CN112763007A - Method and device for determining split-phase flow of wet natural gas and storage medium - Google Patents
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Abstract
The disclosure discloses a split-phase flow determining method and device for wet natural gas and a storage medium. The wet natural gas is formed by mixing natural gas and liquid, the liquid at least comprises hydrocarbon liquid, and the split-phase flow determining method comprises the following steps: acquiring the natural gas flow before mixing and the hydrocarbon liquid flow before mixing; determining the natural gas solubility of the hydrocarbon liquid in the wet natural gas; and respectively correcting the natural gas flow before mixing and the hydrocarbon liquid flow before mixing based on the natural gas solubility of the hydrocarbon liquid in the wet natural gas to obtain the natural gas flow and the hydrocarbon liquid flow in the wet natural gas. The flow of the natural gas and the flow of the hydrocarbon liquid can be corrected to be consistent with the flow of the natural gas and the flow of the hydrocarbon liquid of the wet natural gas after mixing, so that the flow of the wet natural gas detected by the wet natural gas detection device can be conveniently corrected, and the detection accuracy is ensured.
Description
Technical Field
The disclosure relates to the technical field of natural gas testing, and in particular to a split-phase flow determining method and device for wet natural gas and a storage medium.
Background
Wet natural gas is a mixture of natural gas and liquid. The liquid that is mixed to form wet natural gas may typically be water and/or a hydrocarbon liquid. When wet natural gas is studied, a wet natural gas detection device is generally used to detect the flow rate, the flow shape, and the like of the wet natural gas. In order to determine the accuracy of the flow of the wet natural gas detected by the wet natural gas detection device, the natural gas flow and the hydrocarbon liquid flow of the wet natural gas before mixing are respectively measured by the flow meter, and the natural gas flow and the hydrocarbon liquid flow measured by the flow meter are used as standard values to be corrected with the flow of the wet natural gas detected by the wet natural gas detection device, so that the accuracy of the detection of the wet natural gas detection device is determined.
However, since the liquid contains the hydrocarbon liquid, when the liquid is mixed with the natural gas, the natural gas may be dissolved in the liquid or the natural gas dissolved in the liquid may be separated out, and the flow rates of the natural gas and the hydrocarbon liquid may be changed before and after the gas and the liquid are mixed, and the measurement result of the flow meter may not accurately represent the flow rate of the natural gas and the flow rate of the hydrocarbon liquid in the wet natural gas obtained after the mixing.
Disclosure of Invention
The embodiment of the disclosure provides a split-phase flow determining method and device for wet natural gas and a storage medium, which can correct natural gas flow and hydrocarbon liquid flow to be consistent with the natural gas flow and the hydrocarbon liquid flow of the mixed wet natural gas, so that the flow of the wet natural gas detected by a wet natural gas detecting device can be conveniently corrected, and the detection accuracy is ensured. The technical scheme is as follows:
in a first aspect, an embodiment of the present disclosure provides a method for determining a phase separation flow rate of wet natural gas, where the wet natural gas is formed by mixing natural gas and a liquid, the liquid at least includes a hydrocarbon liquid, and the method includes: acquiring the natural gas flow before mixing and the hydrocarbon liquid flow before mixing; determining a natural gas solubility of the hydrocarbon liquid in the wet natural gas; and respectively correcting the natural gas flow before mixing and the hydrocarbon liquid flow before mixing based on the natural gas solubility of the hydrocarbon liquid in the wet natural gas to obtain the natural gas flow and the hydrocarbon liquid flow in the wet natural gas.
In another implementation manner of the embodiment of the present disclosure, the modifying the natural gas flow before mixing based on the natural gas solubility of the hydrocarbon liquid in the wet natural gas to obtain the natural gas flow in the wet natural gas includes: determining a difference between natural gas solubility of the hydrocarbon liquid prior to mixing and natural gas solubility of the hydrocarbon liquid in the wet natural gas; and correcting the natural gas flow before mixing by adopting the difference value to obtain the natural gas flow in the wet natural gas.
In another implementation manner of the embodiment of the present disclosure, the correcting the natural gas flow before mixing by using the difference to obtain the natural gas flow in the wet natural gas includes: calculating the product of the hydrocarbon liquid flow rate before mixing and the difference; determining a difference between the natural gas flow before mixing and the product as the natural gas flow in the wet natural gas.
In another implementation manner of the embodiment of the present disclosure, the obtaining the hydrocarbon liquid flow rate in the wet natural gas by respectively correcting the natural gas flow rate before mixing and the hydrocarbon liquid flow rate before mixing based on the natural gas solubility of the hydrocarbon liquid in the wet natural gas includes: determining the liquid variation according to the flow of the hydrocarbon liquid before mixing and the natural gas solubility of the hydrocarbon liquid in the wet natural gas; and determining the sum of the hydrocarbon liquid flow rate before mixing and the liquid change amount as the hydrocarbon liquid flow rate in the wet natural gas.
In another implementation manner of the embodiment of the present disclosure, the split-phase flow determining method further includes: determining the dissolution quality of the natural gas according to the hydrocarbon liquid flow of the wet natural gas and the natural gas solubility of the hydrocarbon liquid of the wet natural gas; and measuring to obtain the hydrocarbon liquid density of the wet natural gas, and determining the dissolved volume of the natural gas according to the hydrocarbon liquid density of the wet natural gas and the dissolved mass.
In another implementation of the disclosed embodiment, the obtaining the natural gas flow rate before mixing and the hydrocarbon liquid flow rate before mixing includes: obtaining the corresponding relation between the density of the hydrocarbon liquid and the natural gas solubility of the hydrocarbon liquid; measuring the density of the hydrocarbon liquid of the wet natural gas; and determining the natural gas solubility of the hydrocarbon liquid in the wet natural gas based on the corresponding relation according to the hydrocarbon liquid density of the wet natural gas.
In a second aspect, an embodiment of the present disclosure provides an apparatus for determining a phase separation flow rate of wet natural gas, the wet natural gas being formed by mixing natural gas and a liquid, the liquid including at least a hydrocarbon liquid, the apparatus comprising: the acquisition module is used for acquiring the natural gas flow before mixing and the hydrocarbon liquid flow before mixing; a determination module that determines a natural gas solubility of a hydrocarbon liquid in the wet natural gas; and the correction module is used for correcting the natural gas flow before mixing and the hydrocarbon liquid flow before mixing respectively based on the natural gas solubility of the hydrocarbon liquid in the wet natural gas to obtain the natural gas flow and the hydrocarbon liquid flow in the wet natural gas.
In another implementation of the disclosed embodiment, the determining module is further configured to determine a difference between a natural gas solubility of the hydrocarbon liquid before blending and a natural gas solubility of the hydrocarbon liquid in the wet natural gas; the correction module is further used for correcting the natural gas flow before mixing by adopting the difference value to obtain the natural gas flow in the wet natural gas.
In another implementation manner of the embodiment of the present disclosure, the split-phase flow determining apparatus further includes: a calculation module for calculating a product of the hydrocarbon liquid flow before mixing and the difference; the determination module is further configured to determine a difference between the natural gas flow before mixing and the product as the natural gas flow in the wet natural gas.
In another implementation of the embodiment of the present disclosure, the determining module is further configured to determine the liquid change amount according to the flow rate of the hydrocarbon liquid before mixing and the natural gas solubility of the hydrocarbon liquid in the wet natural gas; and the sum of the hydrocarbon liquid flow rate before mixing and the liquid change amount is determined as the hydrocarbon liquid flow rate in the wet natural gas.
In another implementation of the embodiment of the present disclosure, the determining module is further configured to determine a dissolution quality of the natural gas according to the hydrocarbon liquid flow rate of the wet natural gas and the natural gas solubility of the hydrocarbon liquid of the wet natural gas; the split-phase flow determination device further comprises a measurement module, the measurement module is used for measuring and obtaining the hydrocarbon liquid density of the wet natural gas, and the determination module is further used for determining the dissolved volume of the natural gas according to the hydrocarbon liquid density of the wet natural gas and the dissolved mass.
In another implementation manner of the embodiment of the present disclosure, the obtaining module is further configured to obtain a corresponding relationship between a density of the hydrocarbon liquid and a natural gas solubility of the hydrocarbon liquid; the measurement module is used for measuring and obtaining the hydrocarbon liquid density of the wet natural gas; the determining module is further configured to determine a natural gas solubility of the hydrocarbon liquid in the wet natural gas based on the correspondence according to the hydrocarbon liquid density of the wet natural gas.
In another implementation manner of the embodiment of the present disclosure, the obtaining module is further configured to obtain a density of the hydrocarbon liquid and a natural gas solubility of the hydrocarbon liquid within a set temperature range and a set pressure range; the split-phase flow determination device further comprises an establishing module, and the establishing module is used for establishing the corresponding relation according to the hydrocarbon liquid density and the natural gas solubility in a set temperature range and a set pressure range.
In a third aspect, an embodiment of the present disclosure provides an apparatus for determining a split-phase flow rate of wet natural gas, the apparatus including: a processor; a memory for storing processor-executable instructions; wherein the processor is configured to perform the method of determining the split phase flow rate of wet natural gas described hereinbefore.
The beneficial effects brought by the technical scheme provided by the embodiment of the disclosure at least comprise:
according to the embodiment of the disclosure, the natural gas flow and the hydrocarbon liquid flow before mixing are obtained, the natural gas solubility of the hydrocarbon liquid in the wet natural gas is determined, and then the natural gas flow and the hydrocarbon liquid flow before mixing are respectively corrected based on the natural gas solubility of the hydrocarbon liquid in the wet natural gas, so that the natural gas flow and the hydrocarbon liquid flow in the wet natural gas are obtained. The natural gas flow and the hydrocarbon liquid flow determined by the correction calculation are consistent with the natural gas flow and the hydrocarbon liquid flow of the wet natural gas after mixing, so that the flow of the wet natural gas detected by the wet natural gas detection device can be corrected, and the detection accuracy is ensured.
Drawings
In order to more clearly illustrate the technical solutions in the embodiments of the present disclosure, the drawings needed to be used in the description of the embodiments are briefly introduced below, and it is obvious that the drawings in the following description are only some embodiments of the present disclosure, and it is obvious for those skilled in the art to obtain other drawings based on the drawings without creative efforts.
FIG. 1 is a flow chart of a method for determining a split-phase flow rate of wet natural gas according to an embodiment of the disclosure;
FIG. 2 is a flow chart of another method for determining the split-phase flow rate of wet natural gas provided by an embodiment of the disclosure;
FIG. 3 is a schematic diagram of an apparatus for determining the split-phase flow rate of wet natural gas according to an embodiment of the disclosure;
FIG. 4 is a schematic diagram of another apparatus for determining the split-phase flow rate of wet natural gas provided by an embodiment of the disclosure.
Detailed Description
To make the objects, technical solutions and advantages of the present disclosure more apparent, embodiments of the present disclosure will be described in detail with reference to the accompanying drawings.
Fig. 1 is a flowchart of a method for determining a split-phase flow rate of wet natural gas according to an embodiment of the disclosure. As shown in fig. 1, the wet natural gas is formed by mixing natural gas and liquid, the liquid at least comprises hydrocarbon liquid, and the split-phase flow determination method is executed by an upper computer and comprises the following steps:
step 101: and acquiring the flow of the natural gas before mixing and the flow of the hydrocarbon liquid before mixing.
Step 102: the natural gas solubility of the hydrocarbon liquid in the wet natural gas is determined.
Step 103: and respectively correcting the natural gas flow before mixing and the hydrocarbon liquid flow before mixing based on the natural gas solubility of the hydrocarbon liquid in the wet natural gas to obtain the natural gas flow and the hydrocarbon liquid flow in the wet natural gas.
According to the embodiment of the disclosure, the natural gas flow and the hydrocarbon liquid flow before mixing are obtained, the natural gas solubility of the hydrocarbon liquid in the wet natural gas is determined, and then the natural gas flow and the hydrocarbon liquid flow before mixing are respectively corrected based on the natural gas solubility of the hydrocarbon liquid in the wet natural gas, so that the natural gas flow and the hydrocarbon liquid flow in the wet natural gas are obtained. The natural gas flow and the hydrocarbon liquid flow determined by the correction calculation are consistent with the natural gas flow and the hydrocarbon liquid flow of the wet natural gas after mixing, so that the flow of the wet natural gas detected by the wet natural gas detection device can be corrected, and the detection accuracy is ensured.
Fig. 2 is a flow chart of another method for determining the split-phase flow rate of wet natural gas according to an embodiment of the disclosure. As shown in fig. 2, the wet natural gas is formed by mixing natural gas and liquid, the liquid at least comprises hydrocarbon liquid, and the split-phase flow determination method is executed by an upper computer and comprises the following steps:
step 201: and acquiring the flow of the natural gas before mixing and the flow of the hydrocarbon liquid before mixing.
Step 202: and acquiring the corresponding relation between the density of the hydrocarbon liquid and the natural gas solubility of the hydrocarbon liquid.
Acquiring the correspondence may include the following two steps:
the first step is as follows: and acquiring the density of the hydrocarbon liquid and the natural gas solubility of the hydrocarbon liquid in a set temperature range and a set pressure range.
Wherein the set temperature range can be 0 ℃ to 45 ℃, and the set pressure range can be 0.3MPa to 9 MPa.
In the first step, the acquired data of the density of the hydrocarbon liquid and the natural gas solubility of the hydrocarbon liquid can be acquired through experimental tests, and the data acquired through the experimental tests are stored in a storage unit for being acquired by an upper computer.
The experimental test can be carried out by placing hydrocarbon liquid in a container under different temperature and pressure conditions, introducing natural gas into the hydrocarbon liquid, and measuring the density of the hydrocarbon liquid and the solubility of the natural gas in the hydrocarbon liquid.
Alternatively, experimental testing may be performed in a controlled variable manner.
Illustratively, the temperature condition during the experimental test is controlled to be constant, and the pressure condition during the experimental test is changed. For example, the temperature of the experimental test is controlled to be 10 ℃, and a plurality of groups of conditions with different pressures (such as 0.3Mpa, 0.5Mpa and 0.7Mpa) are set for the experimental test, so as to determine the solubility of the natural gas and the density of the hydrocarbon liquid under the current conditions of the temperature and the pressure.
Illustratively, the pressure condition during the experimental test is controlled to be constant, and the temperature condition during the experimental test is changed. For example, the pressure during the experimental test is controlled to be 1.0Mpa, and a plurality of sets of different temperature (e.g. 0 ℃, 10 ℃, 20 ℃ and the like) conditions are set for the experimental test, so as to determine the solubility of the natural gas and the density of the hydrocarbon liquid under the current temperature and pressure conditions.
Wherein the temperature condition can be 0 deg.C to 45 deg.C, and the pressure condition can be 0.3MPa to 9MPa, or the temperature condition can be 10 deg.C to 30 deg.C, and the pressure condition can be 1.8MPa to 5 MPa.
Alternatively, when the density of the hydrocarbon liquid is measured, the density of the hydrocarbon liquid may be measured by controlling the noncontact density measuring device. The non-contact density measuring device can be a gamma ray on-line densitometer or an ultrasonic densitometer.
The second step is that: and establishing a corresponding relation between the density of the hydrocarbon liquid and the natural gas solubility of the hydrocarbon liquid according to the density of the hydrocarbon liquid and the natural gas solubility in the set temperature range and the set pressure range.
Optionally, the second step comprises: and fitting a plurality of groups of data of the hydrocarbon liquid density and the natural gas solubility under different temperature and pressure conditions, which are obtained by experiments, and establishing a corresponding relation between the hydrocarbon liquid density and the natural gas solubility of the hydrocarbon liquid.
The established corresponding relation can be expressed by the following formula:
in the formula (1), T is temperature, P is pressure, rho is hydrocarbon liquid density, chi is natural gas solubility of wet natural gas, and T is0Is a known temperature, P0For known pressure, ρo、χoIs a pressure of P0Temperature of T0The hydrocarbon liquid density and natural gas solubility, k, a, b are constants, and can be determined by fitting experimental test data.
The corresponding relationship established in step 202 may be stored in a storage unit, and when the corresponding relationship needs to be obtained for use, the upper computer may directly obtain the corresponding relationship between the density of the hydrocarbon liquid and the natural gas solubility of the hydrocarbon liquid from the storage unit.
Step 203: the hydrocarbon liquid density of the wet natural gas was measured.
In step 203, the hydrocarbon liquid density of the mixed wet natural gas can be obtained by using a gamma ray on-line densitometer and an ultrasonic densitometer.
Step 204: and determining the natural gas solubility of the hydrocarbon liquid in the wet natural gas based on the corresponding relation according to the hydrocarbon liquid density of the wet natural gas.
When the natural gas solubility of the hydrocarbon liquid in the wet natural gas is calculated according to the formula (1), the temperature T and the pressure P after mixing are also required to be determined.
Wherein, the temperature T can be measured by a quick-response temperature transmitter, and the pressure P can be measured by a quick-response pressure transmitter. The temperature and the pressure of the mixed hydrocarbon liquid can be measured by a temperature transmitter and a pressure transmitter, and the measured temperature and the measured pressure and the density of the hydrocarbon liquid measured in the step 203 are substituted into the formula (1) to calculate the natural gas solubility of the hydrocarbon liquid in the wet natural gas.
Step 205: and correcting the natural gas flow before mixing based on the natural gas solubility of the hydrocarbon liquid in the wet natural gas to obtain the natural gas flow in the wet natural gas.
Step 205 may include: determining the natural gas solubility of the hydrocarbon liquid before mixing and the natural gas solubility of the hydrocarbon liquid in the wet natural gas after mixing according to the corresponding relation; determining a difference between the natural gas solubility of the hydrocarbon liquid prior to mixing and the natural gas solubility of the hydrocarbon liquid in the wet natural gas; and correcting the natural gas flow before mixing by adopting the difference value to obtain the natural gas flow in the wet natural gas.
In some embodiments, the hydrocarbon liquid used before mixing may be hydrocarbon liquid that has not been mixed with natural gas, i.e., the hydrocarbon liquid has no natural gas dissolved therein, where the natural gas solubility of the hydrocarbon liquid before mixing is 0, and the difference between the natural gas solubility of the hydrocarbon liquid before mixing and the natural gas solubility of the hydrocarbon liquid in the wet natural gas after mixing is equal to the natural gas solubility of the hydrocarbon liquid in the wet natural gas after mixing.
In other embodiments, the hydrocarbon liquid used before mixing may be a hydrocarbon liquid recovered from wet natural gas, that is, the hydrocarbon liquid is recovered from wet natural gas, and a certain amount of natural gas may be dissolved in the hydrocarbon liquid, so that, at this time, the amount of natural gas dissolved in the hydrocarbon liquid of the hydrocarbon liquid in the wet natural gas after mixing needs to be determined according to the difference between the natural gas solubility of the hydrocarbon liquid before mixing and the natural gas solubility of the hydrocarbon liquid in the wet natural gas after mixing.
Wherein, determining the natural gas flow rate of the wet natural gas according to the difference between the natural gas solubility of the hydrocarbon liquid before mixing and the natural gas solubility of the hydrocarbon liquid in the wet natural gas after mixing may include: calculating the product of the flow rate of the hydrocarbon liquid and the difference value before mixing; the difference between the natural gas flow before mixing and the product is determined as the natural gas flow in the wet natural gas.
The above-described manner of determining the natural gas flow rate of wet natural gas can be summarized as the following formula:
in the formula (2), QgrFor mixed natural gas flow, QgFor the natural gas flow before mixing, QlFor the flow of the hydrocarbon liquid before mixing, p1Density of the hydrocarbon liquid before mixing, p2The density of the hydrocarbon liquid after mixing, T is the temperature, P is the pressure, T0Is a known temperature, P0For known pressure, ρoIs a pressure of P0Temperature of T0Density of hydrocarbon liquid, p1Is before mixingDensity of the hydrocarbon liquid, p2K, a, b are constants that are the densities of the hydrocarbon liquids in the wet natural gas after blending and can be determined by fitting experimental test data.
When determining the natural gas flow rate of the wet natural gas according to the formula (2), first, the hydrocarbon liquid density ρ before mixing is obtained1Natural gas flow rate before mixing QgFlow rate Q of hydrocarbon liquid before mixinglAnd the density p of the hydrocarbon liquid after mixing2And simultaneously measuring the pressure P and the temperature T of the mixed wet natural gas. Then, the measured density ρ of the hydrocarbon liquid before mixing1Natural gas flow rate before mixing QgFlow rate Q of hydrocarbon liquid before mixinglDensity p of mixed hydrocarbon liquid2And substituting the pressure P and the temperature T of the mixed wet natural gas into the formula (2) to determine the flow rate of the mixed natural gas.
Step 206: and respectively correcting the natural gas flow before mixing and the hydrocarbon liquid flow before mixing based on the natural gas solubility of the hydrocarbon liquid in the wet natural gas to obtain the hydrocarbon liquid flow in the wet natural gas.
Step 206 may include: determining the liquid variation according to the hydrocarbon liquid flow before mixing and the natural gas solubility of the hydrocarbon liquid in the wet natural gas; and determining the sum of the hydrocarbon liquid flow rate before mixing and the liquid change amount as the hydrocarbon liquid flow rate in the wet natural gas.
The method for determining the hydrocarbon liquid flow of the mixed wet natural gas can be specifically summarized as the following formula:
in the formula (3), QlrFor the flow of the hydrocarbon liquid after mixing, QlThe hydrocarbon liquid flow before mixing, chi is the natural gas solubility of wet natural gas, T is the temperature, P is the pressure, and k, a and b are constants, can be determined by fitting experimental test data.
When determining the natural gas flow rate of the wet natural gas according to the formula (3), first, a mixture is obtainedFront hydrocarbon liquid flow rate QlAnd the natural gas solubility χ of the mixed wet natural gas, while measuring the pressure P and the temperature T of the mixed wet natural gas. Then, the measured flow rate Q of the hydrocarbon liquid before mixinglSubstituting the pressure P and the temperature T of the mixed wet natural gas and the natural gas solubility x of the mixed wet natural gas determined according to the formula (1) into the formula (3) to determine the flow rate of the mixed hydrocarbon liquid.
Because there may be a part of natural gas dissolved in the hydrocarbon liquid during the mixing process, the flow rate of the mixed natural gas is reduced, the density of the mixed hydrocarbon liquid is reduced, and the flow rate of the mixed hydrocarbon liquid is increased, thereby changing the flow rate of the mixed natural gas and the flow rate of the mixed hydrocarbon liquid. The mixed natural gas flow and the mixed hydrocarbon liquid flow are accurately determined through correction calculation according to the formula, so that the natural gas flow and the hydrocarbon liquid flow determined through correction calculation are consistent with the natural gas flow and the hydrocarbon liquid flow of the mixed wet natural gas, the flow of the wet natural gas detected by the wet natural gas detection device is corrected conveniently, and the detection accuracy is guaranteed.
The split-phase flow determination method provided in the embodiment of the present disclosure may further include: determining the dissolving quality of the natural gas according to the hydrocarbon liquid flow of the wet natural gas and the natural gas solubility of the hydrocarbon liquid of the wet natural gas; and measuring to obtain the hydrocarbon liquid density of the wet natural gas, and determining the dissolved volume of the natural gas according to the hydrocarbon liquid density and the dissolved mass of the wet natural gas.
Fig. 3 is a schematic diagram of an apparatus for determining the split-phase flow rate of wet natural gas according to an embodiment of the disclosure. As shown in fig. 3, the split-phase flow rate determination apparatus includes: an acquisition module 100, a determination module 200 and a correction module 300. The obtaining module 100 is configured to obtain a natural gas flow rate before mixing and a hydrocarbon liquid flow rate before mixing; the determination module 200 is used for determining the natural gas solubility of the hydrocarbon liquid in the wet natural gas; and a correction module 300. The method is used for respectively correcting the natural gas flow before mixing and the hydrocarbon liquid flow before mixing based on the natural gas solubility of the hydrocarbon liquid in the wet natural gas to obtain the natural gas flow and the hydrocarbon liquid flow in the wet natural gas.
Optionally, the determining module 200 is further configured to determine a difference between the natural gas solubility of the hydrocarbon liquid before blending and the natural gas solubility of the hydrocarbon liquid in the wet natural gas; the correction module 300 is further configured to correct the natural gas flow before mixing by using the difference value, so as to obtain the natural gas flow in the wet natural gas.
Optionally, the split-phase flow determination apparatus further comprises a calculation module 400, and the calculation module 400 is configured to calculate a product of the hydrocarbon liquid flow before mixing and the difference; the determination module 200 is further configured to determine a difference between the natural gas flow before mixing and the product as the natural gas flow in the wet natural gas.
Optionally, the determining module 200 is further configured to determine the liquid change amount according to the flow rate of the hydrocarbon liquid before mixing and the natural gas solubility of the hydrocarbon liquid in the wet natural gas; and the sum of the hydrocarbon liquid flow rate before mixing and the liquid change amount is determined as the hydrocarbon liquid flow rate in the wet natural gas.
Optionally, the determining module 200 is further configured to determine the dissolution quality of the natural gas according to the hydrocarbon liquid flow rate of the wet natural gas and the natural gas solubility of the hydrocarbon liquid of the wet natural gas; the split-phase flow determination device further comprises a measurement module 500, wherein the measurement module 500 is used for measuring the density of the hydrocarbon liquid of the wet natural gas, and the determination module is further used for determining the dissolved volume of the natural gas according to the density and the dissolved mass of the hydrocarbon liquid of the wet natural gas.
Optionally, the obtaining module 100 is further configured to obtain a corresponding relationship between the density of the hydrocarbon liquid and the natural gas solubility of the hydrocarbon liquid; the measurement module 500 is used for measuring the density of the hydrocarbon liquid of the wet natural gas; the determining module 200 is further configured to determine the natural gas solubility of the hydrocarbon liquid in the wet natural gas based on the correspondence according to the hydrocarbon liquid density of the wet natural gas.
Optionally, the obtaining module 100 is further configured to obtain a density of the hydrocarbon liquid and a natural gas solubility of the hydrocarbon liquid within a set temperature range and a set pressure range; the split-phase flow determination apparatus further comprises an establishing module 600, and the establishing module 600 is configured to establish a corresponding relationship according to the hydrocarbon liquid density and the natural gas solubility within the set temperature range and the set pressure range.
FIG. 4 is a schematic diagram of another apparatus for determining the split-phase flow rate of wet natural gas provided by an embodiment of the disclosure. As shown in fig. 4, the device 700 for determining the split-phase flow rate of the wet natural gas may be a computer or the like.
Generally, the apparatus 700 for determining the split-phase flow rate of wet natural gas comprises: a processor 701 and a memory 702.
The processor 701 may include one or more processing cores, such as a 4-core processor, an 8-core processor, and so on. The processor 701 may be implemented in at least one hardware form of a DSP (Digital Signal Processing), an FPGA (Field-Programmable Gate Array), and a PLA (Programmable Logic Array). The processor 701 may also include a main processor and a coprocessor, where the main processor is a processor for Processing data in an awake state, and is also called a Central Processing Unit (CPU); a coprocessor is a low power processor for processing data in a standby state. In some embodiments, the processor 701 may be integrated with a GPU (Graphics Processing Unit), which is responsible for rendering and drawing the content required to be displayed on the display screen. In some embodiments, the processor 701 may further include an AI (Artificial Intelligence) processor for processing computing operations related to machine learning.
In some embodiments, the apparatus 700 for determining the split-phase flow rate of the wet natural gas may further include: a peripheral interface 703 and at least one peripheral. The processor 701, the memory 702, and the peripheral interface 703 may be connected by buses or signal lines. Various peripheral devices may be connected to peripheral interface 703 via a bus, signal line, or circuit board. Specifically, the peripheral device includes: at least one of radio frequency circuitry 704, touch screen display 705, camera 706, audio circuitry 707, positioning components 708, and power source 709.
The peripheral interface 703 may be used to connect at least one peripheral related to I/O (Input/Output) to the processor 701 and the memory 702. In some embodiments, processor 701, memory 702, and peripheral interface 703 are integrated on the same chip or circuit board; in some other embodiments, any one or two of the processor 701, the memory 702, and the peripheral interface 703 may be implemented on a separate chip or circuit board, which is not limited in this embodiment.
The display screen 705 is used to display a UI (User Interface). The UI may include graphics, text, icons, video, and any combination thereof. When the display screen 705 is a touch display screen, the display screen 705 also has the ability to capture touch signals on or over the surface of the display screen 705. The touch signal may be input to the processor 701 as a control signal for processing. At this point, the display 705 may also be used to provide virtual buttons and/or a virtual keyboard, also referred to as soft buttons and/or a soft keyboard. In some embodiments, the display 705 may be one, which is provided as a front panel of the device 700 for determining the split-phase flow rate of the wet natural gas; in other embodiments, the display 705 may be at least two, respectively disposed on different surfaces of the device 700 for determining the split-phase flow rate of wet natural gas or in a folded design; in still other embodiments, the display 705 may be a flexible display disposed on a curved surface or a folded surface of the split-phase flow determination device 700 for wet natural gas. Even more, the display 705 may be arranged in a non-rectangular irregular pattern, i.e. a shaped screen. The Display 705 may be made of LCD (Liquid Crystal Display), OLED (Organic Light-Emitting Diode), or the like.
The power supply 709 is used to supply power to various components in the split-phase flow determination device 700 for wet natural gas. The power source 709 may be alternating current, direct current, disposable batteries, or rechargeable batteries. When power source 709 includes a rechargeable battery, the rechargeable battery may support wired or wireless charging. The rechargeable battery may also be used to support fast charge technology.
Those skilled in the art will appreciate that the configuration shown in FIG. 4 does not constitute a limitation of the apparatus 700 for determining the split-phase flow of wet natural gas and may include more or fewer components than shown, or some components may be combined, or a different arrangement of components may be employed.
Embodiments of the present invention also provide a non-transitory computer-readable storage medium, where instructions in the storage medium, when executed by a processor of a device for determining a split-phase flow rate of wet natural gas, enable a device for checking a gas well inflow dynamic curve to perform the method for determining a split-phase flow rate of wet natural gas provided in the embodiment shown in fig. 1 or fig. 2.
A computer program product containing instructions which, when run on a computer, cause the computer to perform the method for determining the split-phase flow rate of wet natural gas as provided in the embodiments of fig. 1 or 2 above.
It will be understood by those skilled in the art that all or part of the steps for implementing the above embodiments may be implemented by hardware, or may be implemented by a program instructing relevant hardware, where the program may be stored in a computer-readable storage medium, and the above-mentioned storage medium may be a read-only memory, a magnetic disk or an optical disk, etc.
The above description is only exemplary of the present disclosure and is not intended to limit the present disclosure, which is to be construed in any way as imposing limitations thereon, such as the appended claims, and all changes and equivalents that fall within the true spirit and scope of the present disclosure.
Claims (16)
1. A method for determining a split-phase flow rate of wet natural gas, the wet natural gas being formed by mixing natural gas and a liquid, the liquid including at least a hydrocarbon liquid, the method comprising:
acquiring the natural gas flow before mixing and the hydrocarbon liquid flow before mixing;
determining a natural gas solubility of the hydrocarbon liquid in the wet natural gas;
and respectively correcting the natural gas flow before mixing and the hydrocarbon liquid flow before mixing based on the natural gas solubility of the hydrocarbon liquid in the wet natural gas to obtain the natural gas flow and the hydrocarbon liquid flow in the wet natural gas.
2. The method for determining the split-phase flow of the wet natural gas according to claim 1, wherein the step of correcting the natural gas flow before mixing based on the natural gas solubility of the hydrocarbon liquid in the wet natural gas to obtain the natural gas flow in the wet natural gas comprises the following steps:
determining a difference between natural gas solubility of the hydrocarbon liquid prior to mixing and natural gas solubility of the hydrocarbon liquid in the wet natural gas;
and correcting the natural gas flow before mixing by adopting the difference value to obtain the natural gas flow in the wet natural gas.
3. The method for determining the split-phase flow of the wet natural gas according to claim 2, wherein the correcting the natural gas flow before mixing by using the difference value to obtain the natural gas flow in the wet natural gas comprises:
calculating the product of the hydrocarbon liquid flow rate before mixing and the difference;
determining a difference between the natural gas flow before mixing and the product as the natural gas flow in the wet natural gas.
4. The method for determining the split-phase flow of the wet natural gas according to claim 1, wherein the step of respectively correcting the natural gas flow before mixing and the hydrocarbon liquid flow before mixing based on the natural gas solubility of the hydrocarbon liquid in the wet natural gas to obtain the hydrocarbon liquid flow in the wet natural gas comprises:
determining the liquid variation according to the flow of the hydrocarbon liquid before mixing and the natural gas solubility of the hydrocarbon liquid in the wet natural gas;
and determining the sum of the hydrocarbon liquid flow rate before mixing and the liquid change amount as the hydrocarbon liquid flow rate in the wet natural gas.
5. The method for determining the split-phase flow rate of wet natural gas according to any one of claims 1 to 4, further comprising:
determining the dissolution quality of the natural gas according to the hydrocarbon liquid flow of the wet natural gas and the natural gas solubility of the hydrocarbon liquid of the wet natural gas;
and measuring to obtain the hydrocarbon liquid density of the wet natural gas, and determining the dissolved volume of the natural gas according to the hydrocarbon liquid density of the wet natural gas and the dissolved mass.
6. The method for determining the split-phase flow of wet natural gas according to any one of claims 1 to 4, wherein the obtaining of the natural gas flow rate before mixing and the hydrocarbon liquid flow rate before mixing comprises:
obtaining the corresponding relation between the density of the hydrocarbon liquid and the natural gas solubility of the hydrocarbon liquid;
measuring the density of the hydrocarbon liquid of the wet natural gas;
and determining the natural gas solubility of the hydrocarbon liquid in the wet natural gas based on the corresponding relation according to the hydrocarbon liquid density of the wet natural gas.
7. The method for determining the split-phase flow of the wet natural gas according to claim 6, wherein the obtaining the corresponding relation between the density of the hydrocarbon liquid and the natural gas solubility of the hydrocarbon liquid comprises:
acquiring the density of the hydrocarbon liquid and the natural gas solubility of the hydrocarbon liquid within a set temperature range and a set pressure range;
and establishing the corresponding relation according to the hydrocarbon liquid density and the natural gas solubility in a set temperature range and a set pressure range.
8. A split-phase flow rate determining apparatus for wet natural gas formed by mixing natural gas and a liquid including at least a hydrocarbon liquid, the split-phase flow rate determining apparatus comprising:
the acquisition module is used for acquiring the natural gas flow before mixing and the hydrocarbon liquid flow before mixing;
a determination module that determines a natural gas solubility of a hydrocarbon liquid in the wet natural gas;
and the correction module is used for correcting the natural gas flow before mixing and the hydrocarbon liquid flow before mixing respectively based on the natural gas solubility of the hydrocarbon liquid in the wet natural gas to obtain the natural gas flow and the hydrocarbon liquid flow in the wet natural gas.
9. The split-phase flow determination device of wet natural gas according to claim 8, wherein the determination module is further configured to determine a difference between a natural gas solubility of the hydrocarbon liquid before mixing and a natural gas solubility of the hydrocarbon liquid in the wet natural gas; the correction module is further used for correcting the natural gas flow before mixing by adopting the difference value to obtain the natural gas flow in the wet natural gas.
10. The split-phase flow rate determination device for wet natural gas according to claim 9, characterized by further comprising: a calculation module for calculating a product of the hydrocarbon liquid flow before mixing and the difference; the determination module is further configured to determine a difference between the natural gas flow before mixing and the product as the natural gas flow in the wet natural gas.
11. The split-phase flow determination device of wet natural gas according to claim 8, wherein the determination module is further configured to determine the liquid change amount according to the flow rate of the hydrocarbon liquid before mixing and the natural gas solubility of the hydrocarbon liquid in the wet natural gas; and the sum of the hydrocarbon liquid flow rate before mixing and the liquid change amount is determined as the hydrocarbon liquid flow rate in the wet natural gas.
12. The split-phase flow determination apparatus of wet natural gas according to any one of claims 8 to 11, wherein the determination module is further configured to determine a dissolved quality of natural gas based on the hydrocarbon liquid flow rate of the wet natural gas and the natural gas solubility of the hydrocarbon liquid of the wet natural gas;
the split-phase flow determination device further comprises a measurement module, the measurement module is used for measuring and obtaining the hydrocarbon liquid density of the wet natural gas, and the determination module is further used for determining the dissolved volume of the natural gas according to the hydrocarbon liquid density of the wet natural gas and the dissolved mass.
13. The split-phase flow determination device of wet natural gas according to any one of claims 8 to 11, wherein the obtaining module is further configured to obtain a correspondence between a density of the hydrocarbon liquid and a natural gas solubility of the hydrocarbon liquid; the measurement module is used for measuring and obtaining the hydrocarbon liquid density of the wet natural gas; the determining module is further configured to determine a natural gas solubility of the hydrocarbon liquid in the wet natural gas based on the correspondence according to the hydrocarbon liquid density of the wet natural gas.
14. The split-phase flow determination device of wet natural gas according to claim 13, wherein the obtaining module is further configured to obtain a hydrocarbon liquid density and a natural gas solubility of the hydrocarbon liquid within a set temperature range, a set pressure range; the split-phase flow determination device further comprises an establishing module, and the establishing module is used for establishing the corresponding relation according to the hydrocarbon liquid density and the natural gas solubility in a set temperature range and a set pressure range.
15. An apparatus for determining a split-phase flow rate of wet natural gas, the apparatus comprising:
a processor;
a memory for storing processor-executable instructions;
wherein the processor is configured to perform the method of determining the split phase flow rate of wet natural gas of any one of claims 1 to 7.
16. A non-transitory computer readable storage medium having stored therein at least one instruction, which is loaded and executed by a processor to implement the method for determining the split phase flow of wet natural gas according to any one of claims 1 to 7.
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