CN112765903A - Layered gas injection parameter determination method and device for gas injection well - Google Patents
Layered gas injection parameter determination method and device for gas injection well Download PDFInfo
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Abstract
The application discloses a method and a device for determining layered gas injection parameters of a gas injection well, wherein the method comprises the following steps: establishing a layered gas injection model according to the gas injection parameters and the measurement parameters; obtaining a value of a measurement parameter; determining gas injection parameters according to the values of the measurement parameters and the layered gas injection model; the gas injection parameters comprise upper-layer system inlet pressure, lower-layer system inlet pressure, upper-layer system absorption air flow and lower-layer system absorption air flow, and the measurement parameters comprise wellhead injection total air flow, wellhead injection pressure, oil pipe inner diameter, average temperature and natural gas viscosity; wherein, the total air flow injected by the wellhead is equal to the sum of the absorption air flow of the upper layer system and the absorption air flow of the lower layer system. The gas injection parameter of layering gas injection can be accurately determined by the method, so that the flowing state of air in the shaft is determined, and layering gas injection is better guided.
Description
Technical Field
The application relates to the technical field of in-situ combustion exploitation, in particular to a method and a device for determining a layered gas injection parameter of a gas injection well.
Background
This section is intended to provide a background or context to the embodiments of the invention that are recited in the claims. The description herein is not admitted to be prior art by inclusion in this section.
At present, the gas injection well that carries out the gas injection to the in situ combustion mainly adopts the gas injection mode of general system, nevertheless because the oil deposit is mostly the oil deposit that development value is relatively poor, the quality is lower to Liaohe oil field du 66 oil deposits are the example, and it is thin interbedded oil deposit itself, and the small bed is many, and thickness is thin, finds after developing the in situ combustion that the oil deposit is vertical to be used the situation and has great difference. Wherein the Du I1-2 has the highest consumption, which is more than 82%, and the Du II 1-4 has only about 50%. The gas injection well inhales unevenly, influences the fireflood development effect.
In order to further accurately inject gas into a small layer, conventional steam flooding employs a manner in which a gas injection string is provided in a concentric double-tube gas injection string structure. However, if a concentric double-pipe gas injection pipe column structure is adopted, in order to meet higher gas injection flow, the requirements on the sizes of an oil layer casing pipe and a technical casing pipe and well conditions are higher on site, and particularly, the method has great limitation when a gas injection well for in-situ combustion with a large number of oil layers is implemented, and the ground gas injection technological process also needs to be independently constructed, but cannot meet the requirements of economic development of fire flooding, so the implementation range is limited. Therefore, there is a need for experimental investigation of layered gas injection into a pipe column.
However, reports and research results of numerical simulation gas of a shaft state injected in different quality categories aiming at different gas injection positions in an oil pipe column are not seen in the conventional pipe column layered gas injection, and related designs do not have corresponding numerical methods at present to simulate the pressure distribution of a shaft of a flame-fired gas injection well containing different oil nozzles and performing quality category gas injection, so that no data can be relied on in later-stage production adjustment and testing.
Therefore, there is a need to develop a method for determining gas injection parameters such as gas injection pressure in a shaft of a gas injection well for in-situ combustion, so as to accurately determine the flowing state of air in the shaft, better guide layered gas injection, further improve the utilization degree of in-situ combustion, improve the interlayer gas suction profile, and the like.
Disclosure of Invention
The embodiment of the application provides a gas injection well layered gas injection parameter determination method, which is used for accurately determining gas injection parameters of layered gas injection, thereby determining the flowing state of air in a shaft and better guiding the layered gas injection, and comprises the following steps:
establishing a layered gas injection model according to the gas injection parameters and the measurement parameters; obtaining a value of a measurement parameter; determining gas injection parameters according to the values of the measurement parameters and the layered gas injection model; the gas injection parameters comprise upper-layer system inlet pressure, lower-layer system inlet pressure, upper-layer system absorption air flow and lower-layer system absorption air flow, and the measurement parameters comprise wellhead injection total air flow, wellhead injection pressure, oil pipe inner diameter, average temperature and natural gas viscosity; wherein, the total air flow injected by the wellhead is equal to the sum of the absorption air flow of the upper layer system and the absorption air flow of the lower layer system.
The embodiment of this application still provides a gas injection well layering gas injection parameter determination device for the gas injection parameter of accurate definite layering gas injection to confirm the mobile state of the interior air of pit shaft, better instruction layering gas injection, the device includes:
the model building module is used for building a layered gas injection model according to the gas injection parameters and the measurement parameters; the acquisition module is used for acquiring the value of the measurement parameter; the determining module is used for determining gas injection parameters according to the values of the measurement parameters acquired by the acquiring module and the layered gas injection model established by the model establishing module; the gas injection parameters comprise upper-layer system inlet pressure, lower-layer system inlet pressure, upper-layer system absorption air flow and lower-layer system absorption air flow, and the measurement parameters comprise wellhead injection total air flow, wellhead injection pressure, oil pipe inner diameter, average temperature and natural gas viscosity; wherein, the total air flow injected by the wellhead is equal to the sum of the absorption air flow of the upper layer system and the absorption air flow of the lower layer system.
In the embodiment of the application, a gas injection parameter model related to gas injection parameters is established according to the gas injection parameters and the measurement parameters, the gas injection parameters are determined according to the measurement parameters which can be actually obtained in the gas injection process, and the gas injection parameters such as the pressure of different gas injection layers in a gas injection shaft are accurately determined, so that the flowing state of air in the shaft is determined, layered gas injection is better guided, and the method has important significance for adjusting the layered combustion front of a stationary pipe column for the layered gas injection.
Drawings
In order to more clearly illustrate the embodiments of the present application or the technical solutions in the prior art, the drawings used in the description of the embodiments or the prior art will be briefly described below, it is obvious that the drawings in the following description are only some embodiments of the present application, and for those skilled in the art, other drawings can be obtained according to the drawings without creative efforts. In the drawings:
FIG. 1 is a flow chart of a method for determining stratified gas injection parameters for a gas injection well according to an embodiment of the present disclosure;
FIG. 2 is a schematic structural diagram of an apparatus for determining a stratified gas injection parameter of a gas injection well according to an embodiment of the present disclosure.
Detailed Description
To make the objects, technical solutions and advantages of the embodiments of the present application more apparent, the embodiments of the present application are further described in detail below with reference to the accompanying drawings. The exemplary embodiments and descriptions of the present application are provided herein to explain the present application and not to limit the present application.
The embodiment of the application provides a method for determining gas injection well layered gas injection parameters, as shown in fig. 1, the method comprises steps 101 to 103:
and 101, establishing a layered gas injection model according to the gas injection parameters and the measurement parameters.
The gas injection parameters comprise upper-layer system inlet pressure, lower-layer system inlet pressure, upper-layer system absorption air flow and lower-layer system absorption air flow, and the measurement parameters comprise wellhead injection total air flow, wellhead injection pressure, oil pipe inner diameter, average temperature and natural gas viscosity.
For the high-pressure air injected during burning, the total air flow injected by the wellhead is equal to the sum of the upper system absorption air flow and the lower system absorption air flow according to the mass conservation law.
Specifically, the stratified gas injection model is built according to the following steps 1011 to 1014:
step 1011, according to
Determining Reynolds number Re of gas flow of upper layer1(ii) a According to
Determining Reynolds number Re of lower layer system gas flow2。
Wherein f is1The coefficient of frictional resistance of the upper layer is; f. of2The coefficient of friction resistance of the lower layer system; d is the inner diameter of the oil pipe and the unit is meter; e is the absolute roughness, which is typically 0.0006 in.
The coefficient of friction resistance f1、f2May be determined by calculation from parameters such as actual flow, pressure or viscosity at the time of experiment, f1And f2The determination method has been described in detail in the prior art, and is not described herein again.
Step 1012, according to
Determining the upper layer absorption air flow rate Q1(ii) a According to
Determining the lower strata intake air flow rate Q2。
Re calculated in step 10111And Re2Substituted into the above formula, in combination with a known engineering standard pressure pscTemperature TscGas relative density gammagViscosity of natural gas mugAnd the inner diameter d of the oil pipe can determine Q1And Q2。
In addition, Q1+Q2＝QGeneral assembly，QGeneral assemblyTotal air flow is injected for the wellhead. Gamma raygThe dimension is not increased; mu.sgThe unit of (b) is mPas.
Step 1013, according to
Determination of the parameter beta1(ii) a According to
Determination of the parameter beta2。
Wherein the content of the first and second substances,
is the average temperature in K;
the coefficient of variation is zero dimension.
Step 1014, according to
Determining upper strata inlet pressure P1(ii) a According to
Determining lower formation inlet pressure P2。
Wherein, P0The gas injection pressure of the wellhead can be obtained through actual measurement; s is an exponential parameter of gas flow, and may be obtained by experimental measurement or determined from actual experience.
And 103, determining gas injection parameters according to the values of the measurement parameters and the layered gas injection model.
In the embodiment of the application, after the gas injection parameters are determined according to the values of the measurement parameters and the layered gas injection model, the flow coefficient and the gas flow index can be determined according to well testing interpretation data; acquiring the equivalent sectional area of the oil sleeve annulus, the equivalent sectional area of the oil pipe, the formation pressure, the flow rate of the current gas entering a gas distribution valve and the flow rate of the current gas entering the oil sleeve annulus; establishing a pressure model related to the equivalent sectional area of the gas distribution valve hole, the upper layer system absorption air flow and the upper layer system inlet pressure according to the flow coefficient, the gas flow index, the equivalent sectional area of the oil sleeve annulus, the equivalent sectional area of the oil pipe, the formation pressure, the current flow rate of gas entering the gas distribution valve and the current flow rate of gas entering the oil sleeve annulus; and when the upper layer system absorbs the air flow and changes, re-determining the equivalent sectional area of the air distribution valve hole according to the changed upper layer system absorbed air flow, the unchanged upper layer system inlet pressure and the pressure model.
Specifically, the method for re-determining the equivalent cross-sectional area of the air distribution valve hole according to the changed upper layer system absorption air flow and the unchanged upper layer system inlet pressure and pressure model comprises the following steps: according to
Determining the upper strata formation suction pressure P11Upper strata formation suction pressure P11Meanwhile, the pressure of the outlet of the gas distribution valve is also the pressure of the gas distribution valve; according to Δ PGeneral assembly＝P1-P11Determination of the Total pressure loss Δ PGeneral assembly(ii) a According to
And Δ PGeneral assembly＝ΔP1+ΔP2Determining the equivalent sectional area A of the valve hole of the air distribution valve1。
Wherein Q is1' is the changed upper layer absorbs the air flow; c is a flow coefficient, n is a gas flow index, and C and n can be obtained through well testing interpretation data; p is a radical ofrFor formation pressure, when the formation is considered to be infinite and flowing steadily, prIs a fixed value; zeta1Is the upper layer resistance coefficient; zeta2The lower layer system resistance coefficient; delta P1The pressure loss of gas entering the gas distribution valve from the oil pipe; delta P2The pressure loss of gas entering the oil sleeve annulus from the gas distribution valve is realized; ρ is the gas density; v1For the flow rate of gas from the oil pipe into the gas distribution valve, V2For the flow rate of gas entering the oil jacket annulus from the gas distribution valve, V1And V2Can be obtained by comparing the flow rate of the gas passing through the gas flow path with the equivalent flow cross section area; a. the1The equivalent sectional area of the valve hole of the air distribution valve; a. the2The equivalent cross-sectional area of the oil sleeve annulus; a. the3Is the equivalent sectional area of the oil pipe.
It should be noted that, according to the theory of fluid mechanics, the high-pressure gas quickly passes through the overflow distribution valve to generate pressure loss, and the main pressure loss is divided into two parts, namely, the instant passage generated by the oil pipe entering the distribution valve is reduced and the instant passage generated by the oil pipe entering the oil sleeve annulus from the distribution valveThe pressure loss caused by the instantaneous channel enlargement is the above-mentioned Δ P1And Δ P2。
After the equivalent sectional area of the gas distribution valve hole is determined again, the aperture size of the gas distribution valve can be adjusted by throwing and fishing the gas distribution valve, and the gas suction capacity between different layers can be adjusted by utilizing the gas distribution valve with the adjusted size, so that the layered gas injection effect of in-situ combustion and the degree for fire driving are effectively improved.
In the embodiment of the application, a gas injection parameter model related to gas injection parameters is established according to the gas injection parameters and the measurement parameters, the gas injection parameters are determined according to the measurement parameters which can be actually obtained in the gas injection process, and the gas injection parameters such as the pressure of different gas injection layers in a gas injection shaft are accurately determined, so that the flowing state of air in the shaft is determined, layered gas injection is better guided, and the method has important significance for adjusting the layered combustion front of a stationary pipe column for the layered gas injection.
In an embodiment of the present application, an apparatus for determining a layered gas injection parameter of a gas injection well is provided, as shown in fig. 2, the apparatus 200 includes a model building module 201, an obtaining module 202, and a determining module 203.
The model building module 201 is configured to build a layered gas injection model according to the gas injection parameters and the measurement parameters.
An obtaining module 202, configured to obtain a value of the measurement parameter.
And a determining module 203, configured to determine the gas injection parameter according to the value of the measurement parameter acquired by the acquiring module 202 and the layered gas injection model established by the model constructing module 201.
The gas injection parameters comprise upper-layer system inlet pressure, lower-layer system inlet pressure, upper-layer system absorption air flow and lower-layer system absorption air flow, and the measurement parameters comprise wellhead injection total air flow, wellhead injection pressure, oil pipe inner diameter, average temperature and natural gas viscosity; wherein, the total air flow injected by the wellhead is equal to the sum of the absorption air flow of the upper layer system and the absorption air flow of the lower layer system.
In an implementation manner of the embodiment of the present application, the determining module 203 is further configured to determine the flow coefficient and the gas flow index according to the well test interpretation data.
The obtaining module 202 is further configured to obtain an equivalent cross-sectional area of the oil casing annulus, an equivalent cross-sectional area of the oil pipe, a formation pressure, a flow rate of the current gas entering the gas distribution valve, and a flow rate of the current gas entering the oil casing annulus.
The model building module 201 is further configured to build a pressure model related to the equivalent sectional area of the gas distribution valve hole, the upper layer absorption air flow and the upper layer inlet pressure according to the flow coefficient, the gas flow index, the equivalent sectional area of the oil sleeve annulus, the equivalent sectional area of the oil pipe, the formation pressure, the flow rate of the current gas entering the gas distribution valve and the flow rate of the current gas entering the oil sleeve annulus;
the determining module 203 is further configured to re-determine the equivalent cross-sectional area of the air distribution valve hole according to the changed upper layer absorption air flow, the unchanged upper layer inlet pressure and the pressure model after the upper layer absorption air flow is changed.
In an implementation manner of the embodiment of the present application, the model building module 201 is configured to:
according to
Determining Reynolds number Re of gas flow of upper layer1(ii) a According to
Determining Reynolds number Re of lower layer system gas flow2；
According to
Determining the upper layer absorption air flow rate Q1(ii) a According to
Determining the lower strata intake air flow rate Q2；
According to
Determination of the parameter beta1(ii) a According to
Determination of the parameter beta2；
According to
Determining upper strata inlet pressure P1；
According to
Determining lower formation inlet pressure P2；
Wherein f is1The coefficient of frictional resistance of the upper layer is; f. of2The coefficient of friction resistance of the lower layer system; q1+Q2＝QGeneral assembly，QGeneral assemblyInjecting total air flow into the wellhead; p0Injecting gas pressure into the wellhead; gamma raygThe gas relative density is zero dimension; mu.sgNatural gas viscosity in mPa · s; d is the inner diameter of the oil pipe and the unit is meter; e is the absolute roughness;
is the average temperature in K;
the coefficient of deviation is zero dimension; p is a radical ofscThe engineering standard pressure is 0.101325 MPa; t isscThe value for temperature is 293K; s is an index parameter for gas flow.
In an implementation manner of the embodiment of the present application, the determining module 203 is configured to:
according to
Determining the upper strata formation suction pressure P11；
According to Δ PGeneral assembly＝P1-P11Determination of the Total pressure loss Δ PGeneral assembly；
According to
And Δ PGeneral assembly＝ΔP1+ΔP2Determining the equivalent sectional area A of the valve hole of the air distribution valve1；
Wherein Q is1' is the changed upper layer absorbs the air flow; c is the flow coefficient; n is a gas flow index; p is a radical ofrIs the formation pressure; zeta1Is the upper layer resistance coefficient; zeta2The lower layer system resistance coefficient; delta P1The pressure loss of gas entering the gas distribution valve from the oil pipe; delta P2The pressure loss of gas entering the oil sleeve annulus from the gas distribution valve is realized; ρ is the gas density; v1The flow rate of the gas entering the gas distribution valve from the oil pipe; v2The flow rate of gas entering the oil sleeve annulus from the gas distribution valve; a. the1The equivalent sectional area of the valve hole of the air distribution valve; a. the2The equivalent cross-sectional area of the oil sleeve annulus; a. the3Is the equivalent sectional area of the oil pipe.
In the embodiment of the application, a gas injection parameter model related to gas injection parameters is established according to the gas injection parameters and the measurement parameters, the gas injection parameters are determined according to the measurement parameters which can be actually obtained in the gas injection process, and the gas injection parameters such as the pressure of different gas injection layers in a gas injection shaft are accurately determined, so that the flowing state of air in the shaft is determined, layered gas injection is better guided, and the method has important significance for adjusting the layered combustion front of a stationary pipe column for the layered gas injection.
The embodiment of the present application further provides a computer device, which includes a memory, a processor, and a computer program stored in the memory and executable on the processor, and when the processor executes the computer program, any one of the methods in step 101 to step 103 is implemented.
An embodiment of the present application further provides a computer-readable storage medium, where a computer program for executing any one of the methods in step 101 to step 103 is stored in the computer-readable storage medium.
As will be appreciated by one skilled in the art, embodiments of the present application may be provided as a method, system, or computer program product. Accordingly, the present application may take the form of an entirely hardware embodiment, an entirely software embodiment or an embodiment combining software and hardware aspects. Furthermore, the present application may take the form of a computer program product embodied on one or more computer-usable storage media (including, but not limited to, disk storage, CD-ROM, optical storage, and the like) having computer-usable program code embodied therein.
The present application is described with reference to flowchart illustrations and/or block diagrams of methods, apparatus (systems), and computer program products according to embodiments of the application. It will be understood that each flow and/or block of the flow diagrams and/or block diagrams, and combinations of flows and/or blocks in the flow diagrams and/or block diagrams, can be implemented by computer program instructions. These computer program instructions may be provided to a processor of a general purpose computer, special purpose computer, embedded processor, or other programmable data processing apparatus to produce a machine, such that the instructions, which execute via the processor of the computer or other programmable data processing apparatus, create means for implementing the functions specified in the flowchart flow or flows and/or block diagram block or blocks.
These computer program instructions may also be stored in a computer-readable memory that can direct a computer or other programmable data processing apparatus to function in a particular manner, such that the instructions stored in the computer-readable memory produce an article of manufacture including instruction means which implement the function specified in the flowchart flow or flows and/or block diagram block or blocks.
These computer program instructions may also be loaded onto a computer or other programmable data processing apparatus to cause a series of operational steps to be performed on the computer or other programmable apparatus to produce a computer implemented process such that the instructions which execute on the computer or other programmable apparatus provide steps for implementing the functions specified in the flowchart flow or flows and/or block diagram block or blocks.
The above-mentioned embodiments are further described in detail for the purpose of illustrating the invention, and it should be understood that the above-mentioned embodiments are only illustrative of the present invention and are not intended to limit the scope of the present invention, and any modifications, equivalent substitutions, improvements, etc. made within the spirit and principle of the present invention should be included in the scope of the present invention.
Claims (10)
1. A method for determining stratified gas injection parameters for a gas injection well, the method comprising:
establishing a layered gas injection model according to the gas injection parameters and the measurement parameters;
obtaining a value of a measurement parameter;
determining gas injection parameters according to the values of the measurement parameters and the layered gas injection model;
the gas injection parameters comprise upper-layer system inlet pressure, lower-layer system inlet pressure, upper-layer system absorption air flow and lower-layer system absorption air flow, and the measurement parameters comprise wellhead injection total air flow, wellhead injection pressure, oil pipe inner diameter, average temperature and natural gas viscosity; wherein, the total air flow injected by the wellhead is equal to the sum of the absorption air flow of the upper layer system and the absorption air flow of the lower layer system.
2. The method of claim 1, wherein after determining the insufflation parameters from the values of the measured parameters and the stratified insufflation model, the method further comprises:
determining a flow coefficient and a gas flow index according to well testing interpretation data;
acquiring the equivalent sectional area of the oil sleeve annulus, the equivalent sectional area of the oil pipe, the formation pressure, the flow rate of the current gas entering a gas distribution valve and the flow rate of the current gas entering the oil sleeve annulus;
establishing a pressure model related to the equivalent sectional area of the gas distribution valve hole, the upper layer system absorption air flow and the upper layer system inlet pressure according to the flow coefficient, the gas flow index, the equivalent sectional area of the oil sleeve annulus, the equivalent sectional area of the oil pipe, the formation pressure, the current flow rate of gas entering the gas distribution valve and the current flow rate of gas entering the oil sleeve annulus;
and when the upper layer system absorbs the air flow and changes, re-determining the equivalent sectional area of the air distribution valve hole according to the changed upper layer system absorbed air flow, the unchanged upper layer system inlet pressure and the pressure model.
3. The method of claim 2, wherein the establishing a stratified gas injection model from gas injection parameters and measurement parameters comprises:
according to
Determining Reynolds number Re of gas flow of upper layer1(ii) a According to
Determining Reynolds number Re of lower layer system gas flow2；
According to
Determining the upper layer absorption air flow rate Q1(ii) a According to
Determining the lower strata intake air flow rate Q2；
According to
Determination of the parameter beta1(ii) a According to
Determination of the parameter beta2；
According to
Determining upper strata inlet pressure P1；
According to
Determining lower formation inlet pressure P2；
Wherein f is1The coefficient of frictional resistance of the upper layer is; f. of2The coefficient of friction resistance of the lower layer system; q1+Q2＝QGeneral assembly，QGeneral assemblyInjecting total air flow into the wellhead; p0Injecting gas pressure into the wellhead; gamma raygThe gas relative density is zero dimension; mu.sgNatural gas viscosity in mPa · s; d is the inner diameter of the oil pipe and the unit is meter; e is the absolute roughness;
is the average temperature in K;
the coefficient of deviation is zero dimension; p is a radical ofscThe engineering standard pressure is 0.101325 MPa; t isscThe value for temperature is 293K; s is an index parameter for gas flow.
4. The method of claim 3, wherein re-determining the equivalent cross-sectional area of the distribution valve bore from the modified upper system uptake air flow, the constant upper system inlet pressure, and the pressure model comprises:
according to
Determining the upper strata formation suction pressure P11；
According to Δ PGeneral assembly＝P1-P11Determination of the Total pressure loss Δ PGeneral assembly；
According to
And Δ PGeneral assembly＝ΔP1+ΔP2Determining the equivalent sectional area A of the valve hole of the air distribution valve1；
Wherein Q is1' is the changed upper layer absorbs the air flow; c is the flow coefficient; n is a gas flow index; p is a radical ofrIs the formation pressure; zeta1Is the upper layer resistance coefficient; zeta2The lower layer system resistance coefficient; delta P1The pressure loss of gas entering the gas distribution valve from the oil pipe; delta P2The pressure loss of gas entering the oil sleeve annulus from the gas distribution valve is realized; ρ is the gas density; v1The flow rate of the gas entering the gas distribution valve from the oil pipe; v2The flow rate of gas entering the oil sleeve annulus from the gas distribution valve; a. the1The equivalent sectional area of the valve hole of the air distribution valve; a. the2The equivalent cross-sectional area of the oil sleeve annulus; a. the3Is the equivalent sectional area of the oil pipe.
5. A gas injection well stratified gas injection parameter determination apparatus, the apparatus comprising:
the model building module is used for building a layered gas injection model according to the gas injection parameters and the measurement parameters;
the acquisition module is used for acquiring the value of the measurement parameter;
the determining module is used for determining gas injection parameters according to the values of the measurement parameters acquired by the acquiring module and the layered gas injection model established by the model establishing module;
the gas injection parameters comprise upper-layer system inlet pressure, lower-layer system inlet pressure, upper-layer system absorption air flow and lower-layer system absorption air flow, and the measurement parameters comprise wellhead injection total air flow, wellhead injection pressure, oil pipe inner diameter, average temperature and natural gas viscosity; wherein, the total air flow injected by the wellhead is equal to the sum of the absorption air flow of the upper layer system and the absorption air flow of the lower layer system.
6. The apparatus of claim 5,
the determining module is also used for determining a flow coefficient and a gas flow index according to the well testing interpretation data;
the acquisition module is also used for acquiring the equivalent sectional area of the oil sleeve annulus, the equivalent sectional area of the oil pipe, the formation pressure, the flow rate of the current gas entering the gas distribution valve and the flow rate of the current gas entering the oil sleeve annulus;
the model building module is also used for building a pressure model related to the equivalent sectional area of the gas distribution valve hole, the upper layer absorption air flow and the upper layer inlet pressure according to the flow coefficient, the gas flow index, the equivalent sectional area of the oil sleeve annulus, the equivalent sectional area of the oil pipe, the formation pressure, the current flow rate of gas entering the gas distribution valve and the current flow rate of gas entering the oil sleeve annulus;
the determining module is further used for re-determining the equivalent sectional area of the air distribution valve hole according to the changed upper layer system absorption air flow, the unchanged upper layer system inlet pressure and the pressure model after the upper layer system absorption air flow is changed.
7. The apparatus of claim 6, wherein the model building module is configured to:
according to
Determining Reynolds number Re of gas flow of upper layer1(ii) a According to
Determining Reynolds number Re of lower layer system gas flow2；
According to
Determining the upper layer absorption air flow rate Q1(ii) a According to
Determining the lower strata intake air flow rate Q2；
According to
Determination of the parameter beta1(ii) a According to
Determination of the parameter beta2；
According to
Determining upper strata inlet pressure P1；
According to
Determining lower formation inlet pressure P2；
Wherein f is1The coefficient of frictional resistance of the upper layer is; f. of2The coefficient of friction resistance of the lower layer system; q1+Q2＝QGeneral assembly，QGeneral assemblyInjecting total air flow into the wellhead; p0Injecting gas pressure into the wellhead; gamma raygThe gas relative density is zero dimension; mu.sgNatural gas viscosity in mPa · s; d is the inner diameter of the oil pipe and the unit is meter; e is the absolute roughness;
is the average temperature in K;
the coefficient of deviation is zero dimension; p is a radical ofscThe engineering standard pressure is 0.101325 MPa; t isscThe value for temperature is 293K; s is an index parameter for gas flow.
8. The apparatus of claim 7, wherein the determining module is configured to:
according to
Determining the upper strata formation suction pressure P11；
According to Δ PGeneral assembly＝P1-P11Determination of the Total pressure loss Δ PGeneral assembly；
According to
And Δ PGeneral assembly＝ΔP1+ΔP2DeterminingEquivalent sectional area A of valve hole1；
Wherein Q is1' is the changed upper layer absorbs the air flow; c is the flow coefficient; n is a gas flow index; p is a radical ofrIs the formation pressure; zeta1Is the upper layer resistance coefficient; zeta2The lower layer system resistance coefficient; delta P1The pressure loss of gas entering the gas distribution valve from the oil pipe; delta P2The pressure loss of gas entering the oil sleeve annulus from the gas distribution valve is realized; ρ is the gas density; v1The flow rate of the gas entering the gas distribution valve from the oil pipe; v2The flow rate of gas entering the oil sleeve annulus from the gas distribution valve; a. the1The equivalent sectional area of the valve hole of the air distribution valve; a. the2The equivalent cross-sectional area of the oil sleeve annulus; a. the3Is the equivalent sectional area of the oil pipe.
9. A computer device comprising a memory, a processor and a computer program stored on the memory and executable on the processor, wherein the processor implements the method of any one of claims 1 to 4 when executing the computer program.
10. A computer-readable storage medium, characterized in that the computer-readable storage medium stores a computer program for executing the method of any one of claims 1 to 4.
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| CN201911064866.8A CN112765903B (en) | 2019-11-04 | 2019-11-04 | Layered gas injection parameter determination method and device for gas injection well |
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| CN112765903B CN112765903B (en) | 2022-11-04 |
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Citations (4)
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| CN104879103A (en) * | 2015-05-22 | 2015-09-02 | 中国石油天然气股份有限公司 | Layered water injection effect analysis method |
| CN105089582A (en) * | 2015-05-28 | 2015-11-25 | 中国石油天然气股份有限公司 | Oil reservoir numerical simulation method and device based on downhole flow control equipment |
| RU2636842C1 (en) * | 2017-01-09 | 2017-11-28 | Ильдар Амирович Сулейманов | Method and arrangement for controlled injection of liquid through formations |
| CN107859506A (en) * | 2017-11-15 | 2018-03-30 | 中国石油天然气股份有限公司 | The determination method of carbon dioxide flooding layered gas-injection well gas injection parameter |
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| CN104879103A (en) * | 2015-05-22 | 2015-09-02 | 中国石油天然气股份有限公司 | Layered water injection effect analysis method |
| CN105089582A (en) * | 2015-05-28 | 2015-11-25 | 中国石油天然气股份有限公司 | Oil reservoir numerical simulation method and device based on downhole flow control equipment |
| RU2636842C1 (en) * | 2017-01-09 | 2017-11-28 | Ильдар Амирович Сулейманов | Method and arrangement for controlled injection of liquid through formations |
| CN107859506A (en) * | 2017-11-15 | 2018-03-30 | 中国石油天然气股份有限公司 | The determination method of carbon dioxide flooding layered gas-injection well gas injection parameter |
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