CN118112051A - Method, device, medium and electronic equipment for determining dryness of shaft steam - Google Patents
Method, device, medium and electronic equipment for determining dryness of shaft steam Download PDFInfo
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Abstract
The application discloses a method, a device, a medium and electronic equipment for determining dryness of shaft steam. Acquiring temperature data, pressure data and friction resistance coefficients corresponding to all test points in a shaft, calculating pressure drops between adjacent test points according to the pressure data, and taking the pressure drops as first pressure drops; setting dryness drop to determine the dryness of steam corresponding to each test point according to the dryness drop; according to the temperature data, the pressure data, the steam dryness and the friction resistance coefficient corresponding to each test point, a steam pressure drop gradient model is built, so that the pressure drop between adjacent test points is calculated according to the steam pressure drop gradient model, and the pressure drop obtained according to the steam pressure drop gradient model is used as a second pressure drop; determining a steam quality of the wellbore based on the first pressure drop and the second pressure drop. The technical scheme provided by the application can improve the convenience of acquiring the dryness of the shaft steam.
Description
Technical Field
The application belongs to the technical field of shaft steam dryness, and particularly relates to a shaft steam dryness determining method, device, medium and electronic equipment.
Background
At present, a plurality of methods for acquiring the dryness of the shaft steam exist, but in the existing methods, the cost of measuring instruments is high, the use is limited by a plurality of occasions, and the testing precision and the service life are not ideal under the high-temperature and high-pressure environment in the pit. Accordingly, a need exists for a method that can improve the convenience of acquiring the dryness of wellbore steam.
Disclosure of Invention
The embodiment of the application provides a method, a device, a medium and electronic equipment for determining the dryness of shaft steam, and the method can improve the convenience of acquiring the dryness of shaft steam.
Other features and advantages of the application will be apparent from the following detailed description, or may be learned by the practice of the application.
According to a first aspect of an embodiment of the present application, there is provided a method for determining dryness of steam in a wellbore, the method comprising: acquiring temperature data, pressure data and friction resistance coefficients corresponding to all test points in a shaft, calculating pressure drops between adjacent test points according to the pressure data, and taking the pressure drops as first pressure drops; setting dryness drop to determine the dryness of steam corresponding to each test point according to the dryness drop; according to the temperature data, the pressure data, the steam dryness and the friction resistance coefficient corresponding to each test point, a steam pressure drop gradient model is built, so that the pressure drop between adjacent test points is calculated according to the steam pressure drop gradient model, and the pressure drop obtained according to the steam pressure drop gradient model is used as a second pressure drop; determining a steam quality of the wellbore based on the first pressure drop and the second pressure drop.
In some embodiments of the present application, based on the foregoing solution, the determining the steam dryness corresponding to each test point includes: judging whether a phase state change condition exists in a shaft or not according to temperature data and pressure data corresponding to each test point in the shaft; if the phase change condition does not exist in the shaft, acquiring the wellhead steam dryness of the shaft, and determining the steam dryness corresponding to each test point according to the wellhead steam dryness and the dryness drop.
In some embodiments of the application, based on the foregoing, the method further comprises: determining a depth of a phase change location in the wellbore if the wellbore has a phase change condition; and determining the steam dryness corresponding to each test point according to the depth of the phase change position and the dryness drop.
In some embodiments of the application, based on the foregoing, the constructing the vapor pressure drop gradient model includes: calculating the density of saturated water and the density of saturated steam corresponding to each test point according to the temperature data and the pressure data corresponding to each test point; calculating the steam density corresponding to each test point according to the density of the saturated water, the density of the saturated steam and the dryness of the steam corresponding to each test point; calculating the steam flow rate corresponding to each test point according to the steam density corresponding to each test point; and constructing a vapor pressure gradient model based on the vapor density, vapor flow rate and friction resistance coefficient corresponding to each test point.
In some embodiments of the application, based on the foregoing, the determining the steam quality of the wellbore from the first pressure drop, and the second pressure drop, comprises: judging the first pressure drop and the second pressure drop, and if the absolute value of the difference value between the first pressure drop and the second pressure drop is smaller than or equal to a preset value, determining the steam dryness of the shaft according to the dryness drop.
In some embodiments of the application, based on the foregoing, the method further comprises: and if the absolute value of the difference value between the first pressure drop and the second pressure drop is larger than a preset value, adjusting the dryness drop so that the absolute value of the difference value between the first pressure drop and the second pressure drop is smaller than or equal to the preset value.
In some embodiments of the application, based on the foregoing, the method comprises: and after obtaining the steam dryness of the shaft, acquiring a dryness profile curve corresponding to the shaft according to the steam dryness of the shaft, wherein the dryness profile curve is used for representing the relation between the depth of the shaft and the steam dryness of the shaft.
According to the method, a plurality of test points are set in a shaft, and pressure data and temperature data corresponding to the test points are obtained. According to the acquired pressure data and temperature data, the actual pressure drop between two adjacent test points can be calculated, and the actual pressure drop is taken as a first pressure drop. Meanwhile, the phase state in the shaft can be judged according to the acquired pressure data and temperature data, so that the steam dryness corresponding to each test point can be determined according to different phase states.
And then, determining the steam dryness corresponding to each test point by setting dryness drop and combining the wellbore depth corresponding to each test point. And then, constructing a steam pressure drop gradient model based on temperature data, pressure data, steam dryness and friction resistance coefficient corresponding to each test point, and calculating the pressure drop between adjacent test points according to the steam pressure drop gradient model to serve as a second pressure drop.
And comparing the first pressure drop obtained based on actual calculation with the second pressure drop obtained through calculation of the vapor pressure gradient model, so that the overall vapor dryness of the shaft can be determined. Therefore, the method can improve the convenience of acquiring the dryness of the shaft steam.
According to a second aspect of an embodiment of the present application, there is provided a device for determining dryness of steam in a wellbore, the device comprising: the device comprises an acquisition unit, a control unit and a control unit, wherein the acquisition unit is used for acquiring temperature data, pressure data and friction resistance coefficients corresponding to all test points in a shaft, calculating pressure drops between adjacent test points according to the pressure data, and taking the pressure drops as first pressure drops; the setting unit is used for setting dryness drop so as to determine the dryness of the steam corresponding to each test point according to the dryness drop; the construction unit is used for constructing a steam pressure drop gradient model according to the temperature data, the pressure data, the steam dryness and the friction resistance coefficient corresponding to each test point, calculating the pressure drop between the adjacent test points according to the steam pressure drop gradient model, and taking the pressure drop obtained according to the steam pressure drop gradient model as a second pressure drop; and the determining unit is used for determining the steam dryness of the shaft according to the first pressure drop and the second pressure drop.
According to a third aspect of embodiments of the present application, there is provided a computer readable storage medium having stored therein at least one program code loaded and executed by a processor to implement operations performed by the method.
According to a fourth aspect of an embodiment of the present application, there is provided an electronic device, characterized in that the electronic device comprises one or more processors and one or more memories, the one or more memories having stored therein at least one program code loaded and executed by the one or more processors to implement the operations performed by the method.
The advantages of the embodiments of the second aspect and the fourth aspect may be referred to the advantages of the first aspect and the embodiments of the first aspect, and are not described here again.
It is to be understood that both the foregoing general description and the following detailed description are exemplary and explanatory only and are not restrictive of the application as claimed.
Drawings
The accompanying drawings, which are incorporated in and constitute a part of this specification, illustrate embodiments consistent with the application and together with the description, serve to explain the principles of the application. It is evident that the drawings in the following description are only some embodiments of the present application and that other drawings may be obtained from these drawings without inventive effort for a person of ordinary skill in the art. In the drawings:
FIG. 1 is a graph showing wellbore configuration and annulus conditions as a function of steam dryness profile in an embodiment of the application;
FIG. 2 illustrates a flow chart of a method of determining dryness of wellbore steam in an embodiment of the application;
FIG. 3 shows a flowchart for determining the steam dryness corresponding to each test point in an embodiment of the application;
FIG. 4 shows a flow chart of the calculation of steam dryness and dryness profile curves in an embodiment of the application;
FIG. 5 shows a schematic structural diagram of a well bore steam quality determination device in an embodiment of the application;
fig. 6 shows a schematic structural diagram of an electronic device in an embodiment of the application.
Detailed Description
The following description of the embodiments of the present application will be made clearly and completely with reference to the accompanying drawings, in which it is apparent that the embodiments described are only some embodiments of the present application, but not all embodiments. All other embodiments, which can be made by those skilled in the art based on the embodiments of the application without making any inventive effort, are intended to be within the scope of the application.
Furthermore, the described features, structures, or characteristics may be combined in any suitable manner in one or more embodiments. In the following description, numerous specific details are provided to give a thorough understanding of embodiments of the application. One skilled in the relevant art will recognize, however, that the application may be practiced without one or more of the specific details, or with other methods, components, devices, steps, etc. In other instances, well-known methods, devices, implementations, or operations are not shown or described in detail to avoid obscuring aspects of the application.
The block diagrams depicted in the figures are merely functional entities and do not necessarily correspond to physically separate entities. That is, the functional entities may be implemented in software, or in one or more hardware modules or integrated circuits, or in different networks and/or processor devices and/or microcontroller devices.
The flow diagrams depicted in the figures are exemplary only, and do not necessarily include all of the elements and operations/steps, nor must they be performed in the order described. For example, some operations/steps may be decomposed, and some operations/steps may be combined or partially combined, so that the order of actual execution may be changed according to actual situations.
FIG. 1 is a graph showing wellbore configuration and annulus conditions as a function of steam dryness profile in an embodiment of the application. In fig. 1, the wellbore may be composed of different wellbore structures. For example, the heat-insulating pipe consists of a large-pipe-diameter heat-insulating pipe, a small-pipe-diameter heat-insulating pipe and an oil pipe. In addition, the corresponding annular conditions of the well structure are different. For example, the large-diameter heat insulation pipe corresponds to air, nitrogen or water vapor. The small-diameter heat insulation pipe is corresponding to air, nitrogen or water vapor. The upper part of the oil pipe is corresponding to air, nitrogen or water vapor. The lower part of the oil pipe is correspondingly provided with an aqueous medium. Thus, in combination with the above, the current wellbore configuration and annulus conditions can be divided into 3. In the first case, the annular medium changes and there is a gas (air, nitrogen, water vapor, etc.) liquid interface. In the second case, the pipe diameter of the heat insulation pipe is changed, mainly the inner diameter of the heat insulation pipe is changed. In the third case, the well body material is changed, and the well body material mainly comprises a heat insulation pipe, an oil pipe and the inner diameter (or outer diameter) of the heat insulation pipe is changed.
In the application, when the steam dryness of the shaft is measured, the steam dryness of the shaft mouth can be obtained by an assay method. Meanwhile, during stable steam injection of the shaft, temperature data and pressure data of a plurality of test points can be acquired in the shaft through the high-temperature high-precision electronic pressure gauge. After the temperature data and the pressure data of the plurality of test points are obtained, the friction resistance coefficient of the shaft can be combined, and the steam dryness corresponding to each test point is calculated, so that the steam dryness of the shaft and the dryness profile curve corresponding to the shaft are obtained.
In addition, the steam injection rate of the shaft, the shaft size and other related parameters can be combined, a steam shaft flow pressure loss theoretical model is established, so that the pressure loss of the shaft is calculated according to the steam shaft flow pressure loss theoretical model, and the friction resistance coefficient of the shaft and the pressure loss of the shaft are combined, so that the steam dryness of the shaft and a dryness profile curve corresponding to the shaft are obtained.
The present application will be described in detail below:
FIG. 2 shows a flow chart of a method of determining dryness of wellbore steam in an embodiment of the application. The method for determining the dryness of the shaft steam can be performed by a device with a calculation processing function, such as a device for determining the dryness of the shaft steam. Referring to fig. 2, the method for determining the dryness of the steam in the shaft at least includes steps 210 to 270, which are described in detail as follows:
In step 210, temperature data, pressure data, and friction resistance coefficients corresponding to each test point in the wellbore are obtained, so as to calculate pressure drops between adjacent test points according to the pressure data, and the pressure drops are taken as first pressure drops.
According to the method, a plurality of test points are set in a shaft, and based on the test points, temperature data and pressure data corresponding to the test points are obtained. And then, according to the pressure data corresponding to each test point, calculating the pressure drop between the adjacent test points, and taking the pressure drop as a first pressure drop.
It should be noted that the distances between the various test points may be equal. By setting equal intervals, the pressure change condition between the test points can be known more directly.
Besides obtaining the pressure data and the pressure drop of the test points, the temperature data corresponding to each test point is also required to be obtained. By combining the pressure data and the temperature data, the phase state of the shaft can be judged, so that the steam dryness corresponding to each test point can be determined according to the phase state of the shaft.
At the same time, it is also desirable to obtain the friction coefficient of the wellbore. By acquiring the friction resistance coefficient of the shaft, a vapor pressure gradient model can be constructed, so that the vapor dryness of the shaft can be obtained, a dryness profile curve corresponding to the shaft can be obtained, and the change trend of the vapor dryness of the shaft can be obtained.
With continued reference to FIG. 2, in step 230, a dryness drop is set to determine a dryness of the steam corresponding to each test point based on the dryness drop.
According to the method and the device, when the temperature data and the pressure data corresponding to each test point in the shaft are obtained, the actual steam dryness in the shaft can be obtained. And then analyzing and integrating the obtained actual steam dryness to obtain a linear change rule of the steam dryness. Based on the linear change rule of the dryness of the steam, dryness drop corresponding to the unit distance can be set to be equal. For example, the dryness per unit distance can be set to be reduced to 0.005. After the dryness drop is set, determining the dryness of the steam corresponding to each test point through the dryness drop under the condition that the dryness of the steam at the wellhead of the shaft and/or the depth of the steam in the shaft is zero.
In an embodiment of the present application, the determining the dryness of the steam corresponding to each test point may specifically include steps 231 to 232:
and step 231, judging whether the phase state change condition exists in the shaft according to the temperature data and the pressure data corresponding to each test point in the shaft.
And 232, if the phase change condition does not exist in the shaft, acquiring the wellhead steam dryness of the shaft, so as to determine the steam dryness corresponding to each test point according to the wellhead steam dryness and the dryness drop.
According to the method and the device, the phase state in the shaft can be judged according to the acquired temperature data and pressure data corresponding to each test point. For example, refer to formula (1). And (3) carrying the temperature data and the pressure data corresponding to each test point into the formula (1), and if the temperature data and the pressure data corresponding to each test point meet the formula (1), indicating that no phase change exists in the current shaft, namely, the state from the wellhead of the shaft to the bottom of the shaft is steam. Therefore, in order to determine the steam dryness corresponding to each test point, the steam dryness corresponding to the wellhead of the wellbore needs to be obtained, so as to determine the steam dryness corresponding to each test point according to the steam dryness of the wellhead and the set dryness drop. Wherein, the formula (1) is as follows:
In formula (1), p s is the steam saturation pressure, and T s is the steam saturation temperature. If the temperature data and the pressure data corresponding to each test point are substituted into the formula (1) and the formula (1) can be satisfied, the current temperature data and the current pressure data are the steam saturation pressure and the steam saturation temperature, so that the current shaft is steam, and the process of converting steam into water does not exist.
In an embodiment of the present application, the determining the dryness of the steam corresponding to each test point may specifically further include steps 233 to 234:
At step 233, if a phase change condition exists in the wellbore, a depth of a phase change location is determined in the wellbore.
And step 234, determining the steam dryness corresponding to each test point according to the depth of the phase change position and the dryness drop.
According to the method and the device, the phase state in the shaft can be judged according to the acquired temperature data and pressure data corresponding to each test point. For example, refer to formula (1). And (3) taking the temperature data and the pressure data corresponding to each test point into the formula (1), and if the temperature data and the pressure data corresponding to the test points do not meet the formula (1), indicating that the phase state change exists in the current shaft, namely that steam is converted into water in the shaft. Therefore, in order to determine the steam dryness corresponding to each test point, the depth of the well bore at the position of the phase change, that is, the depth of the well bore corresponding to the intersection of the steam medium and the water medium, needs to be obtained. Since the change of the dryness of the steam in the shaft is known to be linear, the dryness of the steam corresponding to each test point can be determined according to the depth and dryness drop of the shaft at the obtained phase change position. Wherein, the formula (1) is as follows:
in formula (1), p s is the steam saturation pressure, and T s is the steam saturation temperature. If the temperature data and the pressure data corresponding to each test point are substituted into the formula (1) and the formula (1) cannot be satisfied, the current temperature data and/or the current pressure data are/is not steam saturation pressure and/or steam saturation temperature, so that the process of converting steam into water in the current shaft is described.
With continued reference to fig. 2, in step 250, a vapor pressure drop gradient model is constructed according to the temperature data, the pressure data, the vapor dryness, and the friction coefficient corresponding to each test point, so as to calculate the pressure drop between the adjacent test points according to the vapor pressure drop gradient model, and the pressure drop obtained according to the vapor pressure drop gradient model is taken as the second pressure drop.
According to the method, after the steam dryness corresponding to each test point is calculated according to the acquired temperature data and pressure data corresponding to each test point, a steam pressure gradient model is constructed by combining friction resistance coefficients corresponding to a shaft. The friction coefficient of the well bore is related to the structure of the well bore. For example, with continued reference to FIG. 1, in FIG. 1, the wellbore may be comprised of a large pipe diameter thermal insulation, a small pipe diameter thermal insulation, and an oil pipe. Therefore, because the friction resistance coefficients corresponding to different pipelines are different, when the steam pressure drop gradient model is constructed according to the friction resistance coefficients, the influence caused by the difference of the friction resistance coefficients needs to be considered. Wherein, the average value of the friction resistance coefficient can be calculated to construct the steam pressure drop gradient model according to the average value of the friction resistance coefficient.
After the vapor pressure drop gradient model is constructed, the pressure drop between adjacent test points can be calculated according to the temperature data and the pressure data corresponding to each test point, and the pressure drop obtained according to the vapor pressure drop gradient model is used as a second pressure drop.
Referring to fig. 3, a flowchart for determining the dryness of steam corresponding to each test point in the embodiment of the application is shown. Specifically, steps 310 to 370 are included:
And 310, calculating the density of the saturated water and the density of the saturated steam corresponding to each test point according to the temperature data and the pressure data corresponding to each test point.
And 330, calculating the steam density corresponding to each test point according to the density of the saturated water, the density of the saturated steam and the steam dryness of the saturated steam corresponding to each test point.
And 350, calculating the steam flow rate corresponding to each test point according to the steam density corresponding to each test point.
And 370, constructing a vapor pressure gradient model based on the vapor density, the vapor flow rate and the friction resistance coefficient corresponding to each test point.
In the application, taking the case that no phase change exists in a shaft as an example, after temperature data and pressure data corresponding to each test point are obtained, the saturated water density and the saturated steam density corresponding to each test point can be calculated according to the formula (2) and the formula (3). Wherein, the formula (2) -formula (3) is as follows:
ρw＝3786.31-37.2487T+0.196246T2-5.04708×10-4T3
lnρs＝-93.7072+0.833941T-0.00320809T2+6.57652×10-6T3
In the formulas (2) - (3), ρ w is the saturated water density, ρ s is the saturated steam density, and T is the steam temperature (i.e., the acquired temperature data).
After calculating the saturated water density and saturated steam density corresponding to each test point, the steam density corresponding to each test point can be calculated according to the steam dryness corresponding to each test point and the formula (4). Wherein the formula (4) is as follows:
in formula (4): ρ is the steam density, ρ w is the saturated water density, ρ s is the saturated steam density, and X is the steam dryness.
And then, based on the steam density obtained in the formula (4), combining the formula (5) to obtain the steam flow rate corresponding to each test point. Wherein the formula (5) is as follows:
in equation (5), v is the steam flow rate, q is the steam mass flow, S is the wellbore cross-sectional area, ρ is the steam density.
And finally, constructing a steam pressure drop gradient model according to the parameters, friction resistance coefficients and momentum conservation principles obtained by the formula (1) -the formula (5). Wherein the vapor pressure gradient model is shown in the following formula (6):
In formula (6), Δp is the pressure loss per unit length, Δz is the unit length (i.e., the distance between the test points), f m is the friction resistance coefficient, ρ m is the density of the unit length of the wet steam fluid, v m is the average velocity of the unit length of the wet steam fluid, d is the inner tube diameter, and g is the gravitational acceleration.
In particular, the data used to construct the vapor pressure drop gradient model can be referenced in table 1. The table 1 is shown below:
TABLE 1
With continued reference to FIG. 2, in step 270, a steam quality of the wellbore is determined based on the first pressure drop, and the second pressure drop.
In the application, after the first pressure drop is obtained according to the obtained pressure data corresponding to each test point and the second pressure drop is obtained according to the vapor pressure drop gradient model, the first pressure drop and the second pressure drop can be compared, so that the accuracy of the second pressure drop is proved.
After the accuracy of the second pressure drop is proved, the temperature data, the pressure data and the vapor pressure drop gradient model corresponding to each test point can be combined to obtain the vapor dryness corresponding to each test point. And then, determining the steam dryness of the shaft according to the dryness drop and the steam dryness corresponding to each test point calculated according to the steam pressure drop gradient model.
In one embodiment of the present application, the determining the steam dryness of the wellbore according to the first pressure drop and the second pressure drop may specifically include step 271:
And step 271, judging the first pressure drop and the second pressure drop, and if the absolute value of the difference between the first pressure drop and the second pressure drop is smaller than or equal to a preset value, determining the steam dryness of the shaft according to the dryness drop.
In the method, after a first pressure drop is obtained according to the obtained pressure data corresponding to each test point and a second pressure drop is obtained according to a vapor pressure drop gradient model, the first pressure drop and the second pressure drop are judged, and if the absolute value of the difference value between the first pressure drop and the second pressure drop is smaller than or equal to a preset value, the vapor dryness of the shaft is determined according to the dryness drop.
In combination with the above method, it will be appreciated that the first pressure drop is derived from measured pressure data at each test point in the wellbore. The second pressure drop is calculated by the vapor pressure drop gradient model, i.e. the second pressure drop calculated by the vapor pressure drop gradient model can be understood as a predicted or theoretical value of the pressure drop. Therefore, according to comparing the first pressure drop and the second pressure drop and combining the change trend of the steam dryness in the shaft, the steam dryness of the whole shaft can be obtained. At this time, the steam dryness of the entire well bore obtained according to the steam pressure gradient model may be understood as a predicted value or a theoretical value of the steam dryness of the well bore. Therefore, through the vapor pressure gradient die, the vapor dryness of different shafts can be accurately and efficiently calculated, and the actual vapor dryness of the shafts does not need to be obtained in large quantity, so that the convenience of calculating the vapor dryness of the shafts is improved.
In one embodiment of the present application, the determining the steam dryness of the wellbore according to the first pressure drop and the second pressure drop may specifically further include step 272:
Step 272, if the absolute value of the difference between the first pressure drop and the second pressure drop is greater than a preset value, adjusting the dryness drop to make the absolute value of the difference between the first pressure drop and the second pressure drop smaller than or equal to the preset value.
In the present application, if the absolute value of the difference between the first pressure drop and the second pressure drop is greater than a preset value, it is indicated that an error occurs in the calculation of the second pressure drop. Specifically, since the first pressure drop is calculated according to the pressure data corresponding to the actual test point, it can be deduced that an error occurs in the construction of the vapor pressure gradient model. Furthermore, since the vapor pressure gradient model is obtained according to the calculated pressure data corresponding to each test point (i.e. the predicted pressure value or the theoretical pressure value corresponding to each test point), it can be deduced that the calculated pressure data corresponding to each test point has errors. Furthermore, since the calculated pressure data corresponding to each test point is calculated according to the set dryness drop, it can be deduced that the error occurs in the set dryness drop.
In summary, the above logic derivation process may be used to adjust the dryness drop set value, so as to reconstruct the steam pressure drop gradient model according to the adjusted dryness drop, so that the absolute value of the difference between the first pressure drop and the second pressure drop is smaller than or equal to the preset value, and further, an accurate steam pressure drop gradient model may be determined.
In one embodiment of the present application, after obtaining the steam quality of the wellbore, step 273 may specifically be further included:
Step 273, after obtaining the steam dryness of the shaft, obtaining a dryness profile curve corresponding to the shaft according to the steam dryness of the shaft, wherein the dryness profile curve is used for representing the relation between the depth of the shaft and the steam dryness of the shaft.
According to the method, after the steam dryness of the shaft is obtained, a dryness profile curve corresponding to the shaft can be obtained according to the steam dryness. For example, with continued reference to fig. 1, after obtaining the dryness of the steam corresponding to the large-diameter heat-insulating pipe, the small-diameter heat-insulating pipe, and the oil pipe, a dryness profile curve corresponding to each pipe is obtained, so as to obtain a dryness profile curve of the shaft. It should be noted that, since the calculation of the dryness of the steam is related to the material of the pipe and the annulus condition, in fig. 1, the dryness profile curve corresponding to the oil pipe is composed of two sections of curves. Meanwhile, the variation difference of the steam dryness among different pipelines and the variation efficiency of the steam dryness can be obtained according to the dryness profile curve.
In the present application, referring to fig. 4, a flowchart of calculation of steam dryness and dryness profile curves in an embodiment of the present application is shown. Setting a plurality of test points in a well bore, and acquiring pressure data and temperature data corresponding to each test point. According to the acquired pressure data and temperature data, the actual pressure drop between two adjacent test points can be calculated, and the actual pressure drop is taken as a first pressure drop. Meanwhile, the phase state in the shaft can be judged according to the acquired pressure data and temperature data, so that the steam dryness corresponding to each test point can be determined according to different phase states.
And then, determining the steam dryness corresponding to each test point by setting dryness drop and combining the wellbore depth corresponding to each test point. And then, constructing a steam pressure drop gradient model based on temperature data, pressure data, steam dryness and friction resistance coefficient corresponding to each test point, and calculating the pressure drop between adjacent test points according to the steam pressure drop gradient model to serve as a second pressure drop.
And comparing the first pressure drop obtained based on actual calculation with the second pressure drop obtained through calculation of the vapor pressure gradient model, so that the overall vapor dryness of the shaft can be determined. Therefore, the method can improve the convenience of acquiring the dryness of the shaft steam. Meanwhile, after the steam dryness of the shaft is obtained, a dryness section curve corresponding to each section of shaft structure can be obtained, so that the dryness section curve of the shaft is obtained.
The application also provides a device for determining the dryness of the shaft steam based on the same inventive concept, and referring to fig. 5, a schematic structural diagram of the device for determining the dryness of the shaft steam in the embodiment of the application is shown. The determining device 500 includes: an obtaining unit 501, configured to obtain temperature data, pressure data, and a friction resistance coefficient corresponding to each test point in a wellbore, calculate a pressure drop between adjacent test points according to the pressure data, and take the pressure drop as a first pressure drop; a setting unit 502, configured to set dryness drop, so as to determine dryness of steam corresponding to each test point according to the dryness drop; a construction unit 503, configured to construct a steam pressure drop gradient model according to the temperature data, the pressure data, the steam dryness, and the friction resistance coefficient corresponding to each test point, so as to calculate a pressure drop between adjacent test points according to the steam pressure drop gradient model, and take the pressure drop obtained according to the steam pressure drop gradient model as a second pressure drop; a determining unit 504 for determining a steam quality of the wellbore based on the first pressure drop and the second pressure drop.
For details not disclosed in the embodiments of the apparatus of the present application, please refer to the embodiments of the method of the present application.
The present application also provides a computer readable storage medium, based on the same inventive concept, characterized in that at least one program code is stored in the computer readable storage medium, the at least one program code is loaded and executed by a processor to implement operations performed by the method
The application also provides an electronic device based on the same inventive concept, and referring to fig. 6, fig. 6 shows a schematic structural diagram of the electronic device in the embodiment of the application.
The electronic device comprises one or more memories 604, one or more processors 602 and at least one computer program (program code) stored on the memories 604 and executable on the processors 602, the processor 602 implementing the methods as described above when executing the computer program.
Where in FIG. 6, a bus architecture (represented by bus 600), bus 600 may include any number of interconnected buses and bridges, with bus 600 linking together various circuits, including one or more processors, represented by processor 602, and memory, represented by memory 604. Bus 600 may also link together various other circuits such as peripheral devices, voltage regulators, power management circuits, etc., as are well known in the art and, therefore, will not be described further herein. The bus interface 605 provides an interface between the bus 600 and the receiver 601 and transmitter 603. The receiver 601 and the transmitter 603 may be the same element, i.e. a transceiver, providing a unit for communicating with various other apparatus over a transmission medium. The processor 602 is responsible for managing the bus 600 and general processing, while the memory 604 may be used to store data used by the processor 602 in performing operations.
The functions described herein may be implemented in hardware, software executed by a processor, firmware, or any combination thereof. If implemented in software that is executed by a processor, the functions may be stored on or transmitted over as one or more instructions or code on a computer-readable medium. Other examples and implementations are within the scope and spirit of the 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, hardwired, or a combination of any of these. In addition, each functional unit may be integrated in one processing unit, each unit may exist alone physically, or two or more units may be integrated in one unit.
In the several embodiments provided in the present application, it should be understood that the disclosed technology may be implemented in other manners. The above-described embodiments of the apparatus are merely exemplary, and the division of the units, for example, may be a logic function division, and may be implemented in another manner, for example, a plurality of units or components may be combined or may be integrated into another system, or some features may be omitted, or not performed. Alternatively, the coupling or direct coupling or communication connection shown or discussed with each other may be through some interfaces, units or modules, or may be in electrical or other forms.
The units described as separate components may or may not be physically separate, and components as control devices may or may not be physical units, may be located in one place, or may be distributed over a plurality of units. Some or all of the units may be selected according to actual needs to achieve the purpose of the solution of this embodiment.
The integrated units, if implemented in the form of software functional units and sold or used as stand-alone products, may be stored in a computer readable storage medium. Based on such understanding, the technical solution of the present application may be embodied essentially or in part or all of the technical solution or in part in the form of a software product stored in a storage medium, including instructions for causing a computer device (which may be a personal computer, a server, or a network device, etc.) to perform all or part of the steps of the method according to the embodiments of the present application. And the aforementioned storage medium includes: a usb disk, a Read-Only Memory (ROM), a random access Memory (RAM, random Access Memory), a removable hard disk, a magnetic disk, or an optical disk, or other various media capable of storing program codes.
The above description is only an example of the present application and is not intended to limit the present application, but various modifications and variations can be made to the present application by those skilled in the art. Any modification, equivalent replacement, improvement, etc. made within the spirit and principle of the present application should be included in the scope of the claims of the present application.
Claims (10)
1. A method of determining dryness of a wellbore vapor, the method comprising:
acquiring temperature data, pressure data and friction resistance coefficients corresponding to all test points in a shaft, calculating pressure drops between adjacent test points according to the pressure data, and taking the pressure drops as first pressure drops;
setting dryness drop to determine the dryness of steam corresponding to each test point according to the dryness drop;
According to the temperature data, the pressure data, the steam dryness and the friction resistance coefficient corresponding to each test point, a steam pressure drop gradient model is built, so that the pressure drop between adjacent test points is calculated according to the steam pressure drop gradient model, and the pressure drop obtained according to the steam pressure drop gradient model is used as a second pressure drop;
Determining a steam quality of the wellbore based on the first pressure drop and the second pressure drop.
2. The method of claim 1, wherein determining the steam dryness for each test point comprises:
judging whether a phase state change condition exists in a shaft or not according to temperature data and pressure data corresponding to each test point in the shaft;
If the phase change condition does not exist in the shaft, acquiring the wellhead steam dryness of the shaft, and determining the steam dryness corresponding to each test point according to the wellhead steam dryness and the dryness drop.
3. The method according to claim 2, wherein the method further comprises:
determining a depth of a phase change location in the wellbore if the wellbore has a phase change condition;
And determining the steam dryness corresponding to each test point according to the depth of the phase change position and the dryness drop.
4. The method of claim 1, wherein said constructing a vapor pressure drop gradient model comprises:
Calculating the density of saturated water and the density of saturated steam corresponding to each test point according to the temperature data and the pressure data corresponding to each test point;
Calculating the steam density corresponding to each test point according to the density of the saturated water, the density of the saturated steam and the dryness of the steam corresponding to each test point;
calculating the steam flow rate corresponding to each test point according to the steam density corresponding to each test point;
And constructing a vapor pressure gradient model based on the vapor density, vapor flow rate and friction resistance coefficient corresponding to each test point.
5. The method of claim 1, wherein determining the steam quality of the wellbore based on the first pressure drop and the second pressure drop comprises:
Judging the first pressure drop and the second pressure drop, and if the absolute value of the difference value between the first pressure drop and the second pressure drop is smaller than or equal to a preset value, determining the steam dryness of the shaft according to the dryness drop.
6. The method of claim 5, wherein the method further comprises:
and if the absolute value of the difference value between the first pressure drop and the second pressure drop is larger than a preset value, adjusting the dryness drop so that the absolute value of the difference value between the first pressure drop and the second pressure drop is smaller than or equal to the preset value.
7. The method according to claim 1, characterized in that the method comprises:
And after obtaining the steam dryness of the shaft, acquiring a dryness profile curve corresponding to the shaft according to the steam dryness of the shaft, wherein the dryness profile curve is used for representing the relation between the depth of the shaft and the steam dryness of the shaft.
8. A device for determining dryness of steam in a well bore, the device comprising:
the device comprises an acquisition unit, a control unit and a control unit, wherein the acquisition unit is used for acquiring temperature data, pressure data and friction resistance coefficients corresponding to all test points in a shaft, calculating pressure drops between adjacent test points according to the pressure data, and taking the pressure drops as first pressure drops;
The setting unit is used for setting dryness drop so as to determine the dryness of the steam corresponding to each test point according to the dryness drop;
The construction unit is used for constructing a steam pressure drop gradient model according to the temperature data, the pressure data, the steam dryness and the friction resistance coefficient corresponding to each test point, calculating the pressure drop between the adjacent test points according to the steam pressure drop gradient model, and taking the pressure drop obtained according to the steam pressure drop gradient model as a second pressure drop;
and the determining unit is used for determining the steam dryness of the shaft according to the first pressure drop and the second pressure drop.
9. A computer readable storage medium having stored therein at least one program code loaded and executed by a processor to implement operations performed by the method of any of claims 1 to 7.
10. An electronic device comprising one or more processors and one or more memories, the one or more memories having stored therein at least one piece of program code that is loaded and executed by the one or more processors to implement the operations performed by the method of any of claims 1-7.
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| CN202211522810.4A CN118112051A (en) | 2022-11-30 | 2022-11-30 | Method, device, medium and electronic equipment for determining dryness of shaft steam |
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| CN202211522810.4A CN118112051A (en) | 2022-11-30 | 2022-11-30 | Method, device, medium and electronic equipment for determining dryness of shaft steam |
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| CN202211522810.4A Pending CN118112051A (en) | 2022-11-30 | 2022-11-30 | Method, device, medium and electronic equipment for determining dryness of shaft steam |
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