AEP-NRC-2012-93, Response to NRC Bulletin 2012-01, Design Vulnerability in Electric Power System

Response to NRC Bulletin 2012-01, Design Vulnerability in Electric Power System

ML12312A465
Person / Time
Site:	Cook
Issue date:	10/25/2012
From:	Gebbie J AEP Indiana Michigan Power Co, Indiana Michigan Power Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
AEP-NRC-2012-93, BL-12-001
Download: ML12312A465 (42)

Text

• (JU:A!7(fl* Indiana Michigan Power Cook Nuclear Plant One Cook Place Bridgman, MI 49106 A unit of American Electric Power IndianaMichiganPower.corn October 25, 2012 AEP-NRC-2012-93 10 CFR 50.54(f)

Docket Nos.: 50-315 50-316 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001

Subject:

Donald C. Cook Nuclear Plant Unit 1 and Unit 2 Response to NRC Bulletin 2012-01, Design Vulnerability in Electric Power System

Dear Sir or Madam,

On July 27, 2012, the U. S. Nuclear Regulatory Commission (NRC) issued Bulletin 2012-01, "Design Vulnerability in Electric Power System." The objectives of the bulletin were stated as follows:

" To notify the addressees that the NRC staff is requesting information about the facilities' electric power system designs, in light of the recent operating experience that involved the loss of one of the three phases of the offsite power circuit (single-phase open circuit condition) at Byron Station, Unit 2, to determine if further regulatory action is warranted.

• To require that the addressees comprehensively verify their compliance with the regulatory requirements of General Design Criterion (GDC) 17, "Electric Power Systems," in Appendix A, "General Design Criteria for Nuclear Power Plants," to 10 CFR Part 50 or the applicable principal design criteria in the updated final safety analysis report; and the design criteria for protection systems under 10 CFR 50.55a(h)(2) and 10 CFR 50.55a(h)(3).

• To require that addressees respond to the NRC in writing, in accordance with 10 CFR 50.54(f).

The NRC requested that licensees submit a written response within 90 days of the date of the bulletin. This letter provides Indiana Michigan Power Company's (l&M's) written response for the Donald C. Cook Nuclear Plant (CNP).

The enclosure to this letter provides an affirmation statement. Attachment 1 to this letter provides responses to the specific requests stated in the bulletin. Attachment 2 provides a simplified one-line diagram of CNP electrical distribution system, from offsite power to 4 kilovolt safety related buses. Attachment 3 provides tables supporting the Attachment 1 responses to the specific information requests. Attachment 4 provides protective device schematic figures. Attachment 5 provides a list of abbreviations and acronyms used in Attachments 1 through 4.

U.S. Nuclear Regulatory Commission AEP-NRC-2012-93 Page 2 This letter contains no new or modified regulatory commitments. If there are any questions concerning this letter, please contact Mr. Michael K. Scarpello, Manager, Nuclear Regulatory Affairs, at (269) 466-2649.

Sincerely, Joel P. Gebbie Site Vice President JRW/kmh

Enclosure:

Affirmation.

Attachments: 1. Response to NRC Bulletin 2012-01, Design Vulnerability in Electric Power System.

2. Simplified One-Line Diagram, Offsite Power to 4 kilovolt (kV) Engineered Safety Feature Buses

3. Tables

4. Figures

5. Abbreviations and Acronyms Used in Attachments 1 Through 4 c: C. A. Casto, NRC Region III J. T. King, MPSC S. M. Krawec, AEP Ft. Wayne, w/o enclosures MDEQ - RMD/RPS NRC Resident Inspector T. J. Wengert, NRC Washington, DC

AFFIRMATION I, Joel P. Gebbie, being duly sworn, state that I am Site Vice President of Indiana Michigan Power Company (I&M), that I am authorized to sign and file this request with the Nuclear Regulatory Commission on behalf of I&M, and that the statements made and the matters set forth herein pertaining to I&M are true and correct to the best of my knowledge, information, and belief.

Indiana Michigan Power Company Joel P. Gebbie Site Vice President SWORN TO AND SUBSCRIBED BEFORE ME THIS Z*5 DAY OF C.-,k-'C 2012 My Commission Expires Ito 11-

Attachment I to AEP-NRC-2012-93 Response to NRC Bulletin 2012-01, Design Vulnerability in Electric Power System On July 27, 2012, the U. S. Nuclear Regulatory Commission (NRC) issued Bulletin 2012-01, "Design Vulnerability in Electric Power System." The NRC requested that licensees submit a written response within 90 days of the date of the bulletin. This attachment provides Indiana Michigan Power Company's (l&M's) written response for the Donald C. Cook Nuclear Plant.

I&M's response to Bulletin 2012-01 is structured as shown below, which is similar to the Nuclear Energy Institute template developed for use by nuclear power plant licensees.

Attachment I Response to NRC Bulletin 2012-01, "Design Vulnerability in Electric Power System"

System Description

NRC Request Item 2 and I&M Response NRC Request Item 1.d and I&M Response NRC Request Item 2.a and I&M Response NRC Request Item 2.c and I&M Response System Protection NRC Request Item 1 and I&M Response NRC Request Item l.a and I&M Response NRC Request Item 2.b and I&M Response NRC Request Item 2.d and I&M Response Consequences NRC Request Item 1.b and I&M Response NRC Request Item 1.c and I&M Response NRC Request Item 2.e and I&M Response Simplified One-Line Diagram Offsite Power to 4kV ESF Buses Tables Table 1: - ESF Buses Continuously Powered From Offsite Power Source(s)

Table 2: - ESF Buses Not Continuously Powered From Offsite Power Source(s)

Table 3A-1 through 3B-2: - ESF Buses Major Loads Table 4: - Offsite Power Transformers Table 5A and 5B: - Protective Devices Figures Figure A - Typical RCP UV and UF Relays Figure B - Typical Loss of Voltage and Degraded Voltage Relays Figure C - Typical Differential Relays RATs Figure D - Typical Differential Relays - UATs Figure E - Typical UAT- Generator Overall Differential Relay Figure F - Typical RAT and UAT Ground Overcurrent Relays Figure G - Typical Lead Differential - RATs Figure H - 34.5kV Switchyard Overcurrent Relays, Phase and Ground relays Figure I - Typical EP Overcurrent Relays, Phase and Ground Figure J - Typical EP Bus Overcurrent and Differenial Relays Abbreviations and Acronyms Used in Attachments 1 Through 4 to AEP-NRC-2012-93 Page 1

System Description

NRC Bulletin 2012-01 Items 2, 1d, 2.a, and 2.c request system information and are addressed in this section:

NRC Request Item 2 Briefly describe the operatingconfiguration of the ESF buses (Class 1E for current operatingplants or non-Class IE for passive plants) at power (normal operating condition).

Response to NRC Request Item 2 See Attachment 2 for a simplified one-line diagram showing the off site power sources to the 4160 volt (4 kV) Engineered Safety Feature (ESF) buses. Abbreviations and acronyms are defined in Attachment 5.

As shown in Attachment 2 the onsite alternating current (AC) electric power distribution system for each unit contains four, 4 kV non-safety-related buses designated 1A, 1B, 1C, and 1D for Unit 1 and 2A, 2B, 2C, and 2D for Unit 2. These buses are referred to as the "RCP" buses because they provide power to the reactor coolant pumps. Each of the non-safety-related RCP buses feed a safety related 4 kV ESF bus. These safety-related buses are designated T11A, T11B, T11C, and T1ID for Unit 1 and T21A, T21B, T21C, and T21D for Unit 2. These buses are referred to as the "T" buses. With the main generator on-line, the RCP buses are normally fed from the UATs, which receive power from the main generator. Upon a turbine/reactor trip, the RCP buses are automatically fast transferred from the UATs to the RATs powered by the preferred offsite circuit. If the "T" bus voltage is less than 94 percent of rated voltage for greater than 99 seconds during a non-accident scenario, a fast bus transfer to the offsite source (RATs) takes place. If the degraded voltage condition is not cleared within the following 21 seconds, a dead bus transfer to the EDGs takes place.

The preferred offsite circuit is fed from the 345kV and 765kV switchyards which are normally split between the redundant trains. The 345kV normally supplies Train B via 150MVA, 345kV-34.5kV, Wye-g/Delta, transformer 12-TR-5, and the 765kV switchyard supplies Train A via 12-TR-4, Wye-g/Delta, Auto-transformer 765kV/345kV-34.5kV, with a tertiary rating of 115MVA. The 34.kV power supply from these transformers is further stepped down to 4.16kV level via Delta-Wye, 30MVA, RATs, which are equipped with LTCs. The configuration and ratings for the transformers are shown in Attachment 3, Table 4. In the normal line up, 12-TR-4 feeds Train A of Unit 1 and 2 via RAT101CD and RAT201CD, and 12-TR-5 feeds Train B of Units 1 and 2 via RAT101AB and RAT201AB. The output from the RATs is supplied to the RCP buses which in turn supply the ESF "T" Buses. For example, RAT1 01AB feeds RCP buses 1A and 1 B which further feeds downstream ESF buses T1 1A and T11B respectively. The RATs have automatic LTC with +(-)15% regulation that maintain constant voltage at the 4.16kV buses.

Another offsite source, designated as the alternate offsite source, is supplied by a 69kV circuit, which is manually loaded in the unlikely event that the preferred offsite source and the onsite source (EDGs) become inoperable. This circuit is supplied by 7.5MVA

Attachment 1 to AEP-NRC-2012-93 Page 2 transformer 69/4.16kV, 12-TR-EP-1. The transformer is sized to provide one train of emergency loads and one train of shut down loads.

NRC Request Item 1.d Describe the offsite power transformer(e.g., start-up, reserve, station auxiliary) winding and grounding configurations.

Response to NRC Request Item 1.d See Attachment 3, Table 4 for offsite power transformer winding and grounding configurations.

NRC Request Item 2.a Are the ESF buses powered by offsite power sources? If so, explain what major loads are connected to the buses including theirratings.

Response to NRC Request Item 2.a For at-power (normal operating condition) configurations, ESF buses are not powered by offsite sources. Attachment 3, Table 2, identifies the ESF bus power sources during normal operations. Attachment 3, Table 4, identifies the ESF bus power sources (12-TR-4, 12-TR-5, and the RATs) used during start up and shut down, and following a reactor trip. Attachment 3, Tables 3A-1 and 3A-2, identify the major ESF bus loads energized during normal power

'operations, including their ratings. Since the ESF buses are fed from the RCP buses, the major loads connected to the RCP buses have also been identified (Attachment 3, Table 3B-1 and 3B-2).

NRC Request Item 2.c Confirm that the operating configuration of the ESF buses is consistent with the current licensing basis. Describe any changes in offsite power source alignment to the ESF buses from the originalplant licensing.

Response to NRC Request Item 2.c The normal operating condition configurations have been confirmed to be consistent with the current licensing basis. The following list identifies significant design changes that have been implemented over the life of the plant, along with the approximate time frame.

• In 1978, Transformer 12-TR-5 was added as a backup source to Transformer 12-TR-4 when Unit 2 began operation.

" In 1980, degraded voltage relays were added to the 4 kV buses to protect components from sustained degraded grid voltage as a follow up to an event at Millstone nuclear plant.

to AEP-NRC-2012-93 Page 3

• In 2000, bus-tie breaker "BD" was added on the 34.5kV bus between Transformer 4 and Transformer 5. This change essentially split the 34.5kV bus into two separate buses.

The 34.5kV Bus 1 is fed from transformer 12-TR-5 and the 34.5kV Bus #2 is fed from transformer 12-TR-4. The change also required installation of a new grounding transformer and associated protective relays. The split configuration allowed better flexibility in maintaining adequate voltage at the plant auxiliary loads.

• In 2003-2005, The existing RATs were replaced with LTC transformers to expand offsite power operability over a wider range of offsite voltage.

• In 2007-2008, an NRC backfit order was implemented to change the degraded voltage relays function from "Alarm" only to "Trip" when the ESF buses are powered from the UATs and main generator.

" Degraded voltage protection setpoints have been adjusted several times as necessary to comply with the latest degraded voltage protection schemes.

Note that the GDC listed in 10 CFR 50 Appendix A were published after the CNP construction permits were issued, and GDC 17 was not included in the plant's original licensing basis. The design of the CNP electrical systems is described in the CNP UFSAR, primarily in Chapter 8.

System Protection NRC Bulletin 2012-01 Items 1, 1.a, 2.b, and 2.d request information regarding electrical system protection and are addressed in this section:

NRC Request Item 1 Given the requirements above, describe how the protection scheme for ESF buses (Class 1E for current operatingplants or non-Class IE for passive plants) is designed to detect and automatically respond to a single-phase open circuit condition or high impedance ground fault condition on a credited off-site power circuit or another power sources. Also, include the following information:

Response to NRC Request Item 1 Refer to the response to NRC Request Item 2 for description of the ESF and offsite power supplies.

Consistent with the current licensing basis, existing protective circuitry would separate the ESF buses from a connected failed source due to a loss of voltage or a sustained, balanced degraded grid voltage concurrent with certain design basis accidents. The relay systems were not specifically designed to detect an open single phase of a three phase system.

Since most power cable and bus failures would result in a short circuit rather than an open phase, an open phase failure is not explicitly considered in the CNP design and licensing basis.

Attachment I to AEP-NRC-2012-93 Page 4 The 4.16kV Class 1E "T" buses contain an undervoltage and degraded voltage protection scheme. Each 4.16kV Class 1E bus is normally energized by the main generator via UATs.

If the normal power supply is disconnected at the 4.16 kV Class 1 E bus due to loss of UATs or generator trip, automatic fast transfer to the preferred offsite source (RATs) takes place.

If the normal power supply is lost due to degraded voltage (i.e., 4.16kV Class 1E bus voltage less than 94 percent of rated volts for greater than 99 seconds during a non-accident scenario), a fast bus transfer to offsite source takes place. If the degraded voltage condition is not cleared within the following 21 seconds, a dead bus transfer to the Emergency Diesel Generators takes place.

During normal plant operation the "T" buses are powered from the UAT via the main generator. An open phase on the offsite power supply 345kV or 765kV side would have no effect on the "T' bus voltage. Since the UAT is tied directly to the generator terminals, it would continue to receive three phase voltage on its primary side for as long as the generator remains online. An open phase on the 345kV or 765kV GSU transformer side would most likely trip the main generator on negative sequence or differential and fast bus transfer the 4.16kV buses from the UATs to the RATs.' Therefore, an open phase on the GSU high side while the plant is in normal operation is not of concern.

Additionally, an open phase on the UAT primary side while the isophase bus connections to the main generator and GSU remain intact is not credible due to the isophase bus connection arrangement, which makes it highly unlikely that a phase would open without also shorting to ground and tripping the generator. The UATs and the RATs are physically separated by fire walls (Unit1) or sufficient space (Unit 2) such that there is no common mode failure between them.

The protection scheme at CNP was not designed to detect and automatically respond to a single-phase open circuit condition or high impedance ground fault condition during startup or shutdown when a preferred off-site power circuit is used. A preliminary review has shown that the 4.16kV emergency bus undervoltage (degraded voltage) relay protection would respond to this condition in some instances, specifically during accident conditions, by automatically stripping the bus from degraded source and transferring power to the EDG.

The degraded voltage relays would likely actuate due to the voltage drop caused by loss of phase on the 34.5kV circuit. During an accident condition such as a safety injection, the time delay for degraded voltage relays is 9 seconds, compared to 120 seconds during a non-accident condition. During non-accident conditions, the open phase or high impedance fault may be manifested as other abnormal conditions which may be detected by overload or differential relays, if undervoltage relays do not respond due to the 2-out-of-3 logic. Loss of a phase on the 34.5kv source is more detrimental in terms of voltage unbalance compared to loss of phase on 345kV or 765kV levels.

765kV and 345kV Switchyard - Open Phase Protection An open phase condition in the 765kV or 345kV system would result in a minimal unbalanced voltage on 34.5kV or downstream 4.16kV offsite power source, due to the Wye-g to Delta configuration of the station power transformers 12-TR-4 and 12-TR-5.

Therefore an open phase in the 765kV or 345kV system would not be detected or result in an isolation of offsite power at the 4.16kV Class 1 E buses. An open-phase would result in to AEP-NRC-2012-93 Page 5 other phases carrying the additional load, but due to the oversized transformers this is not a concern.

34.5kV Switchyard (Standby or startup and shutdown source)- Open Phase Protection The 34.5kV yard is Delta connected, with a ground detection via a zig-zag transformer. An open phase condition in the 34.5kV switchyard would result in either loss of voltage or undervoltage on the ESF buses. Although no detailed engineering study is available at this time, preliminary engineering review shows that the degraded voltage relays on some of the phases would drop out, but the 2 out-of-3 logic may or may not actuate.

26kV UATs - Open Phase Protection The connection to 26kV is made up of bolted connections with an isophase bus on the primary side and multiple cable connections on the 4.16kV side which does not result in a credible open phase scenario. A failure of a connection would most likely result in a fault which should be detected and isolated by differential or ground overcurrent relays.

4.16kV System:

The 4.16kV system is made up of multiple bolted connections from the RATs and the UATs and an open-phase is not credible. A failure of a connection would most likely result in a fault which would likely be detected and isolated by differential or ground overcurrent relays.

The 4.16kV ESF trains are provided with degraded voltage and loss of voltage protection. A loss of phase would likely result in actuation of these relays.

High Impedance Faults:

The CNP 345kV and 765kV switchyard is designed with a breaker-and-a-half ring bus configuration with multiple offsite transmission sources normally terminated at the ring bus.

Solid bus work is run from the ring bus to station power transformers 12-TR-4 and 12-TR-5.

The majority of the 34.5kV switchyard is also made up of mainly rigid connections and a failure of a phase to result in a high impedance fault is unlikely. The plant is not currently analyzed for high impedance grounds on the offsite power system and the impact to downstream plant equipment, however the following design features exist which minimize the likelihood or impact of a postulated high impedance ground:

" Based on the ring bus configuration, high impedance grounds on a single phase of an incoming transmission line would not result in discontinuity of voltage on the impacted phase due to voltage support provided by the other lines and station generator when the generator is online and connected to the bus.

• The available fault current at the 345kV ring bus is greater than 20kA and at the 765kv bus over 1OkA when one of the units is on line. This magnitude of fault from the offsite sources ensures any intermittent high resistance ground would self clear or manifest itself into a typical low impedance fault. A high impedance fault just below the relay setpoint may not be sustainable due to the amount of energy going into the fault, e.g. the lowest ground relay setting is 207A (Device 2-51G-T-1,2,3) in Table 5. At this setting the amount of energy is over 4MVA (207A x 19.9kV line-to-neutral). A very high impedance to AEP-NRC-2012-93 Page 6 fault would act more like a single phase load and voltage unbalance should be tolerable to a great extent.

• The bus work from the 765kV and 345kV ring bus to the low side of the 12-TR-4 and 12-TR-5 transformers is outfitted with high speed differential relaying to isolate the faulted circuit.

NRC Request Item l.a The sensitivity of protective devices to detect abnormal operating conditions and the basis for the protective device setpoint(s).

Response to NRC Request Item l.a Consistent with the current CNP licensing basis, existing electrical protective devices are sufficiently sensitive to detect design basis conditions such as a loss of voltage or a degraded voltage, but were not designed to detect a single phase open circuit condition.

Attachment 3, Table 5 identifies the undervoltage protective devices and the basis for the device setpoints.

Existing electrical protective devices are also sufficiently sensitive to detect a ground fault.

Attachment 3, Table 5 lists ground protection/alarms on the ESF buses and the basis for the device setpoints.

The protective devices identified in Attachment 3, Table 5 are summarized as follows.

• All RCP buses have UV protection with a 2-out-of-4 logic (2 relays per bus). Only one of two UV relays is likely to actuate for a loss of a phase on the 34.5kV circuit. The typical arrangement is shown in Attachment 4, Figure A. The UV relay may or may not actuate for a high impedance ground fault, depending on the voltage drop caused by the fault.

• ESF buses T11A (and T11D) in Unit 1 and T21A (and T21D) in Unit 2 have loss of voltage and degraded voltage relays. The relays are arranged to provide a 2-out-of-3 logic. Due to this arrangement, the trip may not actuate for loss of a phase on the 34.5kV circuit. The typical protection arrangement is shown in Attachment 4, Figure B.

The UV relay may or may not actuate for a high impedance ground fault, depending on the voltage drop caused by the fault.

• The differential relays and ground relays on the 34.5kV circuits may or may not actuate depending on the fault impedance. The typical arrangement is shown in Attachment 4, Figure C and Figure 1.

" The differential relays and ground relays on the 26kV circuits may or may not actuate depending on the fault impedance. The typical arrangement is shown in Attachment 4, Figures D, E and F.

" The differential relays and ground relays on the 69kV (EP) circuits may or may not actuate depending on the fault impedance. The typical arrangement is shown in Attachment 4, Figure I and J.

to AEP-NRC-2012-93 Page 7 The EP source is manually loaded if needed and has voltage unbalance protection which automatically separates the offsite source and starts the SDGs. This voltage unbalance relay has a setting of 15% and is part of the SDG control circuitry and not included in Table 5.

NRC Request Item 2.b If the ESF buses are not powered by offsite power sources, explain how the surveillance tests are performed to verify that a single-phase open circuit condition or high impedance ground fault condition on an off-site power circuit is detected.

Response to NRC Request Item 2.b A report by Basler Electric Company, "Practical Guide for Detecting Single-Phasing on a Three Phase Power System," October 2002, indicates that an open phase or high impedance fault on the Delta side of the Delta-Wye transformer, such as the RATs, would reduce the voltage on one or two phases of the Wye side (4.16kV) of the transformer. This characteristic is used to detect an open phase or high impedance fault in the 34.5kV circuit as follows:

1. The LTC tap on the affected RAT is likely to indicate abnormal position, since the reduced voltage on the sensed phase would cause the LTC position to increase, which would alert operators during daily (performed every shift) checks.

2. The voltage on one of the phases would drop to zero, which would actuate loss of sensed voltage annunciation in the control room. The LTC controller senses only the voltage between Phases 1 and 2. Therefore, this detection method is limited to detecting loss of Phase 1 only.

3. The voltmeter in the control room for the 34.5kV voltage would indicate lower voltage which would be detected in the weekly surveillance. The voltmeter measures the voltage across Phase 1 to neutral. Therefore, this surveillance would detect loss of voltage on Phase 1 and Phase 3, but not loss of voltage on Phase 2.

As part of the interim compensatory actions in response to INPO IER L2-12-14, "Automatic Reactor Scram Resulting from a Design Vulnerability in the 4.16-kV Bus Undervoltage Protection Scheme," dated February 16, 2012, the surveillance procedures and alarm procedures were updated to alert the operation crew to an open-phase condition. I&M may implement additional measures based on future studies and/or analyses.

NRC Request Item 2.d Do the plant operating procedures, including off-normal operating procedures, specifically call for verification of the voltages on all three phases of the ESF buses?

to AEP-NRC-2012-93 Page 8 Response to NRC Request Item 2.d The current plant operating procedures, including operating procedures for off-normal alignments, specifically require verification of the voltages on all three phases of the ESF buses. The checks are made on all phases at the 4kV safety buses daily.

Consequences NRC Bulletin 2012-01 Items 1.b, 1.c, and 2.e request information regarding the electrical consequences of an event and are addressed in this section:

NRC Request Item 1.b The differences (if any) of the consequences of a loaded (i.e., ESF bus normally aligned to offsite power transformer) or unloaded (e.g., ESF buses normally aligned to unit auxiliary transformer)power source.

Response to NRC Request Item 1 .b Installed under-voltage, overcurrent and differential relays were not designed to detect single phase open circuit conditions. Existing loss of voltage and degraded voltage relays may respond depending on loading and faulted condition with or without grounds. In general, there would be no plant response for an unloaded power source (e.g., when the ESF buses are normally aligned to unit auxiliary transformers) in the event of a single-phase open circuit on a credited off-site power circuit because there is insufficient current to detect a single-phase open circuit for this configuration. The specific plant response for a loaded power source cannot be calculated without specifying the amount of loading and the specific loads involved. A general discussion of the plant response is provided below.

The plant response for a loaded offsite power source would depend upon the location of the open-phase as follows:

• For an open phase on the 345kV or 765kV offsite source, the voltages at the 4kV levels are expected to be near normal and, therefore, no plant alarm or response is expected to occur.

• For an open phase on the 34.5kV level, the drop in voltage at the 4kV level would be detected by the UV relays. However, due to the 2-out-of-3 logic, there may not be an automatic response.

The plant response for an unloaded offsite power source would also depend upon the location of the open-phase as follows:

• For an open phase on the 345kV or 765kV offsite source, the voltages at the 4kV levels are expected to be near normal and, therefore, no plant alarm or response is expected to occur.

to AEP-NRC-2012-93 Page 9 For an open phase on the 34.5kV level, the voltage at the 4kV level may be detected by the loss of sensing voltage alarm in the main control room depending on which phase is opened. The open phase may also be detected by the routine surveillance for the 34.5kV voltage and the daily rounds for the LTC tap position. These detection methods are dependent on which phase is faulted, since not all phases are monitored.

There would not be an automatic protection for an unloaded offsite power source, i.e.,

the RATs. The open-phase may cause annunciation in the control room depending on the phase. Operators check the LTC position on the RATs every shift. An open phase on the primary side of RAT would cause voltage to drop on the secondary side by about 13%. The LTC would move up to compensate for this drop. The applicable surveillance procedures have been updated to alert operators to be alert for unusual high tap position, which may be an indication of open phase. Operations personnel also check 34.5kV bus voltage in the control room with an installed voltmeter every week. An open phase would be detected during the surveillance. However, the voltmeter only reads one phase. An open phase may also cause loss of sensing voltage in the LTC control circuit which is annunciated in the main control room as an LTC trouble alarm.

NRC Request Item 1.c If the design does not detect and automatically respond to a single-phase open circuit condition or high impedance ground fault condition on a credited offsite power circuit or another power sources, describe the consequences of such an event and the plant response.

Response to NRC Request Item 1 .c For a loss of phase on the 345kV or 765kV sources, the Basler report shows that the voltage unbalance is negligible at the secondary (34.5kV) side of the transformer. This is because 12-TR-4 and 12-TR-5 are Wye-Delta connected transformers. The report shows that the open-phase on the primary side would increase the primary current on the other two phases by a factor of 1.73. This increase in current is still within the nameplate ratings of transformers 12-TR-4 and 12-TR-5 to support the required emergency loads. The typical loading on the transformer winding is less than 50% of the rating. The differential relay on the 12-TR-4 and 12-TR-5 transformers would not trip due to a mismatch between overloaded primary windings compared to the secondary side.

A high impedance ground on the 345kV line side or winding side would have no immediate effect on plant operation. If the ground is sufficiently large to affect plant operation, protective relaying would isolate the ground automatically. The line side fault would likely be detected by the impedance relays and the winding side fault would likely be detected by the differential relay, depending upon the magnitude of the fault.

The CNP Licensing Basis does not credit the Class 1E protection scheme (for the ESF buses) for detection of, and automatic response to, a single-phase open circuit condition on the credited off-site power source as described in the UFSAR and Technical Specifications.

Since the CNP licensing basis does not credit the ESF bus protection scheme as being capable of detecting and automatically responding to a single phase open circuit condition, to AEP-NRC-2012-93 Page 10 an open phase fault was not included in the design criteria for either the ESF bus loss of voltage or the ESF bus degraded voltage relay scheme. Since open phase detection was not credited in the CNP design or licensing basis, no design basis calculations or design documents exist that previously considered this condition.

Without formalized engineering calculations or engineering evaluations, the electrical consequences of such an open phase event (including the plant response), can only be evaluated to the extent of what has already been published by EPRI and Basler, which is a generic overview. The difficulty in applying these documents to the CNP specific response is that these are generic assessments and cannot be formally credited as a basis for an accurate response. The primary reason is that detailed plant specific models would need to be developed (e.g., transformer magnetic circuit models, electric distribution models, motor models; including positive, negative, and zero sequence impedances (voltage and currents),

and the models would need to be compiled and analyzed for the CNP specific Class 1E electric distribution system).

Due to the split lineup from offsite sources, in the worst-case scenario, only one ESF train would potentially be vulnerable to the open phase or high impedance faults. The open-phase on the 345kV or 765kV offsite power supply is not expected to have any adverse consequence due to the Delta-Wye configuration and oversize transformer. An open-phase on the 34.5kV side would most likely be detected by existing surveillance or annunciation in the control room.

NRC Request Item 2.e If a common or single offsite circuit is used to supply redundant ESF buses, explain why a failure, such as a single-phase open circuit or high impedance ground fault condition, would not adversely affect redundant ESF buses.

Response to NRC Request Item 2.e When the preferred offsite sources power the ESF buses (i.e., during startup and shutdown, or following a reactor trip) the redundant ESF buses are split between 345kV and 765kV sources. Therefore, a common or single offsite circuit is not normally used to supply redundant ESF buses. In an unlikely event that the 345kV or the 765kV source (i.e.,

12-TR-5 or 12-TR-4) is out of service, both redundant trains would be fed from one common supply. This configuration is infrequently used and involves manual alignment of the associated breakers. However, the Basler report indicates that loss of a single phase on the 345kV source or the 765kV source does not cause a significant phase unbalance on the secondary voltage levels due to the Wye/Delta configuration of the transformers. There is a small section of the 34.5kV circuit in which an open phase could impact both redundant trains if the 345kV or the 765kV source is out of service. Most of the 34.5 kV circuits are located underground and, therefore, an open phase is unlikely to occur. Nevertheless, Operations personnel have been advised to avoid this configuration to the maximum extent possible, and when in this configuration, to have heightened awareness to recognize and respond to the symptoms of an open phase.

ATTACHMENT 2 to AEP-NRC-2012-93 Simplified One-Line Diagram Offsite Power to 4 kV Engineered Safety Feature Buses

Attachment 2 to AEP-NRC-2012-93 Simplified One-Line Diagram Offsite Power to 4 kilovolt (kV) Engineered Safety Feature Buses adds- seW

?MI"2 imzwVA 4W 4W 4W 4W 4W 4 4W4W 4W 4W4WW 4W* 4W to AEP-NRC-2012-93 Tables to AEP-NRC-2012-93 Page 1 Table 1 - ESF Buses Continuously Powered From Offsite Power Source(s)

Description of ESF BusPower: ESF Bus Name (normal operating Original licensing Descrptio ofnd EFiP basis configuration Soure coditin).(YIN)

This table does not apply to CNP. See Table 2. The ESF Buses are supplied from the UATs during normal unit operation. During startup and shutdown, and following a reactor trip they are powered from offsite via the RATs )

Table 2 - ESF Buses Not Continuously Powered From Offsite Power Source(s)

ESF Bus Name (normal Original licensing i.

Description of ESF Bus Power Source condition. basis co(prN) tion UAT, 1-TR1AB (Unit 1 Main Generator via TRAIN B, 4kv bus T11A and Normal Feed from Unit1 Aux Transformer AB, T11BB Train B, and RCP Buses 1Aand 1B)

UAT, 1-TR1CD (Unit 1 Main Generator via TRAIN A, 4kv bus T11C and Normal Feed from Unit1 Aux Transformer CD, T11DD Train A, and RCP Buses 1C and 1D)

UAT, 2-TR2AB (Unit 2 Main Generator via TRAIN B, 4kv bus T21A and Normal Feed from Unit 2 Aux Transformer AB, T21 B Train B, and RCP Buses 2A and 2B))

UAT, 2-TR2CD (U2 Main Generator via TRAIN A, 4kv bus T21C and Normal Feed from Unit 2 Aux Transformer CD, T21 D Train A, and RCP Buses 2C and 2D) to AEP-NRC-2012-93 Page 2 Table 3A-1 ESF Buses Normally Energized Major Loads Unit I Voltage Level RNormally ESF Bus Load (kV) Rating (HP) (ON/OFF)

T11A (Train B) WEST MOTOR DRIVEN AUXILIARY FEEDWATER PUMP, 1-PP-3W MOTOR 4 500 OFF T11A (Train B) WEST COMPONENT COOLING WATER PUMP, 1-PP-lOW MOTOR 4 500 ON (Note 1)

T11A (Train B) WEST CONTAINMENT SPRAY PUMP, 1-PP-9W MOTOR 4 600 OFF T11A (Train B) SOUTH SAFETY INJECTION PUMP, 1-PP-26S MOTOR 4 400 OFF T11A (Train B) WEST CENTRIFUGAL CHARGING PUMP, 1-PP-50W MOTOR 4 600 ON (Note 1)

T11A (Train B) WEST ESSENTIAL SERVICE WATER PUMP, 1-PP-7W MOTOR 4 450 ON (Note 2)

Tl1A (Train B) WEST RESIDUAL HEAT REMOVAL PUMP, 1-PP-35W MOTOR 4 400 OFF T1lD (Train A) EAST MOTOR DRIVEN AUXILIARY FEEDWATER PUMP, 1-PP-3E MOTOR 4 500 OFF T11D (Train A) EAST COMPONENT COOLING WATER PUMP, 1-PP-1OE MOTOR 4 500 ON (Note 1)

T11D (Train A) EAST CONTAINMENT SPRAY PUMP, 1-PP-9E MOTOR 4 600 OFF T11D (Train A) NORTH SAFETY INJECTION PUMP, 1-PP-26N MOTOR 4 400 OFF T11D (Train A) EAST CENTRIFUGAL CHARGING PUMP, 1-PP-50E MOTOR 4 600 ON (Note 1)

T11D (Train A) EAST ESSENTIAL SERVICE WATER PUMP, 1-PP-7E MOTOR 4 450 ON (Note 2)

Tl1D (Train A) EAST RESIDUAL HEAT REMOVAL PUMP, 1-PP-35E MOTOR 4 400 OFF 11B (Train B) SOUTH NON-ESSENTIAL SERVICE WATER PUMP, 1-PP-8S MOTOR 0.575 250 ON (Note 3) 11C (Train A) NORTH NON-ESSENTIAL SERVICE WATER PUMP, 1-PP-8N MOTOR 0.575 250 ON (Note 3)

Note 1: Normally only one pump is running, e.g., if the Train A pump is ON, then the Train B pump will be OFF.

Note 2: Normally only two of the four pumps are ON unless a unit cross-tie valve is closed.

Note 3: Normally 3 of 4 total Unit 1 and Unit 2 pumps are ON.

to AEP-NRC-2012-93 Page 3 Table 3A-2 ESF Buses Normally Energized Major Loads Unit 2 Voltage Level) Normally ESF Bus Load (kV)(HP) (ON/OFF)

T21A (Train B) WEST MOTOR DRIVEN AUXILIARY FEEDWATER PUMP, 2-PP-3W MOTOR 4 500 OFF T21A (Train B) WEST COMPONENT COOLING WATER PUMP, 2-PP-10W MOTOR 4 500 ON (Note 1)

T21A (Train B) WEST CONTAINMENT SPRAY PUMP, 2-PP-9W MOTOR 4 600 OFF T21A (Train B) SOUTH SAFETY INJECTION PUMP, 2-PP-26S MOTOR 4 400 OFF T21A (Train B) WEST CENTRIFUGAL CHARGING PUMP, 2-PP-50W MOTOR 4 600 ON (Note 1)

T21A (Train B) WEST ESSENTIAL SERVICE WATER PUMP, 2-PP-7W MOTOR 4 450 ON (Note 2)

T21A (Train B) WEST RESIDUAL HEAT REMOVAL PUMP, 2-PP-35W MOTOR 4 400 OFF T21D (Train A) EAST MOTOR DRIVEN AUXILIARY FEEDWATER PUMP, 2-PP-3E MOTOR 4 500 OFF T21D (Train A) EAST COMPONENT COOLING WATER PUMP, 2-PP-10E MOTOR 4 500 ON (Note 1)

T21D (Train A) EAST CONTAINMENT SPRAY PUMP, 2-PP-9E MOTOR 4 600 OFF T21D (Train A) NORTH SAFETY INJECTION PUMP, 2-PP-26N MOTOR 4 400 OFF T21D (Train A) EAST CENTRIFUGAL CHARGING PUMP, 2-PP-50E MOTOR 4 600 ON (Note 1)

T21D (Train A) EAST ESSENTIAL SERVICE WATER PUMP, 2-PP-7E MOTOR 4 450 ON (Note 2)

T21D (Train A) EAST RESIDUAL HEAT REMOVAL PUMP 2-PP-35E MOTOR 4 400 OFF 21B (Train B) SOUTH NON-ESSENTIAL SERVICE WATER PUMP, 2-PP-8S MOTOR 0.575 250 ON (Note 3) 21C (Train A) NORTH NON-ESSENTIAL SERVICE WATER PUMP, 2-PP-8N MOTOR 0.575 250 ON (Note 3)

Note 1: Normally only one pump is running, e.g., if the Train A pump is ON, then the Train B pump will be OFF.

Note 2: Normally only two of the four pumps are ON unless a unit cross-tie valve is closed.

Note 3: Normally 3 of 4 total Unit 1 and Unit 2 pumps are ON.

to AEP-NRC-2012-93 Page 4 Table 3B-1 RCP Buses Normally Energized Major Loads (Note 4)

Unit I ES Bus LoadVoltage Level Normally Voltageoe(kV) Rating (HP) (ON/OFF) 1A (TRAIN B) REACTOR COOLANT PUMP, PP-45-4 MOTOR 4 6000 ON 1A (TRAIN B) MIDDLE HOTWELL PUMP, PP-SM MOTOR 4.16 1250 ON (Note 5) 1A (TRAIN B) MIDDLE CONDENSATE BOOSTER PUMP, PP-6M MOTOR 4 1750 ON (Note 5) 1A (TRAIN B) CIRCULATING WATER PUMP, PP-2-2 MOTOR 4 2750 ON 1B (TRAIN B) REACTOR COOLANT PUMP, PP-45-1 MOTOR 4 6000 ON 1B (TRAIN B) MIDDLE HEATER DRAIN PUMP, PP-22M MOTOR 4 800 ON (Note 5) 1B (TRAIN B) CIRCULATING WATER PUMP, PP-2-3 MOTOR 4 2750 ON 1C (TRAIN A) REACTOR COOLANT PUMP, PP-45-2 MOTOR 4 6000 ON IC (TRAIN A) SOUTH HOTWELL PUMP, PP-5S MOTOR 4.16 1250 ON (Note 5) 1C (TRAIN A) SOUTH CONDENSATE BOOSTER PUMP, PP-6S MOTOR 4 1750 ON (Note 5) 1C (TRAIN A) SOUTH HEATER DRAIN PUMP, PP-22S MOTOR 4 800 ON (Note 5)

ID (TRAIN A) REACTOR COOLANT PUMP, PP-45-3 MOTOR 4 6000 ON ID (TRAIN A) NORTH HOTWELL PUMP, PP-SN MOTOR 4.16 1250 ON (Note 5) 1D (TRAIN A) NORTH CONDENSATE BOOSTER PUMP, PP-6N MOTOR 4 1750 ON (Note 5)

ID (TRAIN A) NORTH HEATER DRAIN PUMP, PP-22N MOTOR 4 800 ON (Note 5) 1D (TRAIN A) CIRCULATING WATER PUMP, PP-2-1 MOTOR 4 2750 ON Note 4: The RCP buses feed the ESF (T Buses), therefore RCP bus loads have also been tabulated.

Note 5: Normally only two of three pumps are ON.

to AEP-NRC-2012-93 Page 5 Table 3B-2 RCP Buses Normally Energized Major Loads (Note 4)

Unit 2 Load Voltage Level Rating (HP) Normally RCP Bus (kV) (ON/OFF) 2A (TRAIN B) REACTOR COOLANT PUMP, PP-45-4 MOTOR 4 6000 ON 2A (TRAIN B) MIDDLE HOTWELL PUMP, PP-5M MOTOR 4 1000 ON (Note 5) 2A (TRAIN B) MIDDLE CONDENSATE BOOSTER PUMP, PP-6M MOTOR 4 1750 ON (Note 5) 2A (TRAIN B) CIRCULATING WATER PUMP, PP-2-2 MOTOR 4 2750 ON 2B (TRAIN B) REACTOR COOLANT PUMP, PP-45-1 MOTOR 4 6000 ON 2B (TRAIN B) MIDDLE HEATER DRAIN PUMP, PP-22M MOTOR 4 1250 ON (Note 5) 2B (TRAIN B) CIRCULATING WATER PUMP, PP-2-3 MOTOR 4 2750 ON 2C (TRAIN A) REACTOR COOLANT PUMP, PP-45-2 MOTOR 4 6000 ON 2C (TRAIN A) SOUTH HOTWELL PUMP, PP-5S MOTOR 4 1000 ON (Note 5) 2C (TRAIN A) SOUTH CONDENSATE BOOSTER PUMP, PP-6S MOTOR 4 1750 ON (Note 5) 2C (TRAIN A) SOUTH HEATER DRAIN PUMP, PP-22S MOTOR 4 1250 ON (Note 5) 2C (TRAIN A) CIRCULATING WATER PUMP, PP-2-4 MOTOR 4 2750 ON 2D (TRAIN A) REACTOR COOLANT PUMP, PP-45-3 MOTOR 4 6000 ON 2D (TRAIN A) NORTH HOTWELL PUMP, PP-5N MOTOR 4 1000 ON (Note 5) 2D (TRAIN A) NORTH CONDENSATE BOOSTER PUMP, PP-6N MOTOR 4 1750 ON (Note 5) 2D (TRAIN A) NORTH HEATER DRAIN PUMP, PP-22N MOTOR 4 1250 ON (Note 5) 2D (TRAIN A) CIRCULATING WATER PUMP, PP-2-1 MOTOR 4 2750 ON Note 4: The RCP buses feed the ESF (T Buses), therefore RCP bus loads have also been tabulated.

Note 5: Normally only two of three pumps are ON.

Attachment 3 to AEP-NRC-2012-93 Page 6 Table 4 - Offsite Power Transformers Transformer Winding Configuration MVA Size Voltage Rating Grounding Configuration (OA/FA/FOA) (Primary/Secondary)

Station Service Xfmr at 765kV Wye (Auto-Transformer) 500MVA Per Soild Grounded Wye Switchyard - Delta Tertiary (765 and 345kV), 765kV- 34.5kV Delta grounded with (3 Single Phase) 345kV tap connects to (75 per phase 345kV/34.5kV Zig-Zag Transformer 12-TR3 112-TR-4 12-T-4 35kV witcyard(34.5kV) 345kV switchyard 5V phase (7.5MVA, 6.86 Ohm)

Station Service Xfmr at 345kV Soild Grounded Wye Switchyard Wye -Delta 90/120/150MVA 345kV/34.5kV 34.5kV Delta grounded with 12-TR-5 Zig-Zag, Transformer 7.5MVA RATs (4) 1-TR101AB, Unit 1 Train B 34.5kV/4.36kV LTC Resistance Grounded 1-TR101CD, Unit 1 Train A Delta-Wye (LTC) 18/24/30MVA (+ -15%, 35 taps) (1.2 Ohm -2000A)

B 2-TR201AB, Unit 2 Train 2-TR201CD, Unit 2 Train A UATs (4) 1-TR1AB, Unit 1 Train B Resistance Grounded 1 -TR1 CD, Unit 1 Train A Delta-Wye (Fixed Taps) 18/24/30MVA 26kV/4.16kV (1.2 Ohm - 2000A) 2-TR2AB, Unit 2 Train B 2-TR2CD, Unit 2 Train A Station Service Xfmr at 69kV Switchyard 7.5MVA (self Solid Grounded Wye, dDelta - Wye cooled) 69kV/4.6kV 69kV Delta ungrounded 12-TR-EP-1,

Attachment 3 to AEP-NRC-2012-93 Page 7 TABLE 5A - Protective Devices (Unit Specific)

Nominal Nominal Protection Zn Fiue Att. 3 DvcID Protective ap(Aor Setpoint Att. 3 adBssProtection Protective n Zn rProtection Protectio Setpoint, Att.

igr3 eic D Protective aps()o Setpoint, Basison Description and No. Zone Figure Device ID amps (A) or and Basis Basis volts (V) volts (V Unit I - Under Voltage 7V 2725V or 2-27-AUV 2870V or 4kV RCP 4kV RCP 1 65.5% of BUS 2A 69.0% of BUS 1A 2-27 4160V Reactor 4160V Coolant Pump AUV Allowable Allowable Value, - Under 2-27-BUV Value, Reactor Coolant 4kV RCP Voltage 4kV RCP Pump - Under 2 BUS 2B BUS 1B 2-27 Voltage 2773V or The sepoints BUV 2918V or Fig. A 66.7% of are to Fig. A 70.2% of The setpoints are to 4160V, minimize 2-27-CUV 4160V, minimize departure 4kV RCP Nominal Trip 4kV RCP Nominal Trip 3 BUS 1C departure from BUS 2C from nucleate Setpoint nucleate 2-27 Setpoint boiling ratio. Two boiling ratio. CUV relays per bus.

Two relays per 2-27-DUV 2 out of 4 Logic bus. 2 out of 4 Logic 4kV RCP 4kV RCP 4 BUS 1D to minimize BUS 2D to minimize spurious trip. 2-27 spurious trip.

DUV ESF UV 3930.9V or 4kV ESF 3930.9V or (Degraded 4kVESF 27-TV of (D94.5%ESF UV 5 BUS T11A, 94.5% of Voltage) BUS 27-T2IA- 4160V (Degraded Voltage)

TRAIN B 4160V Protection BUS T21A 1,2,3 Allowable Protection Allowable Value. 3946.5V Fig. B Value. 3946.5V Time delay is Fig. B or 94.9% of Time delay is used or 94.9% of used to allow 4160V to allow voltage to 4kV ESF 4160V Nominal voltage to 4kV ESF 27-T21D- Nominal Trip recover. The 6 BUS T11A, Trip Setpoint, recover. The BUS 1,2,3 Setpoint, Analytical limit is TRAIN A 2 out of 3 Logic Analytical limit T21D, 2 out of 3 94%.

is 94%. Logic

Attachment 3 to AEP-NRC-2012-93 Page 8 TABLE 5A - Protective Devices (Unit Specific)

Nominal Protection Nominal Protection N0. Protection Att. 3 Protective Setpoint, Description Protection Att. 3 Protective Setpoint, Description and Zone Figure Device ID amps (A) or and Basis Zone Figure Device ID amps (A) or Basis volts (V) volts (V 4kV ESF 27-1,2,3- 4kV ESF 27-1,2,3-BUST11A T11A BUS T21A T21A ESF UV (Loss 3238.9V or of Voltage 3207.2V or 77.9% of Protection) 77.1% of ESF UV (Loss of 8 4kV ESF 27-1,2,3- 4160V Detects 4kV ESF 27-1,2,3- 4160V Voltage )

BUS T11B T11B Allowable 4.16kV power BUS T21 B T21 B Allowable Protection, Detects Value. supply loss Fig. B Value, 3243.3V 4.16kV power Fig. B 3275.3V or and fast or 78.0% of supply loss and fast 4kV ESF 27-1,2,3- 78.7%of 4160V transfer to 4kV ESF 27-1,2,3- 4160V transfer to offsite BUS T11C T11C Nominal Trip offsite power BUS T21 C T21 C Nominal Trip power or dead bus Setpoint, 2 out or dead bus Setpoint 2 out transfer to EDG.

of 3 Logic transfer to of 3 Logic.

EDG 4kV ESF 27-1,2,3- 4kV ESF 27-1,2,3-10 BUST11D T11D BUS T21D T21D Unit I Differential  % it 2i 1 320A on 2 320A on 11 TR101AB T101AB- 34.5kV Tap of Reserve TR201AB T201AB- 34.5kV Tap of 1,2,3 3.2 with 100/1 Auxiliary 1,2,3 3.2 with 100/1 CT TansorerXfmr ato. Th Transformer FLA on Auxiliary Transformer CT ratio. (The Xfmr FLA on Differential Fig. C 345k sid is D renta (r oun Fig. C 34.5kV side is sde s Sttigs.34.5kV 34.5V Settings. The is 301A. side Differential (Ground fault protection).

301A. Ground (Ground fault 2 ground fault 1 12 TR101CD T101CD- Fault on 4kV protection) TR201CD T201CD- current on 4kV 1,2,3 side is 2000A) 1,2,3 side is 2000A).

Attachment 3 to AEP-NRC-2012-93 Page 9 TABLE 5A - Protective Devices (Unit Specific)

Nominal Protection Nominal Protection Zoe ams()o Att. 3 FgroDvc.D Protection Protective Zne Setpoint,Decito Fgr DvceI ams()r Setpoint, Description and No. PrProtection Att. 3 Protective Zone Figure Device volts (A) and Basis Zone Figure Device ID amps (A) or Basis volts (V) volts (V 13 TR1AB 1-87-TAB- 2-87-TAB- 420A on 26kV 1,2,3 420A on 26kV 1,2,3 Tap of 3.5 with Tap of 3.5 with Unit Auxiliary 120/1 CT ratio. Unit Auxiliary 120/1 CT ratio. Transformer (The Xfmr FLA Transformer Fig. D (The Xfmr FLA Differential Fig. D on 26kV side is Differential on 26kV side is Settings. 400A. The Settings. (Ground 400A. Ground (Ground fault ground fault fault protection) 1-87-TCD- Fault on 4kV protection). 2-87-TCD- current on 4kV 14 TR1CD 1,2,3 side is 2000A). TR2CD 1,2,3 sideis2000A).

3480A (345kV 2136A (765V side, Tap 8.7, 1.887xFLA, 400/1 CT ratio) 600/1 CT ratio) and 26600A and 159kA (26kV side, Overall (26kV side, Tap Overall Differential Tap 3.8, Differential 15 TR1/AB/CD Fig. E 87-OA 7000/1 CT and Unit raio. TR2AB/CD he Trnsorer7000/1 Fig. E 87-OA 4.76xFLA,CT and Unit Transformer ratio). The Transformer ratio). The fault Differential Fault Current is Differential current is

>4kA>17kA on 26kV side and 765kV side and

>13kA on >250A on 26kV 345kV side. side.

Attachment 3 to AEP-NRC-2012-93 Page 10 TABLE 5A - Protective Devices (Unit Specific)

Nominal Nominal Protection Protection Protection' Aft. 3 Protective Setpoint, Protection Att. 3 Protective Setpoint, Zone Description Description and Figure Device ID amps (A) or Zone Figure Device ID amps (A) or and Basis Basis volts (V) volts (V Unit I Ground Overcurrent 1-51TN- 2-51TN-AB AB 16 TR1AB TR2AB 1-251TN- 2-251TN-AB AB 1-51TN- 2-51TN-CD 300A on Tap 5 Transformer CD 300A on Tap 5 17 TR1CD with 60/1 CT Neutral TR2CD with 60/1 CT Transformer 1-251TN- ratio (The Ground 2-251TN- ratio (The Neutral Ground Fig. F Fig. F CD Ground Fault Overcurrent CD Ground Fault Overcurrent (with on 4kV side is (with backup on 4kV side is backup relay) 1-51TN- 2000A) relay) 2-51TN- 2000A) 10lAB 201AB 18 TR101AB TR201AB 1-251TN- 2-251 TN-10lAB 201AB 1-51TN- 2-51 TN-19 1 TR101CD TR201CD 101CD 201 CD to AEP-NRC-2012-93 Page 11

___ __Table 5B - Protective Devices (Common) 34.5kV Switchyard Relays (Unit I & 2)

Protective Device Nominal Setpoint, ID amps (A) or volts (V) Protection Description and Basis For 12AB, 1600A on 34.5kV Tap of 4.0 Reserve Feed Lead Differential 87-TABLD with 400/1 CT ratio. The Phase toPrtcin Ground fault is 5785A (12-TR-5).Prtcin For 1200, 2000A on 34.5kV Tap of 5.0 Reserve Feed Lead Differential 87-TCDLD with 400/1 CT ratio. The Phase to Protection.

Ground fault is 6864A (12-TR-5).

1600A on 34.5kV Tap of 4.0 with 400/1 87-TCDLD CT ratio. The phase-to-ground fault 34.5kV Bus - Overall Differential current is 6864A (12-TR-4) and 5785A Protection.

(12-TR-5).

8000A (Tap 4 at 2000/1 CT ratio). The 12-TR-4 34.5kV Lead Differential 2-87-T4L-1,2,3 phase fault current at 34.5kV is greater Protection.

than 31kA.

207A (Tap 1.5A at 30 cycles, CT ratio Overcurrent protection for 2-51G-T-1,2,3 240/1 Delta). The minimum line side fault grounding transformer TR6.

current is 2241A (12-TR-5 source).

2-51 G-TN 720A (Tap 6, CT ratio 120/1) Grounding transformer TR6 ground

( 6neutral protection (backup).

2-59-T4 70V (Broken Delta, 3-PT's 34.5kV Wye- Phase to ground fault (Back up 34.5kV 120V Broken Delta). protection).

23 Fig. H Switchyard 12-51G-BC 600A (Tap 1.5, CT ratio 400/1), The Ground Fault Overcurrent 12-51-12AB phase-to-ground fault current is 6864A protection 12-51-12CD (12-TR-4) and 5785A (12-TR-5). (34.5V Breakers).

4800A (Tap 12, CT ratio 400/1), The 3 Phase Overcurrent protection 2-51-BC-1,3 phase fault current at 34.5kV is 31927A 34.5kV breaker BC - Line side.

(12-TR-4).

8000A (Tap 4, CT ratio 200/1), 3 Phase Phase Overcurrent protection 2-51-LT4-1,2,3 Fault at 34.5kV is 31927A (12-TR-4). 34.5kV breaker BC -Load side.

to AEP-NRC-2012-93 Page 12 Table 5B - Protective Devices (Common) 34.5kV Switchyard Relays (Unit I & 2)

No. Protection Att. 3 Figure Protective Device Nominal Setpoint, Protection Description and Basis Zone ID amps (A) or volts (V) 1920A (Tap 8, CT Ratio 240/1) The FLA Phase Over Current Protection - EP

=1 200A for the 7.5MVA Xfmr. feed breaker.

24 1-52-1EP Fig. I 600A (Tap 2.5, CT Ratio 240/1). The line 51 N-1 EP to ground fault current is over 1OkA at the Groau o n P Xfmr 4kV side.

1920A=1200A (Tap 8, CT Ratio 240/1) The FLA Phase Over Current Protection - EP for the 7.5MVA Xfmr. feed breaker 180A (Tap 6, CT ratio 30/1), The primary Phase Over Current Protection -

51-12HEP-1,2,3 FLA current at 69kV side is -63A). High side 2400A (Tap 10, CT ratio 240/1), The Ground Overcurrent Protection -

26 12EP Fig. J 51-12LEP-1,2,3 ground fault current at 4kV side is over Low side.

10kA (not resistance grounded).

p8with 240/1 CT ratio. Differential protection breakers for 4kV EP and Bus.

Attachment 4 to AEP-NRC-2012-93 Figures These figures are referenced in Attachment 3, Table 5.

Numbers in squares in these figures indicate the number of relays.

to AEP-NRC-2012-93 Page 1 4 kV BUS 1A I 3 PT's I

4200/120V 10 AMPS 10 AMPS 1-27-AUV 1-96-AUF 1-27-1 -AUV 1-96-1-AUF Figure A Typical RCP UV and UF Relays 2 per Bus to AEP-NRC-2012-93 Page 2 4kV BUS T11A

=6L/ 3 PT's 4200/120 V 1-27-1-Ti 1A 1-27-T 1iA-1 1-27-2-T11A 1-27-T 11A-2 1-27-3-Ti1 A 1-27-T 11A-3 Figure B Typical Loss of Voltage and Degraded Voltage Relays 3 per Bus to AEP-NRC-2012-93 Page 3 3 BCT'S MR 240/1 <

CONN 100/1 TR101AB 34.5 kV/4.36 kV/\/\/\/%/\

34)18/24/30 M VA \ //\ ^ r 1-87-T101AB-1 1-87-T 1OlAB-2 1-87-Tl01AB-3

[1A5 1B5 J

3 CT'S-- 3 CT'S <

3500/2.5 - 3500/2.5 <

A Ak 4kV BUS 1A 4kV BUS 1B Figure C Typical Differential Relays - RATs 1 per Phase to AEP-NRC-2012-93 Page 4 3 BCT'S MR 240/1 CONN 120/1 TRIAB 26kV/4.16kV 3Ph 18/24/30 MVA 1-87-TAB-1 3 1-87-TAB-2 1-87-TAB-3 I A7 I B7 3 CT'S 3 CT'S <

3500/2.5< 3500/2.5-<

A A p

4 kV BUS 1A 4 kV BUS lB Figure D Typical Differential Relays - UATs I per Phase to AEP-NRC-2012-93 Page 5 3 BCTs 3 BCTs 2000/5 2000/5 Ki 345 kV BUS K CONNA CONNA 101 101 TRi 343 kV /25 kV S 30 -1300 MVA 3 BCTs 35000/5 26 kV BUS GEN#1 3 BCTs 3 BCTs -z 101 35000/5 101 35000/5 *-

101 A A/V/K/V TRIAE A /\/\ \ TRl1CD

/\/V 26 kV / 4.16 kV Ak/V/,26 kV /4.16 kV 8/24/30 MVA 30 - 18 /24 /30OMVA 4 kV BUS 1A& 1B 4 kVBUS 1C & 1D (BKRS 1A7 & 1B7) (BKRS 1C6 & 1D5)

Figure E Typical UAT- Generator Overall Differential Relay 1 per Phase to AEP-NRC-2012-93 Page 6 26 kW BUS 3 BCTs \A TRANS# 1 DIFF MR 240/1 CONN 120/1 vv 3 AUX CTs 292/5

/\/'v'V\/\ TR1AB

^/V 26 kV/4.16 kV 3 PH. 18/24/30 MVA 1-51TN-AB 1

CONN 60/1 IB for 1-87-TAB-I, 2, 3 see Figure D 1.2 Ohm1A B 1-251N-ABTT 3 CT'S~

3 CT'S 3500/2.5.::-

3500/2.5 A

A 4kV BUS IA 4kV BUS IB Figure F Typical RAT and UAT Ground Overcurrent Relays 1 per Phase to AEP-NRC-2012-93 Page 7 34.5kV BUS 400/1 aI* 12-87-TABLD-2 12-87-TABLD-1 12-87-TABLD-3 1 2AB 1-400/1 <_400/1

\AA/VNI RESERVE AUX /\/\/

TRANSFORMERS\A\/\/\/

TR101lAB TR201AB Figure G Typical Lead Differential - RATs 1 per Phase to AEP-NRC-2012-93 Page 8 1500 MVA TR 4 150 MVA/~~I~i~

345 kV Figure H 34.5kV Switchyard Overcurrent Relays, Phase and Ground Relays to AEP-NRC-2012-93 Page 9 4 kV BUS 2 2" 2-51-2EP-1 3 CT'S 240/1 F 2EP Figure I Typical EP Overcurrent Relays, Phase and Ground to AEP-NRC-2012-93 Page 10 69 kV BUS 12-51-H12EP-2-1 12-51-H12EP-1-1 3 BCTs 3 12-51-H12EP-2-2 3 BCTs 3 12-51-H12EP-1-2 MR 120/1 < 12-51-H12EP-2-3 MR 120/1 12-51-H12EP-1-3 CONN 20/1 CON~

TR12EP-2 TR12EP-1 AAAA A l ~A 69 kV / 4.16 kV 3 0 7500 KVA 3 0 7500 KVA 3 BCTs S: - 12-51-L12EP-2 36BCTs 1 12-51-L12EP- 1 MR 240/1 MR2 240/1 CONN 240/1 CONN 240/1 19*-R 7-P-12-87-B-2 12-87-B-3 1E 3 CTs 3 CTs GUARD HSE SR 1200/5 SR 1200/5 VISITOR CENTER w STREET LIGHTING Figure J Typical EP Bus Overcurrent and Differenial Relays

Attachment 5 to AEP-NRC-2012-93 Abbreviations and Acronymns Used in Attachements 1 Through 4

Attachment 5 to AEP-NRC-2012-93 Abbreviations and Acronyms Used in Attachments 1 Through 4 Abbreviations and acronyms used in Attachments 1 through 4 are defined below. These and other acronyms and abbreviations may also be defined at their point of use.

A, amps amperes AC alternating current AUX auxiliary BCT Bushing Current Transformer CNP Donald C. Cook Nuclear Plant CT current transformer EDG Emergency Diesel Generator EP Emergency Power (69kV circuit)

EPRI Electric Power Research Institute ESF Engineered Safety Feature FA forced air (fans)

FLA full load amperes FOA forced oil air (pumps and fans)

GDC General Design Criteria GEN generator GSU Generator step up HP horsepower HSE house I&M Indiana Michigan Power Company INPO Institute of Nuclear Power Operations kA kiloamp(s) kV kilovolt(s)

LTC load tap changing MR multi-ratio MVA megavolt-amps NC normally closed NO normally open NRC U. S. Nuclear Regulatory Commission OA oil-air Ph phase PT potential transformer RAT Reserve Auxiliary Transformer RCP Reactor Coolant Pump SDG Supplemental Diesel Generator TR transformer UAT Unit Auxiliary Transformer UFSAR Updated Final Safety Analysis Report UF under frequency UV under voltage V volts VR voltage regulator Xfmr transformer