ML18100A516
| ML18100A516 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 08/04/1993 |
| From: | Hagan J Public Service Enterprise Group |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| Shared Package | |
| ML18100A517 | List: |
| References | |
| LCR-93-01, LCR-93-1, NLR-N93075, NUDOCS 9308110132 | |
| Download: ML18100A516 (11) | |
Text
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Public Service Electric and Gas Company Joseph J. Hagan Public Service Electric and Gas Company P.O. Box 236, Hancocks Bridge, NJ 08038 609-339-1200 Vice President - Nuclear Operations AUG 041993 NLR-N93075 LCR 93-01 United States Nuclear Regulatory Commission Document Control Desk Washington, DC 20555 Gentlemen:
REQUEST FOR AMENDMENT A.C. POWER REQUIREMENTS DURING SWITCHYARD MODIFICATIONS SALEM GENERATING STATION UNIT NO. 2 FACILITY OPERATING LICENSES DPR-75 DOCKET NOS. 50-311 In accordance with the requirements of 10CFR50.90, Public Service Electric and Gas Company (PSE&G) hereby transmits a request for amendment of Facility Operating License DPR-75 for Salem Unit No. 2.
Pursuant to the requirements of 10CFR50.91(b) (1), a copy of this request for amendment has been sent to the State of New Jersey.
The proposed amendment would modify the Technical Specifications for the A.C. Power Sources, on a one time basis, to allow connection of two new 500/13.8 kv transformer bus sections as part of the Salem Switchyard project.
The change would extend the Allowed Outage Time for one inoperable offsite power circuit from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 120 hours0.00139 days <br />0.0333 hours <br />1.984127e-4 weeks <br />4.566e-5 months <br /> for two separate action.statement entries to allow switchyard modifications.
It would also exempt the emergency diesel generators from repetitive testing during the action statement entries.
The modifications are planned for the Unit 1 11th refueling outage, beginning in October, 1993. includes the description and justification for the proposed changes, including PSE&G's Determination of No Significant Hazards Consideration. contains the Technical Specification pages revised with pen and ink changes.
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Docum~nt Control Desk NLR-N93075 Affidavit Attachments ( 2) c Mr. J. c. Stone Licensing Project Mr. s. Barr Manager Senior Resident Inspector, Acting Mr. T. Martin, Administrator Region I Mr. K. Tosch, Manager IV Bureau of Nuclear Engineering Department of Environmental Protection CN 415 Trenton, New Jersey 08625 AUG 041993
NLR-N93075 A'ITACHMENT 1
1.0 DESCRIPTION
OF PROPOSED CHANGES Add two footnotes to the Salem Generating Station (SGS) Unit 2 Technical Specification 3.8.1.1, Action a., as follows:
Entry into Action Statement 3.8.1.1.a during the Unit 1 11th refueling outage for the installation of bus connections for 500/13.8 kv Station Power Transformers (SPT's) T3 or T4 does not require diesel testing.
One offsite power circuit may be inoperable for 120 hours0.00139 days <br />0.0333 hours <br />1.984127e-4 weeks <br />4.566e-5 months <br /> for installation of bus connections for 500/13.8 kv SPT T3 or T4 during the Unit 1 11th refueling outage.
The first note would prevent repetitive diesel starts (once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />) required by the present action statement for one inoperable offsite power circuit.
The second note would extend the Allowed Outage Time (AOT) from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 120 hours0.00139 days <br />0.0333 hours <br />1.984127e-4 weeks <br />4.566e-5 months <br />.
These notes would apply only during connection of the two new 500/13.8 kv station power transformers.
2.0 REASON AND JUSTIFICATION FOR THE PROPOSED CHANGES 2.1 Description of Switchyard Modification The bus connections for the new station power transformers are planned for installation during the Unit 1, 11th refueling outage (lRll), and are intended to increase the operational flexibility and overall reliability of offsite power at SGS.
The two existing 500/13.8 kv station power transformers (Tl and T2) each supply offsite power to SGS Unit 1 and 2.
The attached UFSAR Figure 8.3-2 is a simplified illustration of the SGS ring bus arrangement.
The switchyard modification would install 500 kv and 13 kv bus to allow the future connection of the new 500/13.8 kv transformer T3 and a similar connection for the new 500/13.8 kv transformer T4.
The work scope also includes the addition of 13 kv disconnect switches and a new key interlock system.
The attached Design Change Pictogram shows the bus sections and switches that would be added by the modification.
Tl (T2) must be deenergized to allow the installation of the T3 (T4) bus.
The design change instructions call for extensive prestaging to minimize the time that each transformer must be deenergized.
The following is a summary of the work to be performed on the Tl and T3 bus
NLR-N93075 sections; similar modifications are planned for the T2 and T4 side.
500 kv section 1 and Tl will be de-energized and disconnected from the 13 kv switchgear.
Personnel grounds will be installed on Tl and the de-energized 13 kv bus.
The 13 kv bus section between Tl and the 13 kv bus, and its concrete support structure, will be removed.
Preassembled switch structure and disconnect switch 1T50 will then be installed, along with 13 kv bus to facilitate a new 13 kv bus tie.
Prestaged 500 kv bus sections will also be installed between 500 kv section 2 and new circuit switcher 3T60.
This will allow future energization of T3.
Post-modification testing will be performed, including megger testing and verification of the functionality of the interlocks, then Tl will be energized and returned to service.
2.2 Reason for the Proposed Changes When an existing 500/13.8 kv transformer is deenergized, one of the off site power circuits required by Technical Specification 3.8.1.1 (applicable in MODES 1, 2, 3 and 4) is inoperable.
Therefore, the modification cannot be performed without voluntary Technical Specification action statement entries, unless both units are in cold shutdown or refueling modes.
Technical Specification 3.8.1.1, Action a requires unit shutdown if one offsite power circuit is inoperable for greater than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
According to the installation schedule, each transformer is expected to be deenergized for 68 hours7.87037e-4 days <br />0.0189 hours <br />1.124339e-4 weeks <br />2.5874e-5 months <br /> during the Unit 1 eleventh refueling outage.
The extension to a 120 hour0.00139 days <br />0.0333 hours <br />1.984127e-4 weeks <br />4.566e-5 months <br /> Allowed Outage Time (AOT) is being proposed for the operating unit in order to avoid a forced shutdown in the event that the installation time exceeds 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
Entry into Action statement 3.8.1.1.a presently requires repetitive testing of each of the three Emergency Diesel Generators (EDG's) until the Action statement is exited.
If these tests are performed during connection of the transformers, approximately 50 to 60 diesel starts would be required.
Because the switchyard activities do not affect diesel operability, and the diesels are periodically demonstrated operable during normal surveillance testing, testing while in an action statement is not necessary to ensure diesel operability.
Therefore, this proposed change would not require diesel testing due to entering the action statement for a deenergized transformer.
2.3 PRA Considerations for the Operating Unit The Salem Probabilistic Risk Assessment (PRA) model was used to estimate the effect of the AOT extension on core damage probability.
The PRA compared two cases for each transformer
NLR-N93075 connection.
The first case calculated the probability of core damage resulting from manually shutting down the reactor upon expiration of the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> action statement, with one station power transformer de-energized.
The second case calculated the probability of core damage resulting from continuing to operate for 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> beyond the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> action statement, with one station power transformer de-energized.
In each case, the three Emergency Diesel Generators (EDG's) are assumed to be available, consistent with Technical Specification requirements.
For the connection of transformer T3, Tl is de-energized.
In this configuration, T2 and Unit 3 (gas turbine) are the available sources of power to the group (nonvital) busses in the PRA model.
T2, Unit 3 and the three EDG's are the available sources of power to the vital busses.
The Unit 3 gas turbine will be demonstrated operable within 14 days prior to the start of the refueling outage, and will be maintained available for the duration of the T3 connection activities.
The probability of core damage for case 1 (manual shutdown at 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />) is calculated to be a minimum of 1.37 E-6.
For case 2 (operate for an additional 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />), the calculated core damage probability is 3.09 E-7.
The increase in core damage probability for the 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> period with Tl out of service, vs. 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> of operation with Tl in service (i.e., the base case PRA core damage probability), is 4.51 E-8.
For the connection of transformer T4, T2 is de-energized.
In this configuration, Tl is the available source of power to the group busses in the PRA model; Tl and the three EDG's are the sources of power to the vital busses.
The probability of core damage for case 1 (manual shutdown) is calculated to be a minimum of 1.37 E-6.
For case 2 (operate for an additional 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />),
the calculated core damage probability is 3.25 E-7.
This value is slightly higher than the probability for case 2 with Tl deenergized (3.09 E-7), primarily because the Unit 3 gas turbine generator must be isolated from the group and vital busses to allow the connection of T4.
The increase in core damage probability for the 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> period with Tl out of service, vs.
the base case core damage probability during 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> of operation, is 6.09 E-8.
The PRA results support the conclusion that extending the action statement time from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 120 hours0.00139 days <br />0.0333 hours <br />1.984127e-4 weeks <br />4.566e-5 months <br /> poses less risk to the operating unit than manually shutting down the unit if the allowable 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> action time is exceeded.
They also support the conclusion that the total increase in core damage probability associated with the proposed action statement time increase is very low.
2.4 Loads on Energized Station Power Transformer The nonvital loads, including the Reactor Coolant Pumps (RCP's) are powered by the group busses.
During power operation, the
NLR-N93075 four group busses are normally supplied with power from the unit's main generator via the Auxiliary Power Transformer (APT).
Group bus loads are powered by the station power transformers when the unit's main generator is not available.
In the event of a unit trip, the Unit 2 group busses would fast transfer from the APT to the 13.8/4.16 kv SPTs.
The fast transfer of group bus loads would place a loading transient on the 13.8/4.16 kv SPT's, and ultimately the 500/13.8 kv SPT.
In order to reduce the severity of a potential fast transfer of the operating unit loads, the base load on the energized 500/13.8 kv SPT will be reduced by minimizing group bus loads for the shutdown unit, as discussed in Section 2.5.
2.5 Considerations for the Shutdown Unit The 500/13.8 kv SPT's will not be deenergized for switchyard project implementation until after Unit 1 has entered MODE 5 (cold shutdown) for its eleventh refueling outage.
Technical Specification LCO 3.8.1.2 requires one offsite power circuit in MODES 5 and 6, and this request is therefore applicable only to Unit 2.
However, PSE&G recognizes the concerns relative to loss of power events during shutdown, particularly during switchyard activities.
In accordance with our outage management program, the modifications have been scheduled such that the risk of loss of A.C. power is reduced during the Unit 1, 11th refueling outage.
By procedure, a total of approximately 48 MVA of large 4.16 kv balance of plant loads will be secured as Unit 1 reduces power.
These loads include the condensate pumps, heater drain pumps circulating water pumps and turbine auxiliaries cooling pumps.
The (4) 4650 KVA reactor coolant pumps, which are also powered from the group busses, will be secured prior to deenergizing Tl.
Removal of these loads would minimize the base load on the energized 500/13.8 kv SPT in the event of a group bus transfer from the operating unit's auxiliary power transformer to the SPT.
With the reactor coolant system pumps secured in MODE 5, at least one RHR pump will be placed in operation for decay heat removal.
Two Residual Heat Removal (RHR) subsystems, with their Emergency Diesel Generators (EDG's), and two nuclear service water headers will be operable, to provide redundant decay heat removal capability without relying solely on offsite power.
No reactor draindown, and therefore no mid-loop operation, or fuel movement in the core will be performed while the 500/13.8 kv transformer is de-energized.
The second transformer connection (T2 to T4) is scheduled coincident with the Unit 1 reactor defueled.
In this configuration, decay heat removal for the spent fuel pool is the key safety function of concern.
The methods of spent fuel pool cooling used at SGS Unit 1 are:
- 1) The Spent Fuel Pool Cooling System (SFPCS) for Unit 1; 2) the SFPCS for Unit 2, using a cross
NLR-N93075 tie to provide cooling to the Unit 1 pool; 3) a portable diesel driven pump, taking suction from either the Primary Water Storage Tank or the Refueling Water Storage Tank (RWST); and 4) the RHR system, which may be used if the refueling cavity is flooded and connected to the spent fuel pool.
Before the transformer is deenergized, the unit will be defueled in a configuration consistent with existing operating procedures:
a minimum of one operable offsite power circuit and two operable Emergency Diesel Generators (EDG's), a minimum spent fuel pool water level of 23 feet above the top the irradiated fuel assemblies, a maximum pool water temperature of 150 degrees F, and at least two independent means of spent fuel pool cooling.
Because the portable diesel driven pump is independent of normal offsite or EDG supplied power, it will be verified to be available prior to deenergizing the transformer with Unit 1 defueled.
This would facilitate recovery actions in the unlikely event of a total loss of spent fuel pool cooling due to loss of A.C. power during the switchyard modifications.
2.6 Controls on Switchyard Activities Operation and tagging of switchyard equipment is the responsibility of the Salem Operations department.
Control of switchyard equipment includes the use of keys for switches and breakers.
Direct communication between the electric system operator and the nuclear shift supervisor is established during switchyard equipment operation.
The switchyard activities will be performed in accordance with OSHA requirements, including minimum clearance distances for equipment and personnel.
These controls are responsive to the concerns identified in NRC Information Notice 91-81, "Switchyard Problems that Contribute to Loss of Offsite Power."
In addition, cognizant PSE&G personnel will maintain a presence in the switchyard during the modification, to provide an added level of supervision and control.
2.7 Basis for Proposed Diesel Testing Exceptions The current action statement for one inoperable off site power circuit would require each of the three Unit 2 diesels to be started within one hour and once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter.
The proposed change would not require-testing due to the action statement entry during the installation of the bus connections.
Elimination of the requirement for repetitive diesel starts in an action statement is consistent with the NRC's position as given in the Westinghouse Standard Technical Specifications (NUREG-1431).
A 500/13.8 kv Station Power Transformer will not be removed from service unless the three Unit 2 diesels are operable.
Each EDG will have been demonstrated operable by test within a maximum of 31 days prior to de-energizing the transformer.
The switchyard configuration for the transformer connections will not introduce
NLR-N93075
- a common failure mode for the EDG 1 s or 4.16 kv vital busses.
Based on adequate demonstration of EDG operability and no common failure mode, PSE&G believes the exception to repetitive diesel testing is justified.
This is consistent with the improved standard Technical Specifications approved by NRC via NUREG 1431.
3.0 DETERMINATION OF NO SIGNIFICANT HAZARDS CONSIDERATION The proposed changes to Technical Specification 3.8.1.1 for Salem Unit No. 2:
(1) do not involve a significant increase in the probability or consequences of an accident previously evaluated.
The proposed change to the Salem Generating Station (SGS) Unit 2 Technical Specifications would allow extension of the action statement 3.8.1.1.a for one inoperable offsite power circuit, from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 120 hours0.00139 days <br />0.0333 hours <br />1.984127e-4 weeks <br />4.566e-5 months <br />.
This extension would apply to two separate action statement entries to enable bus connections for new 500/13.8 kv transformers as part of the Salem Switchyard Project.
The proposed change would also allow the action statement entries without repetitive testing of the Emergency Diesel Generators.
The Salem Probabilistic Risk Assessment was used to compare the impact of extending the action time vs. the impact of manual reactor shutdown on core damage probability.
The PRA results support two conclusions: 1) the risk of operating SGS Unit 2 for 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> beyond the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> action time is less than the risk of shutting down the unit upon expiration of the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> clock; and
- 2) the increase in core damage probability associated with the increased action time is insignificant.
With one 500/13.8 kv transformer deenergized, and Unit 1 in a refueling outage, Unit 1 plant loads will be supplied by the one energized transformer.
With Unit 2 operating, its plant electrical loads will be powered from the Unit 2 main generator via the Auxiliary Power Transformer (APT).
In the event of a Unit 2 trip, the group bus (nonvital) loads would be transferred to the one 500/13.8 kv transformer.
In order to minimize the effects of the potential load transfer, a 500/13.8 kv transformer will not be deenergized until the large Unit 1 balance of plant loads (i.e., condensate pumps, circulating water pumps, heater drain pumps and turbine auxiliaries cooling pumps), and reactor coolant pumps are secured.
This will reduce the base load on the 500/13.8 kv transformer to accommodate the potential Unit 2 load transfer.
The 500/13.8 kv transformers will not be removed from service unless the three Unit 2 EDG 1 s are operable.
These EDG 1 s will be available to provide vital power in the event of a loss of offsite power.
The switchyard activities performed during the Unit 1 refueling outage are scheduled such that redundant decay heat removal and A.C. power capability will be maintained.
The modifications will
NLR-N93075
- be performed in accordance with OSHA requirements relative to minimum clearance distances for energized equipment, and will be subject to the operations department administrative controls for switchyard equipment.
The proposed change would also exempt the Unit 2 EDG's from repetitive testing during the action statement entries.
The Unit 2 EDG's will have been successfully tested to demonstrate operability within a maximum of 31 days prior to deenergizing a 500/13.8 kv transformer.
Implementation of the switchyard modifications would not challenge EDG operability.
This proposed change is consistent with the Improved Standard Technical Specifications as approved by NRC in NUREG 1431, which do not require EDG testing with an inoperable offsite circuit.
Based on the above, the proposed changes do not involve a significant increase in probability or consequences of an accident.
(2) do not create the possibility of a new or different kind of accident from any accident previously evaluated.
The proposed change would extend the allowable time that SGS Unit 2 may operate with one inoperable offsite power circuit. It would not allow the plant to operate in any new configuration that is prohibited by the present plant Technical Specifications.
The proposed change includes an exception to repetitive diesel testing while in an action statement for an inoperable off site power circuit.
Deenergizing a 500/13.8 kv transformer will not affect EDG operability, and would not involve any changes to EDG operation.
Therefore, the proposed changes do not involve any new or different kind of accident from any previously evaluated.
(3) do not involve a significant reduction in a margin of safety.
The Technical Specification requirements for A.C. power sources ensure that redundant electrical power is available to mitigate the consequences of any design basis accident and bring the plant to a safe shutdown condition.
The proposed change would not affect the ability of SGS Unit 2 to recover from any design basis transient involving loss of offsite power plus a single failure of one EDG.
Unit 1 will be shutdown with redundant decay heat removal capability during implementation of the proposed change.
Therefore, the proposed changes do not involve a reduction in any margin of safety.
Therefore, PSE&G has' concluded that the changes proposed herein do not involve a Significant Hazards Consideration.
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