Detection system and detection method based on sulfur-containing natural gas medium

Abstract

The invention discloses a sulfur-containing natural gas detection method and a sulfur-containing natural gas detection system, and relates to the technical field of oil and gas measurement. A detection system based on a sulfur-containing natural gas medium comprises a standard flow measurement unit, a hydrogen sulfide filling system, a detected flow measurement unit and a hydrogen sulfide recovery system. The standard flow measurement unit, the detected flow measurement unit and the hydrogen sulfide recovery system are sequentially arranged in the natural gas inlet direction. The hydrogen sulfide filling system, the detected flow measurement unit and the hydrogen sulfide recovery system are connected in series; the standard flow measuring unit and the hydrogen sulfide filling system are connected in parallel, flow detection of the detected flow measuring unit is not affected by the content of hydrogen sulfide components in an upstream gas source by adjusting the hydrogen sulfide filling system, the gas quality condition and the detection flow of the high-sulfur-content natural gas flowmeter are covered more widely, and stability is better. And the accuracy of the measurement result of the flowmeter used on site is improved.

Description

Technical Field

[0001] The present invention relates to the field of sour natural gas flow measurement, and in particular to a detection system and a detection method based on sour natural gas medium. Background Art

[0002] Worldwide, the reserves of high-sulfur natural gas reservoirs are huge and widely distributed, mainly in the United States and Canada in North America, Germany, France and Russia in Europe. Similarly, my country's high-sulfur natural gas reserves are also very rich, accounting for a large proportion of natural gas resources, basically accounting for more than 50%. In recent years, natural gas, as a clean and environmentally friendly energy, has been applied to all aspects of industrial production and residents' lives. The development and utilization of natural gas has occupied an important position in the world's energy production and consumption process. At present, the proportion of natural gas in my country's energy consumption structure continues to rise, and the rapid construction of various infrastructures continues to promote the rapid development of natural gas transportation and sales.

[0003] During the process of natural gas extraction, transportation and sales, product quantitative measurement is the basis for calculating its economic benefits. How to ensure the measurement accuracy during the natural gas trade handover process has received more and more attention and has also put forward higher requirements. With the rapid growth of conventional natural gas demand and the decreasing reserves of conventional natural gas itself, the proportion of high-sulfur natural gas reservoirs is increasing, which also brings new challenges to the measurement field. According to GB / T 26979-2011 "Classification of Natural Gas Reservoirs", natural gas with a volume fraction of H2S of 2% to 10% or a mass content of 30g / m3 to 150g / m3 is called high-sulfur natural gas.

[0004] At present, domestic calibration institutions use purified natural gas or air as the medium for calibration work, and are unable to calibrate the flowmeters used in sulfur-containing sites. Since the metering performance of sour natural gas flowmeters is different under different pressure and medium conditions, even a small metering deviation in future trade transfers will bring great financial risks. At the same time, with the exploration and development of sour gas fields, there will be more and more trade cooperation between different companies, and for public infrastructure, directly carrying out trade transfer of raw gas will become a development trend. In the actual production process, the measurement of sour natural gas directly applies the measurement methods and standards of conventional natural gas, and there is still a lack of effective methods and technical means for the measurement of sour natural gas. Therefore, it is still necessary to establish a detection system with sour natural gas as the medium, which can meet the calibration requirements for high-sulfur field flowmeters, so as to solve the problems of high safety risks, low metering efficiency, large metering errors and heavy equipment operation and maintenance workload caused by the existing high-sulfur natural gas flow measurement using conventional natural gas metering devices. Summary of the invention

[0005] The technical problem to be solved by the present invention is that the existing high-sulfur natural gas flow measurement uses conventional natural gas metering devices, which leads to high safety risks, low metering efficiency, large metering errors and a large workload for equipment operation and maintenance; the purpose is to provide a detection system and method based on sulfur-containing natural gas medium, which realizes the calibration of high-sulfur field flow meters and solves the above problems.

[0006] The present invention is achieved through the following technical solutions:

[0007] A detection system based on a sulfur-containing natural gas medium comprises a standard flow measurement unit, a hydrogen sulfide filling system, a flow measurement unit to be tested and a hydrogen sulfide recovery system; the standard flow measurement unit, the flow measurement unit to be tested and the hydrogen sulfide recovery system are arranged in sequence along the natural gas intake direction; the hydrogen sulfide filling system, the flow measurement unit to be tested and the hydrogen sulfide recovery system are connected in series; the standard flow measurement unit and the hydrogen sulfide filling system are connected in parallel.

[0008] The above-mentioned detection system based on sulfur-containing natural gas medium includes a main pipeline and a bypass pipeline; the above-mentioned standard flow measurement unit, the above-mentioned flow measurement unit to be tested and the above-mentioned hydrogen sulfide recovery system are installed on the above-mentioned main pipeline in sequence along the natural gas intake direction; the above-mentioned bypass pipeline is connected between the above-mentioned standard flow measurement unit and the above-mentioned flow measurement unit to be tested; the above-mentioned hydrogen sulfide filling system is installed on the above-mentioned bypass pipeline.

[0009] A mixer is provided between the standard flow measurement unit and the flow measurement unit to be tested; the bypass pipeline is communicated with the main channel through the mixer; and a component analysis device is provided between the mixer and the flow measurement unit to be tested.

[0010] The standard flow measurement unit or the inspected flow measurement unit includes a measuring flow meter, a pressure measurement unit and a temperature measurement unit.

[0011] The above-mentioned hydrogen sulfide recovery system includes a desulfurization device; the above-mentioned hydrogen sulfide filling system includes a hydrogen sulfide gas storage tank and a sulfur adding and pressure regulating unit; the output of the above-mentioned hydrogen sulfide gas storage tank is connected to the input of the sulfur adding and pressure regulating unit, and the output of the above-mentioned sulfur adding and pressure regulating unit is connected between the above-mentioned standard flow measurement unit and the above-mentioned flow measurement unit to be tested.

[0012] A detection method based on a sulfur-containing natural gas medium is implemented based on the above-mentioned detection system based on a sulfur-containing natural gas medium, and includes the following steps: according to the filling data of the above-mentioned hydrogen sulfide filling system, the measurement data of the above-mentioned standard flow measurement unit and the measurement data of the above-mentioned flow measurement unit to be tested, and the gas compression factor calculated by the data of the above-mentioned component analysis equipment, the data deviation between the above-mentioned flow measurement unit to be tested and the above-mentioned standard flow measurement unit is obtained after calculation, thereby obtaining the measurement error of the above-mentioned flow measurement unit to be tested.

[0013] The above-mentioned detection method based on sulfur-containing natural gas medium includes the following steps. Obtaining the above-mentioned gas compression factor includes the following steps: obtaining multiple groups of sampling data of the natural gas in the above-mentioned main pipeline, each group of the above-mentioned sampling data includes data measured by the above-mentioned component analysis equipment; and calculating the above-mentioned gas compression factor based on the above-mentioned multiple groups of sampling data of the natural gas in the above-mentioned main pipeline.

[0014] The above-mentioned detection method based on sulfur-containing natural gas medium includes the following steps: the measurement error of the above-mentioned flow measurement unit is Obtained by the following formula: Among them, V2 is the measurement value of the above-mentioned flow measurement unit under test; V1 is the gas parameter measurement value of the above-mentioned standard flow measurement unit; m0 is the measurement value of the above-mentioned hydrogen sulfide filling system; P1 is the pressure measurement value of the above-mentioned standard flow measurement unit, T1 is the temperature measurement value of the above-mentioned standard flow measurement unit, P2 is the pressure measurement value of the above-mentioned flow measurement unit under test, T2 is the temperature measurement value of the above-mentioned flow measurement unit under test, Z1 is the gas compression factor at the standard flow measurement unit, and Z2 is the gas compression factor at the flow measurement unit under test.

[0015] Compared with the prior art, the present invention has the following advantages and beneficial effects:

[0016] The present invention provides a detection system based on a high-sulfur natural gas medium, in which a standard flow measurement unit, a flow measurement unit to be detected and a hydrogen sulfide recovery system are sequentially arranged along the natural gas intake direction, so that two flow detections and comparisons are performed along the sulfur-containing natural gas, and the hydrogen sulfide gas in the detection section is recovered and processed by the hydrogen sulfide recovery system, thereby reducing the impact on the downstream gas quality; the hydrogen sulfide filling system, the flow measurement unit to be detected and the hydrogen sulfide recovery system are connected in series, and the standard flow measurement unit and the hydrogen sulfide filling system are connected in parallel, so that after the standard flow measurement unit is detected, the hydrogen sulfide filling system is configured with natural gas with a corresponding hydrogen sulfide content, so that the measurement data of the flow measurement unit to be detected changes with the configuration of the hydrogen sulfide filling system, so that whether the flow measurement unit to be detected is accurate is judged according to the change difference. The hydrogen sulfide filling system can configure natural gas with different hydrogen sulfide contents according to the detection requirements of the detected flow measurement unit, so that the detected flow measurement unit can be unaffected by the content of hydrogen sulfide components in the upstream gas source of the standard flow measurement unit, thereby meeting the test of the detected flow measurement unit with different natural gas quality conditions and calibration flow ranges, with better stability, and improving the accuracy of the measurement results of the flow meter used on site. The present invention also provides a detection method based on a high-sulfur natural gas medium based on the above system, according to the filling data of the hydrogen sulfide filling system, the measurement data of the standard flow measurement unit and the measurement data of the detected flow measurement unit, and the gas compression factor in the intake pipe, so as to calculate the data deviation between the detected flow measurement unit and the standard flow measurement unit, and use the data deviation to obtain the measurement error of the detected flow measurement unit, and then confirm the accuracy of the detected flow measurement unit. By simulating the working conditions of the high-sulfur field through filling data, configuring the gas quality components consistent with the field conditions, and determining the test value of the flow measurement unit under different conditions according to different compression factors, and comparing it with the test value of the standard flow measurement unit and the hydrogen sulfide filling system, the actual flow test of the high-sulfur natural gas flow is achieved. The overall measurement principle is clear, the system is simple, and it is easy to maintain. The present invention realizes the calibration of the flow meter for high-sulfur field, thereby solving the problem that the conventional natural gas metering device is still used in the existing wellhead high-sulfur natural gas flow measurement, resulting in high safety risks, low metering efficiency, large metering errors, and equipment operation and maintenance workload. BRIEF DESCRIPTION OF THE DRAWINGS

[0017] In order to more clearly illustrate the technical solutions of the exemplary embodiments of the present invention, the following briefly introduces the drawings required for use in the embodiments. It should be understood that the following drawings only illustrate certain embodiments of the present invention and should not be regarded as limiting the scope. For those of ordinary skill in the art, other relevant drawings can be obtained based on these drawings without creative work. In the drawings:

[0018] Figure 1This is a schematic diagram of a detection system based on a sulfur-containing natural gas medium according to Example 1 of the present application;

[0019] Figure 2 This is an application diagram of a detection system based on a sulfur-containing natural gas medium according to Example 1 of the present application;

[0020] Figure 3 This is a flow chart for preparing a detection method based on a sulfur-containing natural gas medium according to Example 2 of the present application;

[0021] Marks and corresponding parts names in the attached drawings:

[0022] 1- one-way valve, 2- pressure transmitter at the air inlet, 3- standard flow meter, 4- temperature transmitter at the air inlet, 5- hydrogen sulfide gas storage tank, 6- pressure regulating valve, 7- mixer, 8- component analysis equipment, 9- pressure transmitter at the air outlet, 10- flow meter under test, 11- temperature transmitter at the air outlet, 12- desulfurization device. DETAILED DESCRIPTION

[0023] In order to make the objectives, technical solutions and advantages of the present invention more clearly understood, the present invention is further described in detail below in conjunction with embodiments and drawings. The exemplary embodiments of the present invention and their description are only used to explain the present invention and are not intended to limit the present invention.

[0024] Example 1

[0025] An embodiment of the present application proposes a detection system based on a sulfur-containing natural gas medium, comprising a standard flow measurement unit, a hydrogen sulfide filling system, a flow measurement unit to be tested and a hydrogen sulfide recovery system; the standard flow measurement unit, the flow measurement unit to be tested and the hydrogen sulfide recovery system are arranged in sequence along the natural gas intake direction; the hydrogen sulfide filling system, the flow measurement unit to be tested and the hydrogen sulfide recovery system are connected in series; the standard flow measurement unit and the hydrogen sulfide filling system are connected in parallel.

[0026] The above-mentioned detection system based on sulfur-containing natural gas medium includes a main pipeline and a bypass pipeline; the above-mentioned standard flow measurement unit, the above-mentioned flow measurement unit to be tested and the above-mentioned hydrogen sulfide recovery system are installed on the above-mentioned main pipeline in sequence along the natural gas intake direction; the above-mentioned bypass pipeline is connected between the above-mentioned standard flow measurement unit and the above-mentioned flow measurement unit to be tested; the above-mentioned hydrogen sulfide filling system is installed on the above-mentioned bypass pipeline.

[0027] A mixer 7 is provided between the standard flow measurement unit and the flow measurement unit to be tested; the bypass pipeline is connected to the main channel through the mixer 7; and a component analysis device 8 is provided between the mixer 7 and the flow measurement unit to be tested.

[0028] The standard flow measurement unit or the tested flow measurement unit includes a standard flow meter 3, a pressure measurement unit and a temperature measurement unit.

[0029] The above-mentioned hydrogen sulfide recovery system includes a desulfurization device 12; the above-mentioned hydrogen sulfide filling system includes a hydrogen sulfide gas storage tank 5 and a sulfur adding and pressure regulating unit; the output of the above-mentioned hydrogen sulfide gas storage tank 5 is connected to the input of the sulfur adding and pressure regulating unit, and the output of the above-mentioned sulfur adding and pressure regulating unit is connected between the above-mentioned standard flow measurement unit and the above-mentioned flow measurement unit to be tested.

[0030] Among them, the upstream purified natural gas flows into the standard flow measurement unit from the air inlet end. The gas parameter measurement of the standard flow measurement unit is mainly detected by the standard flow meter 3, the air inlet pressure transmitter 2 and the air inlet temperature transmitter 4 to obtain the flow and speed, pressure and temperature value of the natural gas here. After the gas source is detected by the standard flow measurement unit, it enters the flow measurement unit to be tested through the mixer 7 for detection. The other end input of the mixer 7 is also connected to the output of the hydrogen sulfide filling system, and the hydrogen sulfide filling system is connected to the pressure regulating valve 6 through the gas storage tank. The flow measurement unit to be tested detects the pressure, flow and speed, and temperature through the outlet pressure transmitter 9, the flow meter to be tested 10 and the outlet temperature transmitter 11. Optionally, the on-site environmental conditions of the flow measurement unit to be tested can be simulated by adjusting the hydrogen sulfide filling system, so as to facilitate the rapid testing of the accuracy of the high-sulfur field flow meter using the air inlet end. Optionally, the detection data of the flow measurement unit to be tested can be made consistent with the detection data of the standard flow measurement unit by adjusting the hydrogen sulfide filling system, so as to judge and verify the accuracy of the flow measurement unit to be tested by using the adjustment parameters of the hydrogen sulfide filling system. Optionally, a one-way valve 1 is provided between the air inlet and the standard flow measurement unit, the standard flow measurement unit and the mixer 7, the mixer 7 and the flow measurement unit to be tested, and the flow measurement unit to be tested and the desulfurization device 12 to connect or disconnect the main pipeline for transmitting the purified natural gas to the mixer 7, and the bypass pipeline is connected to the side wall of the main pipeline and is arranged at the upstream position of the flow measurement unit to be calibrated. The bypass pipeline is a hydrogen sulfide filling system, which is equipped with different volumes of hydrogen sulfide gas. Natural gas with different hydrogen sulfide contents can be configured according to the detection requirements, so as to obtain the measurement data of hydrogen sulfide entering the above-mentioned mixer 7, and determine the amount of hydrogen sulfide filling according to the experimental conditions. The desulfurization device 12 is used to recover the hydrogen sulfide gas existing in the detection section to reduce the impact on the downstream gas quality. Based on the filling data of the hydrogen sulfide filling system, the measurement data of the standard flowmeter 3 (a vortex flowmeter can be used) and the measurement data of the flowmeter under test 10, as well as the calculation data of the compression factor, the error between the flowmeter under test 10 and the standard flowmeter 3 is calculated, which can further confirm the accuracy of the flowmeter under test 10.

[0031] Example 2

[0032] The embodiment of the present application proposes a detection method based on a sulfur-containing natural gas medium, which is implemented based on the above-mentioned detection system based on a sulfur-containing natural gas medium, and includes the following steps: according to the filling data of the above-mentioned hydrogen sulfide filling system, the measurement data of the above-mentioned standard flow measurement unit and the measurement data of the above-mentioned flow measurement unit to be tested, and the gas compression factor calculated by the data of the above-mentioned component analysis equipment 8, the data deviation between the above-mentioned flow measurement unit to be tested and the above-mentioned standard flow measurement unit is obtained after calculation, thereby obtaining the measurement error of the above-mentioned flow measurement unit to be tested.

[0033] The above-mentioned detection method based on sulfur-containing natural gas medium includes the following steps. Obtaining the above-mentioned gas compression factor includes the following steps: obtaining multiple groups of sampling data of the natural gas in the above-mentioned main pipeline, each group of the above-mentioned sampling data includes data measured by the above-mentioned component analysis equipment 8; and calculating the above-mentioned gas compression factor according to the component sampling data of the natural gas in the above-mentioned main pipeline in accordance with the public international and domestic standards.

[0034] Multiple groups of sampling data of natural gas in the main pipeline are obtained, each group of data includes gas quality component parameters measured by the component analysis device 8, and the gas compression factor is calculated based on the multiple groups of sampling data, thereby ensuring the accuracy of the gas compression factor.

[0035] Among them, the gas parameters of the standard flow measurement unit include the vortex flowmeter, the inlet pressure transmitter 2 and the inlet temperature transmitter 4, which respectively detect the natural gas flow and velocity, pressure and temperature values. The gas parameters of the flow measurement unit under test include the flow meter under test 10, the outlet pressure transmitter 9 and the outlet temperature transmitter 11, which respectively detect the natural gas flow and velocity, pressure and temperature values. The gas compression factor at the standard flow measurement unit is calculated by the measured value of the standard flow measurement unit, and the gas compression factor at the flow measurement unit under test is calculated by the measured value of the flow measurement unit under test.

[0036] According to the on-site process conditions of the flow measurement unit under test, the filling amount of the hydrogen sulfide filling system is adjusted to make it consistent with the on-site use conditions of the flow meter 10 under test, so that the flow meter 10 under test is not affected by the upstream gas source of the standard flow meter 3. The accuracy test of the flow measurement unit under test is completed through on-site simulation.

[0037] According to the disclosed method for calculating the gas compressibility factor, a suitable calculation method is selected according to the gas components obtained by the component analysis device 8. When the H2S molar content measured by the component analysis device in the sampling data is less than 0.02%, the compression factor at the flow meter is calculated according to the AGA8-92DC natural gas physical property calculation method or the method in the GB / T17747.2-2011 natural gas compression factor calculation standard. The AGA8-92DC natural gas physical property calculation method and the method for calculating the compression factor at the flow meter in the GB / T17747.2-2011 natural gas compression factor calculation standard are a standard and belong to the known technology, which will not be described here. It also includes that when the H2S molar content in the sampling data is greater than 0.02% and less than 27%, the compression factor at the flow meter is calculated according to the method in the ISO20765.2-2015 thermodynamic property calculation and the AGA NO.8.2:2017 natural gas physical property calculation method standard, which belongs to the known technology and will not be described here;

[0038] The above-mentioned detection method based on sulfur-containing natural gas medium includes the following steps: the measurement error of the above-mentioned flow measurement unit is Obtained by the following formula: Among them, V2 is the measurement value of the above-mentioned flow measurement unit under test; V1 is the gas parameter measurement value of the above-mentioned standard flow measurement unit; m0 is the measurement value of the above-mentioned hydrogen sulfide filling system, that is, the filling mass of hydrogen sulfide gas; P1 is the pressure measurement value of the above-mentioned standard flow measurement unit, T1 is the temperature measurement value of the above-mentioned standard flow measurement unit, P2 is the pressure measurement value of the above-mentioned flow measurement unit under test, T2 is the temperature measurement value of the above-mentioned flow measurement unit under test, Z1 is the gas compression factor calculated at the standard flow measurement unit according to the GB / T17747.2-2011 natural gas compression factor calculation standard, and Z2 is the gas compression factor obtained at the flow measurement unit under test according to the ISO20765.2-2015 thermodynamic property calculation method.

[0039] The calculation of gas compression factor is divided into two cases. One is the calculation of purified gas. The standard GB / T17747.2-1999 has a complete calculation formula. When the sulfur content is relatively high, the second calculation method is used, that is, the standard ISO20765.2-2015 is used. Both methods are public and there is no need to describe them in detail here.

[0040] Among them, the process parameters of the main pipeline, such as pipeline path, pipeline radius and gas composition, can be directly obtained according to the on-site process conditions of the flow measurement unit under inspection. According to the sulfur content of hydrogen sulfide tested by the gas component analysis device 8 when the flow measurement unit under inspection is in actual working state, the hydrogen sulfide filling amount of the hydrogen sulfide filling system is confirmed, thereby simulating the on-site working state to meet the needs of the experiment and the main pipeline. The gas compressibility factor in the main pipeline can be calculated according to the gas component parameters obtained by the gas component analysis device 8 in the main pipeline according to the ISO20765.2-2015 thermodynamic property calculation method, wherein the gas component parameters include gas composition, molar volume of different gas components, pressure and temperature data. Optionally, the filling data of the hydrogen sulfide filling system includes hydrogen sulfide filling amount, filling pressure and filling temperature; the measurement data of the standard flow measurement unit or the flow measurement unit under inspection includes natural gas flow, velocity, pressure and temperature. Therefore, the error size of the flow detection data is judged according to the filling parameters before and after filling, and the accuracy of the flow measurement unit under inspection is calculated.

[0041] The specific implementation methods described above further illustrate the objectives, technical solutions and beneficial effects of the present invention in detail. It should be understood that the above description is only a specific implementation method of the present invention and is not intended to limit the scope of protection of the present invention. Any modifications, equivalent substitutions, improvements, etc. made within the spirit and principles of the present invention should be included in the scope of protection of the present invention.

Claims

1. A detection system based on sulfur-containing natural gas medium, characterized in that: It includes a standard flow measurement unit, a hydrogen sulfide filling system, a flow measurement unit to be tested and a hydrogen sulfide recovery system; the standard flow measurement unit, the flow measurement unit to be tested and the hydrogen sulfide recovery system are arranged in sequence along the natural gas intake direction; the hydrogen sulfide filling system, the flow measurement unit to be tested and the hydrogen sulfide recovery system are connected in series; the standard flow measurement unit and the hydrogen sulfide filling system are connected in parallel.

2. A detection system based on sulfur-containing natural gas medium according to claim 1, characterized in that: It comprises a main pipeline and a bypass pipeline; the standard flow measurement unit, the tested flow measurement unit and the hydrogen sulfide recovery system are sequentially installed on the main pipeline along the natural gas intake direction; the bypass pipeline is connected between the standard flow measurement unit and the tested flow measurement unit; the hydrogen sulfide filling system is installed on the bypass pipeline.

3. A detection system based on sulfur-containing natural gas medium according to claim 1, characterized in that: A mixer is provided between the standard flow measurement unit and the flow measurement unit to be tested; the bypass pipeline is communicated with the main channel through the mixer; and a component analysis device is provided between the mixer and the flow measurement unit to be tested.

4. A detection method based on sulfur-containing natural gas medium according to claim 1, characterized in that: The standard flow measurement unit or the inspected flow measurement unit includes a measuring flow meter, a pressure measurement unit and a temperature measurement unit.

5. A detection method based on sulfur-containing natural gas medium according to claim 1, characterized in that: The hydrogen sulfide recovery system includes a desulfurization device; the hydrogen sulfide filling system includes a hydrogen sulfide gas storage tank and a sulfur adding and pressure regulating unit; the output of the hydrogen sulfide gas storage tank is connected to the input of the sulfur adding and pressure regulating unit, and the output of the sulfur adding and pressure regulating unit is connected between the standard flow measurement unit and the tested flow measurement unit.

6. A detection method based on sulfur-containing natural gas medium, characterized in that: A detection system based on a sulfur-containing natural gas medium according to claim 3 is implemented, comprising the following steps: according to the filling data of the hydrogen sulfide filling system, the measurement data of the standard flow measurement unit and the measurement data of the flow measurement unit to be tested, and the gas compression factor calculated by the data of the component analysis equipment, the data deviation between the flow measurement unit to be tested and the standard flow measurement unit is obtained after calculation, thereby obtaining the measurement error of the flow measurement unit to be tested.

7. A detection method based on sulfur-containing natural gas medium according to claim 6, characterized in that: The method comprises the following steps: obtaining the gas compression factor comprises the following steps: obtaining multiple groups of sampling data of the natural gas in the main pipeline, each group of the sampling data comprises data measured by the component analysis equipment; and calculating the gas compression factor according to the multiple groups of sampling data of the natural gas in the main pipeline.

8. A detection method based on sulfur-containing natural gas medium according to claim 6, characterized in that: The following steps are included: the measurement error of the flow measurement unit to be tested Obtained by the following formula: ； in, is the measured value of the flow measurement unit under inspection; is the gas parameter measurement value of the standard flow measurement unit; is the measurement value of the hydrogen sulfide filling system; P1 is the pressure measurement value of the standard flow measurement unit, T1 is the temperature measurement value of the standard flow measurement unit, P2 is the pressure measurement value of the tested flow measurement unit, T2 is the temperature measurement value of the tested flow measurement unit, Z1 is the gas compression factor at the standard flow measurement unit, and Z2 is the gas compression factor at the tested flow measurement unit.

9. A computer device comprising a memory, a processor and a computer program stored in the memory and executable on the processor, characterized in that: When the processor executes the computer program, the detection method based on sulfur-containing natural gas medium as described in any one of claims 6 to 8 is implemented.

10. A computer-readable storage medium storing a computer program, wherein the computer program, when executed by a processor, implements a detection method based on a sulfur-containing natural gas medium as claimed in any one of claims 6 to 8.

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