CN114544906B - Device and method for detecting content of liquid hydrocarbon in natural gas - Google Patents
Device and method for detecting content of liquid hydrocarbon in natural gas Download PDFInfo
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- CN114544906B CN114544906B CN202011328355.5A CN202011328355A CN114544906B CN 114544906 B CN114544906 B CN 114544906B CN 202011328355 A CN202011328355 A CN 202011328355A CN 114544906 B CN114544906 B CN 114544906B
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- G—PHYSICS
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- G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
- G01N33/00—Investigating or analysing materials by specific methods not covered by groups G01N1/00 - G01N31/00
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Abstract
The invention provides a device and a method for detecting the content of liquid hydrocarbon in natural gas, wherein the device comprises a sample inlet pipe; the sample injection pipe is communicated with one end of the heat exchanger; the other end of the heat exchanger is communicated with the input end of the gas-liquid separator; the input end of the liquid hydrocarbon content detection component is communicated with the liquid outlet end of the gas-liquid separator; the input end of the gas flow detection component is communicated with the gas outlet end of the gas-liquid separator; and the differential pressure testing component is connected with the liquid hydrocarbon content detection component and is used for testing the differential pressure value of the liquid in the liquid hydrocarbon content detection component. The device and the method for detecting the content of the liquid hydrocarbon in the natural gas can simply, efficiently and accurately detect the content of the liquid hydrocarbon in the natural gas.
Description
Technical Field
The invention relates to a device and a method for detecting the content of liquid hydrocarbon in natural gas, and belongs to the technical field of natural gas detection.
Background
In recent years, the development of the natural gas industry in China is rapid, and in 2018, the natural gas consumption in China reaches 2810 hundred million m 3 Throughput of 1610 hundred million m 3 Inlet amount is 1200 hundred million m 3 。
The natural gas contains methane as main component, and small amount of ethane, propane, butane, pentane and hexane (C) 6 + ) Hydrocarbon gas, additionally comprising CO 2 、N 2 、H 2 S、O 2 、H 2 And a trace amount of a non-hydrocarbon gas such as an inert gas (e.g., he, ar). When heavy hydrocarbon components in natural gas are high, the natural gas is generally called condensed natural gas, and the mixture in the natural gas is subjected to isothermal degradationLiquid can be condensed in the pressing process, and the phase characteristics different from those of pure gas bring great challenges to the links of natural gas exploitation, processing and conveying.
The condensed natural gas reservoirs are widely distributed in areas such as Xinjiang, shaanxi, inner Mongolia, sichuan and the like in China, and gas sources of the first line of Western gas delivery and the second line of Western gas delivery of the natural gas delivery big artery are all condensed natural gas with higher heavy hydrocarbon components. Therefore, the accurate liquid hydrocarbon content in the natural gas under the specific pressure and temperature state is known, and the method has important guiding significance for improving the recovery ratio of the condensed natural gas reservoir, ensuring the product gas quality of a natural gas treatment plant and ensuring the safe and efficient operation of a natural gas pipeline.
Except that the condensed natural gas is possibly at a higher temperature in a gas reservoir, the condition that the temperature is lower than the normal temperature (25 ℃) can be caused in the processing and pipeline conveying links, so that the liquid hydrocarbon content in the natural gas with different temperature, pressure conditions and different gas compositions can be accurately measured, scientific and comprehensive basic data are provided for the design and operation of a natural gas processing device and the dew point control of conveying natural gas hydrocarbon, and the problems of the operation of various processing devices and the low-efficiency operation of a gas pipeline caused by the condensation of the liquid hydrocarbon can be avoided.
However, the natural gas with different temperature, pressure and different gas composition has larger difference of liquid hydrocarbon content, and the natural gas with different gas composition which is in gas state at normal temperature (25 ℃) can have hydrocarbon content distributed at 5mg/Nm under the conditions of 4MPa and 0 DEG C 3 To 15g/Nm 3 And the range is even wider, so the measuring device needs to have higher test sensitivity and stronger natural gas adaptability.
Chinese patent CN 103076404 discloses a method for detecting total liquid hydrocarbons in natural gas by gas composition analysis, using subtraction of C from 100% 1 -C 4 The method for weighting the content is used for obtaining the composition content of liquid hydrocarbon in natural gas, and the analysis is quick, however, the method is rough, the obtained calculated value does not change along with pressure and temperature, and the calculated value is not in accordance with the actual situation, and is often difficult to guide the actual production.
In addition, the natural gas composition analysis result is commonly used as an input value in the industry, the liquid hydrocarbon content in the natural gas is predicted by adopting a state equation, and the design, the operation and the running of the natural gas treatment device are further guided.
Accordingly, there is a need in the art for a method and apparatus that can achieve accurate determination of liquid hydrocarbon content in natural gas to address the above-identified problems.
Disclosure of Invention
In order to solve the above-mentioned drawbacks and disadvantages, an object of the present invention is to provide a device for detecting the content of liquid hydrocarbon in natural gas.
The invention also aims at providing a method for detecting the content of liquid hydrocarbon in natural gas. The device and the method provided by the invention can simply, efficiently and accurately detect the content of the liquid hydrocarbon in the natural gas.
In order to achieve the above object, in one aspect, the present invention provides a device for detecting a liquid hydrocarbon content in natural gas, wherein the device for detecting a liquid hydrocarbon content in natural gas comprises:
a sample inlet tube;
the sample injection pipe is communicated with one end of the heat exchanger;
the other end of the heat exchanger is communicated with the input end of the gas-liquid separator;
the input end of the liquid hydrocarbon content detection component is communicated with the liquid outlet end of the gas-liquid separator;
the input end of the gas flow detection component is communicated with the gas outlet end of the gas-liquid separator;
and the differential pressure testing component is connected with the liquid hydrocarbon content detection component and is used for testing the differential pressure value of the liquid in the liquid hydrocarbon content detection component.
The beneficial effects of the invention are as follows: (1) The differential pressure signal of the liquid hydrocarbon can be detected through the differential pressure testing component, and the gas phase flow in the natural gas can be detected through the gas flow detecting component, so that the liquid hydrocarbon content can be calculated, and the accurate determination of the liquid hydrocarbon content in the natural gas can be realized;
(2) The device can detect the content of the liquid hydrocarbon in the natural gas very conveniently and rapidly, has high detection accuracy, and is beneficial to actual production operation.
On the basis of the technical scheme, the invention can be improved as follows.
Further, the liquid hydrocarbon content detection component comprises a plurality of measuring pipes with different pipe diameters, and one ends of the measuring pipes are communicated with the liquid outlet end of the gas-liquid separator.
The beneficial effects of adopting the further scheme are as follows: according to the liquid hydrocarbon content in different natural gases, different pipe diameters can be selected, and the continuous test of hydrocarbon liquid with the same time length is basically realized on the premise of using the same differential pressure gauge.
Further, the liquid hydrocarbon content detection member further includes: a liquid dispenser and a calibration liquid system;
the liquid distributor is connected to the liquid outlet end of the gas-liquid separator, a plurality of liquid outlets which are in one-to-one correspondence with the measuring pipes are arranged on the liquid distributor, a first valve is arranged on the liquid outlets, and one ends of the measuring pipes are connected and communicated with the corresponding liquid outlets;
and the output ends of the calibration liquid system are respectively connected and communicated with the other ends of the measuring pipes.
The beneficial effects of adopting the further scheme are as follows: the separate liquid phases are advantageously introduced into the measuring tube, wherein the calibration liquid system is capable of filling the measuring tube with a calibration liquid, which is calibrated in advance for the differential pressure gauge.
Further, the calibration liquid system comprises a calibration liquid metering pump and a calibration liquid inlet pipe, the calibration liquid inlet pipe corresponds to the measurement pipes one by one, the calibration liquid inlet pipe is respectively connected and communicated with the corresponding other ends of the measurement pipes after being split, the other ends of the split pipes of the calibration liquid inlet pipe are connected and communicated with the output ends of the calibration liquid metering pump, and the split pipes of the calibration liquid inlet pipe are respectively provided with one-way valves.
The beneficial effects of adopting the further scheme are as follows: through calibration liquid metering pump and many calibration liquid admission pipe can conveniently send into corresponding measuring intraductal with calibration liquid, can control the volume of calibration liquid of input simultaneously.
Further, the differential pressure test part is a sensitive differential pressure gauge, the detection ends of the sensitive differential pressure gauge are respectively connected with the two ends of the liquid hydrocarbon content detection part, and the differential pressure value of the input end and the output end of the liquid hydrocarbon content detection part is detected by the sensitive differential pressure gauge.
The beneficial effects of adopting the further scheme are as follows: the differential pressure value of the corresponding input end and output end of the measuring tube can be detected, so that the differential pressure value of the liquid phase in the measuring tube is obtained.
Further, the gas flow detection component comprises a rectifier, a flow sensor, an exhaust pipe and an exhaust control valve, wherein the input end of the rectifier is communicated with the air outlet end of the gas-liquid separator, the input end of the flow sensor is communicated with the output end of the rectifier, one end of the exhaust pipe is connected and communicated with the output end of the flow sensor, and the exhaust control valve is installed on the exhaust pipe.
The beneficial effects of adopting the further scheme are as follows: and the flow rate of the gas phase is conveniently detected.
Further, the device also comprises a pretreatment component and a pressure control component, one end of the sample inlet pipe is communicated with the input end of the pretreatment component, the output end of the pretreatment component is communicated with the input end of the pressure control component, the output end of the pressure control component is communicated with one end of the heat exchanger, and the other end of the heat exchanger is communicated with the input end of the gas-liquid separator.
The beneficial effects of adopting the further scheme are as follows: the method can pretreat the natural gas, improve the detection accuracy, and is suitable for detecting the content of liquid hydrocarbon in the natural gas with different pressures, different temperatures and different gases, so that the application range is wider.
Further, the pretreatment component comprises a dust filter, a water filter and a cut-off valve, one end of the sample inlet pipe is connected and communicated with one end of the cut-off valve, the other end of the cut-off valve is communicated with one end of the dust filter, and the other end of the dust filter is communicated with one end of the water filter.
Further, the pressure control part comprises a pressure reducing valve, a pressure stabilizing valve and a pressure sensor, the other end of the water filter is communicated with one end of the pressure reducing valve, the other end of the pressure reducing valve is communicated with one end of the pressure stabilizing valve, the other end of the pressure stabilizing valve is communicated with one end of the heat exchanger, the pressure sensor is located between the pressure reducing valve and the pressure stabilizing valve, and the pressure sensor is used for detecting the pressure of gas depressurized through the pressure reducing valve.
The beneficial effects of adopting the further scheme are as follows: the pressure, temperature and flow of the natural gas can be accurately controlled, and the detection accuracy of the liquid hydrocarbon content in the natural gas is improved.
Further, a bypass pipe is arranged between the cut-off valve and the dust filter and used for draining and discharging excessive natural gas, and a bypass valve used for opening or closing the bypass pipe is arranged on the bypass pipe.
The beneficial effects of adopting the further scheme are as follows: and a bypass pipe arranged between the cut-off valve and the dust filter can drain and release excessive natural gas.
Further, an electric heater is arranged between the water filter and the pressure reducing valve, and natural gas is heated by the electric heater.
The beneficial effects of adopting the further scheme are as follows: and heating the natural gas by the electric heater.
Further, the device also comprises a water bath kettle, and the gas-liquid separator and the liquid hydrocarbon content detection component are positioned in the water bath kettle.
Further, the temperature of the water bath kettle can be adjusted, and the minimum temperature is less than-30 ℃.
The beneficial effects of adopting the further scheme are as follows: is favorable for separating gas phase and liquid phase.
Further, the device also comprises a liquid hydrocarbon recovery system which is connected with and communicated with the other ends of the measuring pipes.
Further, a second valve is arranged at the other ends of the measuring pipes.
The beneficial effects of adopting the further scheme are as follows: whether the liquid hydrocarbon in the measuring tube flows into the liquid hydrocarbon recovery system or not can be controlled by the second valve. When the liquid level in the measuring tube reaches the high liquid level limit, the second valve can be slowly opened, and the liquid level in the measuring tube is reduced.
Further, the liquid hydrocarbon recovery system comprises a liquid hydrocarbon collector, a liquid discharge pipe and a liquid discharge valve, wherein the liquid hydrocarbon collector is connected and communicated with the other ends of the measuring pipes through connecting pipelines, one end of the liquid discharge pipe is connected and communicated with the liquid hydrocarbon collector, and the liquid discharge valve is arranged on the liquid discharge pipe.
The beneficial effects of adopting the further scheme are as follows: the liquid hydrocarbon collector is connected and communicated with the other ends of the measuring pipes through connecting pipelines, so that liquid hydrocarbon in the measuring pipes can flow into the liquid hydrocarbon collector, one end of the liquid discharge pipe is connected and communicated with the liquid hydrocarbon collector, the liquid discharge valve is arranged on the liquid discharge pipe, and the liquid discharge pipe can be opened or closed through the liquid discharge valve.
Further, a temperature sensor is arranged at the output end of the gas-liquid separator and used for detecting the temperature of the separated liquid phase.
On the other hand, the invention also provides a method for detecting the content of liquid hydrocarbon in natural gas, wherein the method for detecting the content of liquid hydrocarbon in natural gas comprises the following steps:
s1, filling calibration liquid into a liquid hydrocarbon content detection component, measuring differential pressure of the calibration liquid in the liquid hydrocarbon content detection component, obtaining a differential pressure signal, and calculating a functional relation between the differential pressure signal and the mass of the calibration liquid to obtain a calibration function;
s2, taking natural gas to be detected, and performing gas-liquid separation to obtain a gas phase and a liquid phase;
s3, filling the liquid phase obtained in the step S2 into a liquid hydrocarbon content detection component, measuring the differential pressure change of the liquid phase in the liquid hydrocarbon content detection component, and calculating to obtain the liquid phase quality change rate according to the calibration function obtained in the step S1;
s4, measuring the flow of the gas phase obtained in the step S2 to obtain a gas phase flow value, and calculating to obtain a standard state gas phase flow according to a gas state equation;
and S5, calculating the content of liquid hydrocarbon in the natural gas according to the liquid phase quality change rate obtained in the step S3 and the standard state gas phase flow obtained in the step S4.
Further, in S5, according to the liquid phase quality change rate obtained in step S3 and the standard state gas phase flow obtained in step S4, the liquid hydrocarbon content in the natural gas is calculated according to the following formula 1:
in formula 1), w liq The unit is mg/Nm of the mass of liquid hydrocarbon in the natural gas per standard formula 3 The method comprises the steps of carrying out a first treatment on the surface of the dm is the liquid phase mass change rate obtained in the step S3, and the unit is mg/h; q 0 For the standard state gas phase flow rate obtained in step S4, the unit is Nm 3 /h。
The method for detecting the content of the liquid hydrocarbon in the natural gas has the beneficial effects that: the method solves the problem of accurately measuring the content of different liquid hydrocarbons in the natural gas composed of different gases under different pressure and temperature conditions, and provides a scientific, accurate and integrated liquid hydrocarbon content testing method for each link of natural gas treatment and transportation.
Drawings
In order to more clearly illustrate the embodiments of the present invention or the technical solutions in the prior art, the drawings required for the description of the embodiments will be briefly described, and it is obvious that the drawings in the following description are some embodiments of the present invention, and other drawings may be obtained according to the drawings without inventive effort for a person skilled in the art.
Fig. 1 is a schematic structural diagram of a device for detecting the content of liquid hydrocarbon in natural gas according to an embodiment of the present invention.
In the drawings, the components represented by the respective reference numerals are as follows:
1. a shut-off valve; 2. a dust filter; 3. a water filter; 4. an electric heater; 5. a pressure reducing valve; 6. a pressure stabilizing valve; 7. a heat exchanger; 8. a gas-liquid separator; 9. a liquid dispenser; 10. a first valve; 11. a measuring tube; 11-1, a first measuring tube; 11-2, a second measurement tube; 11-3, a third measuring tube; 12. a second valve; 13. a liquid hydrocarbon collector; 14. a liquid discharge valve; 15. a rectifier; 16. an exhaust control valve; 17. a one-way valve; 18. calibrating a liquid metering pump; 19. calibrating the liquid inlet tube; 20. a bypass valve; 21. a pressure sensor; 22. a temperature sensor; 23. a flow sensor; 24. a sensitive differential pressure gauge; 25. a sample inlet tube; 26. an exhaust pipe; 27. a liquid discharge pipe; 28. and (5) a water bath kettle.
Detailed Description
In order to make the technical features, objects and advantageous effects of the present invention more clearly understood, the technical aspects of the present invention will now be described in detail with reference to the following specific examples, but should not be construed as limiting the scope of the present invention.
Example 1
The embodiment provides a device for detecting the content of liquid hydrocarbon in natural gas, the structure of which is shown in fig. 1, and as can be seen from fig. 1, the device comprises:
a sampling tube 25, a heat exchanger 7, a gas-liquid separator 8, a liquid hydrocarbon content detection component, a gas flow detection component, a differential pressure test component and a connecting pipeline.
The sampling pipe 25 is communicated with one end of the heat exchanger 7, and the other end of the heat exchanger 7 is communicated with the input end of the gas-liquid separator 8. The input end of the liquid hydrocarbon content detection component is communicated with the liquid outlet end of the gas-liquid separator 8. The input end of the gas flow detection component is communicated with the gas outlet end of the gas-liquid separator 8; the differential pressure test part is connected with the liquid hydrocarbon content detection part, and the differential pressure value of the liquid in the liquid hydrocarbon content detection part is measured through the differential pressure test part.
The natural gas enters the heat exchanger 7 through the sample injection pipe 25, is cooled in the heat exchanger 7, condenses out liquid phase from the natural gas, then enters the gas-liquid separator 8, separates gas phase and liquid phase in the natural gas through the gas-liquid separator 8, wherein the separated liquid phase enters the liquid hydrocarbon content detection component, the differential pressure value of the liquid phase is detected through the differential pressure detection component, the gas phase enters the gas flow detection component, and the flow of the gas phase is detected.
Wherein the heat exchanger 7 may be a tube array heat exchanger 7.
The liquid hydrocarbon content in the liquid phase is converted into a differential pressure signal, and the differential pressure signal is converted, so that the liquid hydrocarbon content can be calculated, and the accurate determination of the liquid hydrocarbon content in the natural gas is realized.
Preferably, in the present embodiment, the liquid hydrocarbon content detecting means includes a plurality of measuring pipes 11 having different pipe diameters, and one end of the plurality of measuring pipes 11 communicates with the liquid outlet end of the gas-liquid separator 8. The three measuring pipes 11 comprise a first measuring pipe 11-1, a second measuring pipe 11-2 and a third measuring pipe 11-3, wherein the pipe diameter of the first measuring pipe 11-1 is 16mm, the pipe diameter of the second measuring pipe 11-2 is 20mm, and the pipe diameter of the third measuring pipe 11-3 is 32mm. Through the measuring pipe 11 of a plurality of different pipe diameters that set up, according to the hydrocarbon content of liquid in the different natural gas, can select different pipe diameters, guarantee to use under the prerequisite of same differential pressure meter, basically realize the hydrocarbon liquid continuous test of same length of time.
Preferably, in this embodiment, a liquid dispenser 9 and a calibration liquid system are also included. The liquid phase can be injected into the different measuring tubes 11 by means of the liquid distributor 9.
Preferably, in this embodiment, the liquid distributor 9 is connected to the liquid outlet end of the gas-liquid separator 8, the liquid distributor 9 is communicated with the liquid outlet end of the gas-liquid separator 8, the liquid phase separated by the gas-liquid separator 8 can enter the liquid distributor 9, a plurality of liquid outlets corresponding to the measuring tubes 11 one by one are arranged on the liquid distributor 9, the first valves 10 are arranged on the liquid outlets, one ends of the measuring tubes are connected and communicated with the corresponding liquid outlets, and the corresponding liquid outlets can be controlled to be opened or closed by the first valves 10, so as to control whether the liquid phase enters the corresponding measuring tubes. The use is more convenient, and the selection can be carried out according to the actual situation. The measuring pipe with the corresponding pipe diameter can be selected according to the gas quality condition of the natural gas to be measured.
In this embodiment, the output ends of the calibration liquid system are respectively connected and communicated with the other ends of the plurality of measurement pipes. Wherein the calibration liquid system is capable of filling the measuring tube with calibration liquid, performing a pre-measurement calibration and back-filling the measuring tube 11 for cleaning.
Preferably, in this embodiment, the calibration liquid system includes a calibration liquid metering pump 18 and a plurality of calibration liquid inlet pipes 19, the plurality of calibration liquid inlet pipes 19 are in one-to-one correspondence with the plurality of measurement pipes 11, one end of each of the plurality of calibration liquid inlet pipes 19 is connected and communicated with the other end of the corresponding measurement pipe 11, the other end of each of the plurality of calibration liquid inlet pipes 19 is connected and communicated with the output end of the corresponding calibration liquid metering pump 18, the calibration liquid can be fed into the corresponding measurement pipe 11 through the calibration liquid metering pump 18 and the plurality of calibration liquid inlet pipes 19, the check valves 17 are arranged on the calibration liquid inlet pipes 19, and the liquid in the measurement pipes 11 can be prevented from entering the calibration liquid inlet pipes 19 through the check valves 17.
Preferably, in this embodiment, the differential pressure measuring means is a plurality of differential pressure gauges 24, wherein the differential pressure gauges 24 are also provided in plural and are in one-to-one correspondence with the measuring pipes 11, the detecting ends of the differential pressure gauges 24 are respectively connected with the two ends of the corresponding measuring pipes 11, and the differential pressure values of the input end and the output end of the corresponding measuring pipe 11 are detected by the differential pressure gauges 24, so that the differential pressure value of the liquid phase in the measuring pipe 11 is obtained.
Preferably, in this embodiment, the gas flow detecting component includes a rectifier 15, a flow sensor 23, an exhaust pipe 26 and an exhaust control valve 16, the input end of the rectifier 15 is connected and communicated with the gas outlet end of the gas-liquid separator 8 through a connecting pipeline, wherein the gas phase separated by the gas-liquid separator 8 enters the rectifier 15, is rectified and stabilized by the rectifier 15 to obtain a stable gas phase, the input end of the flow sensor 23 is communicated with the output end of the rectifier 15 through the connecting pipeline, the stable gas phase enters the flow sensor 23, the flow of the gas phase is detected by the flow sensor, one end of the exhaust pipe 26 is connected and communicated with the output end of the flow sensor 23, the exhaust control valve 16 is installed on the exhaust pipe 26, and the gas phase can be discharged to a designated combustion point through the exhaust pipe 26 for unified combustion treatment. Wherein the flow sensor 23 may be an electronic flow meter.
Preferably, in this embodiment, the device further comprises a pretreatment component and a pressure control component, one end of the sample injection pipe 25 is communicated with the input end of the pretreatment component, the output end of the pretreatment component is communicated with the input end of the pressure control component through a connecting pipeline, the output end of the pressure control component is communicated with one end of the heat exchanger 7 through a connecting pipeline, and the other end of the heat exchanger 7 is communicated with the input end of the gas-liquid separator 8 through a connecting pipeline. After the natural gas is purified by the pretreatment component, the natural gas enters the gas-liquid separator 8 for separation after the pressure is regulated, so that the method can be suitable for detecting the content of liquid hydrocarbon in the natural gas composed of different gases with different pressures, different temperatures and different gases, and the application range is wider.
Preferably, in this embodiment, the pretreatment unit includes a dust filter 2, a water filter 3, and a shut-off valve 1, one end of a sample injection pipe 25 is connected to and communicates with one end of the shut-off valve 1, the other end of the shut-off valve 1 communicates with one end of the dust filter 2 through a connection pipe, and the other end of the dust filter 2 communicates with one end of the water filter 3 through a connection pipe. The natural gas can filter solid dust through the dust filter 2, and the water carried in the natural gas can be removed through the water filter 3, so that the detection of the liquid hydrocarbon content is avoided, wherein the shutoff valve 1 can close the sampling tube 25 to stop sampling. Wherein the dust filter 2 may be a filter net and the water filter 3 may be a tank filled with a water absorbing material. The dust filter and the water filter 3 are all conventional devices.
Preferably, in this embodiment, the pressure control part includes a pressure reducing valve 5, a pressure stabilizing valve 6 and a pressure sensor 21, the other end of the water filter 3 is connected and communicated with one end of the pressure reducing valve 5 through a connecting pipe, the other end of the pressure reducing valve 5 is connected and communicated with one end of the pressure stabilizing valve 6 through a connecting pipe, the other end of the pressure stabilizing valve 6 is communicated with one end of the heat exchanger 7 through a connecting pipe, the pressure sensor 21 is located between the pressure reducing valve 5 and the pressure stabilizing valve 6, the pressure of the natural gas reduced by the pressure reducing valve 5 is detected by the pressure sensor 21, the pressure of the natural gas reduced by the pressure reducing valve 5 can be detected, and the pressure stabilizing valve 6 is used for stabilizing the pressure of the natural gas, so that the pressure of the natural gas can be conveniently regulated. The pressure, temperature and flow of the natural gas can be accurately controlled, and the detection accuracy of the liquid hydrocarbon content in the natural gas is improved.
Preferably, in this embodiment, the apparatus further comprises a water bath 28, the gas-liquid separator 8 and the liquid hydrocarbon content detecting component are located in the water bath 28, and the temperature of the water bath 28 is less than-30 ℃. Is favorable for separating gas phase and liquid phase.
Preferably, in this embodiment, the gas-liquid separator 8 is a cyclone separator, or a gas-liquid separator 8 including inner members such as a defoaming screen and a baffle plate may be used, wherein the separation efficiency of the gas-liquid separator 8 for droplets having a particle diameter of 5 μm or more may be 95% or more.
Preferably, in this embodiment, the device further comprises a liquid hydrocarbon recovery system connected to and communicating with the other end of the measuring tube 11. The other ends of the measuring pipes 11 are respectively provided with a second valve 12, and whether the liquid hydrocarbon in the measuring pipes 11 flows into the liquid hydrocarbon recovery system can be controlled by the second valves 12. When the liquid level in the measuring tube 11 reaches the high level limit, the second valve 12 can be opened slowly, lowering the liquid level in the measuring tube 11.
Preferably, in the present embodiment, the liquid hydrocarbon recovery system includes the liquid hydrocarbon collector 13, the drain pipe 27, and the drain valve 14, the liquid hydrocarbon collector 13 being connected to and communicating with the other end of the measurement pipe 11 through a connection pipe so that the liquid hydrocarbon in the measurement pipe 11 can flow into the liquid hydrocarbon collector 13, wherein one end of the drain pipe 27 is connected to and communicating with the liquid hydrocarbon collector 13, the drain valve 14 being mounted on the drain pipe 27, and the drain pipe 27 being openable or closable by the drain valve 14.
Preferably, in this embodiment, a temperature sensor 22 is provided at the output end of the gas-liquid separator 8 for detecting the temperature of the separated liquid phase.
Preferably, in the present embodiment, a bypass pipe is provided between the shut-off valve 1 and the dust filter 2, and is capable of draining and discharging excessive natural gas, and a bypass valve 20 for opening or closing the bypass pipe is provided on the bypass pipe.
Preferably, in this embodiment, an electric heater 4 is further disposed between the water filter 3 and the pressure reducing valve 5, and natural gas can be heated by the electric heater 4.
Example 2
The embodiment provides a method for detecting the content of liquid hydrocarbon in natural gas, wherein the method is realized by using the device for detecting the content of liquid hydrocarbon in natural gas provided by the embodiment 1, and the method comprises the following specific steps:
s1, taking n-undecane of a calibration liquid, filling the calibration liquid into a second measuring tube 11-2 with the tube diameter of 20mm, measuring differential pressure of the calibration liquid at two ends of the measuring tube through a sensitive differential pressure meter 24, obtaining differential pressure signals, and obtaining the functional relationship between the differential pressure signals and the mass of the calibration liquid by using least square fitting according to experimental data in the table 1, wherein the mass of the n-undecane and the differential pressure signals filled into the measuring tube and a connecting pipeline are shown in the table 1, and the calibration function is obtained as shown in the following formula 2):
m cali =0.043·Δp+0.596 equation 2);
in formula 2), m cali The mass of n-undecane is expressed in g, the delta p is the differential pressure, and the unit is Pa.
The calibration liquid is fed through the calibration liquid metering pump 18 to the measuring tube and the gas-liquid separator and other equipment, and the whole device is back-blown and cleaned.
TABLE 1
S2, injecting natural gas to be detected into a sample injection pipe 25, opening a cut-off valve 1, enabling the natural gas to flow into a dust filter 2, filtering solid dust through the dust filter 2, flowing into a water filter 3, absorbing and filtering water in the natural gas, heating the natural gas by an electric heater 4, then enabling the natural gas to enter a pressure reducing valve 5, reducing pressure by the pressure reducing valve 5, then enabling the natural gas to enter a heat exchanger 7 after being subjected to pressure regulation by a pressure stabilizing valve 6 to reach target pressure, cooling and condensing in the heat exchanger 7, and then entering a gas-liquid separator 8, and separating gas from liquid to obtain gas phase and liquid phase.
The composition of the natural gas to be detected in the step S2 is shown in the following table 2, the target pressure is 3MPa, and the condensation separation temperature is-11.1 ℃.
TABLE 2
| Sequence number | Component (A) | Mole percent content |
| 1 | Nitrogen gas | 2.0681 |
| 2 | Carbon dioxide | 2.0041 |
| 3 | Methane | 90.3295 |
| 4 | Ethane (ethane) | 3.079 |
| 5 | Propane | 1.0257 |
| 6 | Isobutane | 0.4963 |
| 7 | N-butane | 0.4988 |
| 8 | Isopentane | 0.1999 |
| 9 | N-pentane | 0.2001 |
| 10 | N-hexane | 0.0985 |
And S3, distributing the liquid phase obtained in the step S2 into a plurality of measuring pipes through the liquid distributor 9, moving the liquid phase in the measuring pipes, gradually increasing the readings of the sensitive differential pressure meter 24 along with the time, measuring the differential pressure of the liquid phase at the two ends of the measuring pipes after the differential pressure change readings of the sensitive differential pressure meter 24 are stable, and calculating the mass change rate dm of the liquid phase according to the calibration function obtained in the step S1. Wherein the measured liquid hydrocarbon enters the liquid hydrocarbon collector 13 and is uniformly discharged through the liquid discharge pipe 27.
In step S3, the second measuring tube 11-2 having a tube diameter of 20mm is taken as an example, and the differential pressure of the second measuring tube and the mass of the liquid phase calculated according to the calibration function shown in the above formula 2) are given as shown in the following table 3.
TABLE 3 Table 3
| Duration/h of test | Differential pressure value/Pa | Calculated mass/g |
| 0 | 0.15 | 0.602 |
| 1 | 0.18 | 0.604 |
| 2 | 3.89 | 0.763 |
| 3 | 20.03 | 1.457 |
| 4 | 36.36 | 2.159 |
| 5 | 55.98 | 3.003 |
| 6 | 70.36 | 3.622 |
| 7 | 88.46 | 4.400 |
| 8 | 104.27 | 5.080 |
| 9 | 119.62 | 5.740 |
| 10 | 134.20 | 6.367 |
| 11 | 157.52 | 7.369 |
| 12 | 174.55 | 8.101 |
| 13 | 192.64 | 8.880 |
| 14 | 209.24 | 9.593 |
| 15 | 218.81 | 10.005 |
| 16 | 234.42 | 10.676 |
Wherein, for 0-2 hours, the system is in a debugging state, the working condition is unstable, and meanwhile, the differential pressure value does not change linearly along with time due to the influence of a liquid storage dead zone of the system; from 3 to 16 hours, each parameter of the system runs stably, the differential pressure value changes linearly along with time, the liquid phase quality data after 3 to 16 hours are fitted with the test duration data, and the liquid phase quality change rate can be obtained, and the obtained liquid phase quality change rate dm is 733mg/h.
S4, the gas phase obtained in the step S2 enters a rectifier 15, is rectified by the rectifier 15, enters a flow sensor 23, measures the flow of the gas phase to obtain a gas phase flow value q, uniformly discharges the gas phase through an exhaust pipe 26, and calculates the gas phase flow q in a standard state according to a gas state equation 0 2.08Nm 3 And/h. Wherein the standard state gas phase flow rate q 0 Refers to the standard (1 atm,20 ℃) flow of gas under steady conditions for the same period of time.
S5, calculating the content W of liquid hydrocarbon in the natural gas according to the liquid phase mass change rate obtained in the step S3 and the standard state gas phase flow obtained in the step S4 by adopting the following formula 1) liq The liquid hydrocarbon content W in the natural gas to be detected calculated in the step S5 liq 352.4mg/Nm 3 。
In formula 1), w liq The unit is mg/Nm of the mass of liquid hydrocarbon in the natural gas per standard formula 3 The method comprises the steps of carrying out a first treatment on the surface of the dm is the liquid phase mass change rate obtained in the step S3, and the unit is mg/h; q 0 For the standard state gas phase flow rate obtained in step S4, the unit is Nm 3 /h。
In summary, according to the method for detecting the liquid hydrocarbon content in the natural gas provided by the embodiment of the invention, the liquid hydrocarbon content in the liquid phase is converted into the differential pressure signal, and the differential pressure signal is converted, so that the liquid hydrocarbon content can be calculated, and the accurate determination of the liquid hydrocarbon content in the natural gas is realized. The method solves the problem of accurately measuring the content of different liquid hydrocarbons in natural gas compositions under different pressure and temperature conditions, and provides a scientific, accurate and integrated liquid hydrocarbon content testing method for each link of natural gas treatment and transportation.
It should be noted that the term "comprising" in the description of the invention and the claims and any variations thereof in the above-described figures is intended to cover a non-exclusive inclusion, such as a process, method, system, article, or apparatus that comprises a list of steps or elements is not necessarily limited to those steps or elements that are expressly listed or inherent to such process, method, article, or apparatus.
In the present invention, it should be understood that the terms "center", "longitudinal", "lateral", "upper", "lower", "front", "rear", "left", "right", "vertical", "horizontal", "top", "bottom", "inner", "outer", etc. refer to an orientation or a positional relationship based on the orientation or positional relationship shown in the drawings, and these terms are mainly used for convenience in describing the present invention and simplifying the description, and do not indicate or imply that the apparatus or elements referred to must have a specific orientation, be configured and operated in a specific orientation, and thus should not be construed as limiting the present invention. Also, some of the terms described above may be used to indicate other meanings in addition to orientation or positional relationships, for example, the term "upper" may also be used to indicate some sort of attachment or connection in some cases. The specific meaning of these terms in the present invention will be understood by those of ordinary skill in the art according to the specific circumstances.
Furthermore, the terms "first," "second," and the like, are used for descriptive purposes only and are not to be construed as indicating or implying a relative importance or implicitly indicating the number of technical features indicated. Thus, a feature defining "a first", "a second", etc. may explicitly or implicitly include one or more such feature. In the description of the invention, unless otherwise indicated, the meaning of "a plurality" is two or more.
Furthermore, the terms "disposed," "mounted," "connected," and the like are to be construed broadly. For example, "connected" may be in a fixed connection, a removable connection, or a unitary construction; may be a mechanical connection, or an electrical connection; may be directly connected, or indirectly connected through intervening media, or may be in internal communication between two devices, elements, or components. The specific meaning of the above terms in the present invention can be understood by those of ordinary skill in the art according to the specific circumstances.
The foregoing description of the embodiments of the invention is not intended to limit the scope of the invention, so that the substitution of equivalent elements or equivalent variations and modifications within the scope of the invention shall fall within the scope of the patent. In addition, the technical features and the technical features, the technical features and the technical invention can be freely combined for use.
Claims (13)
1. A device for detecting the content of liquid hydrocarbon in natural gas, wherein the device for detecting the content of liquid hydrocarbon in natural gas comprises:
a sample inlet tube (25);
the sample injection pipe (25) is communicated with one end of the heat exchanger (7);
the other end of the heat exchanger (7) is communicated with the input end of the gas-liquid separator (8);
the input end of the liquid hydrocarbon content detection component is communicated with the liquid outlet end of the gas-liquid separator (8);
the input end of the gas flow detection component is communicated with the gas outlet end of the gas-liquid separator (8);
the differential pressure testing component is connected to the liquid hydrocarbon content detecting component and is used for testing the differential pressure value of the liquid in the liquid hydrocarbon content detecting component;
the liquid hydrocarbon content detection component comprises a plurality of measuring pipes (11) with different pipe diameters, and one ends of the measuring pipes (11) are communicated with the liquid outlet end of the gas-liquid separator (8);
the liquid hydrocarbon content detection component further includes: a liquid dispenser (9) and a calibration liquid system;
the liquid distributor (9) is connected to the liquid outlet end of the gas-liquid separator (8), a plurality of liquid outlets which are in one-to-one correspondence with the measuring pipes (11) are arranged on the liquid distributor (9), a first valve (10) is arranged on the liquid outlets, and one ends of the measuring pipes (11) are connected and communicated with the corresponding liquid outlets;
the output ends of the calibration liquid system are respectively connected and communicated with the other ends of the measuring pipes (11);
the calibration liquid system comprises a calibration liquid metering pump (18) and a calibration liquid inlet pipe (19), the calibration liquid inlet pipe (19) corresponds to the measurement pipes (11) one by one, the calibration liquid inlet pipe (19) is respectively connected and communicated with the other ends of the corresponding measurement pipes (11) after being split, the other ends of the split pipes of the calibration liquid inlet pipe (19) are connected and communicated with the output ends of the calibration liquid metering pump (18), and the split pipes of the calibration liquid inlet pipe (19) are respectively provided with one-way valves (17);
the gas flow detection component comprises a rectifier (15), a flow sensor (23), an exhaust pipe (26) and an exhaust control valve (16), wherein the input end of the rectifier (15) is communicated with the air outlet end of the gas-liquid separator (8), the input end of the flow sensor (23) is communicated with the output end of the rectifier (15), one end of the exhaust pipe (26) is connected and communicated with the output end of the flow sensor (23), and the exhaust control valve (16) is arranged on the exhaust pipe (26);
the differential pressure test component is a sensitive differential pressure meter (24), the detection ends of the sensitive differential pressure meter (24) are respectively connected with the two ends of the liquid hydrocarbon content detection component, and the differential pressure value of the input end and the output end of the liquid hydrocarbon content detection component is detected by the sensitive differential pressure meter (24).
2. The device for detecting the content of liquid hydrocarbon in natural gas according to claim 1, wherein the device further comprises a pretreatment component and a pressure control component, one end of the sample injection pipe (25) is communicated with the input end of the pretreatment component, the output end of the pretreatment component is communicated with the input end of the pressure control component, the output end of the pressure control component is communicated with one end of the heat exchanger (7), and the other end of the heat exchanger (7) is communicated with the input end of the gas-liquid separator (8).
3. The device for detecting the content of liquid hydrocarbon in natural gas according to claim 2, wherein the pretreatment component comprises a dust filter (2), a water filter (3) and a cut-off valve (1), one end of the sample injection pipe (25) is connected and communicated with one end of the cut-off valve (1), the other end of the cut-off valve (1) is communicated with one end of the dust filter (2), and the other end of the dust filter (2) is communicated with one end of the water filter (3).
4. A device for detecting a liquid hydrocarbon content in natural gas according to claim 3, wherein the pressure control means comprises a pressure reducing valve (5), a pressure stabilizing valve (6) and a pressure sensor (21), the other end of the water filter (3) is communicated with one end of the pressure reducing valve (5), the other end of the pressure reducing valve (5) is communicated with one end of the pressure stabilizing valve (6), the other end of the pressure stabilizing valve (6) is communicated with one end of the heat exchanger (7), and the pressure sensor (21) is located between the pressure reducing valve (5) and the pressure stabilizing valve (6), and the pressure of the gas depressurized by the pressure reducing valve (5) is detected by the pressure sensor (21).
5. The device for detecting the content of liquid hydrocarbon in natural gas according to claim 3 or 4, wherein a bypass pipe is arranged between the shut-off valve (1) and the dust filter (2) and is used for draining and discharging excessive natural gas, and a bypass valve (20) for opening or closing the bypass pipe is arranged on the bypass pipe.
6. The device for detecting the content of liquid hydrocarbon in natural gas according to claim 3 or 4, wherein an electric heater (4) is further arranged between the water filter (3) and the pressure reducing valve (5), and the natural gas is heated by the electric heater (4).
7. The device for detecting the liquid hydrocarbon content in natural gas according to claim 1, wherein the device further comprises a water bath (28), and the gas-liquid separator (8) and the liquid hydrocarbon content detection component are located in the water bath (28).
8. The device for detecting the content of liquid hydrocarbons in natural gas according to claim 7, wherein the temperature of the water bath (28) is adjustable, and the minimum temperature is less than-30 ℃.
9. The device for detecting the liquid hydrocarbon content in natural gas according to claim 1, wherein the device further comprises a liquid hydrocarbon recovery system connected to and communicating with the other ends of the plurality of measuring pipes (11).
10. The device according to claim 9, wherein a second valve (12) is provided at the other end of each of the measuring tubes (11).
11. The device for detecting the content of liquid hydrocarbon in natural gas according to claim 9 or 10, wherein the liquid hydrocarbon recovery system comprises a liquid hydrocarbon collector (13), a liquid discharge pipe (27) and a liquid discharge valve (14), the liquid hydrocarbon collector (13) is connected and communicated with the other ends of the plurality of measuring pipes (11) through connecting pipelines, one end of the liquid discharge pipe (27) is connected and communicated with the liquid hydrocarbon collector (13), and the liquid discharge valve (14) is mounted on the liquid discharge pipe (27).
12. The device for detecting the content of liquid hydrocarbons in natural gas according to claim 1, wherein the output end of the gas-liquid separator (8) is provided with a temperature sensor (22) for detecting the temperature of the separated liquid phase.
13. A method for detecting the content of liquid hydrocarbon in natural gas, wherein the method for detecting the content of liquid hydrocarbon in natural gas is realized by using the device for detecting the content of liquid hydrocarbon in natural gas according to any one of claims 1 to 12, and the method comprises the following steps:
s1, filling calibration liquid into a liquid hydrocarbon content detection component, measuring differential pressure of the calibration liquid in the liquid hydrocarbon content detection component, obtaining a differential pressure signal, and calculating a functional relation between the differential pressure signal and the mass of the calibration liquid to obtain a calibration function;
s2, taking natural gas to be detected, and performing gas-liquid separation to obtain a gas phase and a liquid phase;
s3, filling the liquid phase obtained in the step S2 into a liquid hydrocarbon content detection component, measuring the differential pressure change of the liquid phase in the liquid hydrocarbon content detection component, and calculating to obtain the liquid phase quality change rate according to the calibration function obtained in the step S1;
s4, measuring the flow of the gas phase obtained in the step S2 to obtain a gas phase flow value, and calculating to obtain a standard state gas phase flow according to a gas state equation;
s5, calculating the content of liquid hydrocarbon in the natural gas according to the liquid phase quality change rate obtained in the step S3 and the standard state gas phase flow obtained in the step S4;
in S5, according to the liquid phase quality change rate obtained in the step S3 and the standard state gas phase flow obtained in the step S4, the liquid hydrocarbon content in the natural gas is calculated according to the following formula 1:
equation 1);
in the formula 1) of the present invention,w liq the unit is mg/Nm of the mass of liquid hydrocarbon in the natural gas per standard formula 3 ；dmThe unit of the liquid phase mass change rate obtained in the step S3 is mg/h;q 0 for the standard state gas phase flow rate obtained in step S4, the unit is Nm 3 /h。
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| CN202748069U (en) * | 2012-07-24 | 2013-02-20 | 兰州海默科技股份有限公司 | Moisture flow measuring device |
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