Synchronization Theory

The Four Conditions for Paralleling

To safely connect (parallel) two AC voltage sources, four conditions must be satisfied simultaneously:

1. Voltage Magnitude — The RMS voltage magnitudes of both sources must be approximately equal.
2. Frequency — Both sources must operate at nearly the same frequency.
3. Phase Angle — The instantaneous phase angle difference must be near zero at the moment of breaker closure.
4. Phase Sequence (Rotation) — Both sources must have the same phase sequence (A-B-C). This is verified during commissioning and does not change during normal operation.

Phasor Analysis

We can represent the bus voltage and incoming voltage as phasors (rotating vectors in the complex plane). The bus voltage is conventionally taken as the reference phasor, fixed at angle 0°. The incoming voltage phasor rotates relative to the bus at the slip frequency.

The voltage across the open breaker contacts is the vector difference of the two sources:

If we assume both sources have the same magnitude V and the incoming source leads the bus by angle δ, then:

This formula is fundamental. At δ = 0° (in phase), |V_diff| = 0. At δ = 180° (fully out of phase), |V_diff| = 2V, meaning the voltage across the breaker is twice the system voltage.

What Happens When You Close Out of Phase

When a circuit breaker closes and connects two AC sources that are not synchronized, the voltage difference across the breaker instantaneously drives current through the system impedance (primarily reactance). This current can be enormous — comparable to or exceeding fault-level currents — and it persists as a damped transient until the two sources either pull into synchronism or protective relaying trips the breaker.

Mechanical Consequences

• Generator Shaft Torque: The electromagnetic torque pulse on the generator shaft can exceed 10× rated torque for a 180° closure. This can crack the shaft, damage couplings, shear keys, or destroy the prime mover gearbox. Even at smaller angles, repeated out-of-phase closures cause cumulative fatigue damage to turbine blades and shaft bearings.
• Transformer Winding Forces: Mechanical forces on transformer windings are proportional to I². An out-of-phase closure producing 5× rated current creates 25× the normal winding forces, potentially displacing windings and causing turn-to-turn shorts. This damage may be latent and progressive.
• Bus Bar and Structure Forces: Bus bars experience mechanical forces proportional to I²/d (where d is spacing). Extreme currents can bend bus bars, crack insulators, and damage support structures.
• Breaker Contact Damage: The breaker contacts close into an extreme current, causing arc erosion, contact welding, and potential breaker failure. The breaker may be unable to re-open if contacts weld, removing a critical layer of protection.

Thermal Consequences

While the synchronizing transient is relatively brief (typically decaying over 0.5 to 5 seconds), the energy involved (I²t) at very high currents can cause:

• Conductor heating beyond short-time thermal ratings
• CT saturation and relay misoperation
• Insulation degradation from temperature rise

System Stability Impact

Beyond equipment damage, an out-of-phase closure can trigger cascading failures:

• The transient power swing can cause distance relays to trip healthy lines (Zone 3 misoperation)
• Generator loss-of-field relays may operate due to the massive VAR demand
• Under-frequency load shedding may trigger if generators trip
• A system split at the point of closure can propagate into a wide-area blackout

Phase Angle (δ)

The phase angle difference at the moment of breaker closure is the most critical parameter. Industry standards and equipment ratings establish the acceptable limits:

• NERC Standard TOP-001-5 (Transmission Operations) requires reliability coordinators and transmission operators to have procedures for synchronizing to the grid, including defined limits for angle, voltage, and frequency.
• NERC Standard TOP-003 addresses planned outage coordination and requires synchronization plans for returning equipment to service.
• IEEE C37.04 defines circuit breaker ratings, including the out-of-phase switching duty. Standard breakers are rated for closing at 90° out of phase (not 180°). Exceeding the rated angle voids the breaker's switching capability guarantee.
• Typical utility sync check relay (Device 25) settings: ±10° to ±20° phase angle window for permissive closing. Some utilities use tighter limits (±5° to ±10°) for generator breakers.

Voltage Difference

A mismatch in voltage magnitude between the two sources causes reactive power (VAR) flow upon closure. The bus at higher voltage will supply VARs to the lower-voltage bus, following the relationship:

Acceptable voltage difference is typically 0–5% of bus voltage. Larger mismatches can cause unacceptable VAR flow, voltage regulator hunting, and in extreme cases, generator over-excitation trips.

Slip Frequency

The slip frequency determines how fast the synchroscope needle rotates and, critically, how much time the operator has to initiate breaker closure at the correct moment.

• Ideal range: 0.033–0.067 Hz (the needle takes approximately 15–30 seconds per revolution)
• At 0.067 Hz, one revolution takes about 15 seconds — comfortable for an experienced operator
• At 0.033 Hz, one revolution takes about 30 seconds — very comfortable but may be impractical to maintain
• Slip above 0.1 Hz (10 seconds per revolution) makes timing difficult and increases the angular error at closure
• The needle should be rotating slowly clockwise (incoming slightly fast) so the phase angle is approaching zero as you close. This is preferred because:
• The incoming machine will naturally decelerate as it takes on load after closure
• Clockwise approach to 12 o'clock is the expected convention; closing on counter-clockwise motion means the incoming source is slower and may accelerate toward the bus after closure, causing a potentially larger transient

Phase Sequence

Phase sequence (rotation) must be verified during commissioning, after any wiring changes, or after transformer replacement. If the phase sequence does not match (e.g., A-B-C connecting to A-C-B), closing the breaker connects phases that are 120° out of phase from each other, guaranteeing massive currents and equipment damage.

• Phase sequence is verified using a phase sequence meter (rotation meter) or by comparing the phase sequence of voltage waveforms from both sides using a relay test set.
• Once verified and documented, phase sequence does not change unless physical wiring is altered.
• A wrong phase sequence closure is always catastrophic — there is no acceptable tolerance.

Purpose and Function

The sync check relay (IEEE Device Number 25) is a protective relay that monitors the phase angle, voltage magnitude, and frequency difference between two AC sources. It provides a permissive (go/no-go) signal to the breaker close circuit, preventing the breaker from closing unless all synchronization parameters are within the preset limits.

Think of it as an electronic gatekeeper: even if the operator presses the close button, the breaker will not close unless the sync check relay confirms that conditions are acceptable.

Settings

• Phase Angle Window (δ_max): Typically ±10° to ±20°. The relay permits closing only when the angle difference is within this window centered on 0°.
• Voltage Window (ΔV_max): Typically ±5% to ±10% of nominal. Both sources must have voltage within the acceptable band.
• Slip Frequency Limit (f_slip,max): Typically 0.05–0.10 Hz. The relay will block closing if the frequency difference is too large.
• Dead Bus / Dead Line Logic: Most modern sync check relays can detect when one side is de-energized (below a voltage threshold, typically 20–30% of nominal) and permit closing without sync check (dead bus or dead line closing). This must be configured carefully.

Device 25 vs. Device 25A

How the Relay Prevents Catastrophic Closures

The sync check relay is wired in series with the breaker close circuit. The closing sequence is:

1. Operator (or automatic system) issues the close command
2. The close command reaches the sync check relay
3. The relay evaluates angle, voltage, and slip against its settings
4. If all parameters are within limits, the relay passes the close signal to the breaker close coil
5. If any parameter is out of limits, the close signal is blocked and the breaker remains open

Most relays also have a close pulse timer — once the relay permits closing, it issues a timed close pulse (typically 100–200 ms) to prevent multiple close attempts if the operator holds the close button.

When Manual Closing Is Required

There are situations where operators may need to close without an active sync check relay:

• Relay failure: If the sync check relay fails, manual closing with synchroscope verification may be required per utility switching procedures.
• Commissioning: During initial energization of new equipment, the sync check relay may not be commissioned yet.
• Emergency restoration: During system restoration after a blackout, standard protection may not be available and experienced operators may need to synchronize manually.
• Dead bus / dead line closing: When one side is de-energized, sync check is not applicable (but the operator must verify the bus or line is actually dead using voltage indicators).

Pre-Synchronization Checks

1. Verify authorization. Confirm you have a valid switching order or operational directive that authorizes closing this breaker. Identify the breaker by name, number, and station. Confirm the type of closure (sync close, dead bus, dead line).
2. Verify sync check relay status. Is the sync check relay (Device 25) in service and functioning? If not, follow your utility's bypass procedure before proceeding. Check for any alarms or flags on the relay.
3. Verify phase sequence (if applicable). If this is the first parallel after construction, wiring changes, or transformer replacement, phase sequence must be verified before any live paralleling attempt. Use a phase rotation meter or relay test set.
4. Verify instrumentation. Confirm the synchroscope is energized and receiving voltages from the correct sources (bus PT and incoming PT). Verify that separate voltmeters and frequency meters for both sources are available and reading correctly.

Synchronization Steps

1. Observe the synchroscope. Determine the direction of rotation. Clockwise = incoming is faster (FAST). Counter-clockwise = incoming is slower (SLOW). Note the speed of rotation — count seconds per revolution.
2. Adjust frequency (governor). Increase or decrease the incoming machine's speed to achieve slow clockwise rotation. Target: approximately 15–30 seconds per revolution (slip of 0.033–0.067 Hz). If the needle is going counter-clockwise, raise the incoming machine's speed until the needle reverses to slow clockwise.
3. Adjust voltage (exciter/AVR). Compare the voltmeter readings for bus and incoming. Adjust the incoming machine's excitation (voltage regulator setpoint) until both voltages match within 2–5% of bus voltage.
4. Verify all parameters simultaneously. Before closing, confirm:
   • Synchroscope: slow clockwise rotation approaching 12 o'clock
   • Voltmeters: magnitudes matched within tolerance
   • Frequency meters: frequencies nearly equal (small positive difference)
5. Time the closure. Account for the breaker closing time (typically 3–5 cycles = 50–83 ms at 60 Hz). Initiate the close command slightly before the needle reaches 12 o'clock, so that the breaker contacts actually make at or very near 0°. With practice, operators develop a feel for the correct anticipation angle based on the needle speed and the specific breaker's closing time.
6. Close the breaker. Press or turn the close control decisively. Do not hesitate once you have committed to the closure. If you miss the window, do NOT try to close — wait for the next revolution.
7. Verify successful closure. Immediately after closing:
   • The synchroscope needle should stop rotating (both sources now locked together)
   • Check MW and MVAR meters for expected load sharing
   • Listen/watch for any abnormal indications (protective relay alarms, abnormal sounds)
   • Confirm breaker status indication shows CLOSED

Critical Errors

Other Common Mistakes

• Closing with large voltage mismatch: While less immediately catastrophic than a phase angle error, a large voltage mismatch (>10%) causes a large reactive power surge that can trip generator protection (loss-of-field, over-excitation) or cause voltage regulator instability. Always check voltmeters before closing.
• Ignoring counter-clockwise rotation: Counter-clockwise rotation means the incoming machine is slower than the bus. Some operators try to "catch" the needle as it passes through 12 o'clock while going counter-clockwise. This is risky because:
  • After closure, the slower machine acts as a motor momentarily, drawing a large current pulse
  • The timing is counterintuitive — you must close after 12 o'clock (needle going from 12 toward 11) rather than before
  • Best practice: adjust the governor to reverse the rotation to clockwise before attempting to close
• Not accounting for breaker closing time: Newer operators often close at exactly 12 o'clock, but by the time the breaker contacts make (3–5 cycles later), the angle has advanced past zero. With practice, operators learn to anticipate by initiating the close slightly before 12 o'clock.
• Relying solely on the synchroscope: The synchroscope does not indicate voltage magnitude or absolute frequency. Operators who watch only the synchroscope may close with a large voltage mismatch. Always cross-check with voltmeters and frequency meters.
• Incorrect PT connections: If the voltage transformer (PT) connections to the synchroscope are swapped (bus connected to incoming terminals and vice versa), the rotation direction indication is reversed. "Clockwise" now means the incoming is actually slower. This has led to real-world incidents. Verify connections during commissioning.

Lessons from Industry Events

The following are generalized descriptions of real-world synchronizing incidents used for training purposes:

• Generator shaft failure after 120° closure: A generating station operator attempted to synchronize a 200 MW combustion turbine during a system emergency. Under pressure to restore generation quickly, the operator closed at approximately 120° phase angle with a slip of 0.3 Hz. The resulting torque transient fractured the generator coupling, requiring 6 months of repairs and $12M in damages.
• Transformer failure from incorrect phase sequence: Following transformer replacement at a 230 kV substation, maintenance crews reconnected the phase conductors in the wrong sequence (A-C-B instead of A-B-C). The sync check relay was not yet commissioned on the new transformer bay. The first closure attempt resulted in a phase-to-phase fault that destroyed the transformer bushing and caused an oil fire.
• Cascading outage from high-angle closure: During system restoration after an ice storm, an operator closed a 345 kV transmission tie with a 45° phase angle (the synchroscope was malfunctioning and showing near-zero angle). The resulting power swing tripped three additional transmission lines via Zone 3 distance relay operations, extending the blackout by 8 hours.

Dead Bus Closing

A "dead bus" closure is one where one side of the breaker has no voltage (the bus or line is de-energized). In this case, synchronization is not required because there is no second source to synchronize with. However:

• You must verify the bus is actually de-energized using voltage indicators, bus PTs, or line PTs. Capacitively coupled voltage transformers (CCVTs) may show a small residual voltage from coupled parallel circuits; this does not constitute an energized bus.
• The sync check relay should be configured to recognize dead bus conditions (voltage below threshold on one side) and permit closing without sync check.
• If the sync check relay does not have dead bus logic, it may need to be bypassed per procedure.
• The synchroscope will not function properly with one side de-energized — it may not rotate or may spin erratically.

Dead Line Closing

Closing onto a de-energized transmission line from an energized bus is also a non-sync closure, but carries additional risks:

• Verify the line is actually dead. Trapped charge on a long transmission line can maintain significant voltage for seconds to minutes after disconnection. Shunt reactors or grounding switches discharge trapped charge.
• Charging current: Energizing a long transmission line draws significant capacitive charging current (leading VARs). Ensure the source can supply this reactive power without excessive voltage rise.
• Switching transients: Energizing an unloaded line produces a traveling wave voltage that can reach up to 2.0 per-unit at the remote (open) end. Pre-insertion resistors or controlled switching (point-on-wave) mitigate this.
• Reclosing into a faulted line: If the line was tripped by protective relays, reclosing restores voltage to the fault. Automatic reclosing sequences include a time delay to allow temporary faults (tree contact, lightning) to clear.

Black Start Conditions

During a system blackout, generating units must start without an external power supply (black start). The first unit to start establishes the system voltage and frequency reference. Key considerations:

• The first unit does not need synchronization — it energizes a dead bus.
• Subsequent units must synchronize to the bus established by the first unit. However, the bus frequency may be unstable (no load damping), making synchronization more challenging.
• Standard sync check settings may be too tight for black start conditions. Some utilities have special "black start" relay settings with wider tolerances.
• Communication between the generating station and system operator is critical, as SCADA may be unavailable.

Closing Across a Transmission Tie Line

Synchronizing across a transmission tie (connecting two independently operating portions of the grid) is fundamentally different from synchronizing a single generator to a bus:

• Both sides have large inertia and many generators — neither side's frequency can be easily adjusted by a single operator.
• The phase angle across the tie reflects the power flow pattern and may not be exactly zero even under normal conditions (angle across a loaded line is δ = P·X / (V₁·V₂)).
• Frequency difference between two islands tends to drift, and the operator must time the closure to a window when the angle is passing through an acceptable range.
• System operators (dispatchers) coordinate the frequency of both islands, typically by having one island raise and the other lower frequency until they nearly match.

Island Reconnection After System Split

After an unplanned system separation (island formation), reconnecting the islands requires:

• Identification of the synchronizing breaker(s) — the breaker(s) that will reconnect the two islands.
• Frequency matching between islands (coordinated by reliability coordinator).
• Load balancing within each island to minimize the power flow transient upon reconnection.
• Careful monitoring of angle across the tie — large power systems can have significant "angle spread" even when frequency is matched, if the load/generation pattern creates a standing angle.
• This is one of the most challenging synchronization scenarios and typically requires experienced system operators with real-time angle measurement (synchrophasor/PMU data).

Generator Synchronization vs. Transmission Line Closing