship is determined by the law of conservation of energy: Formula (24),

[0082] In the formula, wt This represents the mass flow rate of the hot fluid in the wellbore, expressed in kg / s, and is obtained based on in-situ conversion production operation parameters; C pm T represents the specific heat capacity at constant pressure of a fluid, expressed in J / (kg·℃). It can be obtained by consulting relevant literature after acquiring the fluid composition parameters based on the in-situ conversion production operation parameters. f This indicates the temperature of the hot fluid in the well section, expressed in °C.

[0083] Based on the steady-state heat transfer calculation formula from the radial direction of the wellbore to the cement sheath interface per unit length and the relationship determined by the above energy conservation, we can obtain: Formula (25).

[0084] Set the specific heat capacity C of the fluid at constant pressure in each well section. pm Given that the total thermal resistance R and the total heat transfer coefficient U per unit length of the wellbore remain constant, the boundary conditions at the well section inlet are as follows: .

[0085] At the bottom of the well, the temperature of the hot fluid in the wellbore is the same as the formation temperature. Therefore, the boundary conditions at the bottom of the well are: Where H is the bottom depth and T is the bottom depth. eb This refers to the formation temperature at the bottom of the well.

[0086] Combining formula (23) and boundary conditions, the solution is as follows:

[0087] Formula (26); Among them, T fout T represents the temperature of the fluid inside the wellbore at the well outlet, in °C. eout Z represents the formation temperature at the well outlet, in °C. in Z represents the well depth at the well entrance, in meters (m). out Indicates the well depth at the outlet end of the well section, in meters; T fin T represents the temperature of the fluid inside the wellbore at the well inlet, in °C. ein This indicates the formation temperature at the well entrance, in °C.

[0088] For production section 54, the fluid temperature inside the wellbore at the inlet end of the section is equal to the formation temperature at the bottom of the well, i.e., T fin-54 =T eb The fluid temperature T at the wellbore outlet of section 54 is calculated using the formula (26) above. fout-54 T fout-54 Further, the fluid temperature inside the wellbore at the inlet end of section 53, i.e., T, is taken as the reference value. fout-54 =Tfin-53 Then calculate the fluid temperature T inside the wellbore at the outlet end of section 53. fout-53 This process is repeated to calculate the fluid temperature inside the wellbore at the inlet end of each well section.

[0089] The fluid temperature inside the wellbore at different depths within the same well section is calculated using the following formula: Formula (27), Among them, T fz T represents the temperature of the hot fluid in the wellbore at depth z, in °C. ez Z represents the formation temperature at well depth z, in °C. in Z represents the well depth at the well inlet, in meters; Z represents the well depth at the temperature location to be determined, in meters; T fin T represents the temperature of the fluid inside the wellbore at the well inlet, in °C. ein This represents the formation temperature at the wellhead, expressed in °C. Based on this, the wellbore fluid temperature at different depths from the bottom to the wellhead can be calculated.

[0090] Further, it can be based on the wellbore thermal fluid temperature T at well depth z. fz The temperature T at the cement sheath interface at well depth z is calculated using formula (23). h Based on the wellbore thermal fluid temperature T at well depth z fz By utilizing the radial thermal resistance of each layer and the continuity of heat flow through steady-state heat transfer, the temperature drop is calculated layer by layer to obtain the cement sheath interface temperature and the casing temperature of the adjacent formation at well depth z. For example, the steady-state heat transfer equation (20) can be used to calculate the cement sheath interface temperature and the casing temperature of the adjacent formation. Alternatively, since the cement sheath is relatively thin, its heat transfer can be regarded as one-dimensional steady-state heat conduction. The temperatures of the hot fluid and the cement sheath interface have been calculated, which can be simplified to calculating the cement sheath interface temperature and the casing temperature of the adjacent formation by interpolation.

[0091] Figure 6 A schematic diagram of the temperature field of an in-situ conversion production wellbore according to a specific example of the present invention is shown.

[0092] In step S300, the stress distribution field of the wellbore cement sheath is calculated based on the wellbore temperature field and geostress parameters.

[0093] The wellbore temperature field is used as the thermal load input condition for the wellbore cement sheath stress distribution field. Combined with the geostress parameters, the finite element method is used to establish a wellbore cement sheath stress distribution field model for the production well.

[0094] Specifically, the entire production wellbore can be divided into multiple sub-units ranging from 0.01 to 10 meters, with the sub-units appropriately densified based on points of structural change (such as changes in casing layers, cement sheath properties, and abrupt temperature gradients) to ensure that material properties, temperature, and in-situ stress are approximately uniform within each unit. For each sub-unit, a two-dimensional or three-dimensional finite element model is established. In the finite element model, the in-situ stress field at the corresponding well depth needs to be applied. The calculated temperature field at that unit depth (including fluid temperature, casing temperature, cement sheath first interface temperature, second interface temperature, and formation temperature) is applied as temperature boundary conditions to each node of the model. Steady-state or transient thermo-mechanical coupling analysis is then performed using finite element software to obtain the stress distribution of the cement sheath at different depths. The finite element model can be based on existing commercial software or custom-developed software.

[0095] Figure 7 A finite element model according to a specific application example of the present invention is shown in the figure. The finite element model includes, but is not limited to, the formation, cement sheath, casing model, and the corresponding boundary conditions, temperature field, and mesh generation.

[0096] Finite element methods are used to establish finite element models for different well sections. Establishing finite element models for different well sections of a production well requires adding in-situ stress parameters of the drilled formation at the corresponding well depth. The parameters for establishing finite element models for different well sections of a production well can include horizontal in-situ stress, vertical in-situ stress, and temperature parameters. Horizontal in-situ stress can be a combination of the maximum and minimum horizontal principal stresses, such as their average value. Furthermore, to improve safety, the maximum horizontal principal stress can be used. The temperature parameter is the highest temperature of the well section to be cemented, which can be obtained by solving for the temperature of the well section to be cemented using the aforementioned temperature field.

[0097] The horizontal in-situ stress was calculated using the maximum principal stress and a finite element model. The stress field of the cement sheath under different combinations of in-situ stresses was obtained based on the wellbore temperature field. Figure 8 A schematic diagram of the stress field distribution of a cement ring according to a specific application example of the present invention is shown. By extracting the average stress on the cement ring, a map of the average stress of the cement ring under temperature field conditions is plotted. Figure 9 A schematic diagram of a cement sheath stress map according to a specific application example of the present invention is shown. The cement sheath stress map can be a series of contour lines with horizontal stress as the abscissa and vertical stress as the ordinate. Based on the actual cementing layer's temperature, horizontal stress, and vertical stress, the predicted stress magnitude of the cement sheath at that layer can be obtained through the stress map.

[0098] In step S400, the cement stone performance parameters for the corresponding well section are determined based on the cement ring stress distribution field and the wellbore temperature field.

[0099] Specifically, based on the actual temperature, horizontal and vertical stress of the cementing layer, the predicted stress of the cement sheath in that layer is obtained through a stress map.

[0100] Specifically, a cement slurry system with a compressive strength higher than the predicted stress of the cement sheath and a temperature resistance greater than the wellbore temperature of the corresponding well section is selected. At the same time, the wellbore cement slurry system is preferred due to factors such as ease of cementing construction and low cementing cost.

[0101] Lower-cost cementing slurry systems include, but are not limited to, ambient temperature resistant cementing slurry systems, high temperature resistant cementing slurry systems, and ultra-high temperature resistant cementing slurry systems. The cost and compressive strength of cementing slurry systems can be reduced by methods such as replacing cementing slurry admixtures and reducing admixture content, among others.

[0102] The cement slurry system selected can be the same cement slurry system, or it can be multiple cement slurry systems with compressive strength higher than the predicted stress of the cement sheath and temperature resistance greater than the wellbore temperature of the corresponding well section.

[0103] By employing the above methods, based on the wellbore parameters and operational parameters of the in-situ conversion production well, and calculating the temperature field and cement sheath stress distribution field of the wellbore, the cement stone performance parameters for the corresponding well section can be accurately determined according to the temperature distribution field and cement sheath stress distribution field. This solves the problem in existing in-situ conversion of horizontal wells in medium- and low-maturity shale oil where wellbore temperature, formation, and casing mechanical strength cannot be accurately considered, thus hindering the targeted selection of cement stone performance parameters. This improves the quality and safety of cement slurry performance design and operation in in-situ conversion of horizontal wells in medium- and low-maturity shale oil. Compared to traditional methods that only use formation parameters for simulation calculations, this invention uses a preset geostress field to form a cement sheath stress prediction chart. After obtaining geostress data during drilling, the cement sheath stress prediction results can be quickly obtained, reducing the time spent waiting for simulation results before cementing and facilitating rapid prediction of cement sheath stress in multiple wells within the same block.

[0104] Another aspect of this invention provides an apparatus for determining the performance parameters of cement stone in in-situ conversion production wells. The apparatus generally includes: The basic parameter determination unit is configured to determine the wellbore parameters, original formation parameters, in-situ conversion production operation parameters, and geostress parameters of the in-situ conversion production well. The wellbore temperature field determination unit is configured to calculate the wellbore temperature field of the production well based on wellbore parameters, original formation parameters, and operational parameters. The wellbore cement sheath stress distribution field determination unit is configured to calculate the wellbore cement sheath stress distribution field of the production well based on the wellbore temperature field and geostress parameters. The cement stone performance parameter determination unit is configured to determine the cement stone performance parameters of the corresponding well section based on the cement ring stress distribution field and the wellbore temperature field.

[0105] The apparatus for determining the performance parameters of cement stone in in-situ conversion production wells according to the present invention is used to implement the method for determining the performance parameters of cement stone in in-situ conversion production wells described in any of the above embodiments and has the beneficial effects corresponding to the method.

[0106] Finally, it should be noted that those skilled in the art will understand that all or part of the processes in the above embodiments can be implemented by a computer program instructing related hardware. The program can be stored in a computer-readable storage medium, and when executed, it can include the processes of the embodiments of the above methods. The storage medium for the program can be a magnetic disk, optical disk, read-only memory (ROM), or random access memory (RAM), etc. The above computer program embodiments can achieve the same or similar effects as any of the corresponding foregoing method embodiments.

[0107] Those skilled in the art will also understand that the various exemplary logic blocks, modules, circuits, and algorithm steps described in conjunction with the disclosure herein can be implemented as electronic hardware, computer software, or a combination of both. To clearly illustrate this interchangeability between hardware and software, the functionality of various illustrative components, blocks, modules, circuits, and steps has been generally described. Whether this functionality is implemented as software or as hardware depends on the specific application and the design constraints imposed on the system as a whole. Those skilled in the art can implement the functionality in various ways for each specific application, but such implementation decisions should not be construed as departing from the scope of the embodiments disclosed herein.

[0108] The above are exemplary embodiments disclosed in this invention. However, it should be noted that various changes and modifications can be made without departing from the scope of the embodiments of this invention as defined by the claims. The functions, steps, and / or actions of the methods according to the disclosed embodiments described herein do not need to be performed in any particular order. The sequence numbers of the disclosed embodiments of this invention are for descriptive purposes only and do not represent the superiority or inferiority of the embodiments. Furthermore, although the elements disclosed in the embodiments of this invention may be described or claimed individually, they may be understood as multiple unless explicitly limited to a singular number.

[0109] It should be understood that, as used herein, the singular form “a” is intended to include the plural form as well, unless the context clearly supports an exception. It should also be understood that, as used herein, “and / or” refers to any and all possible combinations of one or more of the associated listed items.

[0110] 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 disclosed embodiments of the present invention is limited to these examples. Within the framework of the present invention, technical features of the above embodiments or different embodiments can also be combined, and many other variations of different aspects of the present invention as described above exist, which are not provided in detail for the sake of brevity. Therefore, any omissions, modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the protection scope of the present invention.

Claims

1. A method for determining the performance parameters of cement stone in in-situ conversion production wells, characterized in that, Includes the following steps: Determine the wellbore parameters, original formation parameters, in-situ conversion production operation parameters, and geostress parameters of the in-situ conversion production well; The wellbore temperature field of the production well is calculated based on the wellbore parameters, the original formation parameters, and the operating parameters. Based on the wellbore temperature field and the geostress parameters, the stress distribution field of the cement sheath in the production well is calculated. The performance parameters of the cement stone are determined based on the stress distribution field of the cement ring in the wellbore and the temperature field in the wellbore.

2. The method for determining the performance parameters of cement stone in in-situ conversion production wells according to claim 1, characterized in that, The calculation of the wellbore temperature field of the production well based on the wellbore parameters, the original formation parameters, and the operating parameters includes: Based on the wellbore parameters, the production well is divided into four sections: the guide section, the surface casing section, the technical casing section, and the production casing section. The total heat transfer coefficient per unit length of the wellbore perimeter in different well sections is calculated based on the wellbore parameters. Based on the overall heat transfer coefficient around the wellbore, the original formation parameters, and the operating parameters, the wellbore temperature at different depths is calculated sequentially from the bottom of the well to the wellhead.

3. The method for determining the performance parameters of cement stone in in-situ conversion production wells according to claim 2, characterized in that, Calculating the total heat transfer coefficient per unit length of the wellbore perimeter for different well sections based on the wellbore parameters includes: calculating the total thermal resistance per unit length of each component based on the radial composition of each well section in the guide section, the surface casing section, the technical casing section, and the production casing section, and the wellbore parameters; and then determining the total heat transfer coefficient per unit length of the wellbore perimeter based on the total thermal resistance per unit length.

4. The method for determining the performance parameters of cement stone in in-situ conversion production wells according to claim 2, characterized in that, The wellbore temperature includes the fluid temperature inside the wellbore, the casing temperature of adjacent formations in each well section, the cement sheath first interface temperature, and the cement sheath second interface temperature.

5. The method for determining the performance parameters of cement stone in in-situ conversion production wells according to claim 4, characterized in that, Based on the overall heat transfer coefficient around the wellbore, the original formation parameters, and the operating parameters, the wellbore temperature at different depths is calculated sequentially from the bottom of the well to the wellhead, including: In the radial direction of the wellbore, based on the steady-state heat transfer equation from the wellbore to the cement sheath interface per unit length, the unsteady-state heat transfer equation from the outer edge of the cement sheath to the formation per unit length, and the continuity condition that the heat is equal in the steady-state and unsteady-state heat transfer stages, the relationship between the temperature of the cement sheath interface and the temperature of the fluid inside the wellbore is determined. Based on the principle of energy conservation, a differential equation for the axial temperature field of the wellbore is established. The temperature of the cement sheath interface is substituted into the differential equation for the axial temperature field. Combined with the bottom boundary conditions, the fluid temperature inside the wellbore at the outlet end of each well section is calculated segment by segment. The fluid temperature inside the wellbore at the outlet end of the lower well section is taken as the fluid temperature inside the wellbore at the inlet end of the upper well section connected to it, and the fluid temperature inside the wellbore at each depth in each well section is calculated. In the radial direction of the wellbore, the temperature of the cement sheath interface is calculated based on the relationship between the temperature of the fluid inside the wellbore and the temperature of the cement sheath interface with the temperature of the fluid inside the wellbore. Based on the fluid temperature inside the wellbore and the interface temperature of the cement sheath, the casing temperature and the interface temperature of the cement sheath in each well section are calculated using interpolation or steady-state heat transfer equations.

6. The method for determining the performance parameters of cement stone in in-situ conversion production wells according to claim 1, characterized in that, Calculating the stress distribution field of the cement sheath in the production well based on the wellbore temperature field and the geostress parameters includes: using the wellbore temperature field as the thermal load input condition for the stress distribution field of the cement sheath in the wellbore, and combining the geostress parameters to establish a model of the stress distribution field of the cement sheath in the production well using the finite element method.

7. The method for determining the performance parameters of cement stone in in-situ conversion production wells according to claim 6, characterized in that, The geostress parameters include the maximum horizontal principal stress and the vertical geostress. The temperature parameter used to construct the stress distribution field model of the wellbore cement sheath of the production well is the highest temperature of the section to be cemented. The highest temperature is obtained by solving the temperature field of the wellbore corresponding to the section to be cemented.

8. The method for determining the performance parameters of cement stone in in-situ conversion production wells according to claim 7, characterized in that, The method also includes using the wellbore cement sheath stress distribution field model to calculate the cement sheath stress field under different combinations of geostress, extracting the average stress on the cement sheath, and drawing the average stress map of the cement sheath under temperature field conditions.

9. The method for determining the performance parameters of cement stone in in-situ conversion production wells according to claim 8, characterized in that, Determining cement stone performance parameters based on the wellbore cement sheath stress distribution field and the wellbore temperature field includes: obtaining the predicted stress magnitude of the cement sheath at the actual cementing layer through a stress map based on the actual cementing layer temperature, the maximum horizontal principal stress, and the vertical ground stress; and selecting a cement slurry system with a compressive strength higher than the predicted stress of the cement sheath and a temperature resistance greater than the wellbore temperature of the corresponding well section.

10. An apparatus for determining the performance parameters of cement stone in in-situ conversion production wells, characterized in that, include: The basic parameter determination unit is configured to determine the wellbore parameters, original formation parameters, in-situ conversion production operation parameters, and geostress parameters of the in-situ conversion production well. The wellbore temperature field determination unit is configured to calculate the wellbore temperature field of the production well based on the wellbore parameters, the original formation parameters, and the operating parameters. The wellbore cement sheath stress distribution field determination unit is configured to calculate the wellbore cement sheath stress distribution field of the production well based on the wellbore temperature field and the geostress parameters. The cement stone performance parameter determination unit is configured to determine the cement stone performance parameters based on the stress distribution field of the wellbore cement sheath and the temperature field of the wellbore.

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