With the widespread application of digital microcomputer protection, monitoring technology, and remote communication technology, the automation level of power system substations has undergone a fundamental transformation. Substation integrated automation, as a new technology, has emerged and is now widely adopted in newly built 110 kV substations in China. Through continuous improvement in practice, it has developed into a mature technology. The 220 kV Dongguan Chang'an Substation adopted integrated substation automation technology to replace the conventional substation secondary system, supported by this technological background. [b]1 Project Overview[/b] The 220 kV Dongguan Chang'an Substation (hereinafter referred to as Chang'an Station) is planned to have 6 220 kV lines, 8 110 kV lines, 3 180 MVA three-winding transformers, 24 10 kV lines, and 12 sets of 10 kV compensation capacitors. The current phase includes 4 220 kV lines, 2 to Shajiao Power Plant, and the other 2 to Xixiang Station and Gongming Station in Shenzhen, respectively. The substation has 6 110 kV outgoing lines, 2 180 MVA three-winding transformers, and uses a double busbar main connection with bypass for both 220 kV and 110 kV lines. Whether considering its scale or its position within the system, Chang'an Substation is a large-scale 220 kV hub substation, holding a very important position in the system. [b]2 Important Principles of Automation System Configuration[/b] Since Chang'an Substation is located between the main power source (Shajiao Power Plant) and the heavy load area, and is itself located at the power load center, the primary objective that the secondary automation system design must ensure is the system's safety and reliability. Any negligence or deficiency in the system's safety and reliability design, and any potential hidden dangers it may bring to the system, could cause significant power supply losses. To effectively improve the safety and reliability of the automation system, the following aspects are guaranteed: 2.1 Ensuring the complete independence of protection devices. Protection configuration is set independently according to the protection design specifications, with all bay unit protections being completely independent and unrelated. The operating conditions of the protection devices are determined solely by the protection devices themselves, and do not depend on the physical state of the computer network at any given time. In short, even if the monitoring computer network is completely paralyzed, it will not affect the correct operation of the protection device. The relationship between the protection and monitoring systems is only that the protection system sends protection action information to the monitoring system after the protection action is taken. 2.2 Object-Oriented Distributed Measurement and Control Units Although the monitoring system is less important than the protection device in the secondary system, the security and reliability of the monitoring system are still of great importance to the normal operation of the system. Therefore, extremely high requirements are placed on the reliability of the monitoring system. As we all know, the higher the degree of functional integration of any device, the lower the relative functional cost of the hardware, but the greater the system risk caused by its failure. In order to effectively reduce the impact of the failure of a component in the system, distributed measurement and control units are adopted. From the 10 kV feeder to the 220 kV line bay, each bay is equipped with one measurement and control unit. The measurement and control unit only performs the telemetry, telesignaling, and remote control functions of its own bay. The measurement and control units are connected through a computer network. The failure or abnormality of any measurement and control unit only affects the data acquisition and information transmission of its own bay, without affecting the normal operation of other units and the entire computer network, thereby minimizing the system risk of hardware failure. Meanwhile, the use of object-oriented, distributed measurement and control units increases the flexibility of system hardware configuration. When the substation primary system is expanded, only the corresponding measurement and control units need to be added and the database expanded, without affecting the normal operation of the already online monitoring system. [b]3 Network Structure of Integrated Automation System[/b] The basic form of the integrated automation system of this station is a hierarchical distributed network structure, which has three layers: bay layer, network communication management layer, and station-level layer. The bay layer consists of all distributed measurement and control units, protection device communication interfaces, protection communication management units, electricity meter communication interfaces, electricity meter communication management units, and network communication lines of the above devices. The bay layer faces the controlled object and plays the roles of data acquisition, processing, and control output. In fact, the bay layer can be regarded as the interface between the monitoring system and the monitored object. The communication management layer consists of two communication management units mounted on the main control cabinet. It acts as the communication hub of the entire station's automation system, receiving information from various subnets and sending information according to the requirements of the local master station, the five-prevention workstation, the relay protection engineer station, and the remote control interface. It also receives control commands from these workstations and the remote dispatch center and sends them to the designated controlled units. Because this communication management unit plays a crucial role in managing all station information communication, its position in the monitoring system is obviously vital. Its failure or anomaly will paralyze the entire monitoring system and remote control communication. Therefore, this communication management unit becomes the most concentrated risk link in the monitoring system. The impact of failures in any other link is local and limited, while the impact of the communication management unit is holistic and comprehensive. In the design of any system, no matter how rigorous the selection of components, the possibility of failure or anomaly in any component must be considered. We must consider the system's contingency measures and the acceptable level of system risk brought about by such a possibility. Clearly, if the system risk caused by a failure of the communication management unit cannot be eliminated in a timely manner, the risk is unacceptable. Therefore, this automation system is configured with two communication management units, employing a dual-machine hot standby automatic switching operation. During normal operation, unit A is active while unit B is on standby. If unit A fails, unit B automatically switches to active status. Once unit A recovers, it switches back to active status, and unit B returns to hot standby. The risk of short-term communication interruptions (approximately 10 seconds) during switching is acceptable because it does not affect the safe operation of the primary system or the normal operation of all relay protection devices. The possibility of simultaneous failure of both communication management units is not considered. The station-level layer consists of two monitoring master stations and one relay protection engineer station, with each workstation directly connected to the communication management unit. In addition to replacing conventional control and signal panels, the monitoring master stations also have VQC (voltage and reactive power control) and on-load tap changer automatic adjustment control functions, as well as microcomputer-based five-proof functions. During normal operation, one unit is configured as the background monitoring master station, and the other as a dedicated five-proof workstation—specifically used to prevent misoperation of the station's isolating switches and grounding switches. When one monitoring workstation malfunctions and shuts down, another workstation simultaneously performs the tasks of both main monitoring stations. Because relay protection management has a clear division of labor and independence in technical management compared to conventional monitoring functions, a separate protection engineer station is set up to manage all relay protection devices in the entire station. This workstation records the actions of all digital protection devices in the station, performs fault analysis on relay protection and power grid faults using dedicated analysis software, and sets and modifies parameters for each protection device. More practically, this relay protection engineer station is connected to a public telephone network modem, extending its reach to any location with telephone service. The 110 kV, 220 kV, and main transformer monitoring and control units use DISA-910S monitoring and control devices, distributed across the protection panel on the same screen as the control box. Each DISA-910S also has a synchronous closing function, eliminating the need for a dedicated centralized synchronizing device and simplifying secondary wiring. All DISA-910S devices are connected to the main control cabinet communication management unit via a dual CAN bus network, using shielded twisted-pair cable as the communication medium. The 10 kV section uses the DISA-920 monitoring and control unit. Because the 10 kV switchgear is far from the main control cabinet's communication management unit, its communication medium uses a one-to-one fiber optic star topology to directly connect to the fiber optic management unit on the main control cabinet, which then connects to the communication management unit. This monitoring and control unit is installed side-by-side with the protection devices on the 10 kV switchgear. For the 110 kV and 220 kV line protection and main transformer protection, products from NARI Protection Co., Ltd. are used. All protection devices are connected to the CM-90 protection communication management unit via their serial interfaces, and the CM-90 then connects to the main control cabinet's communication management unit via a serial port. The 10 kV line and capacitor protection, as well as the 110 kV and 220 kV bus differential protection, use products from NARI Shenzhen Co., Ltd. The 10 kV line and capacitor protection information is connected to the ISA-100 protection communication management unit via a shielded twisted-pair CAN BUS network. The 110 kV and 220 kV bus differential protection are connected to the ISA-100 protection communication management unit via serial port, and the ISA-100 then connects to the main control cabinet communication management unit via serial port. All electricity meters in this station are digital electricity meters. These digital electricity meters are connected to the matching energy metering communication management unit via their own RS-485 interface, and then connected to the main control cabinet communication management unit via serial port to transmit the corresponding electricity information, replacing the traditional electricity pulse acquisition method. In summary, due to the large variety of secondary equipment manufacturers used in this station, the entire network structure is relatively complex. The communication of each manufacturer's digital equipment is connected to the main network (communication management unit) through its own developed communication management unit. [b]4 Remote Control Interfaces[/b] There are 4 remote control interfaces, 2 for the provincial dispatch center and 2 for the municipal dispatch center, simultaneously sending the required remote control information. To improve the reliability of information transmission, channel switching is performed at the dispatching end to select the working channel. The provincial dispatch center only sends the necessary telemetry and telesignaling signals and does not remotely control the equipment within the station. The municipal dispatch center not only receives telemetry and telesignaling information from the substation, but also, when the substation control mode is set to remote operation, remotely controls the substation's 10 kV and above circuit breakers, main transformer neutral grounding switches, and main transformer on-load tap changers. [b]5 Control Mode[/b] All circuit breakers with voltage levels of 10 kV and above and the main transformer neutral grounding switches can be remotely operated and operated via keyboard on the station's monitoring master station. Since this station will operate entirely in an unmanned mode, remote operation by the municipal dispatch center will be the control mode during normal operation. Considering the possibility of a complete system failure of the station's computer network in extreme cases, making control operations impossible at the municipal dispatch center or monitoring master station, a trip/close operation mode selection switch and control button are installed on the protection panel. Local operation can be selected on the protection panel to achieve synchronous closing via DISA-910S (circuit breakers with voltage levels above 110 kV). When DISA-910S fails to operate, the asynchronous closing function in local operation can be selected to directly operate the circuit breaker by pressing the button. The protection device on the 10 kV switchgear also has buttons for local opening and closing operations. [b]6 VQC Regulation Implementation Method[/b] Conventional 220 kV substations use a dedicated VQC regulation device for VQC regulation. For a 220 kV substation with 3 main transformers, in order to determine the synchronous parallel operation conditions between the main transformers under different operating modes, a large number of related switch and isolating knife position signals need to be collected. If a dedicated device is used, these signals will be repeatedly collected, resulting in complex secondary circuit wiring and limitations on the modification of the regulation software. In view of these factors, we require the use of a background monitoring computer to complete VQC regulation, which not only simplifies the secondary wiring but also makes software modification extremely convenient. [b]7 Aspects Worth Discussing and Improving[/b] Although the design and equipment selection of Chang'an Station are advanced and reasonable, and all equipment and integration methods represent the current advanced level in China, there are still many aspects worth discussing and improving from a developmental perspective. 7.1 In terms of network structure, as mentioned earlier, all information communication in this station is realized by the communication management unit, which is in a central position. At the same time, the communication management unit also has to complete some data processing functions. Once the communication management unit fails, all information transmission will be interrupted. Although a dual-machine hot standby switching method is adopted to ensure the reliability of communication, this method is still insufficient. Perhaps eliminating the communication management unit layer and directly adopting the local area network communication method, and adding a remote control workstation directly connected to the local area network, will help improve network reliability. 7.2 Adding a weekly load shedding function to 110 kV line protection For conventional 220 kV substations, both 110 kV lines and 10 kV lines may be set as weekly load shedding release points. Generally, digital 10 kV feeder protection has a weekly load shedding function. This substation uses the ISA series 10 kV feeder protection, which also has this function. However, the 110 kV line protection lacks a weekly load shedding function. Therefore, a weekly load shedding panel was added specifically for the 110 kV line, increasing both investment and the complexity of secondary wiring. Currently, some manufacturers produce 110 kV microprocessor-based protection systems with weekly load shedding functionality. 7.3 Fault Recording Function Existing 110 kV and 220 kV microprocessor-based line protection systems have basic fault recording functions, but due to hardware structure and software design limitations, they still cannot meet the performance and functional requirements of dedicated fault recorders. Therefore, this substation specifically configured three dedicated fault recording panels, again increasing investment and the complexity of secondary wiring. With the increasing application of integrated substation automation technology in 220 kV substations and industry competition, this issue will inevitably attract sufficient attention from manufacturers.