Pagkotrol sa Prekensya sa Load (LFC) & Pagkotrol sa Gobernador sa Turbina (TGC) sa Sistema sa Kuryente
Pitabyang Introduksyon sa mga Thermal Generating Units
Ang paggawa sa kuryente nagbatasan sa parehas nga renewable ug non-renewable energy resources. Ang mga thermal generating units mao ang tradisyonal nga paraan sa pagprodukt sa lakas. Sa kini nga mga unit, ang mga fuel sama sa coal, nuclear energy, natural gas, biofuel, ug biogas gisunog sa usa ka boiler.
Ang boiler sa usa ka generating unit mao ang napakomplikado nga sistema. Sa iyang pinakasimple nga konsepto, mahimong makita kini isip usa ka chamber diin ang mga pipa adunay tubig nga naglupyo sa wala. Ang thermal energy nga giliberar sa pagsunog sa fuel sa loob sa boiler mihatag sa kini nga tubig. Sa proseso niini, ang tubig gibag-o ngadto sa dry saturated steam nga may high pressure (sa rango gikan sa 150 ksc hangtod sa 380 ksc, depende sa disenyo) ug high temperature (gikan sa 530°C hangtod sa 732°C, depende sa design specifications).
Kini nga saturated steam pagkaron gi-feed sa usa ka turbine, diin gi-expand kini ug ang temperatura nia mobaba. Sa proseso niini, ang steam nimoho ang iyang thermal energy sa rotational energy sa shaft sa turbine. Ang flow sa steam sa turbine giregula sa usa ka control valve, nga giregula sa governing system sa turbine. Kini mao ang kontrol sa active power output sa turbine sa pamila sa governor. Ang turbine gisulod sa usa ka synchronous generator.
Ang synchronous generator nimoho ang mechanical energy sa turbine ngadto sa electrical energy. Ang synchronous generators moprodukt og kuryente sa relatively low voltages, kasagaran sa rango gikan sa 11 kV hangtod sa 26 kV, sa nominal frequency. Kini nga voltage pagkaron gi-step up ngadto sa 220 kV/400 kV/765 kV pinaagi sa usa ka generating transformer aron mogahin sa power grid. Sa mga pagtambal sa power system, ang tanang integrated system mao ang gitawag og generating unit.
Turbine Governor Control (TGC)
Isip maong gisulti, ang governor regula ang active power flow sa turbine pinaagi sa pagkontrol sa position sa control valve. Ang hydraulic governor mahimo mapamodel isip usa ka integral controller nga naghimo og feedback gikan sa actual rotational speed sa turbine. Ang Figure 1 nagpakita sa operasyon sa governor sa speed-control mode.
Ang actual speed sa turbine gigamit sa reference speed (naa sa nominal grid frequency). Ang resultante nga speed error signal (∆ωᵣ) pagkaron gi-feed sa governor. Pinaagi niining error signal, ang governor adjust ang position sa control valve: kon positive error signal ang natumba (nagpakita nga ang actual frequency labi sa nominal frequency), ang governor slightly close ang valve; sa uban, ang valve open kon negative error signal ang natumba.
Ang “R” mao ang droop setting sa governor, kasagaran sa rango gikan sa 3% hangtod sa 8%. Mathematically, ini define isip:
R = (per unit change in frequency) / (per unit change in power)
Ang droop settings importante para sa stable parallel operation sa multiple generating units, tungod kay sila magdetermina paano ang load gishare sa usa ka control area. Ang mga unit nga may smaller droop value automatico mag-assume og larger share sa load.
Control Area
Sa usa ka power system, ang mga generating units ug loads gisdistribuha sa dako nga geographical regions. Aron matubag ang stability, ang tanang grid gisubdivided ngadto sa mas gamay nga control areas (primarily based on geography). Kini nga subdivision mahimo:
Sa usa ka control area, ang multiple generating units ug loads coexist. Ang subdividing sa power system sa control areas mahimo several key objectives:
1. Load Frequency Control
Kini nga framework mahimo ang paggamit sa load-frequency control methods aron matubag ang grid frequency—a concept explored in greater detail later.
2. Determination of Scheduled Interchanges
Kon ang generation sa usa ka control area short sa iyang load demand, ang power flows sa area gikan sa neighboring control areas pinaagi sa tie lines (ug vice versa).
3. Effective Load Sharing
Ang load demand nagbago sa panahon (e.g., lower sa gabii, peaking sa buntag ug hapon). Ang control areas simplifies ang proseso sa:
Power Balance
Ang electrical energy consumed sa real-time (wala kini mahimo molihok sa large scale). Busa, ang power balance mao ang fundamental requirement:
Power Generated (P₉) = Load Demand (Pd) + Transmission Losses (Pₗ)
Ang transmission losses kasagaran account sa ~2% sa generated power ug kasagaran ignored kon focused sa frequency control. Para simple, approximate mi:
Power Generated (P₉) ≈ Load Demand (Pd)
Frequency Variation
Grid frequency fluctuates due to mismatches between load demand and generation. While minor deviations are stabilized by system inertia, significant gaps (e.g., unit trips, large load changes) can cause frequency to vary by ±5%. Key scenarios include:
In most cases (e.g., unit/line trips, large load connection), demand exceeds generation, causing frequency to drop. Conversely, if a transmission line serving a large load trips, generation may exceed demand, causing frequency to rise. Though the system responds oppositely to these scenarios, understanding frequency dips suffices to grasp both behaviors.
Why Frequency Dips Occur
Two inherent system behaviors drive frequency dips:
1. Load Dampening
Induction motors (e.g., household fans, industrial drives) dominate grid loads. Their power consumption is frequency - dependent: a 1% frequency reduction typically reduces active power consumption by ~2% in large systems. When new loads connect, frequency drops, and existing induction loads automatically consume less power—partially mitigating the demand - generation gap.
2. Kinetic Energy Release from Turbine - Generator (TG) Sets
Conventional TG sets have massive rotors (often >25 tonnes) spinning at 3000 RPM (for 50Hz grids). When demand exceeds generation, these rotors temporarily supply stored kinetic energy (for 3–5 seconds, depending on inertia). As rotors slow down, grid frequency drops.
Frequency Control
Load - frequency control (LFC) restores grid frequency to its nominal value after demand - generation mismatches. Two tiers of control exist:
1. Primary Frequency Control
At the unit level, the turbine’s governing system adjusts speed (and thus frequency). As shown earlier, each unit modulates steam input based on frequency deviations. The full primary control loop for a generating station is depicted in the figure below.
2. Secondary Frequency Control
This involves coordinated control across multiple units in different control areas, ensuring long - term frequency stability and optimal load sharing.
Primary Frequency Control Limitations
Primary frequency control alone results in a steady - state frequency deviation, influenced by the governor droop characteristic and load frequency sensitivity. This occurs because individual units adjust speed without considering where new loads are connected or how much load is added. Without such contextual assessment, power balance cannot be fully restored, and frequency deviation persists. Following primary control actions, the steady - state frequency error may be either positive or negative.
Secondary Frequency Control
Restoring system frequency to its nominal value requires secondary control, which accounts for new load locations and adjusts reference setpoints for selected units. When load increases in a control area, generation within that area must rise to:
To achieve this:
Once revised load setpoints are issued, units begin adjusting generation. Due to the mechanical nature of power production, it takes 25–30 minutes for units to reach their scheduled outputs. When all generating stations achieve target generation, power balance is reinstated, and frequency returns to nominal.
The overall response of the system with the primary and secondary frequency control can be understood by the graph below.
System Response to Load Increase (A-B-C-D)
A-B: Transient Kinetic Energy Release
Before point A, the system operates in power balance. At point A, load suddenly increases from P₀ to P₀ + ∆P. A 3–5 second delay occurs before the governor responds. During this interval, the rotor's stored kinetic energy supplies the excess load, causing rotor speed to drop and frequency to dip to a minimum value f₁.
B-C: Primary Frequency Control Action
At ~5 seconds, the governor initiates speed control, increasing steam input to restore rotor speed. This phase lasts 20–25 seconds (dependent on the frequency dip magnitude). As discussed, primary control alone leaves a steady - state frequency error ∆f due to governor droop.
C-D: Secondary Frequency Control (AGC Activation)
Once frequency stabilizes, secondary control (via AGC) adjusts generation for selected units in each control area. This process considers:
Generation adjustments are limited by the units’ design ramp rates, taking several minutes to complete. Upon finishing, scheduled interchanges return to pre - calculated values, and the system achieves a new power balance with nominal frequency.
