CN112763007B - Method and device for determining split-phase flow of wet natural gas and storage medium - Google Patents

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 detection device can be 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 a hydrocarbonaceous 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 flow of the hydrocarbon liquid 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 flow rate of the hydrocarbon liquid before mixing and the liquid change amount as the flow rate of the hydrocarbon liquid 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 density of the hydrocarbon liquid in 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 an embodiment of the present disclosure, 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 an embodiment of the present disclosure, the determining module is further configured to determine a dissolved quality of the 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.

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 relationship according to a 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 effect that technical scheme that this disclosure embodiment provided brought includes at least:

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.

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 hydrocarbonaceous 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 natural gas flow before mixing and the hydrocarbon liquid flow 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 9MPa.

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 manner that controls variables.

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 0.7 Mpa) 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 5MPa.

Alternatively, when the density of the hydrocarbon liquid is measured, the density of the hydrocarbon liquid may be measured by controlling the non-contact 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 is ₀ Is a known temperature, P ₀ For known pressure, p _o 、χ _o Is a pressure of P ₀ Temperature of T ₀ The hydrocarbon liquid density and natural gas solubility, k, a and b are constants, and can be determined by fitting experimental test data.

Step 203: the hydrocarbon liquid density of the wet natural gas was measured.

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.

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 hydrocarbonaceous liquid prior to mixing and the natural gas solubility of the hydrocarbonaceous 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 blending may be a hydrocarbon liquid that has not been blended with natural gas, i.e., the hydrocarbon liquid has no natural gas dissolved therein, where the natural gas solubility of the hydrocarbon liquid before blending is 0, and the difference between the natural gas solubility of the hydrocarbon liquid before blending and the natural gas solubility of the hydrocarbon liquid in wet natural gas after blending is equal to the natural gas solubility of the hydrocarbon liquid in wet natural gas after blending.

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), Q _gr For mixed natural gas flow, Q _g For the natural gas flow before mixing, Q _l Flow rate of hydrocarbon liquid before mixing, p ₁ Density of the hydrocarbon liquid before mixing, p ₂ The density of the hydrocarbon liquid after mixing, T is the temperature, P is the pressure, T ₀ Is a known temperature, P ₀ For known pressure, ρ _o At a pressure of P ₀ Temperature of T ₀ Density of hydrocarbon liquid, p ₁ Density, p, of the hydrocarbon liquid before mixing ₂ K, 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 obtained ₁ Natural gas flow rate before mixing Q _g Flow rate Q of hydrocarbon liquid before mixing _l And the density p of the hydrocarbon liquid after mixing ₂ And 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 mixing ₁ Natural gas flow rate before mixing Q _g Flow rate Q of hydrocarbon liquid before mixing _l Density p of mixed hydrocarbon liquid ₂ And (3) 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 mode of determining the hydrocarbon liquid flow of the wet natural gas after mixing can be specifically summarized as the following formula:

in the formula (3), Q _lr For the flow of the hydrocarbon liquid after mixing, Q _l The 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, the hydrocarbon liquid flow rate Q before mixing is obtained _l And 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 mixing _l Substituting 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 determining 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 density of the hydrocarbon liquid of the wet natural gas, and 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.

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 carry out the method of determining the split-phase flow rate of wet natural gas as provided in the embodiment of fig. 1 or 2 described 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 disclosure is intended to be exemplary only, and not limiting, and all such modifications, equivalents, improvements, and equivalents that fall within the spirit and scope of the present disclosure are intended to be embraced therein.