View source for RA-19-0089, Response to Request for Additional Information - Application to Revise Technical Specifications to Adopt TSTF-439, Eliminate Second Completion Times Limiting Time from Discovery of Failure...

{{Adams
| number = ML19042A015
| issue date = 02/08/2019
| title = Response to Request for Additional Information - Application to Revise Technical Specifications to Adopt TSTF-439, Eliminate Second Completion Times Limiting Time from Discovery of Failure...
| author name = Gideon W
| author affiliation = Duke Energy Progress, LLC
| addressee name = 
| addressee affiliation = NRC/Document Control Desk, NRC/NRR
| docket = 05000324, 05000325
| license number = DPR-062, DPR-071
| contact person = 
| case reference number = EPID L-2018-LLA-0220, RA-19-0089
| document type = Letter type:RA, Response to Request for Additional Information (RAI)
| page count = 13
| project = EPID:L-2018-LLA-0220
| stage = Response to RAI
}}

=Text=
{{#Wiki_filter:William R. Gideon Vice President Brunswick Nuclear Plant P.O. Box 10429 Southport, NC 28461 o: 910.832.3698 February 8, 2019 Serial: RA-19-0089                                                                 10 CFR 50.90 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001

==Subject:==
Brunswick Steam Electric Plant, Unit Nos. 1 and 2 Renewed Facility Operating License Nos. DPR-71 and DPR-62 Docket Nos. 50-325 and 50-324 Response to Request for Additional Information - Application to Revise Technical Specifications to Adopt TSTF-439, "Eliminate Second Completion Times Limiting Time From Discovery of Failure To Meet an LCO

==References:==
: 1. Letter from William R. Gideon (Duke Energy) to the U.S. Nuclear Regulatory Commission Document Control Desk, Application to Revise Technical Specifications to Adopt TSTF-439, "Eliminate Second Completion Times Limiting Time From Discovery of Failure To Meet an LCO, dated August 14, 2018, ADAMS Accession Number ML18227A535
: 2. E-Mail Capture from Dennis Galvin (NRC) to Art Zaremba (Duke Energy), Brunswick RAIs - LAR to Revise TSs to Adopt TSTF-439, "Eliminate Second Completion Times Limiting Time From Discovery of Failure To Meet an LCO (EPID L 2018-LLA-0220),
dated January 10, 2019, ADAMS Accession Number ML19010A387 Ladies and Gentlemen:
By letter dated August 14, 2018 (i.e., Reference 1), Duke Energy Progress, LLC (Duke Energy),
submitted a license amendment request (LAR) for the Brunswick Steam Electric Plant (BSEP),
Unit Nos. 1 and 2. Consistent with Technical Specification Task Force Traveler 439 (TSTF-439), the proposed amendment deletes second Completion Times from the affected Required Actions contained in TS, along with removing the example contained in TS Section 1.3 and adding a discussion about alternating between Conditions.
On January 10, 2019, (i.e., Reference 2), the NRC provided a request for additional information (RAI) regarding the LAR. Duke Energy's response to the RAI is included in the enclosure.
This document contains no new regulatory commitments.

U.S. Nuclear Regulatory Commission Page 2 of 2 I declare, under penalty of perjury, that the foregoing is true and correct. Executed on February 8, 2019.
s~
William R. Gideon MAT/mat

==Enclosure:==

Response to Request for Additional Information cc (with Enclosure):
U.S. Nuclear Regulatory Commission, Region II ATTN: Ms. Catherine Haney, Regional Administrator 245 Peachtree Center Ave, NE, Suite 1200 Atlanta, GA 30303-1257 U.S. Nuclear Regulatory Commission ATTN: Mr. Dennis J. Galvin 11555 Rockville Pike Rockville, MD 20852-2738 U.S. Nuclear Regulatory Commission ATTN: Mr. Gale Smith, NRC Senior Resident Inspector 8470 River Road Southport, NC 28461-8869 Chair - North Carolina Utilities Commission {Electronic Copy Only) 4325 Mail Service Center Raleigh, NC 27699-4300 swatson@ncuc.net Mr. W. Lee Cox, Ill, Section Chief {Electronic Copy Only)
Radiation Protection Section North Carolina Department of Health and Human Services 1645 Mail Service Center Raleigh, NC 27699-1645 lee.cox@dhhs.nc.gov

RA-19-0089 Enclosure Page 1 of 11 Response to Request for Additional Information By letter dated August 14, 2018, Duke Energy Progress, LLC (Duke Energy), submitted a license amendment request (LAR) for the Brunswick Steam Electric Plant (BSEP), Unit Nos. 1 and 2. Consistent with Technical Specification Task Force Traveler 439 (TSTF 439), the proposed amendment deletes second Completion Times from the affected Required Actions contained in TS, along with removing the example contained in TS Section 1.3 and adding a discussion about alternating between Conditions.
On January 10, 2019, the NRC provided a request for additional information (RAI) regarding the LAR. Duke Energy's response is provided below.
Request for Additional Information TSTF-439, Revision 2 provides a discussion of each of the specifications affected by the TSTF that justifies deleting the second CTs from the specification in NUREG-1433. The licensees application does not provide a comparable discussion for the proposed variations. For the specifications listed in the BSEP variations, TS 3.7.2, TS 3.8.1, and TS 3.8.7, provide a discussion similar to that in TSTF-439 for each specification to justify proposed deletions of second CTs. In particular, this plant-specific justification should address the following:
: a. For TS 3.7.2, Required Actions B.1, C.2, and E.1, the identified more restrictive change;
: b. For TS 3.8.1, Required Actions B.3, C.3, and D.5, as applicable, unique TSs due to the BSEPs shared electrical distribution systems configuration and the reference to LCO 3.8.1 NOTES a or b;
: c. For TS 3.8.7, Required Actions A.1, B.1, C.4, and D.1, as applicable, unique TSs due to the BSEPs shared electrical distribution systems configuration.

===Response===
TS 3.7.2, Required Actions B.1, C.2, and E.1 Service Water System Description The Service Water (SW) System provides water from the Cape Fear River for lubrication and cooling of equipment in the Reactor Building, Turbine Building, Diesel Generator Building, and the Circulating Water System. Each units SW system is subdivided into two major headers, the Nuclear Service Water (NSW) header and the Conventional Service Water (CSW) header. The NSW header normally provides cooling water for equipment in the Reactor Building and Diesel Generator Building. The CSW header normally supplies cooling water for equipment in the Turbine Building and balance of plant equipment in other areas. Each units SW system is assigned five pumps, of which two are designated as NSW pumps and three are designated as CSW pumps. Under normal operating conditions, two NSW pumps (one operating and one in standby) provide water to the NSW header, and three CSW pumps (two operating and one in standby) provide water to the CSW header. Each header is operated independently; however, the CSW pumps can supply the NSW header in the event of additional NSW heat load requirements or NSW pump failure. In addition, cross-connect valves allow the CSW header to supply selected equipment normally handled by the NSW header as conditions dictate.

RA-19-0089 Enclosure Page 2 of 11
* TS 3.7.2, Required Action B.1, One required Nuclear Service Water (NSW) pump inoperable.
Specification 3.7.2, SW System and Ultimate Heat Sink, has a 7-day Completion Time for one required NSW pump inoperable (Condition B) and a 12-hour Completion Time to be in Mode 3 for two or more required NSW pumps inoperable (Condition I). Condition B has a second Completion Time of 14 days from discovery of failure to meet the Limiting Condition for Operation (LCO).
The SW system is considered operable when it has two operable CSW pumps (unit dependent) and three site of the four NSW pumps (any combination of Unit 1 and Unit 2 NSW pumps). The loss of one NSW pump does not dictate entry into Required Action B.1. The loss of a second NSW pump (one of the three required) would dictate entry into Required Action B.1. This condition would not constitute a loss of safety function. The loss of a third site NSW pump (two of the three required) would dictate entry into Required Action I.1 and constitute a loss of safety function.
For the 14-day second Completion Time to be limiting, entry into and out of Condition B and Condition I must occur multiple times. This scenario would assume the loss of various NSW pumps multiple times, but with none of the overlapping inoperabilities lasting more than 12 hours (Condition I). This highly improbable scenario is further limited by the short Completion Times of Required Action I.1 (Be in Mode 3 within 12 hours) and Required Action I.2 (Be in Mode 4 within 36 hours).
The Reactor Oversight Process monitors the availability of mitigating systems, including the cooling water system (Service Water). Such frequent, repeated failures or extended unavailability of the NSW pumps would be reported to the NRC and this represents a strong

RA-19-0089 Enclosure Page 3 of 11 disincentive to such operation. Additionally, 10 CFR 50.65 (a)(1), "Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, (the Maintenance Rule) requires a comprehensive program which provides much greater assurance of safe plant operation than the second Completion Times in the TS.
Based on the above, the second Completion Time for Required Action B.1 is not required.
* TS 3.7.2 Required Action C.2, One required Conventional Service Water (CSW) pump inoperable.
Required Action E.1, Two required CSW pumps inoperable.
Specification 3.7.2, SW System and UHS, has a 7-day Completion Time for one required CSW pump inoperable (Condition C) and a 72-hour Completion Time for two required CSW pumps inoperable (Condition E). Condition C and E both have second Completion Times of 14 days from discovery of failure to meet the LCO.
The SW system is considered operable when it has two operable CSW pumps (unit dependent) and three site NSW pumps (any combination of Unit 1 and Unit 2 NSW pumps). The loss of one of the three CSW pumps on a unit does not dictate entry into Condition C. The loss of a second CSW pump (one of the two required) would dictate entry into Condition C. With one required CSW pump inoperable, the inoperable pump must be restored to operable status within 7 days. With the unit in this condition, the operable CSW pump and NSW pumps are adequate to perform the heat removal function. The 7-day Completion Time is based on the availability of two unit-specific SW pumps (an operable CSW pump and an operable NSW pump), each powered from separate 4.16 kV emergency buses, to support the unit's service water loads.
The 7-day Completion Time is based on the remaining SW heat removal capability, a reasonable time for repairs, and the low probability of an event occurring during this time period requiring the SW System.
With two required CSW pumps inoperable, one required inoperable pump must be restored to operable status within 72 hours. With the unit in this condition, the operable NSW pumps are adequate to perform the heat removal function. The 72-hour Completion Time is based on the availability of the remaining NSW pumps to support the unit's Service Water loads. The 72-hour Completion Time is based on the remaining SW System heat removal capability, a reasonable time for repairs, and the low probability of an event occurring during this time period requiring the SW System.
For the 14-day second Completion Time to be limiting, entry into and out of Condition C and Condition E must occur multiple times. This scenario would assume the loss of various CSW pumps multiple times, but with none of the overlapping inoperabilities lasting more than 72 hours (Condition E). This highly improbable scenario is further limited by the short Completion Times of Required Action I.1 (Be in Mode 3 within 12 hours) and Required Action I.2 (Be in Mode 4 within 36 hours). Furthermore, Required Action C.1, verify the one operable CSW pump and one operable unit specific NSW pump are powered from separate emergency buses, must be completed immediately. If Required Action C.1 cannot be verified, then Condition D is entered which requires the restoration of the inoperable CSW pump to be completed within 72 hours.

RA-19-0089 Enclosure Page 4 of 11 The Reactor Oversight Process monitors the availability of mitigating systems, including the cooling water system (Service Water). Such frequent, repeated failures or extended unavailability of the CSW pumps would be reported to the NRC and this represents a strong disincentive to such operation. Additionally, the Maintenance Rule requires a comprehensive program which provides much greater assurance of safe plant operation than the second Completion Times in the TS.
Based on the above, the second Completion Times for Required Action C.2 and E.1 are not required.
TS 3.8.1, Required Actions B.3, C.3, and D.5 AC Sources Description Offsite power is supplied to the 230 kV switchyards from the transmission network by eight transmission lines. From the 230 kV switchyards, two qualified electrically and physically separated circuits provide AC power, through either a startup auxiliary transformer (SAT) or backfeeding via a unit auxiliary transformer (UAT), to 4.16 kV balance of plant (BOP) buses. A single circuit path (master/slave breakers and interconnecting cables) from each BOP bus provides offsite power to its associated downstream 4.16 kV emergency bus. A qualified offsite circuit consists of all breakers, transformers, switches, interrupting devices, cabling, and controls required to transmit power from either 230 kV bus (bus A or B) to the onsite Class 1E emergency buses. The Unit 1 main generator provides the normal source of power to 4.16 kV emergency buses E1 and E2 via its respective UAT. The Unit 2 main generator provides the normal source of power to 4.16 kV emergency buses E3 and E4 via its respective UAT.
The onsite standby power source for 4.16 kV emergency buses E1, E2, E3, and E4 consists of four diesel generators (DGs). Each DG is dedicated to its associated emergency bus. A DG

RA-19-0089 Enclosure Page 5 of 11 starts automatically on a loss of coolant accident (LOCA) signal from either Unit 1 or Unit 2 or under emergency bus degraded voltage or undervoltage conditions. After the DG has started, it automatically ties to its respective bus after offsite power is tripped as a consequence of emergency bus undervoltage or degraded voltage, independent of or coincident with a LOCA signal (refer to LCO 3.3.8.1, "Loss of Power (LOP) Instrumentation"). The DGs also start and operate in the standby mode without tying to the emergency bus on a LOCA signal alone.
Following the trip of offsite power, all loads are stripped from the emergency bus except the 480 V emergency bus. When the DG is tied to the emergency bus, select safety related loads are then sequentially connected to their respective emergency bus by individual timers associated with each auto-connected load following a permissive from a voltage relay monitoring each emergency bus.
The capability is provided to connect a supplemental diesel generator (SUPP-DG) to supply power to any of the four 4.16 kV emergency buses via a BOP circuit path. This BOP circuit path consists of the BOP bus and the associated circuit path (master/slave breakers and interconnecting cables) to a 4.16 kV emergency bus. The SUPP-DG is commercial-grade and not designed to meet Class 1E requirements. The SUPP-DG is made available to support extended Completion Times in the event of an inoperable DG. The SUPP-DG is made available as a defense-in-depth alternate source of AC power to one emergency bus.
The Class 1E AC electrical distribution system is divided into four load groups. Each load group consists of a primary emergency bus, its downstream secondary emergency bus, 120 VAC vital bus, and transformers and interconnecting cables. The buses associated with each of the four load groups are defined as follows:
* Load group E1 consists of 4.16 kV bus E1, 480 V bus E5, and 120 VAC vital bus 1E5.
* Load group E2 consists of 4.16 kV bus E2, 480 V bus E6, and 120 VAC vital bus 1E6
* Load group E3 consists of 4.16 kV bus E3, 480 V bus E7, and 120 VAC vital bus 2E7.
* Load group E4 consists of 4.16 kV bus E4, 480 V bus E8, and 120 VAC vital bus 2E8.
The E1 and E2 load groups are supplied from Unit 1 balance of plant (BOP) buses and primarily serve Unit 1 loads. The E3 and E4 load groups are supplied from Unit 2 BOP buses and primarily serve Unit 2 loads. In some instances, loads associated with one unit are supplied from the opposite unit's load group buses.
* TS 3.8.1 Required Action B.3, Two Unit 1 offsite circuits inoperable due to one Unit 1 balance of plant circuit path to the downstream 4.16 kV emergency bus inoperable for planned maintenance. AND DG associated with the affected downstream 4.16 kV emergency bus inoperable for planned maintenance. (Unit 2)
Due to the shared configuration of the BSEP electrical distribution system, two Unit 1 and two Unit 2 qualified circuits between the offsite transmission network and the onsite Class 1E Distribution System and four separate and independent DGs both Unit 1 and Unit 2 are required to be operable when a unit is in Mode 1, 2, or 3. TS 3.8.1, Condition B was established to allow sufficient time to perform maintenance on the BOP buses and the associated 4.16 kV emergency bus of the opposite, shutdown unit without placing an operating unit in an unduly restrictive Completion Time. To perform maintenance on the 4.16 kV emergency bus, the associated DG must be rendered inoperable.

RA-19-0089 Enclosure Page 6 of 11 The second Completion Time for Required Action B.3 establishes a 10-day limit on the maximum time allowed for any combination of required AC power sources to be inoperable during any single contiguous occurrence of failing to meet LCO 3.8.1.a or b. For the 10-day second Completion Time to be limiting, additional unplanned failures would be required. Since Condition B is used to support planned maintenance, normal work control practices would be in place to protect the remaining operable distribution subsystems. As a result, such a scenario is highly unlikely. However, it should be noted that while in this condition each of the remaining three 4.16 kV emergency buses will have their standby emergency source and two sources of offsite power operable. If one or both sources of offsite power are lost to an additional 4.16 kV emergency bus, then Condition E is entered which requires restoration of all but one offsite circuit to operable status within 24 hours.
Condition B is modified by two notes. Note 1 only allows this Condition to be used when the opposite unit is in Mode 4 or 5. For example, when two offsite circuits are inoperable, due to one Unit 1 BOP circuit path and the DG associated with the downstream 4.16 kV emergency bus inoperable, while Unit 1 is in Mode 1, 2, or 3, Condition I (Enter LCO 3.0.3) of Unit 2 Specification 3.8.1 must be entered and the associated Required Actions performed. Note 2 prevents Condition B from being entered coincident with Condition A (the SAT and UAT feeds to the operable BOP circuit path shall both be operable). The Unit 1 BOP buses 1C and 1D are supplied from the Unit 1 SAT and UAT. Inoperability of the Unit 1 SAT or UAT, as provided for in Condition A, would result in the loss of redundancy of offsite power to the operable BOP bus if Condition A and B were allowed to be entered coincidentally. Elimination of the second Completion Time of Required Action B.3 does not impact the applicability of these Notes.
The Reactor Oversight Process monitors the availability of mitigating systems, including the AC electrical distribution system. Such frequent, repeated failures or extended unavailability of the AC electrical distribution system would be reported to the NRC and this represents a strong

RA-19-0089 Enclosure Page 7 of 11 disincentive to such operation. Additionally, 10 CFR 50.65 (a)(1), "Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, (the Maintenance Rule) requires a comprehensive program which provides much greater assurance of safe plant operation than the second Completion Times in the TS.
Based on the above, the second Completion Time for Required Action B.3 is not required.
* TS 3.8.1 Required Action C.3, One offsite circuit inoperable for reasons other than Conditions A or B.
This change is the same as the change made by TSTF-439 to TS 3.8.1, Required Action A.3.
In each case the second completion time is associated with the inoperability of one offsite circuit. BSEP Condition C includes the qualifier that the offsite circuit is inoperable for reasons other than Conditions A or B. Due to the shared configuration of the BSEP electrical distribution system, BSEP Conditions A and B are plant specific and were included in the TSs to allow sufficient time to perform maintenance on the opposite, shutdown unit without placing an operating unit in an unduly restrictive Completion Time. Therefore, the justification provided in TSTF-439 for "AC Sources - Operating (BWRs and PWRs)" is applicable to the BSEP change.
Based on the above, the second Completion Time for Required Action C.3 is not required.
* TS 3.8.1 Required Action D.5, One DG inoperable for reasons other than Condition B.
This change is the same as the change made by TSTF-439 to TS 3.8.1, Required Action B.4.
In each case the second completion time is associated with the inoperability of one DG. BSEP Condition D includes the qualifier that the DG is inoperable for reasons other than Condition A.
Due to the shared configuration of the BSEP electrical distribution system, BSEP Condition A is plant specific and was included in the TSs to allow sufficient time to perform maintenance on the opposite, shutdown unit without placing an operating unit in an unduly restrictive Completion Time. Therefore, the justification provided in TSTF-439 for "AC Sources - Operating (BWRs and PWRs)" is applicable to BSEP.
Based on the above, the second Completion Time for Required Action D.5 is not required.
TS 3.8.7, Required Actions A.1, B.1, C.4, and D.1 Electrical Distribution System Description The onsite Class 1E AC and DC electrical power distribution system is divided into redundant and independent AC and DC electrical power distribution subsystems.
The Class 1E AC electrical distribution system is divided into four load groups. Each load group consists of a primary emergency bus, its downstream secondary emergency bus, 120 VAC vital bus, and transformers and interconnecting cables. The buses associated with each of the four load groups are defined as follows:
* Load group E1 consists of 4.16 kV bus E1, 480 V bus E5, and 120 VAC vital bus 1E5.
* Load group E2 consists of 4.16 kV bus E2, 480 V bus E6, and 120 VAC vital bus 1E6

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* Load group E3 consists of 4.16 kV bus E3, 480 V bus E7, and 120 VAC vital bus 2E7.
* Load group E4 consists of 4.16 kV bus E4, 480 V bus E8, and 120 VAC vital bus 2E8.
The E1 and E2 load groups are supplied from Unit 1 balance of plant (BOP) buses and primarily serve Unit 1 loads. The E3 and E4 load groups are supplied from Unit 2 BOP buses and primarily serve Unit 2 loads. In some instances, loads associated with one unit are supplied from the opposite unit's load group buses.
Each primary emergency bus (4.16 kV emergency bus) has access to two offsite sources of power via a common circuit path from its associated upstream BOP bus (master/slave breakers and interconnecting cables). In addition, each 4.16 kV emergency bus can be provided power from an onsite diesel generator (DG) source. The upstream BOP bus associated with each 4.16 kV emergency bus is normally connected to the main generator output via the unit auxiliary transformer. During a loss of the normal power source to the 4.16 kV BOP bus, the preferred source supply breaker attempts to close. If all offsite sources are unavailable, the affected 4.16 kV emergency bus is isolated from its associated upstream 4.16 kV BOP bus and the onsite emergency DG will supply power to the 4.16 kV emergency bus. Control power for each 4.16 kV emergency bus is supplied from a Class 1E battery with manual transfer capability to another Class 1E battery.
The secondary plant distribution system includes 480 VAC emergency buses E5, E6, E7, and E8 and associated motor control centers (MCCs), transformers, and interconnecting cables.
Secondary emergency buses E5, E6, E7, and E8 are supplied from primary emergency buses E1, E2, E3, and E4, respectively. Control power for each 480 VAC emergency bus is supplied from a Class 1E battery with manual transfer capability to another Class 1E battery.
The 120 VAC vital buses 1E5, 1E6, 2E7, and 2E8 are arranged in four load groups and are powered from secondary emergency buses E5, E6, E7, and E8, respectively.
There are two independent 125/250 VDC electrical power distribution subsystems consisting of the necessary batteries, chargers and distribution network to satisfy the design separation and redundancy criteria for the site. Each battery contains its own dedicated charger. The loss of any single piece of equipment in the DC distribution system will not prevent the containment isolation system or the core standby cooling systems from performing their intended functions.
This single piece of equipment lost can be any component including a battery, charger, breaker, distribution center, interconnecting wiring or cabling.
* TS 3.8.7 Required Action A.1, One AC electrical power distribution subsystem inoperable for planned maintenance due to either inoperable load group E1 bus(es) or inoperable load group E2 bus(es). (Unit 2)
Required Action B.1, One or more AC electrical power distribution subsystems inoperable for reasons other than Condition A.
As discussed above, the E1 and E2 load groups are supplied from Unit 1 BOP buses and primarily serve Unit 1 loads. The E3 and E4 load groups are supplied from Unit 2 BOP buses and primarily serve Unit 2 loads. TS 3.8.7, Condition A, was established to allow for maintenance on an electrical power distribution subsystem primarily associated with the opposite, shutdown unit without placing an operating unit in an unduly restrictive Completion

RA-19-0089 Enclosure Page 9 of 11 Time. With one Unit 2 AC electrical power distribution subsystem inoperable, the remaining AC electrical power distribution load groups are capable of supporting the minimum safety functions necessary to shut down the operating reactor and maintain both reactors in a safe condition, assuming no single failure in the remaining AC electrical power distribution load groups. If Unit 1 is in Mode 1, 2, or 3, then both the Unit 1 and Unit 2 Required Action B.1 of TS 3.8.7 requires restoration of the associated AC electrical power distribution subsystem within 8 hours of the inoperability. A similar discussion applies with Unit 1 operating and Unit 2 shutdown.
The second Completion Time for Required Action A.1 establishes a 176-hour limit on the maximum time allowed for any combination of required distribution subsystems to be inoperable during any single contiguous occurrence of failing to meet the LCO. For the 176-hour second Completion Time to be limiting, entry into and out of Condition A and Condition B must occur.
This scenario would assume the loss of AC electrical power distribution subsystems multiple times, but with none of the overlapping inoperabilities lasting more than 8 hours (Condition B).
Since Condition A is used to support planned maintenance on AC electrical distribution subsystems, normal work control practices would be in place to protect the remaining operable distribution subsystems. As a result, such a scenario is highly unlikely and would be further limited by the short Completion Time of Required Action E.1 (Be in Mode 3 within 12 hours).
Additionally, any overlapping inoperabilities that result in a loss of safety function requires entry into LCO 3.0.3 per TS 3.8.7, Condition F.
Condition B is associated with inoperabilities that are not the result of maintenance on an electrical power distribution subsystem primarily associated with the opposite, shutdown unit (either both units are operating or the affected subsystem is primarily associated with the unit).
The second Completion Time for Required Action B.1 establishes a 176-hour limit on the maximum time allowed for any combination of required distribution subsystems to be inoperable

RA-19-0089 Enclosure Page 10 of 11 during any single contiguous occurrence of failing to meet the LCO. For the 176-hour second Completion Time to be limiting, entry into and out of Condition B must occur. This scenario would assume the loss of AC electrical power distribution subsystems multiple times, but with none of the overlapping inoperabilities lasting more than 8 hours (Condition B). Such a scenario is highly unlikely and would be further limited by the short Completion Time of Required Action E.1 (Be in Mode 3 within 12 hours). Additionally, any overlapping inoperabilities that result in a loss of safety function requires entry into LCO 3.0.3 per TS 3.8.7, Condition F.
The Reactor Oversight Process monitors the availability of mitigating systems, including the AC electrical distribution system. Such frequent, repeated failures or extended unavailability of the AC electrical distribution system would be reported to the NRC and this represents a strong disincentive to such operation. Additionally, the Maintenance Rule requires a comprehensive program which provides much greater assurance of safe plant operation than the second Completion Times in the TS.
Based on the above, the second Completion Time for Required Actions A.1 and B.1 are not required.
* TS 3.8.7 Required Action C.4, One or more DC electrical power distribution subsystems inoperable due to loss of Normal DC sources.
Required Action D.1, One or more DC electrical power distribution subsystems inoperable for reasons other than Condition C.
TS 3.8.7, Conditions C and D, are applicable to inoperability of DC electrical power distribution subsystems due to loss of a normal DC source or for other reasons. Appropriate Required Actions are established based on the cause of the inoperability. In either case, a 176-hour limit on the maximum time allowed for any combination of required distribution subsystems to be inoperable during any single contiguous occurrence of failing to meet the LCO is established.
With one or more DC electrical power distribution subsystems inoperable (Condition C or Condition D), the remaining DC electrical power distribution subsystem(s) are capable of supporting the minimum safety functions necessary to shutdown the reactor and maintain it in a safe shutdown condition, provided safety function is not lost and assuming no single failure.
Therefore, for the 176-hour second Completion Time to be limiting, entry into and out of Condition C or D must occur. This scenario would assume the loss of DC electrical power distribution subsystems multiple times. Such a scenario is highly unlikely and would be further limited by the short Completion Time of Required Action F.1, which requires entry into LCO 3.0.3 if inoperablilites result in a loss of function.
The Reactor Oversight Process monitors the availability of mitigating systems, including the DC electrical distribution system. Such frequent, repeated failures or extended unavailability of the DC electrical distribution system would be reported to the NRC and this represents a strong disincentive to such operation. Additionally, the Maintenance Rule requires a comprehensive program which provides much greater assurance of safe plant operation than the second Completion Times in the TS.
Based on the above, the second Completion Time for Required Actions C.4 and D.1 are not required.

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