Download P1547-6-Minutes-20060804 - IEEE Standards working groups

MINUTES OF P1547.6 MEETING
(Presented as Annotated Agenda)
P1547.6 Meeting Aug 3–4, 2006
IEEE P1547.6 Draft Recommended Practice for Interconnecting Distributed Resources
with Electric Power Systems Distribution Secondary Networks
Las Vegas NV, Embassy Suites Convention Center
J. Koepfinger, Chair [email protected] J. Bzura, Vice Chair [email protected]
T. Basso, Secretary [email protected]
August 3, 2006 Thursday 8 a.m.–5 p.m.
8–8:30 a.m. Arrive/Register
8:30–9:15 a.m.





Welcome/introductions.
Presentation of P1547.6 and IEEE background material and draft agenda for meeting.
Past minutes presentation and approval.
Agenda review and approval.
John Bzura introduced the scope of the work for the day (see Annex B). He indicated that papers had
been presented by Murray Davis and Jim Daley and that Mr. Ferro would make a presentation on his
work on network interconnections.
9:15–10:30 a.m.

Status report on material for P1547.6 proposed new outline clauses: J. Koepfinger, J. Bzura, and
writing team leads (approximately 30 minutes each), including team leaders’ responses to minutes
February 2006 action items (minutes annexes F and G).
o
Clause 7, “Overview of Network Distribution Systems: Design, Components and
Operation”
 Mr. Peterson discussed the work that has been done on this clause.
 For details, see Annex C.
o
Clause 8, “Primary Concerns of Operating DR on Networks”
 Presentation made by Mr. Moh Vaziri.
 See Annex D for the presentation material.
o
Clause 9, “Fundamental Requirements for Interconnection of DR on Networks”
 Presented by Dr. Bzura.
 See Annex E for the presentation material.
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
1
o
Clause 10, “Procedures to Alleviate Concerns of Operating DR on Networks”









The presentation was made by Mr. Davis.
See Annex F for presentation material.
Methods to solve DR interconnections to networks were presented.
NP will open on about 5% reverse power.
Network relay can determine the difference and between reversed fault current
from Dr generation and reverse load current.
Spot Network solutions were discussed. Clearing time is 3–5 cycles. Some
clearing times may approach 20 cycles. Time delay is sometimes used to
coordinate NP with DG protection. Another solution is not to connect the DR
directly to the network but connect it to an independent network feeder. One of the
solutions was to take a trip signal from the NP to trip the DR if any of the DR saw
reverse flow.
In another installation, use was made of a Solid States Switch to switch the
generator of the network to its dedicated load on reverse flow through the NP.
Use of FO is possible as a channel for transfer trip. As the customer load
decreases, the output of Dr is reduced to keep a fixed ration between DR output
and customer load.
There should be a note in the document that network grid DR connections are
limited to none export applications.
 MTC Proposed R&D to Advance DR/Network Interconnections – William Ferro
See Annex G for presentation material.
This presentation discussed work done for a Northeast utility to develop a recommended practice for
the interconnection of DR to spot networks that would not require the use of time delay of the NP to
coordinate with the DR protection during a low reverse flow through the NP.
Techno-economic issues yet to be discussed include:
o
o
o
o
How to select the low reverse power setting for various types of DR
Guidance on how to select the minimum necessary time delay to avoid false tripping of the
NP
DR size restrictions
Caution on using the time delay technique, e.g. evolving faults and cross-town faults.
Techno-legal issues yet to be discussed include:
o De facto giving reverse power tripping control to a non-utility entity when the DR or
facilitator owns and maintains the circuits which determine when a network under
power limit has been reached.
o Migrating this exposure to a non-utility protective function failure by limiting the
size of the DR that can be interconnected to less than the minimum spot network
load.
o The non-time delay method is the use of breaker duty relief scheme, where the
tripping of the NP is interlocked with the DR isolating device. This tripping is
sequential.
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
2
o The method for accomplishing a highly reliable scheme is posted on Massachusetts
Technology Collaborative website: www.masstech.org/dg/collab.reports.htm.
12–1:15 p.m. Lunch
1:15–5 p.m.

Breakouts for proposed new outline clauses 7–10. All WG members joined a group to review
proposed clause outline and initial material, draft detailed proposed sub-outline, and draft revised and
new material for respective clauses 7–10.
August 4, Friday 8 a.m.–3 p.m.
8–8:30 a.m. Arrive/Register
8:30–10:15 a.m.

Status reports by breakout leaders (20 minutes each), including progress, recommendations, and
discussion questions for consideration by the WG as a whole.
o Clause 7, presented by J. Koepfinger and R. Peterson
This is complete except for the art work. A request was made for art work. Before it can
be circulated, it will be necessary to include the graphics mentioned in the clause. See
Annex H for this material.
o Clause 8, presented by Moh Vaziri




30 issues were presented and discussed.
The material presented is in Annex I.
It was suggested that the material should avoid saying who should do what.
The task force draft will be rewritten to take into consideration a concern that it
should not appear to be of the nature that its sounds like a directive for EPS
operations.
o Clause 10, presented by Dr. Bzura
 Clause 9 has been integrated into Clause 10.
 The discussion material is found in Annex J.
10:15 a.m.–Noon


Open discussion of P1547.6 topics and recommendations – J. Koepfinger.
Presentation and discussion of the draft P1547.6 extended outline (based on 8/05 and 2/06 WG
meetings and yesterday’s breakouts sessions) – John Bzura and Joe Koepfinger.
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
3
Noon–1:15 p.m. Lunch
1:15–1:45 p.m.
 Summarize action items, plans, and the proposed next meeting.
1:45–3 p.m. (Adjourn)
 Breakout sessions reconvene based on morning’s discussions.
Respectfully Submitted,
Joe Koepfinger – Chair P1547.6; John Bzura – Vice Chair, Tom Basso – Secretary, and Amy
Vaughn – NREL Communications Specialist.
------------------------- see annexes for further details -----------------List of Annexes:
Annex A:
Annex B:
Annex C:
Annex D:
Annex E:
Annex F:
Annex G:
Annex H:
Annex I:
Annex J:
Attendees: P1547.6 Meeting, Las Vegas, Nevada, August 1–4, 2006
P1547.6 Draft Outlines
P1547.6 Clause 7 Pre-Breakout Status Report
P1547.6 Clause 8 Pre-Breakout Status Report
P1547.6 Clause 9 Pre-Breakout Status Report
P1547.6 Clause 10 Pre-Breakout Status Report
Bill Feero Network Interconnection Presentation
P1547.6 Clause 7 Post-Breakout Status Report
P1547.6 Clause 8 Post-Breakout Status Report
P1547.6 Clauses 9 & 10 Post-Breakout Status Report
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
4
ANNEX A:
ATTENDEES: P1547.6 MEETING
LAS VEGAS, NEVADA, AUGUST 1–4, 2006
Joe Koepfinger – Chair
David Beach
James Daley
Murray Davis
Richard DeBlasio
Andris Garsils
C. Travis Johnson
John Bzura – Vice Chair
Mike Miller
Jock Moffat
George Moskos
Robert Peterson
Amy Vaughn
Mohammad Vaziri
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
Tom Basso – Secretary
Tim Wall
James Watts
Charles Whitaker
Steve Chalmers
Bill Feero
5
ANNEX B:
P1547.6 DRAFT OUTLINES
IEEE P1547.6 Initial Draft Outline
(August 5, 2005)
1. Introduction
2. Scope
3. Purpose
4. Limitations
5. References
6. Definitions/Acronyms
7. Types/characteristics of network and control systems
7.1. Spot networks
7.1.1 Consideration for integration of DR into spot networks
7.1.1.1. Map 1547 requirement to networks
7.1.1.2. Planning consideration
7.1.1.3. Protection Considerations and settings – impact of DR on
7.1.1.4. Communication Considerations
7.2. Grid Networks
7.2.1. Consideration for Integration of DR into spot networks
7.2.1.1. Map 1547 requirements to networks
7.2.1.2. Planning consideration
7.2.1.3. Protection consideration – impact of DR on
7.2.1.4. Communication considerations
8. Essential issues to be addressed for interconnection of DR on networks
8.1. Spot network
8.2. Grid network
Annex A – Bibliography
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
6
Proposed Draft Outline Revisions
J. Bzura
P1547.6 Meeting Atlanta GA; February 2-3, 2006
7. Overview of Network Distribution Systems: Design, Components and Operation
(Joe Koepfinger, Martin Baier, Dave Costyk, Jim Daley, Bob Peterson,
Betty Tobin )
7.1 Spot Networks
7.2 Area Networks
8. Primary Concerns of Operating DR on Networks
(Moh Vaziri, Larry Gelbien, F. Bigenho, Jim Watts, Tim Wall, Dan Sammon,
Chuck Whitaker, Travis Johnson, David Smith, other volunteers)
8.1 Reverse power flow
8.2 Fault current contributions
8.3 Effects of DR on area network load flows
8.4 Effects of potential network system component failures
9. Procedures to Alleviate Concerns of Operating DG on Networks
(Murray Davis, John Bzura, Marty Baier, Murray Davis, Jim Daley, Jock Moffat,
David Beach, Larry Gelbien, Moh Vaziri, Sam McAllister, _ Ebrahim, Tom Greely,
other volunteers)
9.1 Measures to sense and ameliorate (prevent) reverse current flow
9.1.1 Minimum power level DR trip
9.1.2 Reverse power flow sensing for DR trip
9.2 Fault current minimization
9.2.1 Limitation by DR technology
9.2.2 Limitation by switching technology
9.3 Site-specific analysis of DG on area networks (Larry G to lead?)
9.4 Coordination of DR with network operations (Murray D to lead?)
9.4.1 monitoring and control specific to DR on networks
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
7
10. Requirements for Integration of DG on Networks
(John Bzura, Martin Baier, Murray Davis, Jim Daley, Jock Moffat, David Beach,
Larry Gelbien, Moh Vaziri, Sam McAllister, _ Ebrahim, Tom Greely)
10.1 Fundamental Hypothesis
The primary function of a protective relay and control scheme for a proposed DG unit
operating in parallel with a network grid is to separate the power source from the network
immediately* on the occurrence of any anomaly in the network voltage, frequency or power flow
direction.
10.2 Reverse Power Flow Criteria
The Interconnection System (IS) shall prevent the occurrence of reverse power flow
through the network protector(s) under all normal conditions and absolutely minimize reverse
power flow under adverse conditions such that network protector capability is never impaired.
There shall be at least two independent subsystems employed in the IS to accomplish this
requirement.
10.3 Fault Current Contribution Criteria
The IS will respond to any indication of a fault on the network by immediately*
disconnecting the DG unit from the network so that the fault current contribution from the DG
unit is either zero or minimized to the point of being inconsequential.
10.4 Area Network Load Flow Analysis and Conclusion
The utility customer or the customer’s agent will work with the utility to analyze network
load flow parameters at the proposed DG site to determine whether the proposed type of DG unit
can be accommodated for operation. If the conclusion is negative, alternative measures such as
reconfiguration for a radial interconnection shall be evaluated.
_________________
* Immediately is defined for present purposes as within 3 cycles (50 milliseconds).
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
8
(Missing Pages 10 – 13)
Proposed Draft Outline Revisions -- J. Bzura
P1547.6 Meeting Las Vegas, NV; August 3–4, 2006
Slide 1
2nd REORGANIZATION OF P1547.6 - AREAS 7 – 10
7. Overview of Network Distribution Systems: Design, Components and Operation
(Joe Koepfinger, Bob Peterson, Martin Baier, Dave Costyk, Jim Daley,
Betty Tobin )
8. Primary Concerns of Operating DR on Networks
(Moh Vaziri, Jim Watts, F. Bigenho, Tim Wall, Dan Sammon,
Chuck Whitaker, Travis Johnson, David Smith, other volunteers)
9. Fundamental Requirements for Interconnection of DR on Networks
(John Bzura …, Murray Davis, Martin Baier, Jim Daley, Jock Moffat, David
Beach, Moh Vaziri, Sam McAllister, Mohammed Ebrahim, Tom Greely)
10. Procedures to Alleviate Concerns of Operating DR on Networks
(Murray Davis, Jim Daley, Jock Moffat, John Bzura, Marty Baier, David Beach,
Moh Vaziri, Sam McAllister, Mohammed Ebrahim, Tom Greely, others)
8/06 P1547.6 MTG
J. J. BZURA
1
Slide 2
2nd REORGANIZATION OF P1547.6 - AREAS 7 – 10
7. Overview of Network Distribution Systems: Design, Components and Operation
(Joe Koepfinger, Bob Peterson, Martin Baier, Dave Costyk, Jim Daley,
Betty Tobin )
7.1 Spot Networks
7.2 Area Networks
8. Primary Concerns of Operating DR on Networks
(Moh Vaziri, Jim Watts, F. Bigenho, Tim Wall, Dan Sammon,
Chuck Whitaker, Travis Johnson, David Smith, other volunteers)
8.1 Reverse power flow
8.2 Fault current contributions
8.3 Effects of DR on area network load flows
8.4 Effects of potential network system component failures
8/06 P1547.6 MTG
J. J. BZURA
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
2
9
Slide 3
2nd REORGANIZATION OF P1547.6 - AREAS 7 – 10
9. Fundamental Requirements for Interconnection of DR on Networks
(John Bzura …, Murray Davis, Martin Baier, Jim Daley, Jock Moffat,
David Beach, Moh Vaziri, Sam McAllister, M. Ebrahim, Tom Greely)
9.1 Separation Requirement
9.2 Prohibition of Reverse Power Flow
9.3 Fault Current Contribution Limit
9.4 Determination of DR Interconnection Feasibility
8/06 P1547.6 MTG
J. J. BZURA
3
Slide 4
2nd REORGANIZATION OF P1547.6 - AREAS 7 – 10
10. Procedures to Alleviate Concerns of Operating DR on Networks
(Murray Davis, Jim Daley, Jock Moffat, John Bzura, Marty Baier, David Beach,
Moh Vaziri, Sam McAllister, Mohammed Ebrahim, Tom Greely, others)
10.1 Measures to sense and limit reverse power flow
10.1.1 Minimum power level DR trip
10.1.2 Reverse power flow sensing for DR trip
10.2 Fault current minimization
10.2.1 Limitation by DR technology
10.2.2 Limitation by switching technology
10.3 Site-specific analysis of DR on area networks (Moh V to lead?)
10.4 Coordination of DR with network operations (Murray D to lead?)
8/06 P1547.6 MTG
J. J. BZURA
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
4
10
Slide 5
2nd REORGANIZATION OF P1547.6 - AREAS 7 – 10
9.1 Separation Requirement
On the detection of any anomaly in the network voltage, frequency or power
flow direction, the Interconnection System (IS)* shall separate the DR unit from
the network within 3 cycles.**
9.2 Prohibition of Reverse Power Flow
The IS shall prevent the occurrence of reverse power flow through any
network protector under all normal conditions of voltage and frequency. There
shall be at least two independent subsystems within the IS to accomplish this
requirement. Optional sentence – During abnormal conditions, reverse power
flow shall be limited to X% of the network protector rating and be curtailed within
3 cycles.**
*The Interconnection System (IS) is defined as a protective relay and
control scheme designed to allow operation of a DR unit in parallel with a
network grid.
** The exact number is open for discussion.
8/06 P1547.6 MTG
J. J. BZURA
5
Slide 6
2nd REORGANIZATION OF P1547.6 - AREAS 7 – 10
9.3 Fault Current Contribution Limit
During a fault on the network, the IS shall limit the initial fault current
contribution from the DR unit to Y%** of the normal network protector rating, and be
curtailed within 3 cycles.** For network protector circuits already at 100% of
calculated fault current capacity, the DR fault current contribution shall be 0%.
*The Interconnection System (IS) is defined as a protective relay and control
scheme designed to allow operation of a DR unit in parallel with a network grid.
** The exact number is open for discussion.
8/06 P1547.6 MTG
J. J. BZURA
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
6
11
Slide 7
2nd REORGANIZATION OF P1547.6 - AREAS 7 – 10
9.4 Determination of DR Interconnection Feasibility
The utility customer or the customer’s agent will work
with the utility to analyze network load flow parameters at
the proposed DR site to determine whether the proposed
type of DR unit can be accommodated for operation. If the
conclusion is negative, alternative measures such as
reconfiguration for a radial interconnection shall be
evaluated.
8/06 P1547.6 MTG
J. J. BZURA
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
7
12
ANNEX C:
P1547.6 CLAUSE 7 PRE-BREAKOUT STATUS REPORT
P1547.6 – proposed Clause 7 “Overview of Network Distribution Systems: Design,
Components and Operation.
Initial draft by Bob Peterson with comments by Joe Koepfinger and responses by Bob.
[email protected] [mailto:[email protected]]
----------------------- --------------------------------- ------------------------------------
An Overview of Network Distribution Systems: Design, Components and Operation
Background Discussion:
Low voltgage alternating current networks were first developed in the 1920’s to provide highly
reliable electric service to concentrated load centers mainly in the downtown areas of major
cities. There are two types of low voltage networks, the secondary network (also referred to as
an area network, grid network or street network) and the spot network. For the purpose of this
guide secondary network will be referred to as a grid network. A minimum of two primary
feeders are required to supply a network, The number of feeder to a network is dependent upon
load requirement of the grid network or the spot network load.
The grid network may consist of more that one area that are operated independently from each
other. Several separate grids can be used to form the low voltage network within a city.
Customers in a low voltage network area are typically take service from the network at the grids
voltage level. In some cases large buildings may have a separate service not connected to the
grid, this are called spot networks High reliability is achieved by designing the system to carry
full load with n-1 primary feeder out of service and by rapidly removing any faulted primary
feeder or transformer connection to the low voltage network.
NETWORK TRANSFORMERS:
Network transformers are typically liquied filled and air cooled, although some dry type network
transformers have been used. Historically they were filled with a fluid that contained PCB’s
continued use of such transformer is required by regulations to have lower thatn 100 ppm PCB,
In most cases the coolant has a low flammability but newer units can be strictly mineral oil or be
silicone filled. Newer vegetable oil based coolant with low flammability show promise for use
in network transformers.
(1. Joe: As I remember it wasn’t necessary to remove or retrofil the 120/208 Volt PCB
filled network transformers. I think all you had to do was set-up a monitoring program for
the transformers. At ComEd we chose to replace the 120/208 volt transformers and
perhaps so did everyone else.)
The network transformer may have a manually operated primary oil switch located directly on
the transformer, which can be in the closed, opened or grounded position The network
transformer is equipped network protector (explained later) mounted directly on the transformer
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
13
or mounted within close proximity of the transformer. In this latter case it is cable connected to
the transformer. . Typical network transformer secondary voltages are 120/208Y and 277/480Y
volts. The primary of the network transformer my be connected either in delta or ungrounded
wye. The secondary of the network transformer is usually connected ground wye. to supply
120/208Y or 277/480Y voltage to the grid network or the spot network customer.
(2. Joe: You mentioned ungrounded wye. We had some that were connected grounded
wye. Might be worth asking how the other utilities with wye network transformers run
them.)
SPOT NETWORKS:
A spot network consists of two or more network transformers connected by a common bus at a
single location, such as in the basement of a building. In normal operation, all the spot’s network
transformers will be feeding the bus simultaneously, from their respective primary feeders. The
building may have additional spot networks on upper floors, but there is no connection between
the vaults on the secondary side. Spot networks are installed with secondary voltages of
120/208volts and 277/480 volts.
“PICTURE OF A SPOT NETWORK”
In order that the spot network can continue to operate if a primary feeder becomes faulted, each
network transformers is equipped with a network protector containing a low-voltage circuit
breaker,and a protective package. The protective package includes a network relay or master
relay that is sensitive to directional real and reactive power flo. It senses the reverse flow
through the transformer for feeder fault or flow due to ythe feeder changing current or
transformer magnetizing current. This protection operates to cause the network breaker to open
and isolate the initiating condition. The network relay is a very sensitive reverse-power relay,
with a pickup level on the order of 1 to 2 kW. It is the mission of the reverse power relay to be
capable of sensing reverse power flow with no other feeder loads than the core losses of its own
network transformer (With delta primary network transformers, little to no fault current will flow
for a primary phase to ground fault.).
Network protectors by themselves do not contain any forward looking over current protection.
In many cases fuses are installed in series with the network protector. This fuse is sized well
above the capability of one transformer and will have limit capability to operate for arcing type
faults that are the most common in the network vault. It will operate for a bolted three phase
fault within the vault. Multiple sets of secondary cables are typically installed between the
network protector and the collector bus. These may be protected with inline fuses called cable
limiters on each end, such that cable faults are isolated by the limiters. Limiters may also be
installed on the service cables going to the customer’s switchgear. The primary pjurpoes of a
limiter is to protected the conductors of a cable from thermal damage.
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
14
(3. Joe: I don’t recall that cable limters provided cable overload protection. In the old
Westinghouse T&D book it stated that limiters are installed to isolate cable faults and to
protect the cable insulation from damage from the fault current.)
The master relay also has another function, which is to supervise the closing of the network
protector. The relay looks at the voltage on both side of the protector and if the transformer side
is higher than the bus side (by perhaps 1 volt) the first close criteria is met. Next the phasing
relay looks for the proper phase rotation between the two voltages before allowing the protector
to close. Closing will occur if the two voltages are basically in phase with one another.
A spot network is supplied by two or more primary distribution circuits, from a single substation
and single bus section or multiple bus sections with closed bus ties. Occasionally feeders from
separate substations have been used, but the flow of circulating currents between substations can
result in excessive protector operations (Especially at light load). Primary feeders at the
substation typically will have time-overcurrent phase and ground protection to see faults on the
circuit. They may have an instantaneous ground element set to see faults on the primary side of
the network transformer. Delta – wye connection of the network transformers limit the reach of
the ground relays on one primary network feeder from seeing ground faults on the primary of
another primary network feeder and over-tripping. Typically the substation relaying will not see
faults on the secondary side of the transformer and considerable damage has occurred in vaults
before any of the protection operates. “IEEE Guide for the Protection of Network Transformers”
C37.108 goes into much more sophisticated schemes of protection, but is beyond the scope of
this short discussion on networks.
SECONDARY NETWORK GRIDS:
A network grid could be thought of as several spot networks tied together with secondary cables.
The low voltage cables may have customer service cables connected in manholes between the
network transformer vaults. With a secondary network grid, it isn’t always necessary to put a
minimum of two transformers in a vault, as the secondary cables (fed by network transformers
connected to alternate primary circuits) can supply the load for a transformer or primary feeder
outage. Transformers are located at various locations throughout the grid to supply power and
support the grid voltage as required per studies. The same transformers and network protectors
are used here as with Spot networks. Secondary grid networks are typically 120/208 volts
although some 277/480 volts systems were developed. Secondary grids typically have multiple
sets of secondary cables per phase running between network transformers” secondary. These
cables can have inline fuses (Cable limiters) installed at each end to isolate a faulted cable and
provide thermal overload protection for the cables without interrupting customers or the grid. If
limiters are not present or the limiters don’t function the cables will burn clear for a fault. The
number of sets of low-voltage cables installed is determined by performing load flow studies
both under normal and emergency conditions to avoid conditions that would result in overload
conditions for both normal and emergency conditions. Emergency condition are passed on
planning criteria established by the Area EPS.
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
15
(4. Joe: With paper lead cable our old philosophy for 120/208Volts was not to have limiters
installed and to let the cable burn the fault clear. The old Westinghouse T&D book stated
that limiters were developed and first applied in New York City in 1936. It also stated that
with paper lead cable faults will burn clear if there is sufficient fault current. We install
limiters when the cable is replaced with plastic insulated cables. The Westinghouse book
also states that at 480 volts the cable may not burn clear and that limiters should be
installed.)
“PICTURE OF A GRID NETWORK”
Different planning strategies may exist for a secondary grid network, but a typical scenario
would be to allow for one primary circuit to be out of service (faulted) at peak load times and
two primary circuits to be out of service (one for maintenance with a subsequent fault occurring
on another) at non-peak times. Load flows must be run for all these scenarios, to insure
customers receive adequate voltage and no equipment is overloaded. With the criteria stated
above, the minimum number of feeders required for a network grid system is three but systems
with more than 20 feeders exist. If the primary feeders come from different bus sections at a
substation or different substations, a bus outage that can take out two or more network feeders
must be considered in the load flows to see that a single contingency such as this does not cause
network problems.
It might be thought that utilities have instant access to loads and load flow directions as well as
voltages on the grid. At most utilities this is not the case. The utility typically only has access to
peak loads that occurred at the network center without any time stamp and customer peak
demands, with or without time of day depending on the size. Periodic voltage measurements are
made on the grid, but may not correspond to when specific load data was extracted. The utility
also has substation loads for the primary feeders that are part of the grid. From this type of data
the utility engineer is expected to run a load flow and plan secondary network grid upgrades.
Without proper monitoring, distributed generation will lend another item of uncertainty in
planning the grid. It will also complicate the running of load flows. Each load flow scenario
must be run with the generator on and the generator off, as the utility has no control of forced
DG outages.
OPERATION:
Normal operation of the grid would be to have the entire network feeders closed, all the network
protectors closed, and all the secondary cables in service at both peak and light load times.
While this is the preferred method of operation, secondary cable faults can occur at any time,
which will be cleared by limiters or burn clear. These faulted cables will not be detected until a
physical inspection of the grid is performed. Network protectors can be out of service for
maintenance, a primary feeder fault or a failure of the protector to close (Typically a burned out
close motor). A protector that failed in the open position will again not be detected until a
physical inspection is performed, unless the protectors are supervised. A primary feeder can trip
open due to a fault and this will cause all the protectors connected to that feeder to open. If
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
16
SCADA is present at the substation this would be detected immediately, but if SCADA is not
present and the feeder serves only network load, this would not be detected until a physical
inspection of the substation is performed. All of these possible abnormal conditions that can
occur during normal operation of networks (Spot or Grid) make applying generation difficult.
Network feeders are radial feeders that normally do not have ties on the primary to other feeders.
Typically there are sectionalizing switches installed on the network feeders supplying network
transformeres. If a fault occurs on a network feeder, the feeder will be out of service until the
fault is located and repaird. Prior to repair, the protectors would be verified open and if present,
the transformer primary switches put into the grounded position. This can be a lengthy process
that distributed generation could make longer.
(5. Joe: You changed the above to say there are sectionalizing switches in network grids. I
don’t think typically this is the case. The only switches are on the network transformers
themselves. The network feeders cannot be split up and re-livened, at least at ComEd
without cutting the cable. Perhaps others have installed switches to be able to break up the
feeder. This is one that the group could provide input on.)
If an entire grid goes down it can be a lengthy process to get it restored. Typically there are no
switches on the secondary cables in the grid. It may be necessary to make secondary cable cuts
or unbolt secondary cables from buses to start picking up the grid in pieces. In some cases it
may be possible to do a simultaneous group close of all the feeders in the grid (If they come from
the same substation).
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
17
1
How does the DR provide Network
Transformer protection function
normally provided by the feeder’s
protective relay?
2
What kind of communication is
necessary between the protectors and
the DR?
X
X
3
How might the DR cause false
tripping of the protectors?
X
X
4
How might the DR prevent proper
Opening protectors?
X
X
5
How might the DR prevent proper
closing protectors?
X
X
X
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
Technology
Dependent
Primary Fed
Grid
Issue
Spot
APPENDIX D: P1547.6 CLAUSE 8 PRE-BREAKOUT STATUS REPORT
Area
Protection/
Coordination
DR Impact on
Network
equipment/operatio
n
DR Impact on
Network
equipment/operatio
n
DR Impact on
Network
equipment/operatio
n
DR Impact on
Network
equipment/operatio
n
Comments
Potential Solutions
DR connected to the
Primary would be handled
like any radial connected
DR. Unclear what else this
might address
Possibly NP status via monitoring
system, Also status of network
transformer with open protector
(energized or de-energized)
Exporting across the NP; VAR
swings? Var swings would have
impact primarily if the watt-var trip
characteristic is used in the NWP’s.
Min impact with watt trip
characteristic.
Not sure how to cause this. If timedelay trip is added due to DR, and
SLG fault on HV feeder, NWP
tripping would be unnecessarily
delayed for SLG fault
Minimum import (Spot),
limit DR capacity(Grid)
Need to understand load
levels necessary for proper
closing
Reduce network Xformer size,
minimum import (spot), In Spot
nwks, use circle rather than straight
line close characteristic) DR
capacity (grid)
Testing Issue
18
Technology
Dependent
Primary Fed
Comments
DR Impact on
Network
equipment/operatio
n
DR Impact on
Network
equipment/operatio
n
DR Impact on
Network
equipment/operatio
n
If DR forms an island by opening of
all NWP’s in a spot, the NWP
interrupting capability may be
exceeded.
Grid
Area
Spot
Issue
Will any Network equipment be
overstressed (Fault) due to the DR
interconnection?
X
X
7
Will any Network equipment be over
loaded (normal current) due to the
DR interconnection?
X
X
X
8
What effects will the DR have on the
Network Protector relays, and what
are the new relay setting criteria?
What are impacts of increased time
delay for low level rev power setting
How will the presence of the DR
affect the protectors’ response to
faults outside of their protection
zones? (e.g. response to adjacent
feeder fault, AFF)
Is the operation of a single-phase
overcurrent device (protector fuse) a
concern with the presence of DR?
X
X
X
X
X
DR Impact on
Network
equipment/operatio
n
DR requires addition of time delay
tripping at low reverse powers, that
otherwise would not be required.
Test to determine potential impacts
of delay
May allow SLG fault to propagate
into a three-phase fault
In normal spot nwk, protection zone
of NWP is from the LV terminals of
the Nwk Xfr back to the primary
feeder breaker. Should have minimal
impact.
X
X
DR Impact on
Network
equipment/operatio
n
Does not appear to be an issue. With
one NWP fuse blown and balanced
load conditions in two good phases,
current for trip increases by 50 %
with MNPR & MPCV Nwk relays
6
9
10
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
X
Potential Solutions
Limit DR or replace
overstressed equipment
Install relaying and control to
prevent formation of island.
Not necessarily a “network” Limit DR or replace over
issue
loaded equipment
See Feero report for possible relay
settings.
Requires replacing electro
mechanical relays in NWP with
microprocessor relays.
Consider low level rev
power time delays (similar
to requirement for regn
braking of elevators)
19
What conditions must be satisfied
before paralleling is allowed? What
will be the paralleling procedure?
X
X
12
Will a dedicated transformer for the
DR be required?
X
X
13
How do requirements vary with the
number of Network Transformers
(eg. Dozens to hundreds spread out
over a wide area?
X
14
Will addition of DR impact arc detection
(ozone, heat/smoke/flash)? Will
requirements be different for 208 volt
grid nwks, 208-V spot nwks, 480 volt
spot networks, and 480-V grid nwks
because of the different arcing
characteristics? How are the arcing
characteristics different?
X
Technology
Dependent
Grid
11
Primary Fed
Spot
Issue
Area
Comments
X
DR Paralleling
requirements
Minimum import (across NP),
Sufficient NP’s closed, Sync
tolerances met. Paralleling vs
synchronization. Are different Sync
tolerances required? Are NWP’s
equipped with time delay trip if
momentary reverse power during
synchronization
X
DR Requirements
Does not appear to be an
issue (not a networkspecific issue)
X
Network
configuration
Does not appear to be an issue In
spots, with the >50 % closed rule,
utility may have more flexibility in
large spots. With large spots,
control & monitoring more complex
X
Network
Configuration
Testing needed to define
issue. Some utilities have
installed ground-fault
protection schemes in 480volt spot networks.
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
X
Potential Solutions
Micro processor relays on NWP,
PLC or equivalent for monitoring
and control, communication link
between NWPs and DR
More xformers could ease
the requirements
20
15
Will the presence of, or lack of, Cable
Limiters on the secondary cables
result in different DR interconnection
requirements?
16
17
(combined with 13)
Will changes in power flow over the
daily or weekly load cycle result in
protector Cycling at a point remote
from the DR’s PCC?
Will different protection requirements
apply to Network systems supplied
from three-wire and four-wire
primaries? With delta-wye or wyewye transformers?
18
X
X
X
X
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
X
Network
Configuration
Not aware of any different needs.
Could have a big impact when
considering DR on grid nwks. If
utility does not know limiter status,
secondary ties believed closed could
be open
Network
Configuration
If nwk fdrs come from same electric
bus in sub, DR on spot nwks reduces
load on primary feeders which
should reduce angular differences
between feeders (a positive).
Network line
configuration
Nwk Xfr winding connection affects
backfeed to ground faults on HV
feeder with feeder breaker open,. If
ground fault relaying used in 480volt spot networks, may affect
relaying. With YY nwk xfrs, ground
relay for primary feeder can not be
set as sensitive as with Δ Y network
transformers
Better monitor status of limiters in
grid type networks.
Different relay settings and
coordination
21
19
20
How will the protector be prevented
from isolating distributed resources
from the utility system? if the DR
islands, will the Network Protector
relay tolerate 180 deg out of phase
voltage? If the DR islands, how will
the Network master (/phasing?) relay
be prevented from reclosing the
protector switch during an out-ofsynchronism condition?
X
What would be an acceptable ratio of
the minimum customer load current
over the maximum DR output to
eliminate any possibility of reverse
power through a protector?
X
X
X
X
Protector breakers
are not designed to
interrupt fault
current from
generators or
withstand out-ofphase conditions
across the open
switch. Nwk relays
were never intended to
operate in “nonsynchronized systems.
X
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
Reverse power
through Network
Protector
Another islanding problem
1) Test NP to see if it can
withstand 180
It is known that if a NWP is open,
and then a voltage of twice line-toground voltage is applied across its
contacts, it can withstand this. This
also applies to Nwk Relays. This
occurs under crossed phases with Δ
Y Nwk Xfrs. Question is whether it
can interrupt when the normal
frequency recovery voltage is 2.0 per
unit
Replace NP
Anti islanding
>50% NP closed
requirement
Limit DR capacity
Minimum import
Install relaying such that island can
never form,
This is the FIRST thing to
test!!! (see 3)
Moh: I think a more reasonable
criteria is “What must the net input
from the spot be in per unit of the
rating of one network transformer”
This number is, I believe, a function
of the number of units in the spot
network. Then the difference
between the DR output and the
customer load at any load level
must exceed this net import figure..
22
21
What action needs to be taken with a
sudden loss of large load with
generation in operation?
X
X
Reverse power
through Network
Protector
Issue not understood
Transient low load issue?,
inadvertent export? Is this
really a subset of 3?
Time delay tripping of NWP, with
sufficient time delay to allow other
under power or reverse power relays
time to disconnect the DG before
NWP’s can trip
Limit generator output such that
dropping of largest load will
maintain some minimum power
import from the spot network
22
23
24
25
26
Can power swings or loss-ofsynchronism, loss of field by rotating
generators cause reverse power
through a Network Protector?
Can insertion of customer PF caps
cause reverse power through a
Network Protector?
X
X
X
Reverse Power
through Network
Protector
A testing issue
X
X
X
Reverse Power
through Network
Protector
Testing issue (Moh)
(Combined with 19)
(Combined with 19)
How can addition of DR contribute to
or exacerbate cycling or pumping of
NP
X
X
X
X
X
X
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
X
Will have minimum impact on power
flow in closed protectors. Can have
significant impact on auto closing of
NWP.
From auto closing consideration, use
in spot networks the circle rather
than the straight line close
characteristic in Nwk Relays.
Needs testing; what
constitutes “exacerbate”?
Addition of DR can not improve
stability of operation on NWP’s.
May have no impact or negative
impact, depending on particulars
23
27
28
29
Is there any fault detection (Phase or
ground fault) required for DR?
Should DR trip before NP?
What equipment damage can occur
due to increased time delay for low
reverse power
Modifications to Network equipment
may be problematic and costly due to
access limitations, equipment age,
etc.
X
X
X
X
X
X
Why? (MDGC issue)
(MDGC issue) testing
needed to determine
impacts
May result in SLG fault on primary
feeder propagating into a multi-phase
fault
Addition of time delay tripping,
control equipment, etc to allow
application of DR can only result in
a degradation of reliability because
of the added complexity. However,
quantifying this is not easy.
X
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
Technology
Dependent
Grid
Spot
Issue
Primary Fed
30
Area
Comments
Potential Solutions
24
31
32
3
How might the DR cause false
tripping of the protectors?
X
X
DR Impact on
Network
equipment/operatio
n
Exporting across the NP; VAR
swings? Var swings would have
impact primarily if the watt-var trip
characteristic is used in the NWP’s.
Min impact with watt trip
characteristic.
Minimum import (Spot),
limit DR capacity(Grid)
5
How might the DR prevent proper
closing protectors?
X
X
DR Impact on
Network
equipment/operatio
n
Need to understand load
levels necessary for proper
closing
8
What effects will the DR have on the
Network Protector relays, and what
are the new relay setting criteria?
What are impacts of increased time
delay for low level rev power setting
X
X
DR Impact on
Network
equipment/operatio
n
DR requires addition of time delay
tripping at low reverse powers, that
otherwise would not be required.
Test to determine potential impacts
of delay
May allow SLG fault to propagate
into a three-phase fault
Reduce network Xformer size,
minimum import (spot), In Spot
nwks, use circle rather than straight
line close characteristic) DR
capacity (grid)
Testing Issue
See Feero report for possible relay
settings.
Requires replacing electro
mechanical relays in NWP with
microprocessor relays.
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
X
25
20 What would be an acceptable ratio of
the minimum customer load current
over the maximum DR output to
eliminate any possibility of reverse
power through a protector?
X
23 Can insertion of customer PF caps
cause reverse power through a
Network Protector? (See Issue 3)
X
26 How can addition of DR contribute to
or exacerbate cycling or pumping of
NP
X
X
X
X
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
X
X
Reverse power
through Network
Protector
This is the FIRST thing to
test!!! (see 3)
Reverse Power
through Network
Protector
Testing issue (Moh)
Moh: I think a more reasonable
criteria is “What must the net
import from the spot be in per unit of
the rating of one network
transformer” This number is, I
believe, a function of the number of
units in the spot network. Then the
difference between the DR output
and the customer load at any load
level must exceed this net import
figure..
Will have minimum impact on power
flow in closed protectors. Can have
significant impact on auto closing of
NWP.
From auto closing consideration, use
in spot networks the circle rather
than the straight line close
characteristic in Nwk Relays.
Needs testing; what
constitutes “exacerbate”?
Addition of DR can not improve
stability of operation on NWP’s.
May have no impact or negative
impact, depending on particulars
26
APPENDIX E:
P1547.6 CLAUSE 9 PRE-BREAKOUT STATUS REPORT
2nd REORGANIZATION OF P1547.6 - AREAS 7–10
7. Overview of Network Distribution Systems: Design, Components and Operation
(Joe Koepfinger, Bob Peterson, Martin Baier, Dave Costyk, Jim Daley,
Betty Tobin )
7.1 Spot Networks
7.2 Area Networks
8. Primary Concerns of Operating DR on Networks
(Moh Vaziri, Jim Watts, F. Bigenho, Tim Wall, Dan Sammon,
Chuck Whitaker, Travis Johnson, David Smith, other volunteers)
8.1 Reverse power flow
8.2 Fault current contributions
8.3 Effects of DR on area network load flows
8.4 Effects of potential network system component failures
9. Fundamental Requirements for Interconnection of DR on Networks
(John Bzura …, Murray Davis, Martin Baier, Jim Daley, Jock Moffat, David
Beach, Moh Vaziri, Sam McAllister, Mohammed Ebrahim, Tom Greely)
9.1 Separation Requirement
On the detection of any anomaly in the network voltage, frequency or power flow
direction, the Interconnection System (IS)* shall separate the DR unit from the network within 3
cycles.**
9.2 Prohibition of Reverse Power Flow
The IS shall prevent the occurrence of reverse power flow through any network protector
under all normal conditions of voltage and frequency. There shall be at least two independent
subsystems within the IS to accomplish this requirement. Optional sentence – During abnormal
conditions, reverse power flow shall be limited to X% of the network protector rating and be
curtailed within 3 cycles.**
9.3 Fault Current Contribution Limit
During a fault on the network, the IS shall limit the initial fault current contribution from
the DR unit to Y%** of the normal network protector rating, and be
curtailed within 3 cycles.** For network protector circuits already at 100% of calculated fault
current capacity, the DR fault current contribution shall be 0%.
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
27
* The Interconnection System (IS) is defined as a protective relay and control scheme designed
to allow operation of a DR unit in parallel with a network grid.
** The exact number is open for discussion.
9.4 Determination of DR Interconnection Feasibility
The utility customer or the customer’s agent will work with the utility to analyze network
load flow parameters at the proposed DR site to determine whether the proposed type of DR unit
can be accommodated for operation. If the conclusion is negative, alternative measures such as
reconfiguration for a radial interconnection shall be evaluated.
10. Procedures to Alleviate Concerns of Operating DR on Networks
(Murray Davis, Jim Daley, Jock Moffat, John Bzura, Marty Baier, David Beach,
Moh Vaziri, Sam McAllister, Mohammed Ebrahim, Tom Greely, others)
10.1 Measures to sense and limit reverse power flow
10.1.1 Minimum power level DR trip
10.1.2 Reverse power flow sensing for DR trip
10.2 Fault current minimization
10.2.1 Limitation by DR technology
10.2.2 Limitation by switching technology
10.3 Site-specific analysis of DR on area networks (Moh V to lead?)
10.4 Coordination of DR with network operations (Murray D to lead?)
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
28
APPENDIX F:
P1547.6 CLAUSE 10 PRE-BREAKOUT STATUS REPORT
(Old number 7.2.1.2.6 also this is prior write up minutes Feb 2006)
(a) Secondary Grid Network Modifications for DR Interconnection
Murray W. Davis
1. It is difficult to insure that reverse power flows, through the network protectors due to the
DR generation, will not cause the network protectors to open. Typically, the network
protector will open for reverse current of 5% or more of the network protector rating. If all
the loads and all the generation is monitored on the grid, so that the generation never exceeds
the load on the secondary grid then this could be an acceptable solution.
2. A network relay can determine the difference between reverse fault current from DR
generation and reverse load current. The phase angles for fault currents are generally much
greater than for load currents. Also, consideration must be given to the DR units causing
high voltage during light load periods.
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
29
7.2.1.2.6
(b) Secondary Spot Network
What Does the Standard Say?
1. The connection of the DR’s to the Area EPS is only permitted if the Area EPS network bus is
already energized by more than 50% of the installed network protectors.
2. The DR output shall not cause any cycling of network protectors.
3. The network equipment loading and fault interrupting capacity shall not be exceeded with the
addition of DR’s.
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
30
(c) Secondary Spot Network Modifications for DR Interconnection
1. The reverse power relay and breaker clearing time (i.e. sense time of the protective function
and opening time of the interrupting device) is about 3 to 5 cycles. Some utilities have much
longer clearing times, as much as 20 cycles, which allows more time for the reverse power
relay (32) of the DR to operate at the PCC and thus prevent the network protector from
opening.
2. Another solution is shown in Figure 1 where a separate generator and facility load bus are
created with an additional breaker at the PCC including a (32) relay function. The breaker at
the PCC opens under system fault conditions while the generator continues to serve the
facility load. It should be noted that if three network protectors are serving load, two must be
in service to meet more than the 50% criteria. The concern of the 50% rule above is the
reduced reliability of the network if there is 50% or less of the network protectors remaining
(considering protectors out of service for maintenance).
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
31
3. Another solution for installation of DR’s is shown in Figure 2. Here a new radial circuit
serves the DR and facility load which allows for exporting power and alleviates the reverse
power issue of directly connecting to the spot network.
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
32
4. Another solution is given in Figure 3, where the network protector relays sense the reverse
current under fault conditions and initiate a generator trip. Separate contacts are used in each
reverse current relay to close and pick up the generator trip coil.
“A”
Contacts from each
protector reverse
current relay
“A”
PCC
“G”
Gen
“b”
3
Protector tripping
coil operates
when gen. is
offline and reverse
current exists due
to faults or normal
network protector
operation
Figure 3.
If the generator causes reverse power through the network protector under normal load
conditions the reverse power relay (32) of the network protector causes one or more of the
“A” contacts to close and trip the generator via “G” trip coil. If the reverse power condition
is eliminated by tripping the generator breaker then there is no reverse power through the
network protectors and same remain closed, thus avoiding a potential interruption.
If the generator is operating when a fault occurs this causes reverse current through the
network protector. The reverse current relay contacts “A” (not the main contacts of the
network protector) close thus energizing the trip coil “G” of the generator breaker. This trip
coil trips the generator breaker and isolates the DR from the network. Another option is to
trip the breaker at the PCC which allows the generator to continue operating and serve
facility load (if the capacity is large enough).
It should be noted that the time delay tripping of the network protector may be required to
permit resetting of the directional overcurrent relays to insure the relay contacts are open
before the generator breaker auxiliary “b” contacts close. See Figure 3.
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
33
5. Another solution is to use a Solid State Switch generator breaker to isolate the generator from
the network protector secondary bus within 1/8 to ¼ of a cycle thus preventing the opening
of the network protector (typically 5 cycles to open) for either normal reverse load current
from the generator or reverse current due to a fault on the primary of the spot network. The
sensing of reverse current for the solid state switch is typically on the load side of the
interconnection breaker at the PCC of Figure 1., but the solid state switch is installed on the
generator terminals, especially for multiple unit installations.
6. Finally, another solution is to install Fiber Optic communication links between any sensing
point on the system and the generator breaker to cause a transfer trip when an abnormal
system or generator output in excess of its local load condition occurs.
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
34
APPENDIX G:
BILL FEERO NETWORK INTERCONNECTIONS PRESENTATION
Slide 1
MTC Proposed R&D to Advance
DR/Network Interconnections
Email [email protected]
Suggested
Advancements
1
Slide 2
Purpose
• To advance the acceptability of DR on
network service by encouraging changes in
the network protector (NWP) relays and in
the DR controls to react instantaneously to
required switching conditions utilizing
communications between the NWP relays
and the DR controls.
Suggested
Advancements
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
2
35
Slide 3
Approach
• Held meetings with protector relay
manufacturers, DR interface manufacturers,
and utilities to determine what
developments they feel are feasible and
then, prepared a plan for a prototype
demonstration project.
Suggested
Advancements
3
Slide 4
Observations
• At present, grid interconnections of .1 to
2MW DR are not meeting widespread
acceptance. The most obvious technical fix
would require the installation of a gridwide, protection-speed communication and
automatic adaptive control schemes. While
conceptually feasible, the implementation
cost appears to be well beyond any
justification that can be envisioned.
Suggested
Advancements
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
4
36
Slide 5
Observations (continued)
• The prospect of developing Recommended
Practice for spot network interconnections
using presently available technology will
hinge on achieving general acceptability of
using NWP time delay tripping for low
reverse power.
Suggested
Advancements
5
Slide 6
Observations (continued)
• Techno-economic issues yet to be discussed
are: 1.How to select the low reverse power
setting for various types of DR; 2.Guidance
on how to select the minimum necessary
time delay to avoid false tripping of the
NWPs; 3.DR size restrictions; and
4.Cautions on using the time delay
technique, e.g., evolving faults and cross
town faults.
Suggested
Advancements
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
6
37
Slide 7
Observations (continued)
• Techno-legal issues yet to be discussed are:
• De facto giving reverse power tripping control to a
non-utility entity when the DR or facilitator owns
and maintains the circuits which determine when a
network underpower limit has been reached.
• Mitigating this exposure to a non-utility protective
function failure by limiting the size of the DR that
can be interconnected to less than the minimum
spot network load.
Suggested
Advancements
7
Slide 8
Concerns of Many Utilities
• Salient concerns expressed by many utilities are:
• 1. The determination of abnormal system
conditions on the utility system that would require
network protector action or non-action absent DR
interconnections should be controlled and
maintained by the utility.
• 2. Adding intentional time delay to provide
coordination time intervals between independently
acting relays (utility’s and DR’s) may adversely
impact the utility system.
Suggested
Advancements
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
8
38
Slide 9
Present DR Interconnecting Using a
NWP Relay with Low Reverse Power
Time Delay
from Baier, Feero, Smith 2003 T&D Conference Paper
Suggested
Advancements
9
Slide 10
Required Advancements to
Mitigate these Concerns
• To alleviate concern #1, a suggested solution is a
NWP microprocessor relay capable of providing:
• A means of computing the power import by each
protector and sending a trip signal to the DR (or to
a vault control unit -later slide) if the imported
power dropped below a selectable level such as
6% of the transformer’s rating. To prevent
cycling of the DR, this relay should also have an
over power setting to be exceeded before the DR
could be connected online.
Suggested
Advancements
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
10
39
Slide 11
Required Trip of the DR
• Presently Required Trip (RT) of the DR is not
Initiated by the NWP Relay.
• In some cases the DR Interface Unit attempts to
determine the Required Trip at its terminals.
• More generally the Required Trip is determined at
a summing point off the network bus in the
customer’s facility.
• Depending on the location of the summing point,
the sensing relay is either a reverse power relay or
a under power relay.
Suggested
Advancements
11
Slide 12
Operating Time of the
NWP Relay in seconds
The Suggested NWP Relay
Conceptual Characteristic
0.75--
Network Protector Open
0.50 --
0.25 --
Load Current
in the NWP
Zone of NWP Time Delay
before Opening
Reverse Current in the NWP
DR
DR
RT
Instantaneous Zone
Trip Threshold
Network
Protector Closed
Suggested
Advancements
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
12
40
Slide 13
Required Advancements to
Mitigate these Concerns –
(continued)
Vault Control Unit
For spot networks with more than two
transformers, an individual protector relay’s
call for trip would have to be modified by
some form of instantaneous acting AND
circuit to only trip the DRs when 50% or
more of the protectors required a DR trip
Suggested
Advancements
13
Slide 14
Black Box Conceptual
Arrangement
13.8 kV Bus
NWP#1
NWP#2
RT
NWP#3
RT
Black Box that
Determines if
50% of the
Protectors are
open
NWP#4
NWP#5
NWP#6
RT
RequiredTrip
command Line
480 volt bus
Building Main
Breaker
DR Control
Lines
Load
Trip Co
mmands
Load
DR
Controller
480/208 Volt
Transformer
Synchronous
Generator
Induction Generator
Roof PV Array
Suggested
Advancements
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
14
41
Slide 15
Required Advancements to
Mitigate these Concerns –
(continued)
• Concern #2 For utilities who do not wish to
set any intentional time delay, a network
relay system that could issue a DR trip
command and then trip itself, if required,
after receiving a confirmation signal that the
DR had tripped-- a form of permissive
tripping. This ability will also require some
development by the DR manufacturers.
Suggested
Advancements
15
Slide 16
Operating Time of the
NWP Relay in seconds
NWP Relay Utilizing Permissive
Trip Scheme
0.75--
Network Protector Open
0.50 --
0.25 --
Delay Waiting on DR
Trip
Load Current
in the NWP
Reverse Current in the NWP
DR
DR
RT
Instantaneous Zone
Trip Threshold
Network
Protector Closed
Suggested
Advancements
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
16
42
Slide 17
Conceptual Permissive Trip
Circuit
13.8 kV Bus
NWP#1
NWP#2
NWP#3
RT
RT
Black Box that
Determines if
50% of the
Protectors are
open
NWP#4
NWP#5
NWP#6
RT
RequiredTrip
command Line
480 volt bus
Trip Completed
Circuit
mmands
DR Control
Lines
Load
Trip Co
Building Main
Breaker
Load
DR
Controller
480/208 Volt
Transformer
Synchronous
Generator
Induction Generator
Roof PV Array
Suggested
Advancements
17
Slide 18
Required Advancements to
Mitigate these Concerns –
(continued)
• A variation might be to block any network
protector tripping if all network protector reverse
power relays were calling for a trip. The DR trip
command would be sent and individual NWPs
would be released to trip as soon as at least one
unit’s power flow moved back into the import
(non-trip) direction. This would guard against
dumping the network bus for the adjacent feeder
fault on the utility system when DRs are
interconnected and yet not materially slow
tripping for faults on one of the feeders supplying
Suggested
18
the spot network.
Advancements
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
43
Slide 19
Preliminary Discussions with both NWP
Relay and DR Manufacturers
• Discussed the concept of NWP relay
centered control and the feasibility of
receiving and sending trip communications
between the NWP relay system and the DR
interface system.
• Reaction has generally been favorable and
deemed not to be any significant
technological hurdle.
Suggested
Advancements
19
Slide 20
Discussions with Select Utilities*
• Three allow interconnections on Spot
Networks by applying low reverse power
time-delayed tripping.
• Two do not allow time delay of the
protector tripping and therefore have very
few and small interconnections.
• *Note some other utilities do allow PV systems small
compared to loads on network systems.
Suggested
Advancements
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
20
44
Slide 21
Discussions with Select Utilities(continued)
• Of the three that allow interconnections:
• One would like a better way that would increase
reliability and reduce pre-engineering time.
• One has not worried about it lately because of
little interconnection activity
• One has a form of Vault Control Unit and sets DR
size limits that, with time delay, solves any
problems of importance to the utility
Suggested
Advancements
21
Slide 22
Consider a Large Spot Network
13.8 kV Bus
NWP#1
NWP#2
NWP#3
Trip command
Line
NWP#4
NWP#5
NWP#6
480 volt bus
Under Power
Detection
Building
Main
Breaker
DR Control
Lines
Induction Generator
Load
Load
DR
Controller
Owned
and
Operated
by the
Customer
Vault Control
Unit
Determines if
50% of the
Protectors are
open
Current limiter
480/208 Volt
Transformer
Roof PV Array
Suggested
Advancements
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
Synchronous
Generator
22
45
Slide 23
One Utility’s Approach
• Spot Networks are designed to an N-2 criteria, so
for a 10 MVA max load they would install six 2.5
MVA units.
• The minimum network import permitted would be
1 MVA for such a spot or 167 KVA per unit.
• With a 6% minimum criteria, they have reasonable
margin even with 20% unbalance.
• Max DR MVA allowed <minimum load MVA1MVA.
Suggested
Advancements
23
Slide 24
The Tie-line Control Approach
• Requires:
– Low Reverse Power Time Delay of NWPs
which is long enough for tie-line corrections.
– A Vault Control Unit to determine when
50% of the protectors are open.
– DR size limited to less than minimum load or
customer maintenance of a tie-line control
which meets or exceeds local utility quality and
maintenance practice.
Suggested
Advancements
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
24
46
Slide 25
Tie-line Control Works, BUT
• The use of time delay increases the utility’s exposure to
additional fault damage, at the point of fault or cross town,
i.e., other phase remote.
• It relies on good maintenance by the customer or
– DR rated output restrictions at initial installation, and,
– Future awareness of any drop in minimum load.
– In the event of a reduced minimum load, network
reliability is only as good as the tie-line control’s
reliability.
Suggested
Advancements
25
Slide 26
Next Steps
• The Massachusetts Technology Collaborative,
MTC, has developed and posted on its web site an
RFP for these suggested NWP relay developments
that might be possible by the responding team(s).
A team would likely consist of a relay
manufacturer, a utility, and at least one DR
manufacturer.
• www.masstech.org/dg/collab.reports.htm
• Attachment F: Relaying and Control Technology
Development for Spot Networks.
Suggested
Advancements
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
26
47
Slide 27
GOALS OF MTC’s RFP
• To advance the acceptability of DG on
network service by encouraging changes in
the network protector (NWP) relays and in
the DG controls to react instantaneously to
required switching conditions utilizing
communications between the NWP relays
and the DG controls.
Suggested
Advancements
27
Slide 28
GOALS OF MTC’s RFP
(continued)
• Encourage protector relay manufacturers,
DG interface manufacturers, and utilities to
determine what developments they feel are
feasible, develop a prototype relaying and
control system, and prepare a plan for a
prototype demonstration project on a spot
network test bed.
Suggested
Advancements
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
28
48
Slide 29
GOALS OF MTC’s RFP
(continued)
• Increase the acceptability of DG interconnection
with network service by utilities by assuring that
all conditions that can cause protector operations
are controlled by utility owned and maintained
relays and controls.
• Decrease the complexity and site-specific
variability for DG suppliers in designing network
interconnection systems.
Suggested
Advancements
29
Slide 30
GOALS OF MTC’s RFP
(continued)
• Advance communication and control
exchanges between network protectors and
DG to achieve high levels of security while
increasing operating range flexibility.
Suggested
Advancements
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
30
49
Slide 31
Conclusions
• The relay advancements that are suggested in this
presentation are an attempt to offer tools to
utilities who don’t permit time delays and won’t
accept customer controls that can impact their
network’s reliability.
• The functions that could be performed in the
suggested relay development and the ability to
deal with two-way communications will also be a
key step in resolving the grid interconnection
issue.
Suggested
Advancements
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
31
50
ANNEX H:
P1547.6 CLAUSE 7 POST-BREAKOUT STATUS REPORT
P1547.6 – proposed Clause 7 “Overview of Network Distribution Sysytems: Design,
Components and Operation.
----------------------- --------------------------------- ------------------------------------
An Overview of Network Distribution Systems: Design, Components and Operation
Background Discussion:
Low voltage alternating current networks were first developed in the 1920’s to provide highly
reliable electric service to concentrated load centers mainly in the downtown areas of major
cities. There are two types of low voltage networks, the secondary network (also referred to as
an area network, grid network or street network) and the spot network. For the purpose of this
guide secondary network will be referred to as a grid network. A minimum of two primary
feeders are required to supply a network, The number of feeders to a network is dependent upon
load requirement of the grid network or the spot network load.
The grid network may consist of more that one area that are operated independently from each
other with in a city Customers in a low voltage network area typically take service from the
network at the grids voltage level. A spot network supplies grid like service to a particular
customer installation to achieve, high level of reliability and is designed to carry full load with a
minimum of n-1 primary feeder out of service. To achieve high reliability faulted primary feeder
or transformer connection to the low voltage network are isolated within a few cycles.
NETWORK TRANSFORMERS:
Network transformers are typically liquid filled and air cooled, although some dry type network
transformers have been used. Historically they were filled with a fluid that contained PCB’s
continued use of such transformer is required by regulations to have a low PCB content or
comply with the applicable environmental regulations. In most cases the coolant has a low
flammability Newer vegetable oil based coolant with low flammability show promise for use
in network transformers. In some cases, mineral oiled filled transformer have been used.
However use of this filling material maybe subject to acceptance by local authorities.
The network transformer may have a manually operated primary oil switch located directly on
the transformer, which can be in the closed, opened or grounded position The network
transformer is equipped with a network protector) mounted directly on the transformer or
mounted within close proximity of the transformer. In this latter case it is cable connected to the
transformer. . Typical network transformer secondary voltages are 120/208Y, 125/216Y, and
277/480Y volts. The primary of the network transformer my be connected either in delta or
grounded wye. The secondary of the network transformer is usually connected ground wye. to
supply 120/208Y or 277/480Y voltage to the grid network or the spot network customer.
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
51
SPOT NETWORKS:
A spot network consists of two or more network transformers connected by a common bus low
voltage side at a single location. Each network transformer and protector for the spot may be
located in a separate vault below the sidewalk or street, with the parallel connections on the LV
side made in a separate bus hole or compartment. With this arrangement, the equipment is in a
harsh environment, which may be frequently submersed, complicating the interfacing with other
control equipment. In normal operation, all the spot’s network transformers will be feeding the
bus simultaneously, from their respective primary feeders. The building may have additional
spot networks on upper floors, but there is no connection between the vaults on the secondary
side. Spot networks are installed with secondary voltages of 120/208volts and 277/480 volts.
“PICTURE OF A SPOT NETWORK”
FIGJURE 1
SPOT NETWORK
In order that the spot network can continue to operate if a primary feeder becomes faulted, each
network transformers is equipped with a network protector containing a low-voltage circuit
breaker, and a protective package. The protective package includes a network relay or master
relay that is sensitive to directional real and reactive power flow. It senses the reverse flow
through the transformer for feeder faults or flow due to the feeder charging current or
transformer magnetizing current. This protection operates to cause the network breaker to open
and isolate the initiating condition. The network relay is a very sensitive reverse-power relay,
with a pickup level on the order of 1 to 2 kW. It is the mission of the reverse power relay to be
capable of sensing reverse power flow with no other feeder loads than the core losses of its own
network transformer (With delta primary network transformers, little to no fault current will flow
for a primary phase to ground fault.).
It should be noted that with low-loss network transformers and the reverse current trip setting
used by some utilities, the network protector will not trip on just the core losses of the
transformer to which it is connected. However, this does not mean that the protector will not
open when the feeder breaker is opened in absence of a fault, or with a SLG fault on the primary
feeder. Under these conditions, there are circulating flows between closed protectors due to
difference in voltages throughout the network. Also, when a protector opens, the core losses of
its transformer are supplied from those protectors that are still closed. The last protector to open
is supplying the core losses of all network transformers on the feeder.
Network protectors by themselves do not contain any forward looking over current protection.
In many cases fuses are installed in series with the network protector. This fuse is sized well
above the capability of one transformer and will have limited capability to operate for arcing
type faults that are the most common in the network vault. It will operate for a bolted three
phase fault within the vault.
The main purpose of the network protector fuse is to act as a backup to the network protector for
a fault on the primary feeder in the event the network protector fails to open for the fault on the
primary feeder. This could be due to a network relay or network protector malfunction. Further,
under this backfeed condition the fuse is to provide through fault protection to the back feeding
network transformer.
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
52
Multiple sets of secondary cables are typically installed between the network protector and the
collector bus. These may be protected with inline fuses called cable limiters on each end, such
that cable faults are isolated by the limiters. Limiters may also be installed on the service cables
going to the customer’s switchgear. The primary purpoes of a limiter is to protected the
insulation of the conductors from excessive thermal damage.
The master relay has another function, which is to supervise the closing of the network
protector. The relay looks at the voltage on both side of the protector and if the transformer side
voltage higher than the bus side (by perhaps 1 volt) the first close criteria is met. The phasing
relay looks at the angle between the phasing voltage (voltage across the open contacts of the
protector – on just one phase with the electro-mechanical relays) and the network line-to-ground
voltage. If the phasing voltage is leading the network line-to-ground voltage, or is not lagging by
a large angle as determined by the setting of the phasing relay, the phasing relay will make its
close contact. Basically, the phasing relay permits closing if the transformer side line-to-ground
voltage is leading the network side line-to-ground voltage at the open protector.
Currently electro mechanical master relay and phasing relay functions have been combined into
a single relay, that may be either solid state or micro processor type relay..
Typically, a spot network is supplied by two or more primary distribution circuits, from a single
substation and single bus section or multiple bus sections with closed bus ties. Occasionally
feeders from separate substations have been used, but the flow of circulating currents between
substations can result in excessive protector operations (Especially at light load). Primary
feeders at the substation typically are protected by time-overcurrent phase and ground protection
to see faults on the circuit. They may have an instantaneous ground element set to see faults on
the primary side of the network transformer. Delta – wye connection of the network
transformers limits the reach of the ground relays on one primary network feeder from seeing
ground faults on the primary of another primary network feeder and over-tripping. Typically the
substation relaying will not see faults on the secondary side of the network transformer and
considerable damage has occurred in vaults before any of the protection operates for sustained
faults in 480-volt network protectors. “IEEE Guide for the Protection of Network Transformers”
C37.108 goes into much more sophisticated schemes of protection, but is beyond the scope of
this short discussion on networks.
SECONDARY GRID NETWORK:
A grid network could be thought of as several spot networks tied together with secondary cables,
sometimes called secondary mains or street ties. The low voltage cables may have customer
service cables connected in manholes between the network transformer vaults. With a secondary
network grid, it isn’t always necessary to put a minimum of two transformers in a vault, as the
secondary cables (fed by network transformers connected to alternate primary circuits) can
supply the load for a transformer or primary feeder outage.
Network transformers are located at various locations throughout the grid to supply power and
support the grid voltage as required per studies. The same transformers and network protectors
are used here as with spot networks. Secondary grid networks are typically 120/208 volts
although some 277/480 volts systems were developed. Secondary grids typically have multiple
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
53
sets of secondary cables per phase running between network transformers. These cables can
have inline fuses (cable limiters) installed at each end to isolate a faulted cable and provide for
high-current faults and thermal overload protection for the cables without interrupting customers
or the grid. If limiters are not present or the limiters don’t function, the cables will burn clear
for a fault a fault condition. The number of sets of low-voltage cables installed is determined by
performing load flow studies both under normal and emergency conditions to avoid conditions
that would result in overload conditions for both normal and emergency conditions. Emergency
conditions are bassed on planning criteria established by the Area EPS. Since 480 volts cable
may not burn clear limiters should be installed.)1
“PICTURE OF A GRID NETWORK”
FIGURE 2
GRID NETWORK
Different planning strategies may exist for a secondary grid network, but a typical scenario
would be to allow for one primary circuit to be out of service (faulted) at peak load times and
two primary circuits to be out of service (one for maintenance with a subsequent fault occurring
on another) at non-peak times. Load flows studies must be run for all these scenarios, to insure
customers receive adequate voltage and no equipment is overloaded. With the criteria stated
above, the minimum number of feeders required for a network grid system is three but systems
with more than 20 feeders exist. If the primary feeders come from different bus sections at a
substation or different substations, a bus outage that can take out two or more network feeders
must be considered in the load flows to see that a single contingency such as this does not cause
network problems.
Some substations for networks are designed such that a bus fault does not cause the loss of more
than one primary feeder to a network. Shown below is a simplified one-line diagram of a
substation for supply of three-six feeder networks. With this design, a bus fault, or fault in a bustie breaker results in a loss of just one primary feeder to each network. Other designs are
available which provide similar performance for bus faults, and bus tie breaker faults.
The effectiveness of the substation ground can have an influence on the possibility of sympthatic
faults on non-faulted cables due to the rise in voltage on the unfaulted phase during the ground
fault.
1
Westinghouse Distribution Book,
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
54
69 KV BUS
2000 AMP
69 KV LINE B
69 KV LINE C
69 KV LINE A
69 KV LINES ARE
PIPE-TYPE CABLES
69 KV BREAKERS
3500 MVA IR
XFR. # 1
XFR. #2
XFR. #3
NOTE:
3 OHM RESISTOR IN NEUTRAL
OF EACH TRANSFORMER
11.5 KV BUS # 1
NWK 1
FDR 1
NWK 2
FDR 1
NWK 3
FDR 1
11.5 KV BUS # 2
NWK 1
FDR 2
NWK 2
FDR 2
NWK 3
FDR 2
11.5 KV BREAKERS ARE VACUUM
1000 MVA INTERRUPTING
11.5 KV BUS # 3
NWK 1
FDR 3
NWK 2
FDR 3
NWK 3
FDR 3
11.5 KV BUS # 5
NWK 1
FDR 5
11.5 KV BUS # 4
NWK 1
FDR 4
NWK 2
FDR 4
NWK 3
FDR 4
NWK 2
FDR 5
NWK 3
FDR 5
11.5 KV BUS # 6
NWK 1
FDR 6
NWK 2
FDR 6
NWK 3
FDR 6
FEEDER BREAKER CONTROLS ARRANGED TO PERMIT
SIMULTANEOUS RECLOSING FOR EACH NETWORK
NWK D 22, SUB 8.FCW
FIGURE 3
TYPICAL NETWORK FEEDER SYSTEM
It might be thought that utilities have instant access to loads and load flow directions as well as
voltages on the grid. At most utilities this is not the case. The utility typically only has access to
peak loads that occurred at the network center without any time stamp and customer peak
demands, with or without time of day depending on the size. Periodic voltage measurements are
made on the grid, but may not correspond to when specific load data was extracted. The utility
also has substation loads for the primary feeders that are part of the grid. From this type of data
the utility engineer is expected to run a load flow and plan secondary network grid upgrades.
Without proper monitoring, distributed generation will lend another item of uncertainty in
planning the grid. It will also complicate the running of load flows. Each load flow scenario
must be run with the generator on and the generator off, as the utility has no control of forced
DG outages. Further, load flows must be run with all feeders in service, as well as with each
feeder out of service, and perhaps with any two feeders out of service (double contingency). If a
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
55
network has N feeders, and double contingency response is to be analyzed, the number of load
flows to be run is N*(N-1)/2 if distributed generation is not accounted for. Including the
distributed generation will add significantly to the number of case that must be considered. The
detail of the load full case may be significantly impacted by the number of distributed resources
connected to the grid. The results of these studies are use by the planning engineer to ascertain
the impact of the distributed resources upon the grid operation and reliability
OPERATION:
Normal operation of the grid would be to have the entire network feeders closed, all the network
protectors closed, and all the secondary cables in service at both peak and light load times.
While this is the preferred method of operation, secondary cable faults can occur at any time,
which will be cleared by limiters or burn clear. These faulted cables will not be detected until a
physical inspection of the grid is performed, unless the loss results in a low-voltage complaint, or
overloading of in-service cables with resultant smoking, fire, or other noticeable activity..
Network protectors can be out of service for maintenance, a primary feeder fault or a failure of
the protector to close (Typically a burned out close motor). A protector that failed in the open
position will again not be detected until a physical inspection is performed, unless the protectors
are supervised. A primary feeder can trip open due to a fault and this will cause all the protectors
connected to that feeder to open. If SCADA is present at the substation this would be detected
immediately, but if SCADA is not present and the feeder serves only network load, this would
not be detected until a physical inspection of the substation is performed. All of these possible
abnormal conditions that can occur during normal operation of networks (Spot or Grid) make
applying generation difficult.
Network feeders are radial feeders that normally do not have ties on the primary to other feeders.
Typically there are no sectionalizing switches installed on the network feeders supplying
network transformers accept for the disconnect switch on the primary of the network
transformer. If a fault occurs on a network feeder, the feeder will be out of service until the fault
is located and repaird. Prior to repair, the protectors would be verified open and if the
transformer primary switches are available they put into the grounded position.
If an entire grid network (secondary) goes down it can be a lengthy process to get it restored.
Typically there are no switches on the secondary cables in the grid. It may be necessary to make
secondary cable cuts or unbolt secondary cables from buses to start picking up the grid in pieces.
In some cases it may be possible to do a simultaneous group close of all the feeders in the grid.
In addition the overcurrent protection setting have to consider the impact of the additional inrush
current that is associated with an extended outage of the grid network.
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
56
ANNEX I:
P1547.6 CLAUSE 8 POST-BREAKOUT STATUS REPORT
MO’s Notes
Discussion of the 30 issues
Issues Related to NP Tripping (opening) :
George NSTAR discussed bus differential scheme that one customer installed.
There are three schemes: bus differential, Fenwal and ABB arc guard.
(Variety of different schemes being used by utilities)
Bus differential may require an NEC variance (Jock)
Make sure the NP is not the first device to trip, DG must come off first.
Don’t want manhole covers to fly: therefore, delay is not recommended. Don’t want to
introduce delay.
The main concern with all these systems is arcing faults. (this maybe an existing
problem exacerbated by addition of DG)
Reduction of arc flash incident energy is a major concern. Jock discussed a system that
will allow temporary settings while personnel are working in a vault. All time delays
removed for this work period. Eaton asked to develop a system to accomplish this.
Arc fault suppression and reduction is a concern.
Asynchronous interrupting, Jock discussed Magnum breakers and their design. They
will interrupt 100 kA, but may not achieve the number of operations desired (10,000).
Mo – two spot network: low level reverse flow – is there a concern with the NP opening?
Jock- this fault is limited by transformer impedance. Low until sub breaker opens, then
the current is higher through the NP. with a delta high side, the DG does not see the phgnd fault. When wye-wye, the DG would see the fault. (For most cases, detection
Phase/Ground faults on the utility system maybe difficult to accomplish by the DG.
Transfer Trip or other schemes requiring communication maybe cost prohibitive with
little/no added value! – Need to investigate further!)
For faults on the station bus, ph-gnd fault, what happens?
For low level faults, tripping of NP is not an issue. (Consensus) with or without DG
being in parallel operation)
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
57
What assurance do we have that the customer’s system will be properly maintained and
routinely tested to ensure tripping? Can the utility monitor customer’s relays, settings,
status etc. periodically? (Maintenance Issue)
How do we monitor the >50% closed status of the NPs? Trip signal sent to DG when 2 nd
of three opens. What if the customer breaker doesn’t trip? Periodic testing is required.
Monitoring is beneficial for status etc. George: often customer breakers don’t trip. They
send letters periodically to advise customers to maintain their equipment. Reports are
requested from customers. (Maintenance Issue)
Monitoring at PLC is desired, in addition to breaker status.
Time Delay concept: low level reverse feed, tripping is slow now. With differential
scheme, there is little damage, but the trouble is hard to find. With the Fenwal, there is a
burn making it easier to find. Contamination is an issue when burning takes place.
What about faults in the network secondary spot bus. Will the customer DG trip?
(Detection/communication are issues to investigate)
Network voltage during light loading is a concern(unnecessary opening) The voltage
may rise and this may cause electro-mechanical relays to open the NP. Some of the old
GE breakers are a concern with the method of relaying. Electro-mechanical breakers
must be replaced (Consensus) with addition of DG (Machine based?).
Old NPs are a concern, based on X/R ratio. The newer higher kVA are 12-13 X/R ratios.
The R values are very low. The NP may not even trip for a number of fault conditions
because of the X/R ratio. The DR increases the X/R ratio. This may require a change in
the NP relay that is used. Is the issue the relay’s ability to see the fault, or the ability of
the NP to interrupt the fault?
Also, the old NPs had no fault close capability, the newer ones do. Some installations
will require newer NPs.
Fault Detection: the DR shall detect faults on the system. How does the DR detect phgnd faults on the primary side of the network transformer? The DR does not see these
faults if the network transformer is a delta on the primary side. As long as the utility has
an NP closed, the DR does not need to see the fault and separate. The DR must be
able to see ph-ph faults also. Should the DR separate if there are at least 50% of the
NPs closed? If the fault occurs on the substation bus, how does the DR detect the fault?
If the sub bank breaker opens, the DR will be overcome by load. Is it practical to install
communication to transfer trip for faults seen by the substation breaker. Communication
would be required from all breakers feeding the spot. Fault detection by DR in a network
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
58
system will be contrary to IEEE 1547 requirements. KISS! Communication (transfer trip)
is complicated, but should be owned and maintained by the utility.
Review/Modification of Network Design Criteria ( Long term Issue – Depends on Control
jurisdiction)
N-1 is a design criteria. Putting on too large of DG would be a serious design concern.
Over-sizing the transformer would make the relays hunt and the NPs pump. Relays
would have to be de-sensitized to accommodate the larger transformer. These are a
function of impedances and voltages. The DG takes load off the transformer, unloading
the transformer and increasing the chances of the NP pumping. Should the DG be
under the control of the utility. Utility would likely install the DG at the substation bus, not
on the spot network. Controls for the protection of the network should stay under the
control of the utility. Controls for the protection of the DG should be under the control of
the DG owner.
Design criteria: if the utility has control of the DR, the utility can include the DG in the
design (planning) of the network. If the utility does not have control of the DG, it should
not consider the DR in its design (planning).
Can the NP relays be programmed with alternate settings that are implemented
automatically when the DR is on line?
====================
Closing Issues: (Prevention of “Proper” closing , initiation of “Improper” closing)
Closing back is another issue when the load in the building has dropped off.
Synch check must be performed at the customer’s tie breaker (if the customer elects to
have the capability of operating the generator to supply some critical loads during
system outages). What functions are required? This may require sync check at two
customer breakers. One of the requirements is for under-power, not reverse power.
Relays look at, normally, apparent power. (Simple Diagram to show PCC and Gen
Breakers and different tripping/closing schemes)
Frequency Issue (during closing)
Frequency: Martin’s paper addresses frequency. NP relay is not adequate for
synchronizing. But with the 50% NP rule, this condition should not occur unless there is
some failure.
For a successful closure of the NP there is a minimum amount of phasing voltage
required, that is a function of the impedance of the transformer and the load current.
The bigger the transformer is, with a corresponding lighter load the smaller the phasing
voltage and the less likely it is that the NP will close and stay closed without pumping.
The addition of DR reduces the transformer load, with a corresponding decrease in
phasing voltage, increasing the likely hood of pumping. An evaluation of the relay
settings at steady output of the DR is recommended. Review close and trip settings on
a case by case basis.
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
59
90o
Adjustable Over-Voltage Close Curve 1
Adjustable Over-Voltage Close Curve 2
PV2
PV1
0o
180o
Φ (System Impedance Angle)
I2
I1
270o
Figure X – Network Relay Closing Characteristics
Cold start-up (network is out totally) the customer’s PCC breaker must be open. The
customer PCC breaker cannot close until network has been restored for some period of
time. How does the utility insure that the customer’s PCC breaker is open? Is this size
dependent? Does the utility need to know when all or certain size generators are
brought back on line with the network? Are communication circuits needed for this?
If the network is totally out, the NPs won’t change state. It is important that the DR
comes off high speed and that the utility has assurance that the DR is disconnected.
The customer’s PCC breaker must be battery powered DC trip.
If the network breakers trip (15 cycles), will the NPs trip? Will the DR provide enough
voltage to trip the NPs?
We need to monitor the 52B contacts to ensure that closing out of sync does not occur.
We cannot delay restoring the network because of the DR. Can we depend on undervoltage tripping? The automatic transfer timing is an issue. Will a second breaker be
required to account for stuck breaker possibility? Can the DR breaker serve as the
second breaker for stuck breaker. It is unlikely the customer would want to open the
PCC and DR tie breaker. The customer will usually chose one of the two to trip.
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
60
ANNEX J:
P1547.6 CLAUSES 9 & 10 POST-BREAKOUT STATUS REPORT
Section 9 & 10 Working Group Notes of Meeting August 3, 2006
(J. Bzura revised 8/15/06)
Note: The concerns of the old Clause 9 have been integrated into this new
Clause 9, “Recommendations for Interconnection of DR on Networks”.
9. Means of Interconnecting DR on Networks (All writing team members)
Introduction: The methods below are intended to ensure:
no backfeeding of NPs
no connect or disconnect of DG via NP
no false tripping of NP
don't prevent an NP from closing appropriately
fault current limitations are considered
operational failures of components are addressed
9.1 Spot Networks - Considerations of Facility Load and DR Output (Daley, Watts)
Controlling DR Output and Facility Import
Where a utility deems necessary ...
May need a NPs "interaction with DR" system
May need a DR control system to manage the operation of the DR to
ensure satisfactory or "normal" NP operation
May need a "No go" signal from NP "interaction with DR" system
May need a "Low load" signal from NP "interaction with DR" system
May need a "Full operation allowed" signal from "interaction with DR"
system
How to determine minimum level of feeder load
Net import matters
Issue: double-ended unit substation (multiple facility feeds)
Control system manages the flow of power into the facility
Load management and shedding
Power rating and max power (can be different)
Reactive load variations (example light load NP conditions)
How DR typically controlled
Response time of automatic voltage regulators (dynamics issue?)
9.1.1 "De Minimus" DR Power Rating (Bzura)
What % of service connection is de minimus? (Example: 1/15th of load in MA)
Rating of DR relative to spot load
relative to season
relative to time and type of day demand
Minimum expected facility load for when DR is operating
"This concept assures a high probability of no reverse power flow"
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
61
9.1.2 DR Capacities Greater than De Minimus (Davis, Daley)
Active control of import power levels
Ability to accept loss of single largest facility load without falling below import
criteria
Ability to respond to facility load reductions that would cause power flow into the
spot network bus from the DR
Minimum load threshold (unload the DR)
Actual reverse real and reactive power (stop the DR)
Time sensitivity?
Control strategies to address the import power level
9.1.3 NP Auxiliary Contact Generator Trip Protection (Davis)
9.2 Area Networks: Considerations of Facility Load and DR Output (Daley, Watts)
For DR greater than de minimus, studies may be required (fault current, network
component loading, and area load flow)
Effect of DR on network load flow (distribution of power on the grid from
generators) (Davis)
Multiple feeds to facility (main-tie-main)
“The focus of this guide is for power import from the network to the facility.
Power export from DR to the network will be a topic under consideration
for a future revision.”
Size and number of DR relative to the location of their connection points and to
the locations of the loads and network transformers in the area grid (Davis)
Controlling DR Output and Facility Import
Control system manages the bidirectional flow of power
between the grid and the facility
between various internal facility components
between ... (tbd)
Load management and shedding
Power rating and max power
Reactive load variations (example light load NP conditions)
Considerations for when the number of connected NPs is reduced in emergency
situations (Sammon)
9.2.1 "De Minimus" DR Power Rating (Daley, Whitaker, Bzura)
What % is de minimus? (Example: PG&E policy)
Rating of DR relative to area grid load
relative to season
relative to time and type of day demand
relative to location (impedances)
Minimum expected facility and area grid loads for when DR is operating
Special interconnection agreement provisions (for example: time of generation)
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
62
9.2.2 DR Capacities Greater than De Minimus (Davis, Daley)
Control strategies to address the power flow
Active control of DR power levels
Ability to accept loss of single largest facility load without falling below criteria
determined by study
Ability to react to facility load reductions that would cause power flow into the
network from the DR
(Example: DR located at same facility as largest load in the network,
impact on area grid operation?)
9.3 Fault Considerations For All Secondary Networks (Costyk, Beach, Bzura)
Fault current interrupting rating of NP
Fault current contributions of DRs;
inverters, induction, synchronous
Current-limiting fuses on spot network buses
Current-limiting technologies for DRs
Fast solid state switches that interrupt within 1/8 to 1/4 cycle
Fault contribution of the system and how affected by the DR
De-sensitizing of system fault protection
9.4 Breaker failure schemes (ex: stuck breaker, not responding, etc.) (Beach)
Require minimum of two interrupting devices or functions between the DR and
the NPs
P1547.6 Meetings for August 3-4, 2006 Working Group Meeting
63