CN112765903B - 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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- CN112765903B CN112765903B CN201911064866.8A CN201911064866A CN112765903B CN 112765903 B CN112765903 B CN 112765903B CN 201911064866 A CN201911064866 A CN 201911064866A CN 112765903 B CN112765903 B CN 112765903B
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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
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
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 system inlet pressure, lower system inlet pressure, upper system absorption air flow and lower 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 cage system, nevertheless because the fire flooding oil reservoir is mostly the oil reservoir that development value is relatively poor, the quality is lower to 66 oil reservoirs in Liaohe oil field are for example, and it is thin interbedded oil reservoir itself, and the small bed is many, and thickness is thin, discovers that there is great difference in the oil reservoir situation of using on vertically after carrying out the fire flooding. Wherein the highest utilization degree of the Du I1-2 reaches more than 82%, and the utilization degree of the Du II 1-4 is 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 by different qualities 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 have no corresponding numerical method at present to simulate the shaft pressure distribution of a burning gas injection well containing different oil nozzles and performing quality gas injection, so that no data can be relied on in later-stage production adjustment and test.
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 the present application further provides a device for determining gas injection well stratified gas injection parameters, so as to accurately determine gas injection parameters of stratified gas injection, thereby determining a flow state of air in a shaft, and better guiding stratified gas injection, the device including:
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 to explain the present application and should not be interpreted as limiting 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 the burning, 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 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 layer 1 (ii) a According to
Determining Reynolds number Re of lower layer system gas flow 2 。
Wherein f is 1 The coefficient of frictional resistance of the upper layer is; f. of 2 The lower layer is the friction resistance coefficient; d is the inner diameter of the oil pipe and the unit is meter; e is the absolute roughness, which is typically 0.0006in.
The coefficient of friction resistance f 1 、f 2 May be determined by calculation from parameters such as actual flow, pressure or viscosity at the time of experiment, f 1 And f 2 The 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 absorbing the air flowQuantity Q 1 (ii) a According to
Determining the lower layer absorption air flow rate Q 2 。
Re calculated in step 1011 1 And Re 2 Substituted into the above formula, in combination with a known engineering standard pressure p sc Temperature T sc Gas relative density gamma g Viscosity of natural gas mu g And the inner diameter d of the oil pipe can determine Q 1 And Q 2 。
In addition, Q 1 +Q 2 ＝Q General assembly ，Q General assembly The total air flow is injected for the wellhead. Gamma ray g The dimension is not increased; mu.s g The unit of (b) is mPas.
Step 1013, based on
Determination of the parameter beta 1 (ii) a According to
Determination of the parameter beta 2 。
Wherein the content of the first and second substances,
is the average temperature in K;
is a deviation coefficient without dimension.
Step 1014, according to
Determining upper strata inlet pressure P 1 (ii) a According to
Determining lower formation inlet pressure P 2 。
Wherein, P 0 The pressure for injecting gas into the wellhead can be obtained through actual measurement; s is an index parameter of gas flow, canAs measured experimentally or determined empirically.
And 103, determining gas injection parameters according to the values of the measured 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 an oil sleeve annulus, the equivalent sectional area of an oil pipe, the formation pressure, the flow rate of current gas entering a gas distribution valve and the flow rate of 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 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 comprises the following steps: according to
Determining upper strata formation suction pressure P 11 Upper strata suction pressure P 11 Meanwhile, the pressure of the outlet of the distributing valve is also the pressure of the outlet of the distributing valve; according to Δ P General assembly ＝P 1 -P 11 Determination of the Total pressure loss Δ P General assembly (ii) a According to
And Δ P General assembly ＝ΔP 1 +ΔP 2 Determining the equivalent sectional area A of the valve hole of the air distribution valve 1 。
Wherein Q 1 ' is the changed upper layer absorbs the air flow; c is flow coefficient, n is gas flow index, and C and n can be obtained by well test interpretation data; p is a radical of r For formation pressure, p when the formation is considered to be infinite and flowing steadily r Is a fixed value; zeta 1 Is the upper layer resistance coefficient; ζ represents a unit 2 The lower layer system resistance coefficient; delta P 1 The pressure loss of gas entering the distributing valve from the oil pipe; delta P 2 The pressure loss of gas entering the oil sleeve annulus from the gas distribution valve is realized; ρ is the gas density; v 1 The flow rate of gas entering the distributing valve from the oil pipe, V 2 The flow rate V of gas entering the oil sleeve annulus from the gas distribution valve 1 And V 2 Can be obtained by comparing the flow rate of the gas passing through the gas flow path with the equivalent flow cross section area; a. The 1 The equivalent cross section of the valve hole of the air distribution valve; a. The 2 The equivalent cross-sectional area of the oil sleeve annulus; a. The 3 Is the equivalent sectional area of the oil pipe.
It should be noted that, according to the theory of hydrodynamics, the pressure loss is generated when the high-pressure gas rapidly passes through the overflowing distributing valve, and the main pressure loss is divided into two parts, that is, the pressure loss is caused by the instant passage generated by the oil pipe entering the distributing valve being reduced and the instant passage generated by the oil pipe entering the oil sleeve annulus from the distributing valve being enlarged, and the two part losses are the above-mentioned Δ P 1 And Δ P 2 。
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 for determining the gas injection parameters according to the values of the measurement parameters 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 system inlet pressure, lower system inlet pressure, upper system absorption air flow and lower 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, after the upper layer system absorption air flow rate is changed, re-determine the equivalent cross-sectional area of the air distribution valve hole according to the changed upper layer system absorption air flow rate, the unchanged upper layer system inlet pressure and the pressure model.
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 layer 1 (ii) a According to
Determining the Reynolds number Re of the lower system gas flow 2 ；
According to
Determination of the upper layer absorption air flow rate Q 1 (ii) a According to
Determining the lower strata intake air flow rate Q 2 ；
According to
Determination of the parameter beta 1 (ii) a According to
Determination of the parameter beta 2 ；
According to
Determining upper strata inlet pressure P 1 ；
According to
Determining lower formation inlet pressure P 2 ；
Wherein, f 1 Is the coefficient of frictional resistance of the upper layer; f. of 2 The lower layer is the friction resistance coefficient; q 1 +Q 2 ＝Q General assembly ，Q General assembly Injecting total air flow into the wellhead; p is 0 Injecting gas pressure into well head；γ g The gas relative density is zero dimension; mu.s g Is the natural 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 of sc The engineering standard pressure is 0.101325MPa; t is sc The 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 P 11 ；
According to Δ P General assembly ＝P 1 -P 11 Determination of the Total pressure loss Δ P General assembly ；
According to
And Δ P General (1) ＝ΔP 1 +ΔP 2 Determining the equivalent sectional area A of the valve hole of the air distribution valve 1 ；
Wherein Q 1 ' is the changed upper layer absorbs the air flow; c is the flow coefficient; n is a gas flow index; p is a radical of r Is the formation pressure; ζ represents a unit 1 Is the upper layer resistance coefficient; zeta 2 The lower layer system resistance coefficient; delta P 1 The pressure loss of gas entering the gas distribution valve from the oil pipe; delta P 2 The pressure loss of gas entering the oil sleeve annulus from the gas distribution valve is realized; ρ is the gas density; v 1 The flow rate of the gas entering the gas distribution valve from the oil pipe; v 2 The flow rate of gas entering the oil sleeve annulus from the gas distribution valve; a. The 1 The equivalent sectional area of the valve hole of the air distribution valve; a. The 2 The equivalent cross section area of the oil sleeve annulus; a. The 3 For equivalent cutting of oil pipeArea (d).
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 flowchart illustrations and/or block diagrams, and combinations of flows and/or blocks in the flowchart illustrations 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 provided to further explain the objects, technical solutions and advantages of the present application in detail, and it should be understood that the above-mentioned embodiments are only examples of the present application and are not intended to limit the scope of the present application, and any modifications, equivalents, improvements and the like made within the spirit and principle of the present application should be included in the scope of the present application.
Claims (6)
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;
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 an oil sleeve annulus, the equivalent sectional area of an oil pipe, the formation pressure, the flow rate of current gas entering a gas distribution valve and the flow rate of 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;
when the upper layer system absorbs the air flow and changes, according to the upper layer system after changing and absorbing the air flow, invariable upper layer system inlet pressure and pressure model, confirm the equivalent cross-sectional area of the valve hole of the air distribution again;
wherein the establishing a stratified gas injection model based on the gas injection parameters and the measurement parameters comprises:
according to
Determining Reynolds number Re of gas flow in upper layer 1 (ii) a According to
Determining the Reynolds number Re of the lower system gas flow 2 ；
According to
Determination of the upper layer absorption air flow rate Q 1 (ii) a According to
Determining the lower strata intake air flow rate Q 2 ；
According to
Determination of the parameter beta 1 (ii) a According to
Determination of the parameter beta 2 ；
According to
Determining upper strata inlet pressure P 1 ；
According to
Determining lower formation inlet pressure P 2 ；
Wherein, f 1 The coefficient of frictional resistance of the upper layer is; f. of 2 The lower layer is the friction resistance coefficient; q 1 +Q 2 ＝Q General assembly ，Q General (1) Injecting total air flow for the wellhead; p 0 Injecting gas pressure to the well mouth; gamma ray g The gas relative density is zero dimension; mu.s g Natural 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 of sc The value is 0.101325MPa for engineering standard pressure; t is sc The value for temperature is 293K; s is an index parameter for gas flow.
2. The method of claim 1, 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 upper strata formation suction pressure P 11 ；
According to Δ P General assembly ＝P 1 -P 11 Determination of the Total pressure loss Δ P General (1) ；
According to
And Δ P General (1) ＝ΔP 1 +ΔP 2 Determining the equivalent sectional area A of the valve hole of the air distribution valve 1 ；
Wherein Q 1 ' is the modified upper layer absorbs the air flow; c is the flow coefficient; n is a gas flow index; p is a radical of r Is the formation pressure; zeta 1 Is the upper layer resistance coefficient; zeta 2 The lower layer system resistance coefficient; delta P 1 The pressure loss of gas entering the distributing valve from the oil pipe; delta P 2 The pressure loss of gas entering the oil sleeve annulus from the gas distribution valve is realized; ρ is the gas density; v 1 The flow rate of the gas entering the gas distribution valve from the oil pipe; v 2 The flow rate of gas entering the oil sleeve annulus from the gas distribution valve; a. The 1 The equivalent sectional area of the valve hole of the air distribution valve; a. The 2 The equivalent cross-sectional area of the oil sleeve annulus; a. The 3 Is the equivalent sectional area of the oil pipe.
3. 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;
the determining module is further used for determining a flow coefficient and a gas flow index according to well test interpretation data;
the acquisition module is also used for acquiring the equivalent sectional area of the oil casing 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 casing 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;
wherein the model building module is configured to:
according to
Determining Reynolds number Re of gas flow of upper layer 1 (ii) a According to
Determining the Reynolds number Re of the lower system gas flow 2 ；
According to
Determining the upper layer absorption air flow rate Q 1 (ii) a According to
Determining the lower strata intake air flow rate Q 2 ；
According to
Determination of the parameter beta 1 (ii) a According to
Determination of the parameter beta 2 ；
According to
Determining upper strata inlet pressure P 1 ；
According to
Determining lower formation inlet pressure P 2 ；
Wherein f is 1 The coefficient of frictional resistance of the upper layer is; f. of 2 The coefficient of friction resistance of the lower layer system; q 1 +Q 2 ＝Q General assembly ，Q General (1) Injecting total air flow into the wellhead; p 0 Injecting gas pressure to the well mouth; gamma ray g The gas relative density is zero dimension; mu.s g Is the natural 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 of sc The engineering standard pressure is 0.101325MPa; t is sc The value for temperature is 293K; s is an index parameter for gas flow.
4. The apparatus of claim 3, wherein the determining module is configured to:
according to
Determining the upper strata formation suction pressure P 11 ；
According to Δ P General assembly ＝P 1 -P 11 Determination of the Total pressure loss Δ P General (1) ；
According to
And Δ P General assembly ＝ΔP 1 +ΔP 2 Determining the equivalent sectional area A of the valve hole of the air distribution valve 1 ；
Wherein Q is 1 ' is the modified upper layer absorbs the air flow; c is the flow coefficient; n is a gas flow index; p is a radical of r Is the formation pressure; zeta 1 Is the upper layer resistance coefficient; zeta 2 The lower layer system resistance coefficient; delta P 1 The pressure loss of gas entering the gas distribution valve from the oil pipe; delta P 2 The pressure loss of gas entering the oil sleeve annulus from the gas distribution valve is realized; ρ is the gas density; v 1 The flow rate of the gas entering the gas distribution valve from the oil pipe; v 2 The flow rate of gas entering the oil sleeve annulus from the gas distribution valve; a. The 1 The equivalent sectional area of the valve hole of the air distribution valve; a. The 2 The equivalent cross-sectional area of the oil sleeve annulus; a. The 3 Is the equivalent sectional area of the oil pipe.
5. 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 claim 1 or 2 when executing the computer program.
6. A computer-readable storage medium, characterized in that the computer-readable storage medium stores a computer program for executing the method of claim 1 or 2.
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