1 Introduction With the development of modern power system automation technology, the adoption of microcomputers to achieve comprehensive substation automation for substations of various voltage levels, especially 110 kV and below, has become a development trend. Many newly built substations have proposed unmanned or minimally staffed operation to achieve comprehensive automation; some existing substations have also proposed technical upgrades in this regard. Substation comprehensive automation integrates microcomputer monitoring, data acquisition, and microcomputer protection, and can replace conventional instruments, conventional operation control panels, and central signaling systems in substations, reducing control room space. It enables real-time data acquisition, electrical equipment operation monitoring, prevention of misoperation, automatic voltage regulation, low-current grounding line selection, remote data communication, protection equipment status monitoring, and inspection and modification of relay protection settings. [b]2 Distributed Control System[/b] The distributed control system of substation comprehensive automation has a two-layer structure: station level and bay level. The station level is located in the main control room of the substation and can also be called the substation layer; the bay level faces the primary power equipment in each bay of the substation switchyard, i.e., the bay layer. The main characteristic of this control system is that it uses primary power equipment as the installation unit, distributing control, I/O, and protection units locally on the primary power equipment cabinets. Station-level control units are connected to each primary power equipment cabinet via serial ports and communicate with the host computer and remote dispatch center. The substation level mainly includes local monitoring workstations and engineer workstations, as well as a master station microcomputer for transmitting remote control information. The bay level is horizontally distributed according to the primary equipment (main transformers, lines, etc.) within the station. For station-level and outgoing bay-level functions, microprocessor-based and distributed installation (geographical and functional distribution) are implemented. The station-level main unit, bay-level I/O units, protection units, or integrated measurement and control protection units are further divided into two modes: relatively independent protection, integrated control and measurement, and integrated protection, control, and measurement. The units rely on parameterization to achieve configuration flexibility and reliability. Compared with centralized systems, this distributed control system has the following significant advantages: ① Improved system control reliability; local faults will not lead to the paralysis of the entire system. ② Due to the reasonable distribution of the information acquisition system, the transmission distance and transmission density (i.e., channel flow) are shortened, improving the reliability and availability of the transmission system. It also reduces cable consumption, saves investment, and simplifies maintenance. ③ The burden on the station-level host is reduced. ④ The system response speed is accelerated. ⑤ The scalability and flexibility of the control system are improved, making management easier and allowing for a more reasonable configuration of the capacity and scale of computers at each level, thus increasing the degree of software and software resource sharing. [b]3 Basic Functions[/b] 3.1 Data Acquisition Substation data acquisition includes the acquisition of status quantities, analog quantities, pulse quantities, etc. Status quantities include: circuit breaker status, disconnector status, periodic detection status, lockout status, substation primary equipment operation alarm signals, transformer tap position signals, valve and grounding signals, etc. Protection action signals (conventionally used as status quantity inputs) are obtained through communication via serial port or LAN network. [img=337,195]http://zszl.cepee.com/cepee_kjlw_pic/files/wx/gxdljs/gxdljs99/gxdl9902/image2/44.gif[/img] Figure 1. Schematic diagram of a distributed integrated automation system. Analog quantities include: bus voltage of each section, line voltage, current and power values, feeder current, voltage and power values, frequency, phase, etc. In addition, there are transformer oil temperature, DC power supply voltage, used voltage and power, etc. Pulse quantity refers to the electrical quantity output by the energy meter. 3.2 Control operators can operate the circuit breaker and disconnector switches at the substation or remote dispatch center through the keyboard or mouse, adjust and control the on-load tap changer of the transformer, and switch the capacitor bank. 3.3 Microprocessor Protection: Microprocessor protection includes line protection, transformer protection, feeder protection, busbar protection, capacitor protection, and automatic transfer switching of backup power. For high-voltage systems, it includes main protection and backup protection. 3.4 Data Processing: Substation data processing includes: statistics on circuit breaker operation counts, fault current during circuit breaker fault clearing, and tripping operation counts; active and reactive power data for lines and transformers; maximum and minimum values ​​and their timestamps of busbar voltage recorded periodically; records of control operations and setting modifications; and daily peak and maximum values ​​and their timestamps of active and reactive power for independent loads. 3.5 Event Records and Other Event Records: These include protection action sequence records (generally generated by the microprocessor protection system) and switch tripping/closing records (generally recorded by the monitoring system). Additionally, a dedicated microprocessor fault recorder and automatic low-current grounding line selection function can be configured as needed. 3.6 Communication: The monitoring system should be able to communicate with the microprocessor protection system, microprocessor fault recorder, and dispatch center, and synchronize time. 3.7 Self-diagnostic function: Each plug-in in the system should have a self-diagnostic function, and the self-diagnostic information can be sent to the station-level host or remote control dispatch center. 3.8 Human-machine interface: The main contents of human-machine interface include: display screens and data, such as single-line diagram status, power flow information, protection settings, duty logs, etc.; input data; and the minimum human-machine interface functions required for manual control operations, maintenance, or inspections. [b]4 Basic Structure[/b] For substations with voltage levels of 110 kV and below, the distributed system distributes protection units and measurement and control devices to switchgear and connects them with optical cables, as shown in Figure 1. For the measurement, control, and protection of the main transformer, they can be installed near the main transformer or in the control room. For example, each 10 kV outgoing line and the substation used in the Nan Gong Chaoyang substation is equipped with an I/O unit and a protection device locally, while the main transformer protection and I/O panel are installed in the main control room. For substations with voltage levels of 220 kV and above, protection and control devices for nearby equipment are installed in several small equipment rooms within the switchyard, connected by optical cables, as shown in Figure 2. [b]5 Discussion of Several Issues[/b] ① Protection devices for 10 kV voltage levels should be directly installable in the switchgear and meet the requirements of the application environment regarding electromagnetic interference, vibration (caused by opening and closing operations), temperature, and humidity. [img=413,302]http://zszl.cepee.com/cepee_kjlw_pic/files/wx/gxdljs/gxdljs99/gxdl9902/image2/45.gif[/img] Figure 2 Example of a 220 kV locally distributed substation integrated automation system configuration ② Comparison of domestic and foreign products. Currently, the main shortcomings of domestic substation integrated automation equipment compared to foreign products are as follows: significant gaps in hardware manufacturing processes and substation primary equipment manufacturing processes; fewer use of high-quality equipment such as dedicated chips and optical cables; and the fact that some large multinational corporations offer a complete range of products from primary substation equipment to integrated automation equipment, demonstrating strong product integration. However, domestic products also have their own characteristics. For example, domestic manufacturers are more familiar with domestically produced equipment and have a better grasp of operating procedures, giving them an advantage in developing practical systems and microcomputer protection equipment. Domestic manufacturers possess considerable strength in station control software development, especially in human-machine interface application software, and are particularly adept at localization compared to foreign companies. Domestic manufacturers also have significant advantages in project organization, on-site commissioning, training, and after-sales service. Domestic products also have a price advantage. ③ For the renovation of existing substations, emphasis should be placed on the technical upgrading or replacement of primary equipment to meet the requirements of automatic control. ④ Strengthen technical training to improve the ability of on-site personnel to use, maintain, and troubleshoot. ⑤ Consideration should be given to lightning protection, static electricity protection, and protection against induced overvoltage to ensure the safe operation of system equipment. ⑥ Manufacturers generally set up each microprocessor-based protection unit independently according to the power equipment unit, directly inputting electrical quantities from the relevant CTs and PTs, and sending the action signals directly to the trip coil of the operating switch. In this case, the protection device should be equipped with a communication interface to connect to the station's communication network so as to provide reports to the station-level machine after the protection action. In addition, besides microprocessor-based protection, other automatic devices, such as standby power supply automatic transfer devices, control capacitor switching and voltage control devices for on-load tap changer taps, etc., should also be equipped with dedicated devices and placed on the corresponding bay layers. [b]6 Conclusion[/b] New and existing substations should consider the implementation of integrated automation when conditions permit, and make strict requirements to the manufacturer according to the complete technical functional specifications in order to improve the safe operation level of the substation and achieve better technical and economic benefits. The integrated automation equipment for substations should, as far as possible, select distributed control systems with successful experience in the domestic region, and do a good job in technical cooperation with the manufacturer, coordinating technical cooperation and technical training between manufacturers. In addition, based on the actual situation of domestic policies and funding, there is often a gap of several years or even more than 10 years between the design and installation and commissioning of general projects. For new technological developments during this period, the original design should be modified in a timely manner to directly update the product. [b]References[/b] 1 Zhu Daxin, Liu Jue. Content, functional requirements and configuration of substation integrated automation system. Automation of Electric Power Systems, 1995(10). 2 Pang Zhun, Jiang Geli, Lin Zhiwen. Integrated automation system of Chaoyang 110 kV unmanned substation. Guangxi Electric Power Technology, 1997(3). 3 Tang Tao. Review of the development of unmanned operation and integrated automation technology of substation at home and abroad. Automation of Electric Power Systems, 1995(10).