Substation automation systems and unmanned substations have developed rapidly since the 1990s. This paper analyzes the structure of substation automation systems based on the report "Communication Requirements for Data Flows in Substations" published by Working Group 34.03 of the International Conference on Large Electric Systems (CIGRE) in August 1997. It points out the advantages of using fieldbus to integrate various intelligent electronic instruments (IEDs) to construct substation automation systems. The paper discusses relevant issues in the implementation of substation automation, such as the role of relay protection and remote control devices in substation automation systems, the requirements for sequence of events (SOE) resolution, and anti-interference measures for substation automation systems, and proposes suggestions.
1. Analysis of Substation Automation Systems
In its report "Communication Requirements for Data Streams in Substations," presented at the International Conference on Large Electric Systems (CIGRE) in August 1997 [1, 2], Working Group WG34.03 analyzed 63 functions that substation automation needs to perform and divided these functions into 7 functional groups:
(1) Telemetry function (four remote functions);
(2) Automatic control functions (such as integrated control of on-load tap changer taps and parallel compensation capacitors (VQC). Low-frequency load shedding in power systems, control of static var compensators, fault isolation/restoration of power supply to non-faulty sections and network reorganization, etc.).
(3) Metering functions (such as three-phase intelligent electronic electricity meter, etc.);
(4) Relay protection function;
(5) Functions related to relay protection (such as fault recording, fault location, low current grounding line selection, etc.).
(6) Interface functions (such as interfaces with IEDs for microcomputer-based five-proof, relay protection, power metering, global positioning system (GPS) etc.)
(7) System functions (communication with the main station, local SCADA, etc.).
All devices capable of performing these functions are currently collectively referred to as intelligent electronic instruments (IEDs). The purpose of substation automation is to achieve information sharing among these IEDs, thereby reducing the number and cost of cables used in the substation, improving the operation and safety reliability of the substation, and reducing maintenance workload while improving maintenance levels.
It should be noted that:
(1) All of the above-mentioned automated equipment should have clear responsibilities and not interfere with each other.
(2) Special attention should be paid to the safety and reliability of relay protection equipment and the electromagnetic compatibility requirements of relay protection equipment should not be affected.
Based on the purpose of substation automation, a hierarchical structure is required to achieve information sharing: substation layer (communication with the upper-level dispatch center, local SCADA, etc.), network layer (to realize information integration of various IEDs), bay layer (various IEDs), and equipment layer (high-voltage primary equipment).
2. Implementing substation automation systems using fieldbus networks
For substation automation, the performance of the network layer is crucial, as it integrates moving parts, relay protection devices, various automatic control devices, and intelligent electronic instruments such as electricity metering devices. Fieldbus, which matured in the mid-1990s, is a superior network system for achieving IED integration.
The International Electrotechnical Commission (IEC) proposed the concept of fieldbus. It defines fieldbus as: a digital, serial, bidirectional, multivariable, multi-node communication network connecting instruments in the industrial field with control equipment located in the control room. A fieldbus control system (FCS) is defined as: a system composed of various field instruments interconnected with a human-machine interface in the control room; it is a fully distributed, fully digital, fully open, and operable automated control system for the production process.
Automation systems employing fieldbus technology have the following characteristics:
(1) The traditional input/output (I/O) module has been changed in structure and incorporated into the field intelligent electronic instrument (IED), and collectively referred to as a node.
(2) All signals are bidirectional, and managers can monitor field equipment from the control room.
(3) Fully digital communication improves the accuracy and reliability of data transmission.
(4) All fieldbuses define user-level protocols, enabling interoperability and meeting the requirements of true openness. Unified communication protocols and configuration methods enable products from different manufacturers to interconnect, interchange, and interoperate.
(5) Simplified design and installation. Since the fieldbus only uses one twisted pair cable, it can connect many field instruments, which simplifies the wiring design, saves a lot of cables, and simplifies the installation.
(6) Each node should be able to self-diagnose. When a node fails, it should be able to automatically stop operating without affecting the operation of other nodes.
(7) It is easy to expand equipment and modify products.
Currently, fieldbus products worldwide include LonWorks from Echelon in the United States, CAN from Bosch in Germany, and Profibus from Siemens.
Since the various automation equipment and relay protection devices used in substations do not use fieldbus networks or fieldbus networks that integrate substation automation IEDs, it is necessary to design an integration node so that IEDs from different manufacturers and networks can be connected to the selected fieldbus network.
Since LanWorks was excluded from international standards at the 63rd IEC Annual Meeting held in Kyoto, Japan in October 1999, special attention must be paid to fieldbus products that conform to international standards.
Even though LonWorks is not listed as an international standard, there are domestic manufacturers that produce products compatible with it, and many users use LonWorks. Therefore, this article will still introduce the features of LonWorks and related products.
LonWorks Fieldbus is a widely used fully distributed intelligent control network technology. It is a mature product for realizing the network layer of substation automation systems. The network communication medium is unrestricted and can be twisted pair, fiber optic, power line, wireless, infrared, etc., and can be used in combination within the same network.
The technical characteristics of LonWorks web are:
(1) The basic component is the Neuron chip. It has communication and control functions and has embedded all seven layers of the ISO/CSI protocol, as well as 34 common I/O control objects.
(2) The Ethernet CSMA protocol is modified to the Predictive P-Persistent CSMA protocol. This protocol retains the advantages of Ethernet Sense Multiple Access and overcomes its shortcomings in control applications. Nodes are randomly distributed across different delay levels in a minimum of 16 random time slots. When the network is idle, all nodes are randomly distributed across only 16 slots. When an increase in load is anticipated, nodes will be distributed across more time slots, the number of which is determined by n. n is an estimate of the backlog of work on the channel (from 1 to 63), representing the number of nodes that will send data packets next. A priority mechanism is selectively provided to improve the response time to important data packets.
(3) The Neuron chip is the core of LonWorks technology. It has three 8-bit CPUs to perform media access, network processing and application processing respectively.
(4) The network communication adopts an object-oriented design method called "network variables", which simplifies the design of network communication to parameter setting.
(5) The number of valid bytes per frame of communication can range from 0 to 228B.
(6) Communication rate: 1.25Mb/s, twisted pair, effective distance 130m; 78kb/s, twisted pair, effective distance 2700m.
(7) The communication protocol of LonWroks is called LonTalk protocol, its interoperability standard is LonMark, and its network service operating system is LNS.
(8) The LonTalk protocol defines a hierarchical logical addressing method for domains, subnets, and node addresses. A subnet can include a maximum of 127 nodes, and a domain can define a maximum of 255 subnets, thus allowing a maximum of 32385 (255 × 127) nodes within a domain. A domain is a logical combination of nodes on one or more channels. Communication can only occur between nodes configured within the same domain. Multiple domains can use the same channel. Domains can prevent interference between nodes on different networks.
(9) The LonWorks network can be connected to the Ethernet via the RTLE-KT-03001 gateway. It can also be connected to the Internet or the China Power Information Data Exchange Network via the WBLE-KT-00001 gateway. Both of these gateways are manufactured by Coactive Networks, Inc. of the United States.
ILEX Systems Inc. of the United States has produced a substation automation system using the LonWorks fieldbus network, with integrated nodes called serial nodes. Each serial node can connect 256×8 remote signaling quantities, 128×8 remote measurement quantities, and 32×8 remote control quantities using the same protocol. A substation automation system can connect up to 64 serial nodes. This serial node supports a wide range of communication protocols, such as CDT issued by the Ministry of Electric Power of China, DNP3.0, Modbus, SC1801, Harris 5000/6000, HDLC, QDIP (Quantum meter), PG&E2179 (Cooper 4C/CL4C/SA), etc., and can connect to IEDs from different manufacturers and networks, such as SEL's relay protection devices, Schlumberger's Quantum electricity meter, and the microcomputer-based five-prevention device produced by the Nanjing Institute of Automation. To achieve information sharing, various IEDs can be integrated into the LonWorks network simply by converting the protocol. Furthermore, the various IEDs integrated through this serial port node do not interfere with each other. New IEDs can be connected and their protocols debugged on the serial port node without power interruption, and the operation of the substation automation system will not be affected.
iLex has also designed remote control nodes (TVRs) for LonWorks networks, such as telemetry nodes (A-32), remote signaling nodes (I-64), remote control SBO nodes (C-16), and AC sampling nodes to meet the needs of automatic monitoring. For communication with the upper-level dispatch center and management of the LonWorks network, a communication node (comm) has been designed. The communication node can have up to eight slave communication nodes, each with its own communication protocol for communicating with the master station; each slave node can synchronize its own time, allowing different master stations to add their own time stamps to the SOE (Service Execution Environment) for easier power system fault analysis; it also has the capability to repair faulty nodes without power outages in the automation system, thus improving the mean time between failures (MTBF).
3. Problems in the implementation of substation automation systems
(1) The issue of naming substation automation
In its 1997 report, "Communication Requirements for Data Flows in Substations," Working Group WG34.03 of the International Conference on Large Electric Systems [1, 2] no longer used the term "integrated substation automation," but simply "substation automation," omitting the word "integrated." This was because the meaning of "integrated" was ambiguous and unclear. This terminology has been agreed upon by the IEC and the IEEE. "Substation automation" and "substation automation system" have been formally defined and incorporated into the standard terminology by IEC Technical Committee TC57.
(2) On the position of relay protection and remote control in substation automation system
The basic task of relay protection is to automatically disconnect the faulty power system components from the system in the shortest possible time and smallest possible area when a power system fault or abnormal operating condition occurs, or to give a signal to the on-duty personnel to eliminate the root cause of the abnormal operating condition, so as to avoid or mitigate equipment damage and the impact on power supply to adjacent areas.
Power grid dispatch automation systems are crucial for ensuring the safe, high-quality, and economical power generation and supply of the power grid under normal operating conditions, and for improving dispatch operation and management. Remotely operated units (RTUs) are essential automation devices installed in substations to achieve power grid dispatch automation.
Therefore, relay protection devices and remote control devices are two types of devices that perform different tasks. They each perform their respective duties in power grid dispatching and operation management without interfering with each other.
In the 1990s, my country's power grid widely adopted microprocessor-based protection devices. These devices filtered out high-frequency components from the operating parameters (analog quantities) of power system components (generators, transformers, busbars, and lines) using low-pass filters, reflecting only power frequency quantities. These parameters were then sampled using AC and converted to discrete digital values to protect the power system components. Since microprocessor-based protection can also measure the operating parameters of power grid components, this paper raises the following points for discussion regarding the feasibility of installing "microprocessor-based protection + remote control" devices in substations to achieve substation automation:
1) The performance characteristics of relay protection are safety (no false tripping), reliability (no failure to trip), speed, and sensitivity (ability to reflect faults). For relays, they do not operate when the input value is less than the operating value, and operate immediately when it is greater than the operating value. The accuracy requirement for the input signal is not as high as that for remote control. According to the sampling theorem of the Fast Fourier Transform, the sampling frequency fs must be greater than twice the highest frequency fmax in the signal. Most microprocessor-based protection systems only take the power frequency parameters in the input signal, and the sampling interval is in the range of 0.5 to 2 ms, which is equivalent to sampling only 40 to 10 points per week (20 ms). Regarding the accuracy of A/D conversion, according to the "Inspection Procedures for Microcomputer Protection Devices of Types WXH-11, WXB-11, and SWXB-11" issued by the National Dispatch Center and the Safety and Health Department of the Ministry of Electric Power (Dispatch Network [1994] No. 109), Article 11.3 of the procedure specifies the linearity requirements for each voltage and current channel: "Adjust the voltages to 60, 30, 5, and 1V respectively, and the currents to 30, 10, 1, and 0.5A respectively, and print the corresponding effective values of voltage and current for the nine channels. The error between the external meter reading and the printed value should be less than 10% at 1V, 1A, and 0.5A, and less than 2% for the others." GB/T15145-94 "General Technical Conditions for Microcomputer Line Protection Devices" stipulates: 3.7.4 Accuracy of Measuring Element Characteristics: ① Scale Error: Not greater than ±2%; ② Temperature Error: Not greater than ±3% within the operating ambient temperature range; ③ Comprehensive Error: Not greater than ±5%. This is sufficient for the microcomputer protection device to not fail to operate and to ensure a certain level of sensitivity when a fault occurs in the power grid.
However, this does not meet the requirements for power grid dispatch automation systems. The national standard GB/T13729-29, "General Technical Conditions for Remote Terminals," stipulates that the accuracy of analog telemetry A/D must be less than or equal to 0.5%; the "Operating Procedures for Power Grid Dispatch Automation Systems" DL516-93 stipulates that "the total accuracy of telemetry should not be lower than level 1.5, that is, the total error from the transmitter inlet to the dispatch display terminal, expressed as reference error, should not be greater than +1.5% and not less than -1.5%." For AC direct sampling remote control devices [3], at least 96 points per week are required to ensure correct waveform signal analysis and to meet the accuracy requirements of subsequently calculated electrical parameters. It is also hoped that 0.2-level energy meters can be supported.
2) Remote control devices operate under normal power system conditions, while relay protection devices operate under power system fault conditions. The short-circuit current during a fault will be tens of times larger than that under normal conditions, and the requirements for the CT ratio are different for the two.
3) AC sampling remote control devices require higher accuracy than relay protection devices. The equipment and personnel qualifications needed for maintenance and testing are also higher than those required for DC sampling remote control devices. AC sampling testing personnel must possess a testing certificate issued by a national testing department to be qualified to perform testing. These requirements may not be met by most substations or even power bureaus in my country. If "microcomputer protection + remote control" devices are used to achieve "integrated automation," it will be difficult for substation personnel to test and maintain the remote control components, making it challenging to achieve the accuracy required by national and industry standards for remote control.
4) Relay protection and remote control are two different professions. When a power system fault occurs or a relay protection and remote control device fails, the on-site personnel must each be responsible for managing the equipment within their jurisdiction. If a "microcomputer protection + remote control" device is used, there will be unclear responsibilities or even no one taking responsibility when a problem occurs. This is extremely detrimental to power grid dispatching. (3) Requirements for the resolution of Sequence of Events (SOE).
The National Standard GB/T13729-92 General Technical Conditions for Telecontrol Terminals stipulates that "the resolution of the accident sequence record within the station shall be ≤10ms".
The "Detailed Rules for Practical Acceptance of Power Grid and Provincial Power Grid Dispatch Automation System (Trial)" stipulates that "Session of Events (SOE) is optional, and the inter-station resolution should be less than or equal to 10ms".
The "Detailed Rules for Practical Acceptance of Regional Power Grid Dispatch Automation System" stipulates that "SOE is an optional function and does not affect practical acceptance. The inter-station resolution of SOE should be less than or equal to 20ms."
The "Technical Specification for Design of Power System Dispatch Automation" in the power industry standard DL5003-91 stipulates that "the resolution of the event sequence recording system should be less than 20ms".
The industry standard DL5002-91, Technical Specification for Design of Regional Power Grid Dispatch Automation, stipulates that "the inter-station resolution of event sequence recording shall not exceed 20ms".
The industry standard DL/T635-1997, "Specification for Functional Automation of County-level Power Grid Dispatch," stipulates that "RTU event sequence recording with an intra-station resolution of less than or equal to 10 ms is an optional feature." The basic specification for dispatch automation systems is: SOE inter-station resolution of less than or equal to 20 ms.
This article argues that the aforementioned requirements are reasonable. However, in recent years, my country has seen an increasing trend in demanding SOE (Self-Evaluation) requirements, with some tender documents for substation automation systems or remote control units (RTUs) even requiring an in-station SOE resolution of less than or equal to 1 ms. Such excessive requirements not only increase the cost of remote control units but may also have adverse effects and lead to erroneous results in power system fault analysis. The analysis is as follows:
When a power system fault occurs, the faulty component is not truly isolated until the circuit breaker completely extinguishes its arc. This process includes three stages: relay protection operation time + circuit breaker switching time + arcing time. The circuit breaker operation time collected by the SOE component in the remote control device is the time it takes for the auxiliary contacts to open during the instant the main contacts of the circuit breaker open, while the arcing time is difficult to control and measure. Please visit: Power Transmission and Distribution Equipment Network for more information.
Oil-less circuit breakers were commonly used in substations built in my country during the 1960s and 70s. Air circuit breakers, due to their complex structure and short maintenance intervals, are now rarely used. They have been replaced by sulfur hexafluoride (SF6) circuit breakers, which are widely used due to their shorter arc-extinguishing time, less burn-out of main contacts, and larger breaking capacity. In recent years, vacuum circuit breakers have also seen rapid development. Currently, newly built substations in my country mainly use oil-less, SF6, and vacuum circuit breakers, with oil-less circuit breakers being more commonly used due to their lower cost.
The arc-extinguishing mechanisms and arc-burning times of these different circuit breakers are all different. The arc-burning time includes the sum of the initial opening time and the subsequent opening time, and it is not fixed; it increases with the service life of the circuit breaker and the number of interruptions. Generally speaking, the arc-extinguishing times of different circuit breakers are as follows:
Vacuum circuit breaker 7～15ms
SF6 circuit breaker 17～25ms
• Low-oil circuit breaker 30-40ms
A substation may be equipped with only one type of circuit breaker, or it may be equipped with different types of circuit breakers.
Because the arc extinguishing time of circuit breakers varies, if the resolution requirement within the SOE station is too high, such as less than or equal to 1ms, it will cause errors in the fault analysis of the power system.
Example 1: A substation is equipped with vacuum circuit breakers of varying service life and number of interruptions. When a power system fault occurs, if the older or more frequently operated vacuum circuit breaker B1 operates first, the SOE (Service Execution Environment) first records the operating time of the auxiliary contacts of B1, with a resolution of 1 ms. Its arcing time is 15 ms.
Circuit breaker B2 operates 3ms later than B1, and its arcing time is 7ms. As a result, the actual time for B2 to disconnect the circuit (extinguish the arc) is 5ms faster than B1, i.e., 15ms - (3ms + 7ms) = 5ms.
SOE records that B1 operates 3ms before B2, but in reality, B2 disconnects the circuit 5ms faster than B1.
Example 2: A substation is equipped with different types of circuit breakers, such as SF6 circuit breakers and oil-minimum circuit breakers. When a power system fault occurs, if the main contact of an oil-minimum circuit breaker B1 operates first, the SOE immediately records this time at a resolution of 1ms, and its arcing time is 35ms. 5ms later, the main contact of an SF6 circuit breaker B2 operates, and the SOE records that it is 5ms behind B1 in terms of B2's breaking time. However, B2's arcing time is only 17ms. As a result, the actual circuit breaking (arc extinguishing) time is actually 13ms faster for B2 than for B1, i.e., 35ms - (5ms + 17ms) = 13ms.
Therefore, it is evident that excessively high SOE resolution (≤1ms) will lead to errors in power system fault analysis. It is therefore recommended that relevant organizations not require excessively high SOE resolution when selecting RTUs, but rather choose according to national and industry standards.
For distribution network automation systems, power systems below 110kV in my country are all low-current grounding systems. When a single-phase ground fault occurs, due to the small short-circuit current, the system can generally continue operating for up to 2 hours before the faulty phase is disconnected. Even with the use of FTUs and local SCADA systems to isolate the faulty section and restore power to the non-faulty section, the fastest time is close to 1 minute. Therefore, SOE (Signaling over Equivalent) functionality is completely unnecessary in the FTU; only general remote signaling functions are required, which reduces the cost of the FTU.
(4) Anti-interference measures for substation automation systems
To ensure the reliable and stable operation of substation automation systems, remote control devices must not only pass the quality inspection of the Ministry of Electric Power's Power Equipment and Instrumentation Quality Inspection Center, but also require enhanced anti-interference measures within the substation. This article analyzes and discusses the anti-interference issues within substations as follows.
1) Power supply
Most faults in automatic and remote control systems caused by external interference are due to power supply interference, with spikes and damped oscillations being the main components; followed by positive and negative deviations and short-circuit power outages. Therefore, improving the quality of the power supply system is crucial.
For the requirements and measures regarding power supply and interference immunity of automatic and remote control devices, please refer to reference [4]. This article only discusses the measures that should be considered for the substation itself.
① Pay attention to proper shielding and grounding of the power supply.
② Surge absorbers should be installed between power lines and between power lines and ground to prevent power surge voltage to ground from causing insulation breakdown of the equipment.
③ To prevent low voltage or sudden power outages in the power grid, fluctuations should be minimized.
④ A switching power supply using a flyback converter can suppress input interference signals by utilizing the energy storage function of the converter.
⑤ Power wiring
• Power leads should be as short and thick as possible, and common lines should be avoided to reduce common impedance coupling;
• Use twisted wires whenever possible to suppress electromagnetic interference;
• Various feeders should be wired separately, such as AC lines, DC lines, logic signal lines and analog signal lines, unregulated DC lines, and drive lines for inductive loads such as light bulbs and relays.
2) Interference in the transmission channel
This type of interference mainly manifests as stray electromagnetic fields entering the channel through induction and radiation, including crosstalk between multiple signal lines; interference superimposed on the signal lines due to factors such as leakage current and ground impedance coupling. To prevent this type of interference, the following measures can be taken: Please visit the Power Transmission and Distribution Equipment Network for more information.
① For signal lines with long distances, shielded twisted-pair cable or optical fiber should be used. The shielding layer must be grounded at the end affected by interference.
② Signal lines should be routed as far away as possible from other electrical lines. Power cables should be routed separately. Signal lines should be placed as close to the ground wire as possible or surrounded by a ground wire.
③The RTU and the communication equipment in the channel share a common grounding device, and are connected to the control room grounding network at a single point.
④ When using a direct cable channel (without other communication equipment as a carrier), an isolation and overvoltage protection device should be installed before the channel is connected to the Modem board.
⑤ The casing of the remote control equipment must be directly grounded. The method adopted is to connect the remote control equipment and the relay protection equipment panel with a dedicated grounding copper busbar, and connect it to the ground of the substation control building. The grounding resistance of the entire system should be less than 0.5Ω.
⑥ Different signal types and different electrical intervals cannot share a single cable, and the static induced voltage of the cable core to ground should be less than 0.5V.
⑦ For transmission channels with a length of less than 1km, a transmission module should be added to resist interference.
