PSEG-LONG ISLAND SMART GRID SMALL GENERATOR
INTERCONNECTION SCREENING CRITERIA FOR
OPERATING IN PARALLEL WITH LIPA’S DISTRIBUTION
SYSTEM
PSEG-LI SGSGIP DG Screening Criteria 5-29-14
Table of Contents
I.
INTRODUCTION ...............................................................................................................................................3
II.
GENERAL REQUIREMENTS .........................................................................................................................4
III.
CONTROL AND PROTECTION REQUIREMENTS ....................................................................................6
IV.
NON-INVERTER INTERFACED DG SCREENING CRITERIA ............................................................... 13
A.
B.
C.
D.
E.
F.
G.
H.
I.
V.
VOLTAGE ....................................................................................................................................................... 13
FLICKER ......................................................................................................................................................... 13
VOLTAGE DIP ................................................................................................................................................ 13
FREQUENCY .................................................................................................................................................. 13
HARMONICS ................................................................................................................................................... 14
POWER FACTOR ............................................................................................................................................ 14
EXTERNAL FAULT AND LINE CLEARING ........................................................................................................ 14
DC INJECTION ............................................................................................................................................... 15
UNINTENTIONAL ISLANDING .......................................................................................................................... 15
INVERTER-INTERFACED DG SCREENING CRITERIA ......................................................................... 16
A.
B.
C.
D.
E.
1.
2.
3.
F.
G.
1.
2.
3.
4.
H.
1.
2.
3.
I.
J.
K.
INTRODUCTION .............................................................................................................................................. 16
KEY ASSUMPTIONS ....................................................................................................................................... 16
LIPA DG INTERCONNECTION POLICIES ....................................................................................................... 16
INVERTER-INTERFACED DG IMPACTS........................................................................................................... 17
STEADY-STATE VOLTAGE DEVIATIONS ........................................................................................................ 17
Primary Feeder Voltage Profile ............................................................................................................ 17
Steady-State Primary Voltage Criteria ................................................................................................ 20
Secondary Voltages .............................................................................................................................. 22
CONTINGENCY VOLTAGE DECREASE ON SIMULTANEOUS DG TRIP ............................................................ 25
INADVERTENT ISLANDING AND TEMPORARY OVERVOLTAGE ....................................................................... 26
Temporary Overvoltages ...................................................................................................................... 26
Islanding TOV Criteria ........................................................................................................................... 28
Out-of-Phase Reclosing ........................................................................................................................ 31
Out-of-Phase Reclosing Criteria .......................................................................................................... 32
POWER QUALITY ........................................................................................................................................... 33
Flicker ...................................................................................................................................................... 33
Flicker Screening ................................................................................................................................... 36
Harmonics ............................................................................................................................................... 37
SYSTEM LOADING ......................................................................................................................................... 38
FAULT CURRENT CONTRIBUTION AND PROTECTION .................................................................................... 38
SUMMARY OF RECOMMENDED SCREENS ..................................................................................................... 39
VI.
MAINTENANCE AND OPERATING REQUIREMENTS........................................................................... 43
VII.
CLASSIFICATION OF DG SYSTEM GENERATOR INSTALLATIONS ........................................... 45
VIII.
APPENDIX .................................................................................................................................................. 46
APPENDIX A ............................................................................................................................................................ 46
APPENDIX B ............................................................................................................................................................ 51
APPENDIX C ............................................................................................................................................................ 52
APPENDIX D ............................................................................................................................................................ 53
APPENDIX E ............................................................................................................................................................. 54
APPENDIX F ............................................................................................................................................................. 55
PSEG-LI SGSGIP DG Screening Criteria 5-29-14
I. Introduction
This document provides additional technical requirements defined in the Smart Grid Small
Generator Interconnection Procedures (SGSGIP)for all interconnection Distribution Generation
(DG) system for operating in parallel with LIPA’s distribution system. This document provides
details for the minimum control and protection requirements for safe and effective operation of
Distributed Generation Equipment, interconnecting with the Long Island Power Authority (LIPA)
radial distribution system. The term “Distributed Generation Equipment” (DG System) refers to
generating systems owned by individuals, companies, or agencies, other than PSEG Long Island,
within the PSEG Long Island service area. It is emphasized that these requirements are general
and may not cover all details in specific cases.
The customer must be Primary Metered for DG system greater than 1.5 MVA. Secondary Meter for
DG system greater than 300 kVA will be permitted up to 1.5 MVA on a case by case basis only.
Primary Metering requirements are defined elsewhere. Interconnections shall not be made to
primary feeders supplying secondary network systems. Generator size limitations are
outlined in Section VII - Classification of DG System Generator Installations.
PSEG Long Island will evaluate applications for interconnections to looped radial primary systems
(fused loops). If approved, these interconnections shall be made through a LIPA installed and
owned fused disconnect switch installed on the primary side of the customer owned transformer.
The installation of the fused switch shall be at the DG System’s expense.
Interconnection requirements as well as specific electrical requirements for parallel operation with
the LIPA system are provided for substation and distribution interconnections of synchronous
generators, induction generators, and D.C. generators with inverters.
Application forms from SGSGIP shall be used by the DG System and PSEG Long Island to
document the specific characteristics of the installation. This application shall be coordinated by
PSEG Long Island's Power Asset Management group.
Responsibility for protection of the DG System against possible damage resulting from parallel
operation with the LIPA Distribution System lies solely with the DG System.
The LIPA transmission lines have automatic instantaneous reclosing and distribution
feeders have automatic instantaneous and time delay reclosing with a dead time as short as
12 cycles and as long as 30 seconds. It is the DG System's responsibility to protect its
equipment from being reconnected out-of-synchronism with the LIPA system after
automatic reclosing of a LIPA circuit breaker. The DG System connected to the distribution
system can also be affected by a transmission line breaker reclosure. It is the DG System’s
responsibility to protect its equipment from these reclosures. The DG System shall provide
high speed protective relaying to remove its equipment from the utility circuit prior to the
automatic reclosure. This requirement cannot be met by direct transfer trip equipment.
3
II. General Requirements
Each DG System operating in parallel with the LIPA system shall have its interconnection control
and protection designs reviewed and accepted by PSEG Long Island.
The specific design requirements of the protection system depend on the generator type, size,
and other site specific considerations. The DG System shall meet PSEG Long Island's
Specifications and Requirements for Electric Installations (Red Book), latest revision, all
applicable sections of the NEC and all local and municipal codes.
It is the intent of these Interconnection Requirements that interconnected DG Systems meet
operational requirements outlined in IEEE Standard P1547 and all future companion documents to
P1547, as they may be adopted by the IEEE Standards Board in the future. PSEG Long Island
reserves the right to impose site specific interconnection requirements on a case by case basis.
To eliminate unnecessary costs and delays, a DG System interconnection one line drawing should
be submitted to PSEG Long Island for acceptance prior to the commencement of construction and
ordering of equipment. Seven (7) copies of the following must be submitted before a final
acceptance can be given to the DG System's design:
A.
DG System Interconnection one-line drawing.
B.
Relay Functional diagram showing all current (CT) and potential transformer (PT)
circuits, relay connections, and protective control circuits. All interconnections with
LIPA's circuits should be clearly labeled (See Appendix F for an example of an
acceptable relay functional).
C.
Three line AC schematic diagrams of transformers and bus relay protection.
D.
Interconnection breaker AC and DC schematics.
E.
Protective relay equipment list including manufacturer model number, relay ranges,
manufacturer's bulletins, curves and proposed settings.
F.
Generator, transformer, and breaker nameplate information including generator
transient, generator harmonic characteristics (non type tested generators),
subtransient, and synchronous impedances and transformer positive and zero
sequence impedances (Appendix D).
G.
Producer generator protection scheme.
H.
Interconnection breaker speed curve.
I.
All drawings should incorporate PSEG Long Island's requirements for the name and
number description of major equipment (switches, breakers, etc.).
No installation of equipment can be completed without written acceptance from PSEG Long Island.
If the DG System is installed without prior written acceptance of the equipment by PSEG Long
Island, it shall be done at the DG system’s own risk. The DG System shall be solely responsible
for all costs associated with the replacement of any equipment that has not been accepted by
PSEG Long Island. Final acceptance of the interconnection by PSEG Long Island will be
contingent upon PSEG Long Island's acceptance of all of the DG System's interconnection
equipment.
4
If the DG System makes changes in the design of the project, any previous information furnished
by PSEG Long Island shall be subject to review and possible changes.
At the completion of construction, functional tests of all protective equipment shall be performed by
a qualified testing company acceptable to PSEG Long Island, and PSEG Long Island reserves the
right to witness such tests. If these tests are successful, and the protective relay settings have
been correctly applied, PSEG Long Island shall permit the interconnection to be energized.
To accomplish the interconnection and to provide for continuing operations in a safe, economical
and efficient manner, PSEG Long Island shall prepare and deliver Operating Instructions to the DG
System prior to interconnecting the facility. The Operating Instructions shall include but not be
limited to defining requirements for:
A. Maintaining proper voltage and frequency and for putting into effect voltage changes as
required from time to time.
B. Phasing and synchronizing the facility and LIPA's system.
C. Taking feeders out of service for maintenance during a system emergency or system
pre-emergency conditions and restoring such feeders to service.
D. Controlling the flow of real and reactive power.
E. Periodic maintenance of the interconnection circuit breaker and related facilities.
F. Procedure for communication between electrical operations personnel of the DG
System and PSEG Long Island.
The DG System shall also ensure the availability of a dedicated telephone handset, for use by
PSEG Long Island personnel during testing and maintenance of the DG System's equipment.
The DG System shall be required to have a qualified testing company, acceptable to PSEG Long
Island, perform maintenance, trip tests, and recalibration tests on its protective relaying devices
once every two (2) years. A copy of the test results shall be sent to PSEG Long Island for review,
comment, and acceptance, no later than five (5) working days after completion of tests.
All other DG systems including but not limited to rotating machines, non-inverter interfaced
DG system shall follow the Criteria outlined in Section IV.
All inverter interfaced DG system shall be screened as per “Inverter-Interfaced DG
Screening Criteria” (outlined in Section V).
This document is developed for PSEG Long Island to provide a process to review inverter
interfaced DG interconnection requests to determine the impacts and identify specific mitigation
measures necessary to interconnect the DG. These screening criteria will determine whether an
inverter based DG interconnection should be fast tracked or if the project requires further
engineering study.
5
III. Control and Protection Requirements
The inverter interfaced DG system passing the “Inverter-Interfaced DG Screening
Criteria” may not need following engineering studies performed.
A.
Engineering Studies
Engineering studies shall be performed by PSEG Long Island to determine the exact
electrical configuration of the interconnection installation and to identify any required
additions, changes, or modifications to the LIPA system. Major equipment requirements
such as circuit breakers and special protective relaying shall also be studied. Items
requiring investigation are as follows:
B.
1.
Equipment short circuit duty.
2.
Feeder breaker relay protection coordination due to in-feed for three phase
and line to ground faults.
3.
Branch fusing coordination due to fault current in-feed from DG System's
equipment.
4.
Breaker Failure requirements.
5.
Deadline operating restraints.
6.
VAR requirements.
7.
MVA limitations of generation because of location on the LIPA feeder.
8.
Protective relay coordination for three phase and line to ground faults on the
LIPA system and the DG System's generator installation.
9.
Protective Relay Alarm Breaker Trip (required for DG Systems utilizing only
one microprocessor relay).
Equipment Requirements
The following requirements apply to the interconnection of equipment of all generators
operating in parallel with the LIPA distribution system:
1.
All additions or changes required to protective relay and control equipment
on the LIPA system shall be installed by PSEG Long Island at the DG
System's expense. All additions or changes to relay and control equipment
required at the point of interconnection shall be paid for and installed by the
DG System.
2.
The DG System shall be solely responsible for synchronizing its
generator(s) with the LIPA system.
6
3.
The DG Systems may provide a primary voltage interconnection breaker or
secondary voltage breaker based on the total installed generator nameplate
kVA rating. The breaker shall be located in the DG System's substation. If
the interconnection breaker is a switchgear breaker, it shall be a drawout
type with provisions for installing a ground and test device supplied by the
DG system.
4.
The interconnection breaker shall be capable of withstanding 220% of the
interconnection breaker rated operating voltage.
5.
For interconnection breakers rated at 480 Volts or less operating voltage the
breaker shall be rated to withstand the greater of 220% of the operating
voltage or two times the rated operating voltage of the interconnection
breaker plus one thousand (1000) volts.
6.
An isolation disconnect switch (Utility Disconnect Switch) that is readily
accessible to PSEG Long Island at all times located within 10 feet of the
PSEG Long Island metering point or within 10 feet of the LIPA service
entrance, lockable with a 3/8 inch shank LIPA lock, visible-break and load
break rated shall be installed to isolate the generator from the LIPA system.
If the breaker is a drawout type and the DG System provides a ground and
test device acceptable to PSEG Long Island, PSEG Long Island will
evaluate allowing the DG System to omit the isolation disconnect switch.
DG Systems may be isolated from the LIPA system by means of an isolating
transformer. If this option is selected, the DG System shall have a wye
grounded/delta or a wye grounded/delta/wye transformer with the wye
grounded winding configuration on the LIPA side. See Appendix B for the
technical explanation of this requirement. A ground fault current limiting
neutral reactor shall be installed if required by LIPA on non-dedicated feeder
installations.
7.
8.
The DG system can opt not to use the wye-grounded (utility side)/delta (DG
side) isolation transformer if all of the following conditions are met:
a) The primary connected transformer must be a wye-grounded/wyegrounded transformer, and the generator must be effectively grounded.
The generator neutral reactor is normally used to limit ground fault
current and protect the generator windings. The generator neutral
reactor must be sized such that it both prevents overvoltages and allows
enough ground fault current to be detected by the DG System’s relaying
for faults on the LIPA distribution feeder.
b) The DG System must provide protective relaying that detects
faults on the LIPA system, including ground faults.
c) The DG System must meet the harmonic requirements of the
interconnect guide and test data supporting this is provided.
9.
A DG System with a total connected primary and/or secondary interconnect
generator nameplate rating of greater than 1000 kVA shall require a SCADA
(Supervisory Control and Data Acquisition) system RTU (Remote Terminal
Unit). PSEG Long Island may also require SCADA to be installed on
7
installation smaller than 1000 kVA if deemed necessary for the safe
operation of the LIPA system.
The RTU, if required, will be purchased by PSEG Long Island and paid for
by the DG System or may purchased by the DG System to PSEG Long
Island’s specifications and delivered to PSEG Long Island. The RTU shall
provide PSEG Long Island with supervisory trip control of the
interconnection breaker(s). It shall also provide telemetry of key operating
parameters of the DG System's facility, which shall include but not be limited
to:
a.
b.
c.
d.
Status indication of interconnection breaker(s), generator breaker(s),
and all other devices that are in series with these breakers.
Status indication of various alarms such as loss of DC to
interconnection breaker(s), loss of DC to RTU, loss of AC to RTU
battery charger, loss of relaying communication channel,
microprocessor relay alarm, etc.
Digital metering telemetry for current, voltage, watts, VARS, and
power factor for all interconnection breaker(s).
Pulse accumulation of MWHR (in/out) and MVARHR (in/out) for the
facility Access to the pulse metering signal will be made available to
PSEG Long Island for the installation of additional metering and
communications equipment if required.
The location of the RTU shall depend on the proximity of the DG System to
the interconnecting LIPA substation. The DG System shall not be allowed to
operate in parallel if the RTU or its associated lease line is out of service.
The RTU shall be maintained and repaired by PSEG Long Island at the DG
System's expense.
All costs for additional hardware and software for LIPA's mainframe
supervisory computer that are required for its interconnection shall be
charged to the DG System.
Whether the RTU is purchased by the DG System or by LIPA, it shall be
delivered to PSEG Long Island for testing and programming. At this time,
loss of AC/DC relays, fuses, and various terminal blocks will be installed
within the RTU cabinet by PSEG Long Island at the DG System's expense.
The DG System shall make provisions adjacent to the supervisory control
cabinet to terminate the supervisory control four (4) wire dedicated
telephone lease line(s) on a double pole double throw open blade cut off
switch(es) (diagram Appendix C). The lease line(s) shall be ordered by
LIPA and owned by LIPA. Installation, maintenance and subsequent
monthly charges shall be charged by LIPA to the DG System.
8
10.
For facilities interconnected to LIPA by means of a dedicated feeder, a
breaker shall be installed at the DG System's expense in the LIPA
substation. For a non-dedicated feeder, a disconnect device controlled by
LIPA shall be installed at the DG System's expense at the point of
interconnection with the LIPA system.
11.
The DG System shall be responsible for tripping its interconnection breaker
if a fault occurs on the electric facilities serving its installation. Whenever the
LIPA supply is de-energized, the DG System's interconnection breaker shall
be tripped by voltage and/or frequency relays and transfer tripped from
LIPA's interconnection substation. The interconnection breaker shall be
automatically locked out and prevented from closing into a de-energized or
partially de-energized (loss of one phase) LIPA system. The interconnection
breaker close circuit shall include a synch check and an over/under voltage
permissive contact to prevent closing the breaker when unfavorable voltage
conditions exist.
12.
The direct transfer trip (DTT) receiving terminal shall provide two outputs: a
trip output and an alarm output to indicate a loss of transfer trip condition.
The trip output shall energize a utility type target relay with multiple output
contacts. One (1) output contact of the target relay shall trip the
interconnection breaker. A second output contact of the target relay and the
alarm contact of the DTT terminal shall be wired to the RTU. The DTT
terminal and associated target relay shall be mounted indoors.
13.
The alarm for the loss of a DTT lease line must come from the DG System’s
SCADA or by having a bi-directional tone equipment that can give the alarm
at the LIPA substation. If no SCADA is provided, a transfer trip receiver and
transmitter with 4 wire lease line shall be provided. In the event of DDT
lease line loss, the DG System shall cease parallel operation with the LIPA
system. For DG systems less than 1000 KVA, the transfer trip system will
be used for LIPA supervisory trip.
14.
The required dedicated transfer trip lease line shall be ordered by LIPA.
Installation, maintenance and subsequent monthly charges shall be charged
to the DG System.
The DG System shall make provisions to terminate the lease line with a
double pole double throw open knife blade switch adjacent to the transfer
trip equipment (Appendix C). The DG System will not be allowed to
parallel with the LIPA system if its transfer trip or associated lease line is out
of service.
15.
For DG System’s utilizing only one microprocessor relay, the
interconnection breaker or the generator breaker(s) must be tripped when
the DG System’s protective relaying system goes into an alarm condition.
This trip shall also trip a lock-out relay that requires manual intervention
before the breaker(s) can be reclosed following successful clearing of the
relay alarm condition(s).
9
16.
The alarm for the loss of a DTT lease line must come from the DG System’s
SCADA or by having a bi-directional tone equipment that can give the alarm
at the LIPA substation. If no SCADA is provided, a transfer trip receiver and
transmitter with 4 wire lease line shall be provided. In the event of DDT
lease line loss, the DG System shall cease parallel operation with the LIPA
system. For DG systems less than 1000 KVA, the transfer trip system will
be used for LIPA supervisory trip.
17.
The required dedicated transfer trip lease line shall be ordered by LIPA.
Installation, maintenance and subsequent monthly charges shall be charged
to the DG System.
The DG System shall make provisions to terminate the lease line with a
double pole double throw open knife blade switch adjacent to the transfer
trip equipment (Appendix C). The DG System will not be allowed to
parallel with the LIPA system if its transfer trip or associated lease line is out
of service.
18.
For DG System’s utilizing only one microprocessor relay, the
interconnection breaker or the generator breaker(s) must be tripped when
the DG System’s protective relaying system goes into an alarm condition.
This trip shall also trip a lock-out relay that requires manual intervention
before the breaker(s) can be reclosed following successful clearing of the
relay alarm condition(s).
19.
The following are the minimum relay requirements for the interconnection
breaker:
a. Phase overcurrent relays (one per phase) with instantaneous and
voltage restraint time delay elements are required as well as one
ground overcurrent relay with instantaneous and time delay
elements. Each element of the phase and ground relays shall have
its own target.
b.
c.
d.
e.
f.
g.
Over/under voltage relays and over/under frequency relays are required
on LIPA’s side of the interconnection breaker.
Directional power relays may be required to limit power flow to
contractual agreements.
Directional overcurrent relays shall be required at sites where the DG
System’s load requirements from LIPA exceed the DG Systems
generating capability. Any exceptions to this requirement shall be
approved by LIPA.
Transformer differential relaying shall be required for interconnections
using transformer banks greater than 1500 kVA.
Negative sequence overcurrent relays.
All interconnection breaker relays and required generator breaker relays
shall be approved by LIPA. Interconnection breaker relays must be
10
capable of being calibrated and tested in their installed position to verify
proper application of all relay settings and full functionality of the relay
circuit(s).
20.
All breakers shall be D.C. trip and close. Trip and close circuits of the
interconnection breaker must be separately fused. If SCADA is provided
then loss of D.C. and low DC voltage alarms shall be wired to the RTU.
21.
Control, CT, and telemetering leads which interconnect to LIPA shall have a
minimum size and stranding of 19/25, 19/22, and #18 STP, respectively. All
control, CT, and telemetering leads must be terminated using ring type
connectors.
22.
The station battery shall be sized for an eight hour duty cycle in accordance
with IEEE Standard 485-1983. At the end of the duty cycle the battery shall
be capable of tripping and closing all breakers.
23.
All solid state relays requiring an auxiliary power source shall be powered
from the station battery. AC to DC converters is unacceptable.
24.
All relaying CTs shall have a minimum accuracy of C200. Saturation current
shall not be more than 10% of fault current. Interconnection relaying and
telemetering shall have dedicated CTs.
25.
Three PTs shall be installed on the LIPA side of the interconnection breaker
and shall be connected wye-grounded/wye-grounded. Three red indicating
lights, one per phase, connected phase to ground in the PT secondary, shall
be installed to provide visual verification of potential on each phase. Three
(3) single phase over/under voltage relays, associated with the high side
breaker, shall be connected phase to ground to these PTs.
26.
During emergency conditions, all interconnection breakers shall be capable
of being tripped by LIPA via supervisory control. LIPA will consider tripping
the generator breaker instead of the interconnection breaker if the system
configuration permits. Interconnection breaker and generator breaker(s)
status will be transmitted to LIPA via the RTU. The supervisory equipment
shall be installed and paid for by the DG System.
A digital meter or MW, MVAR, current, voltage and power factor transducers
mounted in flexitest drawout cases shall be connected to the
interconnection breaker CTs and line PTs and wired to the analog inputs of
the RTU. LIPA shall furnish the DG System with the necessary wiring
drawings to connect the transducers to the supervisory equipment.
11
27.
Synch check relays are required across the interconnection breaker of a
synchronous generator unless otherwise specified. A total of four potential
transformers shall be required on the interconnection, three on LIPA's side
of the breaker (as specified in #22) and one on the DG System's. Synch
check relays shall be installed for manual synchronizing. Automatic
synchronizing equipment shall be optional, however, it shall not permit the
exclusion of a synch check relay.
28.
The LIPA substation feeder breaker may require a set (3) of line side
potential transformers to monitor the presence of voltage on the distribution
feeder and to provide voltage to a synch check or voltage relay, which shall
prevent closing the breaker into an unsynchronized DG System's generator.
All costs incurred to purchase and place this system in service shall be at
the DG System's expense.
29.
The kVAR requirements of an induction generator, operating at 100% load,
will be determined and the DG System will be charged that portion of the
cost to install one or more 900 kVAR supervisory controlled distribution
capacitor banks to provide the reactive supply.
30.
Voltage and frequency relays shall be installed at the LIPA substation to
disconnect the DG System's generator from the LIPA bus in the event that
this bus becomes isolated from the LIPA system and the DG System's
generator continues to carry the connected LIPA load. These relays shall be
installed at the DG System's expense.
31.
Interconnection breaker(s) for DG System owned generator(s) on the
distribution system, unless otherwise specified, shall be automatically
tripped for all trips of the LIPA substation feeder breaker. A generator
breaker contact may be used to disable transfer trip of the interconnection
breaker when the generator breaker is open. The communication tripping
channel and transfer tripping equipment at the LIPA substation and at the
DG System's facility shall be purchased and installed at DG System's
expense, as part of the relay protection scheme. The transfer trip
equipment and associated transfer trip communication channel shall be
specified by LIPA.
32.
The transformer configuration of an existing LIPA transformer that is to
become customer-owned in a new primary metered installation must be
verified in the field. The DG Systems will bear the cost of a replacement
wye-wye transformer, which may be greater than the cost of purchasing the
in-place LIPA transformer.
12
IV. Non-inverter Interfaced DG Screening Criteria
It is the policy of LIPA to permit any applicant to operate a DG System in parallel with the LIPA
electric system whenever such operation can take place without adversely affecting other PSEG
Long Island customers, the general public, LIPA equipment and PSEG Long Island personnel. To
minimize this interference, the DG System shall meet the following criteria:
A. Voltage
The DG System shall produce voltages within ± 5% of nominal when operating in parallel
with the LIPA system. (Nominal voltages on the LIPA distribution system are 13.8 and 4.5
kV). The DG System shall provide an automatic means of disconnecting its generating
equipment from LIPA's facilities as follows:
Voltage Range (% of base voltage)
V < 50
50 ≤ V < 88
110 < V > 120
V ≥ 120
Clearing Time (seconds)
0.16
2.0
1.0
0.16
Base voltages are nominal LIPA system voltages. The clearing time is the time between
the start of the abnormal condition and the DG System ceasing to energize the LIPA
system. The clearing times indicated are default times and may be adjusted based upon
application specific requirements subject to PSEG Long Island review and approval.
B. Flicker
The DG System shall not cause voltage variations on the LIPA system exceeding those
defined on the Border Line of Visibility in Appendix E - Voltage Flicker Curves.
C. Voltage Dip
The voltage dip on a primary circuit due to inrush current should not exceed 2 Volts on a
120 Volt base.
D. Frequency
The DG System shall provide an automatic means of disconnecting its generating
equipment from LIPA's facilities for over and under frequency situations. No under
frequency tripping shall take place between 59.9 Hz and 58.0 Hz. The final under frequency
set point shall be determined to best support the operation of the LIPA system. The
equipment must be disconnected within 0.16 seconds for a frequency of 60.5 Hz or more
and within 1.0 second for a frequency of less than 58.0 Hz.
13
E. Harmonics
The total harmonic voltage or current distortion created by a DG System must not exceed
5% of the fundamental 60 Hz voltage or current waveform. The harmonic current injection
shall be exclusive of any harmonic currents due to harmonic voltage distortion present on
the LIPA system without the DG System connected. Any single harmonic shall not exceed
3% of the fundamental frequency.
∞
% Total Harmonic Distortion (THD) =
∑h
2
i
i=2
x100
h1
1
While a Single Component % Distortion = hi
h1
x100
2
Where:
hi = The magnitude of the ith harmonic of either voltage or current.
hl = the magnitude of the fundamental voltage or current.
For non-type tested units, as defined in the New York Standardized Interconnection
Requirements and listed on the New York Public Service Commission website, the DG
System(s) shall provide manufacturer’s harmonic testing reports.
F. Power Factor
DG Systems utilizing synchronous generators shall produce or absorb VARS such that the
overall power factor at the delivery point (location of LIPA's revenue metering equipment) is
between 0.90 and 1.0 leading or between 0.90 and 1.0 lagging. LIPA's System Operator
may request DG System to adjust the power factor at the delivery point, within the above
stated limits.
For DG Systems utilizing induction generators with a nameplate power factor below 1.0,
PSEG Long Island shall provide, at the DG System's expense, VAR capacity from its
system to bring such generators' power factor to 1.0.
G. External Fault and Line Clearing
The DG System shall be responsible for disconnecting from the LIPA system within 8
cycles of the occurrence of a fault on the LIPA distribution system using it’s relaying.
Backup relaying must coordinate with LIPA's protective relaying.
Note: The maximum available symmetrical short circuit current from LIPA on the 13
kV distribution system is 16,000 amperes and is exclusive of any other DG
Systems that may be connected to the same LIPA substation.
14
H. DC Injection
The DG System shall not inject dc current greater than 0.5% of the full rated output current
at the point of interconnection with the LIPA system.
I.
Unintentional Islanding
In the event that an unintentional island in which the DG System energizes a portion of the
LIPA system across the interconnection point, the DG System shall detect the island and
cease to energize the LIPA system within two seconds of the formation of an island.
15
V. Inverter-Interfaced DG Screening Criteria
A. Introduction
Distributed generation (DG) can have an adverse impact on the operation, protection,
equipment duty, and power quality of a distribution feeder. These impacts are a function of the
types of DG and the total amount of DG relative to the characteristics of the feeder. Long
Island Power Authority (LIPA) has established a process for review of DG interconnection
requests in order to determine impacts and identify specific mitigation measures necessary to
interconnect the DG.
B. Key Assumptions
The preparation of this screening methodology is intended to be specifically focused on the
design characteristics of LIPA’s distribution systems. A number of key assumptions have been
made, which are specific to the LIPA system. Thus¸ these criteria may not be applicable to
other distribution systems, nor are the screening criteria necessarily comparable to any other
utility’s or standards body’s criteria.
LIPA Distribution System Design and Operating Characteristics
• Feeders are relatively short, shorter than ten miles with relatively few exceptions.
• Feeder step voltage regulators are infrequently applied in LIPA distribution systems.
• Substation transformers use line drop compensation on the LTC controls.
• Distribution capacitor banks are controlled by time clocks or via pager, and are not
primarily controlled based on local distribution feeder voltage.
• Fixed capacitor banks are infrequently used on feeders.
• Pager-controlled capacitor banks are switched off during light load conditions. Time
clock controlled capacitor banks may be switched on during lighter-load periods (e.g.,
shoulder seasons), but would not be on during nighttime minimum-load periods.
• Three-phase distribution transformers are nearly always configured grounded-wye
grounded-wye.
• Distribution transformer resistances are almost always less than 2%IR.
• Feeder voltages may be as high as 126 V (on a 120 V base).
C. LIPA DG Interconnection Policies
•
•
The consideration of the need to provide a ground source to avoid excess
overvoltages is part of the development of the fast-track screening thresholds defined
in this report. Any inverter-interfaced DG passing the proposed process (i.e., rating
less than the defined thresholds) can be deemed to not need to provide a ground
source to the LIPA feeder. Any DG exceeding the thresholds defined in this report
requires further study to determine the technical requirements for interconnection,
including the provision of a feeder ground source.
Customer service voltages driven out of range by that customer’s DG is not a criterion
for impact assessment or screening.
16
•
•
Flicker imposed on a customer by that customer’s variable DG output is not a criterion
for impact assessment or screening. Flicker imposed on other customers, including
those served by the same distribution transformer, is to be considered.
LIPA may choose to require direct transfer trip (DTT), potentially for reasons beyond
the direct distribution system impact discussed in this report (e.g., overall LIPA system
energy management). Installation of DTT inherently requires engineering effort to
interconnect the DTT system to the feeder protection, and to provide appropriate
controls to transfer the DTT connection when the associated feeder section is
transferred to other feeders during any operational feeder reconfiguration. This
engineering effort, by definition, is inconsistent with the fast track process. Therefore,
any DG interconnection requiring DTT will be assumed to not qualify for the fast-track
process.
D. Inverter-Interfaced DG Impacts
The various impacts of DG have been amply described in many technical papers, as well as in
IEEE Standard 1547.2. In this section of the report, the various types of impacts are catalogued
and briefly described. Specific quantitative screening criteria are established which can be used to
screen interconnection requests for inverter-interfaced DG.
E. Steady-State Voltage Deviations
1. Primary Feeder Voltage Profile
DG output reduces the net load served by the distribution system, and at high
penetration, can potentially reverse the flow of power in the feeder. This can cause
feeder voltage profile deviations, which may result in customer service voltages
outside of ANSI C84.1 Range A. Screening criteria need to identify any significant
risk that a DG interconnection could result in service voltages outside of this range,
for any reasonably anticipated operating condition.
Because DG reduces, or reverses, power flow, the usual effect on steady-state
voltage is to cause an increase of voltage. This is not always the case, however,
when DG interacts with voltage regulating devices using line drop compensation, or
automatic capacitor switching controls. These interactions can potentially result in a
voltage decrease. (Voltage regulating devices, in this context, includes line voltage
regulators and distribution substation transformer on-load tap changers.)
A very serious voltage deviation can occur if power through a feeder voltage
regulator is reversed, and the regulator controls are configured to use reverse
power flow as an indication that the feeder has been reconfigured such that the
substation is now connected to the former load side of the regulator. Regulator
controls with this “reverse power sensing” will switch the side that is regulated. If
the power reversal is caused by DG output, and the substation remains connected
to the same side of the regulator as before the power reversal, the switch of
regulation to the substation side will cause the regulator tap to go to max boost or
max buck tap setting. This is because the regulated side needs to be opposite the
side from which has the most “stiffness”, or short-circuit strength. Inverter DG can
provide power, but do not provide significant “stiffness”. Therefore, the reversal of
17
regulator control configuration, caused by DG-induced power reversal, results in the
regulator attempting to regulate the strong side. As the tap changes, the regulated
side voltage will not change appreciably, but the other side (where the DG is
connected) will. The tap control will not be satisfied – e.g., a high sensed voltage
will cause the regulator to increase buck, and the sensed voltage will increase as a
result – thus causing the regulator to go to the maximum buck limit, resulting in very
low voltages on the DG side of the regulator.
Feeder voltage regulators are infrequently used in the LIPA system, but LIPA
distribution substation transformer LTC controls have automatic voltage regulators
with line drop compensation. LIPA feeder capacitors are pager controlled by
system operators or are controlled by time clocks. Thus, the steady-state voltage
impacts of DG on the LIPA system, for feeders without time clock controlled
capacitor banks, are limited to the more straightforward condition of voltage rise
caused by reversed power flow. The DG output need not exceed the total feeder
load demand in order for power to be reversed on a portion of the feeder, and for
excessively high voltages to occur. Figure 1 illustrates a case where the output of a
large DG connected to the end of a feeder is less than the total feeder demand, but
the voltage at the end of the rises outside of the acceptable range.
Figure 1
Illustration of high voltage caused by DG with a capacity less than feeder load
demand
If a feeder of uniform per-mile impedance and load density is assumed, and it is
also assumed that load power factor is periodically corrected along the feeder, then
a concentration of DG located at the end of the feeder with output equal to 50% of
the feeder demand results in a “U” shaped voltage profile where the substation end
and remote end voltages are approximately equal. This scenario is illustrated in
Figure 2. With these same assumptions, output of DG uniformly distributed along
the feeder, with an aggregate output equal to 100% of feeder demand, results in a
flat voltage profile.
18
Figure 2
Approximate voltage profile for a uniform, power-factor compensated
feeder with a DG located at the remote end with output equal to 50% of
feeder demand.
Some LIPA feeders have capacitor banks that are controlled by time clocks. These
capacitors are switched in for the daytime and evening hours, independent of the
day of week or season of year. Thus capacitors will tend to be on during days when
loading is quite light, such as weekend days during the shoulder seasons. Thus,
these capacitors can overcompensate the feeders during these times, and feeder
voltages at the capacitor bank locations can be substantially elevated. By standard,
the voltage should not be raised greater than 126 V (this value may be exceeded in
some locations in some instances). However, by raising primary voltage to this
level, insufficient margin remains for any secondary voltage rise caused by DG.
Likewise, substation bus voltage or feeder voltage regulator load-side voltage
regulated to the maximum 126 V value also result in lack of margin for secondary
voltage rise. These issues are discussed later in the section covering secondary
voltages.
LIPA substation transformers have on-load tap changer controls with line drop
compensation (LDC), which increase substation bus voltage in proportion to the
total loading on the transformer. This application of LDC has the inherent
assumption that the loading patterns on the feeders are relatively similar, and that
all of the feeders have similar voltage drops. Thus, control of the substation voltage
with LDC can achieve reasonably good control of the feeder-end voltages. Even
without DG present, this assumption is often quite imperfect. For example, a typical
substation may have certain feeders supplying predominately commercial load, and
others serving predominately residential load. Additional voltage range margin is
needed in the feeder voltage management planning to account for the dissimilar
loading pattern and voltage drops.
The presence of DG can aggravate the differences in feeder voltage drop if the DG
power production is dissimilar on the various feeders supplied by the substation.
This can result from either differences in the installed DG capacity, or differences in
the relative output of the DGs due to availability of their energy source (e.g., in the
19
case of possible future wide scale PV deployment, a cloud could shadow the
geographic area served by one feeder while PV generators on another feeder are
receiving full sunlight). Because the LDC at the substation transformer responds to
the total load, and thus controls the average voltage drop, high DG penetration
could cause voltages on certain feeders to be either too high or too low. This is
illustrated in the extreme case shown in Figure 3, where high DG output on the top
feeder causes excessive voltage at the end because the substation voltage has not
been lowered enough, and an undervoltage condition on the end of the bottom
feeder because the substation voltage has not been boosted enough for the voltage
drop due to the loading on that feeder.
Because feeder voltage regulation design must allow for the normal dissimilarities in
feeder loading, there is inherently the capability to accommodate some degree of
DG-caused net load dissimilarities, as well, unless the dissimilarity in DG production
far exceeds the load dissimilarities.
Figure 3
Illustration of DG interaction with substation transformer tap changer
control line-drop compensation
2. Steady-State Primary Voltage Criteria
To allow for feeder voltage drop without DG contribution, LIPA may wish to operate its
distribution substation bus voltages up to 126 V (equivalent, on a 120 V base), the
upper limit of Range A. Thus, any DG output that causes voltage anywhere on the
feeder to exceed the substation bus voltage is undesirable. Within the idealized
assumptions described previously for the example shown in Figure 2, it could be
concluded that DG output up to 50% of the minimum feeder load is acceptable if the
DGs are concentrated at the feeder remote end. If the DGs are widely distributed small
units, the acceptable limit could reach 100% of minimum feeder load.
20
Practical feeders, however, seldom exhibit the uniformity assumed to derive these
thresholds. Reduced conductor size may be used remote from the substation, because
the current in these feeder sections is typically less. Thus, per-mile impedance may
increase as distance from the substation increases, increasing voltage rise due to DGcaused reverse power flow at the remote feeder ends. Loads are also typically not
uniformly distributed along a feeder. Feeders may be overcompensated, by line and
cable charging during light-load conditions, further increasing remote end voltage. (It is
assumed that switched capacitor banks would be off during light-load conditions, and
LIPA infrequently uses fixed capacitor banks.) Thus, it is prudent to allow extra margin
in the criteria to allow for these non-ideal circumstances, as well as to allow for
dissimilarity in the net load of feeders supplied from the same substation. A 50%
margin is deemed sufficient to minimize risks of adverse steady state voltage impact.
The following criteria are recommended to indicate interconnections where impacts are
not deemed significant:
Psingle<0.5/(100% + 50%) = 0.33 Pfdr_min
[3.1]
Ptotal<1.0/(100% + 50%) = 0.66 Pfdr_min
[3.2]
Where:
Psingleis the rating of the DG application being screened
Ptotalisthe sum of all the DG ratings connected to the feeder, including the DG under
screening
Pfdr_min is the minimum load demand of the feeder.
The criterion for Ptotal in Equation 3.2 is based on the assumption of widely distributed
small DG. There could be acase where all the DGs are concentrated at an adverse
location, such as a feeder remote end. In this case, all the DG together could have the
impact of one large DG. The screening can be conservatively simplified to the
following:
Ptotal<0.33Pfdr_min
[3.3]
It is expected that a large percentage of the inverter-interfaced DG that will seek
interconnection to the LIPA system will be PV solar. This form of generation can only
produce during daylight hours. Thus, it may be unduly conservative to compare PV
generation with feeder absolute minimum load which generally occurs during hours of
darkness. Other forms of inverter-interfaced DG are generally uncorrelated with time of
day. The following steady-state screening criteria are recommended to provide
reasonable consideration of the time-dependent output of solar generation:
Ptotal<0.33Pfdr_min_day
and
Ptotal_non-solar<0.33Pfdr_min [3.4]
Where:
Ptotal_non-solaris the sum of all the DG ratings, other than solar, connected to the feeder,
including the DG under screening if it is non-solar.
Pfdr_min_dayis the minimum load demand of the feeder during daylight hours (nominally,
between 7 a.m. and 7 p.m).
21
All other variables are defined as previously.In addition to a screen of the overall feeder
DG capacity and load, similar screening also should be applied for a DG
interconnecting to a single-phase feeder lateral. Lateral voltage rise would generally be
inconsequential for a lateral supplied by the main feeder at a point remote from the
substation. However, rise on a lateral near the substation could result in customers
near the end of that lateral receiving excess voltage. DGs connected to a lateral can be
expected to be of small rating, and thus it is reasonable to assume that if the aggregate
rating of DG on the lateral is sufficient to be of consequence, the DGs can be assumed
to be distributed on the lateral. If distribution of the DG capacity is perfectly uniform,
then DG capacity up to the lateral’s minimum load should not cause voltage rise.
However, the DG capacity will be somewhat unevenly spread in practice, so a 25%
margin is recommended as shown in Equation 3.5. Because capacitor banks are not
typically installed on laterals, this recommended degree of margin can be less than the
50% margin recommended for the feeder as a whole.
Plat<0.80Plat_min_day and
Plat_non-solar<0.80 Plat_min [3.5]
Where:
Platis the sum of all the DG ratings connected to the lateral, including the DG under
screening
Plat_non-solaris the sum of all the DG ratings, other than solar, connected to the lateral,
including the DG under screening if it is non-solar
Plat_min_dayis the minimum load demand of the lateral during daylight hours (nominally,
between 7 a.m. and 7 p.m).
Plat_minis the minimum load demand of the lateral
Actual lateral peak and minimum loading are often not available data, but can be
reasonably estimated. For the purposes of this criterion, the ratio of lateral minimum
load to connected transformer capacity on the lateral can be assumed to be the same
as the ratio of feeder minimum load to total distribution transformer connected to the
entire feeder. This assumption is based on the fact that, with sufficient loads to have
good diversity (typically ten or more), the lateral load cycle will be reasonably consistent
with the overall feeder load cycle. If the lateral has a small number of customers, then
in the case of the LIPA system (in contrast with some rural utilities) it is reasonable to
assume that the lateral is very short and lateral voltage drop/rise is not of significance.
3. Secondary Voltages
The voltage criteria which have been so far described are intended to maintain a
satisfactory voltage profile on the distribution primary feeder and its primary laterals. In
addition to possible impacts on primary voltage, DG interconnection will also affect
secondary voltages. Whereas significant primary voltage impacts will usually require a
significant number of DG installations, a single DG may cause voltage issues at the
secondary level. The impact of DG on secondary voltages may be considered
separately for residential single-phase services, and large commercial three-phase
services. There are significant differences between residential and commercial
services in terms of load diversity, effect on other customers, and typical distribution
transformer impedances.
22
Loading of distribution transformers and secondaries is inherently very non-diverse,
particularly in residential situations. It is quite likely that maximum DG output can occur
when there is very little loading on a residential distribution transformer (e.g., PV on a
sunny weekday noon in the late spring with residents away at work and no need for
heating or air conditioning). Thus, any installed DG capacity can potentially cause
secondary voltages to rise above the per-unit value of the voltage at the primary side of
the particular distribution transformer. If this distribution transformer is close to the
substation, close to the load side of a feeder voltage regulator, or on a feeder with time
clock controlled capacitor banks, then voltage can rise above the substation bus level.
Residential distribution transformers typically have a relatively high resistance; thus
export of power from the customer side results in a proportionately greater voltage rise
than a three-phase transformer serving a large commercial load. Average service cable
length tends to be longer for residential than for large commercial loads. Residential
transformers usually serve multiple customers, but commercial transformers tend to be
dedicated to individual customers (with frequent exceptions, such as strip malls). When
multiple customers are served from the same transformer, DG power export from one
customer can potentially have significant influence on voltages at other customers.
In addition to voltage rise through the distribution transformer impedance, there is also
rise on the secondary service cables. Assuming that each customer is fed radially from
the distribution transformer1, the secondary cable voltage rise will only affect the
customer with the DG. It is assumed that voltage driven outside of Range A by a
customer’s export of power will not be considered as a distribution design requirement
and will not be considered a criterion here.
Because large commercial customers are typically served by a dedicated distribution
transformer, voltage rise through the transformer only affects the customer exporting
power. Using the same rationale as above, this voltage rise will not be considered as a
screening criterion.
Situations where multiple commercial customers are served by a single distribution
transformer have attributes in common with both the residential and large commercial
situations described above. Transformer resistance is low but one customer may affect
another’s secondary voltage. To simplify the definition and application of the secondary
voltage criteria, it is recommended to divide the screening between multi-customer
distribution transformer applications, and dedicated applications instead of residential
versus commercial, in order to avoid ambiguities regarding multi-customer commercial
situations. Applying the higher resistance of residential single-phase distribution
transformers to screening of multi-customer commercial applications results in a slight
overestimation of the impacts, but is a reasonable and conservative simplification of the
criteria.
Thus, at any point on the feeder where the primary voltage exceeds 123 V, there is the
potential for excess voltage at non-DG customer services, unless the DG service is on
1 “Secondary mains”, where multiple customers are served by a secondary cable section, may be used in dense areas. However, it
is assumed that significant DG installation will not take place in such dense areas, and thus the secondary voltage impact of one
customer on another sharing the same cable need not be considered in the design of these screening criteria.
23
a dedicated transformer. Such points include a portion of the feeder near the
substation, downstream of any voltage regulators, and anywhere on feeders where
there are time clock controlled capacitors.
For DG interconnections where there is a dedicated distribution transformer, it is
recommended that no secondary voltage screening criterion be applied.
For DG interconnections where multiple customers are supplied from a common
distribution transformer, a secondary voltage impact screening threshold should be
applied based on the total DG capacity connected to the transformer and the expected
maximum primary voltage at that location. The total DG capacity interconnected to the
primary via a single distribution transformer can be expected to not have an aggregate
rating greater than that of the distribution transformer. The maximum distribution
transformer %IR is assumed to be 2%, thus the maximum voltage rise through the
transformer would be 2.4 V. Considering that this is a relatively extreme %IR, but also
taking into account the resistance of secondary cable segments that serve both the DR
customer and other customers, in common, it seems that a 3 V maximum margin for
secondary voltage rise is reasonable.
The required margin is directly proportional to the rating of the DG served by the
distribution transformer divided by the distribution transformer’s kVA rating.
3*Pdg/Sxfmr<126 - Vp_max
[3.6]
Where:
Pdgis the sum of all the DG ratings connected to the secondary of the distribution
transformer
Sxfmris rating of the distribution transformer
Vp_maxis the maximum primary voltage at the location, on a 120 V base
The maximum primary voltageVp_maxcan be estimated based on the location of the
distribution transformer on the feeder, relative to the feeder head and other equipment.
Assuming a typical maximum 13.8 kV feeder load of 10 MVA, and a minimum load of
25% of the maximum, the minimum current at the feeder head is 105 A. Further
assuming a power factor of 0.9, and a 336 kcmil feeder’s impedance, thevoltage drop is
0.16 V/1000’ (on a 120 V base). 2Thus, for a DG interconnection where the DG rating is
equal to the distribution transformer rating, secondary voltage may be driven out of
range if located within the first 3.6 miles of the feeder. This is the entire extent of many
LIPA feeders. However, most DG ratings will be less than that of the interconnecting
transformer, so Equation 3.6 can be combined with this assumed primary voltage drop
to achieve the following criterion for DG located near the head of a feeder:
Pdg<0.052 SxfmrDfdr
[3.7]
Where:
2
This assumes that the feeder current is constant over the section, which is a reasonable assumption if the section is
a small portion of the feeder at the substation end. Distributed load taps will tend to decrease the average voltage
drop per mile over the section.
24
Dfdris the distance, in thousands of feet, along the main feeder from the substation to
the distribution transformer, or to the lateral tap on the main feeder if the distribution
transformer is located on a lateral
The minimum voltage drop on the feeder downstream of a voltage regulator will be less
than 0.16 V/1000’ because the feeder loading at the regulator location will be much less
than at the feeder head. Secondary voltage rise is quite likely to be constraining for any
reasonable distance downstream of a regulator. Because of this, and the fact that
regulators are infrequently used in the LIPA system, DG interconnections downstream
of a regulator will be defined to fail the screening for expedited interconnection in order
to keep the screening process from becoming unduly complicated.
Likewise, because time-controlled capacitor banks can raise primary voltage to 126 V
at points on the feeder where loading may be far less than the feeder head loading,
raising voltage profiles both before and after these banks, it is not feasible to devise a
simple screen to indicate DG interconnections where secondary voltage rise will not
cause excess service voltage. Rather than screen out all DG interconnections on
feeders containing such banks, LIPA may instead adopt a policy of responding to the
high voltages resulting from DG interconnection if and when they occur. Options
include removal of the capacitor bank, changing capacitor bank settings, installing a
dedicated distribution transformer, installing a transformer with external taps or with a
below-nominal fixed ratio, or adjusting substation LTC set points.
F. Contingency Voltage Decrease on Simultaneous DG Trip
Power production by DG will change the distribution feeder voltage profile, and will cause
tap changer settings and switched capacitor bank status to be altered, as a consequence, if
DG penetration is sufficient. To avoid islanding and continued DG infeed to faults, IEEE Std
1547 requires rather sensitive under- and over-voltage, and over- and under-frequency trip
settings.
While it is clearly desirable for a DG to trip immediately for a fault on the feeder to which it is
connected, the trip settings are also likely to cause DG trip for faults on adjacent feeders, or
even on the transmission system. It is therefore quite possible for all DG on a feeder to trip
simultaneously, even without a fault on that feeder. The resulting step change in DG power
output can make a significant step decrease in feeder voltage, particularly if controlled
devices (e.g., tap changers and capacitor banks) are biased in their setting by the predisturbance DG flow.
Such an event would be considered to be an abnormal contingency, and thus it is
reasonable to allow service voltage levels to fall into Range B of ANSI C84.1 for such an
event. Considering that the pre-disturbance voltage at some service could be as low as the
bottom of Range A (assuming the feeder is designed and operated in accordance with this
standard), the amount of tolerable voltage drop for this contingency is from the least voltage
of Range A (114 V) to the least voltage of Range B (110 V), a change of 4 V. LIPA feeders,
with very few exceptions, are less than ten miles long. LIPA’s construction standard for
backbone three-phase feeders specifies 336 kcmil conductors, having a resistance of
approximately 0.3 ohms per mile. For DG concentrated at the end of such a feeder, loss of
a combined rating of 2100 kW could cause a 4 V (on 120 V base) step decrease in voltage.
25
The peak capacity of LIPA’s 13.8 kV feeders is approximately 10 MVA. A reasonable
estimate of the greatest likely daytime minimum load is 6 MVA. The steady-state voltage
screening criteria defined previously in Equation 3.4 limits solar DG to 33% of the daytime
minimum load. (Because the overall minimum load is less, the limits on non-solar DG are
even more stringent, as defined in Equation 3.3.) Thus, the total feeder DG capacity
screening threshold set by the steady-state voltage criteria prevail over the capacity
threshold relevant to the simultaneous DG trip consideration, and an additional screening
criterion for simultaneous DG trip is not necessary.
G. Inadvertent Islanding and Temporary Overvoltage
Isolation of a feeder or feeder section in response to a fault or due to other switching, can
potentially leave the feeder or section of a feeder energized by DG. This is undesirable for
many reasons including safety, lack of utility control over the quality of power provided to other
customers, and potential for out-of-synchronism reclosing. At any given time, the aggregate
output of the DG is statistically unlikely to be exactly the same as the load demand. Any
imbalance between generation and load will cause deviations in voltage or frequency that will
eventually result in tripping of the DG over and under frequency and voltage protections, per
IEEE 1547 and UL-1741. Inverters tested to UL-1741 must also have some form of active
anti-islanding functionality to force the inverter to trip, even if load and DG output are precisely
balanced. Thus, there is ideally little risk of a sustained island as long as compliant DGs are
connected.3
1. Temporary Overvoltages
Compliant DG can support an island for up to two seconds, per IEEE 1547. Even this
short duration of islanded operation can have serious consequences to the utility and to
customers. The most likely system event initiating an islanding situation is a feeder singlephase fault. During a single-phase fault, effective system grounding is necessary to avoid
elevation of the unfaulted phase voltages to a high value. The normal source for feeder
grounding is the grounded-wye winding of the distribution substation transformer but
isolation of the feeder from the substation removes this ground source. Some utilities
require that DG interconnections provide a ground source to the feeder, typically via a
grounded-wye delta distribution transformer. Introducing ground sources along a feeder
tends to desensitize ground current relays used to detect ground faults.
Typically, the only “sources” of grounding on an islanded LIPA feeder are the wyeconnected loads. If too little load is connected to the island, the three-phase DG inverters
can push the unfaulted phase voltages to excessive levels, potentially damaging utility
equipment, such as surge arresters, and the equipment of other customers connected to
the islanded section. In LIPA distribution systems, single-phase loads are served by phaseto-neutral connected transformers, and thus contribute to grounding. Three phase loads
are supplied by grounded-wye grounded-wye transformers. For these three-phase loads,
only the portion of the load that is connected phase-to-neutral on the secondary of these
transformers contributes to feeder grounding. The windings of three-phase motors are
3
UL-1741 testing is performed with one DG by itself with load. There have been concerns raised in the
industry that dissimilar active anti-island schemes may adversely interact with each other (e.g., one design
tries to push frequency higher while another pushes lower.) There is insufficient information in the literature
on this speculated situation on which to base DG impact assessment or screening criteria.
26
typically connected in delta, or floating wye, and thus do not contribute to grounding.
Lighting loads in commercial buildings with 208Y/120 V service are often connected
phase-to-phase. In commercial facilities with 480Y/277 V service, lighting and plug loads
are usually supplied via stepdown transformers within the facility, and these are typically
connected delta-wye. Thus for a primarily residential feeder, it is estimated that 80% to
90% of the load is contributing, but on a predominately commercial feeder, perhaps as
much as 70% of the load is non-contributing.
A three-phase inverter used for DG applications operates as a controlled positivesequence current source, in contrast to a synchronous generator which can be considered
to be a voltage source in series with an impedance.. Three phase inverters can be
considered to be an approximately ideal positive sequence current source, and they are
effectively open circuits in the negative and zero sequences. Applying these conditions to
a symmetrical component analysis of a single phase fault, the maximum unfaulted-phase
voltage can be calculated as a function of load for a situation where inverter-interfaced DG
supports a feeder island with no source of grounding other than the load. Results of this
fault analysis yields the plots shown in Figure 4 for a residential feeder (assuming 80% of
the load contributes to grounding), and Figure 5for an commercial or industrial feeder
where it is assumed that only 30% of load contributes to grounding.
Single phase inverters, applied and loaded equally on the three phases, have an
aggregate behavior similar to three-phase inverters in most aspects. However, for the case
of islanded operation without a ground source, the performance can be significantly
different. This is because the single-phase inverters are connected to the feeder through
line-to-ground connected distribution transformers, and there is no three-phase isolation
transformer providing zero-sequence decoupling. In the case of an islanded ungrounded
system with a ground fault applied, the single-phase inverters would try to push their rated
current, but their voltage capability to do so is limited (in the case of three-phase inverters,
there can be high feeder phase voltages that are not directly experienced by the inverter
due to the zero-sequence isolation). A typical single-phase inverter design would not be
capable of causing an extreme phase voltage, and neither would the aggregation of many
single-phase inverters.
The ratio of three-phase inverter-interfaced DG capacity to load in a feeder “section” can
be used to indicate the possible overvoltage that may occur if that section is islanded. In a
typical distribution system, there is usually more than one interrupting device upstream of
any given DG interconnection. Any of these interrupters can open, leaving all of the DG
downstream of that point islanded with all of the load downstream of the same point.
Therefore, in this discussion, a feeder section is defined as any portion of a feeder
downstream of an interrupting device.
To illustrate this, refer to Figure 6. DG3 is on a lateral, and blowing of the lateral fuse
islands that
DG with all of the lateral’s load connected at that time. DGs 1 to 4 are on this feeder.
Interruption of the feeder breaker islands all the loads along with all of the DGs. If ASU1
were a recloser, it would be necessary to consider a scenario where DGs 1 – 3 are
islanded along with all the loads downstream of ASU1, shown as yellow and red
diamonds. Because ASU1 is not a fault interrupting device, and DGs should already be
tripped off before ASU1 opens during the main breaker’s reclose delay, it is not necessary
to consider this potential islanding scenario. However, a prior fault could have caused
ASU2 to operate, and after a five-minute delay (per IEEE Std 1547), DG 3 and DG4 could
27
reconnect. Thus, the scenario of DG3 and DG4 islanded with the loads ahead of ASU2
(yellow and green diamonds) needs to be considered. For an interconnection screen of
DG3, or any other DG, all interruption scenarios must be separately screened.
2. Islanding TOV Criteria
There is no standard that clearly defines the acceptable limits of temporary overvoltage
(TOV) magnitude for the two-second duration during which islanding can be assumed to
persist. Feeders without DG, however, routinely experience some degree of TOV due to
ground faults and this TOV can persist for two seconds, depending on protection design.
Thus, normal fault-induced TOV magnitudes (not involving islanding or DG behavior) can
be used to benchmark TOV levels produced by DG islanding, to determine an acceptable
TOV limit.
LIPA feeders are designed to be effectively grounded. Feeders which minimally meet the
formal definition of “effectively grounded”, as established by IEEE C62.92.1, can
experience TOV as high as 1.4p.u.. This is an extreme case, and the grounding of most
LIPA feeders substantially exceeds minimal effective grounding due to the generally short
length of LIPA feeders.
A typical level maximum level of TOV on LIPA feeders is estimated to be about 1.2 p.u.
This level can be considered as an acceptable limit to also apply to TOV caused by DG
islanding with a ground fault present. Referring to Figure 4 and Figure 5, the ratio of
minimum load on a feeder section, relative to the total inverter-interfaced DG connected to
that section, should be at least 87% for a residential feeder and 107% for a commercial or
industrial feeder.
Note that these criteria apply to any portion of a feeder that can become isolated. For each
interrupting device upstream of a DG interconnection, the minimum load test should be
applied. As an example, if a DG under screening is connected to a fused lateral, and the
lateral is downstream of a feeder recloser, the load ratio should be evaluated for each of the
following:
1. the lateral, considering all the DG connected to that lateral
2. the portion of the main feeder ahead of the next downstream ASU, including all
laterals connected to that portion of the main feeder.
28
1.5
1.4
Maximum Phase Voltage (p.u.)
1.3
1.2
1.1
1
0.9
0.8
0.7
0.6
0.5
0.6
0.65
0.7
0.75
0.8
0.85
0.9
0.95
1
1.05
1.1
1.15
1.2
Load Demand (p.u. of DG output)
.Figure 4
Maximum unfaulted phase voltage as a function of load demand for
predominately residential feeders.
1.5
1.4
Maximum Phase Voltage (p.u.)
1.3
1.2
1.1
1
0.9
0.8
0.7
0.6
0.5
0.8
0.85
0.9
0.95
1
1.05
1.1
1.15
1.2
1.25
1.3
1.35
1.4
Load Demand (p.u. of DG output)
Figure 5
Maximum unfaulted phase voltage as a function of load demand for
predominately commercial/industrial feeders.
29
Figure 6
Illustration of the feeder section definition
30
As previously discussed for steady-state voltage impacts, only daytime minimum load needs
to be considered for solar PV. Therefore, the screening criteria in Table 1 Error! Reference
source not found.are recommended for three-phase inverter-interfaced DG.
Table 1
Islanding TOV Criteria
Predominately residential feeders
Other feeders (commercial, residential, mixed)
Ptotal_sect<0.87Psect_min_day
and
Ptotal_sect_non-solar<0.87Psect_min
Ptotal_sect<1.07 Psect_min_day
and
Ptotal_sect_non-solar<1.07Psect_min
The variables in Table 1have the following definitions:
Ptotal_sectis the total three-phase DG capacity on the feeder section, solar plus non-solar.
Ptotal_sect_non-solaris the total non-solar three-phase DG capacity on the feeder section.
Psect_minis the absolute minimum load demand of the feeder section.
Psect_min_dayis the absolute minimum daytime load demand of the feeder section.
3. Out-of-Phase Reclosing
Another adverse aspect of DG-supported islanding is the potential for out-of-phase
reclosing if the feeder breakers reclose before the DGs connected to the feeder trip off.
Unlike synchronous generators, out-of-phase reclosing and the resulting jump of voltage
phase angle are relatively inconsequential to inverter-interfaced DG equipment. However,
such reclosing can result in high transient voltages on the feeder, as well as severe torque
transients on customers’ motor-driven mechanical drive trains (e.g., HVAC air handler
blower) connected to the feeder. The high transient voltages are caused by the transient
overshoot when the voltage abruptly changes from one polarity to the other; very similar to
a capacitor switch restrike. Ideally, voltages as high as 3 p.u. are theoretically possible, but
magnitudes of 2.5 – 2.7 are more realistic.
Current discussion in the development of IEEE P1547.8 indicates an industry consensus
that reclosing out of phase into an energized feeder is assumed to be inconsequential if the
voltage of the island is less than 0.2 – 0.3 p.u. Also, the switching transient caused by such
an event would have a potential overvoltage of around 2 p.u., which should be within the
capability of distribution surge arresters to withstand. For a typical distribution system, outof-phase reclose into an island having a pre-reclose voltage exceeding 0.4 p.u. could result
in a transient voltage peak exceeding 2.0 p.u. upon reclose.
Because IEEE 1547 requires DG to not sustain an island for more than two seconds, the
out-of-phase reclosing concern is only relevant if the feeder breaker reclosing delay is less
than two seconds. LIPA feeders using electromechanical reclosing controls are not set with
any intentional reclosing delay. The inherent delay is about twelve cycles (0.2 seconds).
For other feeders with digital relays, the first reclose is set for 300 ms delay. To avoid the
impacts of out-of-phase reclosing, there are four basic options:
31
a. Increase reclosing delay to greater than two seconds. This adversely impacts power
quality, and is not a preferable option.
b. Use an undervoltage permissive function on reclosing, which would require installing PTs
on the feeders to implement, which would require installing PTs on the load side of the
feeders to implement. A voltage threshold of 0.2 to 0.3 p.u. is recommended, above which
reclosing should be blocked.
c. Ensuring that there is sufficient minimum load on the feeder such that the worst-case phase
voltage is less than 0.2 p.u. in an island situation. (See the discussion on Out of Phase
Reclosing Criteria, below)
d. Implement direct transfer trip to sufficient DG such that the remaining DG cannot result in
worst-case phase voltage greater than 0.2 p.u. during minimum load conditions. The direct
transfer trip needs to be faster, including any DG response time, than the reclosing delay.
In addition to the above, consideration could also be given to a zero sequence overvoltage
(3*V0) high-speed protection function implemented on all DGs. There are a number of
shortcomings to this latter approach, however, including the following:
a. While the scheme should work if the causative event leading to islanding is always a
permanent ground fault, it quite likely that many feeder ground faults will self-clear as soon
as the substation breaker opens and interrupts the major source of fault current. If the fault
is across a gap in open air or under oil, the greatly reduced fault current available from
inverter-interfaced DG is likely to lead to an unstable fault arc, and the arc is likely to
extinguish. Thus, the 3*V0 protection will only see the high zero-sequence voltage for the
duration of the substation breaker clearing time, which may not be sufficient.
b. Feeder islanding can also take place as the result of a balanced fault. While a bolted threephase fault on the feeder would not allow any significant voltage to be present on the
feeder at the time of reclose, a higher-impedance balanced fault could result in feeder
tripping while still allowing a voltage greater than 0.2 p.u. to persist on the island via DG
contribution. A 3*V0 scheme is ineffective for such a situation.
Where 3*V0 schemes are used, the setting should provide the best balance between
sensitivity to detect faults on the same feeder (while the substation breaker is closed, in
order to avoid the self-clearing fault situation discussed above) and selectivity to avoid
pickup for ground faults on adjacent feeders. For DG connected to the main feeder,
consideration may also be given to coordination with lateral fuses, if a fuse-blowing scheme
is used, to minimize DG trips for ground faults on laterals cleared by fuses. Perfect
coordination may not be achievable in many cases, and greater weighting toward island
avoidance should be given over minimization of nuisance DG trips.
Of the four effective options listed previously, the first, and second constitute a change in
LIPA operational and design practices and are beyond the scope of screening process
recommendations. The fourth option requires extensive engineering interaction to
implement, which by definition is contradictory to a fast-track process. Thus, the screening
criteria proposed in this report are focused on the third option.
4. Out-of-Phase Reclosing Criteria
In the case of a balanced system (i.e., no ground fault present), load on the island would
have to be five times the aggregate DG rating, assuming the inverter-interfaced DG
32
maintain a constant-current output and loads behave as constant impedances. If a ground
fault is present, even more load (approximately 6.5 times aggregate DG rating) must be
present if the DG are three-phase inverters, due to neutral shift (lack of adequate
grounding). However, if any phase voltage at the DG terminals is less than 0.5 p.u., the DG
must trip in less than 10 cycles, which is less than the 12 cycle “instantaneous” reclosing
time used by LIPA. Therefore, there must only be sufficient load to reduce voltage to 0.5
p.u. to avoid out-of-phase reclosing. This value of minimum load is approximately two
times the aggregate DG rating; thus yielding the following criteria:
Ptotal_sect<0.5Psect_min_day andPtotal_sect_non-solar<0.5Psect_min
The criteria above supersede those provided previously in Table 1, unless LIPA adopts a
different approach to avoidance of out-of-phase reclosing (i.e., increasing reclosing delay,
undervoltage permissive reclose, or direct transfer trip).
H. Power Quality
Power quality is a wide category, and in the broadest definition includes voltage transients,
sags, and swells, as well as harmonic distortion and rapid voltage variations (flicker). Of these,
the issues relevant to inverter-interfaced DG interconnection are flicker and harmonics.
1. Flicker
Flicker is defined as rapid and repetitive variations in voltage. These voltage variations,
when applied to lighting loads, causes variation in lamp luminance that can be a nuisance
to electric customers and can even cause nausea and other physiological effects if severe.
In the strictest definition, flicker only pertains to these illumination-related effects. However,
frequent voltage variations can also cause impacts to other customer loads and to some
utility equipment such as voltage regulators and voltage-controlled capacitor bank switches.
The industry has come to more loosely define flicker as encompassing any of the adverse
impacts of short-term voltage variation.
The usual cause for flicker caused by inverter-interfaced DG is a variation of the primary
energy source, such as wind speed in the case of wind generation and solar insolation in
the case of PV solar generation. Frequent variations in wind turbine power output can
occur during gusty conditions. Small “backyard” scale wind turbines are far more prone to
short-term power output variations than large utility-scale wind turbines because these
small turbines are not as high, and are thus in a wind regime where there is substantially
more turbulence due to ground obstructions such as structures and trees. Wind generation
is not likely to be a major distributed generation choice on Long Island due to siting, zoning,
and land availability constraints.
Solar generation is subject to variations due to cloud shadows movement. Typically, a
crystalline silicon PV panel power output will decrease 60% - 80% when shadowed by a
typical cumulus cloud on a partly cloudy day. Just prior to the shadowing, the output may
actually increase above the clear-sky potential due to the reflection of light off of the side of
the cloud, intensifying ground-level solar irradiance. This peaking of output immediately
prior to the sharp decrease caused by shadowing increases the abrupt change in solar PV
power output. Partly cloudy conditions typically results in the most severe solar PV
variability. Heavily overcast days produce consistently low output from PV, and clear days
33
produce a smooth output curve over the day which does not result in flicker. For a fixed PV
array, the clear sky output looks like a sinusoidal half-wave. For two-axis tracking PV
arrays, the daily curve is broader, appearing more like a rounded-off square wave.
Figure 7 shows the variations in output of a small PV panel over the mid-day hours. The
variability in this example is extreme, with 80% output variations occurring as often as one
cycle per minute. If there were a large amount of solar PV generation on a feeder, and all
of this generation varied like this, in synchronism, the flicker impact would be severe. This
does not occur, however, because typical cloud shadows4 have physical dimensions less
extensive than the geographic footprint of a distribution feeder. If the PV is distributed
throughout the feeder’s served area, some PV panels will be shaded while others are in the
full sun during partly-cloudy conditions. Thus, there tends to be substantial geospatial
diversity in widely distributed PV generation. This is demonstrated in field results shown in
Figure 8. Solar irradiance measured at one point shows high variability, but the average
irradiance of 25 points in a 4km grid around the single point is much smoother. This is
further reinforced by the statistical correlation of short-term variations in solar irradiance,
versus distance between points, shown in Figure 9. Points that are very close together
have nearly a 100% correlation in output, but correlation drops rapidly, reaching zero at
400m, and actually going negative in the range of distances between 400 m and 1 km.
This means that for two points A and B, say 800 m apart, B is more than likely in the sun
when A is shaded, and vice versa.
(fromM. Grady, U. of T., Austin)
Figure 7
Output variations of a small PV panel
The degree of geographic diversity of PV generation on a feeder has a large influence on
the flicker impact. If there is a large amount of PV concentrated in one area, or one very
large installation, there is limited diversity and a large amount of power output variation,
which could lead to flicker if the location is far from the substation. On the other hand, small
PV that is widely dispersed will have little short-cycle variation.
4
Shadows of scattered to broken cumulus clouds, associated with the partly-cloudy conditions
responsible for periods of high solar variability
34
Designing effective and practically implementable flicker screening criteria can be
problematic. Consider this example: A small PV installation is unlikely to have a significant
flicker impact if all other PV installations on the feeder are of a similar small size. However,
the small PV could be interconnected near a location where a much larger PV has been
previously allowed to interconnect. If the impact of the large facility was very marginally
below the acceptable value, the incremental correlated contribution of the new small facility
may be sufficient to drive impact above the threshold of acceptability. Situations like this
present a particularly challenging dilemma in the design of screening criteria, requiring a
choice between simple screens through which a problematic interconnection could pass
through versus extensive data requirements and analysis to apply a more foolproof screen.
Figure 8
(fromPerez and Hoff)
Comparison of irradiance at one point compared with average irradiance of 25
locations in a 4 km square.
Figure 9
(from Perez)
Correlation of 20-second fluctuations in solar irradiance, as a function between
measurement points
35
2. Flicker Screening
It is assumed that the overwhelming majority of variable DG on Long Island will be solar;
thus the flicker screening process is based on available short-term solar variation
characteristics. For simplicity, the screen can be applied to all other forms of variable DG,
such as wind. Spatial correlations of short-term wind variations, at the heights of backyard
wind generators, are not available.
The first step to defining a flicker screen is to establish a geospatial “zone of correlation”
(ZOC), within which solar DG can be assumed to be well correlated in terms of the shortterm power variation that can lead to flicker. DG beyond this zone is assumed to be
uncorrelated. Figure 9 indicates a 400 m (~0.25 mile) radius of positive correlation. The
correlation is much less than one for most of this radius, so the effective radius would be
less. However, this graph is specifically for 20 second fluctuations. Somewhat longer
fluctuation periods are also of relevance to flicker, which would indicate a larger radius.
Such data are not available. Therefore, it shall be assumed that 0.25 miles is a reasonable
estimate of the effective radius of the ZOC for any fluctuation responsible for flicker.
Next, it is desirable to estimate the amount of variable DG that can be within this ZOC
without introducing risk of flicker. Flicker, at the primary voltage level, is substantially due to
the interaction of the real power variations with the resistive component of feeder
impedance. The amount of tolerable voltage variation is conservatively set at 0.5%. This
value is the “borderline of visibility” in the historic “GE flicker curve” found in IEEE Standard
519. The resistance of backbone feeders designed to LIPA’s standard is 0.3 ohm/mile.
The aggregate variable DG limit within the ZOC is calculated as:
0.3 ⋅ D
Vnom
2
PZOC
= 0.005
[3.8]
⋅ 1000
PZOC = 16.7 ⋅ Vnom / D
2
[3.9]
Where:
D is the feeder distance from the substation to the ZOC
Vnomis the nominal voltage of the feeder in kV (e.g., 13.8)
PZOCis the screening limit for variable DG (typically solar) in the zone of correlation
As an example, Equation 3.9 provides a screening limit of 1060 kW for a ZOC located three
miles from the substation.
When an interconnection is requested for a small variable DG, it is inconvenient to identify
and sum all other DG within a 0.25 mile radius. This step is not necessary if all variable DG
within the radius are smaller than a certain rating, because the maximum number of likely
36
DG within the radius can be conservatively estimated. A 0.25 mile radius encompasses
0.196 square miles, or 126 acres. Assuming a lot size of one-quarter acre, and further
assuming that space occupied by streets and other unavailable land halves the potential
DG density, a very conservative estimate is that there is a potential maximum of 252
variable DGs within the ZOC. Therefore, if no variable DGs within the ZOC exceed a rating
of PZOC/252, then further screening is not needed. If this test is not passed, then the sum
of all variable DG ratings within 0.25 miles need to be summed and compared with PZOC
as calculated by Equation 3.8.
Thus, the primary voltage flicker screen is:
ZOC
Max (P ) < P
var
ZOC
/ 252
or
∑ (P ) < P
var
ZOC
[3.10]
ZOC
Where Pvar are the individual DG ratings in the ZOC.
In addition to this screening for primary voltage impact, an additional screen is needed for
secondary voltage impact when the interconnecting variable DG is supplied by a
distribution transformer also serving other customers. Assuming a maximum distribution
transformer resistance of 2%IR, the recommended secondary voltage flicker screen is:
0.02*Psecv/Sxfmr<0.005which simplifies to: Psecv< 0.25*Sxfmr
[3.11]
WherePsecvis the sum of the variable DG ratings connected to the secondary of the
distribution transformer.
3. Harmonics
Considerable attention has been given to inverter-interfaced DG with regard to harmonic
distortion impact, primarily because there is an implicit assumption by much of the industry
that power electronic devices are inherently “dirty”. There is historical basis to this, as the
previous generations of thyristor and diode conversion equipment did indeed inject
substantial harmonic current. However, almost all inverters used for DG applications today
are based on voltage-source converter technology, with typically high switching
frequencies. Although currents within the VSC inverter are highly distorted, the high
frequency of that distortion makes filtering quite easy. DGs compliant with IEEE 1547, and
tested in accordance with IEEE 1547.1 and UL 1741, have quite low harmonic output
current. The harmonic distortion is far below many types of loads routinely connected to
the distribution system. For example, the harmonic distortion of compact fluorescent lamps
may exceed 100%, in comparison to the 5% total harmonic distortion (THD) limit set by
standards for DG.
The switching frequencies of various VSC inverter designs differ, and switching is usually
not synchronized to the 60 Hz waveform. Therefore, the harmonic contributions of multiple
VSC within the distribution system do not add arithmetically; in fact the injections of one
device may partially cancel another’s. This cancellation effect is particularly pronounced
above the 10th harmonic.
37
Using conservative assumptions, the voltage distortion produced by a 2 MVA standardscompliant inverter located at the remote end of a ten mile long 13.8 kV feeder is less than
the voltage distortion limit recommended by IEEE 519. Considering all the factors
discussed here, there does not appear to be justification to apply any screening criterion to
inverter-interfaced DG with regard to harmonic impact.
I.
System Loading
The general impact of DG on system loading is to cause a decrease in loading. Only certain
extreme scenarios can result in potential LIPA system overload. These include:
•
•
•
High penetration of DG distributed about the feeder overall, with total DG capacity
exceeding the sum of the feeder’s peak load plus the minimum load demand.
A very large concentration of DG, far exceeding local load demand, at the remote end of a
feeder
DG capacity in excess of the serving distribution transformer’s capacity
Other criteria established previously in this document, particularly the steady-state voltage
criteria, are more limiting. Thus, setting additional screens for system loading is unnecessary.
J. Fault Current Contribution and Protection
A significant feature of inverter-interfaced DG is its very low short-circuit contribution. Voltage
source inverters are typically controlled with a very fast-responding current regulation loop.
This fast response is necessary to protect the transistors used in these inverters, because the
overload capability of the transistors is very limited and even a very brief overload beyond a
critical value, on the order of twice rated current, will typically result in permanent failure.
Voltage source inverters will generally limit their current contribution to a fault to their rated
value, except for a transient excursion slightly above rated current for only about the first half
cycle. The inverters also tend to inject their current in phase with the voltage (unity power
factor), which is in quadrature to the predominately reactive nature of fault current.
As a bounding calculation, consider a 13.8 kV, 336 kcmil feeder that is ten miles long, with an
estimated impedance of 3 + j6 ohms, and a peak load of 10 MVA. The minimum load of this
feeder is postulated to be 40% of peak at 0.95 power factor. The minimum load is 4 MVA or 3.8
MW. Application of the steady-state voltage screening limit provided by Equation 3.3 indicates
that an aggregate DG rating of 1.3 MW or more would fail this previous screen. Thus, for the
feeder in this bounding calculation, the worst case with regard to incremental fault current
contribution by DG would be if a 1.3 MW DG is located at the feeder end where the grid
contribution to short circuit current is least. At this location, the fault current due to the grid
alone is 1,190 A, and the fault current contribution from the 1.3 MW DG is 54 A. If the DG
current injection is in quadrature to the grid fault current, the total fault current is increased only
0.1%, and if the DG contribution is perfectly in phase the fault current is only increased by
4.5%.
Therefore, it can be reasonably concluded that DG penetration passing other screens
recommended in this document will not materially affect fault currents and will neither interfere
with system protection nor require changes to protection settings.
38
K. Summary of Recommended Screens
The previous section identified a number of screens to identify inverter-interfaced DG
interconnections where a significant risk of system impact is present. These screens were
presented and discussed, organized by the different types of grid impact. Screens were, in
many cases, divided by type of DG and by whether the DG is served by a dedicated
distribution transformer. The screens are reorganized in this section and presented according
to the DG application, to facilitate use of these screens.
Solar DG
Solar DG interconnections do not require further study if the following screen is true.
If
Ptotal<0.33Pfdr_min_day
(Feeder steady-state voltage rise)
And if the proposed DG is on a lateral:
Plat<0.80Plat_min_day
(Lateral steady-state voltage rise)
And if the proposed DG is not on a dedicated distribution transformer:
(Secondary steady-state voltage rise)
Pdg< 0.052 SxfmrDfdr
And
DG is not downstream of a voltage regulator
(Secondary steady-state voltage rise)
And
DG is not on a feeder with clock-controlled capacitor banks
(Secondary steady-state voltage rise)
(Secondaryflicker)
AndPsecv< 0.25*Sxfmr
And:
(Reclosing)
Ptotal_sect<0.5Psect_min_day
And if:
ZOC
Max (P ) < P
var
ZOC
/ 252
or
∑ (P ) < P
var
ZOC
ZOC
(Primary flicker)
39
Non-Solar Variable DG
Non-solar variable DG primarily includes wind generation. An interconnection using this
technology does not require further study if the following screen is true.
If
Ptotal<0.33Pfdr_min_day
and
Ptotal_non-solar<0.33Pfdr_min
(Feeder steady-state voltage rise)
And if the proposed DG is on a lateral:
Plat<0.80Pflat_min_day
and
Plat_non-solar<0.80Plat_min
(Lateral steady-state voltage rise)
And if the proposed DG is not on a dedicated distribution transformer:
Pdg< 0.052 SxfmrDfdr
(Secondary steady-state voltage rise)
And
DG is not downstream of a voltage regulator
(Secondary steady-state voltage rise)
And
DG is not on a feeder with clock-controlled capacitor banks
(Secondary steady-state voltage rise)
And
Psecv< 0.25*Sxfmr
(Secondaryflicker)
And:
Ptotal_sect<0.5Psect_min_dayandPtotal_sect_non-solar<0.5Psect_min
(Reclosing)
And if:
ZOC
Max (P ) < P
var
ZOC
/ 252
or
∑ (P ) < P
var
ZOC
ZOC
(Primary flicker)
40
Non-Variable DG
Non-variable DG are those inverter-interfaced DG fueled by resources that are reasonably
consistent in supply. Examples are microturbines fueled by natural gas or landfill gas. DG
interconnections in this category do not require further study if the following screen is true.
If
Ptotal<0.33Pfdr_min_day
and
Ptotal_non-solar<0.33Pfdr_min
(Feeder steady-state voltage rise)
And if the proposed DG is on a lateral:
Plat<0.80Pflat_min_day
and
Plat_non-solar<0.80Plat_min
(Lateral steady-state voltage rise)
And if the proposed DG is not on a dedicated distribution transformer:
Pdg< 0.052 SxfmrDfdr
(Secondary steady-state voltage rise)
And
DG is not downstream of a voltage regulator
(Secondary steady-state voltage rise)
And
DG is not on a feeder with clock-controlled capacitor banks
(Secondary steady-state voltage rise)
And:
Ptotal_sect<0.5Psect_min_dayandPtotal_sect_non-solar<0.5Psect_min
(Reclosing)
41
Summary of Variable Definitions
Dfdris the distance, in thousands of feet, along the main feeder from the substation to the
distribution tranfsformer, or to the lateral tap on the main feeder if the distribution transformer is
located on a lateral.
Ptotalis the sum of all the DG ratings connected to the feeder, including the DG under screening
Pfdr_minis the minimum load demand of the feeder.
Ptotal_non-solaris the sum of all the DG ratings, other than solar, connected to the feeder, including
the DG under screening if it is non-solar
Pfdr_min_dayis the minimum load demand of the feeder during daylight hours (nominally, between
7 a.m. and 7 p.m.).
Platis the sum of all the DG ratings connected to the lateral, including the DG under screening
Plat_non-solaris the sum of all the DG ratings, other than solar, connected to the lateral, including
the DG under screening if it is non-solar
Plat_min_dayis the minimum load demand of the lateral during daylight hours (nominally, between
7 a.m. and 7 p.m.).
Plat_minis the minimum load demand of the lateral
Pdgis the sum of all the DG ratings connected to the secondary of the distribution transformer
Sxfmris rating of the distribution transformer
Ptotal_sectis the total DG capacity on the feeder section, solar plus non-solar.
Ptotal_sect_non-solaris the total non-solar DG capacity on the feeder section.
Psect_minis the absolute minimum load demand of the feeder section.
Psect_min_dayis the absolute minimum daytime load demand of the feeder section.
PZOCis the screening limit for variable DG (typically solar) in the zone of correlation, and is equal
to:
PZOC = 16.7 ⋅ Vnom / D
2
Where:
D is the feeder distance from the substation to a ZOC (0.25 mi radius around point of
interconnection of the proposed DG)
Vnomis the nominal voltage of the feeder in kV (e.g., 13.8)
Pvar are the individual DG ratings in a ZOC.
Psecvis the sum of the variable DG ratings connected to the secondary of the distribution
transformer.
42
VI. Maintenance and Operating Requirements
The following requirements apply to all DG System installations.
A. The protective devices (relays, circuit breakers, etc.) required to disconnect the DG
System's generation shall be owned, operated, and maintained by the DG System at its
expense.
B. All final relay setting calculations for the DG System's interconnection breaker shall
be submitted for review and acceptance by LIPA, to assure protection of LIPA
equipment and reliability of service to the adjacent LIPA customers. The DG System
shall be required to change relay settings, if necessary, to accommodate changes in
the LIPA system.
C. If the DG Systems elects to install a solidly grounded neutral, LIPA will require that it
be tested every 2 years and that the test reports be submitted to LIPA.
D. It shall be the DG System's responsibility to have calibration and functional trip tests
performed on its fault and isolation protection equipment. These tests shall be
performed prior to placing equipment in service and once every two (2) years thereafter.
Copies of these test results shall be sent submitted to LIPA no later than five working
days after completion of tests. All the testing and calibration shall be performed by a
qualified independent testing organization, acceptable to LIPA, in accordance with
industry standards and shall be submitted to LIPA for review and acceptance.
Interconnection breaker speed curves shall be verified using a Cincinnati Analyzer or an
equivalent. Battery tests shall meet the requirements of IEEE Standard 450-1987.
LIPA reserves the right to witness and accept or reject the results of all tests. LIPA shall
be notified of the testing two (2) weeks in advance.
E. After the DG System is in service, LIPA reserves the right to test or review on request
the calibration and operation of all protective equipment including relays, circuit
breakers, batteries, etc. at the interconnection, as well as review the DG System's
complete maintenance records. A review of the calibration and operation of protective
equipment may include LIPA-witnessed trip testing of the interconnection breaker from
its associated protective relays.
F. The failure of the DG System to maintain its equipment in a manner acceptable to LIPA
or to furnish maintenance records on demand may result in the DG System being
prevented from operating in parallel with the LIPA system.
43
G. If LIPA is requested to work at the DG System's generating site, LIPA operating and
maintenance personnel shall inspect the site to insure that all LIPA safety requirements
have been met. If not, commencement of the requested work shall be delayed until
conditions are deemed safe by LIPA.
H. LIPA reserves the right to test for or to request the DG System to supply certified test
reports for harmonic content at the point of interconnection. The % Total Harmonic
Distortion (THD) measurements shall be taken with a spectrum analyzer. Inverter
installations shall be required to take two sets of measurements; one with the inverter
isolated and the other with the inverter connected to the LIPA system. The current
harmonic levels should be observed and recorded at 0, 1/2, 3/4, and full power
measurements.
If the % THD exceeds the limits outlined in Section II Part E the DG System shall
install filters to meet the required limits.
If at any time during parallel operation harmonic distortion problems affecting other
customers' equipment can be traced to the DG System's generator, the DG
System's generating equipment shall be immediately disconnected from the LIPA
system and shall remain disconnected until the problem is corrected.
I.
The DG System shall close the interconnection circuit breaker only after obtaining
approved switching orders from the responsible LIPA operator as defined in the
Operating Instructions. No automatic reconnect shall be incorporated in the design.
LIPA reserves the right to open the disconnecting device to the DG System for any of
the following reasons:
1.
System Emergency or System Pre-Emergency
2.
Substandard conditions existing with the DG System's generating and/or
protective equipment.
3.
Failure of the DG System to maintain its equipment in accordance with the
agreed upon schedule.
4.
Failure of DG System to make maintenance records available to LIPA on
request.
5.
Interference by the DG System's generation system with the quality of service
rendered by LIPA to its customers.
6.
Personnel safety.
7.
To eliminate conditions that constitute a potential hazard to the general public.
8.
For LIPA maintenance and construction clearance.
44
VII. Classification of DG System Generator Installations
Distributed Generation installations are classified into two types - those interconnecting to the LIPA
system on a dedicated radial feeder and those interconnecting on a non-dedicated feeder (Refer to
Appendix A).
Maximum Gross Generation Capacity*
Distribution Voltage
Interconnection
13kV
4kV
10MVA
3MVA
Main
3.0 MVA
1MVA
Branch
1.5 MVA
.5 MVA
1.5 MVA
.5 MVA
Main
2.5 MVA
750KVA
Branch
1.0 MVA
300 kVA
Main
1.5 MVA
750 kVA
Branch
1.0 MVA
300 kVA
1.
Dedicated Radial Feeder
2A.i
Synchronous Generators
Non-Dedicated Feeder
2A ii. Primary Metered Secondary Protection
2B.i
Induction Generators
Non-Dedicated Feeder
2B. ii Induction Generators Non-Dedicated
Primary Metered Secondary Protection
* These generation capacities are on a per-Producer basis. It should be noted, however, that the
aggregate generation (sum of the total gross generation of all DG Systems connected to a
particular segment of the LIPA system) on a non-dedicated distribution feeder must not exceed 5
MVA on 13 kV or 1.5 MVA on 4 kV. The maximum capacity of the aggregate generation
connected to a branch circuit is 1.5 MVA on 13 kV and .5 MVA on 4 kV. The maximum aggregate
generation connected to one LIPA 13 kV substation is 10 MVA. The maximum aggregate
generation connected to one LIPA 4 kV substation is 3 MVA. The maximum aggregate generation
shall also be limited to approximately one-third of the MVA rating of the step-down transformer at
LIPA's substation.
The aggregate generation may be further limited by the load and fault duty capability of the
substation equipment and connecting distribution feeder. LIPA shall evaluate each application
before deciding on the maximum MVA allowed onto the LIPA system at a given point.
Special relay coordination problems may exist for non-dedicated feeder installations since all DG
Systems may not be on-line at the same time. Each situation shall be evaluated on its own merits.
45
VIII. Appendix
Appendix A
Interconnection Example Drawing List
1.
Dedicated Feeder Relay Circuit Greater Than 1,000 Feet
Primary Metered - Primary Protection
2.
Dedicated Feeder Differential Circuit Less Than 1,000 Feet
Primary Metered - Primary Protection
3.
Non-Dedicated Feeder Primary Metered - Primary Protection
4.
Non-Dedicated Feeder Primary Metered - Secondary Protection
These drawings are examples of typical interconnections. Each project is site specific and
may have different requirements.
46
APPENDIX A-DRAWING 1
PRIMARY METERED- PRIMARY PROTECTION
48
APPENDIX A - DRAWING 2
PRIMARY METERED- PRIMARY PROTECTION
49
APPENDIX A-DRAWING 3
PRIMARY METERED- PRIMARY PROTECTION
50
51
Appendix B
Explanation of the Requirement for
A Wye Grounded Transformer
All DG System interconnections with LIPA must be grounded sources. During a phase to ground
fault on the LIPA system, the DG System's generator can be isolated with the phase to ground fault
if the LIPA source opens before the DG System's protective equipment detects the fault condition
and isolates from the LIPA system. If the generator is not grounded during the period it is isolated
with the phase to ground fault, the neutral can shift resulting in overvoltage on the two remaining
unfaulted phases. This overvoltage can reach 173% of normal and will damage LIPA phase to
ground connected load or equipment isolated with the generator. To avoid the possibility of an
overvoltage due to a neutral shift, LIPA requires that the DG System's generator interconnect into
the LIPA system as a grounded source.
The designer of the DG installation should be aware that the isolation transformer provides a path
for zero sequence fault current for all phase to ground faults on the circuit. In order to limit the
ground fault current from the DG System's equipment, LIPA may require that the system be
designed to limit the zero sequence current (large zero sequence impedance) and still meet the
grounding requirements.
There are several methods to ground a source. Accepted method is to use a wye groundeddelta step-up transformer with the generator grounded.
An additional purpose of the wye-grounded (LIPA side)/delta (DG System side) isolation
transformer is to filter out the third harmonics and multiples of the third harmonics and to provide a
ground source that enables the DG System(s) protection to be able to detect faults on the LIPA
system.
51
Appendix C
53
Appendix D
This Appendix is blank Not used
53
Appendix E
Voltage Flicker Curves
54
Appendix F
Relaying Functional Example
I
I
TD
TD
(1)
(3)
50
50
51
51N
600/5
ICO
79Y
UNIT
#4
S
TD
PB
TD
SUPV.
0-600
R
A
600/5
TD
CURR
AM
TDCR
(3)
2000/5
AR
95
RFL 6745
D.T.T. XMIT
GROUP 2
LEASE
LINE
NOTE: This is a sample of an acceptable Relaying Functional Diagram, and shall only be used for
reference purposes.
55