[align=left] 0 Introduction Large thermal power generating units, due to their large capacity and high operating parameters, pose significant risks to the safety of the unit itself and even the power grid if operated improperly. Therefore, the requirements and reliance on automatic control are increasingly stringent. The ultimate goal of automatic control for generating units is to safely and quickly meet the load demands of the power grid and ensure power quality. Because the boiler and turbine, which make up a thermal power generating unit, have significantly different load response characteristics, the design of unit-level control must fully consider these different characteristics to ensure coordinated operation of the boiler and turbine, maximizing the unit's actual maximum capacity to meet the grid's requirements. The task of the Coordinated Control System (CCS) is to coordinate the two different process systems—the boiler and turbine—to jointly meet the power load demand. Therefore, the design of the coordinated control system should consider the boiler and turbine as a whole, enabling the unit to maximize the quantity (power) and quality (frequency) of power generation required by the grid within its actual capacity, ensuring the safe, stable, and economical operation of the generating unit. This is the fundamental requirement of coordinated control. There are many ways to implement a coordinated control system in theory, but for a specific generator set, once the main equipment and process system are determined, the most suitable technical solution for the specific conditions of the unit should be selected as the basic strategy for the design of the control system. With the continuous maturation of the application of distributed control systems (DCS), a technical and material basis has been created for thermal power units to realize complex coordinated control. This article describes the design idea, control strategy and actual load response of the unit under the coordinated control mode of the DEB direct energy balance control system. The system hardware used is the MAX1000 distributed control system. [b]1 DEB Principle Analysis[/b] The Direct Energy Balance (DEB) coordinated control system is a proprietary technology created by the former Leeds & Northrup Corporation of the United States (now inherited by the American MetsoMAX Corporation, and Shanghai Automation Instrumentation Co., Ltd. obtained the license to use it through technology introduction). Its famous expression is [1]: (1) Where PTS is the set value of the turbine inlet pressure; P1 is the turbine first-level pressure; PT is the turbine inlet pressure; PD is the steam drum pressure; Cb is the boiler heat storage coefficient. The left side of the equation represents the turbine's energy demand signal, and the right side represents the boiler's heat signal. DEB is essentially a coordinated control system based on boiler following. The turbine controls power while using its energy demand as the boiler load command, directly balancing it with the boiler's heat signal. This balance is achieved by adjusting the amount of fuel input to the boiler. Therefore, the heat signal representing the fuel quantity at the fuel regulator inlet is directly compared with the turbine's energy demand signal. During dynamic adjustment, the proportional-integral fuel regulator, through feedback regulation, always aims to bring the inlet deviation towards zero. Therefore, the fuel regulator inlet error ef at this point is: [align=left] As can be seen from the above relationship, the result of the balance between the energy demand signal and the heat signal can naturally maintain the turbine pressure PT at the set value PTS, thus proving that the DEB control strategy can indeed maintain the energy balance of the turbine and boiler. According to the inherent characteristic of DEB to maintain the turbine pressure at a constant value, the turbine pressure correction regulator can be cancelled [2]. [b]2 DEB Function Design[/b] A complete and practical coordinated control system must consider the matching of target load and actual capacity between systems and equipment under various operating conditions, specifically including: ① matching of grid load requirements with unit output; ② matching of turbine energy requirements with boiler output; ③ matching of boiler output requirements with auxiliary machine capacity. When the relationship between the above "requirements" and "capabilities" is properly matched, the unit operation is safe and economical, and the control system is stable. Figure 1 shows a schematic block diagram of the unit coordinated main control using the direct energy balance principle. [font=SimSun] Figure 1. Schematic diagram of direct energy balance coordination control system. The entire coordination control system consists of three parts: unit instruction processing loop, turbine main control loop and boiler main control loop. The engineering implementation of each loop of the coordination control system using direct energy balance strategy is described below. 2.1 Unit instruction processing The unit instruction processing loop is responsible for issuing power instructions to the boiler and turbine in real time to meet the load requirements of the power grid to the unit to the greatest extent. When the unit is operating abnormally, it will restrict the target instruction of the unit in a timely manner to avoid further expansion of the abnormal condition. Under the premise of ensuring safety, the unit will continue to bear the power generation load with its actual capacity. The specific tasks of the unit instruction processing loop are: (1) Select the load control instruction mode suitable for the unit's current conditions according to the unit's operating status and the requirements of the power grid load control. (2) Process the target instruction to adapt it to the dynamic characteristics and load change capacity of the boiler and turbine, and generate the actual power instruction. There are two types of unit load instruction mode: manual load instruction set by the operator and automatic dispatch instruction from the power grid AGC system. The source of the unit load instruction is selected by T1. T1 provides the interface between the generating unit and the grid AGC system. When the generating unit is operating in coordinated control mode and the AGC command and operator command are well-matched, if the grid dispatch center requests the generating unit to accept AGC control, after receiving the AGC request command, the operator presses the AGC button on the DCS CRT "Generating Unit Main Control" screen, and T1 selects the AGC command. In AGC mode, the operator can switch the generating unit command to manual command at any time. The generating unit command processing loop, while completing the command selection, also sends real-time capacity and status information of the generating unit to the grid AGC system, cooperating with the grid control center to achieve telemetry and remote control of the generating unit. After T1 selects the command source and control mode, it integrates the incoming frequency difference signal to form the generating unit's target load command. The next task of the generating unit command processing loop is to process the target command into an actual power command acceptable to the generating unit, ensuring that the actual output of the generating unit matches the grid requirements within the equipment's permissible capacity. When certain equipment or systems of a continuously operating unit malfunction, causing output or stability issues, the unit may not be able to reach its initial load change range. In this case, the equipment and process limitation logic calculates the unit's real-time load capacity and uses a command interlocking logic loop to perform real-time directional interlocking of the target command, limiting the command to within the unit's allowable capacity. Simultaneously, it adjusts the command change rate limit value according to different situations. When equipment failure or process problems occur, resulting in forced load increases/decreases on the unit side, the unit command processing loop will ensure the command tracks the actual generated power, preventing command disturbances after the forced load increase/decrease process ends. 2.2 Turbine Main Control As shown in Figure 1, the turbine main control loop is a power-pressure cascade plus command feedforward control loop. The turbine directly controls the power, resulting in a fast system response to power commands. The accelerating regulation effect of the power command feedforward control helps the system overcome the reheater volume lag of intermediate reheat units, further improving the response speed. A turbine inlet pressure regulator is connected in parallel with T2 at the output of the power cascade loop. When T2 selects the turbine inlet pressure regulator, the system switches from turbine power regulation to turbine pressure regulation. When the turbine controls the steam pressure, the unit's power is determined by the boiler. The switching of T2 is determined by the coordinated control logic under normal operating conditions. The control interface between the turbine main control loop and the turbine is the turbine digital electro-hydraulic controller (DEH). Because the DEH has good turbine valve management functions (valve characteristic linearization processing), the unit's power control loop can obtain good regulation quality. The control interface between the turbine main control loop and the DEH adopts pulse frequency modulation and is connected by hard wiring. The pulse frequency modulation interface has high safety; even if the control signal connection line is short-circuited, the turbine control will not malfunction. 2.3 Boiler Main Control As shown in Figure 1, there is no turbine inlet pressure regulator in the boiler main control loop. The turbine's energy demand signal is directly fed into the boiler control as a boiler command in a feedforward manner. When the turbine power control is applied to the turbine control valve, the energy demand signal immediately requests the fuel regulator to adjust the boiler fuel input to match the current turbine demand. While this matching (balancing) process is direct and rapid, the boiler's energy conversion process has a significant lag. To overcome this lag and accelerate the boiler's response, dynamic compensation is applied to the energy command (demand) in the DEB engineering design [3]. Dynamic fuel overshoot is used to amplify the variation in boiler combustion rate, prompting the boiler to respond more quickly. Figure 2 shows the functional block diagram of the turbine energy command in practical engineering. The boiler command signal generated after dynamic compensation can greatly improve the energy matching between the turbine and boiler dynamic processes during constant pressure or sliding pressure operation. [/font] Figure 2 Functional block diagram of energy command In DEB control, the pressure ratio signal can sensitively reflect the opening of the turbine valve. At the same time, the pressure ratio is also very sensitive to signal noise. After the advance compensation, the noise of the signal will be further amplified. Therefore, the energy command must be effectively filtered. In engineering, the conventional filtering method is generally to use inertial filtering. Inertial filtering overcomes noise but also sacrifices the sensitivity of the signal. In order to effectively filter out noise without delaying the signal, we adopted the amplitude limiting filter (ALF) method in the design [1]. For the pressure ratio signal, the noise amplitude is relatively uniform. ALF forms a noise filter band floating on the signal by setting a filter amplitude based on the signal mean, so that the noise within the filter band amplitude is effectively overcome, while the useful signal change greater than the filter band amplitude is truly reflected. The ALF filter amplitude setting is very easy in engineering. As long as the average amplitude of the signal noise is recorded and measured, the setting value can be determined. A power plant boiler is a highly complex process system. The coordinated operation of its coal, air, and water systems maintains normal boiler operation and ensures that the output meets the turbine's requirements. When a problem occurs in a local equipment or process system of the boiler, it will affect the overall capacity of the boiler. If a local subsystem is operating with a fault, boiler commands must be limited to ensure that the boiler's load level does not exceed the capacity of the faulty subsystem. If a local system or equipment of the boiler malfunctions and cannot meet the current load level, the boiler output must be forcibly changed to the actual capacity of the local system to prevent the local fault from escalating. The boiler real-time capacity processing loop processes boiler commands in three ways based on boiler subsystem adjustment deviations, equipment operating limits, and auxiliary equipment tripping: direction lockout; forced rise/fall (RUNUP/RUNDOWN); and rapid load reduction (RUNBACK). When a boiler command direction lockout occurs, the boiler real-time capacity processing loop simultaneously locks the unit command in the same direction, ensuring that the unit's actual load command does not exceed the boiler's real-time capacity. When forced load increase/decrease or rapid load reduction occurs, while the boiler side reduces load, the real-time capacity processing loop switches the turbine side's T2 to turbine pressure regulation mode, allowing the turbine to control the main steam pressure, so that the turbine and boiler reach the unit's real-time load capacity in a coordinated and synchronous manner without disrupting the system balance. [b]3 Actual Response Analysis of Units under DEB Coordination Mode[/b] The coordination control system using the DEB strategy has been successfully operated in a 2×300MW unit of a power plant, and has completed the RUNBACK test under various designed tripping conditions, with AGC control engaged. The following analysis of the real-time power response curve and RUN BACK test curve of Unit #1 of a power plant under coordination mode verifies the actual application effect of the DEB strategy. 3.1 Actual Response Analysis of Units under DEB Mode[font=SimSun] Figure 3 shows the actual response curves of the unit under DEB mode. At full load (300MW), when the target load of 250MW is set at the unit's main control station and sent to the CCS, the step disturbance reaches 16.7%, and the command change rate is limited to approximately 4%/min (see curve 4). The actual response of the unit is as follows: the actual generated power (curve 3) tracks the power command very well under DEB control, lagging only 30 seconds behind the command. Once the actual generated power reaches the target value, there is no overshoot or oscillation. On the boiler side, to ensure the energy balance between the boiler and the turbine during dynamic processes, the boiler main control implements powerful dynamic compensation for the energy command signal. The result is reflected in the change in coal quantity (see curve 7). The actual change in coal quantity is large, with an overshoot as high as 96%, resulting in a strong change in combustion within the boiler, thus dynamically compensating for the lag in boiler energy conversion. Maintaining stable boiler combustion and operation during such intense combustion changes is a crucial task for the CCS. Curves 9 and 6 record the changes in flue gas oxygen content and furnace pressure, respectively. The records show that these two parameters are very stable, thus proving that combustion in the furnace is stable during the above dynamic process. The stability of the flue gas oxygen content further demonstrates that the system ensures the combustion economy during the dynamic process. The changes in drum water level and main steam temperature recorded by curves 5 and 1 prove that the steam-water system operation is also stable. The energy balance between the turbine and boiler during the above dynamic process can be reflected by the main steam pressure (see curve 2). The maximum deviation of the main steam pressure during the entire process is only 0.08 MPa, and no excessive control process is observed. The main steam temperature (curve 1) is not significantly disturbed, and the changes are within the normal fluctuation range. This proves that the energy supply and demand of the turbine and boiler are very balanced during the dynamic process, and the quality of the main steam is guaranteed. 3.2 Actual RUNBACK Response of the Unit Figure 4 shows the RUNBACK response curve of the unit when one induced draft fan trips. When the induced draft fan trips, the SCS trips one forced draft fan and one coal mill (direct-fired pulverizing system). The target load of RUNBACK is 150MW. The BUNBACK was successful, with a steam pressure deviation of 0.68 MPa. Figure 4 shows the RB response curve for the induced draft fan trip. Figure 5. RB response curve for air preheater trip. Figure 5 shows the RUNBACK response curve of a unit with an air preheater trip. When the air preheater trips, the SCS trips a coal mill. The target load for RUNBACK is 180MW. RUNBACK was successful, with a steam pressure deviation of 0.64MPa. 3.3 Problems and Solutions As shown in Figures 4 and 5, although the system automatically completed RUNBACK, the main steam pressure deviation during this process was too large. The main reason is that the interface method between CCS and DEH affected the response speed of DEH to CCS commands. As previously mentioned, the interface between CCS and DEH uses a "pulse frequency modulation" method, where the number of pulses represents the increase/decrease in power commands. Under normal operating conditions, the power commands issued by CCS to DEH can be converted into "command pulses" and correctly transmitted and received. However, under operating conditions similar to RUNBACK, the rate of change of commands issued by CCS is very large, causing several "command pulses" to be lost during the interface pulse transmission and reception process, thus affecting the regulation speed of DEH. Another interface scheme between CCS and DEH can be adopted—the "pulse width modulation" method, which uses the duty cycle of the pulse to control the amplitude of the change, while the pulse frequency remains fixed. This avoids pulse loss and improves the regulation strength of CCS on DEH. [b]4 Conclusion[/b] This paper analyzes in detail the technical principles, engineering implementation, actual process response, and operational effects of the coordinated control system using the direct energy balance strategy. The response curves of the main parameters of the unit recorded on-site fully demonstrate the correctness of the direct energy balance control strategy and the feasibility of the scheme. The regulation quality of the unit under DEB control is good; therefore, DEB is an excellent coordinated control strategy. This also proves that the design of the DEB coordinated control strategy for this power plant is successful. [b]References[/b] 1 Metso Automation MAX Controls, Inc. MAX1000 Related application bulletins and product specifications, P-204-U, A-701-U, A-702-U, A-703-U, A-704-U, A-705-U. 2 Teng Weiming, Wang Chunli, Gao Haidong, et al. Control strategy combining energy balance and main steam pressure regulation applied to boiler-turbine coordinated control[J]. Thermal Power Generation. 2005, 6, 42-44. 3 Lin Qing. Compensation of unit dynamic characteristics by DEB system[J]. Journal of Nanjing Institute of Technology, 2005, 3 (4): 14-18. About the author: Li Chaotao (1958-), male, deputy chief engineer of DCS company of Shanghai Automation Instrumentation Co., Ltd., has long been engaged in DCS system design, configuration and field commissioning.