Natural gas system carbon emission metering method and device, electronic equipment and storage medium

Abstract

The application discloses a natural gas system carbon emission metering method and device, electronic equipment and a storage medium, wherein the method comprises the following steps: obtaining the steady-state carbon emission of the current natural gas system by using a pre-trained natural gas system steady-state carbon emission flow model; obtaining the dynamic carbon emission of the current natural gas system by using a pre-trained natural gas system dynamic carbon emission flow model; and calculating the carbon emission of the current natural gas system according to the steady-state carbon emission and the dynamic carbon emission. Thus, the application can effectively identify the carbon emission details of the source, network and load of the natural gas system, clarify the carbon emission responsibilities of the three sides of the source, network and load, realize the accurate metering of the carbon emission of the natural gas system, and has high application value.

Description

Technical Field

[0001] This application relates to the field of low-carbon technology in energy systems, and in particular to a method, device, electronic equipment and storage medium for measuring carbon emissions in a natural gas system. Background Technology

[0002] To address the challenges posed by global climate change, my country has set a goal of peaking carbon dioxide emissions before 2030 and achieving carbon neutrality before 2060. This signifies a comprehensive shift in the domestic energy sector towards cleaner and lower-carbon energy. Natural gas, as a "transitional" fuel, is a relatively low-carbon and efficient energy source among fossil fuels and will gradually replace other fossil fuels with higher carbon emissions, taking a leading position in the energy system. Statistics show that my country's natural gas consumption was 24.7 billion cubic meters in 2000, reaching 328.8 billion cubic meters in 2020, with an average annual growth rate of approximately 14%, and is projected to continue growing until the middle of this century. However, the carbon emissions from the natural gas system remain a significant concern. Real-time, accurate, and comprehensive carbon emission measurement is fundamental and a prerequisite for understanding the current status and trends of carbon emissions in the natural gas system and promoting its low-carbon transformation.

[0003] To better integrate the characteristics of natural gas systems with the concept of low-carbon development and expand research on low-carbon energy technologies, it is necessary to understand and analyze carbon emissions in natural gas systems from a "carbon perspective." Unlike carbon emissions in other energy systems, natural gas is a primary energy source, and its chemical composition includes carbon. The flow of natural gas is equivalent to the flow of its contained carbon elements. This mechanism determines that carbon emissions from natural gas systems are a real flow, providing a clearer and more realistic basis for a comprehensive understanding and analysis of the carbon emission characteristics of natural gas systems.

[0004] Current research on carbon emissions from natural gas systems reveals several shortcomings in traditional life-cycle analysis and macro-statistical methods. These methods are overly macroscopic, failing to consider the pipeline structure and natural gas flow distribution, and thus failing to clearly define the spatiotemporal transfer mechanisms of carbon emissions across different stages of the natural gas system. Furthermore, the dynamic transmission and storage characteristics of natural gas systems result in diverse coupled carbon emission flows corresponding to energy flows within the network. This leads to issues such as unreasonable allocation of carbon emission responsibilities among the natural gas source, pipeline, and consumption sides, hindering guidance for low-carbon optimization of natural gas system operations. Therefore, accurate carbon emission measurement across all stages of the natural gas system remains a significant gap and urgently needs to be addressed. Summary of the Invention

[0005] This application provides a method, device, electronic equipment, and storage medium for measuring carbon emissions in a natural gas system. It can effectively identify the details of carbon emissions in each link of the natural gas system's source, grid, and load, clarify the carbon emission responsibilities of the source, grid, and load, and achieve accurate measurement of carbon emissions in the natural gas system. It has high application value.

[0006] The first aspect of this application provides a method for measuring carbon emissions from a natural gas system, comprising the following steps: obtaining the steady-state carbon emissions of the current natural gas system using a pre-trained steady-state carbon emission flow model of the natural gas system, wherein the steady-state carbon emission flow model of the natural gas system is based on the carbon flow density at natural gas system nodes, the carbon flow density in pipelines, network loss carbon emissions, the carbon flow rate in pipelines, and the carbon flow rate of natural gas load; obtaining the dynamic carbon emissions of the current natural gas system using a pre-trained dynamic carbon emission flow model of the natural gas system, wherein the dynamic carbon emission flow model of the natural gas system is based on the Bernoulli equation for non-ideal fluids, the carbon flow density and carbon flow rate at the pipeline inlet, and the carbon flow density and carbon flow rate at the pipeline outlet; and calculating the carbon emissions of the current natural gas system based on the steady-state carbon emissions and the dynamic carbon emissions.

[0007] Optionally, in one embodiment of this application, it further includes:

[0008] A steady-state carbon emission flow model for the natural gas system is established based on the node carbon flow density, pipeline carbon flow density, network loss carbon emissions, pipeline carbon flow rate, and natural gas load carbon flow rate. Specifically:

[0009] Based on the energy blending criteria, the node carbon flow density of the natural gas system is determined as follows:

[0010]

[0011] in, f represents the carbon flux density at node g in the natural gas system, expressed in tCO2 / MWh. p The gas flow in pipeline p in the natural gas system is expressed in km. 3 / h;f w The output of the gas source w is expressed in km. 3 / h; ξ represents 1km 3 The unit conversion constant between natural gas and 1 MWh of electrical energy; The carbon flow rate of pipe p is expressed in tCO2 / h. Indicates the carbon emission factor of natural gas; The set of pipelines that inject natural gas into node g of the natural gas system; Ω represents the set of gas sources that inject natural gas into node g of the natural gas system. NG A set of nodes in a natural gas system;

[0012] Determine the carbon flow density of natural gas system pipelines based on energy allocation criteria;

[0013]

[0014] in, Here is the carbon flux density of the natural gas pipeline p, expressed in tCO2 / MWh. Ω is the injection node of natural gas pipeline p; BG A collection of natural gas pipelines;

[0015] Determining the network loss carbon emissions of the natural gas system compressor includes: determining the network loss carbon flow rate of the electric compressor.

[0016]

[0017] in, Carbon flux density of electricity consumed by electric compressors, expressed in tCO2 / MWh; The electrical node connected to the electric compressor m; Ω CM1 It is a collection of electric compressors;

[0018] Determine the carbon flow rate of the turbo compressor network loss:

[0019]

[0020] in, Here is the carbon flux density of the natural gas pipeline p, expressed in tCO2 / MWh. The natural gas pipeline connected to the turbo compressor m; v m Natural gas consumed by the turbo compressor; Ω CM2 A collection of turbo compressors;

[0021] Determine the carbon flow rate of the natural gas system pipeline:

[0022]

[0023] Where X is the carbon emission allocation coefficient for network loss; This indicates the compressor connected to pipe p;

[0024] Determine the carbon flow rate of natural gas load:

[0025]

[0026] in, The carbon flow rate is given by the natural gas load d, in units of tCO2 / h; f d This represents the magnitude of the natural gas load d, in km². 3 / h; This indicates the node where the natural gas load d is located.

[0027] Optionally, in one embodiment of this application, the method further includes: calculating the matrix representation of the steady-state carbon emission flow model of the natural gas system.

[0028] Optionally, in one embodiment of this application, the calculation of the matrix representation of the steady-state carbon emission flow model of the natural gas system includes: constructing the node energy flux matrix, branch energy flow matrix, and gas source injection matrix of the natural gas system; performing matrix operations based on the node energy flux matrix, branch energy flow matrix, and gas source injection matrix of the natural gas system to obtain the node carbon flow density vector, and calculating the pipeline carbon flow rate matrix, network loss carbon flow rate matrix, and natural gas load carbon flow rate vector.

[0029] Optionally, in one embodiment of this application, the construction of the node energy flux matrix, branch energy flow matrix, and gas source injection matrix of the natural gas system includes:

[0030] Determine the relationship between the node energy flux matrix, the branch energy flow matrix, and the gas source injection matrix:

[0031]

[0032] Among them, F N Here is the energy flux matrix for the nodes of the natural gas system; N NG and N GG These represent the number of nodes and the number of gas sources, respectively; F B and F G These are the branch energy flow matrix and the gas source injection matrix, respectively;

[0033] Based on the carbon flow density of the natural gas system nodes and pipelines, the following is obtained:

[0034]

[0035]

[0036] Where, ρ NG and ρ GG They are respectively from The nodal carbon flux density vector formed by and The carbon flux density vector formed by the gas source; F BL The branch network loss matrix; This represents a column vector related to the carbon flux density of the electrical nodes connected to the compressor, where node g is the first node of the electric compressor and the carbon flux density of the electrical nodes connected to the compressor is ρ. NG hour, otherwise

[0037] Optionally, in one embodiment of this application, the step of performing matrix operations to obtain the node carbon flow density vector based on the node energy flux matrix, branch energy flow matrix, and gas source injection matrix of the natural gas system, and calculating the pipeline carbon flow rate matrix, network loss carbon flow rate matrix, and natural gas load carbon flow rate vector includes:

[0038]

[0039]

[0040]

[0041] in, The carbon flow rate matrix for the pipeline; The carbon flow rate matrix represents the network loss. f is the carbon flow rate vector of natural gas load; d This is the natural gas load vector.

[0042] Optionally, in one embodiment of this application, it further includes:

[0043] Based on the non-ideal fluid Bernoulli equation governing the gas flow, a dynamic carbon emission flow model for the natural gas system is established using the carbon flow density and rate at the pipe inlet and outlet. Specifically:

[0044] The non-ideal fluid Bernoulli equation followed by the airflow transport is:

[0045]

[0046]

[0047] Where π(x,t) and f(x,t) represent the natural gas pressure and flow rate at location x and time period t, respectively; C1 and C2 are constants related to pipeline parameters; Δt and Δx represent the time interval and spatial step size, respectively.

[0048] Based on the dynamic transmission characteristics of the natural gas system, the carbon flow density and carbon flow rate at the inlet and outlet of the natural gas pipeline at the same moment are expressed as follows:

[0049]

[0050]

[0051] in, and Let represent the inlet carbon flow density and carbon flow rate of the pipeline during time period t, respectively; and Let represent the outlet carbon flow density and carbon flow rate of the pipeline during time period t, respectively; and These represent the inlet and outlet natural gas flow rates of the pipeline during time period t (p).

[0052] Determine the gas storage variation relationship inside the pipeline:

[0053]

[0054] Among them, h p,t The gas storage capacity during pipeline period p is t.

[0055] The carbon flow density at the pipeline outlet and the carbon flow density in the pipeline storage at the same time period are:

[0056]

[0057]

[0058] in, This represents the carbon flow density corresponding to the gas stored in the pipeline during the current time period. This represents the carbon flow density at the pipe inlet during the current time period. This represents the carbon flow density at the pipeline outlet during the current time period.

[0059] According to the energy allocation criteria, the carbon flux density at the pipeline inlet is equal to the carbon flux density at the injection node of the pipeline, which is:

[0060]

[0061] Based on the carbon flow density at the nodes of the natural gas system, the following is obtained:

[0062]

[0063] A second aspect of this application provides a carbon emission metering device for a natural gas system, comprising: multiple natural gas source-side carbon meters connected to a natural gas source for measuring carbon emissions from the natural gas source; multiple natural gas pipeline carbon meters connected to a natural gas pipeline, the natural gas source-side carbon meters and the natural gas pipeline carbon meters being connected together for measuring carbon emissions from the natural gas pipeline; multiple user-side carbon meters, one end of each user-side carbon meter connected to a natural gas user and the other end connected to the natural gas pipeline carbon meters, for obtaining the carbon potential of the node where the user is located and obtaining the carbon emissions caused by the natural gas consumption of each user; and a central server connected to the multiple natural gas source-side carbon meters and the multiple natural gas pipeline carbon meters, for calculating the carbon emission intensity of the natural gas source based on the gas flow data and its carbon emission coefficient, calculating the distribution of carbon emission flow in the natural gas pipeline, and calculating the carbon emissions corresponding to the pipelines connected to the nodes based on the data from the natural gas pipeline carbon meters.

[0064] Optionally, in one embodiment of this application, the carbon meter is also used to display in real time the carbon emission results of the natural gas system calculated by the central server.

[0065] A third aspect of this application provides an electronic device, including: a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein the processor executes the program to perform the carbon emission metering method for a natural gas system as described in the above embodiments.

[0066] A fourth aspect of this application provides a computer-readable storage medium having a computer program stored thereon, which is executed by a processor to perform the carbon emission metering method for a natural gas system as described in the above embodiments.

[0067] The beneficial effects of the embodiments of this application are as follows:

[0068] 1) The carbon steady-state emission flow model of the natural gas system in this application can identify the details of carbon emissions in each link of the natural gas system, including node carbon flow density, pipeline carbon flow density, network loss carbon emissions, pipeline carbon flow rate and natural gas load carbon flow rate, thereby reasonably and effectively distributing the "carbon reduction" task on the source side to the entire "source-grid-load" chain, and further clarifying the carbon emission responsibilities of each link of the natural gas system.

[0069] 2) This application takes into account the dynamic transmission and storage characteristics of natural gas systems, constructs a dynamic carbon emission flow model for natural gas systems, realizes accurate measurement of carbon emissions from natural gas systems, and can grasp the current status and trend of carbon emissions in the system in real time, accurately and comprehensively, which is conducive to further exploring the carbon emission reduction potential of the system.

[0070] 3) The carbon meter system of this application, with the help of a data acquisition, processing and display system, can intuitively display the calculation results of the carbon meter system to natural gas users, which is conducive to a comprehensive understanding of the current status and trend of carbon emissions in the natural gas system and has high application value.

[0071] Additional aspects and advantages of this application will be set forth in part in the description which follows, and in part will be obvious from the description, or may be learned by practice of this application. Attached Figure Description

[0072] The above and / or additional aspects and advantages of this application will become apparent and readily understood from the following description of the embodiments taken in conjunction with the accompanying drawings, wherein:

[0073] Figure 1 This is a flowchart of a carbon emission metering method for a natural gas system according to an embodiment of this application;

[0074] Figure 2 This is a structural diagram of a carbon emission metering method for a natural gas system according to an embodiment of this application.

[0075] Figure 3 This is a schematic diagram of the solution results for the steady-state carbon emission flow of a natural gas system according to an embodiment of this application;

[0076] Figure 4 This is a schematic diagram of the solution results for the dynamic carbon emission flow of a natural gas system according to an embodiment of this application;

[0077] Figure 5 This is an example diagram of a carbon emission metering device for a natural gas system according to an embodiment of this application;

[0078] Figure 6 A schematic diagram of the structure of the electronic device provided in the application embodiment. Detailed Implementation

[0079] The embodiments of this application are described in detail below. Examples of these embodiments are shown in the accompanying drawings, wherein the same or similar reference numerals denote the same or similar elements or elements having the same or similar functions throughout. The embodiments described below with reference to the accompanying drawings are exemplary and intended to explain this application, and should not be construed as limiting this application.

[0080] Figure 1 This is a flowchart of a carbon emission metering method for a natural gas system according to an embodiment of this application.

[0081] like Figure 1 As shown, the carbon emission measurement method for this natural gas system includes the following steps:

[0082] In step S101, the steady-state carbon emissions of the current natural gas system are obtained using a pre-trained steady-state carbon emission flow model of the natural gas system. The steady-state carbon emission flow model of the natural gas system is based on the carbon flow density of natural gas system nodes, carbon flow density of pipelines, carbon emissions from network losses, carbon flow rate of pipelines, and carbon flow rate of natural gas load.

[0083] It is understood that the embodiments of this application establish a steady-state carbon emission flow model of a natural gas system based on carbon emission flow theory, and use the constructed steady-state carbon emission flow model of the natural gas system to obtain the current steady-state carbon emissions of the natural gas system.

[0084] Specifically, the steady-state carbon emission flow model for a natural gas system consists of node carbon flow density, pipeline carbon flow density, network loss carbon emissions, pipeline carbon flow rate, and natural gas load carbon flow rate. The specific steps are as follows:

[0085] 1-1) According to the energy mixing criterion, the carbon flow density of a natural gas system node is equal to the quotient of the total carbon flow rate of pipeline injection and gas source injection and the total natural gas flow. The carbon flow density of the natural gas system node is determined as follows:

[0086]

[0087] in, f represents the carbon flux density at node g in the natural gas system, expressed in tCO2 / MWh. p The gas flow in pipeline p in the natural gas system is expressed in km. 3 / h;f w The output of the gas source w is expressed in km. 3 / h; ξ represents 1km 3 The unit conversion constant between natural gas and 1 MWh of electricity, i.e., the energy value (calorific value) of a unit of natural gas, is taken here as 10.45 MWh / km². 3 ; The carbon flow rate of pipe p is expressed in tCO2 / h. This represents the carbon emission factor of natural gas, which is the carbon emission produced by burning one unit of natural gas. Here, the standard value is taken as 0.20 tCO2 / MWh. The set of pipelines that inject natural gas into node g of the natural gas system; Ω represents the set of gas sources that inject natural gas into node g of the natural gas system. NG It is a set of nodes in a natural gas system.

[0088] 1-2) According to the energy allocation criteria, the carbon flow density of the natural gas system pipeline is equal to the carbon flow density of the injection node. The carbon flow density of the natural gas system pipeline is determined as follows:

[0089]

[0090] in, Here is the carbon flux density of the natural gas pipeline p, expressed in tCO2 / MWh. Ω represents the injection node of natural gas pipeline p; BG It is a collection of natural gas pipelines.

[0091] 1-3) Due to pressure losses during natural gas transmission, compressors are typically used in systems to pressurize pipelines and ensure reliable long-distance transmission of natural gas. The operation of these compressors consumes energy, thus causing network-related carbon emissions. There are two common types of compressors used in natural gas systems: electric compressors and turbo compressors. The former is powered by electricity, while the latter uses natural gas from the network. The network-related carbon emissions of the natural gas system compressors are determined through the following steps:

[0092] 1-3-1) For electric compressors, carbon emissions from the compressor depend not only on the compressor's energy consumption but also on the carbon flux density of the power grid node to which the compressor is connected. The higher the carbon flux density of the power grid node where the compressor is located, the greater the carbon emissions per unit of energy consumption of the compressor. The specific determination of the grid loss carbon flux rate of the electric compressor is as follows:

[0093]

[0094] in, Carbon flux density, representing the amount of electricity consumed by the electric compressor, is expressed in tCO2 / MWh. Ω represents the electrical node connected to the electric compressor m. CM1 It is a collection of electric compressors.

[0095] If a natural gas system has an electric compressor, it is equivalent to a portion of virtual carbon emissions from the power grid entering the natural gas system. In this case, the carbon emission flow of the natural gas system will be affected by the carbon emission flow from the power grid. The carbon emission flow in the natural gas system will be the superposition of the actual carbon emission flow formed by the natural gas flow and the virtual carbon emission flow from the power grid.

[0096] 1-3-2) The turbo compressor obtains natural gas directly from the pipeline. Its corresponding network loss carbon flow rate depends on the compressor's energy consumption and the carbon flow density of the natural gas system pipeline. The network loss carbon flow rate of the turbo compressor is determined as follows:

[0097]

[0098] in, The carbon flux density of the natural gas pipeline p is expressed in units of tCO2 / MWh. This indicates the natural gas pipeline connected to the turbine compressor m; v m Natural gas consumed by the turbo compressor; Ω CM2 It is a collection of turbo compressors.

[0099] 1-4) Similar to power transmission lines, the carbon emission flow of natural gas pipelines also comprises two parts: the coupled carbon emissions from the pipeline natural gas flow, and the carbon emissions corresponding to the energy consumption of the compressors on the pipeline. Likewise, it is necessary to distinguish between the two allocation methods for compressor network loss carbon emissions to determine the carbon flow rate of the natural gas system pipeline, as detailed below:

[0100]

[0101] Where X is the carbon emission allocation coefficient for network loss; This indicates the compressor connected to pipe p.

[0102] 1-5) The carbon flow rate of natural gas load is equal to the product of the load size and the carbon flow density at the node where the load is located. The carbon flow rate of natural gas load is determined as follows:

[0103]

[0104] in, The carbon flow rate is given by the natural gas load d, in units of tCO2 / h; f d This represents the magnitude of the natural gas load d, in km². 3 / h; This indicates the node where the natural gas load d is located.

[0105] The above embodiments constitute a steady-state carbon emission flow model for a natural gas system. The known quantities in the model are the energy flow variables of the natural gas system, including the pipeline flow rate f. p Gas source output f w Compressor energy consumption P m and v m and natural gas load f d The main carbon emission flow variables that need to be solved are pipeline carbon flow density. Node carbon flux density Pipeline carbon flow rate Compressor network loss carbon flow rate and load carbon flow rate

[0106] After constructing the steady-state carbon emission flow model of the natural gas system, the embodiments of this application further include: calculating the matrix representation of the steady-state carbon emission flow model of the natural gas system.

[0107] Specifically, the matrix representation of the steady-state carbon emission flow model of the natural gas system is calculated, including: constructing the node energy flow matrix, branch energy flow matrix, and gas source injection matrix of the natural gas system; performing matrix operations based on the node energy flow matrix, branch energy flow matrix, and gas source injection matrix of the natural gas system to obtain the node carbon flow density vector, and calculating the pipeline carbon flow rate matrix, network loss carbon flow rate matrix, and natural gas load carbon flow rate vector.

[0108] The following section details the process of establishing the matrix expression for a steady-state carbon emission flow model of a natural gas system. The specific steps are as follows:

[0109] 2-1) Construct the nodal energy flow matrix, branch energy flow matrix, and gas source injection matrix of the natural gas system; the specific steps are as follows:

[0110] 2-1-1) Determine the relationship between the nodal energy flux matrix, the branch energy flow matrix, and the gas source injection matrix, as shown in the following expression:

[0111]

[0112] Among them, F N Here is the energy flux matrix for the nodes of the natural gas system; N NG and N GG These represent the number of nodes and the number of gas sources, respectively; F B and F G These are the branch energy flow matrix and the gas source injection matrix, respectively.

[0113] 2-1-2) Based on the carbon flow density of the natural gas system nodes and pipelines described above, the following expression is determined:

[0114]

[0115]

[0116] Equation (8) applies to the case where the compressor in the natural gas system is a turbo compressor; Equation (9) applies to the case where the compressor in the natural gas system is an electric compressor; ρ NG and ρ GG Each is from step 1-1) The nodal carbon flux density vector formed by and The carbon flux density vector formed by the gas source; F BL The branch network loss matrix; This represents a column vector related to the carbon flux density of the electrical nodes connected to the compressor, where node g is the first node of the electric compressor and the carbon flux density of the electrical nodes connected to the compressor is ρ. NG hour, otherwise

[0117] 2-2) Based on the matrix expression in step 2-1), matrix operations can be performed to obtain the nodal carbon flux density vector ρ. NG Then, the carbon flow rate matrix of the branch (pipeline), the carbon flow rate matrix of the network loss (compressor), and the carbon flow rate vector of the natural gas load can be calculated, as follows:

[0118]

[0119]

[0120]

[0121] in, The carbon flow rate matrix for the pipeline; The carbon flow rate matrix represents the network loss. f is the carbon flow rate vector of natural gas load; d This is the natural gas load vector.

[0122] Based on the matrix expression described above, the carbon flow density in the pipeline, the carbon flow density at the nodes, the carbon flow rate in the pipeline, the network loss carbon flow rate of the compressor, and the load carbon flow rate of the natural gas system can be obtained.

[0123] In step S102, the dynamic carbon emissions of the current natural gas system are obtained using a pre-trained dynamic carbon emission flow model of the natural gas system. The dynamic carbon emission flow model of the natural gas system is based on the Bernoulli equation for non-ideal fluids, carbon flow density and carbon flow rate at the pipeline inlet, and carbon flow density and carbon flow rate at the pipeline outlet.

[0124] It is understood that the embodiments of this application take into account the dynamic transmission and storage characteristics of gas flow, establish a dynamic carbon emission flow model of natural gas system, and use the constructed dynamic carbon emission flow model of natural gas system to obtain the current dynamic carbon emission of natural gas system.

[0125] Specifically, the time constant of a natural gas system is typically on the order of minutes or hours, exhibiting a clear dynamic transmission process. Therefore, the flow rates at the first and last nodes of a pipeline may not be equal, implying a certain gas storage effect within the natural gas system, resulting in carbon storage within the pipeline and CO2 transfer at different times. A dynamic carbon emission flow model is established considering the dynamic transmission characteristics of the natural gas system, including the non-ideal fluid Bernoulli equation followed by gas flow transmission, the carbon flow density and rate at the pipeline inlet, and the carbon flow density and rate at the pipeline outlet. The specific steps are as follows:

[0126] 3-1) The transmission of gas flow follows Bernoulli's equation for non-ideal fluids. Assuming the temperature and compressibility of natural gas are constant, the transmission of natural gas in the pipeline satisfies a set of differential equations. These differential equations can be transformed into a set of easily solvable algebraic equations using the finite element method, as shown below:

[0127]

[0128]

[0129] Where π(x,t) and f(x,t) represent the natural gas pressure and flow rate at location x and time period t, respectively; C1 and C2 are constants related to pipeline parameters; Δt and Δx represent the time interval and spatial step, respectively.

[0130] 3-2) Considering dynamic transmission characteristics, the carbon flow density and carbon flow rate at the inlet of the natural gas pipeline at the same moment may not be equal to those at the outlet of the pipeline, specifically as follows:

[0131]

[0132]

[0133] in, and Let represent the inlet carbon flow density and carbon flow rate of the pipeline during time period t, respectively; and Let represent the outlet carbon flow density and carbon flow rate of the pipeline during time period t, respectively; and These represent the inlet and outlet natural gas flow rates of the pipeline during time period t (p).

[0134] 3-3) Simultaneously, the gas storage effect exhibited by the pipeline can be modeled as a virtual natural gas energy storage system. The difference from real energy storage is that injection and outflow occur simultaneously at both ends of the pipeline, while the injection and outflow of real energy storage do not occur at the same time. The specific steps are as follows:

[0135] 3-3-1) Determine the gas storage changes within the pipeline, as follows:

[0136]

[0137] Among them, h p,t Let t be the gas storage capacity of the pipeline during time period p.

[0138] 3-3-2) Based on the concept of virtual pipeline energy storage, the carbon flow density corresponding to the gas stored in the pipeline during the current time period is equal to the average carbon emission per unit natural gas flow resulting from the superposition of the natural gas flow at the pipeline inlet and the gas stored in the pipeline during the previous time period. Furthermore, the carbon flow density at the pipeline outlet and the carbon flow density of the gas stored in the pipeline are always equal during the same time period, as detailed below:

[0139]

[0140]

[0141] in, This represents the carbon flow density corresponding to the gas stored in the pipeline during the current time period. This represents the carbon flow density at the pipe inlet during the current time period. This represents the carbon flow density at the pipeline outlet during the current time period.

[0142] 3-4) According to the energy allocation criteria, the carbon flow density at the pipeline inlet is still equal to the carbon flow density at the injection node of the pipeline, as follows:

[0143]

[0144] 3-5) The carbon flow density at each node in the natural gas system still depends on all the injected gas flows at that node during the current time period. Based on step 1-1) the carbon flow density at each node in the natural gas system, we can obtain:

[0145]

[0146] Based on the aforementioned dynamic carbon emission flow model of the natural gas system, gas pressure, flow rate, and pipeline gas storage are all determined by the energy flow of the natural gas system and are considered boundary conditions of the model. The solution yields the carbon flow density at multiple time points of the natural gas system, the carbon flow density and rate at the pipeline inlet, the carbon flow density and rate at the pipeline outlet, the carbon flow density of the pipeline gas storage, as well as the compressor carbon flow rate and the load carbon flow rate.

[0147] In step S103, the carbon emissions of the current natural gas system are calculated based on the steady-state carbon emissions and the dynamic carbon emissions.

[0148] like Figure 2 The diagram illustrates the framework of a natural gas system carbon emission metering method according to an embodiment of this application. Figure 2 Based on the steady-state carbon emission flow model and the dynamic carbon emission flow model of the natural gas system constructed by the method shown, steady-state and dynamic carbon emission indicators of the natural gas system are obtained.

[0149] In one specific embodiment of this application, it is mainly based on an 11-node natural gas system. The network structure and its steady-state carbon emission flow calculation results are as follows: Figure 3 As shown in the figure, the carbon emissions transferred from the natural gas system to the gas turbine unit are 471.26 tCO2 / h, and the carbon emissions from network losses caused by compressor energy consumption are 13.31 tCO2 / h.

[0150] Based on the dynamic carbon emission flow model of the natural gas system proposed in this application, the carbon flow density at node 11 of the natural gas system at different time periods was calculated, such as... Figure 4 As shown.

[0151] The carbon emission metering method for natural gas systems proposed in this application establishes a steady-state carbon emission flow model based on carbon emission flow theory and provides corresponding matrix calculation expressions. Considering the dynamic transmission and storage characteristics of gas flow, a dynamic carbon emission flow model for the natural gas system is established, and the steady-state and dynamic carbon emission indicators of the natural gas system are obtained by solving this model. This effectively identifies the details of carbon emissions at each stage of the natural gas system, clarifies the carbon emission responsibilities of the source, grid, and load sides, and achieves accurate measurement of carbon emissions from the natural gas system. Furthermore, with the help of a data acquisition, processing, and display system, the calculation results of the carbon meter system can be intuitively presented to natural gas users, which is beneficial for a comprehensive understanding of the current status and trends of carbon emissions in the natural gas system and has high application value.

[0152] Next, the carbon emission metering device for a natural gas system according to an embodiment of this application is described with reference to the accompanying drawings.

[0153] Figure 5 This is an example diagram of a carbon emission metering device for a natural gas system according to an embodiment of this application.

[0154] like Figure 5 As shown, the carbon emission metering device for this natural gas system includes: multiple carbon meters on the natural gas source side, multiple carbon meters on the natural gas pipeline side, multiple carbon meters on the user side, and a central server.

[0155] Among them, the carbon meter on the natural gas source side is connected to the natural gas source and is used to measure carbon emissions on the natural gas source side.

[0156] The carbon meter for natural gas pipelines is connected to the natural gas pipeline, and the carbon meter on the natural gas source side is connected to the carbon meter on the natural gas pipeline to measure carbon emissions from the natural gas pipeline.

[0157] One end of the user-side carbon meter is connected to the natural gas user's end, and the other end is connected to the natural gas pipeline carbon meter. It is used to obtain the carbon potential of the node where the user is located and to obtain the carbon emissions caused by each user's natural gas consumption.

[0158] The central server, acting as the computing center, is responsible for calculating the carbon emission flow of the system and communicating with carbon meters distributed in various stages to obtain the carbon emission information of each stage. The central server is connected to multiple carbon meters on the natural gas source side and multiple carbon meters on the natural gas pipeline side. It is used to calculate the carbon emission intensity of the natural gas source based on the gas flow data and its carbon emission coefficient, and to calculate the distribution of carbon emission flow in the natural gas pipeline. Based on the data from the natural gas pipeline carbon meters, it calculates the carbon emission amount corresponding to the pipeline connected to the node.

[0159] Optionally, in one embodiment of this application, the carbon meter is also used to display in real time the carbon emission results of the natural gas system calculated by the central server.

[0160] In the embodiments of this application, carbon meters are used to collect and calculate the information required for carbon emission measurement, and transmit the relevant information to a central server. The central server uses the collected information to calculate the carbon emissions of the natural gas system, feeds back the calculation results to each carbon meter, and then each carbon meter displays the calculation results fed back by the central server in real time.

[0161] In the embodiments of this application, a carbon meter system is composed of multiple carbon meters. The carbon meter system is a hierarchical system, consisting of an upper layer and a lower layer. The upper layer system includes a central server, natural gas source-side carbon meters, and natural gas pipeline carbon meters. It is used to calculate the carbon emission intensity of the natural gas source based on the gas flow data and its carbon emission coefficient, and then calculate the distribution of carbon emission flow in the natural gas pipeline. Based on the data from the natural gas pipeline carbon meters, it calculates the carbon emission amount corresponding to the pipeline connected to the node. The lower layer system consists of user-side carbon meters. The user-side carbon meters communicate with the natural gas pipeline carbon meters to obtain the carbon potential of the node where the user is located and to obtain the carbon emission amount caused by the natural gas consumption of each user.

[0162] It should be noted that the foregoing explanation of the embodiment of the carbon emission metering method for natural gas systems also applies to the carbon emission metering device for natural gas systems in this embodiment, and will not be repeated here.

[0163] The carbon emission metering device for a natural gas system proposed in this application consists of carbon meters distributed throughout the natural gas system for measuring carbon emissions, a central server, and communication lines. Specifically, it is divided into carbon meters on the natural gas source side, carbon meters on the natural gas pipeline side, and carbon meters on the natural gas user side. This effectively identifies the details of carbon emissions at each stage of the natural gas system (source, network, and load), clarifies the carbon emission responsibilities of the three sides, and achieves accurate measurement of carbon emissions in the natural gas system, thus possessing high application value.

[0164] Figure 6 A schematic diagram of the structure of an electronic device provided in an embodiment of this application. The electronic device may include:

[0165] The memory 601, the processor 602, and the computer program stored on the memory 601 and capable of running on the processor 602.

[0166] When the processor 602 executes the program, it implements the carbon emission measurement method for the natural gas system provided in the above embodiments.

[0167] Furthermore, electronic devices also include:

[0168] Communication interface 603 is used for communication between memory 601 and processor 602.

[0169] The memory 601 is used to store computer programs that can run on the processor 602.

[0170] The memory 601 may include high-speed RAM memory, and may also include non-volatile memory, such as at least one disk storage device.

[0171] If the memory 601, processor 602, and communication interface 603 are implemented independently, then the communication interface 603, memory 601, and processor 602 can be interconnected via a bus to complete communication between them. The bus can be an Industry Standard Architecture (ISA) bus, a Peripheral Component Interconnect (PCI) bus, or an Extended Industry Standard Architecture (EISA) bus, etc. Buses can be categorized as address buses, data buses, control buses, etc. For ease of representation, Figure 6The bus is represented by a single thick line, but this does not mean that there is only one bus or one type of bus.

[0172] Optionally, in a specific implementation, if the memory 601, processor 602, and communication interface 603 are integrated on a single chip, then the memory 601, processor 602, and communication interface 603 can communicate with each other through an internal interface.

[0173] The processor 602 may be a central processing unit (CPU), an application specific integrated circuit (ASIC), or one or more integrated circuits configured to implement the embodiments of this application.

[0174] This embodiment also provides a computer-readable storage medium storing a computer program, characterized in that the program, when executed by a processor, implements the above-described method for measuring carbon emissions from a natural gas system.

[0175] In the description of this specification, the references to terms such as "one embodiment," "some embodiments," "example," "specific example," or "some examples," etc., indicate that a specific feature, structure, material, or characteristic described in connection with that embodiment or example is included in at least one embodiment or example of this application. In this specification, the illustrative expressions of the above terms do not necessarily refer to the same embodiment or example. Furthermore, the specific features, structures, materials, or characteristics described may be combined in any suitable manner in one or more embodiments or examples. Moreover, without contradiction, those skilled in the art can combine and integrate the different embodiments or examples described in this specification, as well as the features of different embodiments or examples.

[0176] Furthermore, the terms "first" and "second" are used for descriptive purposes only and should not be construed as indicating or implying relative importance or implicitly specifying the number of technical features indicated. Thus, a feature defined as "first" or "second" may explicitly or implicitly include at least one of that feature. In the description of this application, "N" means at least two, such as two, three, etc., unless otherwise explicitly specified.

[0177] Any process or method described in the flowchart or otherwise herein can be understood as representing a module, segment, or portion of code comprising one or more N executable instructions for implementing custom logic functions or processes, and the scope of the preferred embodiments of this application includes additional implementations in which functions may be performed not in the order shown or discussed, including substantially simultaneously or in reverse order depending on the functions involved, as should be understood by those skilled in the art to which embodiments of this application pertain.

[0178] It should be understood that the various parts of this application can be implemented using hardware, software, firmware, or a combination thereof. In the above embodiments, the N steps or methods can be implemented using software or firmware stored in memory and executed by a suitable instruction execution system. For example, if implemented in hardware as in another embodiment, it can be implemented using any one or a combination of the following techniques known in the art: discrete logic circuits having logic gates for implementing logical functions on data signals, application-specific integrated circuits (ASICs) having suitable combinational logic gates, programmable gate arrays (PGAs), field-programmable gate arrays (FPGAs), etc.

[0179] Those skilled in the art will understand that all or part of the steps of the methods described in the above embodiments can be implemented by a program instructing related hardware. The program can be stored in a computer-readable storage medium, and when executed, it includes one or a combination of the steps of the method embodiments.

Claims

1. A method for measuring carbon emissions from a natural gas system, characterized in that, Includes the following steps: The steady-state carbon emissions of the current natural gas system are obtained using a pre-trained steady-state carbon emission flow model of the natural gas system, wherein the steady-state carbon emission flow model of the natural gas system is based on the carbon flow density of natural gas system nodes, carbon flow density of pipelines, carbon emissions from network losses, carbon flow rate of pipelines, and carbon flow rate of natural gas load. The dynamic carbon emissions of the current natural gas system are obtained using a pre-trained dynamic carbon emission flow model of the natural gas system, wherein the dynamic carbon emission flow model of the natural gas system is based on the Bernoulli equation for non-ideal fluids, carbon flow density and carbon flow rate at the pipeline inlet, and carbon flow density and carbon flow rate at the pipeline outlet. The carbon emissions of the current natural gas system are calculated based on the steady-state carbon emissions and the dynamic carbon emissions. Based on the non-ideal fluid Bernoulli equation governing the gas flow, a dynamic carbon emission flow model for the natural gas system is established using the carbon flow density and rate at the pipe inlet and outlet. Specifically: The non-ideal fluid Bernoulli equation followed by the airflow transport is: in, and They represent the positions respectively. Time period t Natural gas pressure and flow rate; and These are constants related to pipeline parameters; and These represent the time interval and spatial step size, respectively. Based on the dynamic transmission characteristics of the natural gas system, the carbon flow density and carbon flow rate at the inlet and outlet of the natural gas pipeline at the same moment are expressed as follows: in, and They represent pipes p Time period t Inlet carbon flux density and carbon flux rate; and They represent pipes p Time period t Export carbon flow density and carbon flow rate; and They represent pipes p Time period t The inlet and outlet natural gas flow rates; Determine the gas storage variation relationship inside the pipeline: in, For pipelines p Time period t Gas storage capacity; The carbon flow density at the pipeline outlet and the carbon flow density in the pipeline storage at the same time period are: in, This represents the carbon flow density corresponding to the gas stored in the pipeline during the current time period. This represents the carbon flow density at the pipe inlet during the current time period. This represents the carbon flow density at the pipeline outlet during the current time period. According to the energy allocation criteria, the carbon flux density at the pipeline inlet is equal to the carbon flux density at the injection node of the pipeline, which is: Based on the carbon flow density at the nodes of the natural gas system, the following is obtained: 。 2. The method according to claim 1, characterized in that, Also includes: A steady-state carbon emission flow model for the natural gas system is established based on the node carbon flow density, pipeline carbon flow density, network loss carbon emissions, pipeline carbon flow rate, and natural gas load carbon flow rate. Specifically: Based on the energy blending criteria, the node carbon flow density of the natural gas system is determined as follows: in, For nodes in natural gas systems The carbon flux density is expressed in tCO2 / MWh. For pipelines in natural gas systems airflow, measured in km 3 / h; gas source The output, measured in km. 3 / h; Indicates 1 km 3 The unit conversion constant between natural gas and 1 MWh of electrical energy; For pipelines The carbon flow rate, expressed in tCO2 / h; Indicates the carbon emission factor of natural gas; To natural gas system nodes A collection of pipelines used for injecting natural gas; To natural gas system nodes A collection of gas sources into which natural gas is injected; A set of nodes in a natural gas system; Determine the carbon flow density of natural gas system pipelines based on energy allocation criteria; in, For natural gas pipelines The carbon flux density is expressed in tCO2 / MWh. For natural gas pipelines The injection node; A collection of natural gas pipelines; Determining the network loss carbon emissions of the natural gas system compressor includes: determining the network loss carbon flow rate of the electric compressor. in, Carbon flux density of electricity consumed by electric compressors, expressed in tCO2 / MWh; For electric compressors Connected power nodes; It is a collection of electric compressors; Determine the carbon flow rate of the turbo compressor network loss: in, For natural gas pipelines The carbon flux density is expressed in tCO2 / MWh. For turbo compressors Connected natural gas pipeline; Natural gas consumed by the turbo compressor; A collection of turbo compressors; Determine the carbon flow rate of the natural gas system pipeline: in, This is the carbon emission allocation coefficient for network loss; Indicates with pipes Connected compressor; Determine the carbon flow rate of natural gas load: in, For natural gas load The carbon flow rate, expressed in tCO2 / h; Indicates natural gas load Size, in km 3 / h; Indicates natural gas load The node it is located at.

3. The method according to claim 2, characterized in that, Also includes: Calculate the matrix representation of the steady-state carbon emission flow model of the natural gas system.

4. The method according to claim 3, characterized in that, The calculation of the matrix representation of the steady-state carbon emission flow model of the natural gas system includes: Construct the node energy flow matrix, branch energy flow matrix, and gas source injection matrix of the natural gas system; Based on the node energy flow matrix, branch energy flow matrix, and gas source injection matrix of the natural gas system, matrix operations are performed to obtain the node carbon flow density vector, and the pipeline carbon flow rate matrix, network loss carbon flow rate matrix, and natural gas load carbon flow rate vector are calculated.

5. The method according to claim 4, characterized in that, The construction of the node energy flow matrix, branch energy flow matrix, and gas source injection matrix of the natural gas system includes: Determine the relationship between the node energy flux matrix, the branch energy flow matrix, and the gas source injection matrix: in, This is the energy flux matrix for nodes in a natural gas system. and These are the number of nodes and the number of gas sources, respectively. and These are the branch energy flow matrix and the gas source injection matrix, respectively; Based on the carbon flow density of the natural gas system nodes and pipelines, the following is obtained: in, and They are respectively from The nodal carbon flux density vector formed by and The resulting carbon flux density vector from the gas source; The branch network loss matrix; This represents a column vector related to the carbon flux density of the electrical nodes connected to the compressor. It is the first node of the electric compressor, and the carbon flux density of the power node connected to the compressor is... hour, ,otherwise .

6. The method according to claim 5, characterized in that, The step of performing matrix operations to obtain the node carbon flow density vector based on the node energy flow matrix, branch energy flow matrix, and gas source injection matrix of the natural gas system, and calculating the pipeline carbon flow rate matrix, network loss carbon flow rate matrix, and natural gas load carbon flow rate vector, includes: in, The carbon flow rate matrix for the pipeline; The carbon flow rate matrix represents the network loss. Here is the carbon flow rate vector for natural gas load; This is the natural gas load vector.

7. An electronic device, characterized in that, include: A memory, a processor, and a computer program stored in the memory and executable on the processor, the processor executing the program to implement the carbon emission metering method for a natural gas system as described in any one of claims 1-6.

8. A computer-readable storage medium having a computer program stored thereon, characterized in that, The program is executed by the processor to implement the carbon emission metering method for a natural gas system as described in any one of claims 1-6.

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