Commission Testing

Methods for Protection

Systems

Ken Sletten – Minnesota Power

Tom Ernst– GE Grid Solutions

2017 Minnesota Power Systems Conference

Agenda

• Introduction
• Goals and objectives of protection system commission testing
• Maintenance Testing
• Re-commission testing
• Case Studies
• Conclusions
Introduction
• Protection systems require testing to assure proper operation
• 3 separate stages of testing over protection system’s life
• Type testing
• Commission testing
• Life-cycle maintenance testing
• Commission testing is critical
• Assure safety
• Functional operation
• Equally critical in both utility and industrial systems
• Commission testing provides baseline data for maintenance
• Critical for utility installations subject to NERC PRC-005
• Commission and maintenance testing have different goals
and objectives
 Goals and objectives of protection
system commission testing
• Commission tests are preformed to assure that the protection
system is performing correctly as required for the unique
application
• Must commission test all 5 NERC PRC-005-2 components
• Voltage and current sensing devices
• Protection system DC supply (including batteries, chargers, monitoring
circuitry, and power supplies/inverters whether they include batteries
or not)
• Control circuitry (including wiring, trip coils, electro-mechanical
auxiliary relays and lock-outs, etc.)
• Communication systems required for protection system operation
• Protective relays
• Must also perform energizing procedures and in service load
checks
Voltage and Current Sensing Devices
• Magnetic core devices
• VT commission tests
• Ground leakage test - no
unintentional grounds
• Turns ration check (TTR)
• Polarity check
• Test voltage applied to a VT applied
to the primary winding to avoid the
presence unsafe high voltages
• CT commission tests
• Ground leakage test - no unintentional grounds
• Turns ration check (TTR)
• Polarity check
• Excitation check
Voltage and Current Sensing Devices

• Non-magnetic core device commission

tests
• Optical VTs, CTs
• Devices have self-testing
functionality
• Rogowski coils
• Typically have unique calibration
characteristics provided by
manufacturer
• Primary injection
• In-service load checks
Protection system DC supply
• Batteries, chargers, monitoring circuitry, and power
supplies/inverters whether they include batteries or not
• Tests based on the technology used
• Battery banks - verify the bank meets design specs and
industry standards
• Battery load/capacity tests
• Cell impedance measurement
• Inter-cell connection resistance measurement
• Specific gravity measurement
• Cell voltage checks
Protection system DC supply

• Batteries, chargers, monitoring circuitry, and power

supplies/inverters whether they include batteries or not
• Battery chargers
• Function testing
• Verification of battery charger
settings
• Alarm verification
• Methods and tools used for testing
and the results of the tests should be
saved as base-line data for future
maintenance tests
Control circuitry
• Includes wiring, trip coils, electro-mechanical auxiliary relays,
lock-outs, etc.
• AC and DC wiring should be checked physically and
electrically
• Point to point wire checks
• Wiring is physically in agreement with the design
documents
• Injection of electrical quantities
• Wiring performs the necessary functions
• Helps to identify any errors in the design
• Develope a system to document each test
Control circuitry
• AC and DC wiring electrical tests (cont.)
• Check DC circuits before energizing
• Pull fuses to isolate
• Use an ohm meter to verify there are no short circuits
• Reinstall load fuses one circuit at a time
• Verify no DC grounds are acquired
Control circuitry
• CT secondary injection
• Inject 3-phase test set currents into CT circuit
• Clipping onto the CT wires (no lifting wires)
• Directly on the CT secondary terminals if accessible
• Otherwise on the CT shorting block terminals
• Virtually none of the injected current goes into the CT
• Inject varying magnitudes of current on the three phases
• Ex: 0.5, 1.0 and 1.5 amps into phases A, B and C
respectively
• Verify with receiving relays’ metering functions
Control circuitry
• VT secondary injection
• Isolate the VT winding from the secondary wiring
• Pull the VT secondary fuses
• Clip test set to the load side of the open fuse block
• Wye connected VTs
• Apply varying magnitude phase-neutral voltages
• Open delta connected VTs
• Apply varying magnitude phase-phase voltages
• Verify with the relays’ metering
• Check each device that receives
the VT signal
Control circuitry
• Primary injection less common than secondary injection
• Use a 3-phase generator (typically LV) to energize the
substation bus
• Apply loads on each circuit to cause current flow
• Check relays’ metering to assure functionally correct
• Magnitudes and angles
• Requires a thorough understanding of relay phasor angle
referencing
• Often subject to or controlled by relay settings
• Take care when interpreting the metered values to
assure correct phase identification
• DC control wiring electrically tested
while function testing the relay
Communication systems
• All communication systems need to be verified
• Used by protection system for protection
• Pilot channels, transfer trip, etc.
• Used for operation and control
• SCADA, voice, LANs, data remote access, etc.
• Typically not subject to PRC-005 requirements
• Point to point communications functionally verified and
documented
• Signal levels and data transfer rates
• SCADA remote control functions
• Verify perform as expected
Communication systems
• All communication systems need to be verified (cont.)
• SCADA remote control functions
• Verify perform as expected
• SCADA metering from standalone metering devices
(transducers, meters, etc.)
• Inject current and voltage device
• SCADA metering from relay memory registers
• Test as part of relay functional tests
Communication systems
• All communication systems need to be verified (cont.)
• Stand-alone communications for transfer trip and/or pilot
wire (power line carrier, audio or digital tone systems, etc.)
• Verify end-end functionality before protective relay
functional tests
• Digital relay communications used for transfer trip and/or
pilot wire
• Verify end-end functionality as part of relay functional
tests
Protective relays
• Relay acceptance testing
• Owner preferences
• Verify 100% of all included analog and digital I/O
• Even if not all the I/O are used
• Load Relay Settings
• Digital relays
• Setting files loaded into relays
• Vendor specific software tools
• Verify by comparing relay to setting file
• Should be no differences
• If differences resend or manually correct
• Save an image of the compare report showing no
differences
Protective relays
• Load Relay Settings (cont.)
• Non-digital relays
• Settings entered (adjusted) manually
• Verify with current and/or voltage injection
• Function testing
• Verify all enabled feature as a complete system
• Protection elements, metered values, logic,
communications and I/O
• Demonstrate system functions as designed
Protective relays
• Function testing (cont.)
• Automated testing programs are not suited for
commission function testing
• Inject current and voltage based on relay’s settings
• Not be able to detect setting errors
• Typos
• Bad system data
• Do not test programmed logic or specific I/O functions
• Used at end to establish a base-line testing report for
future maintenance
Protective relays
• Function testing (cont.)
• Use test values derived from system studies
• Not values calculated from relay settings
• Line protection test values from SC program
• Close-in reverse fault
• Close-in forward fault
• Mid-line or balance point
fault
• Remote end fault
• Run tests with the pilot communication system
operational
• Transformer protection
• Test values derived based on the transformer winding
connections and SC program
Protective relays
• Function testing (cont.)
• Programmed logic functional testing (including I/O)
• Inject current and voltage to operate protection
functions used in the logic
• Operate inputs to the relay that are used in the logic
• Verify outputs that are operated by the logic
• Verify DC circuitry correct to end device
• Auxiliary relays, lock-out relays, trip coils, etc.
• Logic diagram useful for complex logic
BUS 1 OP

BKR FAIL 1 RETRIP

1 1096TC#1/3PH (P1)
1096 TRIP (VO11) Operate I on
BKR FAIL 2 TRIP OP OR
OR I off
V on
Seal-In
1096TC#1/3PH IOn (P1) V off

BKR FAIL 3 TRIP OP

BKR FAIL 4 TRIP OP

Energizing procedures and in service
load checks
• Energizing procedures vary widely from owner to owner
• Common goal of energizing the equipment in a logical and
safe manner
• Associated protection systems in service
• In service load checks
• Phase identification
• Voltage readings taken after energization
• All voltage measuring devices
• Assure secondary levels and phase identification
are correct
• Challenging on a totally new power system
• References from existing facilities not available
 Energizing procedures and in service
load checks
• In service load checks (cont.)
• Phase identification (cont.)
• Use end-end communication signal (ex: transfer trip)
• Temporarily trigger waveform capture reports in
relays
• At new substation and in remote existing
system
• Compare waveforms to assure correct phase
identification
• Phasor measurement unit (PMU) data
Energizing procedures and in service
load checks
• In service load checks (cont.)
• Phase identification (cont.)
• Cellular based phase checking systems
• Compare phase angle between remote and local
voltages
• Remove any temporary settings after test complete
• Examine metering of current measuring devices
• Assure correct ratios, phasing and phase shifts
 Energizing procedures and in service
load checks
• In service load checks (cont.)
• Current based differential elements
• Examine differential and restraint quantities
• Differential quantity is near or equal to zero
• Restraint quantity is significant
• Requires a significant amount of load for reliable
results
• High impedance bus differential
• Examine operating quantity
• Voltage across or current through the resistor
• Measure current from each CT to verify ratios
• Record load check data for future comparison
Maintenance Testing
• Commission testing data is baseline for the life-cycle
maintenance
• Date of commissioning records define time 0 for PRC-005
• Current and voltage measuring device insulation failure
detected
• Battery and charger performance degradation observed
• Communication channel degradation flagged
• As-left relay settings are base-line for maintenance
• Changes must be researched and validated
• Automated testing program results remain consistent
Re-commissioning
• Re-commissioning required if significant changes are made
• Only re-commission aspects of system affected
• Physical equipment replacement
• Communication equipment
• CT/VT
• Battery or charger
• Relay
• Re-commission replaced equipment
Re-commissioning
• Re-commissioning required if significant changes are made
• Wiring changes
• Re-commission anything that might have reasonably
been affected
• Setting changes
• Re-commission those elements/systems affected
• Firmware upgrade that requires setting file conversion
• Complete relay re-commission
 Case Study: Protection problems at
mine ID need to re-commission
switchgear
• New cubicles added to existing gear
• No commission testing performed on additions
• Trips during loading attempts
• Wiring errors discovered
• Missing settings discovered
• Similar problems found in existing cubicles
• No commissioning records found
• Safety concerns – workers no longer comfortable
• Re-commission entire line-up during next outage
Case Study: Modelling error discovered
during commissioning
• New replacement 115 kV line panel
• Test quantities for distance elements from SC program
• Ground distance zone 1 operated for remote bus fault
• Math check confirmed that test fault was within reach
• Zero-sequence line impedance error discovered in SC
program data base
• Caused wrong Z0/Z1 ratio
• Resulted in element over-reach
• Modelling error corrected and settings (Z0/Z1) changed
• New test values issued for 1LG faults
• Ground distance performed correctly
• Avoided future false trip
 Case Study: Setting errors discovered
while commissioning replacement
generator protective relay
• New generator protection to replace existing obsolete relay
• Settings calculations based on previous relay’s settings
• Tech ran automated testing program
• Report indicated no errors
• Field Engineer and Tech performed commissioning tests
• Discovered logic and setting omissions
• Trip output for field breaker wired but not
programmed
• Bus ground detection voltage input wired
• No associated element enabled and set
• No output contact programmed or wired
 Case Study: Verification of relaying
functions in relay using simulated
faults discovered firmware issues
• New replacement 115 kV line panel
• Test quantities for distance elements from SC program
• Phase distance failed to operated for 3LG faults
• Examination of SER data discovered that Loss of Potential
(LOP) was operating and blocking the elements
• No similar problems observed with other panels using
same relay models
• This terminal is weak-feed
• Voltage drops unusually low during 3LG faults
• LOP blocks even though memory voltage available for
correct distance element operation
• Waiting for a firmware fix from manufacturer
Conclusions
• Protection systems require testing to assure proper operation
• 3 separate stages of testing over protection system’s life
• Type testing
• Commission testing
• Life-cycle maintenance testing
• Commission testing is critical
• Assure safety
• Functional operation
• Equally critical in both utility and industrial systems
• Commission testing provides baseline data for maintenance
• Critical for utility installations subject to NERC PRC-005
• Commission and maintenance testing have different goals
and objectives
Thank You

Questions?