Download Stakeholder Comment and Replies Matrix AESO AUTHORITATIVE DOCUMENT PROCESS Alberta Reliability Standard

Stakeholder Comment and Replies Matrix
AESO AUTHORITATIVE DOCUMENT PROCESS
Alberta Reliability Standard – Alberta PRC-023-AB-1 Draft 2.1-Transmission Relay Loadability
Date of Request for Comment [yyyy/mm/dd]:
Period of Consultation [yyyy/mm/dd]:
2011-09-28
2011-09-28
through
2011-10-21
COMPARISON BETWEEN NERC PRC-023-1 AND CURRENT ALBERTA PRC-023-AB-1
TRANSMISSION RELAY LOADABILITY
NERC PRC-023-1
Purpose
Protective relay settings shall
not limit transmission
loadability; not interfere with
system operators’ ability to
take remedial action to protect
system reliability and; be set to
reliably detect all fault
conditions and protect the
electrical network from these
faults.
Alberta PRC-023-AB-1 Draft 2
1
(From previous consultation)
Purpose
The purpose of this reliability
standard is to ensure the
protective relay settings do not
limit transmission loadability, do
not interfere with system
operators ability to take
remedial action to protect
system reliability and, are set to
reliably detect all fault
conditions and protect the
electrical network from these
faults.
Alberta PRC-023-AB-1 Draft
2.1
(Revised version for reconsultation)
Purpose
The purpose of this reliability
standard is to ensure the
protective relay settings do not
limit transmission loadability, do
not interfere with an operator’s
ability to take remedial action to
protect the reliability of the
system, and are set to reliably
detect all fault conditions and
protect the electrical network
from these faults.
Differences between
Alberta
PRC-023-AB-1 Draft 2.1 and
NERC PRC-023-1
New Stakeholder
Comments
(Insert comments here)
AESO Replies
AltaLink
Clarified the purpose to align with the content
of proposed PRC-023-AB-1 Draft 2.1.
1. AltaLink notes that this
standard includes
requirements which
define certain guidelines
for protection system
settings (e.g. R1.12
requires the line
protection MTA to be
set to 90 degrees or
maximum allowed by
the relay manufacturer).
AltaLink is seeking
clarification as to
whether or not this
standard will be
referenced in the AESO
Protection Rules.
1.
In accordance with
the AESO’s Alberta
reliability standards
drafting principles,
proposed ISO rules
Section 502.3
Interconnected
Electric System
Protection
Requirements will not
duplicate authoritative
content in proposed
PRC-023-AB-1 Draft
2.1 and result in a
“double jeopardy”
situation. However, a
note will be added in
Information Document
# 2012-004R
1
This column is for information only.
2012-09-06 AESO Reply Matrix PRC-023-AB-1 SCCR 08-30-2012 - Final.doc
Protection System
Information to ensure
that market
participants are aware
of proposed PRC023-AB-1 Draft 2.1.
AESO Replies to Stakeholder Comments: 2012-09-06
Page 2 of 23
ENMAX
2. Clarification: Will this
standard supersede the
NERC 8a standard for
loadability, or will both
s-Atandards be effective
simultaneously?
Applicability
4.1. Transmission Owners with
load-responsive phase
protection systems as
described in Attachment A,
applied to facilities defined
below:
4.1.1 Transmission lines
operated at 200 kV and above.
4.1.2 Transmission lines
operated at 100 kV to 200 kV
as designated by the Planning
Coordinator as critical to the
reliability of the Bulk Electric
System.
4.1.3 Transformers with low
voltage terminals connected at
200 kV and above.
4.1.4 Transformers with low
Applicability
This reliability standard applies
to:
 TFOs with load-responsive
phase protection systems,
as described in Attachment
A, and with any of the
facilities defined below:
o
transmission lines
operated at 200 kV and
above.
o
transmission lines
operated at 100 kV to
200 kV as identified by
the ISO as critical to the
reliability of the BES as
required in requirement
AESO Replies to Stakeholder Comments: 2012-09-06
Applicability
This reliability standard applies
to:
(a) the legal owner of a
transmission facility,
(b) legal owner of a generating
unit
(c) legal owner of an
aggregated generating
facility
with load-responsive phase
protection systems, as
described in Appendix 1 applied
to any one of the facilities
defined below:
(i) transmission lines
operated at 200 kV
and above;
2.
Proposed PRC-023AB-1 Draft 2.1
ensures that
protection settings do
not limit a facilities
rating. NERC
standard FAC-008-3
Facility Ratings
(“NERC FAC-008-3”)
ensures that facilities
are properly
determined. The
AESO will review
NERC FAC-008-3 as
a separate initiative
and adopt it for
Alberta as
appropriate. In the
US both standards
are effective.
3.
Please refer to
requirement R6 of
proposed PRC-023AB-2 Protection and
Control Transmission
Relay Loadability
(“PRC-023-AB-2”)
and Information
Document # 2012004RS PRC-023-AB
R6 Identified
Transmission Lines
and Transformers,
being consulted on
separately, as they
address the identified
concerns.
AltaLink
The terms used to describe applicable entities
in proposed PRC-023-AB-1 Draft 2.1 have
been amended from the NERC version in
order to correctly identify the applicable
entities in Alberta and to align with terms
included in the AESO’s Consolidated
Authoritative Documents Glossary.
 New
 Amended
 Deleted
The Applicability section in proposed PRC023-AB-1 Draft 2.1 has been amended to
identify the responsible entities in Alberta.
The legal owner of an electric distribution
system was not included as all facilities in
Alberta that apply to proposed PRC-023-AB-1
3. AltaLink recommends
that the AESO include
wording to the effect “as
identified in the list as
required in requirement
R3, as published by the
ISO on the AESO
website and as
amended from time to
time by the ISO on
notice to market
participants;” and a
direct reference to the
name of the document
containing the list be
included in this standard
(e.g. “ID# …”) for clarity.
ATCO Power
Page 3 of 23
voltage terminals connected at
100 kV to 200 kV as
designated by the Planning
Coordinator as critical to the
reliability of the Bulk Electric
System.
4.2. Generator Owners with
load-responsive phase
protection systems as
described in
Attachment A, applied to
facilities defined in 4.1.1
through 4.1.4.
4.3. Distribution Providers with
load-responsive phase
protection systems as
described in Attachment A,
applied according to facilities
defined in 4.1.1 through 4.1.4.,
provided that those facilities
have bi-directional flow
capabilities.
4.4. Planning Coordinators.
R3.

o
transformers with low
voltage terminals
connected at 200 kV and
above.
o
transformers with low
voltage terminals
connected at 100 kV to
200 kV as designated by
the ISO as critical to the
reliability of the BES.
ISO
(ii) transmission lines
operated at 100 kV to
200 kV as identified
by the ISO as critical
to the reliability of
the bulk electric
system as required in
requirement R3;
(iii) transformers with low
voltage terminals
connected at 200 kV
and above; or
(iv) transformers with low
voltage terminals
connected at 100 kV
to 200 kV as
designated by the
ISO as critical to the
reliability of the bulk
electric system as
required in
requirement R3; and
(d) the ISO.
Draft 2.1 are managed by a legal owner of a
transmission facility, the legal owner of a
generating unit, or legal owner of an
aggregated generating facility.
4. ATCO Power suggests
that legal owner of a
generating unit and
legal owner of an
aggregated generating
facility be removed from
the applicability section
of this standard. The
removal of these entities
would be consistent with
the findings of NERC
Order 733 which states
in paragraph 342:
The Reliability Standard
applies to facilities 100
kV and above and to
transformers with lowvoltage terminals 200
kV and above. Because
there are no commercial
generators with a
terminal voltage as high
as 100 kV and all
generator step-up and
auxiliary power
transformers have lowvoltage windings well
below 200 kV, PRC023-1 excludes
generators and all
generator step-up and
auxiliary transformers.
Therefore, no generator
owner that is not also a
transmission owner
and/or a distribution
provider will be subject
to PRC-023-1.
4.
In Alberta, legal
owner of a generating
unit and legal owner
of an aggregated
generating facility
may own the switch
yard and associated
transmission line
protections. As such,
proposed PRC-023AB-1 Draft 2.1 must
also apply to legal
owners of generating
units and aggregated
facilities that own
switch yards and
associated
transmission line
protections. Please
refer to the
applicability section of
proposed PRC-023AB-2as its
requirements have
been revised and, in
the AESO’s opinion,
address this concern.
Furthermore, it is clear
AESO Replies to Stakeholder Comments: 2012-09-06
Page 4 of 23
from item 3.4 in
Attachment A that
generating unit
protection relays are
excluded.
Suncor Energy
AESO Replies to Stakeholder Comments: 2012-09-06
5. For this standard, where
exactly does the
jurisdiction of generation
facility owner ends and
where does the
jurisdiction of
transmission facility
owner begins? Suncor
is especially concerned
as much of the
protection systems
overlap.
5.
In Alberta either a
legal owner of a
generating unit, legal
owner of an
aggregated
generating facility, or
legal owner of a
transmission facility
may own the
transmission line
protection systems.
The responsibility of
complying with
proposed PRC-023AB-1 Draft 2.1 is
placed upon the
owner of those
protection systems.
6. (ii): What are AESO’s
guidelines for selection?
Assuming AESO
chooses to add an
existing line to this
category, will
compliance
requirements be
retroactive?
6.
The AESO’s
guidelines for
selection have been
identified in proposed
PRC-023-AB-2.
Compliance will not
be retroactive for
existing transmission
lines added to this
category by the
AESO.
7. (iv): What criteria will
7.
Please see AESO
Page 5 of 23
Effective Date
5.1. Requirement 1,
Requirement 2:
5.1.1 For circuits described in
4.1.1 and 4.1.3 above (except
for switch-on-to-fault schemes)
—the beginning of the first
calendar quarter following
applicable regulatory
approvals.
5.1.2 For circuits described in
4.1.2 and 4.1.4 above
(including switch-on-to-fault
schemes) — at the beginning
of the first calendar quarter 39
months following applicable
regulatory approvals.
5.1.3 Each Transmission
Owner, Generator Owner, and
Distribution Provider shall have
24 months after being notified
by its Planning Coordinator
pursuant to R3.3 to comply
with R1 (including all subrequirements) for each facility
that is added to the Planning
Coordinator’s critical facilities
list determined pursuant to
R3.1.
5.2. Requirement 3: 18 months
following applicable regulatory
Effective Date
For requirements R1 and R2 for
transmission lines operated at
200kV and above and
transformers with low voltage
terminals connected at 200kV
and above, except for switchon-to-fault schemes, the
beginning of the first calendar
quarter following ninety (90)
days after the date of approval
by the Commission.
For requirements R1 and R2 for
transmission lines operated at
100 kV to 200 kV as identified
by the ISO as critical to the
reliability of the BES and
transformers with low voltage
terminals connected at 100 kV
to 200 kV as designated by the
ISO as critical to the reliability of
the BES, including switch-on-tofault schemes, on the first day
th
of the month after the 39 full
month following the date of
approval by the Commission.
Requirement R3, the first day of
th
the month after the 18 full
month following the date of
approval by the Commission.
AESO Replies to Stakeholder Comments: 2012-09-06
Effective Date
For requirements R1 and R2 for
transmission lines operated at
200kV and above and
transformers with low voltage
terminals connected at 200kV
and above, except for switch-onto-fault schemes, on October 1,
2012.
For requirements R1 and R2 for
transmission lines operated at
100 kV to 200 kV as identified by
the ISO as critical to the
reliability of the bulk electric
system and transformers with
low voltage terminals connected
at 100 kV to 200 kV as
designated by the ISO as critical
to the reliability of the bulk
electric system, including
switch-on-to-fault schemes, on
July 1, 2015.
Requirement R3, on January 1,
2014.
 New
 Amended
 Deleted
The proposed effective date has been
amended to October 1, 2012 in proposed
PRC-023-AB-1 Draft 2.1 to allow a
reasonable amount of time for Alberta entities
to implement proposed PRC-023-AB-1 Draft
2.1.
AESO used to
determine this
selection? Suncor
currently has one
transformer that fits the
voltage guideline
dictated. Will this
transformer be selected
for this requirement?
AltaLink
Reply 6 above.
8. AltaLink recommends
R1 and R2 for
transmission facilities at
100 kV to 200 kV as
identified by the ISO as
critical to the reliability
of the bulk electric
system become
effective January 1,
2015 to be consistent
with the timeframe
required in R4. R4
allows market
participants 2 years to
be compliant with R1
after the addition of new
lines to the list of critical
lines between 100kV
and 200kV. The
proposed staggered
approach allows for only
1.5 years after the initial
list of critical lines has
been compiled as per
R3.
ATCO Power
8.
Please refer to
proposed PRC-023AB-2 as the effective
dates have been
revised to allow for a
reasonable amount of
time for market
participants to
implement the
requirements.
9. If the intention of this
standard is to include
generator
interconnections
9.
Please see AESO
Reply 8 above.
Page 6 of 23
approvals.
facilities, given that
some generator
interconnection lines
operate at more than
200 kV, and are sole
use facilities for the
purpose of connecting
generating units to the
AIES, changes to
protection settings of
these lines must be
coordinated with unit
turnaround schedules.
Complying with the date
of October 1, 2012 may
be problematic if
changes to these lines’
settings are required.
ATCO Power suggests
that the effective date
be changed to July 1,
2015 for R1 and R2
regardless of voltage,
for such circumstances.
EDTI
10. EDTI recommends that
all effective dates for
this standard be
consistent with
requirement R4 for
newly added facilities
to the ISO’s critical
facility list. Under
requirement R4, newly
added facilities to the
critical facility list are
permitted 2 years to
comply with
requirement R1.
11. For facilities 200kV
AESO Replies to Stakeholder Comments: 2012-09-06
10. Please see AESO
Reply 8 above.
11. Please see AESO
Reply 8 above.
Page 7 of 23
and above, EDTI
recommends an
effective date of 2
years after approval by
the AUC.
12. For facilities operated
between 100kV and
200kV that are
designated by the ISO
as critical to the BES,
EDTI recommends that
the effective date
remains as stipulated
in requirement R4, 2
years after being
added to the ISO’s
critical facilities list.
Suncor Energy
R1 . Each Transmission
Owner, Generator Owner, and
Distribution Provider shall use
any one of the following criteria
(R1.1 through R1.13) for any
specific circuit terminal to
prevent its phase protective
relay settings from limiting
transmission system loadability
while maintaining reliable
protection of the Bulk Electric
System for all fault conditions.
Each Transmission Owner,
Generator Owner, and
Distribution Provider shall
evaluate relay loadability at
0.85 per unit voltage and a
power factor angle of 30
degrees: [Violation Risk Factor:
High] [Mitigation Time Horizon:
Long Term Planning].
R1 Each TFO must use one of
the criteria set out in
requirements R1.1 through
R1.13, inclusive, for each of its
specific circuit terminals to
prevent its phase protective
relay settings from limiting
transmission system loadability
while maintaining reliable
protection of the BES for all
fault conditions; and evaluate
relay loadability at 0.85 per unit
voltage and a power factor
angle of 30 degrees.
AESO Replies to Stakeholder Comments: 2012-09-06
R1 Each legal owner of a
transmission facility, legal
owner of a generating unit and
legal owner of an aggregated
generating facility must use
one of the criteria set out in
requirements R1.1 through
R1.13, inclusive, for each
specific circuit terminal to
prevent its phase protective
relay settings from limiting
transmission system
loadability while maintaining
reliable protection of the bulk
electric system for all fault
conditions and evaluate the
above relay’s loadability at 0.85
per unit voltage and a power
factor angle of 30 degrees.
 New
Amended
 Deleted
NERC requirement R1 has been amended for
clarity and consistency and to identify the
responsible entities in Alberta.
NERC sub-requirements R1.3.1 and R1.3.2
have been amended in proposed PRC-023AB-1 Draft 2.1 to reflect their interrelationship.
12. Please see AESO
Reply 8.
No Comments
AltaLink
13. AltaLink requests
further clarity be added
on R1.12. It is not clear
which apparent
impedance the AESO
is referring to.
Typically, if there is
concern between line
protection and line load
capabilities, it is with
the Zone 3 reach of the
line protection. Is the
AESO recommending
that the zone reach
causing concern be set
to 125% of the
apparent impedance of
the line in question
which could possibly
13. Yes, the impedance
referred to is the line
impedance. Pursuant
to the requirement, if
the transmission line
capability is limited by
protection then a
setting of 125% is
required subject to the
three sub-conditions.
Page 8 of 23
R1.1. Set transmission line
relays so they do not operate
at or below 150% of the
highest seasonal Facility
Rating of a circuit, for the
available defined loading
duration nearest 4 hours
(expressed in amperes).
R1.2. Set transmission line
relays so they do not operate
at or below 115% of the
highest seasonal 15-minute
2
Facility Rating of a circuit
(expressed in amperes).
2
When a 15-minute rating has
been calculated and published
for use in real-time operations,
the 15-minute rating can be
used to establish the loadability
requirement for the protective
relays.
R1.1. Set transmission line
relays so they do not operate at
or below 150% of the highest
seasonal facility rating of a
circuit for the available defined
loading duration nearest to four
hours, expressed in amperes;
R1.1. Set transmission line
relays so they do not operate at
or below 150% of the highest
seasonal facility rating of a
circuit for the available defined
loading duration nearest to four
(4) hours, expressed in
amperes;
R1.2. Set transmission line
relays so they do not operate at
or below 115% of the highest
seasonal 15-minute facility
rating of a transmission line
expressed in amperes;
R1.2. Set transmission line
relays so they do not operate at
or below 115% of the highest
seasonal 15-minute facility rating
of a circuit expressed in
amperes;
lead to a reduction in
the desired zone
reach?
ATCO Power
14. R1.1:
Please confirm that
R1.1 applies to the
transmission circuit
thermal ratings and not
the generator
nameplate rating.
Please verify that R1.1.
refers to the
transmission facility
and not the generating
facility.
14. Alberta requirement
R1.1 applies to the
transmission line.
ATCO Power
R1.3. Set transmission line
relays so they do not operate
at or below 115% of the
maximum theoretical power
transfer capability (using a 90degree angle between the
sending-end and receiving-end
voltages and either reactance
or complex impedance) of the
circuit (expressed in amperes)
using one of the following to
perform the power transfer
calculation:
R1.3. Set transmission line
relays so they do not operate at
or below 115% of the maximum
theoretical power transfer
capability (using a 90-degree
angle between the sending-end
and receiving-end voltages and
either reactance or complex
impedance) of the transmission
line expressed in amperes,
using one of the following to
perform the power transfer
calculation:
R1.3. Set transmission line
relays so they do not operate at
or below 115% of the maximum
theoretical power transfer
capability, using a 90-degree
angle between the sending-end
and receiving-end voltages and
either reactance or complex
impedance, of the circuit
expressed in amperes, using
one of the following to perform
the power transfer calculation:
R1.3.1. An infinite source (zero
source impedance) with a 1.00
per unit bus voltage at each
R1.3.1. an infinite source (zero
source impedance) with a 1.00
per unit bus voltage at each end
R1.3.1. an infinite source, i.e.
zero source impedance, with a
1.00 per unit bus voltage at
AESO Replies to Stakeholder Comments: 2012-09-06
15. R1.6:Regarding R1.6,
the requirement to
ensure a 230%
loadability margin for
phase protection near
generators is
inconsistent with the
loading philosophy
used in the other
options and appears to
be misaligned with
IEEE Std C37.1021006, the IEEE tutorial
(95 TP 102), and the
PSRC paper titled
Performance of
Generator Protection
During Major System
Disturbances, IEEE
No. TPWRD-00370-
15. The AESO agrees
with ATCO Power that
this Alberta
requirement differs
from what was
typically done in the
past. For now, the
AESO intends to
adopt NERC’s
requirement unless a
specific reason is put
forward regarding why
it can’t be applied in
Alberta.
Page 9 of 23
end of the line.
of the transmission line; or
each end of the transmission
line; or
R1.3.2. An impedance at each
end of the line, which reflects
the actual system source
impedance with a 1.05 per unit
voltage behind each source
impedance.
R1.3.2. an impedance at each
end of the transmission line,
which reflects the actual system
source impedance with a 1.05
per unit voltage behind each
source impedance.
R1.3.2. an impedance at each
end of the transmission line,
which reflects the actual system
source impedance with a 1.05
per unit voltage behind each
source impedance.
R1.4. Set transmission line
relays on series compensated
transmission lines so they do
not operate at or below the
maximum power transfer
capability of the line,
determined as the greater of:
- 115% of the highest
emergency rating of the series
capacitor.
- 115% of the maximum power
transfer capability of the circuit
(expressed in amperes),
calculated in accordance with
R1.3, using the full line
inductive reactance.
R1.4. Set transmission line
relays on series compensated
transmission lines so they do
not operate at or below the
maximum power transfer
capability of the transmission
line, determined as the greater
of:
 115% of the highest
emergency rating of the series
capacitor, or
 115% of the maximum power
transfer capability of the
transmission line (expressed in
amperes), calculated in
accordance with requirement
R1.3, using the full transmission
line inductive reactance;
R1.4. Set transmission line
relays on series compensated
transmission lines so they do not
operate at or below the
maximum power transfer
capability of the transmission
line, determined as the greater
of:
(a) 115% of the highest
emergency rating of the
series capacitor, or
(b) 115% of the maximum
power transfer capability of
the circuit (expressed in
amperes), calculated in
accordance with requirement
R1.3, using the full
transmission line inductive
reactance;
R1.5. Set transmission line
relays on weak source systems
so they do not operate at or
below 170% of the maximum
end-of-line three-phase fault
magnitude (expressed in
amperes).
R1.5. Set transmission line
relays on weak source systems
so they do not operate at or
below 170% of the maximum
end-of-line three-phase fault
magnitude, expressed in
amperes;
R1.5. Set transmission line
relays on weak source systems
so they do not operate at or
below 170% of the maximum
end-of-line three-phase fault
magnitude, expressed in
amperes;
R1.6. Set transmission line
relays applied on transmission
lines connected to generation
stations remote to load so they
R1.6. Set transmission line
relays applied on transmission
lines connected to generating
facilities remote to load so they
R1.6. Set transmission line
relays applied on transmission
lines connected to a generating
facility remote to load so they do
AESO Replies to Stakeholder Comments: 2012-09-06
2003, which NERC’s
application reference
document,
Determination and
Application of Practical
Relaying Loadiability
Ratings Version 1,
cites as a justification
for this unusually
conservative value.
Based on NERC’s
Technical Reference
Document Power Plant
and Transmission
System Protection
Coordination, Revision
1, NERC appears to be
providing an
unconventionally wide
loadability margin to
coordinate with exciter
field forcing, but this is
not clear from the
standard, and may not
be appropriate in the
AIES.
Suncor Energy
16. R1: What is the exact
definition of BES for
this specification?
16. BES is defined in the
AESO’s Consolidated
Authoritative
Document Glossary
located on the AESO
website.
Page 10 of 23
do not operate at or below
230% of the aggregated
generation nameplate
capability.
do not operate at or below
230% of the aggregated
generating unit(s) nameplate
capability;
not operate at or below 230% of
the total nameplate capability of
all the generating units at the
generating facility;
R1.7. Set transmission line
relays applied at the load
center terminal, remote from
generation stations, so they do
not operate at or below 115%
of the maximum current flow
from the load to the generation
source under any system
configuration.
R1.7. Set transmission line
relays applied at the load center
terminal, remote from
generating facilities, so they do
not operate at or below 115% of
the maximum current flow from
the load to the generation
source under any system
configuration;
R1.7. Set transmission line
relays applied at the load center
terminal, remote from a
generating facility, so they do not
operate at or below 115% of the
maximum current flow from the
load to the generation source
under any system configuration;
R1.8. Set transmission line
relays applied on the bulk
system-end of transmission
lines that serve load remote to
the system so they do not
operate at or below 115% of
the maximum current flow from
the system to the load under
any system configuration.
R1.8. Set transmission line
relays applied on the bulk
system-end of transmission
lines that serve load remote to
the system so they do not
operate at or below 115% of the
maximum current flow from the
system to the load under any
system configuration;
R1.8. Set transmission line
relays applied on the systemend of transmission lines that
serve load remote to the
system so they do not operate
at or below 115% of the
maximum current flow from the
system to the load under any
system configuration;
R1.9. Set transmission line
relays applied on the load-end
of transmission lines that serve
load remote to the bulk system
so they do not operate at or
below 115% of the maximum
current flow from the load to
the system under any system
configuration.
R1.9. Set transmission line
relays applied on the load-end
of transmission lines that serve
load remote to the BES so they
do not operate at or below
115% of the maximum current
flow from the load to the system
under any system configuration;
R1.9. Set transmission line
relays applied on the load-end
of transmission lines that serve
load remote to the system so
they do not operate at or below
115% of the maximum current
flow from the load to the system
under any system configuration;
R1.10. Set transformer fault
protection relays and
transmission line relays on
transmission lines terminated
only with a transformer so that
they do not operate at or below
the greater of:
R1.10. Set transformer fault
protection relays and
transmission line relays on
transmission lines terminated
only with a transformer so that
they do not operate at or below
the greater of:
AESO Replies to Stakeholder Comments: 2012-09-06
R1.10. Set transformer fault
protection relays and
transmission line relays on
transmission lines terminated
only with a transformer so that
they do not operate at or below
the greater of:
The typographical error made in Alberta
requirement R1.10 of the previously proposed
17. In addition, can AESO
clarify “shall evaluate
relay loadability at 0.85
per unit voltage and a
power factor angle of
30 degrees?” Does this
mean assumption of
0.85pu voltage and 30
degrees load during
loadability study? Does
this requirement
require Suncor to set
our transmission relays
according to 0.85pu
voltage and 30
degrees load?
17. During system events,
voltage depressions
will occur. To meet
these requirements,
settings must be
applied such that 0.85
per unit voltage does
not cause a false trip.
Load angles are
assumed to be 30
degrees.
18. R1.1: Can AESO
provide guidance on
“nearest 4 hours?”
Does relay settings
have to be altered
every 4 hours / every
season?
18. The relay settings are
to be based on the
transmission lines
four (4) hour rating
not the short term
emergency rating. At
four (4) hours the
AESO anticipates this
will essentially be the
steady state rating.
19. R1.2: Does this means
AESO would require
Suncor to reset all
transmission relay
every season? Can
AESO define “15minute Facility
Rating?” What if such
data is not available?
19. As drafted, the legal
owner is to use the
highest seasonal
rating such that the
relay setting does not
causes capacity
constraints. By using
the highest relay
rating no season
Page 11 of 23
- 150% of the applicable
maximum transformer
nameplate rating (expressed in
amperes), including the forced
cooled ratings corresponding to
all installed supplemental
cooling equipment.
- 115% of the highest operator
established emergency
transformer rating.
 115% of the applicable
maximum transformer
nameplate rating expressed in
amperes, including the forced
cooled ratings corresponding to
all installed supplemental
cooling equipment; or
 115% of the highest operator
established emergency
transformer rating;
(a) 150% of the applicable
maximum transformer
nameplate rating, expressed
in amperes, including the
forced cooled ratings
corresponding to all installed
supplemental cooling
equipment; or
(b) 115% of the highest
established emergency
transformer rating;
R1.11. For transformer
overload protection relays that
do not comply with R1.10 set
the relays according to one of
the following:
Set the relays to allow the
transformer to be operated at
an overload level of at least
150% of the maximum
applicable nameplate rating, or
115% of the highest operator
established emergency
transformer rating, whichever is
greater. The protection must
allow this overload for at least
15 minutes to allow for the
operator to take controlled
action to relieve the overload.
Install supervision for the
relays using either a top oil or
simulated winding hot spot
temperature element. The
setting should be no less than
100° C for the top oil or 140° C
for the winding hot spot
3
temperature .
3
IEEE standard C57.115,
Table 3, specifies that
transformers are to be
designed to withstand a
R1.11. For transformer overload
protection relays that do not
comply with requirement R1.10
set the relays according to the
following:
Set the relays to allow the
transformer to be operated at
an overload level of at least
150% of the maximum
applicable nameplate rating, or
115% of the highest emergency
transformer rating, whichever is
greater. The protection must
allow this overload for at least
15 minutes to allow for the
system operator to take
controlled action to relieve the
overload. Install supervision for
the relays using either a top oil
or simulated winding hot spot
temperature element. The
setting should be no less than
100°C for the top oil or 140°C
for the winding hot spot
temperature;
R1.11. For transformer overload
protection relays that do not
comply with requirement R1.10
set the relays to allow the
transformer to be operated at an
overload level of at least 150%
of the maximum applicable
nameplate rating, or 115% of the
highest emergency transformer
rating, whichever is greater. The
protection relay must allow this
overload for at least fifteen (15)
minutes to allow the system
operator to take controlled
action to relieve the overload.
Install supervision for the relays
using either a top oil or
simulated winding hot spot
temperature element. The
setting should be no less than
100°C for the top oil or 140°C for
the winding hot spot
temperature;
AESO Replies to Stakeholder Comments: 2012-09-06
PRC-023-AB-1 Draft 2 has been corrected in
proposed PRC-023-AB-1 Draft 2.1 to reflect
“150%” of the applicable maximum
transformer nameplate rating which was
incorrectly stated as “115%”.
R1.3. Set transmission line relays so they do
not operate at or below 115% of the maximum
theoretical power transfer capability, using a
90-degree angle between the sending-end
and receiving-end voltages and either
reactance or complex impedance, of the
circuit expressed in amperes, using one of the
following to perform the power transfer
calculation:
R1.3.1. an infinite source, i.e. zero source
impedance, with a 1.00 per unit bus voltage
at each end of the transmission line; or
R1.3.2. an impedance at each end of the
transmission line, which reflects the actual
system source impedance with a 1.05 per
unit voltage behind each source impedance
What is the rationale
behind 115%?
setting changes would
be required.
In Alberta, the legal
facility owner is
accountable for rating
their facilities. The
fifteen (15) minute
rating is what some
transmission facility
owners have been
providing as their
emergency ratings.
When the AESO
reviews and
implements NERC
FAC-008-3 further
detail regarding
methodology will be
developed.
The 115%
requirement provides
15% margin to ensure
the settings do not
restrict the lines
capacity.
20. R1.3: Can AESO
provide additional
details such as
diagrams to better
explain the power
transfer study
described above. Does
“90-degree angle
between the sendingend and receiving-end
voltages” indicates a
phase shift of 90degree during
transmission of each
20. R1.3 is intended to be
a simple calculation
using the theoretical
maximum transfer
limit. The following
formula is the power
transfer formula which
may be used:
P = V1 V2 sin (90)/ line X
Page 12 of 23
winding hot spot temperature
of 180 degrees C, and cautions
that bubble formation may
occur above 140 degrees C.
phase? What
significance does this
implies if each phase is
shifted by the same
amount?
R1.12. When the desired
transmission line capability is
limited by the requirement to
adequately protect the
transmission line, set the
transmission line distance
relays to a maximum of 125%
of the apparent impedance (at
the impedance angle of the
transmission line) subject to
the following constraints:
R1.12. When the desired
transmission line capability is
limited by the requirement to
adequately protect the
transmission line, set the
transmission line distance
relays to a maximum of 125%
of the apparent impedance (at
the impedance angle of the
transmission line) subject to the
following constraints:
R1.12. When the desired
transmission line capability is
limited by the requirement to
adequately protect the
transmission line, set the
transmission line distance relays
to a maximum of 125% of the
apparent impedance (at the
impedance angle of the
transmission line) subject to the
following constraints:
R1.12.1. Set the maximum
torque angle (MTA) to 90
degrees or the highest
supported by the manufacturer.
R1.12.1. Set the maximum
torque angle (MTA) to 90
degrees or the highest setting
supported by the manufacturer.
R1.12.1. Set the maximum
torque angle to ninety (90)
degrees or the highest setting
supported by the manufacturer.
R1.12.2. Evaluate the relay
loadability in amperes at the
relay trip point at 0.85 per unit
voltage and a power factor
angle of 30 degrees.
R1.12.2. Evaluate the relay
loadability in amperes at the
relay trip point at 0.85 per unit
voltage and a power factor
angle of 30 degrees; and
R1.12.2. Evaluate the relay
loadability in amperes at the
relay trip point at 0.85 per unit
voltage and a power factor
angle of 30 degrees; and
R1.12.3. Include a relay setting
component of 87% of the
current calculated in R1.12.2 in
the Facility Rating
determination for the circuit.
R1.12.3. Include a relay setting
component of 87% of the
current calculated in
requirement R1.12.2. in the
facility rating determination for
the circuit.
R1.12.3. Include a relay setting
component of 87% of the current
calculated in requirement
R1.12.2 in the facility rating
determination for the circuit.
R1.13. Where other situations
present practical limitations on
circuit capability, set the phase
protection relays so they do not
operate at or below 115% of
such limitations.
R1.13. Where other situations
present practical limitations on
circuit capability, set the phase
protection relays so they do not
operate at or below 115% of
such limitations.
R1.13. Where other situations
present practical limitations on
circuit capability, set the phase
protection relays so they do not
operate at or below 115% of
such limitations.
AESO Replies to Stakeholder Comments: 2012-09-06
An example would help
eliminate any potential
miscommunication
regarding this
requirement.
21. R1.4: Once again, will
it be possible if AESO
provide an example
case study using the
technique stated
above. This will greatly
assist in eliminating
any inconstant
assumptions from the
original intent of
AESO.
21. There are two series
compensated lines
planned in Alberta.
The legal owners of
these lines will need
to determine the
highest emergency
rating of the series
capacitor and the
maximum power
transfer capability of
the circuit in order to
meet this Alberta
requirement R1.4.
22. R1.5: Can AESO
provide definition on
“weak source systems”
and “maximum end ofline three-phase fault
magnitude?”
22. The AESO does not
intend to define this
term as it is a
commonly understood
industry term.
23. R1.7: Please define
“load center terminal.”
23. Please see AESO
Reply 22 above.
24.
R1.8 - 1.9: What is
AESO’s definition of “load
remote to the system?”
24.
Please see AESO
Reply 22 above.
Page 13 of 23
AESO Replies to Stakeholder Comments: 2012-09-06
25. R1.12: Suncor
requests AESO to
define “distance
relays.” Also, what is
the requirement, if the
impedance angle of
the transmission line is
not constant?
25. Please see AESO
Reply 22 above.
26. R1.12.1: Suncor
requests AESO to
define maximum
torque angle (MTA).
26. Please see AESO
Reply 22 above.
27. R1.12.3: Suncor
requests AESO to
clarify this section.
27. Alberta requirement
R1.12.3 requires a
setting of 87% of the
current rating
calculated in Alberta
requirement R1.12.2.
Page 14 of 23
2
R2. The Transmission Owner,
Generator Owner, or
Distribution Provider that uses
a circuit capability with the
practical limitations described
in R1.6, R1.7, R1.8, R1.9,
R1.12, or R1.13 shall use the
calculated circuit capability as
the Facility Rating of the circuit
and shall obtain the agreement
of the Planning Coordinator,
Transmission Operator, and
Reliability Coordinator with the
calculated circuit capability.
[Violation Risk Factor: Medium]
[Time Horizon: Long Term
Planning]
R2 A TFO that uses a circuit
capability with the practical
limitations described in
requirements R1.6, R1.7, R1.8,
R1.9, R1.12, or R1.13 must use
the calculated circuit capability
as the facility rating of the circuit
and must obtain the agreement
of the ISO to use the calculated
circuit capability
R2. A legal owner of a
transmission facility, legal
owner of a generating unit and
legal owner of an aggregated
generating facility that uses a
circuit capability with the
practical limitations described in
requirements R1.6, R1.7, R1.8,
R1.9, R1.12, or R1.13 must use
the calculated circuit capability
as the facility rating of the circuit
and must obtain the agreement
of the ISO to use the calculated
circuit capability.
 New
 Amended
 Deleted
R3. The Planning Coordinator
shall determine which of the
facilities (transmission lines
operated at 100 kV to 200 kV
and transformers with low
voltage terminals connected at
100 kV to 200 kV) in its
Planning Coordinator Area are
critical to the reliability of the
Bulk Electric System to identify
the facilities from 100 kV to 200
kV that must meet
Requirement 1 to prevent
potential cascade tripping that
may occur when protective
relay settings limit transmission
loadability. [Violation Risk
R3. The ISO must identify
which transmission lines
operated at 100 kV to 200 kV
and transformers with low
voltage terminals connected at
100 kV to 200 kV are critical to
the reliability of the BES in
order to prevent potential
cascade tripping that may occur
when protective relay settings
limit transmission loadability. In
order to carry out this
requirement, the ISO must do
the following:
R3. The ISO must identify which
transmission lines operated at
100 kV to 200 kV and
transformers with low voltage
terminals connected at 100 kV to
200 kV are critical to the
reliability of the bulk electric
system in order to prevent
potential cascading that may
occur when protective relay
settings limit transmission
loadability. In order to carry out
this requirement, the ISO must
do the following:
 New
Amended
 Deleted
Suncor Energy
NERC requirement R2 amended in proposed
PRC-023-AB-1 Draft 2.1 to identify
requirements of the responsible entities in
Alberta.
28. R2: Suncor requests
AESO to define or
provide example of
“out-of-step blocking
elements.”
28. Please see AESO
Reply 22 above.
2
Alberta Variance : The WECC Reliability
Coordinator is not included in Alberta
requirement R2. NERC requirement R2 states
that agreement shall be obtained from the
Planning Coordinator, Transmission Operator,
and Reliability Coordinator. The AESO is the
authority from which legal owners of
transmission facilities, generating units and
aggregated generating units will obtain
agreement for the calculated circuit capability
and the AESO will consult with the WECC
Reliability Coordinator at its discretion.
NERC requirement R3 has been amended in
proposed PRC-023-AB-1 Draft 2.1 for clarity,
consistency and to identify requirements of
the responsible entities in Alberta.
AltaLink
29. 5. Same comments as
in the Applicability
section.
29. Please AESO Reply 3
above.
Deleted redundant NERC requirement in R3
that states, “These identified facilities must
meet requirement R1” from Alberta
requirement in proposed PRC-023-AB-1 Draft
2.1.
An Alberta variance is a change from the US Reliability Standard that the AESO has determined is material.
AESO Replies to Stakeholder Comments: 2012-09-06
Page 15 of 23
Factor: Medium] [Time
Horizon: Long Term Planning]
R3.1. The Planning
Coordinator shall have a
process to determine the
facilities that are critical to the
reliability of the Bulk Electric
System.
R3.1 The ISO must have a
process to determine the
facilities that are critical to the
reliability of the BES and must
consider input from adjoining
planning coordinators and
affected reliability coordinators.
R3.1 The ISO must have a
process to determine the
facilities that are critical to the
reliability of the bulk electric
system and must consider input
from adjoining planning
coordinators and affected
reliability coordinators.
R3.2. The Planning
Coordinator shall maintain a
current list of facilities
determined according to the
process described in R3.1.
R3.2 The ISO must maintain a
current list of facilities
determined according to the
process specified in
requirement R3.1.
R3.2 The ISO must maintain a
current list of facilities
determined according to the
process specified in requirement
R3.1.
R3.3. The Planning
Coordinator shall provide a list
of facilities to its Reliability
Coordinators, Transmission
Owners, Generator Owners,
and Distribution Providers
within 30 days of the
establishment of the initial list
and within 30 days of any
changes to the list.
R3.3 The ISO must provide a
list of facilities maintained
pursuant to requirement R3.2 to
each TFO within 30 days of the
establishment of the initial list
and within 30 days of any
changes to the list.
R3.3 The ISO must provide a list
of facilities maintained pursuant
to requirement R3.2 to each
legal owner of a transmission
facility, legal owner of a
generating unit and legal
owner of an aggregated
generating facility on such list
within thirty (30) days of the
establishment of the initial list
and within thirty (30) days of any
changes to the list.
R4 TFOs must comply with
requirement R1 for all new
facilities added to the ISO’s list
of facilities within 2 years of
receipt from the ISO as
contemplated in requirement
R3.3
R4 The legal owner of a
transmission facility, legal
owner of a generating unit and
legal owner of an aggregated
generating facility must comply
with requirement R1 for all
facilities added to the ISO’s list
of facilities, as contemplated in
requirement R3.3, within two (2)
years of receipt of such list.
AESO Replies to Stakeholder Comments: 2012-09-06
 New
Amended
 Deleted
Alberta requirement R4 added to in proposed
PRC-023-AB-1 Draft 2.1 to address timelines
for responsible entities to meet Alberta
requirement R1 for new facilities added to the
AESO list of facilities. This is consistent with
the timelines in the effective date section of
Capital Power
30. Capital Power
appreciates the
opportunity to
comment on the
proposed reliability
standard.
Capital Power notes
that the level of impact
30. The AESO disagrees
with Capital Power’s
suggested
amendment. Once a
transmission line or
transformer is
identified as being
important to the
system, the AESO
Page 16 of 23
the NERC reliability standard.
for implementing this
standard would require
a comparison of the
existing relay settings
against those listed in
Requirements R1.1 to
R1.13. Evaluation of a
setpoint modification
required to conform
with R1.1 to R1.13 and
whether the existing
relay could be
modified, or if
replacement would be
required. The
modifications may also
require an outage,
which may or may not
fall within the timeline
set by the AESO, and
a facility’s current
planned outage
schedule and reevaluation of the
protection system
coordination. Capital
Power requests the
following wording to
assist in managing the
complexity of this
implementation:
believes that two (2)
years is adequate
time to comply with
these requirements.
Please review Alberta
requirement R6.1 of
proposed PRC-023AB-2.
R4 The legal owner of
a transmission
facility, legal owner of
a generating unit and
legal owner of an
aggregated
generating facility
must comply with
requirement R1 for all
facilities added to the
AESO Replies to Stakeholder Comments: 2012-09-06
Page 17 of 23
ISO’s list of facilities,
as contemplated in
requirement R3.3,
within two (2) years of
receipt of such list, or
as may otherwise be
agreed to by the ISO.
Suncor Energy
No Comments
M1. The Transmission Owner,
Generator Owner, and
Distribution Provider shall each
have evidence to show that
each of its transmission relays
are set according to one of the
criteria in R1.1 through R1.13.
(R1)
MR1. The TFO must have
evidence to show that each of
its transmission relays is set
according to one of the criteria
in requirements R1.1 through
R1.13.
M2. The Transmission Owner,
Generator Owner, and
Distribution Provider with
transmission relays set
according to the criteria in
R1.6, R1.7, R1.8, R1.9, R1.12,
or R.13 shall have evidence
that the resulting Facility Rating
was agreed to by its associated
Planning Coordinator,
MR2 The TFO with
transmission relays set
according to the criteria in
requirements R1.6, R1.7, R1.8,
R1.9, R1.12, or R.13 must have
evidence that the ISO agreed to
the resulting facility rating.
Records of actual settings are
within acceptable tolerances of
the applicable criteria in
requirements R1.1 through
R1.13.
AESO Replies to Stakeholder Comments: 2012-09-06
MR1. Evidence of using one of
the criteria identified in
requirements R1.1 through
R1.13 as required in requirement
R1 exists. Evidence may include
spreadsheets or summaries of
calculations to show that each of
its transmission relays is set in
accordance with requirement
R1.
MR2. Evidence of using and
obtaining the agreement to use
the calculated circuit capability
as required in requirement R2
exists. Evidence may include:
(a) facility rating spreadsheets
or facility rating database to
show that the calculated
circuit capability was used
as the facility rating of the
Suncor Energy
No Comments
ATCO Power
31. ATCO Power suggests
deleting MR2 (a), as
MR2 (b) (dated
correspondence from
ISO) is necessary and
sufficient to show
compliance with R2.
Suncor Energy
31. Please review the
measures in proposed
PRC-023-AB-2.
Page 18 of 23
Transmission Operator, and
Reliability Coordinator. (R2)
circuit; and
(b) dated correspondence to
show that the calculated
circuit capability was agreed
to by the ISO.
No Comments
M3. The Planning Coordinator
shall have a documented
process for the determination
of facilities as described in R3.
The Planning Coordinator shall
have a current list of such
facilities and shall have
evidence that it provided the
list to the appropriate Reliability
Coordinators, Transmission
Operators, Generator
Operators, and Distribution
Providers. (R3)
MR3. The measures for
requirement R3 are identified in
the sub-measures below.
MR3.1 Evidence of having a
process and considering input as
required in requirement R3.1
exists. Evidence may include a
documented process and
documentation to show input
from adjoining planning
coordinators and affected
reliability coordinators were
considered.
Suncor Energy
MR3.1 Written process exists
which includes input from
adjoining planning coordinators
and affected reliability
coordinators and is of sufficient
detail to meet requirements
specified in requirement R3.1.
MR3.2 List is complete and up
to date as specified in
requirement R3.2.
MR3.2 Evidence of maintaining
a current list of facilities as
required in requirement R3.2
exists. Evidence may include a
list published on the AESO
website which identifies the
issue date, version, and revision
history.
MR3.3 Confirmation that the
ISO provided the list as
specified in requirement R3.3.
MR3.3 Evidence of providing a
list of facilities as required in
requirement R3.3 exists.
Evidence may include email or
mail to appropriate recipients.
MR4 Evidence of complying with
requirement R1 as required in
requirement R4 exists. Evidence
may include spreadsheets or
summaries of calculations to
show that each facility added to
the ISO’s list is set in
AESO Replies to Stakeholder Comments: 2012-09-06
No Comments
Suncor Energy
No Comments
Page 19 of 23
accordance with requirement R1
and the date the protective relay
setting changed, if required.
Compliance
To view the compliance section
D of the NERC reliability
standard follow this link:
http://www.nerc.com/files/PRC023-1.pdf
The Alberta reliability standards do not
contain a compliance section. Compliance
with all Alberta reliability standards is
completed in accordance with the Alberta
Reliability Standards Compliance Monitoring
Program, available on the AESO website at:
http://www.aeso.ca/loadsettlement/17189.html
Regional Differences
Regional Differences
Regional Differences
None identified.
None identified.
None identified.
Attachment A / Appendix 1
COMPARISON BETWEEN NERC PRC-023-1 AND CURRENT ALBERTA PRC-023-AB-1
TRANSMISSION RELAY LOADABILITY
NERC PRC-023-1
3
Alberta PRC-023-AB-1 Draft 2
3
(From previous consultation)
Alberta PRC-023-AB-1 Draft
2.1
(Revised version for reconsultation)
Attachment A
Appendix 1
Appendix 1
1. This reliability standard
includes any protective
functions which could trip with
or without time delay, on load
current, including but not limited
to:
1.1. Phase distance.
1.2. Out-of-step tripping.
1.3. Switch-on-to-fault.
1.4. Overcurrent relays.
1.5. Communications aided
protection schemes
including but not limited to:
1. This reliability standard includes
any protective functions which
could trip with or without time
delay, on load current, including
but not limited to:
1.1. Phase distance.
1.2. Out-of-step tripping.
1.3. Switch-on-to-fault.
1.4. Overcurrent relays.
1.5. Communications aided
protection schemes including
but not limited to:
1.5.1 Permissive
1. This reliability standard
includes any protective
functions which could trip with
or without time delay, on load
current, including:
1.1. Phase distance;
1.2. Out-of-step tripping;
1.3. Switch-on-to-fault;
1.4. Overcurrent relays;
and
1.5. Communications aided
protection schemes
including:
Differences between
Alberta
PRC-023-AB-1 Draft 2.1 and
NERC PRC-023-1
Stakeholder Comments
(Insert comments here)
AESO Replies
Suncor Energy
32. A1: How far does the association
reaches? Does this include low /
medium voltage distribution assets?
32. The Appendix is to
be used in
conjunction with the
Applicability section.
This includes
transmission lines
operated at or above
200kV and those
facilities below
200kV identified by
the AESO.
This column is for information only.
AESO Replies to Stakeholder Comments: 2012-09-06
Page 20 of 23
COMPARISON BETWEEN NERC PRC-023-1 AND CURRENT ALBERTA PRC-023-AB-1
TRANSMISSION RELAY LOADABILITY
NERC PRC-023-1
1.5.1 Permissive
overreach transfer
trip (POTT).
1.5.2 Permissive
under-reach transfer
trip (PUTT).
1.5.3 Directional
comparison blocking
(DCB).
1.5.4 Directional
comparison
unblocking (DCUB).
Alberta PRC-023-AB-1 Draft 2
3
(From previous consultation)
overreach transfer trip
(POTT).
1.5.2 Permissive underreach transfer trip (PUTT).
1.5.3 Directional
comparison blocking
(DCB).
1.5.4 Directional
comparison unblocking
(DCUB).
2. This reliability standard
includes out-of-step blocking
schemes which must be
evaluated to ensure that they
do not block trip for faults
during the loading conditions
defined within this reliability
standard’s requirements.
2. This reliability standard includes
out-of-step blocking schemes
which must be evaluated to
ensure that they do not block trip
for faults during the loading
conditions defined within this
reliability standard’s requirements.
3. The following protection
systems are excluded from the
requirements of this reliability
standard:
3. The following protection
systems are excluded from the
requirements of this reliability
standard:
3.1. Relay elements that are
only enabled when other
relays or associated systems
fail. For example:
• Overcurrent elements
that are only enabled
during loss of potential
3.1. Relay elements that are
only enabled when other
relays or associated systems
fail. For example:
• Overcurrent elements that
are only enabled during
loss of potential conditions;
AESO Replies to Stakeholder Comments: 2012-09-06
Alberta PRC-023-AB-1 Draft
2.1
(Revised version for reconsultation)
1.5.1 Permissive
overreach transfer trip;
1.5.2 Permissive
under-reach transfer
trip;
1.5.3 Directional
comparison blocking;
and
1.5.4 Directional
comparison
unblocking.
2. This reliability standard
includes out-of-step blocking
schemes such that that they do
not block trip for faults during
the loading conditions defined
within the requirements of this
reliability standard.
3. The following protection
systems are excluded from
the requirements of this
reliability standard:
3.1. Relay elements that
are only enabled when
other relays or associated
systems fail. For example:
• Overcurrent elements
that are only enabled
during loss of potential
Differences between
Alberta
PRC-023-AB-1 Draft 2.1 and
NERC PRC-023-1
Stakeholder Comments
(Insert comments here)
33. A1.1 - 1.5: Suncor requests AESO to
provide the specific definition of the
following:




AESO Replies
33. Please see AESO
Reply 22 above.
Phase distance.
Out-of-step tripping.
Switch-on-to-fault.
Communications aided protection
schemes
 Permissive overreach transfer
trip.
 Permissive under reach transfer
trip.
 Directional comparison blocking.
 Directional comparison
unblocking.
34. R3.3: Please define “stable power
swings.”
35. R3.4: Please clarify by providing
examples.
36. R3.6: Does this statement refer to
relays which allows minimum of 15
34. Please see AESO
Reply 22 above.
35. All generator
protection systems
will need to be
reviewed by the
legal owner.
Examples may
include any phase
overcurrent or
distance relay which
would have to be
closely examined.
36. Section 3.6 of
Appendix 1 to relays
Page 21 of 23
COMPARISON BETWEEN NERC PRC-023-1 AND CURRENT ALBERTA PRC-023-AB-1
TRANSMISSION RELAY LOADABILITY
NERC PRC-023-1
conditions; or
• Elements that are only
enabled during a loss of
communications.
Alberta PRC-023-AB-1 Draft 2
3
(From previous consultation)
or
• Elements that are only
enabled during a loss of
communications.
Alberta PRC-023-AB-1 Draft
2.1
(Revised version for reconsultation)
conditions; or
• Elements that are only
enabled during a loss of
communications.
3.2. Protection systems
intended for the detection of
ground fault conditions.
3.2. Protection systems
intended for the detection of
ground fault conditions.
3.2. Protection systems
intended for the detection
of ground fault conditions.
3.3. Protection systems
intended for protection
during stable power swings.
3.3. Protection systems
intended for protection during
stable power swings.
3.3. Protection systems
intended for protection
during stable power
swings.
3.4. Generating unit protection
relays that are susceptible to
load.
3.4. Generating unit
protection relays that are
susceptible to load.
3.5. Relay elements used only
for RASs applied and
approved in accordance with
reliability standards PRC-015AB-0, PRC-016-AB-0 and
PRC-017-AB-0.
3.5. Relay elements used
only for remedial action
schemes identified in the
ISO RAS database as
published by the ISO on
the AESO website, and as
amended from time to time
by the ISO on notice to
market participants.
3.6. Protection systems that
are designed only to respond
in time periods which allow
operators 15 minutes or
greater to respond to overload
conditions.
3.6. Protection systems
that are designed only to
respond in time periods
which allow operators
fifteen (15) minutes or
greater to respond to
3.4. Generating unit
protection relays that are
susceptible to load.
3.5. Relay elements used
only for Special Protection
Systems applied and
approved in accordance with
NERC Reliability Standards
PRC-012 through PRC-017.
3.6. Protection systems that
are designed only to
respond in time periods
which allow operators 15
minutes or greater to
respond to overload
AESO Replies to Stakeholder Comments: 2012-09-06
Differences between
Alberta
PRC-023-AB-1 Draft 2.1 and
NERC PRC-023-1
Stakeholder Comments
(Insert comments here)
minutes of overload before tripping?
Or does the statement mean
something else? Please clarify.
37. R3.7: Please clarify by providing
example.
AESO Replies
that operate in
fifteen (15) minutes
or longer for
overload conditions.
37. An examples would
be where a
transmission facility
owner might use a
SEL-049 relay and
dynamically rate a
transmission line.
Page 22 of 23
COMPARISON BETWEEN NERC PRC-023-1 AND CURRENT ALBERTA PRC-023-AB-1
TRANSMISSION RELAY LOADABILITY
NERC PRC-023-1
Alberta PRC-023-AB-1 Draft 2
3
(From previous consultation)
conditions.
Alberta PRC-023-AB-1 Draft
2.1
(Revised version for reconsultation)
overload conditions.
3.7. Thermal emulation
relays which are used in
conjunction with dynamic
Facility Ratings.
3.7. Thermal emulation relays
which are used in conjunction
with dynamic Facility Ratings.
3.7. Thermal emulation
relays which are used in
conjunction with dynamic
facility ratings.
3.8. Relay elements
associated with DC lines.
3.8. Relay elements
associated with DC lines.
3.8. Relay elements
associated with direct
current lines.
3.9. Relay elements
associated with DC
converter transformers.
3.9. Relay elements
associated with DC converter
transformers.
3.9. Relay elements
associated with direct
current converter
transformers.
AESO Replies to Stakeholder Comments: 2012-09-06
Differences between
Alberta
PRC-023-AB-1 Draft 2.1 and
NERC PRC-023-1
Stakeholder Comments
(Insert comments here)
AESO Replies
Page 23 of 23