Restoration Drill & Pre-Drill Training ; System Restoration Overview

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Restoration Drill
Pre-Drill Training
System Restoration Overview

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Safety Moment
• Brief Pause to Review:
– Emergency escape routes; meeting place
– How to dial 9-1-1 from building phones
– Review building street address
2015 Power System Restoration Drill

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Protocols
• This WebEx Session is being recorded
• Questions or Comments?
– Unmute yourself and speak at an appropriate time, OR
– Send a chat to your host, Margaret Stambach (select from
drop-down menu) and type in your question/comment.
• 20-minute break at 10:30 AM ET, 9:30 AM CT

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Learning Objectives
• Review major system events.
• Provide fundamental knowledge and skills in
restoration issues and proven solution
techniques.
• Refresh restoration principles and processes.
• Certificate of Completion – 4 NERC CE hours
− Please complete and return Proctor paperwork
previously sent.

5
Antitrust Guidelines
• It is SERC’s policy and practice to obey the antitrust
laws and to avoid all conduct that unreasonably
restrains competition.
– It is the responsibility of every SERC member company to
carry out this commitment.
• Specifically, participants in SERC activities should
not discuss matters concerning pricing information,
especially profit, marketing strategies, competition,
or other similar matters.

6
Confidentiality Policy
• Participants in SERC meetings also may receive
information of a sensitive and commercial nature that
is confidential in nature and should not be disclosed
publicly.
• During SERC meetings, participants are reminded to
not disclose non-public transmission function or
customer specific information.

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Drill Leader and Instructor

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2015
Power System
Restoration Training

9
Objectives
• Identify historical system events that resulted in
system separation and blackouts
– WSCC/WECC Disturbance 1996
– Northeast Blackout 2003
– Arizona-Southern California Outages 2011
• Identify the elements and importance of a system
assessment following a event
• Review system configurations as a result of the
disturbances

10
• Discuss the options for restoration following a
system disturbance
• Identify the key principles of system restoration
– Switching strategies
– Voltage control
– Load pick-up
– Frequency control
– Rules of thumb
– Island building
– Synchronization of islands
Objectives

11
WSCC/WECC Disturbance
July 2, 1996

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• A few localized line faults
– 345 kV
• Spread to neighboring areas
• Cascaded to the most western
states
• Breakup of the western North
America
July 2 Event

13
• Five Islands
• One blackedout area
– Southern Idaho
– Loss of 11,750MW
Blackout Area

14
Northeast Blackout
August 14, 2003

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• Series of events
– 345 kV lines operating
– System Operator tool malfunctions
– Other contributing events
August 14, 2003

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Line Operations

17
Generator Trippings

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NY Separation

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NYISO System
• 60% Transmission
• 5,700 MW
• HQ support
• IMO generation
• PJM load

21
• 16:11 NYISO entered “Restoration State”
• 16:18 Initial Assessment
– Big Picture – large island energized - not all the details
• 16:27 Identified that Gilboa station was not part of
the surviving island – 1,100 MW pumped storage
– Directed to blackstart
• 16:45 LIPA using gas turbines after complete
separation
High Level Timeline

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• 17:00 Surviving island “relatively stable”
– Surviving 5,700 MW
• 17:18 Discussion of synchronizing with PJM
– 18:02 Attempt unsuccessful due to large frequency
imbalance
• 18:52 First synchronization with PJM
– Result of an auto synch-check relay allowing a reclosing
scheme to continue
– Involved parties unaware of synchronization
High Level Timeline

23
• 19:06 Con Ed attempt to manually close 500 kV tie
to PJM
– Synchroscope at 12 o’clock
• 19:06 – 00:00 Building of system – transmission,
generation, load
• 01:53 NY reconnects with ISO-NE
• 05:12 Con Ed ties with Long Island
High Level Timeline

24
• Gilboa synchronization to backbone island delayed
– Inability to close line at Gilboa due to the large voltage
disparity
– Initially complicated by an erratically operating switch
yard synchroscope at Gilboa
 Operator was able to switch over to a backup synchroscope
– System voltages not stabilized until additional lines
restored
 Within 15 minutes
Restoration Issues

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• 17:05 to 19:00 NYPA ECC operators concern with
load and generation imbalance and voltage stability
– Several 100 MW adjustments (up and down) to the import
from Hydro Quebec
– Rotational load shedding of three 60 MW Alcoa West
facilities
– Opening lines to shed 100 MW of Ontario load
• 18:01 Niagara Mohawk ordered to shed 300 MW
load – generation/load imbalance – declining
frequency
Restoration Issues

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• 07:34 NYISO issued order for Emergency Demand
Response Program/Special Case Resources
– 10:00 - 24:00
• 08:59 NYISO request immediate relief from
EDRP/SCR
• 09:25 NYISO informed TOs of potential rolling
blackouts
– Due to load and generation imbalance
• 09:33 NYISO ordered 300 MW load shed
– Dragging ACE - 630 MW
Restoration Issues

27
• 10:02 NYISO informed TOs that half load could be
restored
– 10:24 Remainder of load could be restored
Restoration Issues

28

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San Diego Area Electric System

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• IID operator not actively monitoring the RTCA
results
– RTCA alarms were also not audible
– Problem with N-1 – transformer overload
• Switching error – technician missed 2 critical steps
– Error caused tripping of 500 kV line
 Phase angle prevented reclosing of line
• Less generation on in San Diego and Mexico
Sequence of Events

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• Flow redistributions, voltage deviations and
overloads caused transformers, transmission lines
and generating units to trip offline
• Northern flows serving load in San Diego and
parts of Arizona and Mexico
– Flows initiated an intertie separation scheme (SONGS)
at San Onofre Nuclear Station
 Separating SDG&E from SCE and tripping both San
Onofre units
Sequence of Event

32

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Impacted Areas
Yuma
CFE
SDGE APS
IID

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Company Load Lost Customers Interrupted
– SDG&E 4293 MW 1.4 million
– CFE 2150 MW 1.1 million
– IID 929 MW 146 thousand
– APS 389 MW 70 thousand
– WALC 74 MW (APS customers)
Disturbance Results
15:38 September 8, 2011

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• All affected entities completed restoration without
need for black start plans
– Access to power from their neighboring systems
• Need for better WECC RC coordination and
assistance
– 30-minute debate occurred between SCE operators and
SONGS operators
 Resulted in a SONGS operator making a unilateral
decision to open a circuit breaker on the line responsible
for restoring power to SDG&E’s system
Restoration

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Restoration

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Restoration

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Restoration

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System
Assessment

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Assessment Elements
• Extent of blackout
• Communication status
• Personnel
• System status
– Generation resources
– Transmission facilities

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• Internal assessment
– Transmission, Generation, Distribution
• Neighboring areas
– Neighboring area communications
– Reliability Coordinator communications
• RC Area, Region, Interconnection
– Reliability Communications
Extent of Blackout

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• What communications are available?
– Control Center to Neighbors
– Control Center to RC
– Control Center to Generation plants
– Control Center to Field Personnel
• Telephones - ?
• Satellite phones - ?
• Radios - ?
• Cell phones - ?
• Computers - ?
Communication Status

43
Personnel
• Where do we need them?
– Control Center
– Substations
– Field
– Plants
• Notifications
• Call out process
• Support personnel

44
System Assessment
Generator StatusIdentify
surviving
generators
Stabilize
surviving
generators
Determine
status of
other
generators
Determine
Start-up
Sequence
Auxiliary
power to
Off-line units
Initiate
unit start-ups

45
Generator Assessment
• Surviving generators
– Current loading level
– Location
– Connected load
– Boundaries of island
– Plant capabilities
– Unit stability region

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• Stabilize Surviving Units
– Add additional load to stabilize
 Station load
 Distribution load
• Determine areas of separation
– May be difficult
– Location and size of islands may effect restoration
strategy

47
• Generation lost
– Damage incurred
– Type of unit and characteristics
• Blackstart
– Capability and location
• Off-line Generation
– Status prior to event
– Type of unit
– Power requirements

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• Nuclear plants
– Company obligations
• Start-up sequencing
– Dependent on operation prior to event
 Size
 Types
 State of operation

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• Sequence considerations
– Hydro – usually quickest
– Combustion Turbines
 Smaller CTs – quick-start (10 minutes)
 Large CTs – may take longer (up to 1 hour)
– Steam - Drum-type
 1-20 hours away
– Steam - Super Critical
 4-20 hours away

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• Fuel supplies – need for power
– Gas plants
– Fuel depots
• Utilization of auxiliary power
– Limited supply
– Best utilization required

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• Abilities and direction of plant operators
• Knowledge of neighboring systems
– Pooling restart sources
– Sharing reserves
– Interconnecting transmission
• Abilities and comparison to plan

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Transmission Assessment
• Facilities energized
– EMS – if operating and reliable
• Faulted Equipment
– Oscillographs
– Digital Fault Recorders (DFRs)
– Inspections by field personnel
– Relay targets in substations
– Smart Relays

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• Breaker indications
– Open
 Permanent faults
 Out-of-Step conditions
 Temporary faults
– Closed
 De-energized line with no problem
 Faulted equipment that never cleared
 Equipment damaged after event

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• Station Batteries
– Capabilities
 Hour until depletion
 Open-close-open operation
• Relay Reliability
– Adequate fault current available
– Most questionable relays
 Re-closing relays
 Station hot bus-dead line re-closing

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• Underfrequency relays
– Status of what activated
– Sequence of restoration
• Facility status with regards to plan
– May not have what you thought you would
 May impact restoration plan

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Restoration Switching Strategies
• Two general strategies:
• “All Open”
– All circuit breakers at affected substations are opened
• “Controlled Operation”
– Only circuit breakers necessary to allow restoration to
proceed are opened

57
“All Open” Strategy
• Can be accomplished by:
– Station Operators
– EMS/SCADA systems
• Advantages
– Simpler and safer configuration to restore
– Only breakers in restorations process will be closed
– Unlikely to experience inadvertent load pick-up
• Disadvantages
– Longer time to accomplish
– More breaker operations

58
“All Open” Strategy
• “All-Open” Approach
– Open all circuit breakers at blacked-out substations prior
to restoration

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“Controlled Open” Strategy
• Advantages
– Less energy requirements
 Breakers not involved in sectionalizing and restoration remain
closed
 Postpone operation of some breaker to later in process
– May be quicker
• Disadvantages
– Higher emphasis on isolation between restored and de-energized
systems
– Must study steady state and transient voltage response
 Multiple lines being energized

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“Controlled Open” Strategy
• “Controlled Operation” Approach
 Open circuit breakers needed to accommodate restoration
Energize
Torrey to
Zanes II
OPEN
CBs

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Restoration Strategies

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Inside-Out Approach
• Sometimes referred to as “Bottom-Up” or
“Blackstart”
– Starts with the formation of islands utilizing blackstart
generation
– Only option available in a complete shutdown without
outside help
– Should serve as the basis for restoration plans
 Worst case
– Different methodologies for restoration can utilize
approach

63
Inside-Out Approach
1. Determine blackstart units to start
2. Stabilize blackstart units brought on line
3. Establish restoration transmission corridor
4. Build island by restoring generation,
transmission, and load
5. Interconnect islands when conditions warrant

64
Inside-Out Approach
“Multiple Island” Method

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• Advantages
– Multiple areas are restored at the same time
– Quicker restoration of generation
– One island going down will not take the others down
– Quicker restoration of load throughout area

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• Disadvantages
– Amount of manpower needed to handle multiple islands
 Beyond the capability of one person
– Longer instability in individual islands
 Due to size
– Managing control of multiple frequencies
 Need to gain assistance from generation operators

67
Inside-Out Approach
“Core Island” Method

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• Advantages
– Develops larger island quicker
 Provides more stability
– Offers more options for restoration
 Able to handle restoring larger blocks of load
 Restoration of underfrequency relays sooner
– Higher emphasis on control
– Higher desirability for interconnecting
– Quicker time in restoring system

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• Disadvantages
– Higher exposure to loss of island for single event
– Start-up power and substation power may be delayed
 Outside island
– Higher chance of diminished battery power before
receiving outside power
 Outside island

70
Inside-Out Approach
“Backbone Island” Method

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• Advantages
– Quickest method for restoring auxiliary power to
generators and light and power to substations
– Focused switching
– Quickly creates backbone of the transmission system
which may allow for quicker connection to the
Interconnection

72
• Disadvantages
– Excess line charging may cause high voltages
 May be the biggest obstacle to overcome
– Island stability will be an issue due to the size,
generation operating, and long transmission paths
– Without building a good foundation, customer load may
take longer to restore

73
“Outside-In” Approach
• Sometimes referred to as “Top-Down Approach”
– Utilize outside assistance to restore major transmission
paths
– Provide power supply to internal generating stations and
substation
– Start-up additional internal generation
– Begin restoration of underlying transmission system
– Restore load as conditions allow
– Continue to restore more generation, transmission, sub-
transmission, and load

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INTERCONNECTION

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• Advantages
– Quick restoration of power to generators and substations
for light & power
– Multiple restoration efforts completed simultaneously
– Higher level of stability
 Part of Interconnection
 Provided strong ties are established
– Issues related to connecting islands is a non-issue

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• Disadvantages
– Early stages of restoration may experience higher
voltages
 Excess line charging
– Neighbors ability to supply power is a key element of
success
– Neighbor assistance will be limited to transfer capability
 Both generation and transmission

77
Combination Approach
• Utilizes both approaches
– Inside-Out - Blackstart
– Outside-In – Neighbor Assistance
• Restores transmission from outside source while
building internal islands
• Islands can be connected to either other internal
islands or outside interconnection points

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INTERCONNECTION

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• Advantages
– Quickest restoration of power to generators and
substations for light & power
– Multiple areas of restoration
 Externally supported
 Internally developed
– Stability
 Areas connected to outside sources

80
• Disadvantages
– Externally tied areas
 High voltages early in process
 Neighbors ability to support
– Island synchronization required
– More complex operation
 Controlling multiple islands
 Maintaining frequency
 Additional manpower required to handle workload

81
Method Selection
• Influences for method selection
– Extent of blackout
 Complete shutdown
 Islanding
– Outside assistance availability
 Level of assistance
– Black-start capability
– Specific company philosophy and protocols

82
NYISO Re-visited

83
Southwest Re-visited
Yuma
CFE
SDGE APS
IID

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Restoration Considerations

85
• Voltage Control
– Bulk Power system maintained 90% - 110 %
– Maintain voltages at minimum levels will reduce charging
current
– Local load must be restored as transmission lines are
energized to reduce voltages
 Station light and power
 Customer load

86
Simulation Demonstration
Voltage Control with Load
SERC Restoration_Voltage Control

87

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• Voltage Control
– Balance reactive resources
 Line charging
 Shunt capacitors
 Removed from service until sufficient load restored
 Shunt reactors
 Placed in service early to reduce voltage
 Static VAR Compensators and Condensers
 Automatic control - in service as soon as practical
 Generator MVAR capabilities

89
• Interconnecting
– Generating plants or stations with
synchroscopes
 Phase angle should be 10o or less
• Transmission Stability
– Only facilities expected to carry significant
load should be energized

90
• Transient Stability Factors dependent on:
– Strength of transmission network
– Strength of tie-lines to the outside
– Characteristics of Generating units
 Inertia
• More lines and strength on bus – less severe the
transients when energizing

91
Generation Restoration
• Unit stability in question during early stages
• More generators on-line = more system stability
– Synchronized inertia
– Frequency and voltage control
• Stronger sources allows more:
– Circuit energization
– Unit start-ups
– Spinning reserves
– Load pick-ups

92
Island
Identification
and
Stabilization

93
Restoration Condition
• A power system restoration condition exists when
large portions of the power system collapse, losing
both voltage and frequency
– Total System Blackout
– Partial System Blackout
– Islanded Power System
 Typically some portion of customer load is being served in
the island

94

95
Islanded Power Systems
• Islands may be unintentionally created when a
disturbance results in system separation.
• Once an island develops the system operator
should:
– Determine island connectivity
– Stabilize the island frequency
– Stabilize the island voltage
– Ensure equipment is within acceptable loading limits

96
Islanded Power Systems
• Islands may also be created intentionally in the
course of the restoration process.
• Multiple islands may be created dependent upon
the restoration process.
• Caution should be exercised with multiple islands
– Simultaneous frequency control
– Spreading thin generation resources (small load blocks)
– Synchronization of multiple islands requires:
 Time
 Coordination
 Careful execution

97
• Five Islands
• One blackedout area
– Southern Idaho
– Loss of 11,750MW
Blackout Area

98
Island Identification
SERC Restoration_Island Identification

99
Island Stabilization
• Determine that an island exists, and the points of
separation.
• It is imperative to immediately monitor and assess
conditions within the island and take any warranted steps
to stabilize.
• Actions from system operators include:
– Switching of reactive control devices
– Generation dispatch/re-dispatch actions
– Transmission switching
– Load shedding
• All the above done in an effort to secure thermal, voltage or
frequency conditions

100
Island Stabilization
• Balancing Authority actions include:
– Select flat frequency or tie line bias to stabilize frequency depending
on status of tie lines
– If isolated implement flat frequency mode should be implemented
– If two or more BAs have remained connected
 Flat frequency for the larger area
 Tie line bias for the smaller area
• Transmission operators should consider the potential for
inadvertent reclosing of breakers via synchro-check relay
schemes.
– If warranted system operators should consider blocking these
automatic schemes

101
Island
Synchronization

102
Synchronizing Theory
• When closing a CB between two separate islands
of the system the voltages on both sides of the CB
are synchronized prior to it’s closing.
• The three aspects of the voltage are called
synchronizing variables:
– The voltage magnitudes
– The frequency of the voltages
– The power angle between the voltages

103
Guidelines for Synching Islanded Systems
• Location of synchronizing equipment must be considered
when developing restoration plans.
• The plan should also identify the type of equipment.
 Synch-scope
 Automatic synchronizer
 Synch-check
• The plan should also estimate locations at which
synchronization will likely be required.
• At times it may be better to wait until neighboring systems
have reached minimum reliability requirements before
synchronization

104
Assessment Prior to Interconnecting
• Communication between parties involved and
Reliability Coordinators must ensure
understanding of:
– Existing conditions after stabilization
– Considerations to remain stable after synchronization

105
• Existing condition assessment includes (but not
limited to):
– Load
– Synchronized Generation
– Prevailing Voltage and Frequency
– System Topology
– System Operating Reserves
– System Reactive Reserves
– First Contingency Loss

106
• Consideration to remain stable after synchronization:
– Frequency
 Continue restoration efforts in a manner that prevents excessive
frequency swings
– Voltage
 System operators should discuss desired voltage levels
 In some cases load should be shed or restored as needed to maintain
voltage within limits
– Thermal Issues
 Normal continuous ratings of any single facility should not be exceeded
 Special attention should also be given to tie lines and interfaces

107

108
Transmission Stability
• Facilities need to be checked before and after
energization
– Aim low on voltage to reduce charging currents
– Facilities must be monitored for loading and voltages
• Only facilities expected to carry significant load
should be energized
• Minimize switching operations
– Excessive switching increases restoration time
– Limited source of energy until L&P are restored

109
Charging Consideration

110
• Load/Frequency Control
– Small increments of generation and load
 Minimize frequency impacts
– Load pick-ups </= 5% total synchronized generating
capability
 Example: You have 1000 MW of synchronized capacity –
maximum load pick-up is 50 MW
– Frequency maintained between 59.75 – 61.00 Hz
 Regulate toward 60.00 Hz

111
Load Pick-up and Frequency
SERC Restoration_Island Connecting

112
• Load/Frequency Control
– Maintain > 59.00 Hz
 May need to use manual load shedding
 Guide – 6-10% for 1 Hz
– Maintain frequency slightly above 60.00 Hz prior to load
pick-up
– Refrain from picking-up UF protected load
 Until load pick-ups are not frequency volatile
 Alternate pick-ups at various steps

113
Load/Frequency Control
• Generators will trip off automatically
– Low Frequency at 57.50 Hz. (Under-frequency relay)
– High Frequency at 61.75 Hz. (Over-speed relay)
• Generators may be tripped manually
– Low Frequency of 57.0 Hz.
– High Frequency of 63.0 Hz.
– Find out your generator policies

114
Isochronous Control
• A governor that strives to maintain its target
frequency (normally 60 Hz) for all load levels is
known as an isochronous governor
• An isochronous governor will do everything within
its means to maintain 60 Hz
• In the example in theory this generator would vary
its output in the range from 0 MW to 300 MW in
response to system frequency changes

115
Isochronous Control (0% droop mode)

116
Synchronous Control
• Governor droop is expressed as a percentage of the
frequency change required for a governor to move a unit
from no load to full load or from full load to no load. (provided
the unit capacity is available)
• NERC recommends that all synchronous generators droop
settings are at 5%
• In the example a 5% droop setting means that a 3 Hz (5% of
60 Hz) change in frequency is required to move the
generator across its entire range
• It should be noted that in actual operations generators rarely
operate under load outside of a 59.5 to 60.5 frequency range

117
Synchronous Control
(speed droop mode – 5% droop)

118
Synchronous vs. Isochronous Control
• Synchronous
– A droop setting (5%) on all generators on a normal
system allows all to respond to frequency deviations
without fighting each other
• Isochronous
– A droop setting (0%) allows these units (typically black-
start) to maintain 60 Hz across their entire range
– Typically in a blackstart situation the isochronous unit
would continually be kept at mid operating range to
control frequency while synchronous units continue to
pick up loads
– Only one unit in an island should be in this mode

119
• Who controls frequency?
• Is frequency monitoring available for area?
• Coordination of generators and LSEs
• Generator operator abilities?
• Implication of LSE actions?

120
• Reserves
– Ample reserve to cover largest unit in each island
 Generation on-line
 Customer load

121
• Interconnecting Islands
– Match frequencies
– Frequency control versus tie-line control
– Best regulating units should be used for frequency
control
 General guide – 2X normal regulation

122
Island Connecting
SERC Restoration_Island Connecting

123
• Island Stability
– Voltages within limits
– Minimal voltage deviations when restoring load
– Frequency within 59.75 and 61.0
– Small frequency deviations when restoring load
– Adequate operating reserves
– Significant amount of U/F load restored

124
Restoring Load – Cold Load Pick-up
• Disconnected load will probably be much higher
than when lost
• Experience high peak demands
– Simultaneous starting of motors, compressors, etc
• Inrush currents can be 10 or more times normal
– Dependent on type of load
– Will last 2-4 seconds
– Remain at 150-200% for as long as 30 minutes

125
Cold Load Pick-up
0
2
4
6
8
10
12
0 1-2 sec 6 sec 30 min
LOAD
Multiplier
of
Normal
Load
Current
Time from Restoration
Initial Surge of
Load Current
Incandescent Lamp
Filaments; Small motors
up to speed
Large motors
up to speed.
Load Diversity
returns.

126
• Priority Customers
– Station service to nuclear plants
– Generating plant fuel supply depots
– Other facilities needed for restoration
• Critical Loads
– Military facilities
– Law enforcement organizations
– Public health facilities
– Public communication facilities

127
Restoring Load – Automatic Schemes
• System Operators must maintain control of
restoration
• Automatic protection devices should be in service
ASAP
• Automatic restoration schemes should not be
enabled
– Until sufficient portion of generation and load has been
restored

128
Restoring Load – Oil Filled Cables
• Loss of power implications
– Oil pressure drops and cable loses temperature
– Gas pockets form
– Can result in fault and damage cable on re-energizing
• Pressures should be verified prior to re-energizing
• System Operators need to know locations of oil
filled cables

129
Reserves
• Balancing Area should carry operating reserve to
cover largest unit in each island
– Reserves can be on-line or customer load that can be
shed
• The smaller the area – the more reserve should be
spinning
• Combination of systems may allow for individual
reductions in reserves

130
• What is the quickest way to get power nuclear
stations?
• Which feeders contain critical customers?
• Where are the oil-filled cables and pumping facilities
on your system?
• What are the operating parameters for oil-filled
cables?
• What are the loads of the distribution feeders?
• Where are UF relays and what are their settings?

131
Quick Review
• System Frequency – 60.05 Hz
• Generating Capacity – 1,800 MW
• System Load – 1,000 MW
• What is the maximum amount of load block that
should be restored?

132
Quick Review
• What is the maximum amount of load block that
should be restored?
1,800 MW x 5% =
90 MW

133
Quick Review
• System Load = 3,400
• System frequency drops to 58.50 Hz
• How much load needs to be dropped to get
frequency back to 60.00 Hz?
3400 X 6-10% = ??MW/1 Hz
Between 204 and 340 MW
306 to 510 MW for 1.5 Hz

134
Quick Review
• Reserves?
• Largest unit covered?
• Options available?
Capacity
(MW)
Loading
(MW)
500 350
300 275
200 175
100 50
65 65
65 65

135

Restoration Drill & Pre-Drill Training ; System Restoration Overview

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