The regulation and control process of large hydroelectric generating units under PFR-AGC coordination

With the increasing penetration of large-scale hydropower bases and long-distance AC/DC transmission, dispatching agencies are applying stricter assessment indices to primary frequency regulation (PFR) and automatic generation control (AGC). In practice, some stations improve the measured response speed by increasing governor sensitivity or shortening command-conversion time constants. Although this may raise short-term performance indicators, it can also enlarge reverse power regulation, reduce damping in the ultra-low-frequency band, and aggravate grid-frequency deterioration after disturbances. To clarify this contradiction, this paper investigates the regulation and control process of large hydroelectric generating units under coordinated PFR-AGC operation. First, the command-generation logic of plant-level AGC, the autonomous droop response of PFR, and their co-control relationship are analyzed. A linearized dynamic model including the water conveyance system, hydraulic turbine, governor, and generator is then established and verified by load rejection and PFR operating records. Based on the validated model, the effects of water-flow inertia constant, pressure-regulation-well coefficient, PWM pulse period, integral conversion parameter, permanent slip coefficient, and governor PID parameters are compared through time-domain simulation and eigenvalue analysis. The results show that excessive pursuit of response speed increases reverse regulation and may move characteristic roots toward the right half-plane. Optimizing PI parameters can reshape the amplitude-frequency and phase-frequency characteristics of the speed control system and suppress ultra-low-frequency oscillation, but a certain reduction in PFR regulating speed should be accepted. The study provides a practical tuning logic for balancing frequency regulation performance and grid stability.