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

Abstract

The application discloses a kind of sulfur-containing natural gas detection method and detection system, it is related to oil and gas measurement technical field.A kind of detection system based on sulfur-containing natural gas medium, including standard flow measurement unit, hydrogen sulfide injection system, the flow measurement unit of being detected and hydrogen sulfide recovery system;Standard flow measurement unit, the flow measurement unit of being detected and hydrogen sulfide recovery system are sequentially arranged along the direction of natural gas intake;Hydrogen sulfide injection system, the flow measurement unit of being detected and hydrogen sulfide recovery system are connected in series;Standard flow measurement unit and hydrogen sulfide injection system are connected in parallel, by adjusting hydrogen sulfide injection system, so that the flow detection of the flow measurement unit of being detected is not influenced by hydrogen sulfide component content in upstream gas source, the gas quality condition of high sulfur-containing natural gas flowmeter is wider, and the stability is better, improves the accuracy of flowmeter measurement result of on-site use.

Description

Technical Field

[0001] This invention relates to the field of sulfur-containing natural gas flow measurement, and specifically to a detection system and method based on sulfur-containing natural gas medium. Background Technology

[0002] Globally, high-sulfur natural gas reserves are vast and widely distributed, primarily in the United States and Canada in North America, and Germany, France, and Russia in Europe. Similarly, my country also possesses abundant high-sulfur natural gas reserves, accounting for a significant portion of its natural gas resources, generally exceeding 50%. In recent years, natural gas, as a clean and environmentally friendly energy source, has been applied to various aspects of industrial production and daily life, and its development and utilization have become crucial in global energy production and consumption. Currently, the proportion of natural gas in my country's energy consumption structure is continuously increasing, and the rapid construction of various infrastructure projects continues to drive the rapid development of natural gas transmission and sales.

[0003] In the extraction, transportation, and sale of natural gas, quantitative measurement is fundamental to calculating its economic benefits. Ensuring the accuracy of measurement during natural gas trade transactions has received increasing attention and raised higher requirements. With the rapid growth in demand for conventional natural gas and the decreasing reserves of conventional natural gas itself, the proportion of high-sulfur natural gas reservoirs being exploited is increasing, which also brings new challenges to the field of measurement. According to GB / T 26979-2011 "Classification of Natural Gas Reservoirs," natural gas with an H2S volume fraction of 2%–10% or a mass content of 30 g / m³–150 g / m³ is classified as high-sulfur natural gas.

[0004] Currently, domestic calibration agencies conduct calibration work using purified natural gas or air as the medium, which cannot calibrate flow meters used in sulfur-containing fields. Because the metering performance of sulfur-containing natural gas flow meters varies under different pressure and medium conditions, even small metering deviations in future trade transactions can lead to significant financial risks. Simultaneously, with the exploration and development of sulfur-containing gas fields, trade cooperation between different companies will increase, and direct trade of raw gas for public infrastructure will become a development trend. In actual production processes, the metering of sulfur-containing natural gas directly applies the metering methods and standards of conventional natural gas, lacking effective methods and technical means for its measurement. Therefore, it is still necessary to establish a detection system using sulfur-containing natural gas as the medium, capable of meeting the calibration needs of flow meters used in high-sulfur fields, to solve the problems of high safety risks, low metering efficiency, large metering errors, and heavy equipment operation and maintenance workload caused by the current use of conventional natural gas metering devices for high-sulfur natural gas flow measurement. Summary of the Invention

[0005] The technical problem to be solved by this 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 media, which realizes the calibration of flow meters used in high-sulfur fields and solves the above problems.

[0006] This invention is achieved through the following technical solution:

[0007] A detection system based on sulfur-containing natural gas includes a standard flow measurement unit, a hydrogen sulfide refueling system, a flow measurement unit under test, and a hydrogen sulfide recovery system. The standard flow measurement unit, the flow measurement unit under test, and the hydrogen sulfide recovery system are arranged sequentially along the natural gas intake direction. The hydrogen sulfide refueling system, the flow measurement unit under test, and the hydrogen sulfide recovery system are connected in series. The standard flow measurement unit and the hydrogen sulfide refueling system are connected in parallel.

[0008] The aforementioned detection system based on sulfur-containing natural gas includes a main pipeline and a bypass pipeline; the aforementioned standard flow measurement unit, the aforementioned tested flow measurement unit, and the aforementioned hydrogen sulfide recovery system are sequentially installed on the aforementioned main pipeline along the natural gas intake direction; the aforementioned bypass pipeline connects the aforementioned standard flow measurement unit and the aforementioned tested flow measurement unit; the aforementioned hydrogen sulfide refueling system is installed on the aforementioned bypass pipeline.

[0009] A mixer is provided between the standard flow measurement unit and the flow measurement unit under test; the bypass pipe is connected to the main channel through the mixer; and a component analysis device is provided between the mixer and the flow measurement unit under test.

[0010] The aforementioned standard flow measurement unit or the aforementioned flow measurement unit under test includes a flow meter, a pressure measurement unit, and a temperature measurement unit.

[0011] The aforementioned hydrogen sulfide recovery system includes a desulfurization device; the aforementioned hydrogen sulfide refueling system includes a hydrogen sulfide storage tank and a sulfurization and pressure regulating unit; the output of the aforementioned hydrogen sulfide storage tank is connected to the input of the sulfurization and pressure regulating unit, and the output of the aforementioned sulfurization and pressure regulating unit is connected between the aforementioned standard flow measurement unit and the aforementioned flow measurement unit under test.

[0012] A detection method based on sulfur-containing natural gas medium, implemented based on the aforementioned detection system for sulfur-containing natural gas medium, includes the following steps: based on the refueling data of the aforementioned hydrogen sulfide refueling system, the measurement data of the aforementioned standard flow measurement unit, the measurement data of the aforementioned flow measurement unit under test, and the gas compressibility factor calculated using the data from the aforementioned component analysis equipment, the data deviation between the flow measurement unit under test and the aforementioned standard flow measurement unit is calculated, thereby obtaining the measurement error of the flow measurement unit under test.

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

[0014] The aforementioned detection method based on sulfur-containing natural gas includes the following steps: the measurement error of the flow measurement unit under test. It can be obtained through the following formula: Wherein, V2 is the measured value of the flow measurement unit under test; V1 is the measured value of the gas parameter of the standard flow measurement unit; m0 is the measured value of the hydrogen sulfide refueling system; P1 is the measured value of the pressure of the standard flow measurement unit; T1 is the measured value of the temperature of the standard flow measurement unit; P2 is the measured value of the pressure of the flow measurement unit under test; T2 is the measured value of the temperature of the flow measurement unit under test; Z1 is the gas compressibility factor at the standard flow measurement unit; and Z2 is the gas compressibility 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] This invention provides a detection system based on high-sulfur natural gas medium. A standard flow measurement unit, a tested flow measurement unit, and a hydrogen sulfide recovery system are sequentially arranged along the natural gas intake direction. This allows for two flow rate measurements and comparisons along the sulfur-containing natural gas. The hydrogen sulfide recovery system recovers and processes the hydrogen sulfide gas within the detection section, reducing its impact on downstream gas quality. The hydrogen sulfide refueling system, the tested flow measurement unit, and the hydrogen sulfide recovery system are connected in series, while the standard flow measurement unit and the hydrogen sulfide refueling system are connected in parallel. After the standard flow measurement unit performs its measurement, the hydrogen sulfide refueling system dispenses natural gas with a corresponding hydrogen sulfide content. This causes the measurement data of the tested flow measurement unit to change with the configuration of the hydrogen sulfide refueling system, allowing the accuracy of the tested flow measurement unit to be determined based on the difference in the change. The hydrogen sulfide refueling system can be configured with natural gas containing different hydrogen sulfide contents according to the detection requirements of the tested flow measurement unit. This ensures that the tested flow measurement unit is unaffected by the hydrogen sulfide content in the upstream gas source of the standard flow measurement unit, thus meeting the testing requirements for flow measurement units with different natural gas quality conditions and calibration flow ranges. This results in better stability and improved accuracy of flow meter measurements in the field. Based on the above system, this invention also provides a detection method for high-sulfur natural gas media. Using the refueling data from the hydrogen sulfide refueling system, the measurement data from the standard flow measurement unit and the tested flow measurement unit, as well as the gas compressibility factor in the inlet pipe, the data deviation between the tested flow measurement unit and the standard flow measurement unit is calculated. The measurement error of the tested flow measurement unit is obtained by using the magnitude of the data deviation, thereby confirming the accuracy of the tested flow measurement unit. This invention simulates the operating conditions of high-sulfur natural gas fields by injecting data, configuring gas composition consistent with field conditions, and determining the test values ​​of the tested flow measurement unit under different conditions based on different compressibility factors. These values ​​are then compared with those of a standard flow measurement unit and a hydrogen sulfide injection system to achieve real-world flow testing of high-sulfur natural gas. The overall measurement principle is clear, the system is simple, and easy to maintain. This invention enables the calibration of flow meters used in high-sulfur field applications, thus solving the problems of high safety risks, low measurement efficiency, large measurement errors, and heavy equipment operation and maintenance workload associated with the current use of conventional natural gas metering devices for measuring the flow of high-sulfur natural gas at wellheads. Attached Figure Description

[0017] To more clearly illustrate the technical solutions of the exemplary embodiments of the present invention, the accompanying drawings used in the embodiments will be briefly described below. It should be understood that the following drawings only show some embodiments of the present invention and should not be considered as a limitation of the scope. For those skilled in the art, other related drawings can be obtained based on these drawings without creative effort. In the drawings:

[0018] Figure 1This is a schematic diagram of the detection system based on sulfur-containing natural gas medium in Embodiment 1 of this application;

[0019] Figure 2 This is an application diagram of the detection system based on sulfur-containing natural gas medium in Embodiment 1 of this application;

[0020] Figure 3 This is a flowchart illustrating the preparation of the detection method based on sulfur-containing natural gas medium in Embodiment 2 of this application;

[0021] The attached diagram shows the markings and corresponding component names:

[0022] 1-One-way valve, 2-Inlet pressure transmitter, 3-Standard flow meter, 4-Inlet temperature transmitter, 5-Hydrogen sulfide storage tank, 6-Pressure regulating valve, 7-Mixer, 8-Component analysis equipment, 9-Outlet pressure transmitter, 10-Flow meter under test, 11-Outlet temperature transmitter, 12-Desulfurization device. Detailed Implementation

[0023] To make the objectives, technical solutions, and advantages of the present invention clearer, the present invention will be further described in detail below with reference to the embodiments and accompanying drawings. The illustrative embodiments and descriptions of the present invention are only used to explain the present invention and are not intended to limit the present invention.

[0024] Example 1

[0025] This application proposes a detection system based on sulfur-containing natural gas, including a standard flow measurement unit, a hydrogen sulfide refueling system, a flow measurement unit under test, and a hydrogen sulfide recovery system; the standard flow measurement unit, the flow measurement unit under test, and the hydrogen sulfide recovery system are arranged sequentially along the natural gas intake direction; the hydrogen sulfide refueling system, the flow measurement unit under test, and the hydrogen sulfide recovery system are connected in series; the standard flow measurement unit and the hydrogen sulfide refueling system are connected in parallel.

[0026] The aforementioned detection system based on sulfur-containing natural gas includes a main pipeline and a bypass pipeline; the aforementioned standard flow measurement unit, the aforementioned tested flow measurement unit, and the aforementioned hydrogen sulfide recovery system are sequentially installed on the aforementioned main pipeline along the natural gas intake direction; the aforementioned bypass pipeline connects the aforementioned standard flow measurement unit and the aforementioned tested flow measurement unit; the aforementioned hydrogen sulfide refueling system is installed on the aforementioned bypass pipeline.

[0027] A mixer 7 is provided between the standard flow measurement unit and the flow measurement unit under test; the bypass pipe 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 under test.

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

[0029] The aforementioned hydrogen sulfide recovery system includes a desulfurization device 12; the aforementioned hydrogen sulfide refueling system includes a hydrogen sulfide storage tank 5 and a sulfurization and pressure regulating unit; the output of the aforementioned hydrogen sulfide storage tank 5 is connected to the input of the sulfurization and pressure regulating unit, and the output of the aforementioned sulfurization and pressure regulating unit is connected between the aforementioned standard flow measurement unit and the aforementioned flow measurement unit under test.

[0030] In this system, purified natural gas flows into the standard flow measurement unit from the inlet. The standard flow measurement unit measures gas parameters primarily through a standard flow meter 3, an inlet pressure transmitter 2, and an inlet temperature transmitter 4, which detect the flow rate, velocity, pressure, and temperature of the natural gas. After being detected by the standard flow measurement unit, the gas enters the flow measurement unit under test via a mixer 7. The other end of the mixer 7 is connected to the output of the hydrogen sulfide refueling system, which is connected via a storage tank and a pressure regulating valve 6. The flow measurement unit under test detects pressure, flow rate, velocity, and temperature through an outlet pressure transmitter 9, a flow meter 10, and an outlet temperature transmitter 11. Optionally, adjustments to the hydrogen sulfide refueling system can simulate the on-site environmental conditions of the flow measurement unit under test, facilitating rapid testing of the accuracy of high-sulfur on-site flow meters at the inlet. Optionally, the detection data of the flow measurement unit under test can be made consistent with the detection data of the standard flow measurement unit by adjusting the hydrogen sulfide filling system. This allows the accuracy of the flow measurement unit under test to be judged and verified using the adjustment parameters of the hydrogen sulfide filling system. Optionally, one-way valves 1 are provided between the inlet and the standard flow measurement unit, between the standard flow measurement unit and the mixer 7, between the mixer 7 and the flow measurement unit under test, and between the flow measurement unit under test and the desulfurization device 12. These valves connect or disconnect the main pipeline for transmitting purified natural gas to the mixer 7. A bypass pipeline connects to the side wall of the main pipeline and is located upstream of the flow measurement unit under test to be calibrated. The bypass pipeline is a hydrogen sulfide filling system containing hydrogen sulfide gas of different volumes. Natural gas with different hydrogen sulfide contents can be configured according to testing requirements to obtain measurement data of hydrogen sulfide entering the mixer 7 and to determine the hydrogen sulfide filling amount based on experimental conditions. The desulfurization device 12 is used to recover hydrogen sulfide gas present in the detection section, reducing its impact on downstream gas quality. Based on the filling data of the hydrogen sulfide filling system, the measurement data of the standard flow meter 3 (which may be a vortex flow meter) and the measurement data of the flow meter under test 10, as well as the calculation data of the compressibility factor, the error between the flow meter under test 10 and the standard flow meter 3 is calculated, which can further confirm the accuracy of the flow meter under test 10.

[0031] Example 2

[0032] This application proposes a detection method based on sulfur-containing natural gas medium, implemented based on the aforementioned detection system for sulfur-containing natural gas medium. The method includes the following steps: based on the refueling data from the hydrogen sulfide refueling system, the measurement data from the standard flow measurement unit, the measurement data from the flow measurement unit under test, and the gas compressibility factor calculated using the data from the component analysis device 8, the data deviation between the flow measurement unit under test and the standard flow measurement unit is calculated, thereby obtaining the measurement error of the flow measurement unit under test.

[0033] The above-mentioned detection method based on sulfur-containing natural gas medium includes the following steps: obtaining the gas compressibility factor includes the following steps: obtaining multiple sets of sampling data of natural gas in the main pipeline, each set of sampling data including data measured by the component analysis equipment 8; and calculating the gas compressibility factor based on the component sampling data of natural gas in the main pipeline according to publicly available international and domestic standards.

[0034] Multiple sets of sampling data of natural gas in the main pipeline are obtained. Each set of data includes gas composition parameters measured by component analysis equipment 8. The gas compressibility factor is calculated based on the multiple sets of sampling data to ensure the accuracy of the gas compressibility factor.

[0035] The standard flow measurement unit measures gas parameters including the natural gas flow rate, velocity, pressure, and temperature values ​​detected by the eddy current flow meter, inlet pressure transmitter 2, and inlet temperature transmitter 4, respectively. The tested flow measurement unit measures gas parameters including the natural gas flow rate, velocity, pressure, and temperature values ​​detected by the tested flow meter 10, outlet pressure transmitter 9, and outlet temperature transmitter 11, respectively. The gas compressibility factor at the standard flow measurement unit is calculated using the measured values ​​from the standard flow measurement unit, and the gas compressibility factor at the tested flow measurement unit is calculated using the measured values ​​from the tested flow measurement unit.

[0036] Based on the on-site process conditions of the flow measurement unit under test, the amount of hydrogen sulfide filling system is adjusted to match the on-site operating conditions of the flow meter 10 under test. This ensures that the flow meter 10 under test is not affected by the upstream gas source of the standard flow meter 3, and the accuracy test of the flow measurement unit under test is completed through on-site simulation.

[0037] According to publicly available methods for calculating gas compressibility factors, and based on the gas components obtained from component analysis device 8, a suitable calculation method is selected. When the H2S molar content measured by the component analysis device in the sampled data is less than 0.02%, the compressibility factor at the flow meter is calculated according to the AGA8-92DC natural gas property calculation method or the method in the GB / T17747.2-2011 natural gas compressibility factor calculation standard. The AGA8-92DC natural gas property calculation method and the method in the GB / T17747.2-2011 natural gas compressibility factor calculation standard for calculating the compressibility factor at the flow meter are standards and are known technologies, and will not be elaborated here. It also includes cases where the H2S molar content in the sampled data is greater than 0.02% and less than 27%, in which case the compressibility factor at the flow meter is calculated according to the methods in ISO20765.2-2015 thermodynamic properties calculation and AGA NO.8.2:2017 natural gas property calculation method standard, which are also known technologies, and will not be elaborated here.

[0038] The aforementioned detection method based on sulfur-containing natural gas includes the following steps: the measurement error of the flow measurement unit under test. It can be obtained through the following formula: Wherein, V2 is the measured value of the flow measurement unit under test; V1 is the measured value of the gas parameter of the standard flow measurement unit; m0 is the measured value of the hydrogen sulfide refueling system, i.e., the refueling mass of hydrogen sulfide gas; P1 is the pressure measured value of the standard flow measurement unit; T1 is the temperature measured value of the standard flow measurement unit; P2 is the pressure measured value of the flow measurement unit under test; T2 is the temperature measured value of the flow measurement unit under test; Z1 is the gas compressibility factor calculated by the standard flow measurement unit according to the GB / T17747.2-2011 natural gas compressibility factor calculation standard; and Z2 is the gas compressibility factor calculated by the flow measurement unit under test according to the ISO20765.2-2015 thermodynamic property calculation method.

[0039] The calculation of gas compressibility factor is divided into two cases. One is the calculation for purified gas, and the standard GB / T17747.2-1999 has a complete calculation formula. When the sulfur content is relatively high, the second calculation method is used, which is to adopt the standard ISO20765.2-2015. Both methods are publicly available and need not be described in detail here.

[0040] The process parameters of the main pipeline, such as pipeline path, pipeline radius, and gas composition, can be directly obtained based on the on-site process conditions of the flow measurement unit under test. The hydrogen sulfide content measured by the gas composition analyzer 8 under the actual operating conditions of the flow measurement unit under test is used to determine the hydrogen sulfide filling amount of the hydrogen sulfide filling system, thereby simulating the on-site operating conditions to meet the needs of the experiment and the main pipeline. The gas compressibility factor within the main pipeline can be calculated based on the gas composition parameters obtained from the gas composition analyzer 8 within the main pipeline, according to the thermodynamic property calculation method of ISO 20765.2-2015. These gas composition parameters include gas composition, molar volume of different gas components, pressure, and temperature. Optionally, the filling data of the hydrogen sulfide filling system includes the hydrogen sulfide filling amount, filling pressure, and filling temperature; the measurement data from the standard flow measurement unit or the flow measurement unit under test includes natural gas flow rate, velocity, pressure, and temperature. Therefore, the error magnitude of the flow detection data is judged based on the filling parameters before and after filling, and the accuracy of the flow measurement unit under test is calculated.

[0041] The specific embodiments described above further illustrate the purpose, technical solution, and beneficial effects of the present invention. It should be understood that the above description is only a specific embodiment 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 within the scope of protection of the present invention.

Claims

1. A detection system based on a sulfur-containing natural gas medium, characterized in that, The standard flow measurement unit, the hydrogen sulfide injection system, the detected flow measurement unit and the hydrogen sulfide recovery system are sequentially arranged along the natural gas inlet direction; the hydrogen sulfide injection system, the detected flow measurement unit and the hydrogen sulfide recovery system are connected in series; the standard flow measurement unit and the hydrogen sulfide injection system are connected in parallel. The standard flow measurement unit comprises an inlet end pressure transmitter, a standard flow meter and an inlet end temperature transmitter, and the detected flow measurement unit comprises an outlet end pressure transmitter, a detected flow meter and an outlet end temperature transmitter.

2. A detection system based on a sulfur-containing natural gas medium according to claim 1, characterized in that, The standard flow measurement unit, the detected flow measurement unit and the hydrogen sulfide recovery system are sequentially arranged along the natural gas inlet direction; the hydrogen sulfide injection system, the detected flow measurement unit and the hydrogen sulfide recovery system are connected in series; the standard flow measurement unit and the hydrogen sulfide injection system are connected in parallel.

3. A detection system based on a sulfur-containing natural gas medium according to claim 2, characterized in that, The standard flow measurement unit and the detected flow measurement unit are provided with a mixer; the bypass pipeline is communicated with the main pipeline through the mixer; and a component analysis device is arranged between the mixer and the detected flow measurement unit.

4. The detection system based on a sulfur-containing natural gas medium according to claim 1, characterized in that, The hydrogen sulfide recovery system comprises a desulfurization device; the hydrogen sulfide injection system comprises a hydrogen sulfide storage tank and a sulfur injection pressure regulating unit; the output of the hydrogen sulfide storage tank is connected to the input of the sulfur injection pressure regulating unit, and the output of the sulfur injection pressure regulating unit is connected between the standard flow measurement unit and the detected flow measurement unit.

5. A method of detecting a sulfur-containing natural gas medium, characterized by, The detection system based on the sulfur-containing natural gas medium according to claim 3 is implemented, comprising the following steps: calculating the data deviation between the detected flow measurement unit and the standard flow measurement unit according to the injection data of the hydrogen sulfide injection system, the measurement data of the standard flow measurement unit and the measurement data of the detected flow measurement unit, and the gas compressibility factor calculated by the data of the component analysis device, so as to obtain the measurement error of the detected flow measurement unit. Measurement error of the flow rate measurement unit to be inspected is obtained by the following equation: ； wherein is the flow measurement value of the standard flow measurement unit; is the flow 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 flow measurement unit under test, T2 is the temperature measurement value of the flow measurement unit under test, Z1 is the gas compressibility factor at the standard flow measurement unit, and Z2 is the gas compressibility factor at the flow measurement unit under test.

6. A method of detecting a sulfur-containing natural gas medium according to claim 5, characterized in that, The gas compressibility factor is obtained by the following steps: obtaining a plurality of groups of sampling data of the natural gas in the main pipeline, each group of the sampling data comprising the data measured by the component analysis device; and calculating the gas compressibility factor according to the plurality of groups of the sampling data of the natural gas in the main pipeline.

7. A computer device comprising a memory, a processor, and a computer program stored on the memory and executable on the processor, characterized in that, The processor executes the computer program to implement the detection method based on the sulfur-containing natural gas medium according to any one of claims 5-6.

8. A computer readable storage medium, the computer readable storage medium storing a computer program, the computer program being executed by a processor to implement the detection method based on the sulfur-containing natural gas medium according to any one of claims 5-6.

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