Shaft steam dryness profile determination method and device, medium and electronic equipment

Abstract

The invention discloses a shaft steam dryness profile determination method and device, a medium and electronic equipment. The method comprises the following steps: acquiring temperature data and pressure data corresponding to a plurality of equidistant measuring points on a shaft; calculating a saturated steam density value and a saturated water density value corresponding to each measuring point according to the temperature data and the pressure data; the average steam density value is calculated according to the saturated steam density value, the saturated water density value and the average steam dryness, and the average steam dryness is the average value of the corresponding steam dryness between the adjacent measuring points; and constructing a steam pressure drop gradient model based on the average steam density value and the average steam flow velocity value. According to the technical scheme provided by the invention, the accuracy of obtaining the shaft steam dryness profile can be improved.

Description

Technical Field

[0001] The present application belongs to the technical field of wellbore steam dryness, and in particular, relates to a wellbore steam dryness profile determination method, device, medium and electronic equipment. Background Art

[0002] In heavy oil steam injection thermal recovery projects, the acquisition of wellbore steam dryness profile has always been an important and extremely difficult engineering technology. Existing non-thermodynamic methods can continuously measure steam dryness, but the general instrument is expensive and has many restrictions on the use occasions. It has not yet reached a mature and practical stage for the high temperature and high pressure environment conditions of steam injection wells. Therefore, a method is needed to improve the accuracy of obtaining wellbore steam dryness profiles. Summary of the invention

[0003] The embodiments of the present application provide a method, device, medium and electronic equipment for determining a wellbore steam dryness profile, wherein the method can improve the accuracy of obtaining a wellbore steam dryness profile.

[0004] Other features and advantages of the present application will become apparent from the following detailed description, or may be learned in part by the practice of the present application.

[0005] According to a first aspect of an embodiment of the present application, a method for determining a wellbore steam dryness profile is provided, characterized in that the method comprises: obtaining temperature data and pressure data corresponding to a plurality of equidistant measuring points on the wellbore; calculating a saturated steam density value and a saturated water density value corresponding to each measuring point based on the temperature data and the pressure data; calculating an average steam density value based on the saturated steam density value, the saturated water density value, and the average steam dryness, wherein the average steam dryness is the average value of the steam drynesses corresponding to adjacent measuring points; and constructing a steam pressure drop gradient model based on the average steam density value and the average steam flow rate value.

[0006] In some embodiments of the present application, based on the aforementioned scheme, before calculating the saturated steam density value and the saturated water density corresponding to each measuring point according to the temperature data and the pressure data, the method also includes: judging the phase change of the wellbore according to the temperature data and the pressure data; and obtaining the temperature data and pressure data corresponding to multiple equidistant measuring points on the wellbore according to the phase change and the wellbore structure of the wellbore.

[0007] In some embodiments of the present application, based on the aforementioned scheme, before obtaining the temperature data and pressure data corresponding to multiple equidistant measuring points on the wellbore according to the phase change and the wellbore structure of the wellbore, the method also includes: if there is a phase change in the wellbore, determining the depth corresponding to the phase change in the wellbore, the existence of the phase change is the situation where steam is converted into water in the wellbore; based on the depth, determining the steam dryness value corresponding to the depth as the initial steam dryness value.

[0008] In some embodiments of the present application, based on the aforementioned scheme, before obtaining the temperature data and pressure data corresponding to multiple equidistant measuring points on the wellbore according to the phase change and the wellbore structure of the wellbore, the method also includes: if the wellbore has different wellbore structures, then according to the different wellbore structures, respectively obtaining the temperature data and pressure data corresponding to multiple equidistant measuring points on the wellbore.

[0009] In some embodiments of the present application, based on the aforementioned scheme, the average steam density value is calculated according to the saturated steam density value, the saturated water density value, and the average steam dryness, including: calculating the average saturated steam density value and the average saturated water density value corresponding to the adjacent measuring points by obtaining the saturated steam density value and the saturated water density value corresponding to the adjacent measuring points; calculating the average steam density value based on the average saturated steam density value, the average saturated water density value, and the average steam dryness.

[0010] In some embodiments of the present application, based on the aforementioned scheme, before constructing the steam pressure drop gradient model, the average steam flow rate value is calculated, including: obtaining the wellbore cross-sectional area and the steam mass flow rate of the wellbore; calculating the average steam flow rate value based on the wellbore cross-sectional area, the steam mass flow rate and the average steam density value.

[0011] In some embodiments of the present application, based on the aforementioned scheme, after constructing the steam pressure drop gradient model, the method also includes: calculating the average dryness drop and the friction coefficient of the wellbore according to the saturated steam density value and the saturated water density value corresponding to each measuring point, and the steam pressure drop gradient model; determining the steam dryness profile corresponding to the wellbore based on the saturated steam density value and the saturated water density value corresponding to each measuring point, the average dryness drop, the friction coefficient and the steam pressure drop gradient model.

[0012] The present application sets a plurality of equally spaced measuring points in the wellbore and obtains the pressure data and temperature data corresponding to each measuring point. According to the obtained pressure data and temperature data, the saturated steam density value and the saturated water density value corresponding to each measuring point are calculated. Then, the average steam density value is calculated according to the calculated saturated steam density value and saturated water density value, so as to construct a steam pressure drop gradient model based on the average steam density value and the average steam flow rate value.

[0013] Through the steam pressure drop gradient model, the steam dryness value corresponding to each position in the wellbore can be calculated, so that the steam dryness value profile corresponding to the wellbore can be determined, thereby improving the changing trend and accuracy of analyzing the steam dryness value of the wellbore.

[0014] According to a second aspect of an embodiment of the present application, a device for determining a wellbore steam dryness profile is provided, characterized in that the device comprises: an acquisition unit, used to acquire temperature data and pressure data corresponding to a plurality of equidistant measuring points on the wellbore; a first calculation unit, used to calculate a saturated steam density value and a saturated water density value corresponding to each measuring point based on the temperature data and the pressure data; a second calculation unit, used to calculate an average steam density value based on the saturated steam density value, the saturated water density value, and the average steam dryness, wherein the average steam dryness is an average value of steam drynesses corresponding to adjacent measuring points; and a construction unit, used to construct a steam pressure drop gradient model based on the average steam density value and the average steam flow rate value.

[0015] According to a third aspect of an embodiment of the present application, a computer-readable storage medium is provided, characterized in that at least one program code is stored in the computer-readable storage medium, and the at least one program code is loaded and executed by a processor to implement the operations performed by the described method.

[0016] According to a fourth aspect of an embodiment of the present application, an electronic device is provided, characterized in that the electronic device includes one or more processors and one or more memories, at least one program code is stored in the one or more memories, and the at least one program code is loaded and executed by the one or more processors to implement the operations performed by the method.

[0017] The beneficial effects of each embodiment of the second to fourth aspects mentioned above can refer to the beneficial effects of the first aspect and each embodiment of the first aspect mentioned above, and will not be repeated here.

[0018] It should be understood that the foregoing general description and the following detailed description are exemplary and explanatory only and are not restrictive of the present application. BRIEF DESCRIPTION OF THE DRAWINGS

[0019] The drawings herein are incorporated into the specification and constitute a part of the specification, showing embodiments consistent with the present application, and together with the specification, are used to explain the principles of the present application. Obviously, the drawings described below are only some embodiments of the present application, and for ordinary technicians in this field, other drawings can be obtained based on these drawings without creative work. In the drawings:

[0020] Figure 1A diagram showing the relationship between the wellbore structure and annulus conditions and the steam quality profile in the embodiment of the present application is shown;

[0021] Figure 2 A flow chart of a method for determining a wellbore steam dryness profile in an embodiment of the present application is shown;

[0022] Figure 3 A schematic diagram of the structure of a wellbore steam dryness profile determination device in an embodiment of the present application is shown;

[0023] Figure 4 A schematic diagram of the structure of an electronic device in an embodiment of the present application is shown. DETAILED DESCRIPTION

[0024] The following will be combined with the drawings in the embodiments of the present application to clearly and completely describe the technical solutions in the embodiments of the present application. Obviously, the described embodiments are only part of the embodiments of the present application, not all of the embodiments. Based on the embodiments in the present application, all other embodiments obtained by ordinary technicians in this field without creative work are within the scope of protection of this application.

[0025] In addition, described feature, structure or characteristic can be combined in one or more embodiments in any suitable manner. In the following description, many specific details are provided to provide a full understanding of the embodiments of the present application. However, those skilled in the art will appreciate that the technical scheme of the present application can be put into practice without one or more of the specific details, or other methods, components, devices, steps, etc. can be adopted. In other cases, known methods, devices, realizations or operations are not shown or described in detail to avoid blurring the various aspects of the application.

[0026] The block diagrams shown in the accompanying drawings are merely functional entities and do not necessarily correspond to physically independent entities. That is, these functional entities may be implemented in software form, or in one or more hardware modules or integrated circuits, or in different networks and / or processor devices and / or microcontroller devices.

[0027] The flowcharts shown in the accompanying drawings are only exemplary and do not necessarily include all the contents and operations / steps, nor must they be executed in the order described. For example, some operations / steps can be decomposed, and some operations / steps can be combined or partially combined, so the actual execution order may change according to actual conditions.

[0028] Figure 1 , shows the relationship between the wellbore structure and annulus conditions and the steam quality profile in the embodiment of the present application. Figure 1In the wellbore, the wellbore can be composed of different wellbore structures. For example, it is composed of large-diameter insulated pipes, small-diameter insulated pipes, and oil pipes. In addition, the annulus conditions corresponding to the wellbore structure are also different. For example, large-diameter insulated pipes correspond to air, nitrogen, or water vapor. Small-diameter insulated pipes correspond to air, nitrogen, or water vapor. The upper part of the oil pipe corresponds to air, nitrogen, or water vapor. The lower part of the oil pipe corresponds to water medium. Therefore, based on the above situation, the current wellbore structure and annulus conditions can be divided into three situations. In the first case, the annulus medium changes, and there is a gas (air, nitrogen, water vapor, etc.) liquid interface. In the second case, the diameter of the insulated pipe changes, mainly the change in the inner diameter of the insulated pipe. In the third case, the wellbore material changes, mainly including the changes in the inner diameter (or outer diameter) of the insulated pipe, the oil pipe, and the insulated pipe.

[0029] The following is a detailed description of this application:

[0030] Figure 2 The flowchart of the method for determining the steam dryness profile of a wellbore in an embodiment of the present application is shown. The method for determining the steam dryness profile of a wellbore can be executed by a device having a computing and processing function, such as a wellbore steam dryness profile determining device. Figure 2 As shown, the method for determining the steam quality profile of a wellbore includes at least steps 210 to 240, which are described in detail as follows:

[0031] In step 210, temperature data and pressure data corresponding to a plurality of equidistant measuring points on the wellbore are obtained.

[0032] In the present application, multiple measuring points are set in the wellbore, and the distances between adjacent measuring points are equal. Based on the measuring points, the temperature data and pressure data corresponding to each measuring point are obtained. By analyzing the temperature data and pressure data corresponding to the same distance, it is possible to clearly understand the uniform change of steam dryness in the wellbore as the wellbore depth changes.

[0033] Continue to refer to Figure 2 In step 220, the saturated steam density value and the saturated water density value corresponding to each measuring point are calculated according to the temperature data and the pressure data.

[0034] In this application, based on the measured temperature data and pressure data, the saturated steam density value and the saturated water density value corresponding to each measuring point are calculated, wherein the saturated steam density value is the density value corresponding to dry steam, and the saturated water density value is the density value corresponding to when steam condenses into water. Specifically, the saturated steam density value and the saturated water density value are calculated respectively by the following formulas:

[0035] ρ w =3786.31-37.2487T+0.196246T2 -5.04708×10 -4 T 3

[0036] +6.29368×10 -7 T 4 -3.08480×10 -10 T 5

[0037] lnρ s =-93.7072+0.833941T-0.00320809T 2 +6.57652×10 -6 T 3

[0038] -6.93747×10 -9 T 4 +2.97203×10 -12 T 5

[0039] Among them, ρ w is the saturated water density, kg / m 3 ρ s is the saturated steam density, kg / m 3 ; T is the steam temperature, K (273.15+℃).

[0040] Further, in one embodiment of the present application, before calculating the saturated steam density value and the saturated water density corresponding to each measuring point according to the temperature data and the pressure data, the following steps are specifically included:

[0041] Step 221, judging the phase change of the wellbore according to the temperature data and the pressure data;

[0042] Step 222, according to the phase change and the wellbore structure of the wellbore, obtain temperature data and pressure data corresponding to multiple equidistant measuring points on the wellbore.

[0043] In this embodiment, since the wellbore may be composed of different wellbore structures, it is necessary to reasonably obtain temperature data and pressure data corresponding to multiple equidistant measuring points on the wellbore according to different phase changes and the wellbore structure of the wellbore.

[0044] Further, in one embodiment of the present application, before obtaining the temperature data and pressure data corresponding to a plurality of equidistant measuring points on the wellbore according to the phase change and the wellbore structure of the wellbore, the steps 223 to 224 are specifically included:

[0045] Step 223, if there is a phase change in the wellbore, determining a depth corresponding to the phase change in the wellbore, wherein the phase change is a situation where steam-converted water exists in the wellbore;

[0046] Step 224: According to the depth, determine the steam quality value corresponding to the depth as the initial steam quality value.

[0047] In this embodiment, if there is a phase change in the wellbore, it means that the steam quality value corresponding to the position where the phase change occurs can be set as the initial steam quality value, wherein the initial steam quality value is 0. That is, the steam quality value corresponding to the remaining part can be calculated in a step-by-step manner according to the position where the phase change occurs.

[0048] Further, in one embodiment of the present application, before obtaining temperature data and pressure data corresponding to a plurality of equally spaced measuring points on the wellbore according to the phase change and the wellbore structure of the wellbore, the method specifically includes step 225:

[0049] Step 225: If the wellbore has different wellbore structures, then according to the different wellbore structures, temperature data and pressure data corresponding to a plurality of equidistant measuring points on the wellbore are respectively obtained.

[0050] In this embodiment, the wellbore may have different wellbore structures, for example, a large diameter heat-insulated pipe,

[0051] The wellbore structure is composed of a small-diameter insulated pipe and an oil pipe. In addition, the annulus conditions corresponding to the wellbore structure are also different. For example, large-diameter insulated pipes correspond to air, nitrogen, or water vapor. Small-diameter insulated pipes correspond to air, nitrogen, or water vapor. The upper part of the oil pipe corresponds to air, nitrogen, or water vapor. The lower part of the oil pipe corresponds to water medium. Therefore, in order to ensure the accuracy of the calculations in this application and the generality of the scope of the method, the temperature data and pressure data corresponding to multiple equidistant measuring points on the wellbore can be obtained according to different wellbore structures, so as to obtain a steam pressure drop gradient model for calculating and analyzing the steam dryness value of the wellbore.

[0052] Continue to refer to Figure 2 In step 230, the average steam density value is calculated according to the saturated steam density value, the saturated water density value, and the average steam dryness, wherein the average steam dryness is the average value of the steam dryness corresponding to adjacent measuring points.

[0053] In the present application, after calculating the saturated steam density value and the saturated water density value, in order to analyze the uniform change of steam dryness in the wellbore, the average steam dryness between each adjacent measuring point can be combined for calculation to obtain the average steam density value corresponding to each measuring point.

[0054] Specifically, the calculation can be performed through the following steps: by obtaining the saturated steam density value and the saturated water density value corresponding to the adjacent measuring points, the average saturated steam density value and the average saturated water density value corresponding to the adjacent measuring points are calculated; based on the average saturated steam density value, the average saturated water density value, and the average steam dryness, the average steam density value is calculated.

[0055] Since the average saturated steam density value and the average saturated water density value corresponding to adjacent measuring points are calculated, the change amount and change trend of the steam dryness value between unit distances can be clearly understood, thereby improving the accuracy of calculating and analyzing the steam dryness value of the wellbore. Among them, the average steam density value can be calculated by the following formula. It should be noted that the average steam dryness is an unknown set value, and specific calculations need to be performed through subsequent steps to determine the steam dryness corresponding to each position in the wellbore based on the average steam dryness.

[0056]

[0057] in, is the average steam density, kg / m 3 ρ w is the saturated water density, kg / m 3 ρ s is the saturated steam density, kg / m 3 ; is the average steam dryness.

[0058] Continue to refer to Figure 2 In step 240, a steam pressure drop gradient model is constructed based on the average steam density value and the average steam flow rate value.

[0059] In this application, after calculating the average steam density value, the steam pressure drop gradient model is constructed in combination with the average steam flow rate value in the wellbore. The steam pressure drop gradient model can calculate and analyze the steam dryness values ​​corresponding to each position in the wellbore according to different wellbore structures and different phase changes, so as to determine the steam dryness profile along the wellbore of the steam injection well.

[0060] Furthermore, in one embodiment of the present application, before constructing the steam pressure drop gradient model, the wellbore cross-sectional area and the steam mass flow rate of the wellbore can be obtained, thereby calculating the average steam flow rate value according to the wellbore cross-sectional area, the steam mass flow rate and the average steam density value. The average steam flow rate value can be calculated by the following formula:

[0061]

[0062] in, is the average steam velocity, m / s; q is the steam mass flow rate, kg / s; S is the wellbore cross-sectional area, m 2 .

[0063] Further, the steam pressure drop gradient model is as follows:

[0064]

[0065] Wherein, Δp is the pressure loss per unit length, Pa; Δz is the distance between adjacent measuring points, m; f m is the friction coefficient, dimensionless; is the average steam density value, kg / m 3 ; is the average steam velocity, m / s; d is the inner tube diameter, m; g is the gravitational acceleration, m / s 2 .

[0066] Furthermore, in one embodiment of the present application, after constructing the steam pressure drop gradient model, the steps 241 to 242 are further included.

[0067] Step 241, calculating the average dryness drop and the friction coefficient of the wellbore according to the saturated steam density value and the saturated water density value corresponding to each measuring point and the steam pressure drop gradient model.

[0068] Step 242, based on the saturated steam density value and the saturated water density value corresponding to each measuring point, the average dryness drop, the friction coefficient and the steam pressure drop gradient model, determine the steam dryness profile corresponding to the wellbore.

[0069] In this embodiment, after obtaining the steam pressure drop gradient model, in order to determine the steam dryness value corresponding to each position in the wellbore, it is necessary to calculate the average dryness drop corresponding to the wellbore and the friction coefficient of the wellbore, so that the steam dryness profile corresponding to the wellbore can be determined based on the average dryness drop, the friction of the wellbore and the steam pressure drop gradient model.

[0070] Specifically, after the saturated steam density value and the saturated water density value corresponding to each measuring point are calculated in combination with the average steam density value calculation formula, the average steam density value corresponding to each measuring point is calculated. Then, by combining the average flow velocity value, the average steam density value and the steam pressure drop gradient model calculated by the average flow velocity value formula, a simultaneous equation is constructed to calculate the average dryness drop corresponding to the equal distance and the friction coefficient corresponding to the wellbore. Based on the average dryness drop and the friction coefficient of the wellbore, the steam dryness profile corresponding to the wellbore can be determined through the steam pressure drop gradient model to achieve accurate calculation and analysis of the steam dryness value of the wellbore.

[0071] Based on the same inventive concept, the present application also provides a device for determining a steam dryness profile of a wellbore, referring to Figure 3 , shows a schematic diagram of the structure of the wellbore steam dryness profile determination device in the embodiment of the present application. The device 300 includes: an acquisition unit 301, used to acquire temperature data and pressure data corresponding to multiple equidistant measuring points on the wellbore; a first calculation unit 302, used to calculate the saturated steam density value and saturated water density value corresponding to each measuring point according to the temperature data and the pressure data; a second calculation unit 303, used to calculate the average steam density value according to the saturated steam density value, the saturated water density value, and the average steam dryness, wherein the average steam dryness is the average value of the steam dryness corresponding to adjacent measuring points; a construction unit 304, used to construct a steam pressure drop gradient model based on the average steam density value and the average steam flow rate value.

[0072] For details not disclosed in the embodiments of the device of the present application, please refer to the embodiments of the above method of the present application.

[0073] Based on the same inventive concept, the present application also provides a computer-readable storage medium, characterized in that the computer-readable storage medium stores at least one program code, and the at least one program code is loaded and executed by a processor to implement the operations performed by the method.

[0074] Based on the same inventive concept, the present application also provides an electronic device, referring to Figure 4 , Figure 4 A schematic diagram of the structure of an electronic device in an embodiment of the present application is shown.

[0075] The electronic device includes one or more memories 404, one or more processors 402, and at least one computer program (program code) stored in the memory 404 and executable on the processor 402. When the processor 402 executes the computer program, the method described above is implemented.

[0076] Among them, Figure 4In the embodiment of the present invention, a bus architecture (represented by bus 400) is shown, which may include any number of interconnected buses and bridges, and bus 400 links various circuits including one or more processors represented by processor 402 and memory represented by memory 404. Bus 400 may also link various other circuits such as peripherals, voltage regulators, and power management circuits, which are well known in the art and are therefore not further described herein. Bus interface 405 provides an interface between bus 400 and receiver 401 and transmitter 403. Receiver 401 and transmitter 403 may be the same element, namely a transceiver, providing a unit for communicating with various other devices over a transmission medium. Processor 402 is responsible for managing bus 400 and general processing, while memory 404 may be used to store data used by processor 402 when performing operations.

[0077] The functions described herein may be implemented in hardware, software executed by a processor, firmware, or any combination thereof. If implemented in software executed by a processor, the functions may be stored as one or more instructions or codes on a computer-readable medium or transmitted via a computer-readable medium. Other examples and implementations are within the scope and spirit of the present application and the appended claims. For example, due to the nature of software, the functions described above may be implemented using software executed by a processor, hardware, firmware, hard wiring, or a combination of any of these. In addition, each functional unit may be integrated into a processing unit, each unit may exist physically separately, or two or more units may be integrated into one unit.

[0078] In the several embodiments provided in this application, it should be understood that the disclosed technical content can be implemented in other ways. Among them, the device embodiments described above are only schematic. For example, the division of the units can be a logical function division. There may be other division methods in actual implementation. For example, multiple units or components can be combined or integrated into another system, or some features can be ignored or not executed. Another point is that the mutual coupling or direct coupling or communication connection shown or discussed can be through some interfaces, indirect coupling or communication connection of units or modules, which can be electrical or other forms.

[0079] The units described as separate components may or may not be physically separated, and the components of the control device may or may not be physical units, that is, they may be located in one place or distributed in multiple units. Some or all of the units may be selected according to actual needs to achieve the purpose of the present embodiment.

[0080] If the integrated unit is implemented in the form of a software functional unit and sold or used as an independent product, it can be stored in a computer-readable storage medium. Based on this understanding, the technical solution of the present application, in essence, or the part that contributes to the prior art or all or part of the technical solution can be embodied in the form of a software product, and the computer software product is stored in a storage medium, including a number of instructions to enable a computer device (which can be a personal computer, a server or a network device, etc.) to perform all or part of the steps of the method described in each embodiment of the present application. The aforementioned storage medium includes: U disk, read-only memory (ROM, Read-Only Memory), random access memory (RAM, Random Access Memory), mobile hard disk, disk or optical disk and other media that can store program codes.

[0081] The above description is only an embodiment of the present application and is not intended to limit the present application. For those skilled in the art, the present application may have various modifications and variations. Any modification, equivalent substitution, improvement, etc. made within the spirit and principle of the present application shall be included in the scope of the claims of the present application.

Claims

1. A method for determining a wellbore steam dryness profile, characterized in that: The method comprises: Obtain temperature and pressure data corresponding to multiple equidistant measuring points on the wellbore; Calculate the saturated steam density value and the saturated water density value corresponding to each measuring point according to the temperature data and the pressure data; Calculate an average steam density value according to the saturated steam density value, the saturated water density value, and the average steam dryness, wherein the average steam dryness is an average value of steam drynesses corresponding to adjacent measuring points; Based on the average steam density value and the average steam flow rate value, a steam pressure drop gradient model is constructed.

2. The method according to claim 1, characterized in that: Before calculating the saturated steam density value and the saturated water density corresponding to each measuring point according to the temperature data and the pressure data, the method further includes: Determining the phase change of the wellbore according to the temperature data and the pressure data; According to the phase change and the wellbore structure of the wellbore, temperature data and pressure data corresponding to a plurality of equidistant measuring points on the wellbore are obtained.

3. The method according to claim 2, characterized in that Before obtaining temperature data and pressure data corresponding to a plurality of equally spaced measuring points on the wellbore according to the phase change and the wellbore structure of the wellbore, the method further comprises: If there is a phase change in the wellbore, determining a depth corresponding to the phase change in the wellbore, wherein the phase change is a condition in which steam-converted water exists in the wellbore; According to the depth, a steam quality value corresponding to the depth is determined as an initial steam quality value.

4. The method according to claim 2, characterized in that: Before obtaining temperature data and pressure data corresponding to a plurality of equally spaced measuring points on the wellbore according to the phase change and the wellbore structure of the wellbore, the method further comprises: If the wellbore has different wellbore structures, the temperature data and pressure data corresponding to a plurality of equidistant measuring points on the wellbore are respectively obtained according to the different wellbore structures.

5. The method according to claim 1, characterized in that The calculating the average steam density value according to the saturated steam density value, the saturated water density value, and the average steam dryness comprises: By obtaining the saturated steam density values ​​and saturated water density values ​​corresponding to the adjacent measuring points, the average saturated steam density values ​​and the average saturated water density values ​​corresponding to the adjacent measuring points are calculated; The average steam density value is calculated based on the average saturated steam density value, the average saturated water density value, and the average steam quality.

6. The method according to claim 1, characterized in that Before constructing the steam pressure drop gradient model, the average steam flow rate value is calculated, including: obtaining a wellbore cross-sectional area and a steam mass flow rate of the wellbore; The average steam flow rate value is calculated based on the wellbore cross-sectional area, the steam mass flow rate and the average steam density value.

7. The method according to claim 1, characterized in that: After constructing the vapor pressure drop gradient model, the method further includes: Calculate the average dryness drop and the friction coefficient of the wellbore according to the saturated steam density value and the saturated water density value corresponding to each measuring point and the steam pressure drop gradient model; Based on the saturated steam density value and the saturated water density value corresponding to each measuring point, the average dryness drop, the friction coefficient and the steam pressure drop gradient model, the steam dryness profile corresponding to the wellbore is determined.

8. A device for determining a steam dryness profile of a wellbore, characterized in that: The device comprises: An acquisition unit, used to acquire temperature data and pressure data corresponding to a plurality of equidistant measuring points on the wellbore; A first calculation unit, used for calculating a saturated steam density value and a saturated water density value corresponding to each measuring point according to the temperature data and the pressure data; a second calculation unit, configured to calculate an average steam density value according to the saturated steam density value, the saturated water density value, and an average steam dryness, wherein the average steam dryness is an average value of steam drynesses corresponding to adjacent measuring points; A construction unit is used to construct a steam pressure drop gradient model based on the average steam density value and the average steam flow rate value.

9. A computer-readable storage medium, characterized in that: The computer-readable storage medium stores at least one program code, and the at least one program code is loaded and executed by a processor to implement the operations performed by the method according to any one of claims 1 to 7.

10. An electronic device, characterized in that: The electronic device includes one or more processors and one or more memories, wherein the one or more memories store at least one program code, and the at least one program code is loaded and executed by the one or more processors to implement the operations performed by the method according to any one of claims 1 to 7.

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