RS-06-060, Additional Information Supporting the License Amendment Request to Extend the Completion Times Related to Technical Specifications Associated with Residual Heat Removal Service Water, Diesel Generator Cooling Water and
| ML061640435 | |
| Person / Time | |
|---|---|
| Site: | LaSalle  |
| Issue date: | 06/12/2006 |
| From: | Bauer J Exelon Generation Co, Exelon Nuclear |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| RS-06-060 | |
| Download: ML061640435 (15) | |
Text
RS-06-060 10 CFR 50.90 June 12, 2006 U. S. Nuclear Regulatory Commission ATTN : Document Control Desk Washington, D. C. 20555 LaSalle County Station, Units 1 and 2 Facility Operating License Nos. NPF-1 1 and NPF-1 8 NRC Docket Nos. 50-373 and 50-374 Subject :
Additional Information Supporting the License Amendment Request to Extend the Completion Times Related to Technical Specifications associated with Residual Heat Removal Service Water, Diesel Generator Cooling Water and the Opposite Unit Division 2 Diesel Generator References :
1. Letter from J. A. Bauer (Exelon Generation Company, LLC) to U.S. NRC, "Request for a License Amendment to Extend the Completion Times Related to Technical Specifications associated with Residual Heat Removal Service Water, Diesel Generator Cooling Water and the Opposite Unit Division 2 Diesel Generator," dated April 13, 2005 2. U.S. NFIC to C. M. Crane (Exelon Generation Company, LLC), "LaSalle County Power Station, Units 1 and 2 - Request for Additional Information Related to Amendment Request," dated December 7, 2005
- 3. Letter from J. A. Bauer (Exelon Generation Company, LLC) to U.S. NRC, "Additional Information Supporting the License Amendment Request to Extend the Completion Times Related to Technical Specifications associated with Residual Heat Removal Service Water, Diesel Generator Cooling Water and the Opposite Unit Division 2 Diesel Generator," dated December 22, 2005 I V wm~
I %I-L& ~
- 4. Summary of March 22, 2006, NRC Public Meeting, "Meeting with Exelon Regarding Additional Information Needed to Support License Amendment Request for Completion Time Extension for the Core Standby Cooling System," dated April 24, 2006 In Reference 1, Exelon Generation Company, LLC, (EGC), requested an amendment to Appendix A, Technical Specifications (TS), of Facility Operating License Nos. NPF-1 1 and NPF-1 8 for LaSalle County Station (LSCS) Units 1 and 2 respectively. Specifically, the
June 12, 2006 U. S. Nuclear Regulatory Commission Page 2 proposed changes modify the Completion Time for TS Sections 3.7.1, "Residual Heat Removal Service Water (RHRSW) System," 3.7.2, "Diesel Generator Cooling Water (DGCW) System,"
and 3.8.1, "AC Sources - Operating." The proposed extensions of the Completion Times will only be used during the specified unit refueling outages.
In Reference 2, the NRC requested additional information to complete the review of the license amendment. This letter requested further information regarding what functions would be affected during each phase of the repairs, what compensatory measures would be in place during each phase of the repairs including any regulatory commitments established to implement the compensatory actions, and why the proposed change was not requested on a permanent basis.
In Reference 3, EGC provided the additional information requested.
A public meeting was held between EGC and the NRC regarding the subject License Amendment Request on March 22, 2006 (Reference 4). During this meeting, the NRC requested additional information to support their review of the License Amendment Request.
Based on the discussions held during this meeting and the additional compensatory actions requested by the NRC, LaSalle County Station (LSCS) has elected to alter the location of two of the non-code mechanical line stops from the original locations and add a temporary jumper (i.e., a temporary line) to support the functionality of the outage unit's Division 2 Diesel Generator (DG). The revised locations for the non-code mechanical line stops will also facilitate installation of additional American Society of Mechanical Engineers (ASME) code isolation valves (one per unit) that will enhance the current Core Standby Cooling System (CSCS) reliability improvement effort and will also facilitate any future maintenance on CSCS strainer backwash lines or valves.
Note that the addition of the new isolation valves will not extend the duration of the Technical Specification Completion Time extensions previously requested in Reference 1 and the work windows are still bounded by the risk assessment performed in Attachment 5 of Reference 1 of this letter provides the requested information and a description of the change in scope from Reference 1 -
EGC has reviewed the information supporting a finding of no significant hazards consideration that was previously provided to the NRC in Attachment 1 of Reference 1. The supplemental information provided in this submittal does not affect the bases for concluding that the proposed license amendment does not involve a significant hazards consideration.
Should you have any questions concerning this letter, please contact Ms. Alison Mackellar at (630) 657-2817.
June 12, 2006 U. S. Nuclear Regulatory Commission Page 3 I declare under penalty of perjury that the foregoing is true and correct. Executed on the 12th day of June 2006.
Respectfully, Joseph A. Bauer Manager - Licensing : Response to Request for Additional Information
Question No. 1
Response
ATTACHMENT I Response to Request for Additional Information A public meeting was held between Exelon Generation Company, LLC, (EGC) and the NRCC regarding the subject License Amendment Request on March 22, 2006 (Reference 4). During this meeting, the NRC requested additional information to support their review of the License Amendment Request. Based on the discussions held during this meeting and the additional compensatory actions requested by the NRC, LaSalle County Station (LSCS) has elected to alter the location of two of the non-code mechanical line stops from the original locations and add a temporary jumper (i.e., a temporary line) to support the functionality of the outage unit's Division 2 Diesel Generator (DG) as illustrated in Figures 3 and 4. The revised locations for the non-code mechanical line stops are on the discharge piping of the outage unit's Division 2 DG cooler. These new locations are also shown in Figures 3 and 4.
Installation of the mechanical line stops at the new locations depicted in Figures 3 and 4 requires the Core Standby Cooling System (CSCS) cooling water for the outage unit Division 2 DG cooler to be temporarily routed to support continued functionality of the DG. The location of the temporary jumper for both outages is also illustrated in Figures 3 and 4. The temporary jumper will be installed in accordance with EGC's Temporary Modification program outlined in EGC procedure CC-AA-112, `Temporary Configuration Changes," and will be administratively controlled by LSCS procedure LLP 2006-002, "Unit Two - Division Two CSCS Draining," or LLP 2006-001, "Unit One - Division Two CSCS Draining."
The revised locations for the non-code mechanical line stops will also facilitate installation of additional American Society of Mechanical Engineers (ASME) code isolation valves (one per unit) that will enhance the current CSCS reliability improvement effort and will also facilitate any future maintenance on CSCS strainer backwash lines or valves. Once installed, the new isolation valves will be used to perform required maintenance on valves and preclude the need for future use of mechanical line stops. The locations of the additional isolation valves are detailed in Figures 3 and 4. (Note that the addition of the new isolation valves will not extend the duration of the Technical Specification (TS) Completion Time extensions previously requested in Reference 1 and the work windows are still bounded by the risk assessment performed in Attachment 5 of Reference 1).
The responses to the following questions are therefore based on the revised locations of the non-code mechanical line stops and consider the temporary routing of the outage unit's Division 2 DG cooling water discharge.
Address the functionality of the Division 2 Diesel Generator (DG) for both units, at all stages of the Line Stop installation and valve replacement maintenance activity.
As stated in Section 3.0 of Reference 1 and further detailed in Reference 3, the non-code mechanical line stops being used to isolate the system during specified refueling outages are being designed to the same pressure and seismic requirements as the CSCS piping and will maintain the availability of the operating unit's Division 2 CSCS system. In addition the mechanical and hydraulic characteristics of the line stop equipment used to cut the existing piping and install the mechanical line stops will be rated for at least the design pressure of the attached CSCS piping. The subject equipment will also be maintained with existing and temporary supports to ensure the affected piping system remains seismically supported during the entire maintenance activity. The mechanical/hydraulic characteristics of the line stop Page 1 of 12
ATTACHMENT 1 Response to Request for Additional Information installation equipment and the temporary supporting configuration serve as an effective system isolation point for the affected piping systems. This ensures other Division 2 CSCS system flow pats remain functional and available during all phases of the maintenance including installation and removal of the line stops, during the scheduled CSCS valve replacements, and throughout the subsequent restoration to operability.
In order to maintain cooling water flow through the outage unit's Division 2 DG cooler, the discharge piping from the outage unit will be temporarily routed such that the non-code mechanical line top can be used to isolate the CSCS discharge line.
Additional stainless steel ASME code isolation valves (one per unit), consistent with the design requirements of the system, will be installed in the DG cooling water discharge lines. Once installed, the new isolation valves will be used to perform required maintenance on valves and preclude the need for future use of mechanical line stops.
During installation of the temporary modification for the DG cooler discharge piping, the outage unit's Division 2 DG will be removed from service, not functional and inoperable. The temporary modification will be installed in accordance with the EGC Temporary Modification program and administratively controlled in accordance with LSCS procedure LLP 2006-002 (LLP 2006-001).
The temporary jumper will maintain the outage unit's Division 2 DG cooling water required flow rate and will be designed to the necessary pressure and temperature requirements of the cooling system. During the time of the jumper installation, installed plant equipment will be used for isolation boundaries. The non-code mechanical line stops as shown in Figures 3 and 4 will not be in service until the outage unit's Division 2 DG 4 restored to a functional status. Note that the outage unit's Division 3 DG will be inoperable as a result of the temporary jumper.
The line stop equipment is designed to maintain the pressure boundary of the attached piping during all phases of the installation and removal of the non-code mechanical line stop as discussed during the March 22, 2006 NRC Public Meeting (Reference 5). The affected piping systems (i.e., those piping systems where the non-code mechanical line stop will be installed) will be isolated, (i.e., no flow through the piping), during installation of the non-code mechanical line stops. The operating unit's CSCS Division 2 DG cooling water system flow path and the temporary flow path for the outage unit's Division 2 DG cooling water remain unaffected by the installation of the non-code mechanical line stops. The non-code mechanical line stops provide downstream isolation for the valves being replaced from the common Division 2 CSCS discharge.
It should be noted that the location of the outage unit's non-code mechanical line stop impacts the outage unit's Division 2 DG cooling water and Residual Heat Removal (RHR) service water strainers' backwash capability during the specific time the new Division 2 DG discharge valve is being installed. Loss of backwash capability will not impact the "functionality" of the outage unit's Division 2 DG or RHR service water for the time required to complete the valve installation. In this configuration, the operating unit's Division 2 DG will meet all design requirements except for the non-code mechanical line stop isolation boundary ; while the outage unit's Division 2 DG will remain functional.
Question No. 2 Assuming a loss of offsite power coincident with the worst-case single failure (which may be a loss of DG-0) discuss the mitigation strategy for both units assuming one unit operating and one Page 2 of 12
Response
ATTACHMENT 1 Response to Request for Additional Information unit shutdown (less than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />). [The 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> is in reference to decay heat that is present immediately following a unit shutdown].
The assumption of an additional single failure while an operating unit is in a TS Required Acton statement places LSCS in a condition that is beyond the original design basis of the plant. In general, an operating unit is required to recognize a loss of redundancy, and therefore loss of single failure tolerance, while in a Limiting Condition for Operation (LCO) Required Action.
Likewise, it is recognized that a unit in an outage is not single failure tolerant due to only one offsite and one onsite AC source being required to be operable.
TS 3.8.2, "AC Sources - Shutdown," requires the outage unit to maintain either Division 1 or Division 2 DGs OPERABLE. TS 3.8.1, "AC Sources - Operating," requires the operating unit to intain Divisions 1, 2, and 3 DGs OPERABLE and the outage unit's Division 2 DG capable of supporting the associated equipment required to be OPERABLE by Limited Condition for Operation (LCO) 3.6.4.3, "Standby Gas Treatment System," LCO 3.7.4, "Control Room Area Filtration System," and LCO 3.7.5, "Control Room Area Ventilation Air Conditioning System."
The Bases for TS 3.8.1 states that the operability of the required AC electrical power sources is consistent with the initial assumptions of the accident analyses and is based upon meeting the design bast of the unit. This includes maintaining the onsite or offsite AC sources OPERABLE during accident conditions in the event of :
a. An assumed loss of all offsite power or all onsite AC power; and b. A worst-case single failure.
TS 3.8.2 Bases states the LCO ensures the capability of supporting system necessary to avoid immediate difficulty, assuming either a loss of all off site power or a loss of all onsite (DG) power.
In general, then a unit is shutdown, the TS requirements ensure the shutdown unit has the capability to mitigate the consequences of a limited scope of postulated accidents.
Assuming another failure, in addition to the inoperable equipment due to outage maintenance activities concurrent with a loss of offsite power, places both LSCS units in a condition beyond the original design and licensing bases as documented in the LSCS Updated Final Safety Analysis Report (UFSAR). Although inoperable due to the non-code mechanical line stops, the Division 2 DGs remain functional and capable of performing their design basis function and therefore both units will essentially remain in a system configuration that has the capability to cope with the worst-case single failure.
Assumed initial DG conditions during CSCS maintenance CIA= Unit Division 1 DG OPERABLE Division 2 DG inoperable (i.e., inoperable but functional)
Division 3 DG inoperable and non-functional Operating Unit 9
Division 1 DG OPERABLE Page 3 of 12
Event 1 ATTACHMENT 1 Response to Request for Additional Information Division 2 DG inoperable (i.e., inoperable due to the use of the non-code mechanical line stops but remains fully functional and capable of performing its design basis function)
Division 3 DG OPERABLE To address the concern of a Loss of Offsite Power (LOOP) concurrent with a failure of a DG the following two events are considered ; a LOOP concurrent with failure of Division 1 DG (i.e., the common DG) and a LOOP concurrent with failure of a Division 2 DG.
Loss of Offsite Power (LOOP) concurrent with failure of Division 1 DG (common DG)
The operating unit's Division 2 DG provides design shutdown capability of the operating unit that is now shutdown due to a LOOP. The outage unit's Division 2 DG provides design capability of maintaining the outage unit in a safe shutdown condition. Either unit's Division 2 DG will supply power to the Standby Gas Treatment (SGT) system and the Control Room Filtration/Air Conditioning (CRAF) system. Division 3 remains available for Reactor Pressure Vessel (RPV) level control for the operating u The Division 2 DG loading for design accident conditions is 2580 kW as documented in UFSAR Table 8.3-1. The DG 8760-hour maintenance interval rating (i.e., the rating at which the DG is considered available based on scheduled maintenance) is 2600 kW and the 2000-hour rating is 2860 kw. This design loading includes all of the Division 2 Emergency Core Cooling System (ECCS) equipment operating in addition to certain accident mitigation loads (e.g., post Loss of Coolant Accident (LOCA) Hydrogen Recombiner loads). LSCS also has the capability to crosstie a Division 2 DG to the opposite unit in accordance with LSCS Abnormal Operating Procedure LOA-AP-101(201), "AC Power System Abnormal." This flexibility provides additional coping capability.
Event 2 LOOP concurrent with failure of a Division 2 DG The Division. 1 DG is designed to automatically start and assume the load of the first unit experiencing an undervoltage condition concurrent with an Engineered Safety Feature (ESF) signal. In this hypothetical event, the Division 1 DG will assume the load of the unit with the failure of the Division 2 DG either automatically on an undervoltage condition or manually in accordance with abnormal operating procedures. The remaining functional Division 2 DG powers all required loads on the opposite unit including the SGT system and the CRAF system.
Division 3 remains available for RPV level control for the operating unit.
Division 1 DG loading for design accident conditions is 2594 kw as presented in UFSAR Table 8.3-1. DG 8760-hour maintenance interval rating is 2600 kw and the 2000-hour rating is 2860 kw. This loading includes all the Division 1 ECCS equipment operating.
Fuel Pool and Reactor Cavity Considerations :
The outage unit will be in Mode 5 with spent fuel pod storage gates removed and water level maintained at Z! 22 ft above the RPV flange. The time to core boil, following loss of cooling, in this configuration is approximately 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br />. The capability to provide cooling to both spent fuel Page 4 of 12
pools and the outage reactor cavity from the operating unit Fuel Pool Cooling system will exist during the requested TS extended Completion Time.
Question No. 3 ATTACHMENT 1 Response to Request for Additional Information Confirm that should the tine Stop(s) fail during an event or occurrence, flooding in either room will not affect required equipment.
Response
The non-code mechanical line stops for the installation of the additional new DG cooler discharge valves (one per unit) are located in the respective units' Division 2 CSCS rooms.
These rooms have a floor elevation at 674' and are flood protected from the redundant Division 1 and 3 CSCS rooms by watertight floodwalls to an elevation of 701'. The rooms are also provided with water level alarms and duplex sump pumps. The 1(2)DG007, (RHR B/C Room Cooler Discharge), valves located in the Reactor Building raceway areas have a floor elevation of 6734" and are flood protected from the Divisional ECCS rooms by watertight floodwalls to an elevation of 6867'. These areas also have water level alarms and duplex sump pumps. These areas have approximately 1000 R3 and 5300 ft3 of unoccupied space per foot of elevation respectively. In the unlikely event that flooding were to occur, this available flood protected volume provides adequate time for the implementation of compensatory actions and ensures potential flooding does not impact redundant equipment in surrounding areas.
The integrity of the non-code mechanical line stops will be leak tested prior to cutting the existing piping systems. Damage control plugs will be pre-staged at each valve location in the unlikely event the mechanical line stops were to become ineffective during maintenance evolutions when the CSCS valve is physically removed. Installation of damage control plugs can be accomplished since the maximum operating pressure at the location of CSCS valve replacement is estimated to be less than 16 psig. Mechanical sealing bands will also be pre-staged at each CSCS valve scheduled for removal. These bands will be capable of isolating partially cut lines in the event of a mechanical line stop failure. In addition, each area/room where the CSCS valves are scheduled to be replaced will be verified to have operable sump pump(s) during the entire CSCS valve replacement work window.
These design features, compensatory actions, and the inherent robust design of the mechanical line stops are considered adequate to ensure that hooding does not occur that could impact redundant Systems Structures and Components (SSCs) during the planned CSCS valve replacements.
Question No. 4 Specifically address the proposed compensatory measures during the line stop installation, line stop removal, and valve replacements. This discussion should be at a sufficient level of detail to address system/major component impacts of these proposed measures.
Page 5 of 12
Response
As described in Reference 1, the use of the non-code mechanical line stops ensures an isolation capability consistent with the pressure and seismic qualifications of the existing piping systems. Installation of the mechanical line stops will impact the following design functions:
Outage Unit Fuel Pool Emergency Pump test line flow capability
" CSCS cooling water flow to Division 2 ECCS area cooler Division 2 DG cooling water flow capability (temporary jumper maintains cooling water functionality)
Division 2 DG cooling water strainer backwash capability Division 2 RHR Service Water strainer backwash capability Operating Unit ATTACHMENT 1 Response to Request for Additional Information Division 2 CSCS (i.e., inoperable due to the use of the non-code mechanical line stops but remains fully functional and capable of performing their design basis function)
In addition to the compensatory actions described in the response to Question 3, protected pathways will be established for SSCs that have been identified as essential to ensure key safety functions are maintained.
The designated protected pathways listed below will be administratively controlled in accordance with LSCS procedure LLP 2006-002 (LLP 2006-001) using physical barricades to segregate protected equipment, poling signs and enhancing plant personnel awareness through pre-job briefings and outage communication bulletins. Protection of the offsite power lines will include physical barricades described above. Communications through the EGC Nuclear Duty Officer, the generation dispatcher and the Transmission Owner (i.e.,
Commonwealth Edison Company), in accordance with approved procedures and established protocol, will specify that the subject lines are considered protected to prevent inadvertent line removal by the Transmission Owner from the transmission end. The LSCS switchyard is a segregated fenced area with access controlled by the Operations Shift Manager and the LSCS Security Department. To assure that offsite power remains protected during this work, no switchyard work will be authorized on the operating unit's ring bus and designated travel paths and protected pathways will be established in the switchyard for both the operating and outage unit's ring bus. In addition, no switching activities will be allowed during the subject maintenance window and the outage unit ring bus will be controlled such that the loss of a single ring bus breaker will not cause a subsequent loss of offsite power to the outage unit.
Protected Pathways Outage Unit Division 1 DG Division 2 DG (including the temporary return flow path)
Three Offsite Power Lines (two offsite lines for operating unit's ring bus and at least one line available on outage unit's ring bus)
Page 6 of 12
Operating Unit ATTACHMENT I Response to Request for Additional Information Division 1 DG Division 2 DG Division 3 DG Three Offsite Power lines (two offsite power lines for the operating unit's ring bus and at least one power line available on the outage unit's ring bus)
Page 7 of 12
ATTACHMENT 1 Response to Request for Additional Information Note : LaSalle has only one lake. To sinTl~,y this diagram, the single lake is shown multiple times.
Und 2 DO 2 LOWS Figure 1 Mechanical System Configuration Page 8 of 12
ATTACHMENT 1 Response to Request for Additional Information (PONT AC h1 DPOIN' BRA'DWYOD PLAO 10103 Wzora 5T.EATOR DREMEN 12 KV YARD Ks 161
- PC1N7AC NIIDPO'NT; PU1N0 BRAIDW00D Figure 2 Electrical System Configuration Page 9 of 12
ATTACHMENT 1 Response to Request for Additional Information FP Emergency MU Pump 1 B 1FC03PB HPCS D/G Cooling Pump 1E22-0002 Temporary Line Stop (Previous location)
Page 10 of 12 Strainer Backwash Line Figure 3 Unit 1 Simplified Sketch of Division 2/3 CSCS (Does not show all components)
Temporary Line Stop (new location)
FP Emerg. MU Pump 2B 2FC03PB HPCS D/G Cooling Pump 2E22-0002 ATTACHMENT 1 Response to Request for Additional Information Temporary Line Stop (Previous location)
Temporary Line Figure 4 Unit 2 Simplified Sketch of Division 2/3 CSCS (Does not show all components)
Page 1 1 of 12 Temporary Line Stop (new location)
References:
ATTACHMENT 1 Response to Request for Additional Information 1. Letter from J. A. Bauer (Exelon Generation Company, LLC) to U.S. NRC, "Request for a License Amendment to Extend the Completion Times Related to Technical Specifications associated with Residual Heat Removal Service Water, Diesel Generator Cooling Water and the Opposite Unit Division 2 Diesel Generator," dated April 13, 2005
- 2. U.S. NRC to C. M. Crane (Exelon Generation Company, LLC), "LaSalle County Power Station, Units 1 and 2 - Request for Additional Information Related to Amendment Request," dated December 7, 2005 3.
Letter from J. A. Bauer (Exelon Generation Company, LLC) to U.S. NRC, "Additional Information Supporting the License Amendment Request to Extend the Completion Times Related to Technical Specifications associated with Residual Heat Removal Service Water, Diesel Generator Cooling Water and the Opposite Unit Division 2 Diesel Generator," dated December 22, 2005 4. Summary of March 22, 2006, NRC Public Meeting, "Meeting with Exelon Regarding Additional Information Needed to Support License Amendment Request for Completion Time Extension for the Core Standby Cooling System," dated April 24, 2006 Page 12 of 12