ਵਿੱਕ ਫਰੀਕਵੈਂਸੀ ਕੰਟਰੋਲ (LFC) ਅਤੇ ਟਰਬਾਈਨ ਗਵਰਨਰ ਕੰਟਰੋਲ (TGC) ਦੀ ਪਾਵਰ ਸਿਸਟਮ ਵਿੱਚ ਵਰਤੋਂ
thermal generating units di takrifi khurd
Bijli banane de upar renewable te non-renewable energy resources da vartaa janda hai. Thermal generating units power production da ek traditional tareeka hain. Iss units vich, coal, nuclear energy, natural gas, biofuel, te biogas da istemal karke boiler vich combustion kiyaa janda hai.
Generating unit da boiler ek bahut hi complex system hai. Iska sabse simple visualization yeh hai ke iska andar pipes se ghira hua ek chamber hota hai, jisme pani continuous tarah se circulates karta hai. Boiler vich fuel ka combustion se nikla thermal energy iss pani ko transfer kiya jata hai. Is process ke dauraan, pani high pressure (150 ksc se 380 ksc tak, design par depend karta hai) aur high temperature (530°C se 732°C tak, design specifications par depend karta hai) wala dry saturated steam mein transform ho jata hai.
Iss saturated steam ko turbine mein feed kiya jata hai, jahaan ise expand kiya jata hai aur ise temperature drop hoti hai. Is expansion process ke dauraan, steam apna thermal energy turbine shaft ke rotational energy mein transfer karta hai. Steam ki turbine mein entry control valve se regulate ki jati hai, jo turbine ke governing system se govern ki jati hai. Is prakar, turbine ki active power output governor se control ki jati hai. Turbine synchronous generator se coupled hota hai.
Synchronous generator turbine ki mechanical energy ko electrical energy mein convert karta hai. Synchronous generators nominal frequency par generally 11 kV se 26 kV ke beech voltage par electricity produce karte hain. Iss voltage ko phir 220 kV/400 kV/765 kV tak generating transformer se step up kiya jata hai transmission ke liye power grid mein. Power system studies mein, iss entire integrated system ko generating unit ke roop mein refer kiya jata hai.
Turbine Governor Control (TGC)
Jaise pehle mention kiya gaya, governor control valve ke position ko control karke turbine mein active power flow ko regulate karta hai. Ek hydraulic governor ko integral controller ke roop mein model kiya ja sakta hai jo turbine ki actual rotational speed se feedback leta hai. Figure 1 governor ke operation ko speed-control mode mein dikhata hai.
Turbine ki actual speed ko reference speed (nominal grid frequency se corresponding) ke against compare kiya jata hai. Resulting speed error signal (∆ωᵣ) phir governor mein feed kiya jata hai. Iss error signal ke based par, governor control valve position adjust karta hai: agar positive error signal detect kiya jata hai (actual frequency nominal frequency se zyada hai), to governor slightly valve band karta hai; vice versa, negative error signal receive hone par valve open karta hai.
“R” governor droop setting represent karta hai, jo typically 3% se 8% tak range karta hai. Mathematically, it is defined as:
R = (per unit change in frequency) / (per unit change in power)
Droop settings multiple generating units ke stable parallel operation ke liye critical hain, kyunki ye determine karte hain ke control area vich load kaise share kiya jaye. Units jo chota droop value rakhte hain, automatically bada share of the load assume karte hain.
Control Area
Power system mein generating units aur loads vast geographical regions par distributed hote hain. Stability maintain karne ke liye, entire grid smaller control areas (primarily based on geography) mein divided hota hai. This division enables:
Ek control area vich multiple generating units aur loads coexist karte hain. Subdividing the power system into control areas serves several key objectives:
1. Load Frequency Control
This framework enables the application of load-frequency control methods to maintain grid frequency—a concept explored in greater detail later.
2. Determination of Scheduled Interchanges
If a control area’s generation falls short of its load demand, power flows into the area from neighboring control areas via tie lines (and vice versa).
3. Effective Load Sharing
Load demand varies throughout the day (e.g., lower at night, peaking in the morning and evening). Control areas simplify the process of:
Power Balance
Electrical energy is consumed in real-time (it cannot be stored on a large scale). Thus, power balance is a fundamental requirement:
Power Generated (P₉) = Load Demand (Pd) + Transmission Losses (Pₗ)
Transmission losses typically account for ~2% of generated power and are often neglected when focusing on frequency control. For simplicity, we approximate:
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.
