File Name: \\oktulsafp002\tplan\Grpdate\NERC\AEP West Intrcnt_guidelines ver_ 10-8-2007.pdf
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Requirements for
Connection of New Facilities or
Changes to Existing Facilities Connected to
The AEP West Transmission System
October 8, 2007
Note: This document has been prepared by, and is the property of, American Electric Power Company, Inc. This document may be changed by AEP.
Users should consult the OASIS site at http://www.aep.com/about/codeofconduct/OASIS/default.asp to determine the latest effective version.
TRANSMISSION PLANNING GUIDELINE
TITLE: Requirements for Connection of New Facilities or Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Responsible Engineer:
Rev. 3
Steve M Scott
Page 1 of 98
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Always check for the latest revision prior to use.
Document Control
Preparation
ACTION
NAME(S)
TITLE
Prepared by:
Steve M. Scott
Engineer
Reviewed by:
Teresa A. Gallup
Reviewed by:
J. Paul Hassink
Approved by:
Edward G. Schnell
Manager
SWTP
Manager
TTP
Director
TP
Review Cycle
Quarterly
Semi-annual
Annual
X
As Needed
X
Release
0
DATE
RELEASED
12/12/2006
1
5/4/2007
2
6/12/2007
3
8/23/2007
VERSION
FILE NAME
CHANGE
NOTICE
AEP West
Intrcnt_guidelines ver_
12-12-2006
AEP West
Intrcnt_guidelines ver_
5-4-2007
AEP West
Intrcnt_guidelines ver_
6-12-2007
AEP West
Intrcnt_guidelines ver_
8-23-2007
REMARKS
Update technical data
Standardize with AEP East
Guidelines.
Standardize with AEP East
Guidelines.
Standardize with AEP East
Guidelines.
Distribution List
NAME(S)
DEPARTMENT
TITLE
Teresa Gallup
Southwest Transmission Planning
Manager
J. Paul Hassink
Texas Transmission Planning
Manager
Transmission and Interconnection
Services West
FERC Order 890
Manager
Robert Pennybaker
OASIS
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
Page 2 of 98
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
1.0
2.0
3.0
4.0
5.0
6.0
7.0
8.0
Introduction
Interconnection Practices and General Requirements for New Transmission Generation Facilities
2.1
Generation Sources
2.2
Practices for Parallel Generation
2.3
Practices for Separate and Parallel System
2.4
Induction Generators
2.5
Inverter Systems
2.6
Specific Interconnection Requirements
2.7
General Operating and Design Requirements
2.8
Restriction on Using Autotransformer Tertiary to Supply Load
Interconnection Practices and General Requirements for New Transmission Establishing New Interconnections with
Other Control Areas
3.1
Design Information
3.2
General Operating and Design Requirements
Interconnection Practices and General Requirements for New Transmission Electrical End-Users Facilities
4.1
Design Information
4.2
General Operating and Design Requirements
4.3
Load Connection Definition and Requirements
4.4
Tap Connection Definition and Requirements
4.5
Looped Connection Definition and Requirements
Construction Practices
Substation Equipment, Insulation, Structural and Conductor Requirements
6.1
Substation Design Requirements
Transmission Line Design, Loading, Clearance, Insulation and Structural Design Requirements
7.1
Transmission Line Design Requirements
Metering and SCADA Requirements
8.1
Transmission Interconnect Metering Requirements
8.2
Transmission Interconnect SCADA Requirements
8.3
Communication Requirements
8.4
RTU Requirements
8.5
Generation Metering Requirements
8.6
Generation SCADA Requirements
Appendices
A: AEP Power Quality Requirements
B: Typical Transmission Tap Supply & Line Looped Supply Configurations
C: Electrical Clearances and Equipment Ratings
D: Generation Abnormal Frequency Operating Allowance
E: Information Supplied By Generator Owner
F: 800 kV Major Equipment Specifications
G: AEP Metering Requirements for Transmission Interconnection Facilities
H: AEP SCADA RTU Requirements at Transmission Interconnection Facilities
I: AEP Protection Requirements for Connecting to the AEP Transmission Grid
J: Transmission Switching Guidelines for In-line Stations
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
Page 3 of 98
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
1.0
INTRODUCTION
American Electric Power Service Corporation (AEPSC), acting on behalf of the four electric operating companies
(OPCO) in AEP’s Western Region (AEPW) has developed these guidelines, which state the minimum
interconnection requirements for Transmission Generation (TG), Transmission Interconnections (TI) and
Transmission Electrical End-Users (TEEU) Requester's facilities to the OPCO owned transmission system or
transmission owned by others connected and operated in a control area. This document may be used as a guide
when planning an installation but may not cover all details in specific cases. TG, TI and TEEU Requesters should
note that the Electric Reliability Council of Texas (ERCOT) and Southwest Power Pool (SPP) have certain
requirements and procedures that must be met. These AEPW guidelines augment the written interconnection
requirements of ERCOT and SPP in those areas where the ERCOT and SPP written interconnection requirements
are silent. If there is a conflict between these guidelines and the interconnection requirements of ERCOT or SPP,
whichever is applicable to an OPCO, the ERCOT or SPP interconnection requirements will prevail.
A TG Requester whose generating facility will be connected to the AEP Texas Central Company (TCC) or AEP
Texas North Company (TNC) system must request an interconnection from the ERCOT in accordance with ERCOT
procedures. A TG Requester whose generating facility will be connected to the Public Service Company of
Oklahoma (PSO) or Southwestern Electric Power Company (SWEPCO) system must request an interconnection
from the SPP in accordance with SPP procedures.
A TI and TEEU Requester should request an interconnection from the AEPSC Manager of Transmission and
Interconnection Services.
TG, TI and TEEU Requesters should also follow the interconnection notification rules established by ERCOT and
SPP, as applicable.
In all cases, an Impact Study and a Facility Study will be conducted in accordance with the provisions of the
generally available transmission service tariff. A TG, TI or TEEU Requester should not purchase interconnecting
equipment until the Facility Study has been completed and an interconnection agreement has been executed between
the TG, TI or TEEU Requester and the OPCO.
2.0
INTERCONNECTION PRACTICES FOR TRANSMISSION GENERATION FACILITIES
2.1
GENERATION SOURCES
The TG Requester may elect to use a variety of energy sources. The end conversion for connection to the
OPCO’s system must be 60-Hertz alternating current.
2.2
PRACTICES FOR PARALLEL GENERATION
It is the practice of the OPCOs to permit any QF or any Exempt Wholesale Generator (EWG) to operate its
generating equipment in parallel with the OPCO electric system whenever this can be done without
adverse effects on the general public, OPCO equipment or other customers. Certain protective devices
(relays, circuit breakers, etc.), specified by AEPW, must be installed at the location where a TG Requester
will operate generation in parallel with the OPCO system. The purpose of these devices is to promptly
disconnect the TG Requester’s equipment from the OPCO system whenever faults or abnormal operations
occur. Other modifications to the existing electrical system configuration or protective relays may be
required in order to accommodate parallel operation.
Neither the OPCO nor AEPW assumes any responsibility for the protection of the TG Requester’s
generator(s), nor of any other portion of the TG Requester’s electrical equipment for any or all operating
conditions. The TG Requester is fully responsible for protecting his equipment in such a manner that
faults or other disturbances on the OPCO system or other interconnected systems do not cause damage to
the TG Requester’s equipment.
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
Page 4 of 98
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
In addition to installation of specified protective devices for disconnection from the power system, a TG
Requester requesting parallel operation of their generation must install and maintain equipment to monitor
and verify the proper interconnected operation (both transient and steady state) for expected power system
disturbances. The TG Requester shall set generator-operating parameters to enhance power system
security as specified by AEPW (see Section 2.7).
2.3
PRACTICES FOR SEPARATE AND PARALLEL SYSTEM
The TG Requester may elect to run his generator in parallel with the OPCO or as a separate system with
the capability of non-parallel load transfer between two independent systems. The requirements for these
two methods of operation are outlined below.
2.3.1
SEPARATE SYSTEM (QF Only) - A separate system is defined as one in which there is no
possibility of connecting the TG Requester’s generating equipment in parallel with the OPCO’s system.
For this design to be practical, the TG Requester must be capable of transferring load between the two
systems in an open transition or non-parallel mode. This can be accomplished by either an electrically or
mechanically interlocked switching arrangement, which precludes operation of both switches in the closed
position.
If the TG Requester has a separate system, AEPW will require verification that the transfer scheme meets
the non-parallel requirement. This will be accomplished by review of drawings by AEPW, by notification
in writing to AEPW and if AEPW so elects, by field inspection of the transfer scheme. AEPW will not be
responsible for reviewing, approving or evaluating the customer’s generation equipment and assumes no
responsibility for its design or operation.
Most Uninterruptible Power Supply (UPS) systems do not specifically meet the separate system criteria.
However, if a UPS system is not capable of back feed (transfer of electric power from the emergency
source to the normal source), it will be classified as a separate system. If it can back feed, it must meet the
requirements of parallel generation.
2.3.2
PARALLEL SYSTEM - A parallel system is defined as one in which the TG Requester
generation can be connected to a bus common with the utility’s system. A transfer of power between the
two systems is a direct and often desired result. A consequence of such parallel operation is that the
parallel generator becomes an electrical part of the utility system, which must be considered in the
electrical protection of the utility’s facilities.
Utility lines are subject to a variety of natural and man-made hazards. Among these are lightning, wind,
animals, automobiles, malicious mischief, etc. Residential and commercial electric systems are subject to
these hazards but not to nearly the same degree because of the limited extent and protected environment of
such systems.
Electrical problems, which can result from these hazards, include short circuits, grounded conductors, and
broken conductors. These fault conditions require that the damaged equipment be de-energized as soon as
possible because of the hazards they pose to the public and the operation of the system.
A parallel generator connected to a utility line represents another source of power to energize the line. The
parallel generator must have adequate protective devices installed to sense trouble in the utility system and
to disconnect from the utility system.
Parallel generation can also cause another condition, “accidental isolation”, in which a portion of the
utility’s load becomes isolated from the utility source but is still connected to the TG Requester’s parallel
generation. In this condition, the voltage may collapse or the isolated system may continue to operate
independent of the utility (possibly with abnormal voltage or frequency). The probability of an isolated
system, continuing to operate under these conditions, increases when the parallel generator size is greater
than the amount of potentially isolated load.
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
Page 5 of 98
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
The protective devices and other requirements required by AEPW in the following sections are intended to
provide protection against the hazards noted above by disconnecting the parallel generator when trouble
occurs. If the generator is small compared with the magnitude of any load with which it could be isolated
and the OPCO’s protective relays operate and isolate the generation with a large amount of load, the
voltage will collapse and should automatically shutdown the generator. This approach is particularly
appropriate for the induction generator or inverter systems since these systems do not contribute sustained
overcurrents, which could also be used to detect faults directly. In most cases, it is impossible to predict
with certainty that the generators will be isolated; as a result, AEPW requires the use of voltage and
frequency measuring relays to detect isolation and trip the TG Requester unit.
For synchronous generator installations, the probability of staying connected in isolated operation is higher
since the available generation may be sufficient to carry the entire load of the facility and/or OPCO load.
For these installations, specific devices are required for the detection of short circuits and grounds on the
utility system as well as voltage and frequency relays to detect isolated operation.
2.4
INDUCTION GENERATORS
Reactive power supply for induction generators may pose difficult design problems, depending on the
generator size. Some installations may require capacitors to be installed to limit the adverse effects of
reactive power flow on the OPCO’s system. The installation of capacitors for reactive power supply at or
near an induction generator greatly increases the risk that the induction machine may become self-excited if
accidentally isolated from the OPCO’s system. A self-excited induction generator can produce abnormally
high voltages, which can cause damage to the equipment of other Customers. Over-voltage relays can limit
the duration of such over-voltages but cannot control their magnitude because of the rapid voltage rise,
which occurs with self-excitation. Because of these problems, the reactive power supply for induction
generators must be studied on an individual basis. Where self excitation problems appear likely, special
service arrangements will be required in order to avoid the induction generator becoming isolated with
small amounts of the OPCO load.
For installations considering an induction generator(s), AEPW should be consulted during the planning and
design process.
2.5
INVERTER SYSTEMS
Reactive power supply requirements for inverter systems are similar to those for induction generators and
the general guidelines discussed in Section 2.4 apply. Likewise, inverter systems are also capable of
isolated operation. Self-commuted inverters have this capability by design. Line commuted inverters
could operate isolated if connected to rotating machines which provide the necessary commutation.
Because of the possibility of self-excited operation, inverter systems are treated as induction machines in
these guidelines.
At present no standards exist for the harmonic output of power inverters. If a TG Requester using such a
device for parallel generation is found to be interfering with other OPCO customers or utilities, or if
standards are adopted in the future, TG Requester may be required to install filtering or other equipment to
bring the harmonic output of his inverter to an acceptable level.
For installations considering an inverter system(s), AEPW should be consulted during the planning and
design process.
2.6
SPECIFIC GENERATOR STEP UP (GSU) TRANSFORMER REQUIREMENTS
AEPW has established Generator Step Up (GSU) transformer requirements for TG Requester owned
parallel generation, with specific protection, metering and operating requirements based upon typical
AEPW installations. The final decision as to the requirements for each installation will be made depending
on the TG Requester’s electrical location of the generator, the existing electrical facilities, the rating of
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
Page 6 of 98
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
existing electrical equipment and generators connected to that circuit or system, available short circuit
contributions, etc.
For parallel transmission generation, Wye - Delta connected Generator Step Up (GSU) transformers, the
GSU will be connected Wye to the bulk transmission system on lines rated 69 kV and above and connected
Delta to the TG Requester’s side. This ground source will provide a means for the TG Requester to
separate its equipment from the OPCO system for ground faults that have not been cleared in a reasonable
amount of time. The low side Delta connection will limit the ground fault currents the TG Requester will
experience for faults on their system.
2.7
GENERAL OPERATING AND DESIGN REQUIREMENTS
2.7.1
The OPCO’s nominal transmission voltages are 69 kV, 115 kV, 138 kV, 161 kV, 230 kV and 345
kV. Contact AEPW for information on the specific circuit(s) serving or available to serve the TG
Requester’s facility.
2.7.2
The TG Requester shall change his facility or equipment as may be required by AEPW to meet
future changes in the transmission system. The TG Requester shall be given reasonable notice by AEPW
prior to the date that the required changes in the TG Requester’s facilities must be made.
2.7.3
The TG Requester is solely responsible for properly synchronizing its generation with the OPCO
and shall provide to AEPW for review, the most current specifications for interconnection equipment,
including control drawings and one-line diagrams. AEPW’s review of TG Requester’s specifications
shall not be construed as confirming or endorsing the design or as any warranty of safety, durability or
reliability of the facility or equipment. Please refer to Appendix I “Automatic Reclosing”.
2.7.4
The TG Requester shall not energize a de-energized circuit owned by the OPCO, unless under
direction of AEPW System Operations.
2.7.5
The TG Requester’s generating equipment shall not cause objectionable interference with the
electric service provided to other Customers by the OPCO nor jeopardize the security of the power system.
In order to minimize the interference of the TG Requester’s parallel generation with AEPW System
Operations, the TG Requester’s generation shall meet the following criteria:
a)
Voltage - The TG Requester’s generating equipment shall not cause excessive voltage
excursions. The TG Requester shall operate its generating equipment in such manner that the
voltage levels on the system are in the same range as if the generating equipment was not
connected to the OPCO system. The TG Requester shall provide an automatic method of
disconnecting his generating equipment from the OPCO’s facilities to protect against excessive
voltage excursions.
b)
Flicker - The TG Requester shall not cause excessive voltage flicker on the electric
facilities of the OPCO. Flicker is to be measured at the TG Requester’s service point and shall
not exceed 1.5% or the Borderline of Visibility Curve (see Section 9, Voltage Flicker Chart,
ANSI/IEEE Std 141-1993) whichever is less.
c)
Frequency - The operating frequency of the TG Requester’s generating equipment shall
not deviate from the OPCO’s system frequency. The TG Requester’s under frequency relays
shall be set the same as the OPCO’s under frequency relays, so that TG Requester’s generator
shall not separate from the OPCO’s system during under frequency conditions until all of
OPCO’s under frequency load shedding equipment has operated. Please refer to Appendix I
“Frequency Protection”.
d)
Harmonics, Telephone Interference and Carrier Interference - The TG Requester’s
generating equipment shall not introduce: excessive distortion of the OPCO’s
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
Page 7 of 98
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
waveforms; voltage and current; telephone interference; or carrier interference at the TG
Requester service point. IEEE Standard 519, approved 1992, shall be used as a guide.
e)
Fault and Line Clearing - The TG Requester shall remove its generating equipment from
connection with the OPCO’s system on occurrence of an outage or fault on the OPCO’s
electric facilities serving the TG Requester’s facilities radially. The TG Requester is
responsible for the stability of its units and providing adequate facilities so that critical
fault clearing times are met.
f)
Power Factor – The power factor of the generator(s) will be at least 0.85 lag and 0.95
lead. For synchronous generators, the generator voltage-VAR schedule, voltage
regulator, and transformer ratio settings will be jointly determined by AEPW and TG
Requester to ensure proper coordination of voltages and regulator action. TG
Requester’s must generate their Var requirements. AEPW may, in order to maintain
security of the power system, request TG Requester to accept or supply reactive power.
In cases where starting or load changes on induction generators will have an adverse
impact on the OPCO system voltage, AEPW is to be consulted on techniques required to
bring voltage changes to acceptable levels.
g)
SCADA – The TG Requester shall provide individual SCADA data values to AEPW
System Operations for all generation. For more detail on these requirements, see
Metering and SCADA Requirements in Section 8.
h)
Excitation System and Automatic Voltage Regulation – TG Requester’s or any
interconnected generator(s) excitation system response ratio shall not be less than 0.5
(five-tenths). TG Requester’s or any interconnected generator(s) excitation system(s)
shall conform, as near as achievable, to the field voltage vs. time criteria specified in
American National Standards Institute Standard C50.13-1989 in order to permit adequate
field forcing during transient conditions. Depending on ERCOT Operating Guide or SPP
criteria requirements or the results of AEPW small signal stability studies (subject to
Independent System Operator review), it may be necessary for TG Requester to install
power system stabilizers (PSS) on TG Requester’s exciter system. If so, AEPW will
require TG Requester to install such PSS on it’s exciter system and AEPW will do so in
a manner that is not discriminatory to TG Requester.
Each generator’s exciter and exciter controls shall have a ride-through capability for
significant system voltage disturbances (i.e., utilize UPS or DC design).
TG Requester’s or any interconnected generator(s) shall maintain the Automatic Voltage
Regulator (AVR) of each generating unit in service and operable at all times. If the AVR
is removed from service for maintenance or repair, AEPW System Operations shall be
notified.
i)
Governor System – TG Requester’s or any interconnected generator(s) governor(s) shall
be able to respond to interconnection frequency deviations and help return
interconnection frequency to normal following an upset on the SPP or ERCOT system to
assist in maintaining interconnection stability.
2.7.6
AEPW shall require dedicated communication channel(s) and/or dial-up facilities be installed, at
the TG Requester’s expense, as part of the relay protection, remote monitoring/control, remote metering
and/or direct voice contact between AEPW and TG Requester is required for switching. For more detail
on these requirements, see Communication Requirements in Section 8.3.
2.7.7
It is the sole responsibility of the TG Requester to protect his equipment from excessive negative
sequence currents.
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
Page 8 of 98
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
2.7.8
The TG Requester shall be required to install, operate and maintain in good order and repair, and
without cost to AEPW, all facilities required by AEPW for the safe operation of the TG Requester’s
generation facilities in parallel with the OPCO’s electrical system. The TG Requester’s generation and
electrical facilities shall be installed, operated, and maintained by the TG Requester at all times in
conformity with generally accepted utility practice and shall comply with the National Electrical Code, the
National Electrical Safety Code, any applicable local codes, and any applicable AEPW service standards
included in the Interconnection Agreement. Any electrical facilities operated, as a part of the transmission
grid shall have the ownership and maintenance responsibility outlined in the interconnection agreement.
2.7.9
The TG Requester shall furnish at a minimum, a manual disconnect switch with visual contacts
and allowance for padlocking, to separate the TG Requester’s generator from the OPCO. The location of
this switch will be determined by AEPW, and be readily accessible to AEPW at all times. The disconnect
switch will be under the exclusive control of AEPW and will be considered as part of AEPW’s switching
arrangement. AEPW reserves the right to open this disconnecting device, isolating the TG Requester
generation, for any of the following reasons:
a)
The TG Requester’s generating equipment upon AEPW’s determination causes
objectionable interference with other Customer’s service or with the secure operation of
the OPCO’s electrical system.
b)
The TG Requester’s generator output as determined by AEPW exceeds the operating
boundaries outlined in Section 2.7.5.
c)
The TG Requester’s control and protective equipment causes or contributes to a
hazardous condition. AEPW reserves the right to verify on demand all protective
equipment including relays, circuit breakers, etc. at the inter-tie location. Verification
may include the tripping of the tiebreaker by the protective relays.
d)
In AEPW’s opinion, continued parallel operation is hazardous to TG Requester, the
OPCO System or to the general public.
e)
To provide AEPW or OPCO personnel the clearances for dead line or live line
maintenance.
The OPCO or AEPW will attempt to notify the TG Requester before disconnection, but notification may
not be possible in emergency situations that require immediate action.
2.7.10 Automatic reclosing is normally applied to transmission and distribution circuits. When the
OPCO’s source breakers trip and isolate the TG Requester’s facilities, TG Requester shall insure that his
generator is disconnected from the OPCO circuit prior to automatic reclosure by the OPCO. Automatic
reclosing out-of-phase with the TG Requester’s generator may cause damage to TG Requester’s
equipment. The TG Requester is solely responsible for the protection of his equipment from automatic
reclosing by the OPCO.
2.7.11 TG Requester is solely responsible for providing adequate protection for TG Requester’s
facilities operating in parallel with the OPCO’s system in such manner that faults or other disturbances on
the OPCO system do not cause damage to TG Requester’s equipment.
2.7.12 The TG Requester may not commence parallel operation of generator(s) until consent has been
given by AEPW. AEPW reserves the right to inspect TG Requester’s facility and witness testing of any
equipment or devices associated with the interconnection. Operating Procedures will be jointly developed
and be agreed to in the Interconnection Agreement.
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
Page 9 of 98
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
2.7.13 The TG Requester shall install protective devices (relays, circuit breakers, etc.), metering
equipment, and synchronizing equipment by as required by AEPW. The protective devices and the
installing party (the OPCO or TG Requester) may differ between installations.
2.7.14 For parallel operation the TG Requester shall submit single-line drawings of this equipment to
AEPW for review of the protective, metering and remote monitoring/control functions. Any changes
required by AEPW shall be made prior to final issue of drawings and AEPW shall be provided with final
copies of the revised drawings.
AEPW will review only those portions of the drawings, which apply to protection, metering and
monitoring which affect the OPCO’s system. To aid the TG Requester, AEPW may make suggestions on
other areas, but will not assume responsibility for the correctness pertaining to TG Requester’s system.
2.7.15 The TG Requester shall maintain an operating log at each generating facility that at a minimum
will indicate changes in operating status (available or unavailable), maintenance outages, trip indications or
other unusual conditions found upon inspection. For generators, which are “block-loaded” to a specific
MW level, changes in this setting shall also be logged; AEPW may waive this requirement at its discretion.
The TG Requester, as required by NERC or ERCOT/SPP, will maintain reliability information.
Regarding MW production, the TG Requester will be required to back down their generation at certain
times to maintain reliability. For example, when system loading is at minimum levels and the TG
Requester has not scheduled the sale/transport of their production outside the AEPW control area, or when
transmission maintenance is required, the TG Requester should be prepared to reduce generation to
maintain operation within system limitations.
2.7.16 Fault (Transient) recorders are designed to record events that are very short in nature, such as
faults on transmission lines or transients produced during switching or arcing of electrical equipment. Fault
(Transient) event records may be only one or two seconds long, but their sample rate may be as high as 75
to 100 samples per cycle. Dynamic recorders are designed for long-term events, such as under frequency
or voltage conditions. Dynamic recorders events may be 5 to 10 minutes long, but their sample rate may be
only 1 to 12 samples per cycle. These events usually show only the trending of the analog values or power
flow out of a generator.
The OPCO shall purchase, install and maintain fault (transient) and long term dynamic recording
equipment to monitor and verify generator’s proper transient and steady-state response to power system
disturbances. This equipment may be located at either the OPCO’s or TG Requestor substation,
depending on each site’s particular needs and requirements.
The fault (transient) / dynamic recorder at the TG Requester’s generator location will be at a mutually
agreed location. The TG Requester shall provide the necessary connections to the recording equipment
and the OPCOs will terminate the signals in the recorder. The OPCO shall own and maintain the
recorder(s). The necessary communication equipment (See Section 8) shall be installed by the TG
Requester and access shall be provided to allow the OPCO the ability to monitor the recorder(s) and
verify the TG Requester’s generator response to power system disturbances. All fault (transient) /
dynamic recorders shall be equipped with time synchronizing equipment. The monitoring requirement of
AEPSC does not reduce the TG Requester’s obligation to meet all NERC – Disturbance Monitoring
requirements contained in the NERC Reliability Standards.
2.8
Restriction on Using Autotransformer Tertiary to Supply Load
The tertiary winding of an AEP autotransformer cannot be used as a source for non-generator or generator load.
The restriction on the tertiary winding as an off-site power source is due to the facts that: 1) significant fault
exposure can be introduced to the transformer when load is served from the transformer tertiary, and 2) there
are several documented cases of transformer life being shortened due to this type of configuration. In addition to
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
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shortening transformer life, these configurations are inordinately difficult and expensive to remove from service
for maintenance. Such load serving configurations are therefore considered reliability risks and are not allowed.
3.0
INTERCONNECTION PRACTICES AND GENERAL REQUIREMENTS FOR NEW
INTERCONNECTIONS WITH OTHER CONTROL AREAS
3.1
DESIGN INFORMATION
3.1.1
The OPCO’s nominal transmission voltages are 69 kV, 115 kV, 138 kV, 161 kV, 230kV and 345
kV. Contact AEPW Transmission Planning Department for information on the specific circuit(s) serving
or available to serve the TI Requester facility
3.1.2
All OPCO’s 200Kv and above transmission lines are primarily protected by two different highspeed pilot relaying system, such as Directional Comparison Blocking, Permissive Overreaching Transfer
Trip (POTT), Permissive Under-reaching Transfer Trip (PUTT), Current Differential, and Directional
Comparison Un-blocking schemes. Most OPCO’s 100Kv – 200Kv transmission lines are protected by a
single high-speed Pilot relaying system, with a Step Distance phase, and directional ground overcurrent
relaying scheme for backup. Most OPCO’s below 100kV lines are protected by a primary and backup
phase Step Distance scheme with a directional ground over-current relay. AEPSC will determine the
appropriate protection for each TI Request. Current differential relays may require fiber optic, microwave,
etc., for their pilot channels..
3.1.3
The TI Requester shall be required to furnish the AEPW System Protection Department with the
specific relay setting information on the TI Requester facilities. This will allow AEPW the opportunity to
review the TI Requester settings to ensure proper coordination with the OPCO’s equipment.
3.1.4
Because most short circuits faults on overhead lines are of a temporary nature, it is the OPCO’s
practice to reclose the circuit breakers on such lines (high-speed) after they have automatically tripped.
This high-speed reclosing typically involves an intentional time delay of 15 - 30 cycles and some additional
time required for the operating speed of the relays and circuit breaker(s). Reclosing for 69kV lines and
those lines that have a high-side transformer recovery scheme have a second reclose. This second reclose
has an intentional time delay of 20 seconds. This practice improves continuity of service to all OPCO
Customers.
3.1.5
All OPCO’s interconnections with other control areas require synchronizing equipment at the
OPCO’s location.
3.1.6
The TI Requester may be responsible for the installation of equipment to island during under
frequency or under voltage conditions. This may include such as transfer trip equipment, at the OPCO
(local end), TI Requester (remote end), or both locations
3.1.7
The TI Requester shall change his facility or equipment as may be required by NERC,
ERCOT/SPP or AEPW for AEPW to meet future changes in the transmission system. The TI Requester
shall be given reasonable notice by AEPW prior to the date that required changes in the TI Requester’s
facilities must be made.
3.1.8
The OPCO reserves the right to inspect, calibrate, test and maintain TI Requester protective
equipment located on OPCO property associated with the protection of the OPCO’s system.
3.2
GENERAL OPERATING AND DESIGN REQUIREMENTS
3.2.1
The TI Requester is solely responsible for properly connecting its equipment to AEPW and shall
provide to AEPW for review the most current specifications for interconnection equipment, including
drawings and one-line diagrams. AEPW’s review of TI Requester specifications shall not be construed as
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
Page 11 of 98
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Always check for the latest revision prior to use.
confirming or endorsing the design or as any warranty of safety, durability or reliability of the facility or
equipment.
3.2.2
The TI Requester shall not energize a de-energized circuit owned by the OPCO, unless under
direction of AEPW System Operations or except by automatic relay operation approved by AEPW.
3.2.3
The TI Requester interconnected system shall not cause objectionable interference with the
electric service provided to other Customers by the OPCO. The TI Requester equipment shall meet the
following criteria:
a)
Voltage - The TI Requester shall operate its system in such manner that the voltage
levels on the system are maintained at reliable levels as per ERCOT Operating Guides or
SPP criteria.
b)
Flicker - The TI Requester shall not cause excessive voltage flicker on the electric
facilities of the OPCO. Flicker is to be measured at the TI Requester’s service point and
shall not exceed 0.6% (see Appendix A, AEP Power Quality Requirements, ANSI/IEEE
Std 1453-2004).
c)
Harmonics, Telephone Interference and Carrier Interference - The TI Requester
interconnect system shall not introduce: excessive distortion of the OPCO’s waveforms;
voltage and current; telephone interference; or carrier interference at the TI Requester
service point. IEEE Standard 519, approved 1992, shall be used as a guide.
d)
Fault and Line Clearing - The TI Requester is responsible for the stability of its system
and providing adequate facilities so that critical fault clearing times are met.
e)
SCADA - The TI Requester shall provide individual SCADA data values to AEPW
System Operations for all interconnects. For more detail on these requirements, see
Metering and SCADA Requirements in Section 8.
3.2.4
AEPW shall require dedicated communication channel(s) and/or dial-up facilities be installed, at
the TI Requester’s expense, as part of the relay protection, remote monitoring/control and, remote
metering. Direct voice contact between AEPW and TI Requester is required for switching. For more
detail on these requirements, see Communication Requirements in Section 8.3.
3.2.5
The TI Requester shall be required to install, operate and maintain in good order and repair, and
without cost to AEPW, all facilities required by AEPW for the safe operation of the TI Requester’s
facilities connected to the OPCO’s electrical system. The TI Requester’s electrical facility shall be
installed, operated, and maintained by the TI Requester at all times in conformity with generally accepted
utility practice and shall comply with the National Electrical Code, the National Electrical Safety Code, any
applicable local codes, NERC Reliability Standards, and any applicable AEPW or other service standards
included in the Interconnection Agreement. Any electrical facilities operated, as a part of the transmission
grid shall have the ownership and maintenance responsibility outlined in the interconnection agreement.
3.2.6
The TI Requester is solely responsible for providing adequate protection for its interconnecting
facilities operating connected to the OPCO’s system in such manner that faults or other disturbances on the
OPCO system do no cause damage to TI Requester’s system. Please refer to Appendix I for details.
3.2.7
The TI Requester may not connect to OPCO’s system until consent has been given by AEPW.
AEPW reserves the right to inspect the TI Requester facility and witness testing of any equipment or
devices associated with the interconnection. Operating Procedures will be developed and become a part of
the Interconnection Agreement.
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
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3.2.8
The TI Requester shall install protective devices (relays, circuit breakers, etc.), metering
equipment, and synchronizing equipment as required by AEPW. The protective devices may differ in
equipment between installations.
3.2.9
The TI Requester shall submit single-line drawings of their interconnection equipment to AEPW
for review of the protective, metering and remote monitoring/control functions. Any changes required by
AEPW shall be made prior to final issue and AEPW shall be provided with final copies of the revised
drawings.
AEPW will review only those portions of the drawings, which apply to protection, metering and remote
monitoring/control, which affect the OPCO’s system. To aid the TI Requester, AEPW may make
suggestions on other areas, but will not assume responsibility for the correctness pertaining to TI
Requester’s system.
4.0
INTERCONNECTION PRACTICES AND GENERAL REQUIREMENTS FOR NEW TRANSMISSION
ELECTRICAL END-USERS FACILITIES
4.1
DESIGN INFORMATION
4.1.1
The OPCO nominal transmission voltages are 69 kV, 115 kV, 138 kV, 161 kV, 230 kV and
345kV. Contact AEPW Transmission Planning department for information on the specific circuit(s)
serving or available to serve the TEEU Requester Facility.
4.1.2
TEEU Requester’s two winding transformer connected to OPCO’s transmission system will be
connected high side Delta and low side Wye. Distribution system with very high fault currents may require
grounding resistor or inductor in the transformer neutral with AEPW approval.
4.1.3
Transformers associated with the bulk (69kV and up) transmission system should be provided
with high-speed protection to minimize damage to the transformer, the associated substation equipment and
the effects upon the system. A protective zone should be provided for each protected transformer. The
various zones should overlap so that no area will be unprotected.
a)
Power transformer fuses are the most economical means of protecting a transformer. But
AEPW recommends that fuses not be used on transformers larger than 10MVA due to
their inability to adequately protect the transformer for all fault conditions. Please refer
to Appendix I “Customer Tapped Station and Fused Transformer Application”.
4.1.5
The TEEU Requester shall be required to furnish the AEPW System Protection Department with
the specific fuse and relay setting information at the TEEU Requester facilities. This will allow AEPW
the opportunity to review the TEEU Requester settings to ensure proper coordination with the OPCO’s
equipment.
4.1.6
A TEEU Requester’s facility that is located on a transmission line tap, where the OPCO’s
transmission line relays cannot adequately protect, the TEEU Requester shall be required to provide
breakers, wave traps, CCVTs, CT, relays and carrier blocking signals at the transmission tap location. The
TEEU Requester will trip and carrier block for faults on the TEEU Requester tap.
4.1.7
All OPCO TEEU Requester Interconnect facilities utilize revenue meters and associated
equipment at the TEEU Requester’s location. Revenue meters shall be specified by AEPW.
4.1.8
The TEEU Requester’s may be required to purchase and install equipment to shed load during
under frequency or under voltage conditions as per ERCOT Operating Guides or SPP criteria at the TEEU
Requester’s facilities. Please refer to Appendix I “Automatic Underfrequency Load Shedding”.
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
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Always check for the latest revision prior to use.
4.1.9
The TEEU Requester shall change their facility or equipment as may be required for AEPW to
meet future changes in the transmission system including a voltage change. The TEEU Requester shall be
given reasonable notice by AEPW prior to the date that the required changes in the TEEU Requester
facilities need to be made.
4.1.10 AEPW shall require dedicated communication channel(s) and/or dial-up facilities be installed, at
the TEEU Requester’s expense, as part of the relay protection, remote monitoring/control, remote
metering and/or direct voice contact between AEPW and TEEU Requester is required for switching. For
more detail on these requirements, see Communication Requirements in Section 8.3.
4.1.11
4.2
See other substation and transmission requirements in sections 6 and 7.
GENERAL OPERATING AND DESIGN REQUIREMENTS
4.2.1
The TEEU Requester is solely responsible for proper coordination of its equipment with the
OPCO’s and shall provide to AEPW for review, the most current specifications for interconnection
equipment, including drawings and one-line diagrams.
AEPW’s review of TEEU Requester
specifications shall not be construed as confirming or endorsing the design or as any warranty of safety,
durability or reliability of the facility or equipment.
4.2.2
The TEEU Requester shall not energize a de-energized circuit owned by the OPCO, unless
under direction of AEPW System Operations.
4.2.3
The TEEU Requester’s interconnect equipment shall not cause objectionable interference with
the electric service provided to other customers by the OPCO. The TEEU Requester’s equipment shall
meet the following criteria:
a)
Power Factor - The TEEU Requester shall operate its equipment in such manner that the
power factor will be as specified in the transmission service agreement.
b)
Flicker - The TEEU Requester shall not cause excessive voltage flicker on the electric
facilities of the OPCO. Voltage flicker will be dictated by the sensitivity of the load or
loads being served. Flicker is to measured at the TEEU Requester’s service point and
shall not exceed 1.5% or the Borderline of Visibility Curve (see Section 9, Voltage
Flicker Chart, ANSI/IEEE Std 141-1993), whichever is less.
c)
Under frequency - The TEEU Requester shall install under frequency relays and shed
load as outlined in the SPP or ERCOT Load Shedding Guides.
d)
Harmonics, Telephone Interference and Carrier Interference - TEEU Requester’s
interconnect equipment shall not introduce: excessive distortion of the OPCO’s wave
forms; voltage and current; telephone interference; or carrier interference at the TEEU
Requester’s service point. IEEE Standard 519, approved 1992, will be used as a guide.
e)
SCADA - The TEEU Requester shall provide individual SCADA data values to AEPW
System Operations for all interconnects. For more detail on these requirements, see
Metering and SCADA Requirements in Section 8.
4.2.4
The TEEU Requester will be required to install, operate and maintain in good order and repair,
and without cost to AEPW, all facilities required by AEPW for the safe operation of the TEEU Requester
facility’s connected to the OPCO’s electrical system. The TEEU Requester electrical facility shall be
installed, operated, and maintained by the TEEU Requester at all times in conformity with generally
accepted utility practice and shall comply with the National Electrical Code, the National Electrical Safety
Code, any applicable local codes, NERC Reliability Standards, and any applicable AEPW service
standards included in the Interconnection Agreement. Any electrical facilities operated, as a part of the
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
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transmission grid shall have the ownership and maintenance responsibility outlined in the interconnection
or operating agreement.
4.2.5
TEEU Requester is solely responsible for providing adequate protection for its interconnecting
facilities connected to the OPCO’s system in such manner that faults or other disturbances on the OPCO
system do no cause damage to TEEU Requester’s equipment. Please refer to Appendix I for details.
4.2.6
The TEEU Requester may not connect to OPCO’s system until consent has been given by
AEPW. AEPW reserves the right to inspect the TEEU Requester’s facility and witness testing of any
equipment or devices associated with the interconnection. Operating Procedures will be developed and
become a part of the Interconnection Agreement.
4.2.7
TEEU Requester shall install protective devices (relays, circuit breakers, etc.) for the protection
of the OPCO’s system and metering equipment as required by AEPW. The protective devices and the
installing party (the OPCO or TEEU Requester) may differ between installations.
4.2.8
The TEEU Requester shall submit single-line drawings of their equipment to AEPW for review
of the protective, metering and remote monitoring/control functions. Any changes required by AEPW
shall be made prior to final issue and AEPW shall be provided with final copies of the revised drawings.
4.2.9
AEPW will review only those portions of the drawings, which apply to protection, metering and
remote monitoring/control, which affect the OPCO’s system. To aid the TEEU Requester, AEPW may
make suggestions on other areas, but will not assume responsibility for the correctness of protection
pertaining to TEEU Requester system.
4.3
Load Connection Definition and Requirements
4.3.1
Tap Connection Definition and Requirements
Any connection to the AEP West Transmission System that results in only the transmission customer load
passing through the connecting facilities under all conditions is considered a tap connection. If the
Requester’s facilities are located near an existing AEP station, the connection from the AEP West
Transmission System may be provided by constructing a radial line from the AEP station to the
Requester's facility. If the Requester's facilities are located near an existing AEP transmission line, the
connection from the AEP Transmission System may be provided by tapping the nearby AEP line (if
adequate transmission capacity exists) and constructing a radial line to the Requester's facility. This
arrangement will provide a radial connection to the Requester but will also result incidentally in creating
in-line facilities at the tap point.
For facilities below 200 kV, Figures 1 and 2 in Appendix J illustrate typical radial line supply
configurations and some of the basic connection requirements. Other possibilities exist depending on the
particular situation. As indicated, line switches are typically the minimum requirements at the tap location
point. The tap line air break switch can disconnect the Load Connection without de-energizing the supply
line and the in-line air break switches allow for sectionalizing the line without supply interruption to the
Load Connection. Motor operated mechanisms (with or without supervisory control) may be required
(refer to TP-000004 – Transmission Switching Guidelines for the In-Line Stations), or optionally can be
added, to in-line air break switches to minimize the time required for restoration following a failure of the
AEP supply line. The in-line switches or circuit breakers must match the thermal capability of the line
conductor. The in-line switches must also be designed to provide appropriate "Line Dropping" or "Loop
Interrupting" capabilities. Capabilities of the radial line and other associated facilities would depend on the
magnitude of the connected load. In addition, the ground wire must meet the selection criteria as outlined in
AEP Report #792, entitled "Selection of Transmission Ground Wires". Connection to the AEP Extra High
Voltage (EHV) transmission system (200 kV and above) will be reviewed on a case-by-case basis.
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
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4.3.2
Looped Connection Definition and Requirements
Any connection to the AEP West Transmission System that provides two line extensions to supply the
Transmission Interconnection and Load Connection is considered a looped connection. In general, the
two line extensions are installed to facilitate the Requester obtaining looped service, not to enable AEP to
provide adequate electrical service to any location other than the Load Connection.
Since some looped connections have the potential to significantly affect the reliability and loadability of the
AEP Transmission System, specific design and operational requirements are imposed which may not be
required for a tapped connection.
Figure 3 in Appendix J illustrates typical looped supply configurations for connections below 200 kV and
some of the basic connection requirements. Other possibilities exist depending on the particular situation.
For looped supply configurations, either a delta or ungrounded-wye high side transformer-winding
configuration is preferred for connecting substation transformers.
5.0
CONSTRUCTION PRACTICES
The following practices are minimum construction standards and as such do not represent a warranty from AEPW
or the OPCOs of the adequacy of the Requester design. These minimum practices refer to initial and all future
construction by Requesters on OPCO facilities located on OPCO property or property owned by Requesters and
also, construction by Requesters on Requester facilities on OPCO property. These practices would also cover
construction by Requester on Requester facilities located on Requesters property, where the facilities are to be
transferred to OPCO ownership and/or control. Construction practices to be followed by the TG, TI and TEEU
Requesters include, but are not limited to the following:
5.1
Work Schedule and Material - A proposed project timetable, including construction milestones shall be
prepared. The schedule should list types, quantity and delivery schedule of major materials and equipment,
required dead line clearances, temporary construction, etc. These milestones should include service date
for the transmission connection and a date for temporary service to test facilities prior to commercial in
service.
5.2
Supervision - Knowledgeable and experienced construction management personnel shall be used to insure
quality workmanship, use of specified materials, and coordination of work between TG, TI and TEEU
Requester’s contractor and AEPW.
5.3
Contractors - Qualification of contractors shall be based on familiarity and experience in working around
energized and similar installations and on known reputation for quality workmanship.
5.4
Insurance - TG, TI and TEEU Requester’s Contractors working on OPCO property or facilities, shall
have insurance equal to or better than the OPCO contractor requirements and the policy shall name the
OPCO and AEPW as an insured.
5.5
Safety - TG, TI and TEEU Requesters personnel, their guests and agents are to be fully aware of the
existence and location of the OPCO transmission, substation and distribution facilities. TG, TI and TEEU
Requesters Requester’s personnel shall be knowledgeable of the risks of conducting activities in the
vicinity of such facilities and be knowledgeable of the procedures and precautions necessary to minimize
such risks. This includes but is not limited to those set for in the OSHA regulations, National Electric
Safety Code (NESC, ANSI C2-1990), National Electrical Code (NEC and Sections 754.001 et. seq. of the
Texas Health and Safety Code).
5.6
For facilities on the TG, TI and TEEU Requester’s side of the point of service, the TG, TI and TEEU
Requesters is responsible for all design and construction. AEPW may advise of known similar
construction and may provide, if requested, a listing of engineering, construction, and construction
management contractors familiar to AEPW.
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
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6.0
SUBSTATION EQUIPMENT, INSULATION AND STRUCTURAL DESIGN REQUIREMENTS
Upon determination of the point of service, the design and construction of new substation facilities on the OPCO
electric system necessary to connect the TG, TI and TEEU Requester shall be done utilizing current OPCO
construction, insulation, and structural practices for new facilities. For proposed facilities on the OPCO-side of the
Interconnections, AEPW will review project plans with the TG, TI and TEEU Requester before work commences.
6.1
SUBSTATION DESIGN REQUIREMENTS
The following is general information on various aspects concerning the design of substation. More detailed
information concerning AEPW guidelines may be obtained by contacting the AEPW Manager of Substation
Design.
6.1.1
Lightning Arrester - The lightning arrester ratings recommended by AEPW are shown in the
table below. Arresters for 230 kV and greater applications need to be evaluated on case by case basis due
to the special duty placed on the arresters due to switching surge capabilities. AEPW Manager of
Transmission Planning can provide more information on this topic. Characteristics of the units to be
installed will be provided to AEPW prior to construction.
AEP Standard Arrester Ratings
System kV
Duty-Cycle Voltage (kV)
69
60
115
90
138
108
161
120
230
**
345
**
765
**
Arrester selection shall conform to IEEE STD C62.22.
Maximum Continuous
Operating Voltage
(MCOV) (kV)
48
70
84
98
**
**
**
6.1.2
Oil Containment - The type of containment system that is to be used in a AEPW substation shall
be determined on a case by case basis by AEPW. TG, TI and TEEU Requesters shall be responsible for
the design, installation and maintenance of the containment system required for its facilities.
6.1.3
Substation Static Wires - The TG, TI and TEEU Requesters shall provide locations and
attachments for required AEPW static wires that will be terminated on TG, TI and TEEU Requester’s
Facilities. Loading requirements will be determined on a case-by-case basis by AEPW.
6.1.4
Substation Ground Grid - Personnel safety is the primary objective of an adequate grounding
system. The ground grid must be designed to limit surface potential gradients to safe values in accordance
with ANSI/IEEE 80. A substation grounding system shall be designed to fulfill the following
requirements:
a)
Proper grounding of equipment, structures, and installation of an adequate earth ground
grid for safety to personnel.
b)
Grounding of system neutrals to stabilize circuit potentials with respect to earth ground,
and to provide circuit relaying for clearing ground faults.
c)
Proper equipment grounding for lightning, surge protection, and low voltage faults.
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
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Always check for the latest revision prior to use.
Contact the AEPW Project Manager to obtain ground fault values and clearing times for AEPW facilities.
The TG, TI and TEEU Requesters shall provide AEPW design drawings and material lists for its
proposed substation ground grid. Ground grid connections between AEPW facilities and TG, TI and
TEEU Requester’s facilities shall be designed and installed in a manner that is acceptable to AEPW.
6.1.5
Substation Fence - The National Electric Safety Code (ANSI 2-1993) references IEEE std. 11191988 as a guide by AEPW for station fence clearances. AEPW recommends the use of 7 foot fabric with
three strands of barbed wire on a single bayonet which extends out of the substation at a 45° angle above
the fabric. The vertical height of bayonets should be one foot. AEPW also recommends that snake fences
be used in new substation construction within certain AEPW areas.
6.1.6
Bus Heights and Phase Spacing - AEPW recommends new substation construction be designed
to the bus heights and phase spacing presented in the table below. An exception is an addition to
an existing substation where existing steel and bus heights may have to be matched. Matching
existing steel is not mandatory, however.
System Voltage
BIL
(kV)
345 kV
1300
345 kV
1050
161 kV
650
138 kV
550
138 kV
650
69 kV
350
Recommended Bus Heights and Phase Spacing
Phase to Phase
High Bus
Low Bus
15’-0”
15’-0”
12’-0”
10’-0”
10’-0”
7’-0”
36’-2”
35’-0”
22’-0”
22’-0”
22’-0”
18’-0”
23’-2”
22’-0”
15’-0”
15’-0”
15’-0”
14’-0”
6.1.7
Control Buildings – AEPW recommends that TG, TI and TEEU Requester’s facilities are
designed to meet the following minimum loading requirements:
Control buildings located within approximately 140 miles of the Gulf of Mexico shall be designed for a
minimum basic wind speed equal to 135 mph. Facilities located in all other areas of the OPCO’s service
territories shall be designed for a minimum basic wind speed equal to 90 mph.
Control buildings shall be designed to support all anticipated dead load including the weight of the building
and the equipment that it supports, including all tray and cable. Buildings shall be designed using a live
load equal to 20 pounds per square foot. The ground snow load used in determination of the design snow
load shall be as defined by the authority having jurisdiction, but shall not be less than 30 pounds per square
foot.
Loads shall be combined as defined in the latest edition of the “International Building Code” or as directed
by the authority having jurisdiction.
In addition to these requirements, the TG, TI and TEEU Requester must ensure that all structural,
electrical, and mechanical design work meets the minimum requirements of the authority having
jurisdiction.
6.1.8
Substation Lighting is needed to provide sufficient illumination where needed in the substation.
With such lighting, personnel will be able to observe and effectively control the operation and maintenance
of various substation equipment and processes. Other applications of lighting will be for security in the
substation.
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
Page 18 of 98
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
6.1.9
AC station service system is extremely important to the reliable operation of substation
equipment when AEPW facilities are located in TG, TI and TEEU Requester’s substation, AEPW must
approve the design and construction of the AC station service system. Receptacles are needed in the
substation yard adjacent to AEPW equipment for various AC needs. AEPW will indicate the type of
receptacle needed for each location.
6.1.11 DC station service system for a substation is needed to supply critical station loads. These
station loads include: circuit switchers, breakers, motor operated switches, switchgear, RTUs, and relays.
The DC system voltage is typically obtained from a station battery and the associated charging system. The
standard AEPW battery voltages are 48VDC and 125 VDC. (It should be noted that some substations have
24 VDC, 32 VDC or 250 VDC.) Each substation must have a properly sized battery and charger to carry
the DC station loads during an AC power failure. AEPW will work with the TG, TI and TEEU
Requesters to determine proper sizing and requirements for the DC system. The DC station service system
shall be no smaller than that determined by AEPW as the minimum size required in joint facilities.
6.1.12 Fusing of Potential Transformers is AEPW’s general rule that fuses should be used in both the
primary and secondary circuits of potential transformers. Secondary fuses should be applied with potential
transformers to protect the transformer against high impedance faults on the secondary circuit of the
transformer.
It is general practice to omit the fuses on the connections to grounded terminals of potential transformers.
This practice is essential in the case of single primary bushing type potential transformers. In addition for
certain applications involving regulators or protective relays, where the continuity of excitation to these
devices is more important than the possibility of damage to the transformer, it is customary to omit the
fuse.
6.1.13 SCADA / RTU - A transmission-specific remote terminal unit (RTU) is required for all
transmission interconnections. In addition, a generation-specific RTU may also be required at TG
Requester’s facilities for AEP’s generation-specific supervisory control and data acquisition (SCADA); for
more detail see Section 8.6.
For additional information see Appendix H (AEP SCADA RTU Requirements at Transmission
Interconnection Facilities – Verification of latest revision required).
6.1.14 Control Cable - AEPW recommends that all control cables be shielded with both ends grounded.
It is also recommended.
Historically, AEPW substation control cable has been 20 mils of polyethylene insulation covered with 10
mils of color-coded polyvinyl chloride (PVC) with an outer PVC jacket and #10 copper stranded
conductors. The color coding is to be in accordance with the below table
Method 1, Table K-1
Number of Conductors
1
2
3
4
5
6
7
8
9
Base Color
Black
White
Red
Green
Orange
Blue
White
Red
Green
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
First Tracer or Stripe
Black
Black
Black
TP-0002
Rev. 3
Page 19 of 98
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
10
Orange
Black
11
Blue
Black
12
Black
White
Cable to be used for SCADA indication and control by AEPW is to be shielded 20/10 utilizing #18
conductors and the K1 color. Each cable shall consist of twisted black and white numbered pairs (labeled
Pr #1, 2, etc.).
Cable tabulations will be prepared for any location where OPCO facilities and TG, TI and TEEU
Requester’s facilities are located in the same yard or interconnections will be made between the two
adjacent facilities.
Each of the OPCO’s has standards for labeling control cables for safety reasons and prevention of misoperations. The Requester who must follow NEC color codes shall end wrap each interconnect
control cable with the appropriate OPCO’s standard color code tape. The following tables shows what
presently exist in each OPCO; however, when a standard does not exist the typical template will be
used.
DISTRIBUTION BREAKER - RELAY INSIDE CONTROL HOUSE
No. of
Wire
No. of Cables
Conductors
Guage
Purpose
1
4/c
#10
DC Supply
1
4/c
#10
AC Supply
1
12/c
#10
Control/Relaying
1
12/c
#10
Spare
1
4/c
#10
CTs
2
4/c
#10
Spare for CTs
1
12/c
#10
Telemetering (SWEPCO Only)
1 (Note 1)
4/c
#10
Bus Differential (CT)
1 (Note 2)
4/c
#10
Transformer Differential (CT)
Note 1: Use this cable/conduit in case of a bus differential scheme
Note 2: Use this cable/conduit in case of a transformer differential scheme
Conduit
No.
1
1
1
1
1
1
1
2
3
DISTRIBUTION BREAKER - RELAY IN YARD (LAST ON COMMUNICATION LOOP)
No. of
Wire
Conduit
Conductors
Guage
No.
No. of Cables
Purpose
1
4/c
#10
DC Supply
1
1
4/c
#10
AC Supply
1
1
12/c
#10
Control
1
1
12/c
#10
Spare
1
1
4pr
#16
RTU Communication
1
2
4/c
#10
Spare for CTs
1
1
12/c
#10
Telemetering (SWEPCO Only)
1
1
4pr
#16
RTU Communication
2
1
4/c
#10
PT
3
1 (Note 1)
4/c
#10
Bus Differential
4
1 (Note 2)
4/c
#10
Transformer Differential
5
Note 1: Use this cable/conduit in case of a bus differential scheme
Note 2: Use this cable/conduit in case of a transformer differential scheme
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
Conduit
Size
4"
4"
4"
4"
4"
4"
4"
1.25"
1.25"
Conduit
Size
4"
4"
4"
4"
4"
4"
4"
1.25"
1.25"
1.25"
1.25"
TP-0002
Rev. 3
Page 20 of 98
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
DISTRIBUTION BREAKER - RELAY IN YARD
No. of
No. of Cables
Conductors Wire Guage
Purpose
1
4/c
#10
DC Supply
1
4/c
#10
AC Supply
1
12/c
#10
Control
1
12/c
#10
Spare
2
4/c
#10
Spare for CTs
1
12/c
#10
Telemetering (SWEPCO Only)
1
4pr
#16
RTU Communication
1
4pr
#16
RTU Communication
1
4/c
#10
PT
1 (Note 1)
4/c
#10
Bus Differential
1 (Note 2)
4/c
#10
Transformer Differential
Note 1: Use this cable/conduit in case of a bus differential scheme
Note 2: Use this cable/conduit in case of a transformer differential scheme
COUPLING CAPACITOR POTENTIAL DEVICE
No. of
No. of Cables
Conductors Wire Guage
1
7/c
#10
1
7/c
#10
1
4/c
#10
1
Coaxial
BUS POTENTIAL CABINET
No. of
No. of Cables
Conductors
Purpose
PT
PT Spare
AC (heater)
Carrier only
Conduit
No.
1
1
1
1
1
1
2
3
4
5
6
Conduit
Size
4"
4"
4"
4"
4"
4"
1.25"
1.25"
1.25"
1.25"
1.25"
Conduit
No.
1
1
1
2
Conduit
Size
2"
2"
2"
1.25"
Wire Guage
Purpose
Conduit
No.
Conduit
Size
1
7/c
#10
PT
1
2"
1
7/c
#10
PT Spare
1
2"
Purpose
Conduit
No.
Conduit
Size
TRANSMISSION BREAKER - NON EHV
No. of
No. of Cables
Conductors Wire Guage
1
4/c
#10
DC Supply
1
4"
1
4/c
#10
AC Supply
1
4"
1
12/c
#10
Control & Relaying
1
4"
1
12/c
#10
Spare
1
4"
1
8pr
#16
Alarms
1
4"
1
4pr
#16
RTU Communication
1
4"
2 or 4 (Note 1)
4/c
#10
CTs
1
4"
1
4/c
#10
Spare for CTs
1
4"
1 (Note 2)
4/c
#10
Bus Differential (CT) Primary
2
1.25"
1 (Note 2)
4/c
#10
Bus Differential (CT) Backup
3
1.25"
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
Page 21 of 98
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
Note 1: (4) if low impedance scheme is used. (2) if high impedance or summation scheme is used for
differential
Note 2: In case of a summation or high impedance bus differential scheme
POWER TRANFORMERS
No. of
Conductors
No. of Cables
4 (Note 1)
4/c
1
4/c
1
4/c
1
4/c
1
4/c
1
8pr
1
8pr
1
4/c
Wire Guage
#10
#10
#10
#10
#10
#16
#16
#6
Purpose
CTs
CTs Spare
Neutral CT
LTC Potential
Sudden Pressure Relay
Alarms
Spare for Alarms
AC for fans and pump
Conduit
No.
1
1
1
1
1
1
1
2
Conduit
Size
4"
4"
4"
4"
4"
4"
4"
1.25"
Note 1: In case a bus or transformer differential scheme is used that requires summation. Use 1.25"
conduit for each CT that is going to differential cabinet in yard
FREE STANDING CT
CABINET
No. of Cables
1
1
1
No. of
Conductors
4/c
4/c
4/c
Wire Guage
#10
#10
#10
Purpose
CT
CT Spare
AC (heater)
Conduit
No.
1
1
1
Conduit
Size
2"
2"
2"
No. of
Conductors
4/c
4/c
Wire Guage
#10
#6
Purpose
TCC
PSO, TNC, SWECPO
Conduit
No.
1
1
Conduit
Size
1.25"
1.25"
Purpose
AC
Spare
Conduit
No.
1
1
Conduit
Size
2"
2"
FILTER TRUCK
RECEPTACLE
No. of Cables
1
1
STATION SERVICE
No. of
No. of Cables
Conductors Wire Guage
3 (Note 1
1
#2 - 2/0
1 (Note 1)
1
#2 - 2/0
Note 1: Use 1.25" conduit for #2 and 2" conduit for 2/0
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
Page 22 of 98
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
CIRCUIT SWITCHER
Wire Guage
#10
#10
#10
#10
#16
Purpose
AC
DC
Control
Control Spare
Alarms
Conduit
No.
1
1
1
1
1
Conduit
Size
3" or 4"
3" or 4"
3" or 4"
3" or 4"
3" or 4"
MOTOR OPERATED AIR BREAK SWITCH
No. of
No. of Cables
Conductors Wire Guage
1
4/c
#10
1
4/c
#10
1
12/c
#10
1
12/c
#10
Purpose
AC
DC
Control
Control Spare
Conduit
No.
1
1
1
1
Conduit
Size
3" or 4"
3" or 4"
3" or 4"
3" or 4"
No. of Cables
1
1
1
1
1
No. of
Conductors
4/c
4/c
12/c
12/c
8pr
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
Page 23 of 98
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
6.1.15 Capacitors - Transmission capacitor banks in AEPW system are usually connected single wye.
Size will vary from 5 to 50 MVARs. A resistive potential device connected in the neutral of the bank to
sense any imbalances caused by pack failures along with a Vee-switch ahead a capacitor switcher to
provide for a means visible of disconnecting it from the circuit.
6.1.16 Substation Power Transformer - The following table list the typical transformer BIL and
Percent Impedance Voltages drop at Self-Cooled (OA) Ratings of the power transformers used by AEPW.
High Voltage BIL
(Without LTC)
(With LTC)
Low Voltage
480 V
Low Voltage
Low Voltage
2400 V
2400 V
and Above
and Above
60-110
5.75 *
5.5 *
150
6.75
6.5
7.0
200
7.25
7.0
7.5
250
7.75
7.5
8.0
350
8.0
8.5
450
8.5
9.0
550
9.0
9.5
650
9.5
10.0
750
10.0
10.5
* For a transformer greater than 5000 KVA self-cooled, these values should be the
same as those shown for 150 kV HV BIL.
(kV)
6.1.17 AEPW Standard Breaker Ratings Used on the AEPW System - The following ratings are
intended to cover any application on the AEPW system. The “Item #” refers to the number used to identify
each breaker within the AEPW Circuit Breaker Specification.
Item #
Voltage Class (kV)
1A
1B
1C
2A
2B
3A
4A
5A
5B
5C
5D
5E
5F
5G
5H
6A
6B
7A
7B
7C
7D
15.5
15.5
15.5
25.8
25.8
38
72.5
145
145
145
145
145
145
145
145
169
169
362
362
362
362
Continuous Current
(A)
1200
2000
2000
1200
2000
1200
3150
2000
3000
2000
3000
4000
2000
3000
4000
3000
3000
2000
3000
2000
3000
Interruptible Current
(kA)
20
20
25
20
20
20
40
40
40
63
63
63
80
80
80
40
63
40
40
63
63
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
BIL
(kV)
110
110
110
150
150
200
350
650
650
650
650
650
650
650
650
750
750
1300
1300
1300
1300
TP-0002
Rev. 3
Page 24 of 98
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
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6.1.18
Switches - AEPW switch specifications are as follows:
a)
Switches will be designed to withstand a 150 mph wind loading and ANSI ice loading.
Switches shall have limited flex, keeping it in a static position such that high resistance
connections will not be created.
b)
Temperature rise for switches will be ANSI standard.
c)
All make-break contact surfaces will be silver-to-silver and replaceable.
d)
Roller, ball, or needle bearings with zert grease fittings are the only acceptable types.
6.1.19 CT’s, PT’s, CCVT’s, & Wavetraps:
Wavetrap Specifications
a)
Provide with resonant type tuning pack
b)
Units to be factory tuned
c)
4-hole NEMA line terminals on both ends
d)
Bird barriers both ends
e)
Corona rings required at voltages 230 kV and above
f)
Standard ampere ratings range from 800 to 2000 amps.
g)
Specify - single, double, or wide band frequency range.
l)
Standard frequencies for wide band traps ranges are 50 - 150 kHz, 70 - 200 kHz, and 100
- 300 kHz.
Consult with the AEPW Project Manager for frequency requirements and ampere rating.
Coupling Capacitors with Voltage Transformers Specifications
a)
Base to contain a case ground terminal case ground terminal
b)
Base and metal parts to be painted with weather resistant ANSI-70 gray paint
c)
Base and metal parts to be stainless steel or aluminum for corrosive environment
d)
Coupling capacitor porcelain housing to be ANSI-70 gray
e)
Top cover to be furnished with a 4-hole NEMA line terminal unless used as a support for
the line trap, where as a 5” bolt circle pattern NEMA is required.
f)
Voltage transformer rated at 150 VA output at marked relaying ratios per ANSI C93.2
g)
Base to contain a potential grounding switch and a 1.5” conduit nipple for potential lead
exit.
h)
Two secondary windings are required. Each winding shall have at least two output
voltages achieved by means of a tap (115/67.7v).
i)
If carrier accessories are required, the base is to contain: Drain coils, choke coil, carrier
grounding switch and gap, and a carrier lead-in bushing.
j)
Tuners are required with carrier and should be designed to pass carrier frequencies
specified by AEPW System Protection Department. If a separate enclosure is used to
mount the tuner it shall be equipped with a 120 VAC heater.
Voltage Transformers Specifications - Voltage transformers shall conform to NEMA and ANSI standards
in all respects. Low voltage PT’s are to be dry-type single bushing transformers with a ±0.3% metering
accuracy for burdens W, X, Y, and Z. High voltage PT’s are to be oil-filled transformers, with a ±0.3%
metering accuracy for burdens W, X, Y, and ZZ for line to ground connections, and will include the
following:
a)
Base and metal parts to be painted with weather resistant ANSI-70 gray paint
b)
Base and metal parts to be stainless steel or aluminum for corrosive environment
c)
Top cover to be furnished with a 4-hole NEMA terminal.
d)
Base shall be equipped to accommodate a minimum of two (2) conduit entrances.
e)
Two secondary windings are required. Each winding shall have at least two output
voltages achieved by means of a tap. (Check substation for special requirements.)
Current Transformers Specifications - The current transformers shall conform to NEMA and ANSI
standards in all respects. Low voltage CT’s can be window or terminal type with a metering accuracy class
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
Page 25 of 98
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
of ±0.3% at specified burden ratings. Relay class may be used if revenue meters are not needed. High
Voltage CT’s shall be outdoor type; freestanding, oil or SF6 filled and shall include the following:
a)
Base and metal parts to be painted with weather resistant ANSI-70 gray paint
b)
Base and metal parts to be stainless steel or aluminum for corrosive environment
c)
Base shall be equipped to accommodate a minimum of two (2) conduit entrances.
d)
Manufacturer shall provide a ground point for grounding the case.
e)
Bushing shall be one-piece porcelain, and ANSI-70 gray.
f)
Bushings shall meet ANSI standards for the type and class required.
g)
If oil filled, oil to be certified non-PCB.
h)
If oil filled, CT’s shall have a visual indication of oil level.
i)
If gas filled, CT’s shall have approved gas density mounting devices for visual indication
of the gas density, which can be read from ground.
6.1.20
INSULATION - Equipment utilized in substations shall comply with the following BIL standard:
Basic Lightning Impulse Insulation Level(BIL)
(kV rms) at System kV listed below
12.47
13.8
25
34.5
Description
2Wdg Xfmr Internal BIL
110
110
150
150
2Wdg Xfmr Bushing BIL
110
110
150
150
Bus/Switch Support BIL
110
110
150
150
Circuit Breaker Bushing BIL
110
110
150
150
Auto Xfmr Internal BIL
110
110
150
150
Auto Xfmr Bushing BIL
110
110
150
150
Description
69
Basic Lightning Impulse Insulation Level(BIL)
(kV rms) at System kV listed below
115
138
161
230
345
2Wdg Xfmr Internal BIL
350
550
550
650
750
1050
2Wdg Xfmr Bushing BIL
350
650
650
750
900
1300
Bus/Switch Support BIL
350
550
550
650
900
1300
Circuit Breaker Bushing BIL
350
650
650
750
900
1300
Auto Xfmr Internal BIL
350
550
550
650
750
1050
Auto Xfmr Bushing BIL
350
650
650
750
900
1300
In areas, classified as “Corrosive Environments”, insulator and bushings will be supplied with high creep
skirts. The BIL rating of the insulator need not be increased, but the total creepage must meet the following
requirements:
Minimum External Creepage Distance (inch)
Equipment Voltage
BIL
AEP Creepage Required
ANSI C37.01.06
Rating (kV)
(kV)
(Reference Only)
15.5
110
17
9
25.8
150
26.5
15
38
200
-
22
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
Page 26 of 98
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
72.5
350
72
42
121
550
-
70
145
650
133
84
169
750
-
93
242
900
-
140
362
1300
318
209
6.1.21 Foundations - Foundations shall be proportioned to resist the maximum calculated structure and
equipment loads using site-specific soil parameters.
6.1.22 Structure Loading – Structures shall be designed to resist all applied loads including but not
limited to conductor tension, wind, ice, and short circuit forces. In addition to strength requirements,
structures shall be proportioned such that the load-induced deflections do not hinder the functionality of the
structure and the equipment it supports.
For a proposed facility on the OPCO-side of the point of service, specifically any dead-end structure and
foundation in an existing OPCO substation, AEPW will design and construct such facility.
AEPW/OPCO will provide a point of attachment on the dead-end structure to connect the proposed
facility to existing OPCO substation.
The following are requirements are used by AEPW in the design of the substation facilities. All design
parameters follow the rules set forth by the “National Electric Safety Code” (NESC); ASCE 7, “Minimum
Design Loads for Buildings and Other Structures”; and other accepted industry practices.
6.1.22.1 Equipment Structures - AEPW recommends that TG, TI, and TEEU Requester’s
facilities located within approximately 140 miles of the Gulf of Mexico be designed for a
minimum basic wind speed equal to 135 mph. AEPW recommends that TG, TI, and TEEU
Requester’s facilities located in all other areas of the OPCO’s service territory be designed for a
minimum basic wind speed equal to 90 mph.
6.1.22.2 Dead-End Structures – Dead-end structures must be designed to the conductor, wind,
and ice loading conditions and strength requirements described in Part 25 of the NESC. A
minimum of three loadings conditions shall be satisfied:
NESC Heavy Loading, Grade B Construction
Extreme Wind, using the basic wind speed of 90 mph or 135 mph as appropriate for the geographical area
in which the facility will be located
Combined Wind and Ice, as defined in Part 25 of the NESC
6.1.23 Steel in Coastal and Industrial Corrosive Environments – AEPW recommends that the
average coating thickness of hot dip galvanizing for structures installed in coastal corrosion or industrial
corrosion environments shall be 5.0 mils. Coastal regions in Texas are defined as the area bounded by the
Gulf of Mexico and US Highway 77. All other structures shall be hot dip galvanized in accordance with
ASTM A 123.
7.0
TRANSMISSION LINE DESIGN, LOADING, CLEARANCE, INSULATION AND STRUCTURAL
DESIGN REQUIREMENTS
7.1
TRANSMISSION LINE DESIGN REQUIREMENT - Upon determination of the point of service, the
design and construction of new transmission line facilities on the OPCO electric system necessary to
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
Page 27 of 98
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
connect to TG, TI and TEEU Requester’s facilities shall be done in accordance with the following
criteria.
8.0
7.1.1
New Transmission Lines Serving only the TG, TI and TEEU Requester and that will not be
owned by the OPCO - New Transmission Lines that are “taps” of existing transmission circuits
built solely to serve the TG, TI and TEEU Requester or otherwise do not involve carrying
OPCO services to other customers or delivery points and will not be owned by the OPCO may be
built to any criteria determined by the facility owner and operator so long as it meets the minimum
requirements of:
• ANSI-C2, National Electric Safety Code (NESC), latest edition, and
• NFPA 70, National Electrical Code (NEC), latest edition, and
• Governmental agencies as needed to obtain permits to construct the line (Ex. U.S Army
Corps of Engineers, FAA, etc.).
• Any additional applicable state and local code or criteria.
7.1.2
New Transmission Lines serving the TG, TI and TEEU Requester and integrated in the
OPCO Network - New Transmission Lines that, in addition to serving the TG, TI and TEEU
Requester involve carrying OPCO services to other customers or delivery points or will be
owned by the OPCO shall, in addition to the criteria indicated above, be designed in accordance
with AEP System Standard TLES-10, “Clearances, Mechanical Loadings and Load Factors
Applicable to Structures, Foundations Hardware, Insulators, Conductors Ground wire and Line
Design” (latest revision).
METERING AND SCADA REQUIREMENTS
8.1
TRANSMISSION INTERCONNECT METERING REQUIREMENTS
For all transmission interconnections, a transfer of power between AEPW and the TG, TI or TEEU Requester
system shall be metered at the point of interconnection. The power transfer between the OPCO and the TG, TI and
TEEU Requester will be metered with bi-directional metering for bi-directional interconnections. Power flow from
AEPW to the TG, TI and TEEU Requester will be designated as “Out” kWh. “Out” kWh is considered positive
and “In” kWh is considered negative. The same conventions will be observed on the reactive power. Each of the
four quantities will be recorded separately. Recording of TG, TI and TEEU Requester energy usage for the billing
period will be determined by AEPW.
If requested by the TG, TI and TEEU Requester, and if available from the AEPW metering equipment, the
following information can be provided to the TG, TI and TEEU Requester at the point of interconnection. If not
available from the OPCO’s metering equipment, the following information can be provided to the TG, TI and
TEEU Requester at the TG, TI and TEEU Requester’s expense:
1)
“Out” kWh
2)
“In” kWh
3)
“Out” kVARh
4)
“In” kVARh
5)
+/- kW
6)
+/- kVAR
If requested by the TG, TI and TEEU Requester, MW and MVAR transducers shall be 3-element transducers with
an accuracy of ±0.2% or better.
For a TG, TI and TEEU Requester having more than one point of interconnection (e.g., two lines), independent bidirectional metering is required on each interconnecting circuit.
All current transformers shall conform to a minimum of ±0.3% metering accuracy class or better. Voltage
transformers shall conform to a minimum of ±0.3% metering accuracy class or better. The current transformers and
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voltage transformers used to meter bi-directional power flow shall meet the latest ANSI C57.13 requirements for
instrument transformers.
All affected parties shall be involved in engineering changes of interconnect metering equipment from project
inception. All parties must be notified so a mutually agreeable time can be set for the changes. All parties involved
must be satisfied to the making of any changes.
Metering and Operation personnel of all affected parties shall be notified at least 48 hours in advance, or at a
mutually acceptable advance notice, prior to any calibrations or maintenance. In emergency conditions, the owner
of the metering installation may make necessary repairs with notification to affected parties within 24 hours. Copies
of the repair and calibration records shall be forwarded to all involved parties.
For additional information see Appendix G (AEP Metering Requirements for Transmission Interconnection
Facilities – verification of latest revision required).
8.2
TRANSMISSION INTERCONNECT SCADA REQUIREMENTS
The following information shall be supplied by the TG, TI and TEEU Requester for each point of interconnection
and connected to the AEPW’s recording equipment and the transmission-specific remote terminal unit (RTU) used
for the point of interconnection. Except where specified as hardwired, RTU inputs shall be supplied from an IED
(Intelligent Electronic Device), from an AEPW–approved interface device, or hardwired. RTU inputs from an IED
or an AEPW–approved interface device shall be Ethernet or RS-485 using DNP 3.0 protocol.
1)
Status Points
a)
Transmission line breaker status (required for each TG, TI and TEEU Requester line)
b)
IED failure (required for each IED sourcing a required point)
c)
IED communications failure (required for each IED sourcing a required point)
d)
Battery charger trouble (required for the battery powering the RTU)
e)
Battery charger AC power failure (required for the battery powering the RTU)
f)
Smoke alarm (required for the structure housing the RTU)
g)
Fire or high temperature alarm (required for the structure housing the RTU)
2)
Analog Points
a)
MW from each TG, TI and TEEU Requester line
b)
MVAR from each TG, TI and TEEU Requester line
c)
Voltage per phase from each TG, TI and TEEU Requester line
d)
Current per phase from each TG, TI and TEEU Requester line
3)
Hourly Accumulation Points
a)
MWh IN from each TG, TI and TEEU Requester line
b)
MWh OUT from each TG, TI and TEEU Requester line
c)
MVARh IN from each TG, TI and TEEU Requester line
d)
MVARh OUT from each TG, TI and TEEU Requester line
All Supervisory Control and Data Acquisition (SCADA) equipment shall be satisfactory to AEPW.
For additional information see Appendix H (AEP SCADA RTU Requirements at Transmission Interconnection
Facilities – verification of latest revision required).
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
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Always check for the latest revision prior to use.
8.3.
COMMUNICATION REQUIREMENTS
8.3.1
CIRCUIT REQUIREMENTS
TG, TI and TEEU Requesters shall be responsible for procuring and paying for communication circuits
for use by AEPW. The TG, TI and TEEU Requester shall be responsible for confirming with AEPW the
project-specific circuit requirements and requesting specific AEPW addresses and AEPW contact names
in preparation for issuing communication circuit orders with the TG, TI or TEEU Requester's
telecommunication service provider of choice. These communication circuits shall be leased telephone
company circuits or other media satisfactory to AEPW. For each telephone company circuit leased by the
TG, TI and TEEU Requester, the TG, TI and TEEU Requester shall provide AEPW and the
telecommunication service provider with advanced authorization for communication circuit maintenance,
allowing AEPW and any of its affiliates and subsidiaries to monitor the circuit, report trouble and take
corrective action with the telecommunication service provider, at the TG, TI or TEEU Requester's
expense, to maintain circuit reliability. The communication circuits described here shall be operational and
commissioned by AEPW prior to AEPW providing a continuous power source to the interconnection
facility. Typical facility circuit requirements include the following:
1)
RTU Communications Circuit - This is a leased circuit from the demark associated with the RTU
at the TG, TI or TEEU Requester's facility to an AEPW Dispatch office; this circuit is to be
ordered and paid for by the TG, TI or TEEU Requester. One circuit is required for each RTU.
This circuit will be utilized by AEPW to communicate with the RTU and, if applicable, the fault
recorder. The required circuit is a 56 Kbps Frame circuit with DDS interface at the RTU end and
DDS interface at the AEPW Dispatch office end.
2)
Voice Dispatch Circuit - This is a leased circuit from the TG Requester's facility plant operators
to an AEPW Dispatch office. If the TG Requester's facility plant operators are not located on the
plant site, then the circuit must be terminated at the actual location of the plant operators. This
circuit is required of the TG Requester where the total plant generation capacity is equal to or
greater than 50 MVA. This circuit is to be ordered and paid for by the TG Requester. The
required circuit is a Bell 428, also known as an OSPA 428. This circuit is a two-point off-premise
station voice-grade two-wire analog facility with loop start signaling at the AEPW Dispatch office
end. For circuit design and ordering purposes, the circuit origination is to be at the AEPW
Dispatch office; the circuit termination is to be at the actual location of the TG Requester's
facility plant operators.
3)
Dial-Up Circuit - This is a standard business telephone line (with a 10-digit telephone number)
with long distance provisioning to be ordered and paid for by the TG, TI or TEEU Requester.
The requirement for one or more Dial-Up Circuits will be determined by AEPW on a projectspecific basis. This circuit may be required for interconnect meter reading, system protection
equipment interrogation and access to the fault recorder. If the interconnect metering, system
protection equipment and fault recorder are located at multiple sites, then multiple Dial-Up
Circuits may be required. If these devices are located at the same site, one Dial-Up Circuit may
suffice for dial-up access. (In this case, the TG, TI or TEEU Requester is to receive approval
from AEPW prior to installing a telephone switch to share one Dial-Up Circuit among multiple
devices.)
8.3.2
DEMARK REQUIREMENTS
For all telephone company circuits leased into a substation, demarcation equipment (demark) satisfactory
to AEPW shall be installed and maintained. The demark will provide the interface between the telephone
company’s service cable and the substation. The demark design shall accommodate 24x7 accessibility by
AEPW personnel without escort from telephone company personnel, the TG, TI or TEEU Requester,
facility operator or land owners. The demark design shall accommodate 24x7 accessibility by telephone
company personnel without escort from AEPW personnel, the TG, TI or TEEU Requester, facility
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
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Transmission System
TP-0002
Rev. 3
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operator or land owners. The demark shall be located on the substation ground grid and accessible from
outside the substation fence or through a secured personnel gate. The TG, TI and TEEU Requester shall
be responsible for providing surge protection satisfactory to AEPW on the communications cable between
the demark and the substation control building.
The demark described here shall be operational and commissioned by AEPW prior to AEPW providing a
continuous power source to the interconnection facility.
8.3.3
HIGH VOLTAGE ISOLATION REQUIREMENTS
If required by the OPCO or the telephone company, high voltage isolation (HVI) equipment for all
telephone company circuits leased into a substation shall be installed and maintained. The HVI equipment
shall be designed to adequately protect against ground potential rise and shall be satisfactory to AEPW and
the telephone company. The HVI equipment design shall accommodate 24x7 accessibility by AEPW
personnel without escort from telephone company personnel, the TG, TI or TEEU Requester, facility
operator or landowners. The HVI equipment design shall accommodate 24x7 accessibility by telephone
company personnel without escort from AEPW personnel, the TG, TI or TEEU Requester, facility
operator or landowners. The HVI equipment shall be located on the central office (telephone company)
side of the demark (see Section 8.3.2). The HVI equipment shall be located on the substation ground grid
and accessible from outside the substation fence or through a secured personnel gate.
The HVI equipment described here shall be operational and commissioned by AEPW prior to AEPW providing a
continuous power source to the interconnection facility.
8.4
RTU REQUIREMENTS
A transmission-specific remote terminal unit (RTU) is required for all transmission interconnections. In addition, a
generation-specific RTU may be required at TG Requester’s facilities for AEPW’s generation-specific Supervisory
Control and Data Acquisition (SCADA); for more information see Section 8.6. The RTU protocol from the RTUs
to the AEPW Dispatch office shall be satisfactory to AEPW. The TG, TI and TEEU Requester shall marshal all
their RS-485 and hardwired RTU inputs at a marshalling cabinet (interface terminal block or interface cabinet)
satisfactory to AEPW. The TG, TI and TEEU Requester shall engineer, procure, construct and own the
marshalling cabinet, wire to the marshalling cabinet from the various generation or substation equipment, provide
AEPW with documentation identifying the location of generation or substation SCADA points wired to the
marshalling cabinet, and provide AEPW with terminals at the marshalling cabinet from which to wire to the RTU.
The TG, TI and TEEU Requester shall provide a dedicated station DC breaker for each RTU.
For additional information see Appendix H (AEP SCADA RTU Requirements at Transmission Interconnection
Facilities – verification of latest revision required).
Prior to AEPW providing a continuous power source to the interconnection facility, the transmission-specific RTU
and the generation-specific RTU described here shall be operational with AEPW-required RTU functions
commissioned by AEPW.
8.5
GENERATION METERING REQUIREMENTS
For generation metering, the “In” / “Out” power flow is referenced from AEPW or the grid’s perspective. Normal
MW generation will be designated as “In” MW. “In” MW is considered negative. Backfeed power from the OPCO
to the TG Requester is “Out” MW and is considered positive. The same conventions will be observed on the
reactive power.
Meters are required for generation gross and station use auxiliaries. Unless used for transmission interconnect
metering (see Section 8.1), all voltage and current transformers used for generation metering shall conform to relay
accuracy class or better. MW and MVAR transducers shall be 3-element transducers with an accuracy of ±0.2% or
better.
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
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For additional information see Appendix G (AEP Metering Requirements for Transmission Interconnection
Facilities – verification of latest revision required).
For those locations where it may be possible to switch the generation between power pools, there will be unique
requirements for metering; such requirements will be determined by AEPW on a project-specific basis.
8.6
GENERATION SCADA REQUIREMENTS
For TG Requesters where the total plant generation capacity is equal to or greater than 50 MVA, a generationspecific RTU is required at TG Requester’s facilities for AEPW’s generation-specific SCADA, and the following
SCADA information shall be required. A specific RTU data interface list will be developed by AEPW as a part of
each generation project based upon the project's electrical configuration. For such purpose the TG Requester shall
be responsible for providing AEPW with metering and relaying one-line diagrams of the generation and substation
facilities. The generation-specific RTU located at the TG Requester's facility will supply the following SCADA
information to AEPW:
1)
Control Points – RTU inputs shall be hardwired.
a)
Trip (required for one or more generation or transmission line breakers to allow AEPW
to trip all generation units during system emergencies)
2)
Status Points – Except where specified as hardwired, RTU inputs shall be supplied from an IED
(Intelligent Electronic Device), from an AEPW–approved interface device, or hardwired. RTU
inputs from an IED or an AEPW–approved interface device shall be Ethernet or RS-485 using
DNP 3.0 protocol.
a)
Generator breaker status (hardwired for each breaker where Trip control is required)
b)
Circuit switcher / line switch status (“a” and “b” contacts)
c)
Transformer high-side breaker status (hardwired for each breaker where Trip control is
required)
d)
Transformer high-side motor operated switch status (“a” and “b” contacts)
e)
Transmission line lockout relay operated
f)
Transmission line lockout relay failure
g)
Auxiliary breaker status
h)
Capacitor bank breaker/switch status
i)
Supervisory cutoff (hardwired for each breaker where Trip control is required)
j)
Breaker failure lockout status (hardwired for each breaker where Trip control is required)
k)
Breaker critical alarm (required for each breaker where Trip control is required, combine
critical alarms for each breaker)
l)
Transformer critical alarm (combine critical alarms for each transformer)
m)
Transformer primary lockout relay operated
n)
Transformer primary lockout relay failure
o)
Transformer backup lockout relay operated
p)
Transformer backup lockout relay failure
q)
IED failure (required for each IED sourcing a required point)
r)
IED communications failure (required for each IED sourcing a required point)
s)
Battery charger trouble (required for the battery powering the RTU)
t)
Battery charger AC power failure (required for the battery powering the RTU)
u)
Smoke alarm (required for the structure housing the RTU)
v)
Fire or high temperature alarm (required for the structure housing the RTU)
w)
Generator automatic voltage regulator (AVR) status
x)
Fault recorder trouble alarm
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
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3)
Analog Points – Except where specified as hardwired, RTU inputs shall be supplied from an IED,
from an AEPW–approved interface device, or hardwired. RTU inputs from an IED or an
AEPW–approved interface device shall be Ethernet or RS-485 using DNP 3.0 protocol.
a)
Generator gross MW (required for each generation unit)
b)
Generator gross MVAR (bi-directional values required for each generation unit)
c)
Generator station use MW auxiliary (required for each auxiliary transformer)
d)
Generator station use MVAR auxiliary (bi-directional values required for each auxiliary
transformer)
e)
Station frequency HZ (for those stations where a common bus does not exist between
multiple generation units, individual unit frequency points will be required)
f)
Voltage per phase where the facility connects to transmission system
g)
Voltage per phase for each winding of each transformer
h)
Current per phase for each winding of each transformer
i)
MW for each winding of each transformer
j)
MVAR for each winding of each transformer
For additional information see Appendix H (AEP SCADA RTU Requirements at Transmission Interconnection
Facilities – verification of latest revision required).
For those locations where it may be possible to switch the generation between power pools, there will be unique
requirements for SCADA; such requirements will be determined by AEPW on a project-specific basis.
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
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TP-0002
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Appendix A
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APPENDIX A
A: AEP Power Quality Requirements
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Appendix A
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Always check for the latest revision prior to use.
AEP Power Quality Requirements
This document summarizes the AEP policy on power quality requirements, which include voltage flicker, harmonic
distortion and other factors, for customers connected to the AEP Transmission System. The term Company is defined as
American Electric Power (AEP). The term Customer is defined as the party connected to the AEP System.
POINT OF COMPLIANCE
The point where the Customer connects to the Company system will be the point where compliance with AEP power
quality requirements is evaluated.
VOLTAGE FLICKER CRITERIA
The random voltage fluctuations (flicker) occurring at the Compliance Point directly attributable to the Customer shall
remain within the limits specified in IEEE Standard 1453-2004, “IEEE Recommended Practice for Measurement and
Limits of Voltage Fluctuations and Associated Light Flicker on AC Power Systems.” These limits are 0.8 and 0.6 for the
PST (short term) and PLT (long term) flicker measures, respectively. PST is the standard reading of a flicker meter,
obtained for each 10-minute interval; PLT is derived mathematically (cube root-mean-cube) from twelve consecutive PST
readings (see Table 1).
The Customer agrees that under no circumstances will it permit the voltage flicker to exceed the Company criteria, whether
or not complaints are received or service/operational problems are experienced on the Company sub-transmission or
transmission system. Should complaints be received by the Company or other operating problems arise, or should the
Customer flicker exceed the Company criteria, the Customer agrees to take immediate action to reduce its flicker to a level
at which flicker complaints and service/operational problems are eliminated.
Corrective measures could include, but are not limited to, modifying production methods/ materials or installing, at the
Customer's expense, voltage flicker mitigation equipment such as a static var compensator. The Company will work
collaboratively with the Customer to assess problems, identify solutions and implement mutually agreed to corrective
measures.
If the Customer fails to take corrective action after notice by the Company, the Company shall have such rights as currently
provided for under the ISO/RTO OATT, which may include discontinuing service, until such time as the problem is
corrected.
HARMONIC DISTORTION CRITERIA
The Company also requires that the Customer's operation be in compliance with the Company's Harmonic Distortion
Guidelines (see Exhibit 2). These requirements are based on IEEE Standard 519, "IEEE Recommended Practices and
Requirements for Harmonic Control in Electric Power Systems".
The Customer agrees that the operation of motors, appliances, devices or apparatus served by its facility that result in
harmonic distortions in excess of the Company's Requirements will be the Customer's responsibility to remedy
immediately, at the Customer's expense, in order to comply with the Company's Harmonic Distortion Requirements. The
Company will work collaboratively with the Customer to assess problems, identify solutions, and implement mutually
agreed to corrective measures.
If the Customer fails to take corrective action after notice by the Company, the Company shall have such rights as currently
provided for under the ISO/RTO OATT, which may include discontinuing service, until such time as the problem is
corrected.
While IEEE Standard 519-1992 recommends that even-numbered harmonic currents be limited to only 25% of the stated
values, the requirements established herein are uniform at the full-limit values for both odd and even harmonics. AEP
reserves the right to limit the even harmonic currents, as recommended by IEEE Standard 519-1992, if operational
problems and/or customer complaints are experienced in the future.
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
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Appendix A
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COMMUNICATION INTERFERENCE
The total communication interference (I*T product) shall not exceed the level of weighted Amperes, at the Compliance
Point, prescribed by IEEE Standard 519-1992 (see Exhibit 2).
OTHER REQUIREMENTS
A.
Electrical Interactions
If Power Quality Compliance Monitoring recordings or analytical studies conducted by AEP indicate likely adverse
electrical interactions (e.g., resonance) between the connected facility and the AEP System, joint efforts will be undertaken
by the Parties to determine the nature and extent of the electrical interaction and to resolve, at no expense to AEP, any
likely adverse impacts on the performance of AEP facilities.
B.
Compliance Assessment
To achieve compliance, at least 95% of all recordings within each harmonic measure and 99% within each flicker measure
must fall below the applicable limit, i.e., the customer will be in material non-compliance with the AEP Power Quality
Requirements if more than 5% of the harmonic voltage and harmonic current recordings and 1% of the flicker recordings
exceed the specified limits.
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
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Appendix A
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EXHIBIT 1
AEP VOLTAGE FLICKER REQUIREMENTS
[Based on IEEE Standard 1453-2004, “IEEE Recommended Practice for Measurement
And Limits of Voltage Fluctuations and Associated Light Flicker on AC Power Systems”]
Voltage Flicker Measure
Maximum Value
PST (Short Term)
0.8
PLT (Long Term)
0.6
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Appendix A
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EXHIBIT 2
AEP HARMONIC DISTORTION REQUIREMENTS
[Extracted from IEEE/ANSI Standard 519-1992, “IEEE Recommended Practices and Requirements for Harmonic
Control in Electric Power Systems.”]
1. HARMONIC VOLTAGE DISTORTION (THDV) LIMITS
[Applicable to Transmission Systems]
Individual Harmonic Voltage
Distortion (%)
3.0
1.5
1.0
Bus Voltage at PCC
≤ 69 kV
> 69 kV and ≤ 161 kV
> 161 kV
Total Voltage Distortion THDv
(%)
5.0
2.5
1.5
2. HARMONIC CURRENT DEMAND DISTORTION (TDD) LIMITS
[Applicable to Individual Customers at the Point of Common Coupling (PCC)]
Maximum Harmonic Current Distortion in Percent of Base Quantity
Harmonic Order (Odd Harmonics)
V ≤ 69 kV
ISC/IL
< 11
11 ≤ h < 17
17 ≤ h < 23
23 ≤ h < 35
35 ≤ h
TDD
<20*
20<50
50<100
100<1000
>1000
4.0
7.0
10.0
12.0
15.0
2.0
3.5
4.5
5.5
7.0
1.5
2.5
4.0
5.0
6.0
0.6
1.0
1.5
2.0
2.5
0.3
0.5
0.7
1.0
1.4
5.0
8.0
12.0
15.0
20.0
0.3
0.5
0.75
1.0
1.25
0.15
0.25
0.35
0.5
0.7
2.5
4.0
6.0
7.5
10.0
0.3
0.45
0.15
0.22
2.5
3.75
69 kV < V ≤ 161 kV
<20*
20<50
50<100
100<1000
>1000
2.0
3.5
5.0
6.0
7.5
1.0
1.75
2.25
2.75
3.5
0.75
1.25
2.0
2.5
3.0
161 kV < V
<50
≥50
2.0
3.0
1.0
1.5
0.75
1.15
Even harmonics are limited to 25% of the odd harmonic limits above.
* All power generation equipment is limited to these values of current distortion, regardless of actual ISC/IL.
where
ISC = Maximum short-circuit current at PCC.
IL = Load current (fundamental frequency component) at time of maximum metered amount at PCC.
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Appendix A
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Always check for the latest revision prior to use.
Definitions
•
Harmonic Voltage Distortion is to be normalized to the nominal system voltage and calculated using Equation 1
TOTAL VOLTAGE HARMONIC DISTORTION (THDV) in percent:
∞
THDV =
∑
n=2
V n2
× 100 %
Vs
(Eq. 1)
Where:
Vn = Magnitude of Individual Harmonics (RMS)
Vs = Nominal System Voltage (RMS)
n = Harmonic Order
•
Harmonic Current Distortion is to be normalized to the customer‘s load current at the time of the maximum metered
demand which occurred over the preceding twelve months for existing customers and the customer’s anticipated peak
demand for new customers. For existing customers who are increasing their load, the projected demand should be used.
The harmonic current demand distortion (TDD) should be calculated using Equation 2.
TOTAL CURRENT DEMAND DISTORTION (TDD) in percent:
∞
TDD =
∑
n=2
I
I n2
× 100%
(Eq. 2)
L
Where:
In = Magnitude of Individual Harmonic (RMS)
IL = Load current at the time of the maximum metered demand
n = Harmonic Order
•
PCC – Point of Common Coupling is the location where the customer accepts delivery of electrical energy from the
utility.
Field Measurements
To gauge the acceptability of field measured harmonic distortion, a statistical evaluation of the data is to be performed.
Measurements should be taken at five minute intervals or less over a minimum of 24 hours. For the measured data to be
considered acceptable, two criteria must be met: 1) 95% of the measured data must fall below the limits stated; and 2) no measure
data shall exceed the limits specified by than 50% of the absolute upper limit value.
3.
COMMUNICATION INTERFERENCE LIMITS (I*T)
Rather than provide specific limits on I*T values, due to the limitations involved, IEEE/ANSI standard 519 outlines the ranges of
I*T values for three potential states of telephone interference inflicted by the harmonic components of current and voltage, which
are shown in the table below. The actual interference to voice communication systems in proximity to the power system is
dependent upon a number of factors not under the control of the utility or customer. These factors will vary from location to
location and from time to time as the state-of-the-art of inductive coordination progresses.
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
Page 39 of 98
Appendix A
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
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IEEE STANDARD 519 – BALANCED I*T GUIDELINES
Category
Description
I*T
I
Levels most unlikely to cause interference
< 10,0000
II
Levels that might cause interference
10,000 to 25,000
III
Levels that probably will cause interference
> 50,000
The limit applicable to AEP is the upper bound limit of the I*T levels that might cause interference on telephone systems. Thus,
the customer induced harmonics shall not result in an I*T product to exceed 25,000 weighted amperes per phase, applicable to
both the transmission and distribution systems. Residual I*T should also be minimized. Residual I*T is IG*T, where IG is the
earth return current and is defined as the difference between the phasor sum of phase currents and neutral current. The I*T
calculation is to be performed using Equation 3. The weighting of harmonic currents should conform to the 1960 TIF data shown
in the table below.
I*T PRODUCT in amperes:
K
I*T = I*TIF =
∑ (I
n =1
n
∗ Wn ) 2 weighted amperes (Eq. 3)
Where:
I = Current of individual harmonics, RMS
T = Telephone Influence Factor (TIF)
Wn = Single frequency TIF weighting at frequency n (refer to tables below)
K ≤ 42, Maximum harmonic order
Frequency
Wn
Frequency
Wn
Frequency
Wn
Frequency
Wn
60
0.5
1020
5100
1860
7820
3000
9670
180
30
1080
5400
1980
8330
3180
8740
300
225
1140
5630
2100
8830
3300
8090
360
400
1260
6050
2160
9080
3540
6730
420
650
1380
6370
2220
9330
3660
6130
540
1320
1440
6650
2340
9840
3900
4400
660
2260
1500
6680
2460
10340
4020
3700
720
2760
1620
6970
2580
10600
4260
2750
780
3360
1740
7320
2820
10210
4380
2190
900
4350
1800
7570
2940
9820
5000
840
1000
5000
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
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Transmission System
TP-0002
Rev. 3
Page 40 of 98
Appendix B
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APPENDIX B
B: Typical Transmission Tap Supply & Line Looped Supply Configurations
Typical Transmission Tap Supply Configurations
Figure 1
Radial Line Supply Alternatives - For Facilities below 200 kV Non-Generators
- Connected to an Existing Station
Figure 2
Radial Line Supply Alternatives - For Facilities below 200 kV Non-Generators
- Connected to an Existing Line
Typical Transmission Line Looped Supply Configurations
Figure 3
Loop Supply Alternatives - For Facilities below 200 kV Non-Generators
- Looped Service
Typical Generation Connection Configurations
Figure 4
Generator Connection Alternatives
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
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TP-0002
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Page 41 of 98
Appendix B
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TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
Page 42 of 98
Appendix B
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TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
Page 43 of 98
Appendix B
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TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
Page 44 of 98
Appendix B
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Figure 4
Generator Connection Alternatives
G eneration C onnections To A E P Transm ission S ystem
1. C onnection To E xisting S tation B us(es)
M
S tation B us
( F or a double connection, another sim ilar
connection can be m ade with any other
station bus)
G
2. S ingle C onnection To E xisting Line
M
M
G
G
3. D ouble C onnection To E xisting Line(s)
M
M
LE G END
M
M
Looping A Single
Circuit Line
G enerating
U nit(s)
G
Loop ing A Double Circuit Line
G
C ircuit
B reaker
G
M
G
G
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
M etering
Air Bre ak Switch
TP-0002
Rev. 3
Page 45 of 98
Appendix C
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APPENDIX C
C: Electrical Clearances and Equipment Ratings
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TITLE: Requirements for Connection of New Facilities or
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TP-0002
Rev. 3
Page 46 of 98
Appendix C
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TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
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TP-0002
Rev. 3
Page 47 of 98
Appendix D
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APPENDIX D
D: Generation Abnormal Frequency Operating Allowance
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TITLE: Requirements for Connection of New Facilities or
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TP-0002
Rev. 3
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Appendix D
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TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
Page 49 of 98
Appendix E
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APPENDIX E
E: Information Supplied By Generation Owner
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TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
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Appendix E
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Information Supplied By Generator Owner (TG)
Name, address, telephone number, and E-mail address of Generator Owner (TG):
Title:
Name:
Company:
Address:
Phone: __________________
Email:
Name of TG Project Manager’s “Single Point of Contact” - individual with authority (equal to
Generator Owner) to make day to day decisions regarding the processing of the Interconnection
Request with ISO/RTO:
Title:
Name:
Company:
Phone:
Address:
Email:
Name, address, telephone number, and E-mail address of individual(s) representing the
TG related to technical questions about the design and operation of the proposed Facility:
Name:
Title:
Company:
Phone:
Address:
Email:
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
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TP-0002
Rev. 3
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Appendix E
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Provide the Following data at time of “Kickoff Meeting”:
Site Plan (on tax map, USGS Topo map, etc) for Interconnection Customer’s Facilities
(Electronic file if available):________________________________________________
Interconnection Customer’s proposed location (if known) for Point of Interconnection (POI) to AEPW
system:_________________________________________________
Type (Synchronous, Induction, Inverter, etc), and rating of proposed generator(s):
______________________________________________________
Project Schedule:
Backfeed Requirement & Date. _______________________
Generation Testing (1st energy into grid) Dates.
, 2____________; 3____________; 4 ____________
Expected Commercial Dates.
, 2____________; 3____________; 4 ____________
Confirm/acknowledge Queue MWs (at 920F ambient) & choice of Capacity or Energy-Only rights:
MW:
Capacity or Energy-Only:
Fuel (gas, wind, nuclear, diesel), and technology (steam turbine-generator, combustion turbine-generator, combined / simple
cycle etc) for generation:___________________________________________
Estimated maximum and minimum Facility load at Point of Interconnection with generation in service:
Maximum __________________
Minimum: __________________
Estimated maximum and minimum Facility load at Point of interconnection without generation in service: Maximum
__________________
Minimum: __________________
Estimated maximum net energy to AEPW System:
If customer’s facilities are already connected to the AEPW System, provide a one line diagram of existing connection
arrangement with existing meter locations identified. Identify meter type (e.g. KWH Revenue, etc.)
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
Page 52 of 98
Appendix E
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The Generator Owner shall provide copies of the following drawings:
One line diagram of Facility electrical arrangement.
All potential elementary drawings associated with the protection and control schemes for the generator and interconnection
equipment.
All current elementary drawings associated with the protection and control schemes for the generator and interconnection
equipment.
A control elementary of the generator breaker and the interconnection breaker.
A three line diagram of generation system.
1.
Documentation of all protective device settings shall be provided. The setting documentation shall also include relay
type, model/catalog number and setting range. If automatic transfer schemes or unique or special protective schemes are
used, a description of their operation should be included. The Company must review and approve the settings of all
protective devices and automatic control equipment which: (1) serve to protect the Connective Power Delivery System
from hazardous currents and voltages originating from the Facility or (2) must coordinate with protective devices or
control equipment located on the Connective Power Delivery System.
2. The following modeling data must be supplied to the Company and/or ISO/RTO to allow necessary interconnection
studies to be performed. It is recognized that some of this data may initially be preliminary in nature. Interconnection
studies will be based on data submitted. Any changes, or modifications, to this data after the interconnection study has
been completed may render the analysis invalid and require re-opening of the interconnection study. It is the Generator
Owners responsibility to make the Company and / or ISO/RTO aware of any changes to this data, and to provide final
certified test reports and modeling data as soon as it is available.
Notes:
The One Line Diagram & Three Line Diagram shall include the following information:
3.
Equipment names and/or numerical designations for all circuit breakers, contactors, air switches, transformers,
generators, etc. associated with the generation as required by the Company to facilitate switching.
4.
Power Transformers – name or designation, nominal kVA, nominal primary, secondary, tertiary voltages, vector diagram
showing winding connections, tap setting and transformer impedance. A copy of the transformer nameplate and test
report can be substituted.
5.
Station Service Transformers – Designate phase(s) connected to and estimated kVA load.
6.
Instrument Transformers – Voltage and current, phase connections.
7.
Surge Arresters/Gas Tubes/Metal Oxide Varistors/Avalanche Diode/Spill Gaps/Surge Capacitors, etc. – Type and
Ratings.
8.
Capacitor Banks – kVAR rating.
9.
Disconnect Switches – Indicate status normally open with a (N.O.) and whether manual or motor operated. Include
switch voltage, continuous and interrupting ratings.
10. Circuit Breakers and/or Contactors – Interrupting rating, continuous rating, operating times.
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
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TP-0002
Rev. 3
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Appendix E
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11. Generators(s) – Include nameplate , test report, type, connection, kVA, voltage, current, rpm, PF, impedances, time
constants, etc.
12. Point of Interconnection to Connective Power Delivery System and phase identification.
13. Fuses – Manufacturer, type, size, speed, and location.
Elementary Diagrams shall include the following information:
1. Terminal designation of all devices – relay coils and contacts, switches, transducers, etc.
2.
Relay functional designation – per latest ANSI Standard. The same functional designation shall be used on all drawings
showing the relay.
3.
Complete relay type (such as CV-2, SEL321-1, REL-301, IJS51A, etc.)
4.
Switch contact shall be referenced to the switch development if development is shown on a separate drawing.
5.
Switch developments and escutcheons shall be shown on the drawing where the majority of contacts are used. Where
contacts of a switch are used on a separate drawing, that drawing should be referenced adjacent to the contacts in the
switch development. Any contacts not used should be referenced as spare.
6.
All switch contacts are to be shown open with each labeled to indicate the positions in which the contact will be closed.
Explanatory notes defining switch coordination and adjustment where mis-adjustment could result in equipment failure
or safety hazard.
7.
Auxiliary relay contacts shall be referenced to the coil location drawing if coil is shown on a separate drawing. All
contacts of auxiliary relays should be shown and the appropriate drawing referenced adjacent to the respective contacts.
8.
Device auxiliary switches (circuit breakers, contactor) should be referenced to the drawing where they are used.
9.
Any interlocks electromechanical, key, etc., associated with the generation or interconnection substation.
10. Ranges of all timers and setting if dictated by control logic.
11. All target ratings; on dual ratings note the appropriate target tap setting.
12. Complete internal for electromechanical protective relays. Microprocessor type relays may be shown as a “black box”,
but manufacturer’s instruction book number shall be referenced and terminal connections shown.
13. Isolation points (states links, PK-2 and FT-1 blocks), etc., including terminal identification.
14. All circuit elements and components, with device designation, rating and setting where applicable. Coil voltage is shown
only if different from nominal control voltage.
15. Size, type, rating and designation of all fuses.
16. Phase sequence designation as ABC or CBA.
17. Potential transformers – nameplate ratio, polarity marks, rating, primary and secondary connections (see Guidelines for
minimum ratings.)
18. Current transformers (including aux. CT's) – polarity marks, rating, tap ratio and connection.
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
Page 54 of 98
Appendix E
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Generator
&
Generator Step-up Transformer
Data
Impedance data required immediately. Remaining data must be provided prior
to start of Impact Study analysis.
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
Page 55 of 98
Appendix E
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Unit Capability Data
Gross MW Output
GSU MW Losses
Unit Auxiliary Load MW
Station Service Load MW
Net MW Capacity
Net MW Capacity = (Gross MW Output - GSU MW Losses – Unit Auxiliary Load MW – Station
Service Load MW)
ISO/RTO Queue Letter/Position/Unit ID: ______________________________________________________
Primary Fuel Type: _______________________________________________________________________
Maximum Summer (92º F ambient air temp.) Net MW Output: _____________________________________
Maximum Summer (92º F ambient air temp.) Gross MW Output: ___________________________________
Minimum Summer (92º F ambient air temp.) Gross MW Output ____________________________________
Maximum Winter (30º F ambient air temp.) Gross MW Output: ____________________________________
Minimum Winter (30º F ambient air temp.) Gross MW Output: _____________________________________
Gross Reactive Power Capability at Maximum Gross MW Output (Leading and Lagging): _______________
*** Please submit Reactive Capability Curve when available
Individual Unit Auxiliary Load at Maximum Summer MW Output (MW/MVAR):______________________
Individual Unit Auxiliary Load at Minimum Summer MW Output (MW/MVAR): ______________________
Individual Unit Auxiliary Load at Maximum Winter MW Output (MW/MVAR): _______________________
Individual Unit Auxiliary Load at Minimum Winter MW Output (MW/MVAR): _______________________
Station Service Load (MW/MVAR): __________________________________________________________
Please provide any comments on the expected capability of the unit:
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
Page 56 of 98
Appendix E
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Unit Generator Dynamics Data
ISO/RTO Queue Letter/Position/Unit ID: ____________________________________________________
MVA Base (upon which all reactance, resistance and inertia are calculated): _________________________
Nominal Power Factor:___________________________________________________________________
Terminal Voltage (kV): __________________________________________________________________
Unsaturated Reactance (on MVA Base)
Direct Axis Synchronous Reactance, Xd(i _____________________________________________________
Direct Axis Transient Reactance, X’d(i): _____________________________________________________
Direct Axis Sub-transient Reactance, X”d(i): _________________________________________________
Quadrature Axis Synchronous Reactance, Xq(i): _______________________________________________
Quadrature Axis Transient Reactance, X’q(i): _________________________________________________
Quadrature Axis Sub-transient Reactance, X”q(i): _____________________________________________
Stator Leakage Reactance, Xl: _____________________________________________________________
Negative Sequence Reactance, X2(i): _______________________________________________________
Zero Sequence Reactance, X0: _____________________________________________________________
Saturated Sub-transient Reactance, X”d(v) (on MVA Base):______________________________________
Armature Resistance, Ra (on MVA Base):__________________________________________ at _____° C
Time Constants (seconds)
Direct Axis Transient Open Circuit, T’do:_____________________________________________________
Direct Axis Sub-transient Open Circuit, T”do: _________________________________________________
Quadrature Axis Transient Open Circuit, T’qo:_________________________________________________
Quadrature Axis Sub-transient Open Circuit, T”qo: _____________________________________________
Inertia, H (kW-sec/kVA, on KVA Base):_____________________________________________________
Speed Damping, D:______________________________________________________________________
Saturation Values at Per-Unit Voltage [S(1.0), S(1.2)]: __________________________________________
Please submit generator certified test report information when available
IEEE dynamic model parameters:
Governor Model: _______________________________________________________________________
Exciter Model: _________________________________________________________________________
Power System Stabilizer Model: ___________________________________________________________
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
Page 57 of 98
Appendix E
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Generator Step-up Unit (GSU) Transformer Data
ISO/RTO Queue Letter/Position/Unit ID ________________________________________________________
GSU MVA Rating: ____________________________________________________________________ MVA
GSU Positive Sequence Impedance (R+jX, on transformer MVA Base):_________________________ Per Unit
GSU Zero Sequence Impedance (Ro+jXo, on transformer MVA Base): _________________________ Per Unit
GSU MVA Base: ______________________________________________________________________ MVA
GSU Low-side Voltage (kV): ______________________________________________________________KV
GSU High-side Voltage (kV): ______________________________________________________________KV
GSU Windings (Delta/Wye):__________________________________________________________________
GSU High-side No Load Tap Changer (NLTC) Taps: ___________________________________________KV
GSU Low-side No Load Tap Changer (NLTC) Taps:____________________________________________KV
Please submit transformer certified test report information when available
In addition, please indicate whether the transformer is shared with other units.
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
Page 58 of 98
Appendix F
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APPENDIX F
F: 800 kV Major Equipment Specifications
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
Page 59 of 98
Appendix F
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800 kV Equipment Dielectric Withstand Rating
SWW (kV Peak)
Equipment Type
60 Hz 1 minute Dry
Withstand (kV rms)
Closed/Open
BIL 1.2X50 Usec.
(kV peak)
Closed/Open
CWW 1.2X50 Usec.
chopped @ 2Usec.
kV Peak Closed/Open
CWW 1.2X50 Usec.
chopped @ 3Usec.
kV peak Closed/Open
Closed/Open
Wet
Closed/Open
Dry
800 kV Circuit Breaker
960 dry
2050/2250
2640
2360
1425/1550
1700/1870
800 kV Current Transformer
960 dry
2050
2640
2360
1550
1700
800 kV Disconnect Switches
850 kV (10sec. Wet)
2050
-
-
1400 (Closed)
1750 (Open)
800 kV CCVT
-
2425
-
2850
1675
-
765 kV Transformer
883 kV (5 sec)
795 kV (1 hr)
2050
-
2260
1450
1700
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
Page 60 of 98
Appendix F
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TECHNICAL REQUIREMENTS OF 800 KV EQUIPMENT
Equipment Type
Max. kV
Rating
800 KV SF6 Dead
Tank Circuit Breaker
800 kV
Equipment Type
Cont.
Nominal
kV Rating Current
SA Rating
765 kV
3000 A
SA MCOV
Interrupting
Current
Max. Interruting
Time
Minimum
Oper. Temp.
Maximum
Oper. Temp.
Limit switching
Surge level
CT Ratio & Accuracy
CT TRF
50/63 kA
2 Cycles
-350 C
>400 C
<1.9 PU
3000/5 C800 @ 2000/5
OR
2000/5 C800 @1200/5
>2
FOW
Protective
Level @ 20 kA
800 kV Metal Oxide
588 kV RMS 476 kV RMS <1620 kV Crest
Surge Arrester
Max. Switching
Surge Protective
Level @ 2KA
<1200 kV Crest
Maximum
Maximum
Discharge kV
Discharge kV
For 8X20 Usec For 8X20 Usec
3 kA
10 kA
<1240 kV Cres
Maximum
Discharge kV
For 8X20 Usec
20 kA
Maximum
Discharge kV
For 8X20 Usec
40 kA
<1340 kV Crest < 1420 kV Crest <1570 kV Crest
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
Page 61 of 98
Leakage Distance
Inches
> 620 inches
Appendix G
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APPENDIX G
G: AEP Metering Requirements for Transmission Interconnection Facilities
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities or
Changes to Existing Facilities Connected to the AEP West
Transmission System
TP-0002
Rev. 3
Page 62 of 98
Appendix G
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AEP METERING REQUIREMENTS FOR TRANSMISSION
INTERCONNECTION FACILITIES
TABLE OF CONTENTS TABLE OF CONTENTS -..................................................................................................................................................... 63
PURPOSE - ............................................................................................................................................................................ 63
SCOPE - ................................................................................................................................................................................. 63
REFERENCES - .................................................................................................................................................................... 64
REVSION HISTORY ............................................................................................................................................................ 64
METERING PACKAGE ....................................................................................................................................................... 64
General ..............................................................................................................................................................................67
Standard Requirements:.....................................................................................................................................................65
Metering Equipment Maintenance & Testing: ..................................................................................................................65
Current Transformer Specifications: .............................................................................................................................66
Voltage Transformers Specifications: ...............................................................................................................................66
Remote Meter Access and Communications .....................................................................................................................66
Requestor Access to AEP Metering Circuits .....................................................................................................................67
Metering For Mining Facilities With An Isolated Neutral Resister Under MSHA Regulations .......................................67
GENERATOR METERING .................................................................................................................................................. 67
Specific Meter Requirements: ...........................................................................................................................................67
Specific Instrument Transformer Requirements................................................................................................................67
RTU Requirements ............................................................................................................................................................68
METERING RADIAL LOADS ............................................................................................................................................. 68
Specific Meter Requirements ............................................................................................................................................68
BIDIRECTIONAL INTERCONNECTION METERING ..................................................................................................... 69
Specific Meter Requirements ............................................................................................................................................69
RTU Requirements ............................................................................................................................................................69
PURPOSE This document is intended to guide AEP Engineers who are involved in the process of connecting non-AEP customer
facilities to the AEP Transmission grid. This provides Planning Engineers, Project Managers, Asset Management
personnel, Design Teams and Field Services personnel with the minimum requirements for associated revenue metering
systems. These requirements are vital in ensuring accurate metering of energy at the customer delivery point, and provide
for reliable cost-effective service of the metering systems. This document is intended to complement the System Planning
connection criteria. This document addresses the specifics of metering requirements while the Planning Connection Guide
addresses the metering requirements in more general terms.
SCOPE This document addresses not only the general energy metering requirements, but also addresses specific applications and
related issues. However, this does not address the requirements at a schematic level of detail. Design and testing
requirements are addressed for not only metering but also a few schedule coordination and other logistical considerations
between the Interconnection requestor and AEP. This document is only applicable for retail and wholesale customer
connections to the AEP Transmission System
Note: This document has been prepared by, and is the property of, American Electric Power Company, Inc. This document may be changed by AEP.
Users should consult the OASIS site at http://www.aep.com/about/codeofconduct/OASIS/default.asp to determine the latest effective version
STATION STANDARDS
TITLE: AEP METERING REQUIREMENTS FOR TRANSMISSION INTERCONNECTION
FACILITIES
Responsible Engineer:
J.C Park
Copyright 2007
American Electric
Power Company, Inc
Rev.
3
SS-490011
Page 63 of 98
Appendix G
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
REFERENCES There was no legacy AEP or CSW standard that this supercedes. However, the following Transmission Planning
Documents were used as starting points for development, and this standard is compatible and complements these Planning
Guides:
CSW Guidelines for Generation, Transmission and Transmission Electricity End-Users Interconnection
Facilities. March 2000. (updated to American Electric Power West Guidelines, May 2002).
AEP Requirements For Connection of Non-Generation Facilities To The AEP Transmission System. March,
2000
AEP Requirements for Connection of Generation facilities to the AEP Transmission System. May 1999.
AEP “In-Line” Facility Policy and Guideline for Generation and Non-Generation Transmission Customers.
May 2002.
o
o
o
o
Other References Include:
SS-451001 AEP Protection Requirements for Connection to AEP Transmission Grid.
SS-500000 AEP SCADA RTU Requirements at Transmission Interconnection Facilities.
o
o
Standard References Include:
ANSI C12.1: Code for Electricity Metering
ANSI C12.7: Requirements for Watt-Hour Meter Socket
ANSI C12.9: Test Switches for Transformer-Rated Meters
ANSI C12.11: Instrument Transformers for Revenue Metering, 10kV thru 350kV BIL
ANSI C12.10: Electromechanical Watthour Meters
ANSI C12.16: Solid State Electricity Meters
ANSI C12.20: Electricity Meters 0.2 and 0.5 Accuracy Class
ANSI C37.90.1: Surge Withstand Capability (SWC) Test
ANSI/IEEE C57.13: Standard Requirements for Instrument Transformers
o
o
o
o
o
o
o
o
o
REVSION HISTORY
Rev.
Description of Change(s)
By
Date
Approved
0
Original Issue
Dan Recker
1-24-03
DJR
1
Scope section and General section, 3rd bullet (page 3), and
added exemption for AEP-owned Distribution. Clarified
“Freeze Signal” section, pg 4. Added a section for special
requirements for mine facilities (pg 5).
Dan Recker
4-19-03
DJR
2
Customer Meter Access - Option for shared meter data on
meters equipped with hardware security lock
Dan Recker
12-29-03
DJR
3
General Changes
D. Bernert
03-09-07
JS
4
METERING PACKAGE
General
o
All metering quantities shall be measured at or, at AEP’s option, compensated to the Point of Interconnection.
There are a number of technical considerations that influence the viability of compensated metering, and AEP
STATION STANDARDS
TITLE: AEP METERING REQUIREMENTS FOR
TRANSMISSION INTERCONNECTION FACILITIES
SS-490011
Page 64 of 98
Appendix G
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
Transmission Protection & Measurements Asset Engineering group shall be consulted before offering this option
to the customer.
o
All reasonable costs associated with the initial installation of the metering package or any recurring operation &
maintenance charges including changes to and/or upgrades to the metering equipment, shall be borne by the
requestor, unless this requirement is superceded by regulatory or contractual requirements
o
This standard applies to all new non-AEP facilities. Existing facilities and like kind replacements of existing
facilities are exempt from these standards and are covered by the existing agreements. However, any
modification, addition or upgrade to facilities and equipment that are necessary to physically and electrically
interconnect to the AEP Transmission system shall require that associated revenue metering systems be reviewed
and brought into compliance with the most recent version of AEP Transmission metering standards.
o
At least (N-1) metering elements will be used to measure all real and reactive power crossing the metering point,
where N is the number of wires in service including the ground wire.
Standard Requirements:
The revenue quality metering package (consisting of instrument transformers, meters, sockets, and test switches)
shall be installed, calibrated, and tested (at Requestor’s expense) in accordance with the latest approved version of
(but not limited to) the Standard Documents listed below:
ANSI C12.1:
“Code for Electricity Metering”
ANSI C12.7:
“Requirements for Watt-Hour Meter Socket”
ANSI C12.9:
“Test Switches for Transformer-Rated Meters”
ANSI C12.11: “Instrument Transformers for Revenue Metering, 10kV thru 350kV BIL”
ANSI C12.10: “Electromechanical Watthour Meters”
ANSI C12.16: “Solid State Electricity Meters”
ANSI C12.20: “Electricity Meters 0.2 and 0.5 Accuracy Class”
ANSI C37.90.1: “Surge Withstand Capability (SWC) Test”
ANSI/IEEE C57.13: “Standard Requirements for Instrument Transformers”
To the extent that the above requirement conflict with the manuals, standards or guidelines of the applicable
Reliability Council regarding interchange metering and transactions, the manuals, standards and guidelines of such
Reliability Council shall control.
AEP shall provide functional specifications and design for the revenue metering at the Requestor’s facility. The
criteria for these functional specifications shall be based on existing AEP measurements practices and standards.
AEP reserves the right to specify the type and manufacturer for all associated revenue metering equipment
including the instrument transformers.
Metering Equipment Maintenance & Testing:
o
Unless otherwise specified, the Revenue Meters shall be inspected and tested in accordance with latest
applicable ANSI Standards upon installation, and at least once every year thereafter. If the requestor
requires additional testing other than the normal test cycle, and the meter is found to be within the
established tolerances, this additional testing shall be performed at the requester’s expense.
o
The accuracy of the Revenue Metering package shall be maintained at three tenths of one percent (0.3%)
accuracy or better, and the meter test shall require the use of a meter standard with accuracy traceable to
the National Institute of Standards and Technology (NIST).
o
If Revenue Metering equipment fails to function, the energy registration shall be determined from the
best available data. This shall include backup metering, check metering, or historical metering data.
STATION STANDARDS
TITLE: AEP METERING REQUIREMENTS FOR
TRANSMISSION INTERCONNECTION FACILITIES
SS-490011
Page 65 of 98
Appendix G
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
o
Instrument Transformers shall be inspected and maintained based on existing AEP Station practices and
standards.
o
The Party that owns the metering equipment shall maintain records that demonstrate compliance with all
meter tests and maintenance conducted in accordance with Good Utility Practice for the life of the
Interconnection Point. The other Party shall have reasonable access to the records.
Current Transformer Specifications:
o
Current transformers shall meet or exceed an accuracy class of 0.3% (as defined in IEEE C57.13).
o
Current transformers shall comply with the minimum BIL rating as specified in standards IEEE C57.13
and ANSI C12.11. In addition, dielectric withstand levels shall meet AEP’s current standard.
o
The mechanical and thermal short time current ratings of the current transformer shall exceed or
withstand the available fault current.
o
The connected CT secondary burden of the current transformer shall not exceed the CT nameplate burden
rating.
o
Optical CT’s shall not be used on AEP Transmission revenue metering applications, where the equipment
is owned or serviced by AEP. If installed by the requestor, Optical CT’s shall be tested at a minimum test
frequency of five years.
o
Interconnections with two or more interconnecting circuits shall be metered independently with
independent CT’s. Under no circumstances shall CT secondary circuits be connected in parallel.
Voltage Transformers Specifications:
o
Voltage transformers shall meet or exceed an accuracy class of 0.3% (as defined in IEEE C57.13).
o
A 115VAC nominal secondary winding of the Voltage Transformer shall be exclusively used for the
Revenue Meters.
o
The VT connected secondary burden of the voltage transformer shall not exceed the VT nameplate
burden rating.
o
Optical VT’s shall not be used on AEP Transmission revenue metering applications, where the equipment
is owned or serviced by AEP. Coupling Capacitor Voltage Transformers may be used only in
installations where a ferroresonance problem is indicated. If installed by the requestor, Optical VT’s and
CCVT’s shall be tested at minimum test frequency of five years.
o
Voltage Transformers shall comply with the minimum BIL rating as specified in standards IEEE C57.13
and ANSI C12.11. In addition, the dielectric withstand levels shall meet AEP’s most recent standard.
Remote Meter Access and Communications:
o Communications – Upon request by AEP, the requestor shall provide the appropriate communication for
electronic remote interrogation of meters and metering devices as specified by the appropriate AEP
parties, in a manner that is compatible with AEP data systems.
o Remote Terminal Unit (RTU) – Prior to the interconnection of the requestor’s facilities to the AEP
Transmission system, an RTU or equivalent device acceptable to AEP, the requestor, and appropriate
parties shall be installed. At the requestor’s expense, the RTU shall provide continuous energy and real
time quantity measurements to the appropriate parties designated by AEP. The communication
STATION STANDARDS
TITLE: AEP METERING REQUIREMENTS FOR
TRANSMISSION INTERCONNECTION FACILITIES
SS-490011
Page 66 of 98
Appendix G
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
o
requirements shall be specified by AEP. See SS-500000 AEP SCADA Requirements at Transmission
Interconnection Facilities for more specific requirements.
Freeze Signals – Revenue meters shall provide energy pulse accumulators (bi-directional, if required) or
energy counters to the RTU (or equivalent device). The energy counters or pulse accumulator data shall
be frozen based on upon the AEP RTU configuration. The accumulator freeze signal shall be
synchronized to Universal Coordinated Time within +/- 2 seconds.
Requestor Access to AEP Metering Circuits:
o Requester access to AEP metering circuits is permitted under the terms and conditions of the most recent
version of the AEP Measurements Bulletin #31.
Metering For Mining Facilities With An Isolated Neutral Resister Under MSHA Regulations:
This document is not intended to address the detailed special requirements of this rare application. Please refer
to AEP Measurements Bulletin 33 for the special AEP requirements of this application. AEP Meter Services
maintains this special bulletin.
GENERATOR METERING
Specific Meter Requirements:
Revenue Meters shall meet all requirements outlined under “METERING PACKAGE” with the following
specific requirements:
o
Primary and Backup energy meters shall be installed on each Transmission Interconnection circuit with
the Generating facility.
o
The Revenue energy metering package shall be maintained at 0.3% accuracy or better over the entire CT
secondary current range, including full generator output and, if applicable, the nominal back-feed
auxiliary power.
o
If, at any test of metering equipment, an inaccuracy shall be disclosed exceeding the ANSI specification
of two percent (2%), the account between the Parties for service theretofore delivered shall be adjusted to
correct for the inaccuracy disclosed over the shorter of the following two periods: (1) for the 30-day
period immediately preceding the day of the test, or (2) for the period that such inaccuracy may be
determined to have existed.
o
Revenue energy meters shall be programmable and capable of measuring, recording, and displaying bidirectional, four-quadrant, kWh and kVARh energy quantities. The meter(s) shall be capable of storing
these quantities as 4 independent 15-minute interval channels for a minimum of 45 days.
o
Power/energy flow from AEP to the Requestor will be designated as “Out” or “Delivered” kWh. “Out”
kWh is considered positive and “In” or “Received” kWh is considered negative. The same conventions
will be observed for reactive energy/power.
o
At a minimum, revenue energy meters shall be capable of displaying the following instantaneous
quantities: Bi-directional kW, Bi-directional kVAR, Primary Voltage (each phase), and Primary Current
(each phase).
o
Revenue energy meters shall have at least one RS-485/232 selectable port and (1) Ethernet port
addressable by AEP’s RTU and capable of providing bi-directional kWh and kVARh energy counters and
all of the above instantaneous values in either DNP 3.0 or Modbus standard protocols. The energy meter
package shall also have an option available to provide hard-wired KYZ energy pulse contacts for each of
the bi-directional kWh and kVARh energy quantities measured, and analog transducers for the kW and
STATION STANDARDS
TITLE: AEP METERING REQUIREMENTS FOR
TRANSMISSION INTERCONNECTION FACILITIES
SS-490011
Page 67 of 98
Appendix G
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
kVAR instantaneous quantities measured. All of the kWh, kVARh, kW, and kVAR multipliers shall be
scaled to sufficiently to resolve full generator output and minimum back-feed of auxiliary power.
o
Revenue energy meters shall be equipped with an internal modem for remote interrogation.
Specific Instrument Transformer Requirements
Current transformers shall meet all requirements outlined under “METERING PACKAGE” with the following
specific requirements:
o
Unless otherwise specified, the current transformers shall be located at the defined point of delivery on
the high side of the Generator Step Up Transformer (GSU) or Reserve Auxiliary Transformer.
o
If applicable, current transformer ratio and accuracy range shall be specified to account for the extended
range of current for measuring maximum generation and nominal auxiliary back-feed, while maintaining
0.3% accuracy or better across the entire range. The secondary burden rating of the CT shall be specified
to meet all the standard burdens of B0.1 through B1.8. Wide Range/Extended Accuracy current
transformers shall be used to meet these requirements. The continuous Thermal Rating factor (RF) of the
CT’s shall be a minimum of 2.0
o
Where practical, individual freestanding combination units shall be specified for generation
interconnection metering. These units shall meet the same electrical, accuracy, and mechanical
specifications as required for the individual revenue class CT’s and VT’s.
RTU Requirements
The Remote Terminal Unit (RTU) shall meet all requirements outlined under “METERING PACKAGE” with
the following requirements: See SS-500000 AEP SCADA Requirements at Transmission Interconnection
Facilities for more specific requirements.
o
The AEP Remote Terminal Unit (RTU) (provided at requestor’s expense) shall have at least five
communication ports, (4) RS-232 ports, and (1) Ethernet port, capable of communicating simultaneous
Modbus, DNP 3.0, or other protocols as specified by AEP. See SS-500000 AEP SCADA Requirements
at Transmission Interconnection Facilities for more specific requirements.
o
Requestor shall provide real time status of station switching equipment (i.e., circuit breakers, motor
operated air break switches, etc.) and real time analog measurements of individual generator kW and
kVAR output to the AEP RTU as serial data . The communication protocol of this data shall be specified
by AEP. See SS-500000 AEP SCADA Requirements at Transmission Interconnection Facilities for
more specific requirements.
METERING RADIAL LOADS
Specific Meter Requirements
Revenue Meters shall meet all requirements outlined under “METERING PACKAGE” with the following
specific requirements:
o
Revenue Meters shall be programmable and capable of measuring, recording, and displaying kWh, and
bi-directional KVarh energy quantities. The meter(s) shall be capable of storing these quantities as 15minute interval data for a minimum of 45 days.
o
For multiple load centers where the aggregate of all measured energy quantities of the connected facility
is required, totalization shall be performed by AEP Load Research and the independent energy meter
STATION STANDARDS
TITLE: AEP METERING REQUIREMENTS FOR
TRANSMISSION INTERCONNECTION FACILITIES
SS-490011
Page 68 of 98
Appendix G
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
recorders will be synchronized with a satellite GPS clock, which shall be provided by the requestor.
o
The Revenue Meter(s) shall also have the option to provide form C (K-Y-Z) dry contact outputs
representing the measured energy quantities.
o
Revenue meters shall have the capability for programmable transformer and line loss compensation. All
displayed, recorded, and output energy quantities will represent the compensated quantities.
o
Revenue Meters shall be equipped with internal modem for remote interrogation. In addition, the revenue
meter shall be equipped with an RS-232 or optical port for local interrogation.
o
The Revenue Meters will be tested periodically as defined in the service agreement and the test results
will be available to all involved parties.
BIDIRECTIONAL INTERCONNECTION METERING
Specific Meter Requirements
Revenue Meters shall meet all requirements outlined under “METERING PACKAGE” with the following
additional requirements:
o
Primary and Backup energy meters shall be installed on each Transmission Interconnecting circuit with
Interconnection facilities.
o
Revenue Meters shall be programmable and capable of independently measuring, recording, and
displaying bi-directional kWh, and KVARh energy quantities. The meter(s) shall be capable of storing
these quantities as 15-minute interval data for a minimum of 45 days.
o
Power/energy flow from AEP to the Requestor will be designated as “Out” or “Delivered” kWh. “Out”
kWh is considered positive and “In” or “Received” kWh is considered negative. The same conventions
will be observed for reactive energy/power.
o
If the Metering location is different than the contractual point of Interconnection, losses shall be
compensation to the contractual point of Interconnection.
o
For a Requester with two or more Interconnections (e.g., two lines) with AEP, metering shall be installed
at each independent Interconnection point.
o
Suitable telemetry equipment shall be installed at the metering point to provide real-time (Bi-directional
kW, kVar) data to AEP and to other participating parties designated by AEP.
o
All real time quantities will originate from common metering equipment. Real time quantities will be 0.2
% or better accuracy.
If, at any test of metering equipment, an inaccuracy of shall be disclosed exceeding the ANSI
specification of two percent (2%), the account between the Parties for service theretofore delivered shall
be adjusted to correct for the inaccuracy disclosed over the shorter of the following two periods: (1) for
the 30-day period immediately preceding the day of the test, or (2) for the period that such inaccuracy
may be determined to have existed. If the agreed upon Interconnection agreement between AEP and the
requestor differs then the above criteria, the Interconnection Agreement will take precedence.
RTU Requirements
The Remote Terminal Unit (RTU) shall meet all requirements outlined under “Metering Package” with the
following requirements: See SS-500000 AEP SCADA Requirements at Transmission Interconnection
Facilities for more specific requirements.
o
STATION STANDARDS
TITLE: AEP METERING REQUIREMENTS FOR
TRANSMISSION INTERCONNECTION FACILITIES
SS-490011
Page 69 of 98
Appendix G
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
o
The AEP Remote Terminal Unit (RTU) (provided at requestor’s expense) shall have at least five
communication ports, (4) RS-232 ports, and (1) Ethernet port, capable of communicating simultaneous
Modbus, DNP 3.0, or other protocols as specified by AEP. See SS-500000 AEP SCADA Requirements
at Transmission Interconnection Facilities for more specific requirements.
o Requestor shall provide real time status of station switching equipment (i.e., circuit breakers, motor
operated air break switches, etc.) and real time analog measurements of individual generator kW and
kVAR output to the AEP RTU as serial data . The communication protocol of this data shall be specified
by AEP. See SS-500000 AEP SCADA Requirements at Transmission Interconnection Facilities for
more specific requirements.
STATION STANDARDS
TITLE: AEP METERING REQUIREMENTS FOR
TRANSMISSION INTERCONNECTION FACILITIES
SS-490011
Page 70 of 98
Appendix H
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
APPENDIX H
H: AEP SCADA RTU Requirements at Transmission Interconnection Facilities
TRANSMISSION PLANNING GUIDELINE
TITLE: Requirements for Connection of New Facilities or Changes
to Existing Facilities Connected to the AEP West Transmission
System
TP-0002
Rev. 3
Page 71 of 98
Appendix H
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
AEP SCADA RTU Requirements at Transmission Interconnection Facilities
1.0 Table of Contents
1.0 Table of Contents ............................................................................................................................................................. 72
2.0 Purpose:............................................................................................................................................................................ 72
3.0 Scope:............................................................................................................................................................................... 72
4.0 References: ....................................................................................................................................................................... 73
5.0 Revision History............................................................................................................................................................... 73
6.0 Definition of Terms Used in this Document .................................................................................................................... 73
7.0 RTU Requirements at Transmission Interconnection Facilities owned and operated by AEP......................................... 73
7.1 Data Requirements.................................................................................................................................................. 73
7.1.1 Interconnection-Specific Data from Revenue Metering............................................................................. 73
7.1.2 Other Interconnection-Specific Data .......................................................................................................... 74
7.2 Supervisory Control Requirements......................................................................................................................... 74
7.3 Communication Requirements................................................................................................................................ 74
7.4 Data and Control Verification................................................................................................................................. 74
7.5 Functional Verification ........................................................................................................................................... 74
7.6 Cost Requirements.................................................................................................................................................. 74
8.0 RTU Requirements at Transmission Interconnection Facilities not owned or operated by AEP ..................................... 74
8.1 Data Requirements.................................................................................................................................................. 74
8.1.1 Interconnection-Specific Data from Revenue Metering............................................................................. 74
8.1.2 Other Interconnection-Specific Data .......................................................................................................... 75
8.2 Supervisory Control Requirements......................................................................................................................... 75
8.3 Communication Requirements................................................................................................................................ 75
8.4 Data and Control Verification................................................................................................................................. 75
8.5 Functional Verification ........................................................................................................................................... 75
8.6 Cost Requirements.................................................................................................................................................. 75
9.0 RTU Requirements at Generation Facilities Connected to the AEP Transmission Grid.................................................. 75
9.1 Data Requirements.................................................................................................................................................. 75
9.1.1 Generation-Specific Analog Data............................................................................................................... 75
9.1.2 Generation-Specific Digital (Status) Inputs ............................................................................................... 76
9.2 Supervisory Control Requirements......................................................................................................................... 76
9.3 Communication Requirements................................................................................................................................ 76
9.4 Data Verification..................................................................................................................................................... 77
9.5 Functional Verification ........................................................................................................................................... 77
9.6 Cost Requirements.................................................................................................................................................. 77
2.0 Purpose:
This document serves as a guideline for AEP’s Planning Engineers, Project Managers, Asset Engineers, Design Teams, and
Field Support personnel, who are assigned to projects involving non-AEP Transmission customers connecting to the AEP
Transmission grid. This document is intended to be used as a complement the System Planning connection criteria.
3.0 Scope:
This document may be employed as a general guideline for the SCADA/RTU requirements for new interconnectionspecific applications involving the AEP Transmission Grid. AEP’s internal station standards (SS) documents shall be used
for the actual engineering and design. Requirements by the regional operators (ERCOT, SPP, or PJM) shall take
precedence, where applicable in this document.
Note: This document has been prepared by, and is the property of, American Electric Power Company, Inc. This document may be changed by AEP.
Users should consult the OASIS site at http://www.aep.com/about/codeofconduct/OASIS/default.asp to determine the latest effective version
AEP SCADA RTU Requirement at Transmission Interconnection Facilities
Responsible Engineer:
Dennis R. Jones
Rev.
1
SS-500000
Page 72 of 98
Appendix H
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
4.0 References
The following is a list of documents from (PMAE) Protection and Measurements Asset Engineering, which are intended to
be used as a compliment to the System Planning connection criteria:
SS-490011 AEP Metering Requirements for Transmission Interconnection Facilities
SS-451001 AEP Protection Requirements for Connection to AEP Transmission Grid
SS-500000 AEP SCADA RTU Requirements at Transmission Interconnection Facilities (This Document)
5.0 Revision History
Rev.
Description of Change(s)
By
Date
0
Initial Release
D.R Jones
04/19/07
1
Added one status point to required Generation data
point list (Section 9.1.2)
D.R Jones
05/18/07
Approved
JS
2
3
4
6.0 Definition of Terms Used in this Document
AEP = AEP Transmission
Transmission Interconnection Facility = Physical location (substation) of Interconnection Revenue Metering
Generation Facility = Generator or Generating Plant connected to AEP Transmission Grid
7.0 RTU Requirements at Transmission Interconnection Facilities owned and operated by AEP
A Transmission-Specific Supervisory Control and Data Acquisition (SCADA) remote terminal unit (RTU), specified by
AEP, shall be installed at all new Transmission Interconnection facilities that are owned and operated by AEP. This
Transmission-Specific RTU shall be procured, engineered, installed, commissioned, and maintained by AEP or its
authorized agents. See “Transmission Interconnection Station” in Figure 1.
7.1 Data Requirements
Data sent to the AEP SCADA Master from the transmission-specific RTU shall include interconnection-specific
data from the interconnection revenue metering (see SS-490011). In addition, the non-AEP interconnect
company may request a communication port from AEP’s transmission-specific RTU to obtain interconnectionspecific data. Interconnection-specific data shall include the following quantities for each interconnecting power
line:
7.1.1 Interconnection-Specific Data from Revenue Metering
1) MWh “Out” (Out = delivered from AEP to non-AEP company)
2) MWh “In” (In = received from non-AEP company to AEP)
3) MVARh “Out”
4) MVARh “In”
5) MW +/- (plus = instantaneous MW from AEP to non-AEP company)
(minus = instantaneous MW from non-AEP company to AEP)
6) MVAR +/7) Instantaneous per phase Voltages (pertaining to each Interconnection Circuit)
8) Instantaneous per phase Currents (pertaining to each Interconnection Circuit)
STATION MAINTENANCE GUIDELINES
TITLE: AEP SCADA RTU Requirements at Transmission
Interconnection Facilities
Rev.
1
SS-500000
Page 73 of 98
Appendix H
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
The MWh, MVARh, MW, and MVAR units may be displayed in terms of kWh, kVARh, kW, and
kVAR at the energy meter. Refer to SS-490011 for more information on Interconnection Metering
Requirements.
7.1.2 Other Interconnection-Specific Data
1) Breaker Status Digital Inputs (pertaining to each Interconnecting Power Line)
2) Alarm Digital Inputs (pertaining to each Interconnecting Power Line and related equipment)
7.2 Supervisory Control Requirements
Control Points, as specified by AEP, from the AEP SCADA RTU shall be provided to the AEP SCADA Master.
The non-AEP interconnect company is not permitted to perform controls through the AEP SCADA RTU.
7.3 Communication Requirements
A communications circuit including associated interface equipment, as specified by AEP, shall be provided from
the RTU to the AEP SCADA Master. An additional communication circuit may be provided by the non-AEP
interconnect company to provide interconnection-specific data (as described in Section 7.1) to their SCADA
Master at their cost.
7.4 Data and Control Verification
An RTU Point Assignment (RPA) shall be compiled by AEP (or its authorized agent). All data and control
points mapped to the SCADA Master(s) shall be completely checked out and verified.
7.5 Functional Verification
Prior to placing the interconnecting power line(s) in service to the requesting interconnecting company, the RTU
shall be fully operational with all data and control points fully commissioned as described in Section 7.4 above.
7.6 Cost Requirements
All costs for the procurement, engineering, installation, and commissioning of the RTU and its communication
circuit shall be paid by the company requesting the transmission interconnection. In addition, any on-going
monthly charges for the required communication circuit shall be paid by the company requesting the
transmission interconnection.
8.0 RTU Requirements at Transmission Interconnection Facilities not owned or operated by
AEP
A Supervisory Control and Data Acquisition (SCADA) remote terminal unit (RTU) shall be installed at all new non-AEP
transmission facilities, which are connected to the AEP Transmission Grid. AEP may require that AEP’s standard RTU (as
described in Section 7.0) be installed at the non-AEP Transmission facility. This transmission-specific RTU shall be
procured, engineered, installed, commissioned, and maintained by AEP or its authorized agents. As an alternative to
installing AEP’s standard RTU, AEP may request to have a modem installed and connected to a communication port from
the non-AEP RTU. See Transmission Interconnection Station in Figure 1.0.
8.1 Data Requirements
If AEP’s standard RTU is installed, RTU inputs shall be supplied from an IED (Intelligent Electronic Device)
via an AEP-approved interface device, unless otherwise specified as hardwired. The communication method
between the RTU and IED(s) shall be Ethernet or RS-485 serial. The communication protocol shall be DNP 3.0.
Data provided from the transmission-specific RTU (or com port of the non-AEP RTU) to the AEP SCADA
Master) shall include the following interconnection-specific data for each interconnecting power line:
8.1.1 Interconnection-Specific Data from Revenue Metering
1) MWh “Out” (Out = delivered from AEP to non-AEP company)
2) MWh “In” (In = received from non-AEP company to AEP)
3) MVARh “Out”
STATION MAINTENANCE GUIDELINES
TITLE: AEP SCADA RTU Requirements at Transmission
Interconnection Facilities
Rev.
1
SS-500000
Page 74 of 98
Appendix H
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
4) MVARh “In”
5) MW +/- (plus = instantaneous MW from AEP to non-AEP company)
(minus = instantaneous MW from non-AEP company to AEP)
6) MVAR +/7) Instantaneous per phase Voltages (pertaining to each Interconnection Circuit)
8) Instantaneous per phase Currents (pertaining to each Interconnection Circuit)
The MWh, MVARh, MW, and MVAR units may be displayed in terms of kWh, kVARh, kW, and
kVAR at the energy meter. Refer to SS-490011 for more information on Interconnection Metering
Requirements.
8.1.2 Other Interconnection-Specific Data
1) Breaker Status Digital Inputs (pertaining to each Interconnecting Power Line)
2) Alarm Digital Inputs (pertaining to each Interconnection Power Line and related equipment)
8.2 Supervisory Control Requirements
If the AEP SCADA Master is to have supervisory control capability at the non-AEP interconnection facility,
then the standard AEP SCADA RTU shall be installed at the facility for controls and data to the AEP SCADA
Master. AEP shall not perform controls through non-AEP SCADA RTUs.
8.3 Communication Requirements
A communications circuit including associated interface equipment, as specified by AEP, shall be provided from
the RTU to the AEP SCADA Master.
8.4 Data and Control Verification
An RTU Point Assignment (RPA) shall be compiled for this transmission-specific RTU and posted by AEP (or
its authorized agent). All data and control points mapped to the SCADA Master(s) shall be completely checked
out and verified.
8.5 Functional Verification
Prior to placing the interconnecting power line(s) in service to the requesting interconnecting company, the RTU
shall be fully operational with all data and control points fully commissioned as described in Section 8.4 above.
8.6 Cost Requirements
All costs for the procurement, engineering, installation, and commissioning of the RTU and its communication
circuit shall be paid by the company requesting the transmission interconnection. In addition, any on-going
monthly charges for the required communication circuit shall be paid by the company requesting the
transmission interconnection.
9.0 RTU Requirements Generation Facilities Connected to the AEP Transmission Grid
In addition to the transmission-specific RTU at the Transmission facility, a generation-specific RTU (specified by AEP)
may be required at interconnected generation facilities to provide generation-specific Supervisory Control and Data
Acquisition (SCADA) to the AEP SCADA Master. This generation-specific RTU shall be procured, engineered, installed,
commissioned, and maintained by AEP or its authorized agents. See Generation Facility in Figure 1.
9.1 Data Requirements
Except where specified at hardwired, RTU inputs shall be supplied from an IED (Intelligent Electronic Device)
via an AEP-approved interface device. The communication method between the RTU and IED(s) shall be
Ethernet or RS-485 serial. The communication protocol shall be DNP 3.0. Data sent to the AEP SCADA
Master from the generation-specific RTU shall include the following:
9.1.1 Generation-Specific Analog Data
1) Gross MW + (instantaneous MW for each Generator)
STATION MAINTENANCE GUIDELINES
TITLE: AEP SCADA RTU Requirements at Transmission
Interconnection Facilities
Rev.
1
SS-500000
Page 75 of 98
Appendix H
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
2) Gross MVAR +/- (instantaneous MVAR for each Generator)
3) Aux MW +/- (instantaneous MW for each AUX transformer)
4) Aux MVAR +/- (instantaneous MVAR for each AUX transformer)
5) Frequency (Hz)
6) Voltage (instantaneous Voltage for each phase at transmission interconnection point)
7) Voltage (instantaneous Voltage for each phase at each winding of each transformer)
8) Current (instantaneous Current for each phase for each winding of each transformer)
9) MW+/- (instantaneous MW for each winding of each transformer)
10) MVAR +/- (instantaneous MVAR for each winding of each transformer)
9.1.2 Generation-Specific Digital (Status) Inputs
1) Generator Breaker Status (Hardwired for each breaker where Supervisory Control is also required)
2) Circuit Switcher / line switch status (“a” and “b” contacts)
3) Transformer high-side Breaker Status (Hardwired for each breaker where Supervisory Control is
required)
4) Transformer high-side motor operated switch status (“a” and “b” contacts)
5) AUX Breaker Status
6) Capacitor Bank Breaker/Switch Status
7) Supervisory Cutoff (Hardwired for each breaker where Supervisory Control is required).
8) Breaker Failure Lockout Status (Hardwired for each breaker where Supervisory Control is
required)
9) Breaker Critical Alarm (Required for each breaker where Trip control is required, combine critical
alarms for each breaker).
10) Transformer Critical Alarm (Group Critical Alarms for each transformer)
11) Transformer Primary Lockout Relay Operated
12) Transformer Primary Lockout Relay Failure
13) Transformer Backup Lockout Relay Operated
14) Transformer Backup Lockout Relay Failure
15) IED Failure (required for each IED that provides data to RTU)
16) IED Communications Failure (required for each IED that provides data to RTU)
17) Battery Charger Trouble (Required for battery which powers the RTU)
18) Battery Charger AC Power Failure (Required for the battery which powers the RTU)
19) Smoke Alarm (Required for the structure housing the RTU)
20) Fire or High Temperature Alarm (Required for the structure housing the RTU)
21) Generator Automatic Voltage Regulator (AVR) Status
22) Fault Recorder Trouble Alarm
23) Transmission line lockout relay operated
24) Transmission line lockout relay failure
9.2 Supervisory Control Requirements
A Trip control shall be provided for one or more of the generation or transmission line breakers to provide the
AEP SCADA Master with the ability to trip all generation units during system emergencies. This trip control
shall be hardwired and have a corresponding Digital (Status) Input that is also hardwired (see Section 9.1 for
Status Inputs).
9.3 Communication Requirements
A communications circuit including associated interface equipment, as specified by AEP, shall be provided from
the generation-specific RTU to the AEP SCADA Master.
STATION MAINTENANCE GUIDELINES
TITLE: AEP SCADA RTU Requirements at Transmission
Interconnection Facilities
Rev.
1
SS-500000
Page 76 of 98
Appendix H
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
9.4 Data Verification
An RTU Point Assignment (RPA) for the generation-specific RTU shall be compiled by AEP (or its authorized
agent). All data and control points mapped to the SCADA Master(s) shall be completely checked out and
verified.
9.5 Functional Verification
Prior to placing the interconnecting power line(s) in service to the requesting interconnecting company, the
generation-specific RTU shall be fully operational with all data and control points fully commissioned as
described in Section 9.4 above.
9.6 Cost Requirements
All costs for the procurement, engineering, installation, and commissioning of the generation-specific RTU and
its communication circuit shall be paid by the company requesting the transmission interconnection. In addition,
any on-going monthly charges for the required communication circuit to this generation-specific RTU shall be
paid by the company requesting the transmission interconnection.
STATION MAINTENANCE GUIDELINES
TITLE: AEP SCADA RTU Requirements at Transmission
Interconnection Facilities
Rev.
1
SS-500000
Page 77 of 98
Appendix H
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
To AEP Transmission Grid
138 kV
Communications
To AEP
SCADA Master
Bus
Com 2
Com 1
Transmission
Interconnection
Station
Breaker
H1
Meter
Meter
Primary
(1)
Back-Up
(11)
Communications
To non-AEP
SCADA Master
(if required)
115 v
H2/3
H4/5
H6
Direct Connection
Generation
Facility
138 kV
Communications
To AEP
SCADA Master
GT-1
GT-2
Com 2
Com 1
Communications
To Generation Company
(if required)
Figure 1
Transmission-Specific and Generation-Specific RTU’s
For AEP Transmission Interconnections
STATION MAINTENANCE GUIDELINES
TITLE: AEP SCADA RTU Requirements at Transmission
Interconnection Facilities
Rev.
1
SS-500000
Page 78 of 98
Appendix I
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
APPENDIX I
I: AEP Protection Requirements for Connecting To the AEP Transmission Grid
TRANSMISSION PLANNING GUIDELINE
TITLE: Requirements for Connection of New Facilities
or Changes to Existing Facilities Connected to the AEP
West Transmission System
TP-0002
Rev. 3
Page 79 of 98
Appendix I
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
AEP PROTECTION REQUIREMENTS FOR CONNECTING TO THE
AEP TRANSMISSION GRID
TABLE OF CONTENTS –
TABLE OF CONTENTS - .................................................................................................................................................... 80
PURPOSE - ........................................................................................................................................................................... 81
SCOPE - ................................................................................................................................................................................ 81
REFERENCES - ................................................................................................................................................................... 81
REVSION HISTORY ............................................................................................................................................................ 81
General - ................................................................................................................................................................................ 82
Requester Protection - .......................................................................................................................................................... 82
Grounding of Requester’s Facilities - ................................................................................................................................... 82
Transmission Line Protection Pilot Channel Requirements - ................................................................................................ 82
AEP Terminals at Remote End of The Requester’s Station - ................................................................................................ 83
Customer Tapped Stations And Fused Transformer Applications - ...................................................................................... 83
Tapped Stations Added To Lines With Carrier - ................................................................................................................... 83
Automatic Underfrequency Load Shedding - ........................................................................................................................ 83
SCADA Considerations - ...................................................................................................................................................... 83
Remote Relay Access............................................................................................................................................................. 84
Environmental Considerations - ............................................................................................................................................ 84
Fault Disturbance Monitoring - ............................................................................................................................................. 84
Power Supply For Protective Relaying - ................................................................................................................................ 84
High Speed Ground Switch Applications (HSGS) - ............................................................................................................. 84
Testing and Maintenance - .................................................................................................................................................... 84
Voice Communications - ....................................................................................................................................................... 85
Requester With Facilities That Are Generation Source - ...................................................................................................... 86
Ground Current Sources - ................................................................................................................................................. 86
Automatic Reclosing - ...................................................................................................................................................... 86
Frequency Protection ....................................................................................................................................................... 86
SUPPLEMENTAL NOTES AND CLARIFICATIONS FOR AEP INTERNAL USE ......................................................... 86
Direct Transfer Trip (DTT) Requirements - ..................................................................................................................... 87
Timeline For Coordinating Area Protection Study and Development Of Relay Settings For Customer Projects ............ 87
Note: This document has been prepared by, and is the property of, American Electric Power Company, Inc. This document may be changed by AEP.
Users should consult the OASIS site at http://www.aep.com/about/codeofconduct/OASIS/default.asp to determine the latest effective version
STATION STANDARDS
TITLE: AEP Protection Requirements For Connecting To The AEP Transmission Grid
Responsible Engineer:
Hank Miller
Copyright 2007
American Electric
Power Company, Inc
Rev.
3
SS-451001
Page 80 of 98
Appendix I
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
PURPOSE –
This document is intended to guide AEP Engineers who are involved in the process of connecting any facilities to the
AEP Transmission grid. This serves as minimum requirements for both internal AEP and external customer facilities.
This provides Planning Engineers, Project Managers, Asset Management personnel, Design Teams and Field Services
personnel with the minimum Protection and Control (P&C) requirements. These requirements are vital in establishing a
reliable connection to the AEP grid in a manner that is cost-effective, and compatible with the rest of the AEP
transmission grid. This document is intended to complement the System Planning connection criteria. This document
addresses the specifics of protection requirements while the Planning Connection Guide addresses protection in very
general terms.
SCOPE –
This document addresses not only the general protection and control requirements, but also addresses specific protection
and control applications and protection requirements for more specific circumstances. However, this does not address
the requirements at a schematic or relay model level. Design and testing requirements are addressed for not only
protection but also data systems, Supervisory Control and Data Acquisition (SCADA), telecommunications, and
reclosing. It also addresses a few schedule coordination and other logistical considerations between the customer and
AEP.
REFERENCES –
There was no legacy AEP or CSW P&C standard that this supercedes. However, the following Transmission Planning
Documents were used as starting points for development, and this standard is compatible and complements these
Planning Guides:
o
CSW Guidelines for Generation, Transmission and Transmission Electricity End-Users Interconnection
Facilities. March 2000.
o
AEP Requirements For Connection of Non-Generation Facilities To The AEP Transmission System. March,
2000
o
AEP Requirements for Connection of Generation facilities to the AEP Transmission System. May, 1999.
o
AEP “In-Line” Facility Policy and Guideline for Generation and Non-Generation Transmission Customers.
May 2002.
Other References Include:
o
Station Standard #SS 420410. P&C Testing and Maintenance.
o
AEP Metering Requirements for Transmission Interconnection Facilities SS# 490011
o
AEP SCADA RTU Requirements at Transmission Interconnection Facilities SS# 500000
o
Substation Data Repository System SS# 501103
o
ANSI/IEEE Standard C37.90
REVSION HISTORYRev.
Description of Change(s)
By
Date
Approved
0
Original Issue
Dan Recker
1-24-03
DJR
1
Page 3, SCADA CONSIDERATION section, added
clarifying sentence. PURPOSE, pg 1, clarified.
Dan Recker
4-19-03
DJR
STATION STANDARDS
TITLE: AEP Protection Requirements For Connecting
To The AEP Transmission Grid
SS-451001
Page 81 of 98
Appendix I
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
2
Page 3, added a section that explicitly addresses fuses
Dan Recker
9-10-05
DJR
3
Revised the Frequency Protection section on page 6,
made some small editing changes, and added some
new references.
Henry Miller
3-25-07
JS
4
General–
AEP will provide functional specifications and relay settings for all protective relays at the Requester’s facility that have
a potential impact on the reliability of the AEP transmission system. The criteria for these functional specifications and
settings will be based on existing AEP protection practices and standards. AEP reserves the right to specify the type and
manufacturer for these protective relays to ensure compatibility with existing relays. The specific recommendations and
requirements for protection will be made by AEP based on the individual station location, voltage and configuration.
AEP further reserves the right to modify relay settings when deemed necessary to avoid safety hazards to utility
personnel or the public and to prevent any disturbance, impairment, or interference with AEP’s ability to serve other
customers. All relays specified for the protection of the AEP system, including time delay and auxiliary relays, shall be
approved by AEP, and shall be utility grade devices. Utility grade relays are defined as follows:
o Meet ANSI/IEEE Standard C37.90, “Relays and Relay Systems Associated with Electric Power
Apparatus”
o Have relay test facilities to allow testing without unwiring or disassembling the relay.
o Have appropriate test plugs/switches for testing the operation of the relay.
o Have targets to indicate relay operation.
Requester Protection –
It is the Requester’s responsibility to assure protection, coordination and equipment adequacy within their facility for
conditions including but not limited to:
o Single phasing of supply
o System faults
o Equipment failures
o Deviations from nominal voltage or frequency
o Lightning and switching surges
o Harmonic voltages
o Negative sequence voltages
o Separation from AEP supply
o Synchronizing generation.
Grounding of Requester’s Facilities –
Requester’s protection and control equipment interfacing with AEP protection and controls must be solidly tied to a
common ground. Grounding of equipment must be consistent with IEEE standards.
Transmission Line Protection Pilot Channel Requirements –
High speed transmission line protection and transfer trip functionality requires pilot channel communication links
between the line terminals. The types of pilot channel communication links can include, but are not limited to the
following: Power line carrier, fiber optic cable, radio, and pilot wire. Critical and sensitive portions of the transmission
grid commonly require transfer trip and/or dual high-speed protection, which requires two separate pilot channel links.
The specific recommendations and requirements for these pilot channels will be based on AEP protection practices and
standards. AEP reserves the right to determine when transfer trip is necessary and to select either single or dual highspeed systems and to specify the type and characteristics of the pilot channel to ensure compatibility with the existing
protection.
STATION STANDARDS
TITLE: AEP Protection Requirements For Connecting
To The AEP Transmission Grid
SS-451001
Page 82 of 98
Appendix I
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Always check for the latest revision prior to use.
AEP Terminals at Remote End of The Requester’s Station –
The protection at all ends of a transmission line must be compatible and function as a system. Thus, the installation or
modification of transmission line protection at the Requester’s station may require the upgrade or replacement of
protection at the remote terminals. Such upgrades or replacements at the remote terminals shall be considered within the
project scope for the requester’s station, and funded, accordingly.
Customer Tapped Stations And Fused Transformer Applications –
For public safety and the protection of the grid infrastructure, AEP sets line protection to clear line faults as fast as
possible, and thus, does not intentionally delay this line protection to coordinate with down line tapped fuses. Similarly,
AEP has an obligation to have a fuse connection policy that ensures reliable zone-to-zone relay coordination for the
reliability of all AEP customers connected to the grid. To achieve this, transformer fuses are generally not applied on
tapped lines with pilot protection or lines with short circuit fault current above 15kA (to stay under the short circuit fault
limit of most fuses). To achieve this, fuses are not permitted at transmission line voltages of 138kv and above. At
subtransmission voltages, fuses sized to carry more than 15 MVA transformer load rarely coordinate with AEP line
protection, and therefore, are not permitted. For all other potential fuse application requests, AEP will recommend a fuse
size that will coordinate with the existing line protection, if one can be found. It will be the connecting customer's
responsibility to coordinate and operate below this specified fuse limit. If AEP cannot find a fuse that reliably
coordinates with the existing line protection, or if the recommended fuse size is unacceptable to the customer, then the
customer will need to upgrade the transformer high-side interrupting device to a circuit switcher or breaker. AEP
reserves the right to require the customer to replace the fuse with an upgraded interruption device if the fuse performance
is found to adversely impact grid reliability or if grid and line protection conditions change.
Tapped Stations Added To Lines With Carrier –
Carrier signals can be degraded by tapped load and load that is electrically located at the ¼ wavelength of the carrier
frequency on the line. It is not practical to accurately predict in advance whether newly tapped load will create this
condition. A wave trap installed at the new tap is one way of insuring that newly tapped load will not adversely affect
the line carrier signal. It is the responsibility of the delivery point requester to insure that the new delivery point does
not degrade the power line carrier signal(s) or protection scheme on the tapped line. This may require a wave trap to be
installed on the appropriate phase at the tap to the requester’s station and tuned to the carrier frequency. The requester
can choose to install this wave trap in advance or determine at the point of energizing the newly tapped station whether a
wave trap is necessary. If the requester elects not to install the wave trap in advance, and it is later determined that the
tapped installation has degraded the carrier signal(s), then the delivery point will be de-energized until such time that the
tapped station has been modified to eliminate the source of carrier signal degradation.
Automatic Underfrequency Load Shedding –
AEP may require an automatic load shedding scheme on connected load to comply with North American Electric
Reliability Corporation (NERC) standards or other system stability considerations. AEP is obligated to have an
automatic underfrequency load shedding plan in effect, which meets these NERC standards. Connecting parties without
an automatic underfrequency load shedding plan for meeting these NERC requirements may need to install
underfrequency relaying and have a load shedding program in place as required by AEP. The amount of load to be shed
and frequency setpoints will be specified by AEP as set forth in the underfrequency load shedding compliance
requirements of NERC and the applicable Regional Reliability Organization.
SCADA Considerations –
Supervisory Control and Data Acquisition (SCADA) is an essential tool for reliably controlling and monitoring the
transmission grid. There are a number of factors and considerations in determining the specific SCADA requirements at
a given site. Generally, if the connecting facility has a circuit breaker(s) or other automatically operated switching
device(s) in the bulk power transfer path, then AEP generally requires the connecting party to provide SCADA. AEP
reserves the right to specify the type, manufacturer and characteristics of the SCADA equipment used at facilities
STATION STANDARDS
TITLE: AEP Protection Requirements For Connecting
To The AEP Transmission Grid
SS-451001
Page 83 of 98
Appendix I
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
connected to the AEP transmission grid. The specifications and requirements for this SCADA equipment and sitespecific application will be based on AEP design practices and standards. Alarm inputs into the SCADA system shall be
categorized as either “emergency” alarms requiring immediate response, or “maintenance” alarms requiring next-day
response.
Remote Relay Access
o
o
Tap Connected Facilities - Remote relay access is not normally required at tap connected facilities.
Loop or Network Connected Facilities - All digital relays which have the capability of recording
system disturbance information and are used for protection of AEP transmission facilities shall be
provided with the equipment necessary to allow AEP to remotely retrieve this data via Requester
supplied commercial telecommunications link. The type of communications circuit will need to meet
all NERC Critical Infrastructure Protection (CIP).
Environmental Considerations –
The performance and durability of modern protective relays is impacted by their surrounding environment, and can be
especially impacted by extreme high and low ambient temperatures. Consequently, protection that can potentially
impact the AEP transmission grid must be installed in a climate controlled environment consistent with AEP
specifications.
Fault Disturbance Monitoring –
AEP is responsible to meet NERC fault disturbance monitoring requirements, and AEP reserves the right to specify the
type, model and specifications of the fault monitoring equipment necessary to meet all applicable regulatory
requirements.
Power Supply For Protective Relaying –
All protection systems, disturbance monitors and SCADA system at the requester’s facilities that can potentially impact
the AEP transmission grid must have a source of power independent from the AC system or immune to AC system loss
or disturbances (e.g. DC battery and charger) to assure proper operation of the protection schemes. Loss of this source
shall require the immediate disconnection from the AEP transmission grid until the source is restored.
High Speed Ground Switch Applications (HSGS) –
HSGS’s shall not be used as the primary means of fault clearing. Under certain rare conditions, it may be permissible to
apply HSGSs as a backup means of fault clearing provided that the requester pays for any resulting damages or liabilities
created by the operation of the HSGS. Approval of HSGS applications on requester’s facilities connected to the AEP
transmission grid will be at the discretion and approval of AEP after factoring all of the reliability and operational
considerations.
Testing and Maintanance –
All Requester owned equipment up to and including the first protective fault interrupting device is to be maintained to
AEP standards. Maintenance specifications are detailed in the Station Standard #SS 420410, P&C Testing and
Maintenance, and Station Standard #SS 420310, Circuit Breaker Maintenance.
The Requester shall have an organization approved by AEP test and maintain all devices and control schemes provided
by the Requester for the protection of the AEP system. Included in the testing and maintenance will be any initial set
STATION STANDARDS
TITLE: AEP Protection Requirements For Connecting
To The AEP Transmission Grid
SS-451001
Page 84 of 98
Appendix I
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
up, calibration, and check out of the required protective devices, periodic routine testing maintenance, and any testing
and maintenance caused by a Requester or AEP change to the protective devices.
If the Requester’s testing and maintenance program is not performed in accordance with AEP’s “Guidelines for
Transmission and Distribution Maintenance and Frequencies,” AEP reserves the right to inspect, test, or maintain the
protective devices required for the protection of the AEP System.
All costs associated with the testing and maintenance of devices provided by the Requester for the protection of the
AEP system, including costs incurred by AEP in performing any necessary tests or inspections, shall be the
responsibility of the Requester.
AEP reserves the right to approve the testing and maintenance practices of a Requester when the End-User’s system is
operated as a network with the AEP transmission system.
Voice Communications –
At AEP’s request, the Requester shall provide a dedicated voice communication circuit to the AEP System Control
Center. Such a dedicated voice communication circuit would originate from the Requester’s office staffed 24 hours a
day and would be typically required for connected transmission facilities that significantly affect the AEP transmission
network capacity and operations.
STATION STANDARDS
TITLE: AEP Protection Requirements For Connecting
To The AEP Transmission Grid
SS-451001
Page 85 of 98
Appendix I
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
Requester With Facilities That Are Generation Source –
Generating sources present some unique considerations as follows:
Ground Current Sources –
Protective relays must be able sense line-to-ground faults. Ground fault protection is predicated upon having an
adequately grounded transmission grid with suitable zero sequence ground fault current levels. This requires that
transformers connected to the transmission grid be specified and connected in a manner that provides for adequate
zero sequence ground fault current. AEP reserves the right to specify the zero sequence impedance requirements
that must be met by the transformer and its connection to the transmission grid, and reserves the right to require a
delta tertiary winding on the transformer for providing a compatible configuration.
Automatic Reclosing –
Automatic reclosing is normally applied to transmission and distribution circuits. When the AEP source breakers
trip and isolate the requester’s facilities, the requester shall insure that their generator is disconnected from AEP
prior to automatic reclosure by AEP. Automatic reclosing out-of-phase with the requester’s generator may cause
damage to the requester’s equipment. The requester is solely responsible for the protection of their equipment from
automatic reclosing by AEP.
Frequency Protection –
Generator underfrequency protection must be set to coordinate with the settings of the NERC-mandated automatic
load shedding protection. Thus, the generator underfrequency protection must not operate before the system
underfrequency load shed protection has a chance to respond. The requester is responsible for setting their generator
underfrequency protection to comply with the local Area Reliability council’s requirements for generator
underfrequency protection. As an example, the requirements for the ECAR Area Council are shown in the table
below:
FREQUENCY
TIME BEFORE GENERATION UNIT ISOLATION
60.0 to 59.5 Hz
Unlimited
59.5 to 58.5 Hz
30.0 minutes before unit isolation can be expected
58.5 to 58.2 Hz
7.0 minutes before unit isolation can be expected
Below 58.2 Hz
Unit isolation without time delay can be expected.
The frequency values shown above change from time to time and it is responsibility of the Requestor to modify their
generator underfrequesncy setting when notified of changes in order to stay compliant with the current requirements
of NERC and the applicable Regional Reliability Organization.
STATION STANDARDS
TITLE: AEP Protection Requirements For Connecting
To The AEP Transmission Grid
SS-451001
Page 86 of 98
Appendix I
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
SUPPLEMENTAL NOTES AND CLARIFICATIONS FOR AEP INTERNAL USE
Direct Transfer Trip (DTT) Requirements –
DTT is commonly installed to protect against breaker failure scenarios. In general, if the failure of a customer’s breaker
places the AEP transmission grid at risk (e.g. risk of voltage collapse) or if it presents a significant risk to other
customers connected to the AEP transmission grid, then the requester should be required to install direct transfer trip to
protect against this breaker failure scenario. Transmission Planning has the responsibility for determining this risk. This
DTT requirement does not consider the protection of the requester’s own facilities, and it is assumed that the requester
will specify DTT if they find it necessary to protect their facilities.
Timeline For Coordinating Area Protection Study and Development Of Relay Settings For
Customer Projects –
Before AEP enters into a commitment with a customer on a plan of service, it is essential that a detailed area protection
study be performed to ensure that the plan of service can be adequately protected. To ensure that the project scope is
complete relative to the protection, the preliminary area protection study needs to occur (performed by Protection
Measurements Asset Engineering - PMAE) before requesting a detailed estimate from Station Projects Engineering.
Once the project is scoped, the design team engineers the project. Once the T-Line engineering and station schematics
are complete, and the Requester defines their setting requirements, and provides any necessary data for their facilities,
then final settings can be developed for the rest of the impacted AEP system. These settings may take 2-6 weeks to
develop depending on the size and complexity of the project. The settings are then issued to the field approximately two
to four weeks prior to the service date.
STATION STANDARDS
TITLE: AEP Protection Requirements For Connecting
To The AEP Transmission Grid
SS-451001
Page 87 of 98
Appendix J
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
APPENDIX J
J: Transmission Switching Guidelines for In-line Stations
TRANSMISSION PLANNING GUIDELINES
TITLE: Requirements for Connection of New Facilities
or Changes to Existing Facilities Connected to the AEP
West Transmission System
TP-0002
Rev. 3
Page 88 of 98
Appendix J
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Always check for the latest revision prior to use.
AEP Guide for
Application of In-Line Manual Air Break
Switches, Automatic Air Break Switches or
Circuit Breakers
September 2005
Note: This document has been prepared by, and is the property of, American Electric Power Company, Inc. , is intended for AEP use only, is
not to be used for any purpose detrimental to AEP’s interest, and is not to be furnished to, or copied or reproduced by, parties not affiliated
with the AEP system without the express written consent of AEP, and is to be returned upon request.
TRANSMISSION PLANNING GUIDELINE
TITLE: AEP Guide for the Application of In-Line Manual Switches, Automatic Switches or Circuit Breakers
Responsible Engineer:
M. Ahmed
Copyright 2007
American Electric Power
Company, Inc
Rev.
0
TP-000004
Page 89 of 98
Appendix J
CAUTION: Printed copies of this document are uncontrolled and may be obsolete.
Always check for the latest revision prior to use.
REVISION HISTORY
Rev.
0
Description of Change(s)
Original Issue
Prepared or
Revised By
M.Ahmed
Date
Approved
September
2005
B.M.
Pasternack
1
2
3
4
TRANSMISSION PLANNING GUIDELINE
TITLE: AEP Guide for the Application of In-Line Manual
Switches, Automatic Switches or Circuit Breakers
Rev.
0
TP-000004
Page 90 of 98
Appendix J
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Always check for the latest revision prior to use.
Table Of Contents
1.0
2.0
3.0
4.0
5.0
6.0
7.0
8.0
8.1
8.2
8.3
Introduction………………………………………………………………………………………………….............90
Background………………………………………………………………………………………………………….92
Scope………………………………………………………………………………………………………………...92
Objectives…………………………………………………………………………………………….……………...93
References………………………………………………………………………………….......................................93
In-Line Tap Connection Definition…………………………………………………………. ……………………...93
In-Line Switching Facilities Definition and Requirements……………………………….….……………………...94
Selection of In-Line Switching Device(s) to Connect LOAD to the Transmission System… ……………………...95
Basic Service Plan ..................................................................................................................................................95
Justification for In-Line MOAB Switches..............................................................................................................95
Justification for In-Line Circuit Breaker (CB)........................................................................................................96
Appendix A
TRANSMISSION PLANNING GUIDELINE
TITLE: AEP Guide for the Application of In-Line Manual
Switches, Automatic Switches or Circuit Breakers
Rev.
0
TP-000004
Page 91 of 98
Appendix J
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Always check for the latest revision prior to use.
1.0
INTRODUCTION
American Electric Power Service Corporation, acting on behalf of the eleven American Electric Power
(AEP) Electric Operating Companies1, has prepared this document which outlines the methodology for
determining the minimum switching/sectionalizing equipment requirements for an in-line connection
of all transmission load facilities to the AEP Transmission System below 200 kV.
In-line
connection refers to the connection of load at a point located in series with the through path of a
transmission circuit. Transmission Load (load)2 facilities refer to the facilities that need to be
installed to establish connections between AEP and the radially served loads (direct connections to
End-Users or the delivery points of wholesale customers such as munis, co-ops or AEP Distribution),
by tapping the transmission circuit and installing sectionalizing facilities.
2.0
BACKGROUND
In the present electric utility environment characterized by deregulation, open access to the
transmission network, wholesale and retail competition, etc., there is a wide recognition that electric
system reliability, safety and quality of service are to be maintained. Maintaining reliability, safety
and quality of service in this changing environment presents additional challenges to those involved in
the planning and operation of electric systems.
As a result of this environment, there are an increasing number of requests to connect to and use the
AEP Transmission System. Each request is reviewed by AEP to identify the impacts and necessary
system improvements on the AEP Transmission System. The purpose of this document is to ensure
that comparable treatment is given to all users, and that reliability, safety, and quality of service are
maintained.
3.0
SCOPE
This report conveys information about the in-line switching requirements for connection to parties
seeking connection of load to the AEP Transmission System. The methodology and the requirements
are applicable to all radially connected load including AEP Distribution load as well as the load served
by wholesale and retail customers, connecting to AEP transmission lines below 200 kV. These
requirements are not a substitute for specific Service Agreements between AEP and non-affiliated
entities connecting to the AEP Transmission System. The requirements described in this document do
not apply to generation facility connections, interconnection tie lines with other Utilities, or connection
of a radial customer directly to an AEP Transmission Station. Furthermore, a separate document3
covers the operational and technical requirements at the point of connection.
1
Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky
Power Company, Kingsport Power Company, Ohio Power Company, Public Service Company of Oklahoma, Southwestern
Electric Power Company, Texas Central Company, Texas North Company and Wheeling Power Company.
2
Transmission Load is hereinafter referred to as load.
3
Connection Guidelines “Requirements for Connection of New Facilities or Changes to Existing Facilities Connected to
the AEP East Transmission System”.
TRANSMISSION PLANNING GUIDELINE
TITLE: AEP Guide for the Application of In-Line Manual
Switches, Automatic Switches or Circuit Breakers
Rev.
0
TP-000004
Page 92 of 98
Appendix J
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Always check for the latest revision prior to use.
This report contains guidelines for the minimum switching requirements that should be adhered to
when connecting load facilities to AEP’s Transmission System operated below 200 kV. Connections
to the Transmission System above 200 kV are not included and will be addressed on a case-by-case
basis. Reliability, power quality and operational concerns may impose the need to install additional
“in-line” sectionalizing facilities. The need for appropriate switching requirements can only be
evaluated once certain details of a proposed load facility are made known and studies have been
conducted.
The requirements for initial facility connection also apply to any upgrades, additions, enhancements,
or changes of any kind to an existing connected facility.
This document does not cover transmission service or deliverability. The load connection entities
requiring transmission service should refer to the AEP, PJM, ERCOT, and SPP Open Access
Transmission Tariffs.
4.0
OBJECTIVES
AEP, in its role as a transmission owner, has prepared this document to accomplish the following
objectives:
1.
Inform those entities that request electric service to their loads from the AEP Transmission
System of the need for minimum in-line sectionalizing facilities required at the point of
connection.
2.
Maintain adequate system reliability, safety of personnel/equipment, and quality of service.
3.
Ensure comparability in the requirements imposed upon the various load-serving entities,
including individual customers, seeking to connect to the AEP Transmission System for
service.
4.
Facilitate uniform and compatible minimum sectionalizing equipment requirements and
installation practices to promote and/or maintain a basic level of service reliability.
5.0
REFERENCES
The following documents were used to develop these guidelines, which are compatible with and
complement the reference Guides:
6.0
1.
Requirements for Connection of Non-Generation Facilities to the AEP East Transmission
System. (TP-000001; June 2004)
2.
Motor Operated Air Break Switches. (SS-476010; January 2003)
TAP CONNECTION DEFINITION
Any connection to the AEP Transmission System that results in only the associated load passing
through the connecting facilities under all conditions is considered a tap connection. If the
TRANSMISSION PLANNING GUIDELINE
TITLE: AEP Guide for the Application of In-Line Manual
Switches, Automatic Switches or Circuit Breakers
Rev.
0
TP-000004
Page 93 of 98
Appendix J
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Requesting Entity's4 facilities are located near an existing AEP station, the connection from the AEP
Transmission System may be provided by constructing a radial line from the AEP station to the
Requester's facility. If the Requester's facilities are located near an existing AEP transmission line,
the connection from the AEP Transmission System may be provided by tapping the nearby AEP line
and constructing a radial line to the Requester's facility. This arrangement will provide a radial
connection to the Requester but will also result incidentally in creating in-line facilities at the tap
point. The in-line facilities will not only carry customer load but also the transmission system power
flows.
For facilities below 200 kV, Figures 1 and 2 in the Appendix B illustrate typical radial line supply
configurations and some of the basic connection requirements to the AEP transmission line. Other
possibilities exist depending on the particular situation.
Typically, a manual three-phase air break line switch (switch) on either side of the tap location point is
the minimum requirement. The tap line switch can disconnect the load connection without deenergizing the supply line. Additionally, in-line air break switches allow for manually sectionalizing
the line without supply interruption to the load. Automatic motor operated mechanisms (with or
without supervisory control) can be added to in-line switches, when justified, to minimize the time
required for restoration following a failure of the AEP supply line.
7.0 IN-LINE SWITCHING FACILITIES DEFINITION AND REQUIREMENTS
Any connection to the AEP Transmission System would require, as a minimum, line disconnect
switches, commonly referred to as “Group Operated Air Break (GOAB)” switches. These switches
are manually operated and not part of the overall system automatic relaying sectionalizing scheme.
The only exceptions to this minimum requirement where switches are not required are the following
situations: 1) the connection established to serve load is temporary and is required for a period less
than a year; 2) the topography of the tap location is such that the tap is not accessible by road, in which
case the in-line switches could be placed elsewhere in a more accessible location, or 3) the tapped inline connection is required temporarily under emergency system conditions.
A GOAB switch that is equipped with automatic line sectionalizing capability is commonly referred as
a “Motor Operated Air Break (MOAB)” switch. A MOAB is simply an air break switch whose
blade moves by action of a motor. If the motor turns in one direction, the blade moves to an open
position. If the motor turns in the opposite direction, the blade moves to a closed position. MOABs
are frequently used on the AEP System below 200 kV as “automatic sectionalizing devices” in
addition to their application in the isolation of transformers or lines emanating from the station busses.
In some applications, MOABs can be operated remotely by supervisory control. The MOAB is more
expensive to install than a GOAB because of the added cost of relaying, supervisory control capability
and automatic sectionalizing capability.
The Circuit Breaker (CB), as used in a Transmission System, is a device that provides high-speed
automatic sectionalizing capability to make or break circuits under normal conditions. A CB can also
4
Requesting Entity – can refer to either a Transmission Interconnection Requester or a Transmission Load
Connection Requester and hereinafter is referred to as a Requester.
TRANSMISSION PLANNING GUIDELINE
TITLE: AEP Guide for the Application of In-Line Manual
Switches, Automatic Switches or Circuit Breakers
Rev.
0
TP-000004
Page 94 of 98
Appendix J
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interrupt fault currents. This automatic sectionalizing by CBs is done with as little disturbance as
possible to the system. In general, a CB is inherently more reliable than a MOAB in protecting against
false trips, particularly for intermittent line faults. The cost to install a CB is greater than that of a
MOAB or GOAB due its more sophisticated sectionalizing capability and function, as well as greater
land requirements.
8.0
Selection of In-Line Switching Device(s) to Connect LOAD to the Transmission System
Any plan to serve load from an AEP Transmission Line involves establishing a connection point. At
the connection point, appropriate facilities are required to provide adequate service to the new
customer while maintaining service reliability and quality to other customers served from the subject
transmission line. Several factors are considered in determining the in-line facilities requirement over
and above the minimum requirement of GOAB switches. The factors that influence the decision
include: 1) the magnitude of load affected; 2) the exposure to fault conditions, i.e. the line length
between two automatic sectionalizing devices; and 3) the probability of an outage of the transmission
line involved.
8.1 Basic Service Plan
AEP requires that any new plan to connect load to the transmission system typically must
include in-line GOAB switches at the point of connection. This is referred to as the “Basic
Plan” and therefore, is the minimum accepted switching arrangement for new connections. The
only exceptions to this minimum requirement are described in Section 7.0.
8.2 Justification for In-Line MOAB Switches
Installation of in-line MOAB switches at the point where load is connected to a transmission
system improves the automatic line sectionalizing capability of the circuit and reliability of
service to the load from a permanent forced outage standpoint. In order to determine if the
MOAB switches are required, a factor referred to as the ‘Forced Outage Index (FOI)” is
calculated and compared with the established threshold index values.
The FOI is defined as:
FOI = Load (Lf) X Miles of Exposure X Permanent Forced Outage Rate (Pf)—see explanation
below
Where;
Lf = Peak load (in MW) that is directly jeopardized by the forced outage of the subject line
Miles of Exposure = Number of miles between two existing automatic sectionalizing devices
(MOABs or CBs) plus new tap line length
Pf = Permanent forced outage rate of the subject line (outages/year/mile). If the outage rate of
the subject line is not available, a five year system average outage rate can be used.
TRANSMISSION PLANNING GUIDELINE
TITLE: AEP Guide for the Application of In-Line Manual
Switches, Automatic Switches or Circuit Breakers
Rev.
0
TP-000004
Page 95 of 98
Appendix J
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Always check for the latest revision prior to use.
Install MOAB switches if the “FOI” is equal to or greater than six (6.0)
The following exceptions apply:
1.
The P&C guidelines (“Motor Operated Air Break Switches SS-476010”) require that
the number of in-line MOAB switches be limited to three (3) on a transmission
circuit. If more than three automatic sectionalizing devices are required, installation
of a CB is to be considered.
2.
AEP reserves the right to disallow application of in-line MOABs where the existing
protection system is incompatible with in-line MOABs.
3.
AEP reserves the right to request the installation of a Circuit Switcher instead of a
MOAB if deemed necessary when considering P&C, physical location, or the critical
nature of the transmission line.
8.3 Justification for In-Line Circuit Breaker (CB)
Installation of an in-line CB(s) at the point where load is connected to a transmission system
improves the automatic line sectionalizing capability of the circuit and reliability of service to
the load, both from the momentary as well as from the permanent forced outage standpoints. In
order to determine if a CB is required, a factor referred to as the ‘Momentary Permanent Outage
Index (MPOI)” is calculated and compared with the established threshold index value.
The MPOI is defined as:
MPOI = Load (Lf) X Miles of Exposure X Forced Outage Rate {Permanent Forced Outage Rate
(Pf) + Momentary Forced Outage Rate (Mf)}
Where;
Lf = Peak load (MW) directly jeopardized by the forced outage of the subject line
Miles of Exposure = Number of miles between two existing automatic sectionalizing CBs, plus
new tap line length
Forced Outage Rate (outages/year/mile) = Permanent forced outage rate (Pf) + Momentary
forced outage rate (Mf)
Install a CB if the “MPOI” is equal to or greater than two hundred (200).
TRANSMISSION PLANNING GUIDELINE
TITLE: AEP Guide for the Application of In-Line Manual
Switches, Automatic Switches or Circuit Breakers
Rev.
0
TP-000004
Page 96 of 98
Appendix J
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Always check for the latest revision prior to use.
The following exceptions apply:
1). In situations where the calculated MPOI is less than 200 and power quality is a concern
due to forced momentary outages, installation of a CB can be considered.
2). If the FOI calculation (Section 8.2) indicates a justification for a MOAB installation on a
circuit that already contains three (3) in-line MOAB switches, a CB installation should be
considered.
3). If a circuit is critical for overall system reliability or as an outlet for generation, installation
of a CB should be considered.
TRANSMISSION PLANNING GUIDELINE
TITLE: AEP Guide for the Application of In-Line Manual
Switches, Automatic Switches or Circuit Breakers
Rev.
0
TP-000004
Page 97 of 98
Appendix J
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Always check for the latest revision prior to use.
APPENDIX A
A - Typical In-Line Transmission Tap Supply & Line Looped Supply
Configurations
Typical Transmission Tap Supply Configurations
Figure 1
Radial Line Supply Alternatives - For Facilities below 200 kV Non-Generators
- Connected to an Existing Station
Typical Transmission Line Looped Supply Configurations
Figure 2
Loop Supply Alternatives - For Facilities below 200 kV Non-Generators
- Looped Service
[Note: Figrue 1 and 2 are also included in Appendix B of the main document
(TP-000001) and were therefore removed from this copy of document TP000004]
Note: This document has been prepared by, and is the property of, American Electric Power Company, Inc. , is intended for AEP use only,
is not to be used for any purpose detrimental to AEP’s interest, and is not to be furnished to, or copied or reproduced by, parties not
affiliated with the AEP system without the express written consent of AEP, and is to be returned upon request.
TRANSMISSION PLANNING GUIDELINE
TITLE: AEP Guide for the Application of In-Line Manual Switches, Automatic Switches or Circuit Breakers
Responsible Engineer:
M. Ahmed
Copyright 2007
American Electric Power
Company, Inc
Rev.
0
TP-000004
Page 98 of 98