CN114544906A - 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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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 inlet 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 part is connected to the liquid hydrocarbon content detecting part, and the differential pressure value of the liquid in the liquid hydrocarbon content detecting part is tested through the differential pressure testing part. 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 natural gas industry in China is rapidly developed, and in 2018, the natural gas consumption in China reaches 2810 hundred million m3The throughput was 1610 hundred million m3The inlet amount is 1200 hundred million m3。
The natural gas contains methane as main component and small amount of ethane, propane, butane, pentane and hexane (C)6 +) A hydrocarbon gas, further comprising CO2、N2、H2S、O2、H2And a trace amount of a non-hydrocarbon gas such as an inert gas (e.g., He or Ar). When the heavy hydrocarbon component in the natural gas is higher, the heavy hydrocarbon component is generally called as condensed natural gas, liquid can be condensed out from a mixture in the natural gas in an isothermal depressurization process, and the phase state characteristic different from that of pure gas brings huge challenges to the links of natural gas exploitation, processing and transportation.
Gas reservoirs of condensed natural gas are widely distributed in regions of Xinjiang, Shaanxi, inner Mongolia, Sichuan and the like in China, and gas sources of the first east line and the second east line of the western gas for conveying the main artery natural gas 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 obtained, 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.
The condensed natural gas is possibly at a higher temperature in a gas reservoir, and the temperature is lower than the normal temperature (25 ℃) in the links of processing and pipeline transportation, so that the content of liquid hydrocarbon in the natural gas with different temperature, pressure conditions and different gas compositions can be accurately measured, scientific and comprehensive basic data can be provided for the design and operation of natural gas processing devices and the dew point control of the hydrocarbon for transporting the natural gas, and the problems of the operation of various processing devices and the inefficient operation of gas pipelines caused by the condensation of the liquid hydrocarbon can be avoided.
However, natural gas of different temperature, pressure conditions, and different gas compositionsThe natural gas with different gas qualities has large difference of medium liquid hydrocarbon content, the hydrocarbon content can be distributed at 5mg/Nm under the conditions of 4MPa and 0 ℃ in the natural gas with different gas qualities and gas state at normal temperature (25℃)3To 15g/Nm3And the range is even wider, so the measuring device needs to have higher testing sensitivity and stronger natural gas quality adaptability.
Chinese patent CN 103076404 discloses a method for detecting total liquid hydrocarbons in natural gas by analyzing the composition of natural gas by subtracting C from 100%1-C4The method for weighting the content obtains the content of the liquid hydrocarbon composition in the natural gas, the analysis is rapid, however, the method is rough, the obtained calculated value does not change along with the pressure and the temperature, and the calculated value is not consistent with the real situation, and the actual production is often difficult to guide.
In addition, the natural gas composition analysis result is generally used as an input value in the industry, the state equation is adopted to predict the liquid hydrocarbon content in the natural gas, and further the design and operation of the natural gas processing device are guided.
Therefore, there is a need in the art for a method and apparatus that can achieve accurate determination of the liquid hydrocarbon content in natural gas to solve the above-mentioned problems.
Disclosure of Invention
To solve the above drawbacks and disadvantages, an object of the present invention is to provide a device for detecting the content of liquid hydrocarbons in natural gas.
The invention also aims to provide a method for detecting the content of the liquid hydrocarbon in the 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 an apparatus for detecting a content of liquid hydrocarbons in natural gas, wherein the apparatus for detecting a content of liquid hydrocarbons in natural gas comprises:
a sample inlet pipe;
the sample inlet 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 part is connected to the liquid hydrocarbon content detecting part, and the differential pressure value of the liquid in the liquid hydrocarbon content detecting part is tested through the differential pressure testing part.
The invention has the beneficial effects that: (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 content of the liquid hydrocarbon can be calculated, and the content of the liquid hydrocarbon in the natural gas can be accurately measured;
(2) the detection device can be used for conveniently and rapidly detecting the content of the liquid hydrocarbon in the natural gas, has high detection accuracy and is beneficial to actual production operation.
On the basis of the technical scheme, the invention can be further improved as follows.
Further, the liquid hydrocarbon content detection part comprises a plurality of measuring tubes with different tube diameters, and one end of each measuring tube is communicated with the liquid outlet end of the gas-liquid separator.
The beneficial effect of adopting the further scheme is that: according to the content of liquid hydrocarbon in different natural gases, different pipe diameters can be selected, and the continuous test of the hydrocarbon liquid in the same time length is basically realized on the premise of ensuring the use of the same differential pressure gauge.
Further, the liquid hydrocarbon content detection section 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 tubes are formed in the liquid distributor, first valves are arranged on the liquid outlets, and one ends of the measuring tubes are connected and communicated with the corresponding liquid outlets;
and the output end of the calibration liquid system is respectively connected and communicated with the other ends of the measuring tubes.
The beneficial effect of adopting the above further scheme is: the introduction of the separated liquid phase into the measuring tube is facilitated, wherein the calibration liquid system can fill the measuring tube with a calibration liquid, which calibrates the differential pressure gauge beforehand.
Further, calibration liquid system includes calibration liquid measuring pump and calibration liquid admission pipe, calibration liquid admission pipe with survey buret one-to-one, behind the reposition of redundant personnel of calibration liquid admission pipe respectively with correspond survey the other end of buret and connect and communicate, the shunt tubes other end of calibration liquid admission pipe with the output of calibration liquid measuring pump is connected and is communicated, all be equipped with the check valve on the calibration liquid admission pipe shunt tubes.
The beneficial effect of adopting the further scheme is that: through calibration liquid metering pump and many in the calibration liquid admission pipe can conveniently send calibration liquid into corresponding measuring tube, the volume of the calibration liquid that can control the input simultaneously.
Further, the differential pressure test part is a sensitive differential pressure gauge, the detection end of the sensitive differential pressure gauge is 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 through the sensitive differential pressure gauge.
The beneficial effect of adopting the further scheme is that: the differential pressure values of the input end and the output end of the measuring pipe can be detected correspondingly, so that the differential pressure value of the liquid phase in the measuring pipe can be obtained.
Further, the gas flow detection component comprises a rectifier, a flow sensor, an exhaust pipe and an exhaust control valve, the input end of the rectifier is communicated with the gas 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 effect of adopting the further scheme is that: the flow of the gas phase is detected conveniently.
Further, the device still includes pretreatment component and pressure control part, the one end of advance appearance pipe with pretreatment component's input intercommunication, pretreatment component's output with pressure control part's input intercommunication, pressure control part's output with the one end intercommunication of heat exchanger, the other end of heat exchanger with gas-liquid separator's input intercommunication.
The beneficial effect of adopting the further scheme is that: the natural gas pretreatment device can be used for pretreating natural gas, improves the detection accuracy, and is suitable for detecting the content of liquid hydrocarbon in natural gas composed of different pressures, different temperatures and different gas qualities, so that the application range is wider.
Further, pretreatment component includes dust filter, water filter and cut-off valve, the one end of advance appearance pipe with the one end of cut-off valve is connected and is communicate, the other end of cut-off valve with dust filter's one end intercommunication, dust filter's the other end with water filter's one end intercommunication.
The pressure control component 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 detects the gas pressure reduced by the pressure reducing valve.
The beneficial effect of adopting the further scheme is that: the pressure, the temperature and the flow of the natural gas can be accurately controlled, and the detection accuracy of the content of the liquid hydrocarbon in the natural gas is improved.
Furthermore, a bypass pipe is arranged between the block valve and the dust filter and used for draining and discharging excessive natural gas, wherein a bypass valve used for opening or closing the bypass pipe is arranged on the bypass pipe.
The beneficial effect of adopting the further scheme is that: 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 the natural gas is heated by the electric heater.
The beneficial effect of adopting the further scheme is that: heating natural gas by the electric heater.
Further, the device also comprises a water bath, and the gas-liquid separator and the liquid hydrocarbon content detection part are positioned in the water bath.
Further, the temperature of the water bath kettle can be adjusted, and the lowest temperature is less than minus 30 ℃.
The beneficial effect of adopting the above further scheme is: the separation of gas phase and liquid phase is facilitated.
Further, the device also comprises a liquid hydrocarbon recovery system, and the liquid hydrocarbon recovery system is connected and communicated with the other ends of the measuring pipes.
Further, a plurality of second valves are arranged at the other ends of the measuring pipes.
The beneficial effect of adopting the further scheme is that: whether the liquid hydrocarbon in the measuring pipe flows into the liquid hydrocarbon recovery system or not can be controlled through the second valve. When the liquid level in the measuring tube reaches the high liquid level limit, the second valve can be opened slowly to reduce the liquid level height in the measuring tube.
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 installed on the liquid discharge pipe.
The beneficial effect of adopting the further scheme is that: the liquid hydrocarbon collector is connected and communicated with the other ends of the plurality of measuring pipes through connecting pipelines, so that the liquid hydrocarbon in the measuring pipes can flow into the liquid hydrocarbon collector, wherein one end of the liquid discharge pipe is connected and communicated with the liquid hydrocarbon collector, and a liquid discharge valve is installed on the liquid discharge pipe, and the liquid discharge pipe can be opened or closed through the liquid discharge valve.
Further, the output end of the gas-liquid separator is provided with a temperature sensor for detecting the temperature of the separated liquid phase.
In another aspect, the invention further provides a method for detecting the content of liquid hydrocarbons in natural gas, where the method for detecting the content of liquid hydrocarbons in natural gas includes:
s1, filling the calibration liquid into the liquid hydrocarbon content detection part, measuring the differential pressure of the calibration liquid in the liquid hydrocarbon content detection part to obtain a differential pressure signal, and calculating the functional relation between the differential pressure signal and the quality of the calibration liquid to obtain a calibration function;
s2, taking the 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 part, measuring the differential pressure change of the liquid phase in the liquid hydrocarbon content detection part, and calculating to obtain the liquid phase mass 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 the gas phase flow in a standard state according to a gas state equation;
and S5, calculating the content of the 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 rate obtained in the step S4.
Further, in S5, the liquid hydrocarbon content in the natural gas is calculated according to the following formula 1) based on the liquid phase mass change rate obtained in step S3 and the standard state gas phase flow rate obtained in step S4:
in formula 1), wliqThe mass of liquid hydrocarbon in each standard square of natural gas is in mg/Nm3(ii) a dm is the liquid phase mass change rate obtained in the step S3, and the unit is mg/h; q. q.s0The standard state gas phase flow rate obtained in step S4 is in Nm3/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 with different gas compositions under different pressure and temperature conditions, and provides a scientific, accurate and integrated liquid hydrocarbon content measuring 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 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 some embodiments of the present invention, and it is obvious for those skilled in the art that other drawings can be obtained according to the drawings without creative efforts.
Fig. 1 is a schematic structural diagram of a device for detecting the content of liquid hydrocarbons in natural gas according to an embodiment of the present invention.
In the drawings, the reference numerals denote the following components:
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 maintaining valve; 7. a heat exchanger; 8. a gas-liquid separator; 9. a liquid dispenser; 10. a first valve; 11. a measurement tube; 11-1, a first measurement tube; 11-2, a second measurement tube; 11-3, a third measurement tube; 12. a second valve; 13. a liquid hydrocarbon collector; 14. a drain valve; 15. a rectifier; 16. an exhaust control valve; 17. a one-way valve; 18. calibrating the liquid metering pump; 19. a calibration 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 pipe; 26. an exhaust pipe; 27. a liquid discharge pipe; 28. a water bath kettle.
Detailed Description
In order to clearly understand the technical features, objects and advantages of the present invention, the following detailed description of the technical solutions of the present invention will be made with reference to the following specific examples, which should not be construed as limiting the implementable scope of the present invention.
Example 1
The embodiment provides a device for detecting the content of liquid hydrocarbons in natural gas, the structural schematic diagram of which is shown in fig. 1, and as can be seen from fig. 1, the device comprises:
the device comprises a sample inlet pipe 25, a heat exchanger 7, a gas-liquid separator 8, a liquid hydrocarbon content detection part, a gas flow detection part, a differential pressure test part and a connecting pipeline.
The sample inlet 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 part is communicated with the liquid outlet end of the gas-liquid separator 8. The input end of the gas flow detection part is communicated with the gas outlet end of the gas-liquid separator 8; the differential pressure testing part is connected to the liquid hydrocarbon content detecting part, and the differential pressure value of the liquid in the liquid hydrocarbon content detecting part is measured through the differential pressure testing part.
The natural gas enters the heat exchanger 7 through the sample inlet pipe 25, is cooled in the heat exchanger 7, is condensed to form a liquid phase from the natural gas, then enters the gas-liquid separator 8, and is separated from a gas 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 test component, and the gas phase enters the gas flow detection component to detect the flow of the gas phase.
Wherein the heat exchanger 7 can be a shell and tube heat exchanger 7.
The content of the liquid hydrocarbon in the liquid phase is converted into a differential pressure signal, and then the differential pressure signal is converted, so that the content of the liquid hydrocarbon can be calculated, and the content of the liquid hydrocarbon in the natural gas can be accurately measured.
Preferably, in the present embodiment, the liquid hydrocarbon content detecting member includes a plurality of measuring pipes 11 of different pipe diameters, and one ends of the plurality of measuring pipes 11 communicate with the liquid outlet end of the gas-liquid separator 8. The three measuring tubes 11 comprise a first measuring tube 11-1, a second measuring tube 11-2 and a third measuring tube 11-3, wherein the tube diameter of the first measuring tube 11-1 is 16mm, the tube diameter of the second measuring tube 11-2 is 20mm, and the tube diameter of the third measuring tube 11-3 is 32 mm. Through the measuring tubes 11 with different tube diameters, different tube diameters can be selected according to the content of liquid hydrocarbon in different natural gases, and continuous testing of the hydrocarbon liquid with the same time length is basically realized on the premise of ensuring the use of the same differential pressure gauge.
Preferably, in this embodiment, a liquid distributor 9 and a calibration liquid system are further included. The liquid phase can be injected into the different measuring tubes 11 by means of the liquid distributor 9.
Wherein, preferably, in this embodiment, liquid distributor 9 is connected on the play liquid end of vapour and liquid separator 8, liquid distributor 9 and vapour and liquid separator 8's play liquid end intercommunication, the liquid phase through vapour and liquid separator 8 separation can enter into liquid distributor 9, be equipped with a plurality of and a plurality of liquid outlets of surveying buret 11 one-to-one on liquid distributor 9, be equipped with first valve 10 on a plurality of liquid outlets, the one end of a plurality of survey burets is connected and is linked together with corresponding liquid outlet, can control the liquid outlet that corresponds through first valve 10 and open or close, thereby whether control liquid phase enters into corresponding survey buret. The use is more convenient, and the selection can be carried out according to the actual situation. The measuring tube with the corresponding tube 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 connected to and communicate with the other ends of the plurality of measuring tubes, respectively. Wherein the calibration liquid system is capable of filling the measurement tube with calibration liquid, performing a pre-measurement calibration and back-filling for cleaning the measurement tube 11.
Preferably, in this embodiment, the calibration liquid system includes calibration liquid metering pump 18 and many root system calibration liquid admission pipes 19, many root system calibration liquid admission pipes 19 and a plurality of survey buret 11 one-to-one, many root system calibration liquid admission pipes 19's one end is connected and is communicate with the other end of surveying buret 11 that corresponds respectively, many root system calibration liquid admission pipes 19's the other end is connected and is communicated with the output of calibration liquid metering pump 18, can send calibration liquid into corresponding survey buret 11 in through calibration liquid metering pump 18 and many root system calibration liquid admission pipes 19, all be equipped with check valve 17 on the calibration liquid admission pipe 19, can avoid the liquid in surveying buret 11 to enter into in the calibration liquid admission pipe 19 through check valve 17.
Preferably, in this embodiment, the differential pressure measuring component is a plurality of sensitive differential pressure meters 24, wherein the plurality of sensitive differential pressure meters 24 are also provided and correspond to the measuring tubes 11 one by one, the detecting ends of the sensitive differential pressure meters 24 are respectively connected with the two ends of the corresponding measuring tubes 11, and the differential pressure values of the input end and the output end of the corresponding measuring tubes 11 are detected by the sensitive differential pressure meters 24, so as to obtain the differential pressure value of the liquid phase in the measuring tubes 11.
Preferably, in this embodiment, the gas flow rate detecting component includes a rectifier 15, a flow sensor 23, an exhaust pipe 26 and an exhaust control valve 16, an input end of the rectifier 15 is connected and communicated with an outlet end of the gas-liquid separator 8 through a connecting pipeline, wherein a gas phase separated by the gas-liquid separator 8 enters the rectifier 15 and is rectified and stabilized by the rectifier 15 to obtain a stabilized gas phase, an input end of the flow sensor 23 is communicated with an output end of the rectifier 15 through a connecting pipeline, the stabilized gas phase enters the flow sensor 23 and detects a gas phase flow rate through the flow sensor, one end of the exhaust pipe 26 is connected and communicated with an output end of the flow sensor 23, and the exhaust control valve 16 is installed on the exhaust pipe 26, and the gas phase can be discharged to a specified combustion point through the exhaust pipe 26 to perform a unified combustion process. 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, wherein one end of the sample inlet pipe 25 is communicated with an input end of the pretreatment component, an output end of the pretreatment component is communicated with an input end of the pressure control component through a connecting pipeline, an 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 an 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 adjusted, so that the method is suitable for detecting the content of the liquid hydrocarbon in the natural gas composed of different pressures, different temperatures and different gas qualities, and the application range is wider.
Preferably, in the present embodiment, the pretreatment unit includes a dust filter 2, a water filter 3, and a cut-off valve 1, one end of the sample inlet pipe 25 is connected to and communicates with one end of the cut-off valve 1, the other end of the cut-off valve 1 communicates with one end of the dust filter 2 through a connection line, and the other end of the dust filter 2 communicates with one end of the water filter 3 through a connection line. The natural gas can filter solid-state dust through dust filter 2, can get rid of the moisture that carries in the natural gas through water filter 3, avoids influencing the detection of liquid hydrocarbon content, and wherein sample injection pipe 25 can be closed to shut-off valve 1, stops to advance the appearance. Wherein the dust filter 2 can be a filter screen, and the water filter 3 can be a tank filled with water absorbing material. Both the dust filter and the water filter 3 are conventional devices.
Preferably, in this embodiment, the pressure control component includes a pressure reducing valve 5, a pressure maintaining 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 pipeline, the other end of the pressure reducing valve 5 is connected and communicated with one end of the pressure maintaining valve 6 through a connecting pipeline, the other end of the pressure maintaining valve 6 is communicated with one end of the heat exchanger 7 through a connecting pipeline, the pressure sensor 21 is located between the pressure reducing valve 5 and the pressure maintaining valve 6, the pressure sensor 21 detects the pressure of the gas decompressed by the pressure reducing valve 5, the pressure of the natural gas decompressed by the pressure reducing valve 5 can be detected, and the pressure maintaining valve 6 is used for stabilizing the pressure of the natural gas, so that the pressure of the natural gas can be conveniently adjusted. The pressure, the temperature and the flow of the natural gas can be accurately controlled, and the detection accuracy of the content of the liquid hydrocarbon 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 ℃. The separation of gas phase and liquid phase is facilitated.
Preferably, in the present embodiment, the gas-liquid separator 8 is a cyclone separator, or a gas-liquid separator 8 including an internal member such as a defoaming screen and a baffle plate may be used, wherein the separation efficiency of the gas-liquid separator 8 for liquid droplets having a particle size of 5 μm or more is 95% or more.
Preferably, in this embodiment, the apparatus further comprises a liquid hydrocarbon recovery system connected to and in communication with the other end of the measurement pipe 11. Wherein the other ends of the plurality of measuring pipes 11 are provided with second valves 12, and whether the liquid hydrocarbon in the measuring pipes 11 flows into the liquid hydrocarbon recovery system or not can be controlled through the second valves 12. When the level of the liquid in the measuring tube 11 reaches a high level limit, the second valve 12 can be opened slowly, lowering the level of the liquid in the measuring tube 11.
Preferably, in the present embodiment, the liquid hydrocarbon recovery system includes a liquid hydrocarbon collector 13, a liquid discharge pipe 27, and a liquid discharge 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 liquid discharge pipe 27 is connected to and communicating with the liquid hydrocarbon collector 13, the liquid discharge valve 14 being mounted on the liquid discharge pipe 27, and the liquid discharge pipe 27 can be opened or closed by the liquid discharge valve 14.
Preferably, in this embodiment, a temperature sensor 22 is disposed on the output end of the gas-liquid separator 8 for detecting the temperature of the separated liquid phase.
Preferably, in the embodiment, a bypass pipe is arranged between the cut-off valve 1 and the dust filter 2, and the excess natural gas can be drained and discharged, wherein a bypass valve 20 for opening or closing the bypass pipe is arranged on the bypass pipe.
Preferably, in the present embodiment, an electric heater 4 is further disposed between the water filter 3 and the pressure reducing valve 5, and the natural gas can be heated by the electric heater 4.
Example 2
The embodiment provides a method for detecting the content of liquid hydrocarbons in natural gas, wherein the method is implemented by using the device for detecting the content of liquid hydrocarbons in natural gas provided in embodiment 1, and the method includes the following specific steps:
s1, taking n-undecane as a calibration liquid, filling the n-undecane into a second measuring tube 11-2 with the tube diameter of 20mm, measuring the differential pressure of the calibration liquid at two ends of the measuring tube through a sensitive differential pressure gauge 24 to obtain a differential pressure signal, wherein the mass of the n-undecane filled into the measuring tube and a connecting pipeline and the data of the differential pressure signal are shown in the following table 1, and a function relation between the differential pressure signal and the mass of the calibration liquid is obtained by fitting according to the experimental data in the table 1 by using a least square method to obtain a calibration function, which is shown in the following formula 2):
mcali0.043 · Δ p +0.596 formula 2);
in formula 2), mcaliIs the mass of n-undecane in g, and Δ p is the differential pressure in Pa.
And (3) conveying the calibration liquid to the measuring pipe and the gas-liquid separator and other equipment through the calibration liquid metering pump 18, carrying out back flushing on the whole device, and cleaning.
TABLE 1
S2, injecting natural gas to be detected into the sample inlet pipe 25, opening the block valve 1 to enable the natural gas to flow into the dust filter 2, filtering solid dust through the dust filter 2, then flowing into the water filter 3, absorbing and filtering moisture in the natural gas, heating the natural gas through the electric heater 4, enabling the natural gas to enter the pressure reducing valve 5, reducing the pressure through the pressure reducing valve 5, regulating the pressure to a target pressure through the pressure stabilizing valve 6, entering the heat exchanger 7, cooling, condensing in the heat exchanger 7, entering the gas-liquid separator 8, and separating gas and liquid to obtain a gas phase and a liquid phase.
The composition of the natural gas to be detected in step S2 is shown in table 2 below, the target pressure is 3MPa, and the condensation separation temperature is-11.1 ℃.
TABLE 2
| Serial number | Components | Mole percentage content |
| 1 | Nitrogen gas | 2.0681 |
| 2 | Carbon dioxide | 2.0041 |
| 3 | Methane | 90.3295 |
| 4 | Ethane (III) | 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 |
S3, distributing the liquid phase obtained in the step S2 to a plurality of measuring pipes through a liquid distributor 9, moving the liquid phase in the measuring pipes, gradually increasing the reading of the sensitive differential pressure gauge 24 along with the time, measuring the differential pressure of the liquid phase at two ends of the measuring pipes after the reading of the differential pressure change of the sensitive differential pressure gauge 24 is stable, and calculating to obtain the liquid phase quality change rate dm according to the calibration function obtained in the step S1. Wherein the measured liquid hydrocarbon enters the liquid hydrocarbon collector 13 and is discharged out through the liquid discharge pipe 27.
The second measurement pipe 11-2 having a pipe diameter of 20mm is also taken as an example in step S3, and the differential pressure of the second measurement pipe and the mass of the liquid phase calculated according to the calibration function shown in the above formula 2) are given as shown in table 3 below.
TABLE 3
| Duration of test/h | 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, the system is in a debugging state and the working condition is unstable after 0-2 hours, and meanwhile, the differential pressure value does not linearly change along with the time due to the influence of a liquid storage dead zone of the system; and (3) from 3 to 16 hours, operating each parameter of the system stably, linearly changing the differential pressure value along with time, and fitting the liquid phase quality data after 3 to 16 hours with the test duration data to obtain the liquid phase quality change rate, wherein the obtained liquid phase quality change rate dm is 733 mg/h.
S4, the gas phase obtained in the step S2 enters a rectifier 15, enters a flow sensor 23 after being rectified by the rectifier 15, the flow of the gas phase is measured to obtain a gas phase flow value q, the gas phase is uniformly discharged through an exhaust pipe 26, and the gas phase flow q in a standard state is obtained through calculation according to a gas state equation0At 2.08Nm3H is used as the reference value. Wherein the gas phase flow rate q in the standard state0Refers to the gas standard condition (1atm, 20 ℃) flow in the same time period under stable conditions.
S5, calculating the content W of the liquid hydrocarbon in the natural gas by adopting the following formula 1) according to the liquid phase mass change rate obtained in the step S3 and the gas phase flow rate in the standard state obtained in the step S4liqThe content W of the liquid hydrocarbon in the natural gas to be detected calculated in the step S5liqIs 352.4mg/Nm3。
In formula 1), wliqThe mass of liquid hydrocarbon in each standard square of natural gas is in mg/Nm3(ii) a dm is the liquid phase mass change rate obtained in the step S3, and the unit is mg/h; q. q.s0The standard state gas phase flow rate obtained in step S4 is in Nm3/h。
In summary, in the detection method for the content of the liquid hydrocarbon in the natural gas provided by the embodiment of the invention, the content of the liquid hydrocarbon in the liquid phase is converted into the differential pressure signal, and then the differential pressure signal is converted, so that the content of the liquid hydrocarbon can be calculated, and the content of the liquid hydrocarbon in the natural gas can be accurately measured. The method solves the problem of accurately measuring the contents of different liquid hydrocarbons in natural gas with different gas compositions under different pressure and temperature conditions, and provides a scientific, accurate and integrated liquid hydrocarbon content measuring method for each link of natural gas treatment and transportation.
It should be noted that the term "comprises/comprising" and any variations thereof in the description and claims of this invention and the above-described drawings is intended to cover non-exclusive inclusions, such that a process, method, system, article, or apparatus that comprises a list of steps or elements is not necessarily limited to those steps or elements expressly listed, but may include other steps or elements not expressly listed or inherent to such process, method, article, or apparatus.
In the present invention, it is to be understood that the terms "central," "longitudinal," "lateral," "upper," "lower," "front," "rear," "left," "right," "vertical," "horizontal," "top," "bottom," "inner," "outer," and the like are used in an orientation or positional relationship indicated based on the orientation or positional relationship shown in the drawings, which are used primarily for convenience in describing and simplifying the invention, and are not intended to indicate or imply that the device or element being referred to must have a particular orientation, be constructed in a particular orientation, and be operated, and therefore should not be considered as limiting the invention. Moreover, some of the above terms may be used to indicate other meanings besides the orientation or positional relationship, for example, the term "on" may also be used to indicate some kind of attachment or connection relationship in some cases. The specific meanings of these terms in the present invention can be understood by those skilled in the art as appropriate.
Furthermore, the terms "first", "second", etc. are used for descriptive purposes only and are not to be construed as indicating or implying relative importance or implicitly indicating the number of technical features indicated. Thus, a feature defined as "first," "second," etc. may explicitly or implicitly include one or more of that feature. In the description of the invention, the meaning of "a plurality" is two or more unless otherwise specified.
Furthermore, the terms "disposed," "mounted," and "connected" are to be construed broadly. For example, "connected" may be a fixed connection, a detachable connection, or a unitary construction; can 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 meanings of the above terms in the present invention can be understood by those of ordinary skill in the art according to specific situations.
The above description is only exemplary of the invention and should not be taken as limiting the scope of the invention, so that the invention is intended to cover all modifications and equivalents of the embodiments described herein. In addition, the technical features and the technical inventions of the present invention, the technical features and the technical inventions, and the technical inventions can be freely combined and used.
Claims (19)
1. A device for detecting the content of liquid hydrocarbons in natural gas, wherein the device for detecting the content of liquid hydrocarbons in natural gas comprises:
a sample inlet tube (25);
the sample inlet 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);
and the differential pressure testing part is connected to the liquid hydrocarbon content detecting part, and the differential pressure value of the liquid in the liquid hydrocarbon content detecting part is tested through the differential pressure testing part.
2. The apparatus for detecting the content of liquid hydrocarbons in natural gas according to claim 1, wherein the liquid hydrocarbon content detecting member comprises a plurality of measuring tubes (11) of different tube diameters, and one end of the plurality of measuring tubes (11) is communicated with the liquid outlet end of the gas-liquid separator (8).
3. The apparatus for detecting the content of liquid hydrocarbons in natural gas according to claim 2, wherein the liquid hydrocarbon content detecting means further comprises: 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 correspond to the measuring tubes (11) one to one are formed in the liquid distributor (9), first valves (10) are arranged on the liquid outlets, and one ends of the measuring tubes (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 tubes (11).
4. The device for detecting the content of the liquid hydrocarbons in the natural gas according to claim 3, wherein 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 measuring pipe (11) one by one, the calibration liquid inlet pipe (19) is connected and communicated with the other end of the measuring pipe (11) after being divided, the other end of the dividing pipe of the calibration liquid inlet pipe (19) is connected and communicated with the output end of the calibration liquid metering pump (18), and the dividing pipe of the calibration liquid inlet pipe (19) is provided with a one-way valve (17).
5. The device for detecting the content of liquid hydrocarbons in natural gas according to claim 1, wherein the differential pressure testing component is a sensitive differential pressure gauge (24), the detection end of the sensitive differential pressure gauge (24) is respectively connected with the two ends of the liquid hydrocarbon content detecting component, and the differential pressure value of the input end and the output end of the liquid hydrocarbon content detecting component is detected by the sensitive differential pressure gauge (24).
6. The apparatus for detecting the liquid hydrocarbon content in natural gas according to claim 1, wherein the gas flow rate detection means includes a rectifier (15), a flow rate sensor (23), an exhaust pipe (26), and an exhaust control valve (16), an input end of the rectifier (15) is communicated with an outlet end of the gas-liquid separator (8), an input end of the flow rate sensor (23) is communicated with an output end of the rectifier (15), one end of the exhaust pipe (26) is connected and communicated with an output end of the flow rate sensor (23), and the exhaust control valve (16) is installed on the exhaust pipe (26).
7. The device for detecting the content of liquid hydrocarbons in natural gas according to any one of claims 1 to 6, wherein the device further comprises a pre-treatment unit and a pressure control unit, one end of the sample inlet pipe (25) is communicated with an input end of the pre-treatment unit, an output end of the pre-treatment unit is communicated with an input end of the pressure control unit, an output end of the pressure control unit is communicated with one end of the heat exchanger (7), and the other end of the heat exchanger (7) is communicated with an input end of the gas-liquid separator (8).
8. The device for detecting the content of liquid hydrocarbons in natural gas according to claim 7, wherein the pretreatment component comprises a dust filter (2), a water filter (3) and a shut-off valve (1), one end of the sample inlet pipe (25) is connected and communicated with one end of the shut-off valve (1), the other end of the shut-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).
9. The device for detecting the content of liquid hydrocarbons in natural gas according to claim 8, wherein the pressure control means comprises a pressure reducing valve (5), a pressure maintaining 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 maintaining valve (6), the other end of the pressure maintaining valve (6) is communicated with one end of the heat exchanger (7), the pressure sensor (21) is located between the pressure reducing valve (5) and the pressure maintaining valve (6), and the pressure of gas reduced by the pressure reducing valve (5) is detected by the pressure sensor (21).
10. The detection device for detecting the content of liquid hydrocarbons in natural gas according to claim 8 or 9, wherein a bypass pipe is arranged between the shut-off valve (1) and the dust filter (2) for draining and discharging excess natural gas, and a bypass valve (20) for opening or closing the bypass pipe is arranged on the bypass pipe.
11. The device for detecting the content of the liquid hydrocarbons in the natural gas according to claim 8 or 9, 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).
12. The device for detecting the content of liquid hydrocarbons in natural gas according to any one of claims 1 to 6, wherein the device further comprises a water bath (28), and the gas-liquid separator (8) and the liquid hydrocarbon content detection component are positioned in the water bath (28).
13. The apparatus for detecting the content of liquid hydrocarbons in natural gas according to claim 12, wherein the temperature of the water bath (28) is adjustable, and the minimum temperature is less than-30 ℃.
14. The device for detecting the content of liquid hydrocarbons in natural gas according to claim 2, wherein the device further comprises a liquid hydrocarbon recovery system connected and communicating with the other ends of the plurality of measuring tubes (11).
15. The device for detecting the content of liquid hydrocarbons in natural gas according to claim 14, wherein a second valve (12) is provided on the other end of each of the plurality of measuring tubes (11).
16. The apparatus for detecting the content of liquid hydrocarbons in natural gas according to claim 14 or 15, 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 a connecting pipeline, 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 installed on the liquid discharge pipe (27).
17. The device for detecting the content of the liquid hydrocarbons in the natural gas according to any one of claims 1 to 6, wherein a temperature sensor (22) is arranged on the output end of the gas-liquid separator (8) and is used for detecting the temperature of the separated liquid phase.
18. A method for detecting the content of liquid hydrocarbons in natural gas comprises the following steps:
s1, filling the calibration liquid into the liquid hydrocarbon content detection part, measuring the differential pressure of the calibration liquid in the liquid hydrocarbon content detection part to obtain a differential pressure signal, and calculating the functional relation between the differential pressure signal and the quality of the calibration liquid to obtain a calibration function;
s2, taking the 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 part, measuring the differential pressure change of the liquid phase in the liquid hydrocarbon content detection part, and calculating to obtain the liquid phase mass 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 the gas phase flow in a standard state according to a gas state equation;
and S5, calculating the content of the 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 rate obtained in the step S4.
19. The method for detecting the content of liquid hydrocarbons in natural gas according to claim 18, wherein in step S5, the content of liquid hydrocarbons in natural gas is calculated according to the following formula 1) according to the liquid phase mass change rate obtained in step S3 and the standard state gas phase flow rate obtained in step S4:
in formula 1), wliqThe mass of liquid hydrocarbon in each standard square of natural gas is in mg/Nm3(ii) a dm is the liquid phase mass change rate obtained in the step S3, and the unit is mg/h; q. q.s0The standard state gas phase flow rate obtained in step S4 is in Nm3/h。
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