CN114861963A - Method and device for estimating yield of gas well - Google Patents
Method and device for estimating yield of gas well Download PDFInfo
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- CN114861963A CN114861963A CN202110171366.5A CN202110171366A CN114861963A CN 114861963 A CN114861963 A CN 114861963A CN 202110171366 A CN202110171366 A CN 202110171366A CN 114861963 A CN114861963 A CN 114861963A
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- G06Q—INFORMATION AND COMMUNICATION TECHNOLOGY [ICT] SPECIALLY ADAPTED FOR ADMINISTRATIVE, COMMERCIAL, FINANCIAL, MANAGERIAL OR SUPERVISORY PURPOSES; SYSTEMS OR METHODS SPECIALLY ADAPTED FOR ADMINISTRATIVE, COMMERCIAL, FINANCIAL, MANAGERIAL OR SUPERVISORY PURPOSES, NOT OTHERWISE PROVIDED FOR
- G06Q10/00—Administration; Management
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
- E21B47/06—Measuring temperature or pressure
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- G—PHYSICS
- G06—COMPUTING; CALCULATING OR COUNTING
- G06Q—INFORMATION AND COMMUNICATION TECHNOLOGY [ICT] SPECIALLY ADAPTED FOR ADMINISTRATIVE, COMMERCIAL, FINANCIAL, MANAGERIAL OR SUPERVISORY PURPOSES; SYSTEMS OR METHODS SPECIALLY ADAPTED FOR ADMINISTRATIVE, COMMERCIAL, FINANCIAL, MANAGERIAL OR SUPERVISORY PURPOSES, NOT OTHERWISE PROVIDED FOR
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Abstract
The application relates to a method and a device for estimating gas well yield, and belongs to the technical field of natural gas exploitation. The method comprises the steps of determining a plurality of production well sections of a target gas well and a flow pattern of each production well section according to logging data of the target gas well; calculating the gas phase apparent velocity of each production well section according to a gas phase apparent velocity formula corresponding to the flow pattern to which each production well section belongs; calculating the gas production rate of each production well section according to the gas phase superficial velocity of each production well section and the cross-sectional area of the casing; calculating a first total gas production rate of a casing of the target gas well according to the gas production rate of each produced well section; acquiring a second total gas production rate of an oil pipe of the target gas well; and estimating the daily gas production of the target gas well according to the first total gas production and the second total gas production. By the method and the device, the flow pattern of the target gas well is divided, the gas production rate of the output well section is calculated, the total gas production rate in the oil pipe is used for correcting the gas production rate of the output well section, and the accuracy of the estimation result can be improved.
Description
Technical Field
The application relates to the technical field of natural gas exploitation, in particular to a method and a device for estimating gas well yield.
Background
Gas wells typically produce natural gas as a mist stream at the beginning of their production, and the liquid in the well bore is usually distributed in the gas phase in the form of droplets, in which case the gas is a continuous phase and the liquid is a discontinuous phase, and most of the produced liquid is condensed water. When the gas reservoir pressure is reduced to cause the gas flow rate of a shaft to be reduced and the liquid carrying capacity to be reduced, a part of formation water is produced along with the gas flow rate. When the gas flow rate is reduced to the flow rate of the adjacent liquid carrying boundary, liquid begins to gather in the shaft, and gas is produced from the accumulated liquid to form unstable multiphase flow.
Therefore, in estimating the gas well yield, if the whole production zone is regarded as a flow pattern, such as a fog flow pattern, to estimate the gas well yield, the difference between the actual yield and the estimated yield is large, and the accuracy of the estimated result is low.
Disclosure of Invention
The application provides a method and a device for estimating gas well yield, which can overcome the problems in the related art. The technical scheme is as follows:
according to the application, a method for estimating the yield of a gas well is provided, and the method comprises the following steps:
determining a plurality of production well sections of a target gas well and a flow pattern of each production well section according to logging data of the target gas well;
calculating the gas phase apparent velocity of each production well section according to a gas phase apparent velocity formula corresponding to the flow pattern to which each production well section belongs;
calculating the gas production rate of each production well section according to the gas phase superficial velocity of each production well section and the cross-sectional area of the casing of the target gas well;
calculating a first total gas production rate of a casing of the target gas well according to the gas production rate of each produced well section;
obtaining a second total gas production rate of an oil pipe of the target gas well;
if the difference value between the first total gas production rate and the second total gas production rate is smaller than a set threshold value, estimating the daily gas production rate of the target gas well according to the first total gas production rate;
and if the difference value between the first total gas production rate and the second total gas production rate is not less than the set threshold value, determining a correction coefficient according to the first total gas production rate and the second total gas production rate, correcting the gas production rate of each production well section by using the correction coefficient to obtain the corrected gas production rate of each production well section, and estimating the daily gas production rate of the target gas well according to the corrected gas production rate of each production well section.
Optionally, determining a correction coefficient according to the first total gas production rate and the second total gas production rate, and correcting the gas production rate of each production well section by using the correction coefficient to obtain a corrected gas production rate of each production well section, including:
taking the ratio of the second total gas production rate and the first total gas production rate as a correction coefficient;
and multiplying the gas production rate of each production well section by the correction coefficient respectively to obtain the corrected gas production rate of each production well section.
Optionally, the well logging data includes at least one of flow data, density, pressure, temperature, water holdup, and gas holdup.
Optionally, the flow pattern includes a mist flow pattern, a slug flow pattern, and a bubble flow pattern, and the logging data includes a gas holdup;
gas holdup rate Y g Satisfy Y g The flow pattern of the production well section of more than or equal to 0.85 is the mist flow pattern;
gas holdup rate Y g Satisfy 0.3 < Y g The flow pattern of the production well section less than or equal to 0.85 belongs to the slug-shaped flow pattern;
gas holdup rate Y g Satisfy Y g The flow pattern to which the production interval < 0.3 belongs is the bubbly flow pattern.
Optionally, the flow pattern comprises a mist flow pattern, a slug flow pattern, and a bubble flow pattern;
the gas phase apparent velocity formula corresponding to the fog flow pattern is as follows:
V sg ＝C V ×Y g ×V m ；
the gas phase apparent velocity formula corresponding to the slug-like flow pattern is as follows:
the gas phase apparent velocity formula corresponding to the bubble flow pattern is as follows:
V sg ＝Y g ×V m +Y g ×(1-Y g )×V s ，V s ＝60×[0.95-(1-Y g ) 2 ] 0.25 +1.5；
in the formula: v sg Is the gas phase apparent velocity, m/s; c V The correction coefficient of the velocity profile is zero dimension; y is g The gas holdup is zero dimension; v m Is the total average velocity, m/s; c is a phase distribution coefficient, has no dimension and has a value range of 1.2 to 2; v t The buoyancy lifting speed of the bubbles in the static water is m/s; g is gravitational acceleration, cm/s 2 (ii) a D is the diameter of the casing of the target gas well, cm; rho w Is the density value of formation water in g/cm 3 ；ρ g Is the density value of the natural gas in the well in g/cm 3 ；V s The slip speed of air and water is m/s.
Optionally, the obtaining a second total gas production rate of the oil pipe of the target gas well includes:
and determining a second total gas production rate of the oil pipe of the target gas well through an online flowmeter in the oil pipe of the target gas well.
Optionally, the method further includes:
and calculating the water production of each production well section according to the apparent liquid phase velocity of each production well section and the cross-sectional area of the casing of the target gas well, wherein the apparent liquid phase velocity of each production well section is the difference between the total average velocity and the apparent gas phase velocity of the corresponding production well section.
On the other hand, the device for estimating the gas well yield is also provided,
the flow pattern determining module is used for determining a plurality of output well sections of the target gas well and the flow pattern of each output well section according to the logging data of the target gas well;
the first calculation module is used for calculating the gas phase apparent velocity of each production well section according to a gas phase apparent velocity formula corresponding to the flow pattern to which each production well section belongs;
the second calculation module is used for calculating the gas production rate of each production well section according to the gas phase superficial velocity of each production well section and the cross section area of the casing of the target gas well;
the third calculation module is used for calculating the first total gas production rate of the casing of the target gas well according to the gas production rate of each produced well section;
the acquisition module is used for acquiring a second total gas production rate of the oil pipe of the target gas well;
the first estimation module is used for estimating the daily gas production of the target gas well according to the first total gas production if the difference value between the first total gas production and the second total gas production is smaller than a set threshold value;
and if the difference value between the first total gas production rate and the second total gas production rate is not less than the set threshold value, determining a correction coefficient according to the first total gas production rate and the second total gas production rate, correcting the gas production rate of each production well section by using the correction coefficient to obtain the corrected gas production rate of each production well section, and estimating the daily gas production rate of the target gas well according to the corrected gas production rate of each production well section.
Optionally, the first estimation module is configured to:
taking the ratio of the second total gas production and the first total gas production as a correction coefficient;
and multiplying the gas production rate of each production well section by the correction coefficient respectively to obtain the corrected gas production rate of each production well section.
Optionally, the apparatus further includes a second estimation module, configured to calculate a water production rate of each production well section according to the superficial velocity of the liquid phase of each production well section and the cross-sectional area of the casing of the target gas well, where the superficial velocity of the liquid phase of each production well section is a difference between the total average velocity and the superficial velocity of the gas phase of the corresponding production well section.
The beneficial effect that technical scheme that this application provided brought includes at least:
in the embodiment of the application, when the yield of the gas well is estimated, the flow patterns of all produced well sections of the target gas well are divided, then the gas production rates of the produced well sections are calculated by using the corresponding flow patterns, and then the gas production rates of all the produced well sections are corrected by using the total gas production rate in the oil pipe, so that the estimated daily gas production rate has smaller deviation compared with the actual gas production rate, and the accuracy of the estimation result can be improved.
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.
Drawings
The accompanying drawings, which are incorporated in and constitute a part of this specification, illustrate embodiments consistent with the present application and together with the description, serve to explain the principles of the application. In the drawings:
FIG. 1 is a schematic flow diagram illustrating a method for estimating gas well production according to an embodiment;
FIG. 2 is a schematic diagram illustrating a natural gamma curve and temperature curve according to an embodiment;
FIG. 3 is a diagram illustrating the production of well log data according to an embodiment;
fig. 4 is a schematic diagram illustrating a composition structure of PPI software according to an embodiment;
FIG. 5 is a diagram illustrating an interface for PPI software login, according to an embodiment;
FIG. 6 is an interface diagram illustrating a log data loading according to an embodiment;
FIG. 7 is an interface diagram illustrating PVT parameter scaling of a medium according to an embodiment;
FIG. 8 is a schematic diagram illustrating an interface for single-layer parameter setting and flow intersection calculation, according to an embodiment;
FIG. 9 is a diagram of an interface for one result view, shown in accordance with an embodiment;
FIG. 10 is a schematic diagram of an apparatus for estimating gas well production according to an embodiment;
FIG. 11 is a schematic diagram of an apparatus for estimating gas well production according to an embodiment.
With the above figures, there are shown specific embodiments of the present application, which will be described in more detail below. These drawings and written description are not intended to limit the scope of the inventive concepts in any manner, but rather to illustrate the inventive concepts to those skilled in the art by reference to specific embodiments.
Detailed Description
Reference will now be made in detail to the exemplary embodiments, examples of which are illustrated in the accompanying drawings. When the following description refers to the accompanying drawings, like numbers in different drawings represent the same or similar elements unless otherwise indicated. The embodiments described in the following exemplary embodiments do not represent all embodiments consistent with the present application. Rather, they are merely examples of apparatus and methods consistent with certain aspects of the present application, as detailed in the appended claims.
The embodiment of the application provides a method for estimating the yield of a gas well, which can be executed by equipment provided with PPI software, wherein the PPI software is software for processing logging data and explaining a production zone of the gas well according to the logging data.
The method may be performed according to the flow shown in fig. 1.
In step 101, a plurality of production well sections of the target gas well and a flow pattern of each production well section are determined according to the logging data of the target gas well.
Wherein the target gas well may be at least one gas well in a gas field, for example, may be at least one gas well in an astringency north gas field.
The well log data may include at least one of magnetic positioning, natural gamma, flow data, density, pressure, temperature, water and gas holdup, among others.
In one example, the temperature profile reflects the combined effects of water production, gas production, and the geothermal field on the reservoir, e.g., if the temperature rise of the water production producing temperature is sufficient to overcome the temperature drop of the gas production producing temperature, the temperature profile appears as a positive anomaly, as shown in fig. 2 (a) and (c), and the temperature profile at the reservoir appears as a positive anomaly. For another example, if the temperature rise due to the produced water is exactly equal to the temperature drop due to the produced gas or no production, the temperature curve is displayed as a normal gradient. For another example, if the temperature rise due to water production is less than the temperature drop due to gas production, the temperature profile will exhibit a negative anomaly, as shown in fig. 2 (b), and the temperature profile at the reservoir will exhibit a negative anomaly.
In one example, the natural gamma curve shows abnormally high values on the reservoir and the magnitude of the anomaly has an increasing trend as the water production time and water production increases, as can be seen in fig. 2 (a), (b) and (c).
In one example, when liquid accumulation and sand accumulation occur at the bottom of the well, the density curve changes correspondingly when measured at different depths, and the sand accumulation can cause the flow curve to become poor in correlation.
In one example, the density, gas holdup and pressure curves can obviously show the change of a gas-liquid interface in a target gas well, and the gas-liquid mixing position and the mist flow pattern have inflection points at the liquid accumulation position and have better consistency, so that the density curve, the gas holdup curve, the pressure curve and the like can be used for judging the flow pattern of each produced well section, and the flow pattern is preferably judged according to the gas holdup under the condition that the gas holdup curve is formed in the judgment.
After the logging data are obtained, the production zone of the target gas well can be divided according to the change of the logging data to obtain a plurality of output well sections. For example, as shown in fig. 3, for a data plot of log data for a target interval comprising two perforated layers 1048.0m through 1050.4m and 1051.6m through 1056.0m, production intervals partitioned by the log data may include three production intervals 1048.0m through 1050.4m, 1051.0m through 1052.7m, and 1053.3m through 1056.0 m.
In fig. 3, (a) is a log data diagram at a perforation layer, and in fig. 3, (b) is a log data diagram above the perforation layer.
The flow pattern may include a mist flow pattern, a slug flow pattern, and a bubble flow pattern, and the flow pattern of each production interval is also determined according to the log data.
For example, if the well log data includes gas holdup, the flow patterns to which the various producing intervals belong may be determined in terms of gas holdup, illustratively, gas holdup Y g Satisfy Y g The flow pattern of the production well section is more than or equal to 0.85, the flow pattern is a mist flow pattern, and the gas holdup rate is Y g Y is not less than 0.3 g The flow pattern of the production well section less than 0.85 is a slug flow pattern, and the gas holdup rate Y g Satisfy Y g The flow pattern to which the production interval < 0.3 belongs is a bubbly flow pattern.
As another example, if the well log data does not include gas holdup, the flow patterns to which the various producing intervals belong may also be determined based on density, illustratively, satisfying ρ m ＜0.304g/cm 3 The flow pattern of the production well section is fog-like and popular, and the density meets 0.304g/cm 3 ≤ρ m ＜0.692g/cm 3 The flow pattern of the production well section is a slug flow pattern, and the density meets rho m ≥0.692g/cm 3 The production interval of (a) is of a bubbly flow pattern.
As described above, when the logging data includes a gas holdup, the flow pattern to which each production well section belongs may be determined on the basis of the principle that the gas holdup is prioritized, and when the logging data does not include a gas holdup, the flow pattern to which each production well section belongs may be determined from data such as density, pressure, and temperature.
In step 102, the gas phase superficial velocity of each production well section is calculated according to the gas phase superficial velocity formula corresponding to the flow pattern to which each production well section belongs.
In one example, after determining the flow pattern to which each production interval belongs based on log data such as gas holdup, density, pressure, and temperature, the gas superficial velocity of each production interval may be calculated according to a gas superficial velocity formula corresponding to each flow pattern.
The gas phase apparent velocity formula corresponding to the mist flow pattern is as follows:
V sg ＝C V ×Y g ×V m equation 1
In the formula, V sg Is the gas phase apparent velocity, m/s; c V The correction coefficient of the velocity profile is zero dimension; y is g The gas holdup is zero dimension; v m The total average velocity, m/s, may be determined from the flow in the log data.
The gas phase apparent velocity formula corresponding to the slug-like flow pattern is as follows:
V sg ＝Y g ×(C×V m +V t ) Equation 2
Wherein the content of the first and second substances,
in the formula, C is a phase distribution coefficient, has no dimension and has a value range of 1.2 to 2; v t The buoyancy lifting speed of the bubbles in the static water is m/s; g is gravity acceleration, cm/s 2 (ii) a D is the diameter of the casing of the target gas well in cm; rho w Is the density value of formation water in g/cm 3 ；ρ g Density value of natural gas in g/cm 3 。
The gas phase apparent velocity formula corresponding to the bubble flow pattern is as follows:
V sg ＝Y g ×V m +Y g ×(1-Y g )×V s equation 3
Wherein, V s ＝60×[0.95-(1-Y g ) 2 ] 0.25 +1.5
In the formula, V s The slip speed of air and water is m/s.
Thus, if the flow pattern to which the producing interval belongs is a vaporous flow pattern, the superficial gas phase velocity can be determined according to equation 1, if the flow pattern to which the producing interval belongs is a slug flow pattern, the superficial gas phase velocity can be determined according to equation 2, and if the flow pattern to which the producing interval belongs is a bubble flow pattern, the superficial gas phase velocity can be determined according to equation 3.
In step 103, the gas production rate for each production interval is calculated based on the superficial gas phase velocity for each production interval and the cross-sectional area of the casing of the target gas well.
The gas production rate of each production well section is the flow rate of gas phase in units, and the daily gas production rate is calculated by multiplying time.
In one example, since the producing zones are all below the tubing, the medium is flowing in the casing and accordingly, after determining the superficial gas velocities for each producing zone, the gas production for each producing zone can be calculated according to equation 4 below.
Q g ＝V sg ×S Sleeve pipe Equation 4
In the formula, Q s For gas production, V sg Is the apparent velocity of the gas phase, S Sleeve pipe The cross-sectional area of the sleeve.
In step 104, a first total gas production of the casing of the target gas well is calculated from the gas production of each producing interval.
In one example, after calculating the gas production rate of each production well section according to the flow pattern to which each production well section belongs, and the gas apparent velocity formula and formula 4 corresponding to each flow pattern, the sum of the gas production rates of each production well section is the first total gas production rate in the casing of the target gas well, which can be denoted as Q 1 。
In step 105, a second total gas production rate of the tubing of the target gas well is obtained.
In one example, in acquiring logging data, a flowmeter, such as one or both of a turbine flowmeter and an online flowmeter, may be lowered in a target gas well to enable a flow rate of a gas phase flow in a tubing to be determined via the flowmeter and then based on the determined flow rateThe total gas production rate of the oil pipe in unit time can be obtained by the cross section area of the oil pipe and can be recorded as a second total gas production rate, and Q is used 2 And (4) showing.
The turbine flowmeter and the online flowmeter can be lowered in the target gas well, the turbine flowmeter is used for obtaining a flow curve in the casing, and the online flowmeter is used for obtaining the flow in the oil pipe.
In step 106, the daily gas production of the target gas well is estimated.
In one example, a first total gas production Q within the casing of a target gas well is determined 1 And a second total gas production Q in the oil pipe 2 The daily gas production of the target gas well may be estimated later.
Theoretically, according to the principle of conservation of mass, no matter whether accumulated liquid exists in the target gas well or not and whether 'backflow' exists in the target gas well or not, only the relative flow speed of the gas in different environments is changed, the gas production rate cannot be changed, and then, the first total gas production rate Q 1 And a second total gas production amount Q 2 And are equal. But with a liquid film in the target gas well, the first total gas production Q is calculated 1 And a second total gas production amount Q 2 There may be a deviation.
If the difference between the first total gas production rate and the second total gas production rate is small, for example, smaller than a set threshold, the difference between the first total gas production rate and the second total gas production rate is negligible, and then the daily gas production rate of the target gas well can be estimated according to the first total gas production rate. For example, the first total gas production may be multiplied by the time of day to obtain the daily gas production of the target gas well.
And if the difference between the first total gas production rate and the second total gas production rate is relatively large, for example, not smaller than a set threshold value, the difference between the first total gas production rate and the second total gas production rate cannot be ignored, determining a correction coefficient according to the first total gas production rate and the second total gas production rate, correcting the gas production rate of each production well section by using the correction coefficient to obtain the corrected gas production rate of each production well section, and estimating the daily gas production rate of the target gas well according to the corrected gas production rate of each production well section.
Wherein the correction coefficient is the ratio of the second total gas production rate to the first total gas production rate.
In one example, the total gas production in the tubing may be used to scale the gas production of each producing interval to correct the gas production of each producing interval since the second total gas production in the tubing is relatively accurate.
For example, the gas production rates of the respective production intervals may be multiplied by the correction coefficients, respectively, to obtain corrected gas production rates of the respective production intervals. The sum of the corrected gas production rates of the various production well sections is the first total gas production rate corrected in the casing, and then the corrected first total gas production rate can be multiplied by the time of one day to obtain the daily gas production rate of the target gas well.
Therefore, the flow patterns of all the produced well sections of the target gas well are divided, the gas production rates of the produced well sections are calculated by using the flow patterns corresponding to the flow patterns, and then the total gas production rate in the oil pipe is used for correcting the gas production rates of all the produced well sections, so that the estimated daily gas production rate has smaller deviation compared with the actual gas production rate, and the accuracy of the estimated result can be improved.
In one example, after calculating the daily gas production of the target gas well, the daily water production can also be calculated, and accordingly, the method further comprises: and calculating the water yield of each production well section according to the liquid phase superficial velocity of each production well section and the cross-sectional area of the casing of the target gas well, wherein the liquid phase superficial velocity of each production well section is the difference between the total average velocity and the gas phase superficial velocity of the corresponding production well section.
Wherein, V sw ＝V m -V sg In the formula, V sw Is the apparent velocity of liquid phase, V m Is the total average velocity, V sg Is the gas phase superficial velocity.
In one example, after calculating the apparent liquid phase velocity for each production interval, the water production from each production interval may be calculated based on the product of the cross-sectional area of the casing and the apparent liquid phase velocity for each production interval, i.e., the water production from each production interval may be calculated according to equation 5. And then, calculating the total water yield of the target gas well according to the sum of the water yields of all the produced well sections, and multiplying the total water yield by the time of one day to obtain the daily water yield of the target gas well.
Q w ＝V sw ×S Sleeve pipe Equation 5
In the formula, Q w For water production, V sw Is the apparent velocity of the liquid phase, S Sleeve pipe The cross-sectional area of the sleeve.
Based on the above, the log data graph shown in fig. 3 is analyzed as follows:
from the turbine flow curve, the swing amplitude of the curve above 1048m is large, and even a crossing phenomenon occurs; from the density curve, the density value of the medium below 1056m is close to that of the formation water, and the density value is 1.2g/cm in the section of 1056m-1052m 3 It became 0.9g/cm 3 The negative anomaly of the temperature curve indicates that the pressure curve has an inflection point at 1051.2m, which indicates that there is an interfacial reaction at this point, indicating that the bottom hole effusion height position is about 1051.2m, therefore, it is judged that below 1052m, gas is produced from the effusion and carries part of the liquid flow, and the flow pattern should be bubble flow.
At 1050m, the density of the medium is from 0.68g/cm 3 It became 0.3g/cm 3 Therefore, 1050m or more should be a slug flow. When the fluid enters the oil pipe, the density value of the fluid changes again from 0.3g/cm 3 It became 0.12g/cm 3 And the method adopted at the moment is an oil pipe scale principle, a fog-like flow model is adopted, the total output is calculated, and the total gas production rate in the sleeve is corrected. The well logging data of the target gas well are respectively processed and explained according to the two conditions of not considering and considering the split flow type, and the results are shown in the table 1.
TABLE 1 target gas well output section well logging interpretation result table
Table 1 shows that when the target gas well is explained without considering the flow regime split, the total gas production is obtained at 22717.4m 3 D and a water yield of 28.6m 3 D, total gas production obtained when interpreting the target gas well in view of flow regime splitIs 18463m 3 D and a water yield of 23.5m 3 D, and the gas production amount measured with the ground is 17751m 3 D and water yield of 22.8m 3 Compared with the method/d, the relative error is 27.9% without considering the explanation of the flow pattern division, the relative error is 4.01% with considering the explanation of the flow pattern division, and the error is reduced by 22.89%.
In one possible application, the above procedure can be performed by using PPI software in the device, which is used to explain 60 wells with different yield characteristics in the northbound gas field, and is compared and explained with foreign software at the same time, the application effect is better, and the comparison result can be shown in table 2.
TABLE 2 Emeraude software and PPI software interpretation results and error statistics
In one example, the process of interpreting a target gas well using PPI software installed in the device may be as follows:
by adopting the interpretation method, the PPI aiming at the multiphase flow data processing software of the northbound gas field is compiled by utilizing the Visual Studio language and the XML data storage format. The software is mainly composed of three parts, and can be referred to as shown in fig. 4.
Firstly, a logging data decompiling module is developed by using a data bottom layer WellBase to complete decompiling of a single file and realize input of original data.
Secondly, by using a C + + input/output interface function provided by WellBase and a derived class logging data IO class (ClogIO) and a logging data processing class (ClogProcess) of a basic IO class (CWeisio), functional modules with logging data preprocessing, editing, interpreting, result outputting and the like are developed to realize data editing and outputting.
And finally, developing an interpretation calculation module with a segmentation processing function by utilizing a derived class logging data IO class (ClogIO) of a basic IO class (CWeisIO) and a logging data processing Fortran library (FLogIO) through a C + + input-output interface function provided by WellBase.
The method comprises the following specific steps: fig. 5 is a PPI interpretation software entry, fig. 6 is logging raw data loading, fig. 7 media PVT parameter conversion, fig. 8 is single layer parameter setting and flow intersection calculation, and fig. 9 is interpretation result viewing.
In the embodiment of the application, when the yield of the gas well is estimated, the flow patterns of all the produced well sections of the target gas well are divided, then the gas production rates of the produced well sections are calculated by using the flow patterns corresponding to the gas wells, and then the gas production rates of all the produced well sections are corrected by using the total gas production rate in the oil pipe, so that the estimated daily gas production rate has smaller deviation compared with the actual gas production rate, and the accuracy of the estimation result can be improved.
The embodiment of the present application further provides a device for estimating gas well yield, where the device may be the above device installed with PPI software, and as shown in fig. 10, the device may include:
the flow pattern determining module 1010 is used for determining a plurality of output well sections of a target gas well and a flow pattern of each output well section according to logging data of the target gas well;
the first calculation module 1020 is used for calculating the gas phase apparent velocity of each production well section according to a gas phase apparent velocity formula corresponding to the flow pattern to which each production well section belongs;
a second calculation module 1030 for calculating the gas production rate for each production interval based on the superficial gas phase velocity for each production interval and the cross-sectional area of the casing of the target gas well;
a third calculating module 1040, configured to calculate a first total gas production rate of a casing of the target gas well according to the gas production rate of each produced well section;
an obtaining module 1050, configured to obtain a second total gas production rate of the oil pipe of the target gas well;
a first estimation module 1060, configured to estimate the daily gas production of the target gas well according to the first total gas production if a difference between the first total gas production and the second total gas production is smaller than a set threshold;
and if the difference value between the first total gas production rate and the second total gas production rate is not less than the set threshold value, determining a correction coefficient according to the first total gas production rate and the second total gas production rate, correcting the gas production rate of each production well section by using the correction coefficient to obtain the corrected gas production rate of each production well section, and estimating the daily gas production rate of the target gas well according to the corrected gas production rate of each production well section.
Optionally, the first estimation module 1060 is configured to:
taking the ratio of the second total gas production rate and the first total gas production rate as a correction coefficient;
and multiplying the gas production rate of each production well section by the correction coefficient respectively to obtain the corrected gas production rate of each production well section.
Optionally, as shown in fig. 11, the apparatus further comprises a second estimator module 1070 for calculating the water production from each production well section based on the superficial velocity of the liquid phase of each production well section, which is the difference between the total average velocity and the superficial velocity of the gas phase of the corresponding production well section, and the cross-sectional area of the casing of the target gas well.
It should be noted that: in the device for estimating the gas well yield provided by the embodiment, when the gas well yield is estimated, the division of each functional module is only exemplified, and in practical application, the function distribution can be completed by different functional modules according to needs, that is, the internal structure of the equipment is divided into different functional modules, so as to complete all or part of the functions described above. In addition, the device for estimating the yield of the gas well provided by the embodiment and the method embodiment for estimating the yield of the gas well belong to the same concept, and the specific implementation process is detailed in the method embodiment and is not described again.
In the embodiment of the application, when the yield of the gas well is estimated, the flow patterns of all produced well sections of the target gas well are divided, then the gas production rates of the produced well sections are calculated by using the corresponding flow patterns, and then the gas production rates of all the produced well sections are corrected by using the total gas production rate in the oil pipe, so that the estimated daily gas production rate has smaller deviation compared with the actual gas production rate, and the accuracy of the estimation result can be improved.
It will be understood that the present application is not limited to the precise arrangements described above and shown in the drawings and that various modifications and changes may be made without departing from the scope thereof. The scope of the application is limited only by the appended claims.
Claims (10)
1. A method of predicting gas well production, the method comprising:
determining a plurality of production well sections of a target gas well and a flow pattern to which each production well section belongs according to logging data of the target gas well;
calculating the gas phase apparent velocity of each production well section according to a gas phase apparent velocity formula corresponding to the flow pattern to which each production well section belongs;
calculating the gas production rate of each production well section according to the gas phase superficial velocity of each production well section and the cross-sectional area of the casing of the target gas well;
calculating a first total gas production rate of a casing of the target gas well according to the gas production rate of each produced well section;
obtaining a second total gas production rate of an oil pipe of the target gas well;
if the difference value between the first total gas production rate and the second total gas production rate is smaller than a set threshold value, estimating the daily gas production rate of the target gas well according to the first total gas production rate;
and if the difference value between the first total gas production rate and the second total gas production rate is not less than the set threshold value, determining a correction coefficient according to the first total gas production rate and the second total gas production rate, correcting the gas production rate of each production well section by using the correction coefficient to obtain the corrected gas production rate of each production well section, and estimating the daily gas production rate of the target gas well according to the corrected gas production rate of each production well section.
2. The method of claim 1, wherein determining a correction factor based on the first total gas production and the second total gas production, and using the correction factor to correct the gas production of each producing interval to obtain a corrected gas production of each producing interval comprises:
taking the ratio of the second total gas production rate and the first total gas production rate as a correction coefficient;
and multiplying the gas production rate of each production well section by the correction coefficient respectively to obtain the corrected gas production rate of each production well section.
3. The method of claim 1, wherein the well log data comprises at least one of flow data, density, pressure, temperature, water holdup, and gas holdup.
4. The method of claim 1, wherein the flow patterns include a mist flow pattern, a slug flow pattern, and a bubble flow pattern, and the well log data includes a gas holdup;
gas holdup rate Y g Satisfy Y g The flow pattern of the production well section of more than or equal to 0.85 is the mist flow pattern;
gas holdup rate Y g Satisfy 0.3 < Y g The flow pattern of the production well section less than or equal to 0.85 belongs to the slug-shaped flow pattern;
gas holdup rate Y g Satisfy Y g The flow pattern to which the production interval < 0.3 belongs is the bubbly flow pattern.
5. The method of claim 1, wherein the flow pattern comprises a mist flow pattern, a slug flow pattern, and a bubble flow pattern;
the gas phase apparent velocity formula corresponding to the fog flow pattern is as follows:
V sg ＝C V ×Y g ×V m ；
the gas phase apparent velocity formula corresponding to the slug-like flow pattern is as follows:
V sg ＝Y g ×(C×V m +V t )，
the gas phase apparent velocity formula corresponding to the bubble flow pattern is as follows:
V sg ＝Y g ×V m +Y g ×(1-Y g )×V s ，V s ＝60×[0.95-(1-Y g ) 2 ] 0.25 +1.5；
in the formula: v sg Is the gas phase apparent velocity, m/s; c V The correction coefficient of the velocity profile is zero dimension; y is g The gas holdup is zero dimension; v m Is the total average velocity, m/s; c is a phase distribution coefficient, has no dimension and has a value range of 1.2 to 2; v t The buoyancy lifting speed of the bubbles in the static water is m/s; g is gravity acceleration, cm/s 2 (ii) a D is the diameter of the casing of the target gas well, cm; rho w Is the density value of formation water in g/cm 3 ；ρ g Density value of natural gas in g/cm 3 ；V s The slip speed of air and water is m/s.
6. The method of claim 1, wherein the obtaining a second total gas production rate from the tubing of the target gas well comprises:
and determining a second total gas production rate of the oil pipe of the target gas well through an online flowmeter in the oil pipe of the target gas well.
7. The method of any of claims 1 to 6, further comprising:
and calculating the water production of each production well section according to the apparent liquid phase velocity of each production well section and the cross-sectional area of the casing of the target gas well, wherein the apparent liquid phase velocity of each production well section is the difference between the total average velocity and the apparent gas phase velocity of the corresponding production well section.
8. An apparatus for predicting gas well production, the apparatus comprising:
the flow pattern determining module is used for determining a plurality of output well sections of the target gas well and the flow pattern of each output well section according to the logging data of the target gas well;
the first calculation module is used for calculating the gas phase apparent velocity of each production well section according to a gas phase apparent velocity formula corresponding to the flow pattern to which each production well section belongs;
the second calculation module is used for calculating the gas production rate of each production well section according to the gas phase superficial velocity of each production well section and the cross section area of the casing of the target gas well;
the third calculation module is used for calculating the first total gas production rate of the casing of the target gas well according to the gas production rate of each produced well section;
the acquisition module is used for acquiring a second total gas production rate of the oil pipe of the target gas well;
the first estimation module is used for estimating the daily gas production of the target gas well according to the first total gas production if the difference value between the first total gas production and the second total gas production is smaller than a set threshold value;
and if the difference value between the first total gas production rate and the second total gas production rate is not less than the set threshold value, determining a correction coefficient according to the first total gas production rate and the second total gas production rate, correcting the gas production rate of each production well section by using the correction coefficient to obtain the corrected gas production rate of each production well section, and estimating the daily gas production rate of the target gas well according to the corrected gas production rate of each production well section.
9. The apparatus of claim 8, wherein the first estimation module is configured to:
taking the ratio of the second total gas production rate and the first total gas production rate as a correction coefficient;
and multiplying the gas production rate of each production well section by the correction coefficient respectively to obtain the corrected gas production rate of each production well section.
10. The apparatus of claim 8 or 9, further comprising a second estimator module for calculating water production from each production well section based on the superficial velocity of the liquid phase of each production well section as the cross-sectional area of the casing of the target gas well, the superficial velocity of the liquid phase of each production well section being the difference between the total average velocity and the superficial velocity of the gas phase of the corresponding production well section.
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