distributed energy resources€¦ · before joining beckwith electric, wayne performed in...
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DistributedEnergy
Resources
Operation, Protection & Control
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161031_CNY_2 Hr
November 7, 2016
Syracuse, NY
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Presenter Contact Info
Wayne Hartmann is VP, Protection and Smart Grid Solutions for BeckwithElectric. He provides Customer and Industry linkage to Beckwith Electric’ssolutions, as well as contributing expertise for application engineering, trainingand product development.
Wayne HartmannVP, Smart Grid and Protection Solutions
Beckwith Electric [email protected]
904-238-3844
Before joining Beckwith Electric, Wayne performed in application, sales and marketing managementcapacities with PowerSecure, General Electric, Siemens Power T&D and Alstom T&D. During the courseof Wayne's participation in the industry, his focus has been on the application of protection and controlsystems for electrical generation, transmission, distribution, and distributed energy resources.
Wayne is very active in IEEE as a Senior Member serving as a Main Committee Member of the IEEEPower System Relaying Committee for 25 years. His IEEE tenure includes having chaired the RotatingMachinery Protection Subcommittee (’07-’10), contributing to numerous standards, guides,transactions, reports and tutorials, and teaching at the T&D Conference and various local PES and IASchapters. He has authored and presented numerous technical papers and contributed to McGraw-Hill's“Standard Handbook of Power Plant Engineering, 2nd Ed.”
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Objectives• Define DER
• Explore Types of DERs
• Why DER?
• Utility Drivers for DER
• Mission Critical Power and Conversion to DER
• DER Operational Sequences
• IEEE 1547: Industry DER Guide
• Interconnection Protection: “The Five Food Groups”
• Interconnection Transformer Impacts
• Self Protecting Inverters
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Objectives• Generator Types and Impacts
– Synchronous– Induction– Asynchronous (Inverter Based)
• Example Protection Applications
• Protective Relay as a Utility/DER Interface Point
• Distribution Protection Coordination Issues
• Harmonics
• Smart Grid / Microgrid and DER
• Impact of IEEE 1547A
• VVO/IVVC with DER
• Summary and Q&A
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What is DER?• Generation of electricity from small energy sources
– Typically <=10MW
• May be based at facilities, including industrial, commercial and residential, as well as utilities
• For this exploration, connected into distribution
• Use of Distributed Energy Resource (DER) allows collection of energy from many sources and may provide lower environmental impacts and improved security of supply
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What is DER?
Also called:
• Distributed Generation (DG)
• Distributed Resource (DR)
• Dispersed Generation (DG)
• Embedded Generation
• Decentralized Generation
• Dispersed Storage & Generation (DSP)
• Decentralized Energy
• Distributed Energy
• Independent Power Producer (IPP)
• Non-Utility Generator (NUG)
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• Conventional (Not Green)
– Burn conventional fuel
• Diesel
• Oil
• Gasoline
• Natural Gas (seen as “greener”)
DER: Green or Conventionalby Energy Source
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Conventional DERIndustrial Gas Turbine Reciprocating Diesel
Reciprocating Gaseous FuelMicroturbine Gaseous Fuel
Reciprocating aka: Internal Combustion Engine (ICE)
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Fuel Cell
Conventional DER
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• Green (Renewable)
- Use renewable sources to reduce reliance on fossil fuels:
• Hydro
• Solar (PV)
• Solar (thermal to steam)
• Wind
• Biodiesel
DER: Green or Conventional by Energy Source
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• Biogas (methane decomposition)
• Biomass (direct burn/gasification)
• Tidal
• Storage (battery)
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Renewable DER
Small HydroSolar (PV)
PV Array/Battery
(DC)AC Output
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Solar (Thermal)
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Renewable DER
Biogas
Wind
Biomass
• May be induction or
synchronous generator
output
• May be mixture of
generator and inverter
output
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Renewable DER
Biodiesel Tidal
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Renewable DERStorage Battery
Battery(DC)
AC Output
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• T&D Issues– Decrease losses
– DER at the point of use is not subject to transport loss
– T&D losses range 3-7%
• Demand Response – Turn On Local DER to Turn Off Load to System”
– No prebound/rebound effects in callable application
– Allows larger critical process C&I Customers to participate in demand response programs
– aka: Peak Reduction
Why DER: Utility Drivers
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THIS IS THE MOST EXPENSIVE, INEFFICIENT, AND
ENVIRONMENTALLY-DAMAGING POWER PER KWH OF
ELECTRICITY ACTUALLY CONSUMED
• Accumulated Annual Demand of Highest 5% occurs about 400 hrs/Year
• 100s of Billions of $ of equipment and capacity idle for most of the time
Reality of Grid Load Dynamics (Peak Demand)
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• With DER
DER in a Demand Response Role
• Without DER
DER
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Sustainability & Losses:Conventional Power Delivery
Transmission
Losses
Subtransmission
Losses
Distribution
Losses
Bulk Generation
Asset
Load
525 kVA
500 kVA
•Losses typically 3-7%
•5% used in this example
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Transmission
Losses
Subtransmission
Losses
Distribution
Losses
Bulk Generation
Asset
LoadDG
500 kVA 500 kVA
•Heat rates (efficiency) of modern engine/gensets applied in DER
systems are as good, if not better, than combustion turbines (CTs) [1,2].
• DER capacity has a heat rate of 9,800 btu/kWh saving approximately
2,200 btu/kWh of fuel input compared to the overall peak power
generation portfolio published by eGrid [3].
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[1] California Energy Commission;
http://www.energy.ca.gov/distgen/equipment/reciprocating_engines/reciprocating_engines.html
[2] California Energy Commission;
http://www.energy.ca.gov/distgen/equipment/combustion_turbines/combustion_turbines.html
[3] http://www.epa.gov/cleanenergy/energy-resources/egrid/index.html
Sustainability & Losses:Conventional Power Delivery
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Non-Signaled Passive Demand Response:Rebound Effect
Time of Day
Loa
d
Curtailed Load
Rebound Load
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Signaled Passive Demand Response:Prebound-Rebound Effect
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Signaled DER-based Demand Response:No Prebound-Rebound Effects
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• Transmission decongestion
• Distribution decongestion
• Distribution build-out deferral
• Grid Support – Ancillary Services
• Voltage regulation
• VAR Support
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Why DER: Utility Drivers
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• T&D Issues– Firming of Green Power
• Green power has intermittency issues
• Answered with fast syncing DER
– Conventional DER
– Storage
– Ready and Standby Reserves• Fast syncing prime movers
– Spinning Reserves• Synchronized storage
Why DER: Utility Drivers
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ATS vs. Circuit Breakers
LOAD
UTILITY
G
LOAD
UTILITY
G
G
M
ATS Circuit Breakers
• ATS does not protect
• ATS cannot long-term parallel
• Circuit Breakers cost more than an ATS, but provide
protection and operational flexibility
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Conversion of ATS-based emergency system to dual purpose emergency and
“bumpless” peak shaving system
LOAD
UTILITY
G
LOAD
UTILITY
G
G
M
Existing FacilityFacility Retrofit with Switchgear/
Protection/Controls for Grid Paralleled
Generator Operation
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LOAD
UTILITY
Existing FacilityFacility with Generator and
Switchgear/Protection/Controls
Added
LOAD
UTILITY
G
G
M
Greenfield dual-purpose emergency and “bumpless” peak shaving system
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Complex Application: Dual-Fed Facility Main-Tie-Main
UTILITY UTILITY
T
LOADS
L L LLL L
LOADS
M
1
M
2
Existing Facility
UTILITY UTILITY
LOADS
L L LLL L
LOADS
M
1
M
2
Facility with Generators and
Switchgear/Controls Added
G
G
T
G
G
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Operational Sequence Details
• Emergency Power
• Load Isolation
• Load Following
• Export
To know how DER is controlled in parallel with a utility is important for DER Interconnection protection application
When control fails, protection is the safety net
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Po
we
r
Facility Demand
Generator Output
Utility Import
Time
Generator Starts
Generator CB 52G Closes
Generator Picks Up Load
Utility Power Fails,
Utility CB 52M Opens
Emergency Power Mode
Generator CB 52G Opens,
Generator Shuts Down
Utility CB 52M Closes,
Generator Unloads
LOAD
UTILITY
G
G
M
WL
WU
WG
Emergency Power: Details
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Load Isolation: Details
Load
Management
LOAD
UTILITY
G
G
M
WL
WU
WG
Po
we
rFacility Demand
Generator OutputUtility Import
Time
Load Management Period
Main Breaker to
Utility Opens
Main Breaker to
Utility Closes,
Generator
Unloads
Generator Starts,
Synchronizes and
Picks Up Load
Generator
Breaker Opens,
Generator Shuts
Down
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Load Following: Details
Load Management
LOAD
UTILITY
G
G
M
WL
WU
WG
Po
we
r
Facility Demand
Generator OutputUtility Import
Time
Load Management Period
Utility Import
Generator Starts,
Synchronizes and
Picks Up Load Generator
Breaker Opens,
Generator Shuts
Down
Generator
Unloads
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Export: Details
Load Management
LOAD
UTILITY
G
G
M
WL
WU
WG
Po
we
r Facility Demand
Generator Output
Utility Import
Time
Load Management Period
Export to Utility if Possible
Generator Starts
Generator CB 52G Closes
Generator Picks Up Load
Generator CB 52G Opens,
Generator Cools
& Shuts Down
Generator Unloads
Facility Demand
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Example DER System
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UTILITY
LOAD
52
G
52
M
LV Switchgear
Load Bus
G
Interconnection Protection
Generator Control & Switchgear Position Control
Engine/Generator
Communications for Remote Dispatch &
Monitoring
Interconnection Protection in LV Switchgear
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Interconnection Protection in LV Switchgear
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Protective Relay
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UTILITY
LOAD
52
G
52
M
LV Switchgear
Load Bus
G
Interconnection Protection
Generator Control & Switchgear Position Control
Engine/Generator
Communications for Remote Dispatch &
Monitoring
Protection and Control
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• Protection that allows the DER to operate in parallel to utility
• Large non-utility generators do not require specific interconnection protection
- Integrated into transmission system
- Interconnection breaker(s) are tripped by transmission line/bus/transformer protection.
• Smaller DERs do require specific interconnection protection- Goes for conventional as well as inverter-based systems
What is DER Interconnection Protection?
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Protection ObjectivesUtility Perspective
Personnel safety after deliberate feeder de-energizing
Minimize/prevent DER fault backfeed contribution Coordination issues with other protective elements
Breakers/relays and reclosers on affected feeder
Breakers/relays and reclosers in adjacent feeders off the same bus as affected feeder
Damage to equipment
Transient overvoltage
Ferroresonance
Avoid damage to utility equipment and customer loads from
abnormal operating conditions during islanding Voltage issues
Frequency issues
Harmonic/PQ issues
Simplify restoration Easier reclosing without synchronizing at utility breakers
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Protection Objectives DER Perspective
Avoid mal-synchronization damage
Can occur after utility reclosing after initial feeder clearing
Out-of-phase closing (shaft torque stress; motors and generators)
Minimize/prevent damage to DER by pumping current into
utility fault
Detection of abnormal operating conditions at utility that
can cause damage to DER and facility
Over/under voltage
Over/under frequency
Overexcitation
Unbalanced voltages/single phasing
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• Seamless integration of DERs into utility protection system despite:- “Too many cooks in the kitchen”
• Owner, Consultant, Packager, Utility
- Ownership boundaries- Conflicting objectives of DER Owners vs. Utility
• DER Owner: “We do not want to pay for anything.”• Utility: “We want everything and for you to pay for it.”
• Ensuring protection is correct over the life of installation- Settings are properly developed- If installation or EPS changes, assess impact on existing
protection
DER Protection Engineering Challenges
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IEEE 1547
IEEE Std. 1547A; Ride through (2014)
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Presently under
revision to include
1547a content
Really good
application guide
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• DR Unit: Distributed Resource (DER)
• EPS: Electric Power System
• Interconnection: The result of the process of adding DR to an Area EPS.
• Interconnection Equipment: Individual or multiple devices used in an interconnection system.
• Interconnection System: The collection of all interconnection equipment and
functions, taken as a group, used to interconnect DR unit(s) to an Area EPS.
DR Unit Area EPS
Interconnection system
IEEE 1547 Definitions
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Area EPS
• Area EPS is the portion of the
power system that is impacted
by the DER
• Typically the distribution system
including the connected
substation
• If DER capacity is large,
transmission could possibly be
effected
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IEEE 1547 Definitions
PCC: Point of Common Coupling
PI: Point of Interconnection
EPS: Electric Power System
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IEEE-1547: 50,000’ Overview• Safety
– Personnel working on a utility system must be protected from backfeed or accidental energization from DER
• Impact of size– Intended to cover up to 10MW
• Local Disturbances– Quality of service on the utility system should not be degraded
(voltage, frequency, harmonic limits)
• Impact to Existing Distribution Protection– Dealing with bi-directional power flows and coordination in radial
systems turned multiple source systems
• Impact of Islanding– Creation of unintentional islands must be detected and eliminated as
fast as possible
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Greatly complicates restoration
- Requires synchronizing at utility substation
- Inhibits automatic reclosing
Power quality issue
- DER may not be able to maintain voltage, frequency and harmonics within acceptable levels (load generation; no harmonic “sink”)
SmartGrid and Microgrid may allow islanding in future
Islanded Operation of DER with Utility Load Is Generally Not Allowed
Loads Loads Loads
Loads LoadsLoads Loads Loads
Loads Loads
Loads Loads Loads
Loads
Loads
DER
Utility Substation
If DER creates a feeder island,reclosing requires synchronizing atthe utility substation
Feeder Island
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Feeder deenergizes when utility opens feeder
Restoration responsibility on the DER
- Requires synchronizing to Utility
DER Facility Islanding to the Utility is Allowed
Loads Loads Loads
Loads LoadsLoads Loads Loads
Loads LoadsLoads Loads Loads
Loads
LoadsDER
Utility Substation
DER can create its own island,and synchronize to the utility
DER Island
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DER Interconnection Protection• Transformer connections
– Effect on EPS fault duties
– Effect on possible overvoltage conditions
– Interaction with generator connections
– System modifications
• Grounding of the DER system– Grounding for safety
– Effect on EPS ground protection
• Abnormal system configurations– Alternate source
– Abnormal sectionalizing
– Alternate breaker or transfer bus
IEEE 1547 Standard Series: Addressed Areas
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DER Interconnection Protection• Radial versus bidirectional power flow
– Effect on protective equipment
– Effect on voltage regulators
– System modifications
– System costs
• Voltage deviations– Three-phase
– Single-phase
– Induction versus synchronous
– Voltage rise phenomenon
– Surges, sags, and swells
IEEE 1547 Standard Series: Addressed Areas
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DER Interconnection Protection
• Unintended islanding
• Reclosing– Main or source circuit breaker
– Reclosers and sectionalizers
– DR equipment
• Harmonics
• Flicker
• Spot Networks
IEEE 1547 Standard Series: Addressed Areas
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Spot Network
• Network Protectors are not rated for fault duty that DER can backfeed
through them
• They are also not rated for larger-than-rated voltage that can occur when
DER is on-line and the network protector is open
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DER Interconnection Protection
• Synchronization
• Loss of synchronism
• Operational safety practices
• System capability– Short-circuit capability of EPS equipment
– Loading capability of Area EPS
IEEE 1547 Standard Series Addressed Areas
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• Utility-Grade interconnection relays- Pass all pertinent ANSI standards- C37.90-1,2,3
• CT and VT requirements (quantities sensed)
• Winding configuration of interconnection transformers
• Functional protection- 81U/O, 27, 59, etc. - Settings of some interconnection functions
• Pick ups• Trip times
What Utilities Generally Specify
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Protection Elements and Use
– “The Five Food Groups”• Loss of Parallel Operation (utility disconnected)
– Anti-Islanding
• Abnormal Power Flow– Anti-Islanding
• Fault Backfeed Removal
• Detection of Damaging System Conditions
• Restoration
– Impact on interconnection protection• Interconnection transformer configuration• Various types of DERs
– Induction, Synchronous, Asynchronous (Inverters)
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Loss of Utility Parallel (Anti-Islanding)
– Voltage and frequency (27, 59, 81-U, 81-O)
– Rate-of-change of frequency (81R, aka ROCOF)
Based on load (real and reactive) not equaling generation
Abnormal Power Flow (Anti-Islanding)
– Power (32F, 32R-U)
Based on power flow violations across the PCC
Interconnection Protection“The Five Food Groups”
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Low Import Power: 32R-U
32R-U Relay pickup set
to at least 5% of total
connected generator
rated KVA
32R-U Relay
programmed to trip when
imported power falls
below the pick-up level
Switching off a large
amount of facility load
may cause nuisance
tripping
Generator Control should
have proper bias power
margin set
SUPPLY,Low Side
52
I
UTILITY
52
G
52
L
RelayLOADS
ReversePower
ForwardPower
REVERSE UNDERPOWER (32R-U)
NO TRIP
Reverse Forward
TRIP
Pick up
-P +P
52
G b 52
Ib
Control/Status Input programmed to block 32R-U if either/both the generator breaker or
interconnection breaker are open
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• Bias is made in the genset controller to ensure import of 40kW when paralleled
• 32R-U is set lower with appropriate margin (trips if import goes below genset control setpoint)
Low Import Power: 32R-U
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Fault Backfeed Detection
Phase and overcurrent (51V, 51)
– Directional overcurrent (67) or impedance (21) may be used
Backfeed from Grounded DER
– Ground overcurrent (50N/51N)
Directional ground overcurrent (67N) may be used
Backfeed from Ungrounded DER
– Ground over/under voltage (27N, 27N/59N)
– Negative sequence overcurrent (46)
Based on abnormally high current or abnormally low/high
voltage as a result of faults
Interconnection Protection“The Five Food Groups”
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The winding arrangements facing the
utility and the facility have an impact on
protection
Interconnection Transformer convention:
• Utility = Primary
• Facility = Secondary
Interconnection Transformer Winding
Arrangements Impact Protection
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Interconnection TransformersPrimary (Utility) Grounding Impacts
Grounded Primary: Pros:
• No overvoltage for ground fault at F1
• No overvoltage for ground fault at F2
• No ground current from feeder for faults at
F3 (delta sec. only)
Cons:• Provides an unwanted ground current for
feeder faults at F1 and F2
• Creates a ground source even when delta secondary circuit is disconnected
• May cause coordination problems within facility as well as increased ground fault current to Utility
• Allows feeder relaying at A to respond to a secondary ground fault at F3 (Ygnd-Ygnd
only)
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Interconnection TransformersPrimary (Utility) Grounding Impacts
Ungrounded Primary:
Pros:
• No ground fault backfeed for fault at F1
& F2
• No ground current from breaker A for a
fault at F3
Cons:
• Supplies the feeder from an
ungrounded source after substation
breaker A trips causing overvoltage
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a
bc
a
bc
ground
Van=Vag
Vbn=VbgVbn=Vbg
n=g
vag=0
n
Van
= -Vng
Vcn Vbn
Vbg
Vcg
Unfaulted
Ground Fault
DER
Backfeed to Utility
DER Facility
Ungrounded Primary:
Faulted System Backfeed Overvoltage
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a
bc
a
bc
ground
Van=Vag
Vbn=VbgVbn=Vbg
n=g
vag=0
n
Van
= -Vng
Vcn Vbn
Vbg
Vcg
Unfaulted
Ground Fault
DER
Backfeed to
Utility
DER
Facility
59
N
Sensing Ungrounded System Ground Faults
with 3 Voltage Transformers
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a
bc
a
bc
ground
Van=Vag
Vbn=VbgVbn=Vbg
n=g
vag=0
n
Van
= -Vng
Vcn Vbn
Vbg
Vcg
Unfaulted
Ground Fault
Sensing Ungrounded System Ground Faults
with 1 Voltage Transformer
DER
Backfeed to Utility
DER Facility
59
N
27
N
• Subject to ferroresonance
• Place maximum resistive
burden on VT to help
prevent
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• Many utilities only allow use of ungrounded primary windings only if the DER sustains at least a 200% overload on islanding
• The overload prevents the overvoltage from occurring
Impact of Overvoltage:
Saturation Curve of Pole-Top Transformer
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• When applying non-directional phase or ground elements for fault backfeed protection (50P, 50N, 51P, 51N), they must be coordinated for faults in the facility and on the utility.
• This could lead to longer clearing times for utility faults.
• To speed up response of utility faults, use of directional elements (67, 67N, 21P), set to only trip in the utility’s direction, will provide maximum trip speed.
Directional vs. Non-Directional Elements at the PCC
DG
Protection
C
A
B
DG
Protection
67
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Interconnection Protection“The Five Food Groups”
Damaging System Conditions
– Open phase condition or load imbalance (46, 47), negative sequence current and voltage
– Phase sequence reversal , negative sequence voltage (47)
– Loss of synchronism (78)
– Ferroresonance, instantaneous overvoltage (59I)
Based on current or voltage imbalance (including reverse phase rotation),
power system and DER going out-of-step, or ferroresonance
Facilitate proper restoration
– All elements reset, voltage and frequency within limits
– Reconnect timer (79) (all DER)
– Sync check (25)
• Synchronous generators , some inverters and facilities with motor loads
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• Induction
• Excitation provided externally by system- VAR drain
• Less costly than synchronous machines- No excitation system or control
- No sync equipment needed
• Limited in size to <=500 KVA
• May cause ferroresonance after disconnection from utility
(self-excitation from nearby caps)
VAr Source
Induction Generator
Types of Generators
• Some Wind Power
• Some Small Hydro
• Some small prime mover driven
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• Ferroresonance can take place between an induction generator and capacitors after utility disconnection from feeder
– Ferroresonance can also occur on Synchronous Generators!
• Generator is excited by capacitors if the reactive components of the generator (XG) and aggregated capacitors (XC) are close in value
• This interplay produces non-sinusoidal waveforms with high voltage peaks. This causes transformers to saturate, causing non-linearities that exacerbate the problem.
Ferroresonance
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New York Field Tests- 1989
Field Test Circuit
Test Circuit Setup
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Conditions:
Wye-Wye Transformers, 100kVAr capacitance, 60kW generator, 12kW load
New York Field Tests- 1989
Field Test Circuit
Ferroresonance:
Test Circuit Setup
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52
I
UTILITY
52
G
BUS
LED Targets
Programmable I/O
Metering
IRIG-B Input
Communications Ports
Waveform Capture
Sequence of Events
Integral HMI
Multiple Setting Groups
Dual Power Supply
1
59
N
27
N1 or 3
Ungrounded Primary
Protection Element Usage
51
N
50
N
M-3520 Relay
Fault Backfeed Removal
Damaging Conditions
Loss of Utility Parallel(Anti-Islanding)
Abnormal Power Flow
Restoration
213251
V67
3Y
79
27475981
0/U
81
R
25
59
I
60
FL46
67
N50
1
2 or 3
78
Grounded Primary
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Inverter Active Anti-Islanding Protection
Impedance Measurement
• Similar Methodologies and Other Names– Power Shift; Current Notching; Output Variation
• Theory:– Amplitude of current changed (increased)
– With utility connected, little resultant voltage change
– With utility disconnected, larger resultant change
• Works well with single inverter
• Multiple inverters can swamp each other out as amplitude change is not synced between inverters
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Inverter Active Anti-Islanding Protection
Detection of Impedance at Specific Frequency
• Similar Methodologies and Other Names– Harmonic amplitude jump
• Theory:– Inject a current harmonic of a specific frequency
– Utility impedance is much lower than the load impedance at the harmonic frequency, then the harmonic current flows into the grid, and no abnormal voltage is seen
– With utility disconnected, a harmonic voltage is developed
• Works well with multiple inverters
• May be difficult to obtain secure yet dependable settings
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Inverter Active Anti-Islanding Protection
Slip Mode Frequency Shift (SFS)
• Similar Methodologies and Other Names– Slide Mode Frequency Shift; Phase Lock Loop Slip; “Follow the Herd”
• Theory:– Moves phase angle of voltage dependent on frequency measured,
thereby causing changes in frequency– With utility connected, frequency does not change– With utility disconnected, frequency change is detected
• Highly effective in the multiple inverter applications and provides a good compromise between islanding detection effectiveness, output power quality, and impact on transient response of overall power system.
• May be difficult to obtain secure yet dependable settings
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Inverter Active Anti-Islanding Protection
Frequency Bias
• Similar Methodologies and Other Names– Frequency Shift Up/Down; Active Frequency Drift
• Theory:– Current waveform of inverter is slightly distorted such that there is a
continuous trend to change frequency– When connected to utility, it is impossible to change frequency– When disconnected from utility, frequency forced to drift up or down
• Frequency bias requires small degradation of PV inverter output power quality
• In order to maintain effectiveness in multiple-inverter case, there would have to be agreement between all inverters on direction of the frequency bias.
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Inverter Active Anti-Islanding Protection Sandia Frequency Shift (SFS)
• Similar Methodologies and Other Names– Accelerated Frequency Drift; Active Frequency Drift with Positive
Feedback; “Follow the Herd”
• Theory:– Frequency is changed up or down depending on if higher or lower
than rated– When connected to the utility grid, minor grid frequency changes are
detected and the method attempts to increase the change in frequency but the stability of the grid prevents change
– When disconnected from the utility, the frequency is forced to drift up or down
78
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Inverter Active Anti-Islanding Protection
Sandia Frequency Shift (SFS) (con’t)
• Provides a good compromise between islanding detection effectiveness, output power quality, and system transient response effects
• Requires that the output power quality be reduced slightly when it is connected to the grid because the positive feedback amplifies changes that take place on the grid
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Inverter Active Anti-Islanding Protection Sandia Voltage Shift (SVS)
• Similar Methodologies and Other Names– Voltage shift, positive feedback on voltage; “Follow the Herd”
• Theory:– Voltage is increased or decreased according to if utility voltage is
above or below rated– When connected to the utility grid, there is no change in voltage– When disconnected from the utility, there is a change in voltage
• Effective islanding prevention
• Method may have small impacts on the utility system transient response and power quality– Penetration levels of inverters using SVS may have to be kept low on
weaker grids in order to avoid system-level problems
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Inverter Active Anti-Islanding Protection Frequency Jump
• Similar Methodologies and Other Names– Zebra Method
• Theory:– Dead zones are inserted into the output current waveform at some
interval of cycles– When connected to the utility grid, the dead zone is not detected– When disconnected from the utility grid, the dead zone is detected
• Not useful on multiple inverter applications
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Induction Contributes fault current
Usually not capable of fault backfeed VARs from system required to operate
Fault contribution characteristics same as induction motor
Sync equipment not needed
Synchronous Contributes fault current
Capable of short time sustained fault backfeed due to presence of an exciter
Sync equipment needed
Types of Power Sources
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Synchronous Generator
Synchronous
- Excitation provided by field
• May be a VAR source
• Requires excitation system and control
- Sync equipment needed
- Sized 10kW and up
• Types of Generators
- Prime mover driven
- Some wind
- Some hydro (larger)
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Small Generator Fault Current Contribution
• It’s all about x”d - t”d, x’d - t’d, and xd, plus how excited (self or PMG)
– x”d used for initial fault level determination
• x”d and t”d is subtransient current time
– x”d used for next interval of fault level determination
• x'd and t’d is transient current time
• Consult genset manufacturer for alternator data sheets!
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≈400kVA Generator
Rated Amps = 482A
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Self-Excited
Genset
86
Fault Current for≈400kVA Generator
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Small Genset Current Decrement for PMG
• PMG =
Permanent
Magnet
Generator
• Uses PM
Excitation that
does not fully
collapse fault
current
• This example is
from a small
genset, about
600A rated
current
“Cummins Power Generation: Application Manual -- Liquid Cooled Generator Sets” -- Ver.G.EN
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• Asynchronous (Static Power Converters)
– Capable of limited fault current
– Grid Paralleled and Grid Isolation Variants and Operational Modes• Grid Isolated Mode uses Voltage Control and
may be capable of fault backfeed and fault ride-through
• Grid Isolated Mode may require sync check for connected loads if rotating machinery
Types of Power Sources
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Asynchronous
- Static Power Converter (SPC) converts generator
frequency to system frequency (dc-ac or ac-dc-ac)
VARs
Types of Generators
•Solar, PV
•Fuel Cells
•Wind
•Microturbine
•Storage
Asynchronous Generator:
Static Power Converter or Inverter
DER
89
Asynchronous Tie
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• Voltage Controlled
• Can provide limited fault current to the grid
• Fault current is in the order of 1.1-1.3 pu rated load current
• Can provide fault ride-through
– Fault current will be maintained as long as trip settings allow
• Operating in Voltage Control Mode: Fault current reactive component will increase as the inverter contributes to a fault
• Can cause system transient overvoltages if power output to connected load ratio suddenly decreases (transient control issue)
Non-Grid Parallel Inverters
90
90
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• Current Controlled
• Can provide limited fault current
– Fault current is in the order of 1.1-1.3 pu rated load current
– Fault current will decay when utility disconnects
– If overloaded current will diminish even faster
• Can cause system transient overvoltages if power output to connected load ratio suddenly decreases (transient control issue)
Grid Paralleled Inverters
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• Most grid paralleled inverters have built-in anti-islanding protection (if UL 1741 compliant)
– Inverter tries to periodically change output (f, V or I)• If grid is hot, inverter cannot make noticeable change
• If grid has tripped, the f, V or I moves and the controller trips the machine
– Difficult to test; some utilities do not trust and require other protection
Grid Paralleled Inverters
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Inverters, Sudden Load Rejection and Overvoltage
INVERTER
Inverter Isolation Transformer
PCC Transformer
480V Bus Utility
MV
To UTILITY
SUBSTATION
To OTHER FEEDER LOADS
“Effective grounding of distributed generation inverters may not mitigate transient and temporary overvoltage”;
WPRC Conference 2012; M. E. Ropp, Member, IEEE, M. Johnson, Member, IEEE, D. Schutz, Member, IEEE, S. Cozine,
Member, IEEE
• Tests run on inverter to
connected to 480V Bus,
then connected to
utility MV feeder
• Used different
ISOLATION transformer
winding arrangements
and PCC transformer
winding arrangements
• Varied the level of load
rejection (load:gen) to
see transient voltage
response effects
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Typical response seen when load is suddenly rejected and load:gen ratio changes
94
Inverters, Sudden Load Rejection and Overvoltage
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Transient overvoltage an inverter control issue, not a grounding issue
95
Inverters, Sudden Load Rejection and Overvoltage
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DER Reconnect Timer & Reclose Permissive• Used to assure utility has gone through successful reclose cycle
• Set longer than total reclose cycle
• All clearing and shot time, plus longest possible reclaim time
• Typically set in minutes
• Uses permissive from voltage and frequency functions to assure utility source is back and viable
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DER Protection Coordination
• Tripping Order
– Utility
– DER Interconnect
– DER Generator
• Restoration Order
– Utility Substation Breaker (or Recloser)
– DER Interconnection Breaker
– DER Generator Breaker (if tripped)
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ORUTILITY (PCC)
PROTECTIONS
TRIP
UTILITY
CB
0T
UTIILTY CB
RECONNECT
PERMISSIVE
SYNC CHECK
FUNCTION
NOT
RECONNECT
TIMER
NOTES:
“T” in the timer function is the preset time delay. Timer is time
delay on pickup type.
Sync check function(s) sourced from PTs from the load bus and
the Utility (PCC)
(PCC)
(PCC)
AND
UTILITY
LOAD
52
G
52
M
LV Switchgear
Load Bus
G
Interconnection Protection
Generator Control & Switchgear Position Control
Engine/Generator
Communications for Remote Dispatch &
Monitoring
Typical Trip/Reconnect Logic
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Harmonics
• Single DER harmonic limits• What about high penetration with
different inverter firing methods?
99
Source: 1547 D3.1, unapproved draft
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Harmonic Concerns• If high penetration of inverters causes great
enough harmonics at system resonant point, currents flow to cap banks and cause hearting and possible damage
– Inverters are the source
– Caps are the sink
• A good defense is a good defense
– Employ DER protection and capacitor bank controls with harmonic monitoring, alarming and tripping
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Harmonic Monitoring, Alarming and Tripping
• DER Protective Relay should monitor, log, alarm and trip for:
– THD, voltage or current
– TDD, current
• TDD is called out in IEEE-1547
• Capacitor Control should monitor, log, alarm and trip for:
– THD, voltage
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DER Loads Loads
Utility
Point of Common Coupling
Interconnection Transformer
DER InterconnectionProtection
Sync
3Y
3Y or
1
Point of Interconnection
Interconnection Protection Placement
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DER Loads Loads
DER InterconnectionProtection
Utility
Point of Common Coupling
Interconnection Transformer
Sync
3Y or
1
Point of Interconnection
103
Interconnection Protection Placement
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DER Loads Loads
Utility
Point of Common Coupling
Interconnection Transformer
DER InterconnectionProtection
Sync
Ungrounded Primary
Only
3Y or
1
3Y- or 1
Point of Interconnection
104
Interconnection Protection Placement
104
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DER Loads Loads
Utility
Point of Common Coupling
Interconnection Transformer
DER InterconnectionProtection
Sync
Ungrounded Primary
Only
3Y or
1
3Y- or 1
Point of Interconnection
105
Interconnection Protection Placement
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106
52
I
UTILITY
52
G
BUS
LED Targets
Programmable I/O
Metering
IRIG-B Input
Communications Ports
Waveform Capture
Sequence of Events
Integral HMI
Multiple Setting Groups
Dual Power Supply
1
59
N
27
N1 or 3
Ungrounded Primary
Protection Element Usage
51
N
50
N
M-3520 Relay
Fault Backfeed Removal
Damaging Conditions
Loss of Utility Parallel(Anti-Islanding)
Abnormal Power Flow
Restoration
213251
V67
3Y
79
27475981
0/U
81
R
25
59
I
60
FL46
67
N50
1
2 or 3
78
Grounded Primary
Comprehensive Protection Application
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52
I
UTILITY
52
G
BUS
LED Targets
Programmable I/O
Communications Ports
Waveform Capture
Sequence of Events
Integral HMI
Multiple Setting Groups
59
N
27
N1
Ungrounded Primary
Protection Element Usage
Fault Backfeed Removal
Damaging Conditions
Loss of Utility Parallel(Anti-Islanding)
Abnormal Power Flow
Restoration
51
V3Y
79
27475981
0/U
25
59
I
60
FL46
51
N
1
2 or 3
Grounded Primary
*
**
**
* = Use of 27N & 59N excludes 25 from use* = Use of 25 excludes 27N and 59N from use** = If using 27N, 59N or 25, VTs must be open delta
32
107
Small DER or Inverter Protection Application
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108
Fault Backfeed Removal
Damaging Conditions
Loss of Utility Parallel(Anti-Islanding)
Abnormal Power Flow
Restoration
Protection Element Usage
1
Time Overcurrent
Ground
Inverse TimeOvercurrent
Ground
50G 51G
M-7610A I-PAC
3I1, I2, I3, IN (3 I )
59Vx
27Vx
DirectionalOvercurrent
Ground
Overvoltage Undervoltage
V1, V2, V3 ,VN (3 V )
3
VX
67G
25
Sync Check
5 55
IG
0
0
60FL
VT FuseLoss
DirectionalTime Overcurrent • Phase • Neg. Seq. • Neutral
BreakerFailure
50 BF
DirectionalPower
32
Definite TimeOvercurrent • Phase • Neutral
Inverse TimeOvercurrent• Phase with Voltage Restraint• Phase with Voltage Control• Neutral
NegativeSequence
Overcurrent
45555
UnderPowerRelay
37PQN
6751
50 PN 46
Volts/Hz
24
Undervoltage• Phase• Neutral• Phase-to-Phase
PN
PP27
4
Negative Sequence
Overvoltage
4759
Overvoltage• Phase• Neutral• Phase-to-Phase
PN
PP
4
OU81
Frequency• Over• Under
4
59I
PeakOvervoltage
81R
Frequency Rate of Change
2
P-VRP-VC
N
79
UTILITY
52
I
52
G
1
1 or 3
LOAD BUS
Reconnect
Advanced Convergent Protection Application
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109
• Ethernet
– 7 Concurrent Sessions
• Protocols
– DNP 3.0
– IEC-61850
• Cyber Security
– NERC CIPS
– FIPS
– Radius
– IEEE Complaint Passwords
• Extended Logging
– Distributed Data Storage at PCC
• Power Quality Monitoring
– 128 samples per cycle
– Harmonics to the 63rd
– THD, TDD
– Sag/Swell/Flicker
• DME Oscillography Capture
• Utility/DER Interface Point
Convergent Attributes for Smart Grid
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• 2002 Survey- Grounded wye primary – 58%
- Delta primary – 9%
- Other – 33%
• 1995 Survey- Grounded wye primary – 33%
- Delta primary – 33%
- Other – 33%
Interconnection Transformer
IEEE Distribution Practices Survey – 1/02
110
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• No effect – 22%
• Revised feeder coordination – 39%
• Added directional ground relays – 25%
• Added direction phase relays – 22%
• Added supervisory control - 22%
• Revised switching procedures – 19%
Impact on Utility Protection
IEEE Distribution Practices Survey – 1/02
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Bidirectional Fault Currents: Coordination
• Use directional elements in substation protection, mid-line reclosers and DER
– Substation• Directionalize using 67 and 67N (instead of 50/51 and 50/51N)
• Trip toward DER (downstream) to avoid sympathy trips for out-of-section faults
• Trip toward Substation for remote breaker failure
– Reclosers• Directionalize using 67 and 67N (instead of 50/51 and 50/51N)
• Trip toward Substation for remote breaker failure
– DER• Directionalize using 67 and 67N (instead of 50/51 and 50/51N)
• Trip direction away from DER (upstream)
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50
51
50
N
51
N
50
51
50
N
51
N
50
51
50
N
51
N 50
51
50
N
51
N
50
51
50
N
51
N
50 5150
N
51
N
Radial Distribution
• Non-directional phase and ground overcurrent elements
12
3
113
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DG
6767
N
67
67
N
67
67
N
67
67
N
67
67
N
67
67
N
DER on System
• Directional phase and ground overcurrent elements
• Use voltage polarization
12
3
114
Directionalization toward DER helps prevent sympathy trips
from out-of-section faults
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DG
6767
N
67
67
N
67
67
N
67
67
N
67
67
N
67
67
N
Directionalization toward Substation providesremote breaker failure protection
• Directional phase and ground overcurrent elements• Use voltage polarization• All reverse looking elements trip slower than all forward
looking elements
1
23
4
115
DER on System
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• Revise reclosing practices – 50%
• Added voltage relays to supervise reclosing – 36%
• Extend 1st shot reclose time – 26%
• Added transfer trip – 20%
• Eliminate reclosing – 14%
• Added sync check – 6%
• Reduce reclose attempts – 6%
DER Impact on Utility Reclosing
IEEE Distribution Practices Survey – 1/02
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• If high-speed reclosing is employed, the DER interconnection protection must be faster!
• Clearing time includes protection operation and breaker opening
Utility Reclosing Issues:It is all about time……….
DER must trip from
utility in this interval
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• As DER penetration increases, the ability to “ride-though” transient faults on adjacent feeders and transmission is becoming more important
• IEEE 1547 has had an addendum (1547a-2014) that allows:
– “Loosening” of voltage and frequency limits to allow fault “ride-through”
– DER to actively control their reactive power output
• IEEE 1547 ”a” addresses ride-through by making it a utility choice to allow or disallow it
• Off-nominal voltage and frequency limits may be greatly widened, offering ride-through capability
• Impact: Changes for protection setpoints for all types of DER
IEEE 1547 Addendum: IEEE 1547a
It’s all about “Ride-Through”
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IEEE 1547 Addendum: IEEE 1547a
It’s all about “Ride-Through”
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IEEE 1547 Addendum: IEEE 1547a
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• If large amounts of DER are easily “shaken off” for transient out-of-section faults, voltage and power flow upset can occur in:
– Feeders
– Substations
– Transmission
• Fault ride-through capability makes the system more stable
– Distribution: Having large amounts of DER “shaken off” for transient events suddenly upsets loadflow and attendant voltage drops.
• Impacts include unnecessary LTC, regulator and capacitor control switching
• If amount of DER shaken off is large enough, voltage limits may be violated
– Transmission: Having large amounts of DER “shaken off” for transient events may upset loadflow into transmission impacting voltage, VAR flow and stability
IEEE 1547 Addendum: IEEE 1547a
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aBase voltages are the nominal system voltages stated in [ANSI C84.1] Table 1.
bDR ≤ 30kW, maximum clearing times; DR >30kW, default clearing times.
122
Present IEEE 1547 Trip values for Voltage (59, 27)
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Proposed IEEE 1547A Trip values for Voltage (59, 27)
123
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IEEE 1547 Addendum: IEEE 1547a
Voltage Ridethrough
Graph from “1547a and Rule 21, Smart Inverter Workshop,” June 21, 2013, SCE
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Example of Inverter P & Q Output Capability
Graph from Mar/Apr 2014 IEEE PES Magazine Article “Lab Tests” by Roland Brundlinger,
Thomas Straaser, Georg Lauss, Andy Hoke, Sudipta Chakraborty, Greg Martin, Benjamin Kropotkin,
Jay Johnson and Eric de Jong
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Proposed IEEE 1547A Trip values for Frequency (81-0, 81-U)
Default settings Ranges of adjustability(a)
Function Frequency
(Hz).
Clearing time
(s)
Frequency (Hz) Clearing time
(s)
UF1 57 0.16 56 – 60 0 – 10
UF2 59.5 20 56 – 60 0 – 300
Power reduction (b)
60.3 n/a 60 - 64 n/a
OF1 60.5 20 60 – 64 0 – 300
OF2 62 0.16 60 - 64 0 - 10
(a) Unless otherwise specified, default ranges of adjustability shall be as stated.
(b) When used, the DR power reduction function settings shall be as mutually
agreed to by the area EPS and DR operators.
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IEEE 1547 Addendum: IEEE 1547a
Frequency Ridethrough
Graph from “1547a and Rule 21, Smart Inverter Workshop,” June 21, 2013, SCE
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1547A: Active Voltage/VAR Control
• Coordination with and approval of, the area EPS and DR operators, shall be required for the DR to actively participate to regulate the voltage by changes of real and reactive power.
• The DR shall not cause the Area EPS service voltage at other Local EPSs to go outside the requirements of ANSI C84.1-2006 1 1995, Range A.
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Controls incorporate setpoints, deadbands,
ramp timers, etc.
Example DER Control Interface
Power (W) and
VAR Control
Contacts for
Operation Modes
Power (W) Control
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• Uses droop characteristic
• Based on voltage sensing at PCC or PI
• If inverter based, a “Smart” Inverter
130
DER Actively Controlling VAR
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DER Interconnection Relay as the Utility Interface Point
131
131
DERInterconnectionProtective Relay
DER Control System(MODBUS Master)
UtilitySCADA
(Radio,Fiberoptic,Hardwire
from RTU)
Commands
Data
DNP TCP/IPMODBUS TCP/IP
Embedded cybersecurity
per NERC CIP V5 and
IEEE 1686
RUN/STOP
CONTROL Var/Unity PF
Operational,PQ, Metering,DFR, SOE
Commands
Status
RUN/STOP
CONTROL Var/Unity PF
Operational Status
FACILITY with DER
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DER Variability: V/VAR Issues
Coping Methods for Fast DER Variability: Using DMS and Controllable Assets
– “Ramp Rate” or “Capacity Fill” Dispatch• Conventional “fast start” distributed generation to supply
real/reactive power
• Distributed synchronous condensers to supply/sink reactive power
• Storage/conversion to supply/sink real power
• Storage/conversion to supply reactive power
– May be accomplished by DSM or local control from nearby large DER variable asset
• Starting/Stopping
• Direct setpoint control or initiating setting group changes
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Constant Capacityfrom “Capacity Fill”
Assets
• Not Firmed
• Firmed
Time
Ou
tpu
t
Time
Ou
tpu
t= Variable DR Output
= Output Firmed
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Ramped Capacityfrom
“Capacity Fill” Assets
Time
Ou
tpu
t
Time
Ou
tpu
t= Variable DR Output
= Output Firmed
134
• Not Firmed
• Firmed
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Storage Applications
Utility Distribution Substation Storagefor Demand Response Use
AC/DC
FEEDERS
UTILITY
115kV
13.8kV
Storage
13.8kV 480V
SCADA
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Storage Applications
AC/DC
UTILITY
13.8kV
Storage
480V
SCADA
AC/DC
Storage
AC/DC
13.8kV
Storage
480V
SCADA
AC/DC
Storage
Adjust Storage Capacity forScalable Demand and Duration
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Storage Placement
DER
Highly Variable DER
DER
Storage
(Dispatchable)
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GenTranSubTranDistUtilization
DER Today
DG
DG
DG
Bulk
Generation
Transmission
Sub
Transmission
Distribution
Substation
Substation
With DG
Distribution
With DG
Distribution
Substation
Distribution
Substation
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Bi-Directional Powerflows
DER Tomorrow
DG
DG
DG
DG
DG
DG
DG
DG
DG
DG
DG
DG
Bulk
Generation
Transmission
Sub
Transmission
Distribution
Substation
Distribution
With DG
Distribution
With DG
Distribution
With DG
Distribution
Substation
Distribution
Substation
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• Enables Green Power Interconnected at the Distribution Level
• Smart Grids Must Overcome Many Limitations:
- Loss of Protective System Coordination
- Voltage Control (reactive support)
- Restoration Problems
- Capacity/Load balance
- Green power variability and non-dispatchability
• IEEE 1547 is presently too restrictive for large amounts of DER
– Issue with high amount of DER capacity being lost at once for disturbance or other recoverable event
– 1547A helps address that
Smart Grid and DER
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University Campus Microgrid
Creation of DER and load islands
for economic, power quality or
power security reasons
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Smart Grids ̶ Microgrids
Just as a single DER is synced to the utility, groups of DER as a Microgrid
are synced to the utility after operating islanded
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Smart Grid Application of DER: Microgrids
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• Voltage control with high levels of DER require some type of adaptive watt/VAR control
• Advanced control will be needed on DER, voltage regulating and reactive support (capacitors) elements
• Normal power from Utility to load– Utility strong source
• DER may backfeed– Typically a weaker source
• What to do with power reversal from sectionalizing?
• What to do with power reversal from DER?
• What to do about LDC with DER influencing?
High Penetration of DER on Distribution Systems
Will Require Smart Grid Technology to Control System Voltage
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Acronyms
• CAPC = Capacitor Control
• REGC = Regulator Control
• LTCC = Load Tapchanging Transformer Control
• RPF = Reverse Power Flow
• DA = Distribution Automation
• EMS = Energy Management System
• DMS = Distribution Management System
• EOL = End of Line, as in EOL Voltage
• DERP = DER Protection
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Communications to REGC
• Pros:– REGC does as commanded, using analog setpoint or
profile group • Using “Heartbeat,” control knows if communications is lost
– Go to “Plan B;” operation mode with comms
• Cons:– Costs of communications infrastructure– Requires DMS with either modeling or feedback to
properly execute commands• Feedback requires recloser position status,
EOL voltage sensing• Modeling requires creation, updating and upkeep
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Use of Powerflow Direction Change by REGC
• Pros:
– Communications not needed to detect RPF situation
– Control is autonomous (no DMS/SCADA required)
– Autodetermination Mode allows dynamic source stiffness determination and proper regulation based on the dynamic conditions
• Cons:
– Settings may require change if feeder changes over time
• Ex., LDC-RX
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REGC: Reverse Power Method Discussion
• Regulate Forward (Ignore) – continues unit action as though forward power flow continued to exist. – Use where weak DER without active voltage control was causing RPF
with little expected line drop
• Block – inhibits automatic operation, leaving regulator on present tap. – Use where source of RPF is not expected to change voltage on RPF
side of REG
• Return to Neutral – drives tap position to neutral and then stops– Use where small unpredictable change in voltage may be
encountered on RPF side of REG
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REGC: Reverse Power Method Discussion
• Regulate Reverse – (calculated voltage or measured voltage) regulates according to reverse power settings.– Use where RPF side of REG is a strong source (many MWs of DER or a
feeder reconfiguration) and regulate voltage on the non-RPF side of the REG
• Change in directional of feeder source by DA
• Regulate Reverse (measured) – allows the control to switch its voltage sensing input from a load side VT to a source side VT if one is available and operate in Regulate Reverse Mode using that input.– Use where RPF side of REG is a strong source (DER or feeder) and
regulate voltage on the non-RPF side of the REG
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REGC: Reverse Power Method Discussion
• Distributed Generation – remains forward regulating and allows alternate LDC (R and X) or LDC (Z) values to be applied to control when reverse power is detected. – Use where RPF side is from a moderately stiff source to change
LDC/LDZ while still regulating forward
• Auto Determination – allows control to use "Smart Reverse Power" feature to choose applicable reverse power mode, either DG/DER or Regulate Reverse. – Will dynamically determine stiff source and selectively use either:Forward Regulation in DG/DER
New voltage band center, bandwidth Use of VAR-Bias or LDC RX or Z,
Reverse Regulation New voltage band center, bandwidth Use of VAR-Bias or LDC RX or Z,
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Improved Volt/VAR Coordination between DERs/CAPCs and REGCs/LTCCs
• REGCs and/or LTCCs:
– Typically use LDC-RX or LDC-Z
– No direct feedback mechanism using LDC-RX or LDC-Z for PF or VAR control
• Voltage-control based CAPCs:
– VAR measurement not available
– Switch on voltage• Less expensive than VAR control and sensors
• May be used at end of line
How do we coordinate to obtain optimum VVO/IVVC?
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Use of VAR-Bias to Coordinate DERs/CAPs with REGs and LTCs
• REGC and LTCC use information on VAR flow
– Is the flow out to the line (load)?
– Is the flow into the source?
• The above indicate if you are or are not at/near unity power factor
• VAR flow into the REG or LTC indicate the voltage downline is higher than the voltage at the REG or LTC
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Use of VAR-Bias to Coordinate DERs/CAPs with REGs and LTCs
• Use a“VAR-Bias” characteristic of to change the response of the REGC or LTCC
• The VAR-Bias characteristic can be tailored for normal operation (non-CVR) and CVR operation
– Normal (non-CVR) Operation: Negative VAR Bias
– CVR Operation: Positive VAR Bias
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VAR Bias (LTCC and REGC)• In the Negative Mode (Normal), as:
– VARs flow toward source (leading VAR at LTCC/REGC)• Voltage bandcenter rises, causing voltage-controlled:
DERs to decrease VAR output
CAPCs to switch banks off, stopping VAR output
– VARs flow toward load (lagging VAR at LTCC/REGC)• Voltage bandcenter lowers, causing voltage-controlled:
DERs to decrease VAR output
CAPCs to switch banks on, outputting VAR
154
This action tends to create unity power factor and flatten voltage profile
Normal, Non-CVR ApplicationNegative Linear VAR Bias
Leading VARsLagging VARs120V
121V
118V
117V
116V
122V
123V
124V
119V
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VAR Bias (LTCC and RECC)• In the Positive Mode (CVR), as:
155
This action tends to allow deep voltage reduction at the feeder origin as end of line voltage is higher than at REG or LTC output
Leading VARsLagging VARs120V
121V
118V
117V
116V
122V
123V
124V
119V
CVR ApplicationPositive Linear VAR Bias
155
• VARs flow toward source (leading VAR at LTCC/REGC)
– Voltage bandcenter lowers, causing voltage-controlled:DERs to decrease VAR output
CAPCs to switch banks on, outputting VAR
• VARs flow toward load (lagging VAR at LTCC/REGC)
– Voltage bandcenter rises, causing voltage-controlled:DERs to decrease VAR output
CAPCs to switch banks off, stopping VAR output
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126
120
114
0 1 2 3 4 5 6 7 8
Positive VAR-Bias Method
Traditional VVO; CVR
Distance (%)
Vo
lts
(sec
on
da
ry)
Traditional VVO; non-CVR
No VVO
CVR: REGs/LTC with DERs/CAPs
• For CVR, forcing overVAr on feeder, causes end of line voltage to rise
• You can have a deeper voltage reduction at the beginning of the line where most of the load is located
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Normal Operation:Negative VAR-Bias
• Voltage near center of band
• Near unity power factor
157
52
Closed
Opened
Closed
Opened
Closed
Opened
Closed
Opened
121V
118V
117V
116V
122V
123V
124V
119V
120V
NORMAL OPERATION (non-CVR)
DERVArOUT
VArIN
VLOW VHIGH
DERVArOUT
VArIN
VLOW VHIGH
157
Normal, Non-CVR ApplicationNegative Linear VAR Bias
Leading VARsLagging VARs120V
121V
118V
117V
116V
122V
123V
124V
119V
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Normal Operation:Negative VAR-Bias
• Inductive load increases, pf lags, voltage decreases.
• REG bandcenter lowers.
• Caps come on, DER outputs VAr
• Voltage and VArnormalize
158
52
Closed
Opened
Closed
Opened
Closed
Opened
Closed
Opened
121V
118V
117V
116V
122V
123V
124V
119V
120V
NORMAL OPERATION (non-CVR)
DERVArOUT
VArIN
VLOW VHIGH
DERVArOUT
VArIN
VLOW VHIGH
158
Normal, Non-CVR ApplicationNegative Linear VAR Bias
Leading VARsLagging VARs120V
121V
118V
117V
116V
122V
123V
124V
119V
2
1
3
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Normal Operation:Negative VAR-Bias
• Inductive load decreases, pfleads, voltage rises.
• REG bandcenter rises.
• Caps switch off, DER consumes VAr
• Voltage and VArnormalize
159
52
Closed
Opened
Closed
Opened
Closed
Opened
Closed
Opened
121V
118V
117V
116V
122V
123V
124V
119V
120V
NORMAL OPERATION (non-CVR)
DERVArOUT
VArIN
VLOW VHIGH
DERVArOUT
VArIN
VLOW VHIGH
159
1
Normal, Non-CVR ApplicationNegative Linear VAR Bias
Leading VARsLagging VARs120V
121V
118V
117V
116V
122V
123V
124V
119V
3
2
1
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Normal Operation:Negative VAR-Bias
• Resistive load decreases, pfremains the same, voltage rises
• REG taps down, voltage normalizes
• CAPs and DER do not change VAr output
160
52
Closed
Opened
Closed
Opened
Closed
Opened
Closed
Opened
121V
118V
117V
116V
122V
123V
124V
119V
120V
NORMAL OPERATION (non-CVR)
1
2
3
DERVArOUT
VArIN
VLOW VHIGH
DERVArOUT
VArIN
VLOW VHIGH
160
1
Normal, Non-CVR ApplicationNegative Linear VAR Bias
Leading VARsLagging VARs120V
121V
118V
117V
116V
122V
123V
124V
119V
3
2
1
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Normal Operation:Negative VAR-Bias
• Resistive load increases, pf leads, voltage decreases
• REG taps up, voltage normalizes
• CAPs and DER do not change VAroutput
161
52
Closed
Opened
Closed
Opened
Closed
Opened
Closed
Opened
121V
118V
117V
116V
122V
123V
124V
119V
120V
NORMAL OPERATION (non-CVR)
1
23
DERVArOUT
VArIN
VLOW VHIGH
DERVArOUT
VArIN
VLOW VHIGH
161
1
Normal, Non-CVR ApplicationNegative Linear VAR Bias
Leading VARsLagging VARs120V
121V
118V
117V
116V
122V
123V
124V
119V 3
2
1
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Voltage Bandcenter and Bandwidth: LTC/REG, CAP, DER
• CAPS and DER furthest away from source have faster time delay than upline similar devices
162
162
52
Closed
Opened
Closed
Opened
Closed
Opened
Closed
Opened
DERVArOUT
VArIN
VLOW VHIGH
DERVArOUT
VArIN
VLOW VHIGH
Normal, Non-CVR ApplicationNegative Linear VAR Bias
Leading VARsLagging VARs120V
121V
118V
117V
116V
122V
123V
124V
119V
REGCAP
DER
REG
CAP
DER
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Before CVR Operation:Negative VAR-Bias
• Normal load, voltage near center bandcenter
• Near unity power factor
163
52
Closed
Opened
Closed
Opened
Closed
Opened
Closed
Opened
121V
118V
117V
116V
122V
123V
124V
119V
120V
NORMAL OPERATION (non-CVR)
DERVArOUT
VArIN
VLOW VHIGH
DERVArOUT
VArIN
VLOW VHIGH
163
Normal, Non-CVR ApplicationNegative Linear VAR Bias
Leading VARsLagging VARs120V
121V
118V
117V
116V
122V
123V
124V
119V
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CVR Operation:Positive VAR-Bias
164
52
Closed
Opened
Closed
Opened
Closed
Opened
Closed
Opened
121V
118V
117V
116V
122V
123V
124V
119V
120V
CVR OPERATION
1
2
DERVArOUT
VArIN
VLOW VHIGH
DERVArOUT
VArIN
VLOW VHIGH
• REG forces voltage lower
• CAPs begin to switch on and DER outputs VAr
164
Leading VARsLagging VARs120V
121V
118V
117V
116V
122V
123V
124V
119V
CVR ApplicationPositive Linear VAR Bias
2
1
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CVR Operation:Positive VAR-Bias
165
52
Closed
Opened
Closed
Opened
Closed
Opened
Closed
Opened
121V
118V
117V
116V
122V
123V
124V
119V
120V
CVR OPERATION
1
2
DERVArOUT
VArIN
VLOW VHIGH
DERVArOUT
VArIN
VLOW VHIGH
• VARs begin to lead.
• REG forces voltage even lower.
• More CAPs switch on and DER outputs VAr
165
Leading VARsLagging VARs120V
121V
118V
117V
116V
122V
123V
124V
119V
CVR ApplicationPositive Linear VAR Bias
2
1
3
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DER Interconnection Relay as a Utility Access Point
Embedded cybersecurity is key as DER is not in a substation
166
166
DERInterconnectionProtective Relay
DER Control System(MODBUS Master)
UtilitySCADA
(Radio,Fiberoptic,Hardwire
from RTU)
Commands
Data
DNP TCP/IPMODBUS TCP/IP
Embedded cybersecurity
per NERC CIP V5 and
IEEE 1686
RUN/STOP
CONTROL Var/Unity PF
Operational,PQ, Metering,DFR, SOE
Commands
Status
RUN/STOP
CONTROL Var/Unity PF
Operational Status
FACILITY with DER
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CAPs and DER• As power flows and assumed reactive voltage drops can
change as DER proliferates, consider changing fixed CAPs to switched to avoid overvoltage (from excessive VAR support) under high DER output conditions
• Consider active voltage (VAR) control of DER as proliferation increases
167
VRef
(V2,Q2)V1 V4
Voltage (p.u.)
Re
acti
ve P
ow
er
(% o
f St
ate
d C
apab
ility
)
Inje
ctin
g (o
ver-
exci
ted
)
Dead Band
VL: Voltage Lower Limit for DER Continuous operationVH: Voltage Upper Limit for DER Continuous operation
Ab
sorb
ing
(un
der
-exc
ited
) VL VH
0(V3,Q3)
(V1,Q1)
(V4,Q4)
167
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• Coping Methods for Fast DER Variability:• Consider regulators change taps sequentially ensure
voltage on feeder is quickly restored
• Using sequential over non-sequential operation shortens time to restore voltage
• Consider substation caps be controlled on VAR/pf with high voltage and low voltage override
• Consider line caps be controlled on using voltage
168
Traditional Volt/VAR Elements
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Effects of Reverse Power from DER on
Line Drop Compensation (LDC)
DER
If RPF is large enough to cause reverse power flow, the REGC will operate to lower voltage
Using to “Distributed Generation Mode” changes the polarity of the LDC (and factors if desired) under reverse power conditions to prevent this from occurring
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DER
DER
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Effect of DER on Regulator
Line Drop Compensation (LDC)
LDC is reduced when DER contributes power
More DER power = less load = less LDC = voltage setpoint lowers
If DER is in PF mode, it maintains a VAR output to not import or export any VARs, so it cannot control voltage
Voltage profile can change depending on:
o R and XL of the line
o Reactive compensation to counter the XL
o Power output of the DER
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DER
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DER
Effect of DER on Regulator
Line Drop Compensation (LDC)
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Assume line R and XLdrops are low
Assume REGC in DG Mode
Assume variable DER power output per the graphic
Line voltage assumes “smile” profile
Curve of smile (flat or very arced) not the severeo Arc more severe with
higher R and XL, more DER output
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Effect of DER on Regulator
Line Drop Compensation (LDC)
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DER
Vo
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DER
Assume line R and XLdrops are low
Assume REGC in DG Mode
Assume variable DER power output per the graphic
Line voltage assumes “smile” profile
Curve of smile (flat or very arced) not the severeo Arc more severe with
higher R and XL, more DER output
![Page 173: Distributed Energy Resources€¦ · Before joining Beckwith Electric, Wayne performed in application, sales and marketing management capacities with PowerSecure, General Electric,](https://reader034.vdocument.in/reader034/viewer/2022050101/5f3ff0684772cf7806490006/html5/thumbnails/173.jpg)
DER
SCADADNP 3.0
EOL
Use of an End-of-Line Monitor (EOL) to
Transmit Voltage Value to Regulator
With EOL feedback, you are not modeling the EOL voltage. You measure it.
EOL monitoring, working with a regulator, can handle dynamic situations and multiple sources to adjust line voltage
Works when DG Mode where unfavorable line/DER output characteristics existo Smile arc too severe or DER EOL voltage too high
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DER and REGCs/LTCCs
• Use of VAR-Bias avoids LDC issues as DER power output increases
• If DER can control VAr output, by coordinating DER voltage output setting with REGC/LTCC bandcenter will keep voltage at the setting
– VAR-Bias reacts to VAR to maintain unity PF
– REGC/LTCC, CAPs and active DERs maintain voltage
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DER
SCADADNP 3.0
EOL
Use of an End-of-Line Monitor (EOL) to
Transmit Voltage Value to Regulator
With EOL feedback, you are not modeling the EOL voltage. You measure it.
EOL monitoring, working with a regulator, can handle dynamic situations and multiple sources to adjust line voltage
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Communications to CAPC
• Pros:– CAPC does as commanded, using analog setpoint
or profile group • Using “Heartbeat,” control knows if communications is lost
– Go to “Plan B;” operation mode with comms
• Cons:– Costs of communications infrastructure– Requires DMS with either modeling or feedback to
properly execute commands• Feedback requires recloser position status, EOL voltage
sensing; may require VAR sensing at substation• Modeling requires creation, updating and upkeep
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Use of Autoadaptive Methodology by CAPC
• CAPCs, using Autoadaptive delta-voltage based control, alter their timing to properly switch per control’s new location from source on feeder (furthest from source switches first).
– This implementation maintains better multi-capacitor control action on a given feeder regardless of configuration.
– Uses delta-V observed on switching to change timing
– Increasing delta-V = further distance (more impedance) from source
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Use of Autoadaptive Methodology by CAPC
• Pros:
– Communications not needed to retune CAPC time settings
– Control is autonomous (no DMS/SCADA required)
– Upon another reconfiguration, CAPC will learn new time setting depending on its position form the source
• Cons:
– None
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• Properly designed interconnection protection addresses concerns of both DER owners and utility
• State and national regulators, and the IEEE, continue to create and update interconnection guidelines
• Interconnection transformer configuration plays a pivotal role in interconnection protection
Summary
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• Restoration practices need to be part of the overall interconnection protection
• Smart Grid Solutions will be needed to meet high penetrations of DER
• Protective Relays for DER interconnection protection may find greater application in inverter-based systems due to the adoption of IEEE 1547A
Summary
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Recommended Reading
• IEEE 1547 Series of Standards for Interconnecting Distributed Resources with Electric Power Systems, http://grouper.ieee.org/groups/scc21/
• On-Site Power Generation, by EGSA, ISBN# 0-9625949-4-6
• Intertie Protection of Consumer-Owned Sources of Generation 3 MVA or Less, IEEE PSRC WG Report
• Evaluation of Islanding Detection Methods for Utility-Interactive Inverters in Photovoltaic Systems, Sandia National Laboratories, Ward Bower and Michael Ropp
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• “Update on the Current Status of DG Interconnection Protection―What 1547 Doesn’t Tell You,” Charles Mozina, Beckwith Electric, presented at 2003 Western Protective Relay Conference on Beckwith website
• Distribution Line Protection Practices Industry Survey Results, Dec. 2002, IEEE PSRC Working Group Report
• Combined Heating, Cooling & Power Handbook, Marcel Dekker, by Neil Petchers, ISBN# 0-88173-349-0
• “Benefits of Using Customer Distributed Generation for Demand Response,” W. Hartmann, P. Kalv; Distributech2011
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Recommended Reading
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• “How to Nuisance Trip Distributed Generation,” W. Hartmann, presented at Power System Conference, Clemson University, Clemson, SC, March 2003
• “Relay Performance in DG Islands,” Ferro, Gish, Wagner and Jones, IEEE Transactions on Power Delivery, January 1989
• Effect of Distribution Automation on Protective Relaying, 2012, IEEE PSRC Working Group Report
• 1547a and Rule 21, Smart Inverter Workshop, June 21, 2013, SCE
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Recommended Reading
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DistributedEnergy
Resources
Operation, Protection & Control
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161005_CNY_2 Hr
November 7, 2016
Syracuse, NY