Electric System Design of a Power Plant

Both systems supply DC to the rotor field of a synchronous generator. A brushless system uses a shaft-mounted AC exciter with rotating diodes, so no brushes are needed. A static system takes power from the generator terminals through a transformer and a thyristor bridge, and feeds the field through slip rings and brushes.

Schematic diagrams

 BRUSHLESS EXCITATION
        stationary | rotating (on shaft)
 PMG/aux --> AVR   |
 supply     |      |
            v      |
   Exciter field   |  Exciter armature (3-ph)
   (stator) ~~~~~~~|~~~~> |
                   |   Rotating diode bridge
                   |      |
                   |   Main field (rotor)
                   |      |
               Main generator stator --> Grid

 STATIC EXCITATION
 Gen terminals --+---------------> GSU --> Grid
                 |
          Excitation transformer
                 |
          Thyristor bridge <-- AVR
                 |
          Field breaker
                 |
        Brushes + slip rings
                 |
          Main field (rotor)

Comparison

Conclusion: brushless is chosen where low maintenance and reliability matter (small to medium, remote plants); static is chosen for large units where fast response and transient stability matter.

A grounding (earthing) mat is a buried grid of horizontal conductors with vertical rods under a powerhouse and switchyard. It must carry fault current to earth safely and keep step and touch voltages within tolerable limits. Design normally follows IEEE Std 80.

Layout

  +----+----+----+----+   Horizontal grid
  |    |    |    |    |   (Cu or GI conductor
  +----+----+----+----+    at 0.5-0.8 m depth)
  |    |    |    |    |
  +----+----+----+----+   o = earth rods
  o    |    |    |    o
  +----+----+----+----+

Steps

1. Site data: area of switchyard/powerhouse; measure soil resistivity $\rho$ by the Wenner four-pin method; resistivity of surface layer (crushed rock) $\rho_s$.
2. Fault current and time: find maximum earth fault current $3I_0$, split factor $S_f$ and decrement factor $D_f$:

$$I_G = D_f\, S_f\, 3I_0$$

Fault clearing time $t_f$ and shock duration $t_s$ (e.g. 0.5–1 s). 3. Conductor size: from IEEE 80 (Onderdonk-type) formula

$$A_{mm^2} = \frac{I}{\sqrt{\dfrac{TCAP\times 10^{-4}}{t_c\,\alpha_r\,\rho_r}\ln\dfrac{K_0+T_m}{K_0+T_a}}}$$

then add corrosion allowance and mechanical minimum. 4. Tolerable step and touch voltages (50 kg body):

$$\begin{aligned} E_{step} &= (1000 + 6C_s\rho_s)\frac{0.116}{\sqrt{t_s}} \\ E_{touch} &= (1000 + 1.5C_s\rho_s)\frac{0.116}{\sqrt{t_s}} \end{aligned}$$

5. Initial design: choose grid spacing $D$, depth $h$, total conductor length $L_T$ and number of rods, covering the whole area plus about 1 m beyond the fence.
6. Grid resistance (Sverak):

$$R_g = \rho\left[\frac{1}{L_T} + \frac{1}{\sqrt{20A}}\left(1 + \frac{1}{1 + h\sqrt{20/A}}\right)\right]$$

7. Ground potential rise: $GPR = I_G R_g$. If $GPR < E_{touch}$, the design is safe; go to step 10.
8. Mesh and step voltages:

$$E_m = \frac{\rho K_m K_i I_G}{L_M},\qquad E_s = \frac{\rho K_s K_i I_G}{L_S}$$

9. Check and modify: require $E_m < E_{touch}$ and $E_s < E_{step}$. If not, reduce spacing, add conductors or rods, add crushed rock, or extend the grid, and repeat.
10. Detailed design: connect all equipment frames, neutrals, fences, lightning arresters and cable sheaths; check transferred potentials; target resistance typically below 1 Ω for large stations.

The generator must match the turbine, the grid and the site. The main factors are:

1. Rating (MVA) and power factor: $S = P_{turbine}\,\eta_g / \cos\phi$; power factor usually 0.85–0.9 lagging so the unit can supply reactive power. Some overload margin (e.g. 10%) is often specified.
2. Rated voltage: usually 6.6 kV or 11 kV for hydro units (higher, e.g. 13.8–15.75 kV, for very large units); chosen with GSU and bus/cable cost.
3. Speed and number of poles: fixed by the turbine: $N = 120f/p$. Hydro units are slow, salient-pole machines with many poles.
4. Shaft arrangement: vertical (large Francis/Kaplan) or horizontal (small Pelton/Francis).
5. Reactances and SCR: $X''_d$ sets fault level and breaker rating; SCR and $X_d$ set stability and voltage regulation.
6. Inertia constant (GD²): larger inertia limits speed rise on load rejection and improves stability, but costs more.
7. Efficiency and losses: high efficiency (above 97–98%) saves energy over the plant life.
8. Insulation and temperature rise: class F insulation with class B temperature rise is common; altitude derating above 1000 m.
9. Cooling: air-cooled (open or closed with air–water coolers) for hydro.
10. Excitation system: brushless for small/medium units, static for large units.
11. Neutral grounding: high-resistance grounding via NGT.
12. Grid requirements: capability curve, reactive power range, fault ride-through, harmonics.
13. Transport and erection limits: weight and size on hill roads; split stator if needed.
14. Standards and cost: IEC 60034; capital cost versus loss capitalisation.

Example

For a 10 MW turbine output, $\eta_g = 0.97$, pf 0.85: generator rating $= 10 \times 0.97/0.85 \approx 11.4$ MVA, 11 kV, 50 Hz; if the turbine speed is 600 rpm, poles $= 120 \times 50/600 = 10$.

Significance of SCR in generator design

• Air gap and size: a high SCR needs a low $X_d$, i.e. a larger air gap and more field ampere-turns; the machine becomes larger, heavier and costlier.
• Stability: higher SCR gives a higher steady-state power limit and stronger synchronizing torque.
• Voltage regulation: higher SCR → smaller voltage drop with load, so better regulation.
• Fault level: higher SCR → higher steady short-circuit current, so heavier switchgear.
• Line charging: a high-SCR machine can charge long, lightly loaded lines without self-excitation.
• Losses: a larger field current increases field losses. So SCR is a compromise between cost and performance; hydro generators connected by long lines are usually given SCR of about 1.0–1.2 or more.

Impact on stability

Short circuit ratio (SCR) is the ratio of field current needed to produce rated open-circuit voltage to the field current needed to circulate rated armature current on a sustained three-phase short circuit:

$$SCR = \frac{I_f\ (\text{rated OC voltage})}{I_f\ (\text{rated SC current})} \approx \frac{1}{X_d\,(\text{p.u., saturated})}$$

Typical values: salient-pole hydro generators 1.0–1.5; cylindrical-rotor turbo generators 0.5–0.7.

Analytical relation with stability

Power delivered by a generator (neglecting resistance and saliency) to an infinite bus:

$$P = \frac{E V}{X_d}\sin\delta = E\,V\,(SCR)\sin\delta$$

• Maximum (steady-state limit) power: $P_{max} = \dfrac{EV}{X_d} = E\,V\,(SCR)$. Lower SCR → lower $P_{max}$.
• Load angle for given load: $\sin\delta = \dfrac{P}{E\,V\,(SCR)}$. Lower SCR → larger $\delta$, closer to the 90° limit.
• Synchronizing power coefficient: $P_s = \dfrac{dP}{d\delta} = E\,V\,(SCR)\cos\delta$. Lower SCR → smaller restoring torque after a disturbance.

Numerical illustration ($E = 1.8$ p.u. kept the same, $V = 1$ p.u., $P = 0.85$ p.u.):

So the lower the SCR, the lower the stability margin (higher $\delta$, smaller $P_{max}$ and $P_s$).

On a $P$–$\delta$ graph, a lower SCR gives a flatter sine curve with a lower peak, so the operating point sits closer to the peak and a smaller disturbance can push the machine out of step.

Short circuit ratio $SCR \approx 1/X_d$ (p.u.). Its value changes the size, cost and behaviour of a synchronous generator.

Consequences in brief

• Too high SCR: an over-sized, expensive machine with higher fault levels and more field losses; benefits may not justify the cost.
• Too low SCR: cheaper machine but poor stability margin and voltage regulation; needs fast excitation (static, with PSS) and careful operation; risk of losing synchronism on a weak grid.
• Typical values: hydro (salient pole) 1.0–1.5, turbo generators 0.5–0.7.

A brushless excitation system supplies DC to the rotor of a synchronous generator without brushes or slip rings. A small AC exciter and a diode rectifier are mounted on the generator shaft, so the rectified current goes straight into the field winding.

Schematic

 BRUSHLESS EXCITATION
        stationary | rotating (on shaft)
 PMG/aux --> AVR   |
 supply     |      |
            v      |
   Exciter field   |  Exciter armature (3-ph)
   (stator) ~~~~~~~|~~~~> |
                   |   Rotating diode bridge
                   |      |
                   |   Main field (rotor)
                   |      |
               Main generator stator --> Grid

Working

1. A permanent magnet generator (PMG) on the same shaft (or an auxiliary supply) feeds the AVR.
2. The AVR compares generator terminal voltage with the set value and controls the DC current in the stationary field of the AC exciter.
3. The exciter armature rotates with the shaft and produces three-phase AC.
4. A rotating diode bridge on the shaft converts this AC into DC.
5. This DC flows directly into the main field winding on the rotor; the main generator then produces terminal voltage.
6. If voltage falls (load increase), the AVR raises exciter field current → exciter output rises → main field current rises → terminal voltage is restored.
7. Fuses protect the diodes; a rotor earth-fault relay works through a slip-ring-free telemetry or injection device.

When to recommend brushless excitation

• Small and medium hydro plants, especially remote or unmanned stations in Nepal, where low maintenance is important.
• Where carbon dust from brushes is a problem (enclosed or humid powerhouses) or in hazardous atmospheres.
• High-speed machines (horizontal Pelton/Francis units, turbo generators) where slip ring wear is high.
• Where the generator feeds a weak/isolated system and a PMG-fed AVR keeps excitation during faults.
• When very fast excitation response is not required for system stability (for large units on a stressed grid, static excitation is preferred).

A medium size generator (roughly 5–100 MVA) is protected against internal faults, abnormal operating conditions and system disturbances. Typical schemes, with ANSI device numbers:

Mechanical/hydraulic protections

Overspeed, bearing and oil temperature, vibration, cooling water failure, low oil pressure, shear pin failure.

Tripping logic

Faults like 87G, 64G, 64R (second stage) trip the GCB, field breaker and turbine (emergency shutdown); abnormal conditions like 46, 49 or 81 first alarm, then trip after a time delay.

In a power plant, the generator is connected to the grid through a step-up transformer. Two common schemes are (1) the unit scheme, one generator to one transformer, and (2) the grouped (combined) scheme, two generators to one transformer.

Scheme 1: Unit connection (one generator – one transformer)

   G1          G2
   |           |
  GCB         GCB
   |---UAT     |---UAT
  GSU1        GSU2
   |           |
  HV CB       HV CB
   |           |
 ===================== HV bus

• Fault level: a fault on the generator bus is fed by one generator plus the grid through one GSU impedance; LV fault level is lower, so GCB and bus duct ratings are smaller.
• Maintenance outage: a GSU fault or maintenance takes out only its own unit; other units keep running. Each unit is independent.
• Efficiency: each transformer runs close to full load when its unit runs; when a unit is off, its transformer can be disconnected, so no-load losses are saved. But total no-load and load loss of several small transformers is higher than one large transformer, and cost is higher.
• Reliability: highest; widely used for large units.

Scheme 2: Grouped connection (two generators – one transformer)

   G1          G2
   |           |
  GCB1        GCB2
   |           |
 ================ LV (11 kV) bus
         |---- Station transformer
        GSU (2 x unit rating)
         |
        HV CB
         |
 ================ HV bus

• Fault level: a fault on the LV bus is fed by both generators plus the grid, so the LV fault level is much higher; GCBs and bus need higher breaking capacity.
• Maintenance outage: a GSU fault or maintenance takes out both units, so energy loss is larger. A generator can be taken out by its own GCB while the other runs.
• Efficiency: one large transformer has lower cost per MVA and lower total losses at full load; but when only one unit runs (dry season), the transformer runs at half load and its full no-load loss remains.
• Cost: fewer transformers, HV breakers and bays, so cheaper and smaller switchyard; common for small and medium hydro in Nepal.

Comparison

A technical specification for a power plant's power (step-up) transformer lists the ratings, design, performance and test requirements so that bidders quote a transformer that fits the plant and grid. A typical specification (following IEC 60076) for a hydropower GSU is:

The rating is fixed from generator MVA (e.g. two 15 MVA units → 30 MVA), impedance from fault-level and stability studies, and BIL from the insulation coordination of the HV system.

A capability curve (P–Q chart) of a synchronous generator shows the region of active power $P$ and reactive power $Q$ in which the generator can operate continuously without exceeding thermal and stability limits. Operators use it to set loading and VAr output.

 Q (lagging, over-excited)
  ^
  |-------._    field heating limit
  |         '.
  |           \
  |            |  <- turbine limit
  |            |     (P = Pmax)
  +------------+---> P
  |            |  <- stator heating
  |           /      limit (circle S)
  |   ______.'
  |  under-excitation /
  |  stability limit
  v
 Q (leading, under-excited)

Limits that form the curve

1. Stator (armature) current heating limit: $P^2 + Q^2 = (V I_a)^2 = S^2$; a circle centred at the origin with radius equal to rated MVA.
2. Field (rotor) current heating limit: maximum excitation emf $E_{max}$ gives a circle centred at $(0, -V^2/X_s)$ with radius $E_{max}V/X_s$. This limits the lagging (over-excited) region.
3. Prime mover (turbine) limit: maximum turbine output, a vertical line $P = P_{max}$.
4. Under-excitation limits: in the leading region, the steady-state stability limit ($\delta$ approaching 90°, with practical margin) and stator end-core heating limit the VAr absorption.
5. Minimum load limit: some turbines (e.g. Francis) cannot run stably below about 40% load.

Use

• Rated point lies where the stator circle meets the field circle at rated power factor (e.g. 0.85 lagging).
• Shows how much reactive power the unit can supply or absorb at a given $P$, needed for grid voltage control and for setting AVR limiters (over-excitation and under-excitation limiters).

A neutral grounding transformer (NGT) is a single-phase distribution-type transformer connected between the generator neutral and earth, with a resistor on its secondary. The resistor, reflected to the primary as a high resistance, gives high-resistance grounding of the generator.

   Generator (star)
     \ | /
      \|/  neutral
       |
   NGT primary (e.g. 11 kV/sqrt3)
     |||
   NGT secondary (e.g. 240 V)
       |
      [R]  loading resistor
       |    + 59N relay across R
      ===  earth

Purpose: limits stator earth fault current to about 5–15 A, preventing core damage; limits transient overvoltages during arcing faults; allows sensitive stator earth fault protection (59N relay across the resistor).

Steps to find optimal size of NGT

1. Total capacitance to earth per phase $C_0$: stator winding, generator bus duct/cables, GSU LV winding, surge capacitors and VT windings.
2. Capacitive earth fault current:

$$I_C = 3\omega C_0 V_{ph}, \quad V_{ph} = \frac{V_L}{\sqrt{3}}$$

3. Choose resistor current $I_R \geq I_C$ (resistance not more than the capacitive reactance), so that transient overvoltage stays below about 2.6 p.u.:

$$R_N \leq \frac{1}{3\omega C_0}$$

4. NGT voltage ratio: primary rated at generator phase-to-neutral voltage (often line voltage for safety margin), secondary e.g. 240 V; turns ratio $n = V_1/V_2$.
5. Secondary resistor value: $R_2 = R_N / n^2$.
6. NGT kVA rating: $S = V_{ph} \times I_R$ (short-time rating for 1 min or until protection trips), giving a smaller, cheaper transformer than a continuous rating.
7. Check: total fault current $I_f = \sqrt{I_R^2 + I_C^2}$ is within the allowed limit (typically below 10–15 A) and the relay sensitivity covers about 95% of the winding.

A generator circuit breaker (GCB) is placed between the generator and the step-up transformer. For a hydropower station, an SF6 generator circuit breaker (or a vacuum GCB for small and medium units), designed and tested to IEEE C37.013 / IEC 62271-37-013, is suitable. A normal distribution breaker built to IEC 62271-100 is not adequate.

Why a special GCB is needed

1. High DC component: the generator circuit has a high X/R ratio, so the fault current DC offset decays slowly; currents can have delayed current zeros. The GCB must interrupt such asymmetric currents.
2. High rate of rise of TRV: the transformer and generator have small capacitance, so the transient recovery voltage rises very fast; SF6 and vacuum interrupters can withstand it.
3. High continuous current: e.g. a 30 MVA unit at 11 kV carries about 1.6 kA; large units carry tens of kA.
4. Out-of-phase switching: the GCB must interrupt during unsuccessful synchronisation.
5. Frequent operation: hydro units start and stop daily (peaking), so a long mechanical and electrical life is needed.

Why SF6 (or vacuum)

• SF6 has excellent arc-quenching and dielectric strength, handles high currents and asymmetry, and is compact; it is the usual choice for medium and large hydro units.
• Vacuum GCBs are compact and maintenance-free for small/medium units; precautions: current chopping may cause overvoltage, so surge arresters and RC surge suppressors are fitted near the generator and transformer.
• Air-blast and oil breakers are obsolete for this duty.

Benefits of using a GCB

• Generator faults are cleared fast and selectively; the unit is synchronised on the LV side.
• Station auxiliaries can be fed from the grid through the GSU when the generator is off (back-feeding), so a separate station transformer may not be needed.
• Better protection of the GSU and generator, higher plant availability.

The unit transformer (generator step-up transformer of a unit) connects a generator to the HV system. Its electrical characteristics must suit both the generator and the grid.

Electrical characteristics considered

1. Rated MVA: at least the generator rated MVA (e.g. 15 MVA for a 12.75 MW, 0.85 pf unit); some margin for overload and the unit auxiliary load.
2. Voltage ratio: LV equal to generator voltage (e.g. 11 kV); HV equal to grid voltage plus margin for line drop (e.g. 132 kV).
3. Vector group: YNd11 is common: delta on generator side blocks zero-sequence and third harmonics; star-earthed HV gives an earthed system.
4. Percentage impedance: about 8–14%. Higher impedance reduces fault level and breaker rating; lower impedance improves voltage regulation and stability. Fixed by fault-level and stability studies.
5. Tappings: off-circuit taps (e.g. ±2 × 2.5%) or OLTC on HV, to match grid voltage and control VAr flow.
6. Losses and efficiency: no-load (iron) and load (copper) losses are capitalised; low losses save energy for 30+ years.
7. Insulation level (BIL) and temperature rise: HV BIL as per insulation coordination; temperature rise per IEC 60076 (oil 60 K, winding 65 K); altitude correction above 1000 m.
8. Cooling: ONAN/ONAF for outdoor; OFWF in underground powerhouses.
9. Overfluxing capability: must withstand V/Hz rise on load rejection (e.g. 1.1 p.u. continuous, 1.4 p.u. for a few seconds).
10. Short-circuit withstand: thermal and dynamic for 2 s per IEC 60076-5.
11. Magnetising inrush and noise level.
12. Standards: IEC 60076.

Factors for the choice of generator

1. Rating (MVA) and power factor: $S = P_{turbine}\,\eta_g / \cos\phi$; power factor usually 0.85–0.9 lagging so the unit can supply reactive power. Some overload margin (e.g. 10%) is often specified.
2. Rated voltage: usually 6.6 kV or 11 kV for hydro units (higher, e.g. 13.8–15.75 kV, for very large units); chosen with GSU and bus/cable cost.
3. Speed and number of poles: fixed by the turbine: $N = 120f/p$. Hydro units are slow, salient-pole machines with many poles.
4. Shaft arrangement: vertical (large Francis/Kaplan) or horizontal (small Pelton/Francis).
5. Reactances and SCR: $X''_d$ sets fault level and breaker rating; SCR and $X_d$ set stability and voltage regulation.
6. Inertia constant (GD²): larger inertia limits speed rise on load rejection and improves stability, but costs more.
7. Efficiency and losses: high efficiency (above 97–98%) saves energy over the plant life.
8. Insulation and temperature rise: class F insulation with class B temperature rise is common; altitude derating above 1000 m.
9. Cooling: air-cooled (open or closed with air–water coolers) for hydro.
10. Excitation system: brushless for small/medium units, static for large units.
11. Neutral grounding: high-resistance grounding via NGT.
12. Grid requirements: capability curve, reactive power range, fault ride-through, harmonics.
13. Transport and erection limits: weight and size on hill roads; split stator if needed.
14. Standards and cost: IEC 60034; capital cost versus loss capitalisation.

Lower SCR gives lower stability (analytical proof)

Short circuit ratio (SCR) is the ratio of field current needed to produce rated open-circuit voltage to the field current needed to circulate rated armature current on a sustained three-phase short circuit:

$$SCR = \frac{I_f\ (\text{rated OC voltage})}{I_f\ (\text{rated SC current})} \approx \frac{1}{X_d\,(\text{p.u., saturated})}$$

Typical values: salient-pole hydro generators 1.0–1.5; cylindrical-rotor turbo generators 0.5–0.7.

Analytical relation with stability

Power delivered by a generator (neglecting resistance and saliency) to an infinite bus:

$$P = \frac{E V}{X_d}\sin\delta = E\,V\,(SCR)\sin\delta$$

• Maximum (steady-state limit) power: $P_{max} = \dfrac{EV}{X_d} = E\,V\,(SCR)$. Lower SCR → lower $P_{max}$.
• Load angle for given load: $\sin\delta = \dfrac{P}{E\,V\,(SCR)}$. Lower SCR → larger $\delta$, closer to the 90° limit.
• Synchronizing power coefficient: $P_s = \dfrac{dP}{d\delta} = E\,V\,(SCR)\cos\delta$. Lower SCR → smaller restoring torque after a disturbance.

Numerical illustration ($E = 1.8$ p.u. kept the same, $V = 1$ p.u., $P = 0.85$ p.u.):

So the lower the SCR, the lower the stability margin (higher $\delta$, smaller $P_{max}$ and $P_s$).

Physically, a low SCR means a high synchronous reactance, i.e. weak magnetic coupling between rotor and stator through a small air gap; the generator must swing to a larger angle to transmit the same power, leaving less margin before it slips a pole.

Factors for the choice of generator

1. Rating (MVA) and power factor: $S = P_{turbine}\,\eta_g / \cos\phi$; power factor usually 0.85–0.9 lagging so the unit can supply reactive power. Some overload margin (e.g. 10%) is often specified.
2. Rated voltage: usually 6.6 kV or 11 kV for hydro units (higher, e.g. 13.8–15.75 kV, for very large units); chosen with GSU and bus/cable cost.
3. Speed and number of poles: fixed by the turbine: $N = 120f/p$. Hydro units are slow, salient-pole machines with many poles.
4. Shaft arrangement: vertical (large Francis/Kaplan) or horizontal (small Pelton/Francis).
5. Reactances and SCR: $X''_d$ sets fault level and breaker rating; SCR and $X_d$ set stability and voltage regulation.
6. Inertia constant (GD²): larger inertia limits speed rise on load rejection and improves stability, but costs more.
7. Efficiency and losses: high efficiency (above 97–98%) saves energy over the plant life.
8. Insulation and temperature rise: class F insulation with class B temperature rise is common; altitude derating above 1000 m.
9. Cooling: air-cooled (open or closed with air–water coolers) for hydro.
10. Excitation system: brushless for small/medium units, static for large units.
11. Neutral grounding: high-resistance grounding via NGT.
12. Grid requirements: capability curve, reactive power range, fault ride-through, harmonics.
13. Transport and erection limits: weight and size on hill roads; split stator if needed.
14. Standards and cost: IEC 60034; capital cost versus loss capitalisation.

Significance of SCR in generator selection

$SCR \approx 1/X_d$ (p.u.). It is specified in the purchase specification because:

• Stability: steady-state limit $P_{max} = EV\,(SCR)$; higher SCR gives a larger stability margin, important for plants connected to the grid through long lines.
• Voltage regulation: higher SCR gives less voltage change with load.
• Line charging: high SCR prevents self-excitation when charging long, unloaded lines.
• Cost and size: higher SCR needs a larger air gap and more field copper, making the machine heavier and costlier.
• Fault level: higher SCR raises short-circuit current and switchgear rating. Typical selection: hydro units about 1.0–1.2 (salient pole), turbo units 0.5–0.7.

A brushless excitation system uses a shaft-mounted AC exciter and rotating diodes, while a static excitation system uses a thyristor bridge fed from the generator terminals with slip rings and brushes. Brushless is recommended mainly for reliability, low maintenance and independence from terminal voltage.

 BRUSHLESS EXCITATION
        stationary | rotating (on shaft)
 PMG/aux --> AVR   |
 supply     |      |
            v      |
   Exciter field   |  Exciter armature (3-ph)
   (stator) ~~~~~~~|~~~~> |
                   |   Rotating diode bridge
                   |      |
                   |   Main field (rotor)
                   |      |
               Main generator stator --> Grid

Logic behind recommending brushless over static

1. No brushes or slip rings: removes the main wear part of the static system; no brush replacement, no sparking, no carbon dust that contaminates windings and causes insulation failure.
2. Low maintenance and high availability: ideal for remote, small and medium hydro plants in Nepal where skilled staff and spares are limited.
3. Self-contained supply: with a PMG-fed AVR, excitation does not depend on generator terminal voltage, so excitation stays available during close-in faults and the machine can build up voltage without field flashing from a battery; this helps black start.
4. Better for high speeds: slip ring wear and heating grow with peripheral speed, so high-speed units favour brushless.
5. Safer environment: no open sparking; suitable for dusty, humid or hazardous areas.
6. Fewer external components: no excitation transformer, large thyristor cubicle or field breaker; less space in the powerhouse.
7. Economical for small and medium ratings.

Limitations to keep in mind

• Slower response (exciter time constant), no negative field forcing, so less help for transient stability.
• Rotor current and diode health are hard to monitor; a failed diode needs shutdown to replace.
• For large units on a weak grid, static excitation remains the better choice.

A brushless excitation system supplies the synchronous generator field from a shaft-mounted AC exciter whose output is rectified by a rotating diode bridge, so no brushes or slip rings are needed between the exciter and the main field.

Working

1. A small permanent magnet generator (PMG) or station supply feeds the AVR.
2. The AVR controls a thyristor bridge that feeds the stationary field of the AC exciter.
3. The AC exciter has a rotating armature on the main shaft. Its 3-phase output goes to a rotating diode rectifier mounted on the same shaft.
4. The rectified DC goes directly to the main generator field winding.

 PMG --> AVR --> Exciter field (stator)
                       |
   ===== shaft ========|=====================
   Exciter armature -> Rotating diodes -> Main field
   (rotating)          (rotating)        (rotor)
                                            |
                         Main stator --> Gen terminals

Best alternative

The best alternative is the static (thyristor) excitation system, where the field is fed from the generator terminals through an excitation transformer and thyristor bridge, using slip rings.

Pros of brushless excitation (compared with static)

• No brushes or slip rings: low maintenance, no carbon dust, no brush sparking; good for remote, unmanned plants and hazardous areas.
• Excitation power is taken from the shaft, so it is independent of generator terminal voltage; it can supply field current during close-in faults (good for fault current support and relay operation).
• Self-contained with a PMG: no need for an external supply or field flashing at start.
• Fewer external power components (no large excitation transformer or high-current thyristor cubicle).

Cons of brushless excitation (compared with static)

• Slow response: the exciter field time constant (about 0.5–1 s) adds delay, so transient stability support is poorer than static excitation (response in tens of ms).
• No fast field de-excitation: the main field cannot be forced negative or shorted quickly; field suppression after a fault is slow because the decay depends on the rotor time constant.
• Rotating diodes and fuses cannot be inspected while running; diode failure needs special monitoring.
• Longer shaft and extra rotating mass; higher cost for very large machines.
• Rotor field current and voltage cannot be measured directly.

A static excitation system is one in which the generator field is fed with DC from a thyristor (SCR) rectifier that has no rotating parts. The power is taken from the generator terminals through an excitation transformer and reaches the rotor through slip rings and brushes.

Working

1. An excitation transformer connected to the generator terminals steps the voltage down.
2. A fully controlled 3-phase thyristor bridge rectifies it. The AVR changes the firing angle $\alpha$ to control the field voltage, $V_f \propto 1.35\,V_{ac}\cos\alpha$.
3. The DC goes to the field through slip rings. A field breaker and a discharge resistor/crowbar are provided for de-excitation.
4. At start the terminal voltage is zero, so field flashing from the station battery or AC supply builds up the initial voltage.

 Gen terminals -> Exc. transformer -> Thyristor bridge
                                           |
            PT, CT -> AVR (firing angle) --+
                                           v
 Battery -> Field flashing -> Field CB -> Slip rings
                                           |
                                      Main field

Best alternative

The main alternative is the brushless excitation system: an AC exciter with rotating diodes mounted on the shaft.

Pros (compared with brushless)

• Very fast response: the field voltage changes almost at once. A high ceiling voltage (often 1.6–2 times rated or more) improves transient stability.
• Fast de-excitation: the bridge can work in inverter mode (negative field voltage) to kill the field quickly during internal faults.
• No rotating exciter, so the shaft is shorter and the machine is simpler. Easy to fit in an existing plant.
• Field voltage and current can be measured directly, and PSS and limiters can be added easily.
• Thyristors are easy to reach for maintenance and redundant bridges can be used.

Cons (compared with brushless)

• Needs slip rings and brushes, so brush wear, carbon dust and regular maintenance.
• Supply comes from the generator terminals, so during a close three-phase fault the terminal voltage collapses and the excitation is lost unless there is compound (CT) support. Fault current may decay before the relays act.
• Needs field flashing for start.
• The thyristors produce harmonics and shaft voltages. Cooling and a large transformer are needed.

Both are modern excitation systems for synchronous generators. They differ in where the rectifier is and how DC reaches the field.

Brushless excitation system

• A PMG (pilot exciter) on the shaft supplies the AVR.
• The AVR feeds DC to the stationary field of the main AC exciter.
• The AC exciter armature rotates with the shaft and produces 3-phase AC.
• A rotating diode bridge on the shaft rectifies it and feeds the main field directly. No brushes are needed.
• The AVR controls the exciter field, which in turn controls the main field.

 PMG ---> AVR ---> Exciter field (stationary)
                         :  (air gap)
 [ROTOR] Exciter armature -> Diode bridge -> Main field
                                                :
 Main stator ---> Generator terminals ---> PT/CT to AVR

Static excitation system

• An excitation transformer fed from the generator terminals supplies a thyristor bridge.
• The AVR compares the terminal voltage with the set value and changes the firing angle of the thyristors.
• The DC output goes to the rotor through a field breaker and slip rings/brushes.
• At start, field flashing from the battery gives the initial field until the voltage builds up.

 Gen terminals -> Exc. transformer -> Thyristor bridge
                                          |  (alpha)
                       AVR <- PT, CT      |
                                          v
 Battery -> Field flashing -> Field CB -> Slip rings
                                              |
                                          Main field

An electronic automatic voltage regulator (AVR) keeps the generator terminal voltage at the set value by measuring it continuously and adjusting the field current through power-electronic switches (thyristors or transistors), with no moving parts.

Principle

It is a closed-loop (feedback) control system. The error between the reference voltage $V_{ref}$ and the measured voltage $V_t$ is amplified and used to change the exciter field:

$$E_{fd} = K_A\,(V_{ref} - V_t + V_s)$$

where $K_A$ is the amplifier gain and $V_s$ is the signal from the stabiliser (PSS). If $V_t$ falls (for example, when load increases), the error rises, the field current increases and the voltage comes back.

Block diagram

 Vref -->( + )--> Amplifier -> Firing -> Thyristor
           ^ -     (PID)        circuit   bridge
           |                                 |
           |                                 v
           |                          Exciter / field
           |                                 |
        Rectifier                            v
        & filter <------- PT <------- Generator Vt
           ^
     Stabilising feedback / limiters

Main parts and their work

1. Sensing (PT + rectifier + filter): steps down the terminal voltage, rectifies and smooths it into a DC signal proportional to $V_t$. Often the reactive current from a CT is added (load compensation/droop) so parallel units share vars.
2. Comparator (error detector): compares the sensed signal with a stable reference (zener or digital set-point).
3. Amplifier / controller: op-amp or digital PID amplifies the error.
4. Firing circuit: converts the control voltage into a firing angle $\alpha$ for the thyristors. Smaller $\alpha$ gives more field voltage, since $V_{dc} = 1.35\,V_{ac}\cos\alpha$ for a full bridge.
5. Power stage: thyristor bridge feeding the exciter field (brushless) or main field (static).
6. Stabilising feedback: rate feedback from the field voltage, or a PSS, damps hunting and oscillations.
7. Limiters and protection: over-excitation limiter, under-excitation limiter, V/Hz limiter, stator current limiter.

Operation

• Steady state: firing angle fixed, $V_t = V_{ref}$.
• Load increases or lagging power factor: $V_t$ drops, error positive, $\alpha$ decreases, field current rises, $V_t$ restored.
• Load rejection: $V_t$ rises, $\alpha$ increases (or inverts), field reduced.

Modes

• Auto mode: voltage control as above.
• Manual mode: field current control, used for testing or when the PT fails.

Advantages over electromechanical regulators

• Fast response with no dead band.
• No moving contacts, so little maintenance.
• Accurate regulation (about ±0.5 %).
• Easy to add limiters, PSS and remote control.

The capability curve of an alternator is a P–Q chart that shows the safe region of operation, i.e. the combinations of active power P and reactive power Q that the machine can deliver continuously at rated voltage without exceeding any limit.

Elements that limit the curve

1. Armature (stator) current heating limit: $S = \sqrt{P^2 + Q^2} = 3V_tI_a$. At rated $V_t$ this is a circle centred at the origin with radius equal to rated MVA.
2. Field (rotor) current heating limit: the maximum excitation $E_f$ allowed by rotor heating. It is a circle centred at $(0, -3V_t^2/X_s)$ with radius $3V_tE_f/X_s$. It limits operation at lagging (over-excited) power factor.
3. Prime mover (turbine) limit: maximum mechanical power, a vertical line $P = P_{max}$.
4. Steady-state stability limit: at leading power factor the load angle approaches $90^\circ$. A practical limit with margin is used.
5. Stator end-core heating limit: in under-excited operation leakage flux heats the stator ends and limits leading-var absorption.
6. Minimum excitation / minimum turbine load: for example cavitation zones in hydro turbines limit low load.

Typical capability curve

  Q lagging (MVAr)
   ^
   |~~~~~--..    <- field current limit
   |    A     `.
   |            o  <- rated MVA, rated pf
   |            |  <- stator current limit
   |            |  <- turbine (max P) limit
   +------------+------> P (MW)
   |            |
   |    B      /
   |       ..-`  <- stability / end-core limit
   |..--~~
   v  Q leading (MVAr)

Explanation

• Region A (over-excited, lagging pf): the field current limit is the binding curve from zero P up to the rated power factor point. Above rated pf (more P), the stator current limit governs.
• Rated point: where the field and stator limit circles meet, i.e. rated MVA at rated pf (e.g. 0.85 lagging).
• High P region: the stator circle and the turbine limit line cut off the curve.
• Region B (under-excited, leading pf): the steady-state stability limit (with margin) and stator end heating limit how much reactive power the machine can absorb.
• The operator must keep the operating point inside the enclosed area. The AVR limiters (OEL, UEL) are set from this curve.

The speed governing system of a hydro generator controls the turbine's water flow (wicket gate or needle opening) so that the speed, and hence the frequency, stays constant and load is shared between units in parallel.

Components

• Speed sensor: a PMG or toothed wheel with pick-up giving speed/frequency.
• Governor controller: electronic PID; compares actual speed with the reference and includes droop (permanent speed regulation, usually 4–5 %).
• Electro-hydraulic converter / proportional valve: turns the electrical signal into oil flow.
• Pilot and main distributing valves, servomotor: move the wicket gates (Francis/Kaplan) or the needle and deflector (Pelton).
• Oil pressure unit: pump, accumulator and sump.
• Feedback: gate position transducer.

 f_ref -->( + )--> PID + droop --> E/H valve --> Servomotor
            ^ -                                     |
            |                                 Wicket gates
         Speed sensor <-- Generator <-- Turbine <---+

Working

• Load increases: speed falls, the error opens the gates, more water flows and the speed recovers.
• Droop makes each unit pick up load in proportion to its rating.
• Hydro needs slow gate movement (temporary droop/dashpot) because of water hammer and the water starting time $T_w$. Pelton turbines use a deflector for quick load rejection.

Generator neutral grounding means connecting the star point of the stator winding to earth, directly or through an impedance, to limit earth-fault current, control overvoltages and allow earth-fault protection.

Types

1. Ungrounded (isolated neutral)
2. Solid (effective) grounding: neutral connected straight to earth.
3. Low-resistance grounding: resistor limits fault current to about 100–1000 A.
4. Low-reactance grounding: reactor limits fault current to roughly 25–100 % of the 3-phase fault current.
5. High-resistance grounding: usually through a distribution transformer with a secondary resistor, limiting the fault current to about 5–15 A.
6. Resonant grounding (Petersen coil / ground fault neutraliser): reactor tuned to the stator capacitance; fault current nearly zero.

  Gen       Gen        Gen          Gen
  star      star       star         star
   |         |          |            |
   |        [R]        [X]        )||(  dist. tr.
  ===       ===        ===         [r] secondary
 solid    low-R     reactance    high-R

Selection according to plant size

Advantages and disadvantages

In Nepalese hydro plants, the common practice is a high-resistance grounding through a distribution (neutral grounding) transformer for unit-connected generators, and a neutral grounding resistor for small MV generators sharing a bus.

A grounded system has its neutral connected to earth (solidly or through an impedance). An ungrounded (isolated neutral) system has no intended connection to earth; it is only coupled to earth through the line-to-ground capacitances.

Comparison

Capacitive current in an ungrounded system

When one phase is earthed, the other two line capacitances charge to line voltage. The fault current is

$$I_f = 3\,\omega C_0\,V_{ph}$$

At fault currents above about 4–5 A this capacitive current causes arcing grounds: the arc repeatedly strikes and extinguishes, building up voltage on the healthy phases.

Conclusion for practice

Almost all modern power systems are grounded. The method depends on voltage level: solid for LV and EHV, resistance/reactance for MV, and high-resistance for unit-connected generators.

In solid grounding, the generator neutral is connected directly to the station earth with no intentional impedance.

Advantages

• Neutral held at earth potential: during a line-to-ground fault the healthy phases stay close to phase voltage, so there are no high overvoltages.
• No arcing-ground problem: the fault current is large and the arc does not restrike, so transient overvoltages are eliminated.
• Reduced insulation cost: equipment and lightning arresters can be rated for phase voltage (about 80 % arresters).
• Simple and reliable protection: the large earth-fault current operates ordinary overcurrent/earth-fault relays quickly and selectively.
• Simple and cheap: no resistor, reactor or transformer to buy and maintain.
• Supports single-phase loads: a 4-wire LV supply (phase-to-neutral loads) is possible, which is why small LV diesel and micro-hydro sets are usually solidly grounded.
• Better personnel safety because faults are cleared quickly.

Limitation

For large generators the earth-fault current can exceed the 3-phase fault current (since $X_0$ is small), causing stator core burning and severe mechanical stress, so solid grounding is used mainly on small LV machines.

Step potential is the voltage between a person's two feet, 1 m apart, when standing on the ground during an earth fault. Touch potential is the voltage between the hand touching an earthed metal structure and the feet standing on the ground. Both arise because fault current flowing into the soil makes the ground surface potential uneven.

   Earthed structure
        |  hand
        |---o   <- touch voltage = V(structure) - V(feet)
        |  /|\
  ======|==/=\==============  ground surface
        |  feet 1 m apart <- step voltage = V1 - V2
   ---- grid conductors (mat) buried ~0.5 m ----

How they are used in grid (mat) design (IEEE Std 80)

1. Tolerable limits are found first from the body current that the heart can withstand (Dalziel): $I_B = k/\sqrt{t_s}$, with $k = 0.116$ for a 50 kg person. With body resistance 1000 Ω:

$$\begin{aligned} E_{step,50} &= (1000 + 6C_s\rho_s)\,\frac{0.116}{\sqrt{t_s}} \\ E_{touch,50} &= (1000 + 1.5C_s\rho_s)\,\frac{0.116}{\sqrt{t_s}} \end{aligned}$$

where $\rho_s$ is the surface-layer resistivity, $C_s$ the surface layer derating factor and $t_s$ the fault clearing time.

2. Grid potential rise $GPR = I_G R_g$ is calculated. If GPR is below the tolerable touch voltage, the design is safe.
3. Otherwise the actual mesh voltage $E_m$ (worst touch voltage in a mesh corner) and actual step voltage $E_s$ are calculated from the grid geometry (spacing, conductor length, depth, soil resistivity).
4. The design is accepted only if $E_m < E_{touch}$ and $E_s < E_{step}$. If not, the grid is changed and the check repeated.

Why they are set this way

• Ensures that the current through a human body during the worst fault stays below the ventricular fibrillation threshold within the fault clearing time.
• Touch voltage is usually the critical one, because hand-to-feet current passes near the heart and the feet act in parallel, giving less resistance.

How they are kept within limits

• Close grid spacing and more conductors; extra rods at the perimeter.
• Surface layer of crushed rock/gravel (high $\rho_s$, about 3000 Ω·m), which raises the tolerable limits.
• Faster fault clearing (smaller $t_s$).
• Bonding all metal structures and fences to the grid; grading rings around equipment and at gates.
• Lowering grid resistance with deeper rods or treated soil.

A generator circuit breaker (GCB) must interrupt very high currents with a large DC component and a fast-rising TRV. A vacuum circuit breaker (VCB) chops current sharply, so special precautions are needed.

Precautions

• Surge protection against current chopping: install surge arresters (metal oxide) and RC surge suppressors / surge capacitors at the generator and transformer terminals, because chopping and re-ignition create high $L\,di/dt$ overvoltages on the inductive winding.
• Check DC component and delayed current zeros: the breaker must be type-tested to IEEE C37.013 / IEC 62271-37-013 for generator duty, since the DC offset can delay current zeros.
• TRV control: add capacitors to reduce the rate of rise of recovery voltage.
• Rate it for continuous current with proper cooling, and check vacuum integrity periodically.

Precautions when a VCB is used as a generator CB

A generator breaker sees a very high fault current with a large DC component (because of the high X/R ratio), delayed current zeros, and a very fast TRV rate of rise. A VCB interrupts so well that it can chop the current before natural zero. On the inductive generator and transformer windings this gives $V = L\,di/dt$ overvoltages and multiple re-ignitions. So:

1. Install metal-oxide surge arresters close to the breaker on both sides.
2. Install surge capacitors or RC snubbers at the generator terminals to slow the voltage rise and damp chopping overvoltages.
3. Choose a breaker type-tested for generator duty (IEEE C37.013 / IEC 62271-37-013), including asymmetrical breaking with high DC content and out-of-phase switching.
4. Check the TRV/RRRV capability; add TRV capacitors if needed.
5. Make sure the continuous current rating and temperature rise are adequate (forced cooling if needed).
6. Use low-chopping contact material (e.g. Cu–Cr) and monitor vacuum integrity.

Limitations of VCB compared with SF6 in HV application

Summary of VCB limitations at HV: the dielectric strength of a vacuum gap does not rise linearly with gap length, so a single bottle cannot be built economically above about 40 kV. Several bottles in series need voltage grading. Chopping overvoltages are higher and the continuous current rating is lower. For these reasons SF6 dominates above 72.5 kV, although SF6 is a greenhouse gas.

A vacuum circuit breaker (VCB) extinguishes the arc in a sealed vacuum bottle (about $10^{-6}$ to $10^{-4}$ torr), where the arc is a metal vapour arc that dies at current zero. An SF6 circuit breaker extinguishes the arc by blowing sulphur hexafluoride, an electronegative gas, across it. The gas captures free electrons and quickly restores dielectric strength.

Arc quenching in brief

• VCB: on contact separation, metal vapour from the contacts carries the arc. At current zero the vapour condenses on shields within microseconds, so the gap recovers very fast. Spiral or axial magnetic field contacts keep the arc diffuse.
• SF6: puffer or self-blast type. The moving piston compresses the gas and blows it through the nozzle onto the arc. SF6 has about 2–3 times the dielectric strength of air at the same pressure.

 VCB bottle               SF6 puffer interrupter
 +---------+              +-----------------+
 | fixed   |              | fixed contact   |
 |  ===    |              |   ==   <- gas   |
 |  shield |              |  nozzle  blast  |
 |  ===    |              |   ==  piston    |
 | moving  |              | moving contact  |
 +--bellows+              +-----------------+

Comparison

Use in power systems

• VCB: the usual choice for MV switchgear (11 kV and 33 kV feeders), generator terminals of small–medium hydro units, motor and capacitor bank switching, and frequent-operation duties.
• SF6: the usual choice for 132 kV, 220 kV and 400 kV outdoor switchyards and GIS. In Nepal the 132/220 kV substations of NEA use SF6 breakers, while 11/33 kV panels use VCBs.

For new designs, SF6-free alternatives (vacuum interrupter with clean air insulation) are spreading because of the environmental impact of SF6.

In a mega (large) hydro or thermal project, the alternator and its generator step-up (GSU) transformer are protected by a set of main and backup relays, usually grouped as a unit protection scheme with an overall differential zone.

Generator protections (ANSI number)

GSU transformer protections

Overall scheme

An overall (unit) differential 87GT covers the generator, GSU and unit auxiliary transformer together. Relays are duplicated as Main-1 and Main-2 groups with separate CTs and DC supplies for very large units. Trips go through a master trip relay (86) to the GCB, HV breaker, field breaker and turbine shutdown.

Restricted earth fault (REF) protection is a sensitive unit protection that detects earth faults inside a defined zone only, usually a star-connected transformer or generator winding. It compares the sum of the three phase currents with the neutral current.

Principle

• CTs are placed in each phase and in the neutral-to-earth connection, all of the same ratio.
• The three phase CTs are connected in parallel (residual connection) and then in parallel with the neutral CT, with a relay across them.
• External earth fault (outside the zone): the residual current from the phase CTs equals the neutral CT current, so they circulate between CTs and no current flows through the relay.
• Internal earth fault (inside the winding): the neutral current has no matching residual current, so the difference flows through the relay and it trips.

        A ---[CT]-----+---- to system
        B ---[CT]-----+
        C ---[CT]-----+
   Star |   |   |     |
  winding \ | /       |  residual
         \|/          |
     N ---+--[CT_N]---+---[ R ]--+
          |               relay  |
         earth   (high-impedance, with
                 stabilising resistor
                 and Metrosil)

Features

• Usually a high-impedance relay with a stabilising resistor so CT saturation on heavy external faults does not cause false trips. A non-linear resistor (Metrosil) limits voltage during internal faults.
• Very sensitive: it covers faults close to the neutral end, where the ordinary transformer differential (87T) is not sensitive enough. On a resistance-earthed winding a fault near the neutral gives very little phase current.
• Fast and stable.

Use

• HV star winding of the generator step-up transformer (solidly earthed side).
• Star winding of station/auxiliary transformers.
• Small generators with resistance earthing.

For a delta winding, REF is applied using an earthing transformer or the three phase CTs alone (balanced earth fault protection).

Unit protection scheme of a power transformer

The main unit protection of a power transformer is percentage-biased differential protection (87T), backed by restricted earth fault, Buchholz and others. It compares the currents entering and leaving the transformer. Inside the zone the difference trips the relay; for through faults the currents balance.

   HV bus         Power transformer        LV bus
  ---[CT1]-----+====( Yd11 )====+-----[CT2]---
       |       |   Buchholz(63) |        |
       |      REF(64)           |        |
       |                                 |
       +---> [ 87T  bias + operate ] <---+
               2nd harmonic block
               (inrush), 5th (overflux)
                    |
               Master trip 86 -> HV & LV CBs

Points to note:

• CT ratios and connections (or software settings) correct for the ratio and the phase shift of the vector group (for Yd11, CTs on the Y side connected in delta, or numerical compensation).
• Bias (restraint) handles CT mismatch and tap-changer range.
• 2nd harmonic restraint blocks tripping on magnetising inrush. 5th harmonic blocking is used for overfluxing.
• Supplementary protections: REF (64), Buchholz (63), oil/winding temperature (26/49), pressure relief (63PR), overcurrent and earth-fault backup (50/51, 51N), overfluxing (24).

Selection criteria for a power transformer

• Rated MVA: from generator rating (e.g. generator MVA plus margin), with cooling class ONAN/ONAF/OFAF.
• Voltage ratio: generator voltage to transmission voltage (e.g. 11/132 kV); tap changer range (OLTC or off-circuit, e.g. ±10 % in 1.25 % or 2.5 % steps).
• Vector group to suit the system and earthing (GSU usually YNd11 with HV star grounded).
• Impedance (% Z): balance between fault level limit and voltage regulation/stability; usually 10–14 % for GSU.
• Number of phases: three-phase unit or a bank of single-phase units (transport limits on hilly roads in Nepal).
• Insulation level: BIL and power-frequency withstand.
• Losses (no-load and load), efficiency and capitalised loss cost.
• Cooling, temperature rise, altitude derating, noise, transport size and weight.
• Standards: IEC 60076.

What the vector group reflects

The vector group (e.g. YNd11, Dyn11, Yy0) tells:

1. The winding connection of HV (capital letter: Y, D, Z) and LV (small letter: y, d, z).
2. Whether the neutral is brought out (N or n).
3. The phase displacement of LV with respect to HV by the clock number, each hour being $30^\circ$. For example "11" means LV leads HV by $30^\circ$ (11 o'clock position), and "1" means LV lags by $30^\circ$.

It is essential for parallel operation (only transformers with the same phase shift can be paralleled), for differential CT compensation, and for earthing and the third-harmonic path (a delta winding traps triplen harmonics).

Black start capability is the ability of a generating unit or plant to start itself and energise the dead bus and transmission lines without any power from the external grid, after a total or partial blackout. Such units are used to restore the system.

How a unit is made black-start capable

• Independent auxiliary supply: a diesel generator (DG) set or a small house/auxiliary hydro unit to power the station auxiliaries (governor oil pumps, cooling water pumps, lubrication, lighting).
• Station battery and DC system sized to operate breakers, protection, controls and field flashing during the dead period.
• Excitation able to build up from zero: field flashing from the battery (for static excitation), or a PMG-fed brushless exciter, which needs no external source.
• Governor and turbine that can start with stored oil pressure (accumulator) or DG-powered pumps; hydro gates or valves that can open on DC/stored energy.
• Controls and protection settings for isolated (island) mode: frequency control mode, dead-bus closing logic, synchronising for later reconnection.
• The unit must be able to energise transformers and lines (charging current, inrush) and carry the initial loads.

Hydro plants are ideal black-start sources because they start quickly and need little auxiliary power.

The DC supply system gives a reliable, uninterrupted power source for the vital control, protection and emergency loads of a power station, even when all AC supply is lost.

Requirements

• Loads served: relay and protection circuits, breaker trip and close coils, control and SCADA, alarms, emergency lighting, field flashing, DC emergency oil pumps (governor, bearing lube), communication (often 48 V).
• Voltage levels: typically 220 V or 110 V DC for control and switchgear, 48 V DC for telecom/PLCC, 24 V for some electronics.
• Battery bank: lead-acid (VRLA or flooded) or Ni-Cd, sized for the duty cycle (e.g. 1–3 hours of emergency load plus trip and close surges at the end), with ageing and temperature factors (IEEE 485).
• Battery chargers: float-cum-boost chargers fed from the station AC. Usually two chargers and two battery banks for redundancy in large stations.
• Distribution: DC distribution board with separate feeders, fuses/MCBs, and earth-fault monitoring because the DC system is unearthed.
• Reliability: separate battery room with ventilation (hydrogen), voltage monitoring and alarms, and regular capacity tests.

Depth of discharge (DOD)

Depth of discharge (DOD) is the fraction of a battery's rated capacity that has been taken out, expressed in percent:

$$\text{DOD} = \frac{\text{Ah discharged}}{\text{Rated Ah capacity}} \times 100\,\%$$

It is the complement of the state of charge: $\text{SOC} = 100\,\% - \text{DOD}$. For example, taking 60 Ah from a 200 Ah battery gives a DOD of 30 %.

Importance:

• A deeper DOD shortens battery life (fewer cycles). Lead-acid batteries are usually designed for 50–80 % maximum DOD, Ni-Cd and Li-ion can go deeper.
• Battery sizing for a station uses the allowed DOD and the end-of-discharge voltage (e.g. 1.75–1.8 V/cell for lead-acid).

Station service (auxiliary supply) schemes

Station service supplies the auxiliaries: pumps, cooling, governors, cranes, lighting, battery chargers. Common schemes:

1. Unit auxiliary transformer (UAT) tapped from the generator bus, with station transformer backup

 Gen G1 --+-- GSU T1 --+-- HV bus (132 kV)
          |            |
         UAT1     Station service tr (from HV bus)
          |            |
  Unit aux board 1 ----+---- Common station board
                                  |
                          DG set (standby / black start)

2. Common station service board fed from two sources (main bus and tertiary/grid)

 11 kV gen bus --> SST-1 --+
                           |-- 415 V board --> loads
 33/11 kV feeder -> SST-2 -+   (bus coupler)
                               |
               DG set --> Emergency board
                               |
           Battery charger --> DC board

Key features:

• At least two independent sources with automatic changeover (bus coupler).
• An emergency diesel generator for black start and essential loads.
• Unit boards for each generating unit's own auxiliaries, plus a common board for shared loads.
• Essential loads moved to the emergency board; DC system with its own battery for vital loads.

Auxiliary systems are the supporting systems that are needed for the main generating unit to start, run, and stop safely. Ancillary systems are plant-wide support systems (station services, safety, handling) that are not part of the energy conversion itself. For a 100 MW plant with Francis turbines (assume 2 × 50 MW or 3 units), they are as follows.

Mechanical auxiliary systems

Electrical auxiliary systems

Ancillary systems

In addition, the plant provides ancillary services to the grid: frequency regulation, reactive power/voltage support, spinning reserve and black start.

A busbar is a conductor in a switchyard to which incoming and outgoing circuits are connected. Its arrangement decides reliability, flexibility of maintenance and cost.

Types of HV busbar arrangement

1. Single bus: all circuits on one bus. Cheap, but any bus fault or maintenance shuts down everything.

   L1    L2    L3
   |     |     |
  [CB]  [CB]  [CB]
 ==+=====+=====+==  bus
  [CB]  [CB]
   |     |
   G1    T1

2. Sectionalised single bus: bus split by a bus-section breaker; a fault affects only one section.

3. Main and transfer bus: each circuit normally on the main bus; a bus coupler (transfer) breaker can take over any one feeder whose breaker is under maintenance.

 Main bus     ===+========+========+===
                 |        |        |
               [CB]     [CB]    [BC] coupler
                 |        |        |
 Transfer bus ---+--/ ----+--/ ----+---
                 |  bypass isolator
                 L1       L2

4. Double bus (double bus single breaker): two main buses; each circuit can be connected to either bus through isolators, with a bus coupler.

 Bus-1 ===+=========+=====+===
          |         |    [BC]
 Bus-2 ===+=========+=====+===
          | (isolators)
         [CB]      [CB]
          L1        L2

5. Double bus double breaker: each circuit has two breakers, one to each bus. Very reliable, costly.

6. Breaker-and-a-half (one-and-half breaker): three breakers for two circuits between two buses. Common at 220 kV and 400 kV.

7. Ring (mesh) bus: breakers form a closed loop; each circuit between two breakers.

Main and transfer bus: advantages

• Any feeder breaker can be taken out for maintenance without interrupting that feeder (it is fed through the transfer bus and bus coupler).
• Low cost compared with double bus or breaker-and-a-half: only one extra breaker.
• Simple layout and protection.
• Suitable for 33–132 kV substations.

Main and transfer bus: disadvantages

• A fault on the main bus or its maintenance shuts down the whole substation (no second main bus).
• Only one breaker at a time can be bypassed.
• Protection of the transferred feeder must be switched to the bus coupler, so switching is more complex and error-prone.
• More isolators and switching operations; needs interlocking.

The busbar layout of a substation is the arrangement of buses, breakers and isolators that connects incoming and outgoing circuits. The choice is a trade-off between reliability, operational flexibility, maintenance and cost.

1. Single busbar

   L1     L2     L3
  [CB]   [CB]   [CB]
 ==+======+======+==
  [CB]   [CB]
   T1     T2

Cheap and simple. A bus fault or bus maintenance causes a full outage. Used for small 11/33 kV substations.

2. Sectionalised single busbar

 ==+====+==[BS]==+====+==
  L1   T1       L2   T2

A bus-section breaker (BS) divides the bus, so a fault takes out only half.

3. Main and transfer busbar

 Main  ===+=======+=======+===
         [CB]    [CB]    [BC]
 Trans ---+-------+-------+---
          L1      L2

Any one feeder breaker can be maintained using the transfer bus and bus coupler (BC). A main-bus fault still causes full outage.

4. Double busbar (with bus coupler)

 Bus-1 ===+======+======+===
          |      |     [BC]
 Bus-2 ===+======+======+===
         [CB]   [CB]
          L1     L2

Circuits can be split between buses; either bus can be maintained. Common at 132 kV and 220 kV in Nepal.

5. Breaker-and-a-half

 Bus-1 ==+==============+==
        [CB]           [CB]
         +-- L1    L3 --+
        [CB]           [CB]
         +-- L2    L4 --+
        [CB]           [CB]
 Bus-2 ==+==============+==

Three breakers for two circuits. Any breaker or bus can be taken out without loss of supply. Used at 220–400 kV.

6. Ring (mesh) bus

    L1 --+--[CB]--+-- L2
         |        |
       [CB]     [CB]
         |        |
    L4 --+--[CB]--+-- L3

Each circuit sits between two breakers. Economical for 4–6 circuits, but protection is complex and an open ring reduces reliability.

Comparison

A generator specification is the technical document, part of the tender (bid) documents, that tells manufacturers exactly what generator the project needs. It covers the rating, design, performance, standards, tests and supply scope, so that bids can be compared on equal terms and the delivered machine fits the plant. A typical specification for a hydro generator (example: a 12.5 MVA unit) is set out below.

1. General and standards

• Scope: design, manufacture, testing at works, packing, transport to site, erection supervision and commissioning of 2 sets of three-phase synchronous generators with excitation and accessories.
• Standards: IEC 60034-1 (rating and performance), IEC 60034-3/-33 (hydro generators), IEC 60085 (insulation), IEC 60034-4 (test methods).
• Site conditions: altitude (e.g. 1200 m above MSL), ambient temperature (0–40 °C), humidity, seismic zone (Nepal: horizontal acceleration about 0.3 g), indoor powerhouse.

2. Rating and electrical data

3. Mechanical and construction

• Stator: laminated low-loss steel, class F VPI insulated winding, RTDs (6 per phase) in slots.
• Rotor: salient poles with damper winding, designed for runaway speed.
• Bearings: thrust and guide bearings with oil coolers and RTDs; insulated against shaft currents.
• Cooling: closed-circuit air with air-to-water coolers (one spare cooler), or open ventilation for small sets.
• Brakes and jacks, space heaters, fire protection (CO₂ or water spray), vibration probes.
• Noise ≤ 85 dB(A) at 1 m.

4. Excitation and auxiliaries

• Static (or brushless) excitation with digital AVR, PSS, limiters (OEL, UEL, V/Hz), field flashing, field breaker.
• Ceiling voltage ≥ 1.6 pu, response time < 0.1 s.
• Neutral grounding equipment (NGT with resistor), surge arresters and surge capacitors, CTs and PTs, terminal and neutral cubicles.

5. Tests, documents and commercial items

• Type and routine tests at works: winding resistance, insulation resistance and PI, HV withstand, open- and short-circuit characteristics, reactances, heat run, overspeed, vibration.
• Site tests: dry-out, polarisation index, HV test, commissioning tests (load rejection).
• Documents: guaranteed technical particulars (GTP), drawings, O&M manuals, capability curve, test reports.
• Spares (one set of poles, bearing pads, coolers), tools, training.
• Delivery period, warranty (e.g. 24 months after commissioning), guaranteed efficiency with liquidated damages for shortfall, payment terms and price (FOB/CIF).

A tentative quotation lists the technical data, quantity and price of the breaker so that the developer can budget and compare offers. Assumptions: 48 MW plant with 2 × 24 MW units, evacuation at 132 kV over 15 km by a double-circuit line, so the switchyard has 2 transformer bays and 2 line bays.

Rated current check: $I_{FL} = \dfrac{48/0.85}{\sqrt{3} \times 132} = 247$ A, so a standard 1250 A rating is ample.

QUOTATION (example, indicative prices)

To: XYZ Hydropower Ltd., Kathmandu. Ref: 132 kV switchyard circuit breakers. Validity: 90 days.

Terms:

• Standards: IEC 62271-100; type test reports enclosed.
• Delivery: CIF Birgunj/site within 6 months of LC; packing for hill transport.
• Warranty: 24 months from commissioning; payment by LC (10% advance, 80% on delivery, 10% after commissioning).

Prices are only indicative for budgeting; actual prices come from competitive bids.

A tentative quotation for a power transformer gives the main technical particulars, scope, price and terms so that the developer can budget and compare offers. Assumed project: a medium hydropower plant of 2 × 12 MW in a hilly region (altitude about 1500 m), evacuating at 132 kV. One step-up transformer per unit.

Rating: $S = 12/0.85 = 14.1$ MVA, so a standard 16 MVA unit is chosen.

Main technical particulars offered

Price schedule (indicative)

Commercial terms

• Delivery: 7–9 months after LC; FOR site; route survey by supplier.
• Tests: routine tests (ratio, vector group, losses, impedance, insulation) witnessed by the owner; type test reports (temperature rise, impulse) submitted.
• Loss capitalisation: bids are compared with the capitalised value of guaranteed losses; a penalty applies for excess losses.
• Warranty: 24 months after commissioning; payment by LC; validity 120 days.

Prices are only indicative for budgeting; actual prices come from competitive bids.

Assumptions: riparian release = 10% of the driest monthly mean flow; net head = gross head minus 5% loss; $\rho g = 9.81$ kN/m³; generator power factor 0.85; base = 100 MVA. For fault levels the grid is taken as a source of 2,000 MVA at the 132 kV grid substation at the far end of the line (an assumed typical value, since grid data is not given). The line is taken as a single circuit (not stated).

(i) Installed capacity at $Q_{45\%}$

Driest month = March (4.55 m³/s), so riparian release $Q_r = 0.1 \times 4.55 = 0.455$ m³/s.

$$\begin{aligned} Q_d &= Q_{45\%} - Q_r = 9.82 - 0.455 = 9.365\ \text{m}^3/\text{s} \\ H_n &= H_g(1 - 0.05) = 330 - 16.50 = 313.50\ \text{m} \\ P_{hyd} &= \rho g Q_d H_n = 9.81 \times 9.365 \times 313.50 = 28.801\ \text{MW} \\ P_{shaft} &= \eta_t P_{hyd} = 0.9 \times 28.801 = 25.921\ \text{MW} \\ P_{gen} &= \eta_g P_{shaft} = 0.97 \times 25.921 = 25.144\ \text{MW} \\ P_{out} &= \eta_{tr} P_{gen} = 0.99 \times 25.144 = 24.892\ \text{MW} \end{aligned}$$

Answer: generator output = 25.144 MW; power delivered to the 132 kV bus = 24.892 MW.

(ii) Number of units

• Choose 2 units. With a run-of-river flow that falls well below the design flow in the dry months, one unit can run near full load on half the design flow, so efficiency stays high in winter.
• One unit can be maintained while the other runs, and two units keep the number of machines (and cost) low for a plant of this size.
• Per unit: $Q = 9.365/2 = 4.683$ m³/s, generator output $= 25.144/2 = 12.572$ MW → rate each unit at 12.6 MW.
• Generator rating: $S = 12.6/0.85 = 14.82$ MVA → 15 MVA, 11 kV, 0.85 pf, 50 Hz.
• Step-up transformer, one per unit: 16 MVA, 11/132 kV, YNd11 (next standard size above 15 MVA).

Answer: installed capacity = 2 × 12.6 MW = 25.2 MW.

(iii) Type of turbine

$H_n = 313.50$ m lies in the Francis (10–350 m) and Pelton (50–1300 m) ranges, so the specific speed decides.

Shaft power per unit $P = 25.921/2 = 12960.7$ kW. With $N = 120f/p$ (synchronous speeds) and $N_s = N\sqrt{P}/H_n^{5/4}$, where $H_n^{5/4} = 1319.2$:

Usual ranges: Pelton about 10–30 per jet (multi-jet $N_s = N_{s,jet}\sqrt{z}$), Francis about 60–300, Kaplan 300–1000.

Choose $N = 428.6$ rpm (14 poles): $N_s = 37.0$. With 4 jets, $N_{s,jet} = 37.0/\sqrt{4} = 18.5$, inside the Pelton range.

Check of jet ratio: jet velocity $V_j = 0.98\sqrt{2gH_n} = 76.9$ m/s; bucket speed $u = 0.46V_j$; runner diameter $D = 60u/(\pi N) = 1.58$ m; jet diameter $d = \sqrt{4(Q/z)/(\pi V_j)} = 0.139$ m; $D/d = 11.3 > 10$, acceptable.

A Francis at 1000 rpm ($N_s = 86.3$) is also possible, but the Pelton is preferred because (i) its efficiency stays nearly flat from about 20% to 100% load (jets can be switched off), which suits a run-of-river plant whose flow falls far below the design flow in the dry season, and (ii) it tolerates the heavy sediment of Himalayan rivers better, and worn buckets and needles are easier to repair.

Answer: 2 × vertical-axis 4-jet Pelton turbines, 428.6 rpm, about 12.96 MW each.

(iv) Generator–transformer scheme

Choose the unit scheme (one generator connected to its own step-up transformer, with a generator circuit breaker between them).

Reasons: the units are large (15 MVA each, about 787 A at 11 kV), the transmission voltage is 132 kV, and the unit scheme keeps the 11 kV fault level and generator-voltage switchgear small. The GCB lets the unit be synchronised and tripped at 11 kV while the station transformer, tapped between the GCB and the step-up transformer, stays fed from the grid (back-feed) when the unit is stopped.

(v) Single line diagram

 Line to grid  (132 kV, 20 km)
    |
  [CB]
    |
 ===+====+================+=== 132 kV bus
         |                |
       [CB]             [CB]
         |                |
       (T1)             (T2)
         |                |
  ST1 ---+                +--- ST2
         |                |
       [GCB]            [GCB]
         |                |
       (G1)             (G2)
         |                |
       [NGT]            [NGT]

 ST1, ST2 (11/0.4 kV)
    |               |
 ===+====[BS]=======+=== 0.4 kV aux bus
              |
            [ACB]
              |
            (DG)  diesel set, black start

BS = bus section breaker, GCB = generator circuit breaker, ACB = air circuit breaker. Black start: with the grid dead, the DG energises the 0.4 kV auxiliary bus (governor oil pumps, cooling water, excitation field flashing, lighting and battery chargers), one unit is started and runs in island mode, and it then energises the step-up transformer and the line.

Bus bar used in the SLD

• 132 kV switchyard: double main bus bar with a bus coupler. Each bay (transformer or line) can be put on either bus, so one bus can be maintained without shutting down the plant and a bus fault affects only the circuits on that bus. This is the NEA practice at 132 kV and above.
• 11 kV: no common bus (unit scheme); each generator connects to its transformer through the GCB.

(vi) Rating of the transmission line side circuit breaker (HVCB)

Per-unit reactances on 100 MVA base:

$$\begin{aligned} x_g &= 0.21 \times \frac{100}{15} = 1.4000\ \text{pu}, \quad x_t = 0.0915 \times \frac{100}{16} = 0.5719\ \text{pu} \\ X_L &= 2\pi f L l = 2\pi \times 50 \times 0.95\times10^{-3} \times 20 = 5.969\ \Omega \\ x_l &= \frac{X_L \times 100}{132^2} = \frac{5.969}{174.24} = 0.0343\ \text{pu}, \quad x_{grid} = \frac{100}{2000} = 0.0500\ \text{pu} \\ x_{grid\ path} &= 0.0500 + 0.0343 = 0.0843\ \text{pu} \end{aligned}$$

For a fault on the 132 kV bus, the plant and the grid feed in parallel:

$$\begin{aligned} X_{plant} &= \frac{x_g + x_t}{2} = \frac{1.4000 + 0.5719}{2} = 0.9859\ \text{pu} \\ S_{HV} &= \frac{100}{0.9859} + \frac{100}{0.0843} = 101.4 + 1186.8 = 1288.3\ \text{MVA} \\ I_{sc} &= \frac{1288.3}{\sqrt{3} \times 132} = 5.63\ \text{kA}, \quad I_{make} = 2.55 \times 5.63 = 14.37\ \text{kA peak} \\ I_{FL} &= \frac{2 \times 16}{\sqrt{3} \times 132} = 140\ \text{A} \end{aligned}$$

Answer: HV bus fault level = 1288.3 MVA (5.63 kA); select a 145 kV, 1250 A, 31.5 kA SF6 circuit breaker. Of this, the plant itself contributes only 101.4 MVA; the rest comes from the grid, so the result depends on the assumed grid fault level.

Assumptions: riparian release = 10% of the driest monthly mean flow; net head = gross head minus 5% loss; $\rho g = 9.81$ kN/m³; generator power factor 0.85; base = 100 MVA. For fault levels the grid is taken as a source of 2,000 MVA at the 132 kV grid substation at the far end of the line (an assumed typical value, since grid data is not given).

Transmission voltage (not given)

Use Still's formula for the economical voltage (L in km, P in kW):

$$\begin{aligned} V &= 5.5\sqrt{\frac{L}{1.6} + \frac{P}{100}} = 5.5\sqrt{\frac{20}{1.6} + \frac{23400}{100}} = 86.4\ \text{kV} \end{aligned}$$

Still's value of 86.4 kV lies between 66 kV and 132 kV; choose 132 kV, single circuit, the NEA grid voltage, which also leaves room for future projects in the area.

(i) Installed capacity in MW at $Q_{45\%}$

Driest month = April (3.55 m³/s), so riparian release $Q_r = 0.1 \times 3.55 = 0.355$ m³/s.

$$\begin{aligned} Q_d &= Q_{45\%} - Q_r = 9.8 - 0.355 = 9.445\ \text{m}^3/\text{s} \\ H_n &= H_g(1 - 0.05) = 300 - 15.00 = 285.00\ \text{m} \\ P_{hyd} &= \rho g Q_d H_n = 9.81 \times 9.445 \times 285.00 = 26.407\ \text{MW} \\ P_{shaft} &= \eta_t P_{hyd} = 0.91 \times 26.407 = 24.030\ \text{MW} \\ P_{gen} &= \eta_g P_{shaft} = 0.97 \times 24.030 = 23.309\ \text{MW} \\ P_{out} &= \eta_{tr} P_{gen} = 0.99 \times 23.309 = 23.076\ \text{MW} \end{aligned}$$

Answer: generator output = 23.309 MW; power delivered to the 132 kV bus = 23.076 MW.

(ii) Number of units

• Choose 2 units. With a run-of-river flow that falls well below the design flow in the dry months, one unit can run near full load on half the design flow, so efficiency stays high in winter.
• One unit can be maintained while the other runs, and two units keep the number of machines (and cost) low for a plant of this size.
• Per unit: $Q = 9.445/2 = 4.723$ m³/s, generator output $= 23.309/2 = 11.655$ MW → rate each unit at 11.7 MW.
• Generator rating: $S = 11.7/0.85 = 13.76$ MVA → 14 MVA, 11 kV, 0.85 pf, 50 Hz.
• Step-up transformer, one per unit: 16 MVA, 11/132 kV, YNd11 (next standard size above 14 MVA).

Answer: installed capacity = 2 × 11.7 MW = 23.4 MW.

(iii) Type of turbine

$H_n = 285.00$ m lies in the Francis (10–350 m) and Pelton (50–1300 m) ranges, so the specific speed decides.

Shaft power per unit $P = 24.030/2 = 12015.1$ kW. With $N = 120f/p$ (synchronous speeds) and $N_s = N\sqrt{P}/H_n^{5/4}$, where $H_n^{5/4} = 1171.0$:

Usual ranges: Pelton about 10–30 per jet (multi-jet $N_s = N_{s,jet}\sqrt{z}$), Francis about 60–300, Kaplan 300–1000.

Choose $N = 428.6$ rpm (14 poles): $N_s = 40.1$. With 4 jets, $N_{s,jet} = 40.1/\sqrt{4} = 20.1$, inside the Pelton range.

Check of jet ratio: jet velocity $V_j = 0.98\sqrt{2gH_n} = 73.3$ m/s; bucket speed $u = 0.46V_j$; runner diameter $D = 60u/(\pi N) = 1.50$ m; jet diameter $d = \sqrt{4(Q/z)/(\pi V_j)} = 0.143$ m; $D/d = 10.5 > 10$, acceptable.

A Francis at 1000 rpm ($N_s = 93.6$) is also possible, but the Pelton is preferred because (i) its efficiency stays nearly flat from about 20% to 100% load (jets can be switched off), which suits a run-of-river plant whose flow falls far below the design flow in the dry season, and (ii) it tolerates the heavy sediment of Himalayan rivers better, and worn buckets and needles are easier to repair.

Answer: 2 × vertical-axis 4-jet Pelton turbines, 428.6 rpm, about 12.02 MW each.

(iv) Generator–transformer scheme

Choose the unit scheme (one generator connected to its own step-up transformer, with a generator circuit breaker between them).

Reasons: the units are large (14 MVA each, about 735 A at 11 kV), the transmission voltage is 132 kV, and the unit scheme keeps the 11 kV fault level and generator-voltage switchgear small. The GCB lets the unit be synchronised and tripped at 11 kV while the station transformer, tapped between the GCB and the step-up transformer, stays fed from the grid (back-feed) when the unit is stopped.

(v) Single line diagram

 Line to grid  (132 kV, 20 km)
    |
  [CB]
    |
 ===+====+================+=== 132 kV bus
         |                |
       [CB]             [CB]
         |                |
       (T1)             (T2)
         |                |
  ST1 ---+                +--- ST2
         |                |
       [GCB]            [GCB]
         |                |
       (G1)             (G2)
         |                |
       [NGT]            [NGT]

 ST1, ST2 (11/0.4 kV)
    |               |
 ===+====[BS]=======+=== 0.4 kV aux bus
              |
            [ACB]
              |
            (DG)  diesel set, black start

BS = bus section breaker, GCB = generator circuit breaker, ACB = air circuit breaker. Black start: with the grid dead, the DG energises the 0.4 kV auxiliary bus (governor oil pumps, cooling water, excitation field flashing, lighting and battery chargers), one unit is started and runs in island mode, and it then energises the step-up transformer and the line.

(vi) Rating of generator circuit breaker (GCB)

Per-unit reactances on 100 MVA base:

$$\begin{aligned} x_g &= 0.21 \times \frac{100}{14} = 1.5000\ \text{pu}, \quad x_t = 0.0915 \times \frac{100}{16} = 0.5719\ \text{pu} \\ X_L &= 2\pi f L l = 2\pi \times 50 \times 0.92\times10^{-3} \times 20 = 5.781\ \Omega \\ x_l &= \frac{X_L \times 100}{132^2} = \frac{5.781}{174.24} = 0.0332\ \text{pu}, \quad x_{grid} = \frac{100}{2000} = 0.0500\ \text{pu} \\ x_{grid\ path} &= 0.0500 + 0.0332 = 0.0832\ \text{pu} \end{aligned}$$

A unit-connected GCB sees the larger of two currents: (a) a fault on the transformer side fed by its own generator, (b) a fault on the generator side fed by the system through the unit transformer (grid plus the other units).

$$\begin{aligned} S_a &= \frac{100}{x_g} = \frac{100}{1.5000} = 66.7\ \text{MVA} \\ X_{ext} &= x_{grid\ path} \parallel (x_g + x_t) = 0.0832 \parallel 2.0719 = 0.0800\ \text{pu} \\ S_b &= \frac{100}{x_t + X_{ext}} = \frac{100}{0.5719 + 0.0800} = 153.4\ \text{MVA} \end{aligned}$$

Design fault level for the GCB = larger value = 153.4 MVA.

$$\begin{aligned} I_{sc} &= \frac{153.4}{\sqrt{3} \times 11} = 8.05\ \text{kA}, \quad I_{make} = 2.55 \times 8.05 = 20.53\ \text{kA peak} \\ I_{FL} &= \frac{14}{\sqrt{3} \times 11} = 735\ \text{A}, \quad 1.25 I_{FL} = 919\ \text{A} \end{aligned}$$

Answer: GCB fault level = 153.4 MVA; select a 12 kV, 1250 A, 25 kA generator circuit breaker. The margin covers the DC component and delayed current zeros of generator faults; surge arresters and surge capacitors are fitted at the generator terminals when a VCB is used.