ML090970277
| ML090970277 | |
| Person / Time | |
|---|---|
| Site: | Nine Mile Point  |
| Issue date: | 03/30/2009 |
| From: | Polson K Constellation Energy Group, Nine Mile Point |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| Download: ML090970277 (36) | |
Text
I A -
Keith J. Poison P.O. Box 63 Vice President-Nine Mile Point Lycoming, New York 13093 315.349.5200 315.349.1321 Fax 0
Constellation Energy*
Nine Mile Point Nuclear Station March 30, 2009 U. S. Nuclear Regulatory Commission Washington, DC 20555-0001 ATTENTION:
Document Control Desk
SUBJECT:
Nine Mile Point Nuclear Station Unit No. 2, Docket No. 50-410 License Amendment Request Pursuant to 10 CFR 50.90: Removal of Operating Mode Restrictions for Performing High Pressure Core Spray Emergency Diesel Generator Surveillance Testing Pursuant to 10 CFR 50.90, Nine Mile Point Nuclear Station, LLC (NMPNS) hereby requests an amendment to the Nine Mile Point Unit 2 (NMP2) Renewed Facility Operating License NPF-69. The proposed amendment would modify Technical Specification (TS) 3.8.1, "AC Sources - Operating," by revising certain Surveillance Requirements (SR) pertaining to the Division 3 (High Pressure Core Spray -
HPCS) emergency diesel generator (DG). The Division 3 DG is an independent source of onsite alternating current (AC) power dedicated to the HPCS system. The TSs currently prohibit performing the testing required by SR 3.8.1.7, SR 3.8.1.8, and SR 3.8.1.10 in Modes 1 or 2, and prohibit performing the testing required by SR 3.8.1.9, SR 3.8.1.11, SR 3.8.1.14, SR 3.8.1.15, and SR 3.8.1.17 in Modes 1, 2, or
- 3. The proposed amendment would remove these Mode restrictions and allow all eight of the identified SRs to be performed in any operating Mode for the Division 3 DG.
The Enclosure provides a description and technical bases for the proposed changes, and existing TS pages and associated TS Bases pages marked up to show the proposed changes. NMPNS has concluded that the activities associated with the proposed amendment represent no significant hazards consideration under the standards set forth in 10 CFR 50.92. The enclosed submittal contains no regulatory commitments.
Approval of the proposed license amendment is requested by February 26, 2010, with implementation within 90 days of receipt of the approved amendment. Approval by the requested date is desired to support planning activities for the next NMP2 refueling outage, which is currently scheduled for spring 2010.
A4ol
ft Document Control Desk March 30, 2009 Page 2 Pursuant to 10 CFR 50.91(b)(1), NMPNS has provided a copy of this license amendment request, with Enclosure, to the appropriate state representative.
Should you have any questions regarding the information in this submittal, please contact T. F. Syrell, Licensing Director, at (315) 349-5219.
Very truly yours, STATE OF NEW YORK TO WIT:
COUNTY OF OSWEGO I, Keith J. Polson, being duly sworn, state that I am Vice President-Nine Mile Point, and that I am duly authorized to execute and file this license amendment request on behalf of Nine Mile Point Nuclear Station, LLC. To the best of my knowledge and belief, the statements contained in this document are true and correct. To the extent that these statements are not based on my personal knowledge, they are based upon information provided by other Nine Mile Point employees and/or consultants. Such information has been reviewed in accordance with company practice and I believe it to be reliable.
Subscribed and sworn before me, a Notary Public in and for the State of New York and County of this 8 0 +ýL day of Jfl
,2009.
WITNESS my Hand and Notarial Seal:
(Y-"* 0,.. c
- )t 9_
Notary Public TONYA LYjONES 2
My Comnmission Expires:
Notary Public in the State of New York Oswego County Reg. No. 01J06083354 Date My commission Expires L4*
/IDate*
KJP/DEV
Enclosure:
Evaluation of the Proposed Change cc:
S. J. Collins, NRC R. V. Guzman, NRC Resident Inspector, NRC J. P. Spath, NYSERDA
ENCLOSURE EVALUATION OF THE PROPOSED CHANGE TABLE OF CONTENTS 1.0
SUMMARY
DESCRIPTION 2.0 DETAILED DESCRIPTION 2.1 Description of the Proposed Change
2.2 Background
3.0 TECHNICAL EVALUATION
3.1 General Basis 3.2 Administrative Controls for Online Maintenance 3.3 Online Risk Management 3.4 Online Testing Versus Outage Testing 3.5 Discussion for Individual Surveillance Requirements
4.0 REGULATORY EVALUATION
4.1 Applicable Regulatory Requirements/Criteria 4.2 Precedent 4.3 Significant Hazards Consideration 4.4 Conclusions
5.0 ENVIRONMENTAL CONSIDERATION
ATTACHMENTS
- 1. Nine Mile Point Unit 2 - Proposed Technical Specification Changes (Mark-up)
- 2. Nine Mile Point Unit 2 - Changes to Technical Specification Bases (Mark-up)
Nine Mile Point Nuclear Station, LLC March 30, 2009
ENCLOSURE EVALUATION OF THE PROPOSED CHANGE 1.0
SUMMARY
DESCRIPTION This evaluation supports a request to amend Renewed Facility Operating License NPF-69 for Nine Mile Point Unit 2 (NMP2).
The proposed amendment would modify Technical Specification (TS) 3.8.1, "AC Sources - Operating,"
by revising certain Surveillance Requirements (SR) pertaining to the Division 3 emergency diesel generator (DG). The Division 3 DG is an independent source of onsite alternating current (AC) power dedicated to the High Pressure Core Spray (HPCS) system. The TSs currently prohibit performing the testing required by SR 3.8.1.7, SR 3.8.1.8, and SR 3.8.1.10 in Modes 1 or 2, and prohibit performing the testing required by SR 3.8.1.9, SR 3.8.1.11, SR 3.8.1.14, SR 3.8.1.15, and SR 3.8.1.17 in Modes 1, 2, or
- 3. The proposed amendment would remove these Mode restrictions and allow all eight of the identified SRs to be performed in any operating Mode for the Division 3 DG only. The Mode restrictions will remain applicable to the other two safety-related (Division 1 and Division 2) DGs.
The proposed change will provide greater flexibility in scheduling Division 3 DG testing activities by allowing the testing to be performed during non-outage times. Having a completely tested Division 3 DG available for the duration of a refueling outage will reduce the number of system re-alignments and operator workload during an outage, and can provide significant reductions in outage critical path time.
Therefore, Nine Mile Point Nuclear Station, LLC (NMPNS) requests NRC approval of this amendment request by February 26, 2010 to support planning activities for the next NMP2 refueling outage, which is currently scheduled for spring 2010.
2.0 DETAILED DESCRIPTION 2.1 Description of the Proposed Change The proposed amendment includes the following revisions to TS 3.8.1:
SR 3.8.1.7: Revise Note 1 to remove the restriction that prohibits performance of the SR in Modes 1 or 2, for the Division 3 DG only. This SR requires verification that following rejection of a load greater than or equal to its associated single largest post-accident load for the Division 3 DG (i.e., the 2435 kW HPCS pump), the frequency is within specified limits.
SR 3.8.1.8: Revise Note 1 to remove the restriction that prohibits performance of the SR in Modes 1 or 2, for the Division 3 DG only. This SR requires verification that following a full load rejection (a load > 2600 kW), the Division 3 DG does not trip and voltage is maintained within specified limits.
SR 3.8.1.9: Revise Note 2 to remove the restriction that prohibits performance of the SR in Modes 1, 2, or 3, for the Division 3 DG only. This SR requires verification that the Division 3 DG automatically starts from the standby condition on an actual or simulated Loss of Offsite Power (LOOP) signal, achieves the required voltage and frequency, and supplies permanently connected loads for > 5 minutes.
SR 3.8.1.10: Revise Note 2 to remove the restriction that prohibits performance of the SR in Modes 1 or 2, for the Division 3 DG only. This SR requires verification that the Division 3 DG automatically starts from the standby condition on an actual or simulated ECCS initiation signal, achieves the required voltage and frequency within the specified time, and operates for > 5 minutes.
1 of 15
ENCLOSURE EVALUATION OF THE PROPOSED CHANGE SR 3.8.1.11: Revise the Note to remove the restriction that prohibits performance of the SR in Modes 1, 2, or 3, for the Division 3 DG only. This SR requires verification that the Division 3 DG automatic trips are bypassed on an actual or simulated loss of voltage signal on its associated emergency bus concurrent with an actual or simulated ECCS initiation signal, except for critical protective trip functions.
SR 3.8.1.14: Revise the Note to remove the restriction that prohibits performance of the SR in Modes 1, 2, or 3, for the Division 3 DG only. This SR requires verification that the Division 3 DG can be synchronized with the offsite power source while loaded with emergency loads, and upon a simulated restoration of offsite power, all loads are transferred to offsite power and the DG returns to ready-to-load operation.
SR 3.8.1.15: Revise the Note to remove the restriction that prohibits performance of the SR in Modes 1, 2, or 3, for the Division 3 DG only. This SR requires verification that, with the Division 3 DG operating in the test mode and connected to its bus, an actual or simulated ECCS initiation signal overrides the test mode by returning the DG to ready-to-load operation and automatically energizing the emergency loads from offsite power.
SR 3.8.1.17: Revise Note 2 to remove the restriction that prohibits performance of the SR in Modes 1, 2, or 3, for the Division 3 DG only. This SR requires verification that the Division 3 DG automatically starts from the standby condition on an actual or simulated LOOP signal in conjunction with an actual or simulated ECCS initiation signal, achieves the required voltage and frequency within the specified time, and supplies permanently connected loads for > 5 minutes.
For each of the above SRs, the applicable Note will be revised by adding the following: "(not applicable to Division 3 DG)." provides the existing TS pages marked-up to show the proposed changes. Marked-up pages showing associated changes to the TS Bases are provided in Attachment 2 for information only. The TS Bases changes will be processed in accordance with the NMP2 TS Bases Control Program (TS 5.5.10).
2.2 Background
NMP2 TS 3.8.1, "AC Sources - Operating," specifies requirements for the Class 1E electrical power distribution system AC sources. These AC sources consist of the offsite power sources and the onsite standby power sources (i.e., diesel generators). As required by 10 CFR 50, Appendix A, General Design Criterion (GDC) 17, the design of the AC electrical power system provides independence and redundancy to ensure an available source of power to the Engineered Safety Feature (ESF) systems. The offsite and onsite power sources are described in detail in Chapter 8. of the NMP2 Updated Safety Analysis Report (USAR). A simplified one-line diagram of the NMP2 onsite 4.16 kV emergency electrical distribution system is shown on Figure 1.
The NMP2 Class 1E AC distribution system supplies electrical power to three divisional load groups, Divisions 1, 2, and 3, with each division powered by an independent Class 1E 4.16 kV emergency bus.
The Division 1 and 2 4.16 kV emergency buses each have a separate and independent offsite source of power (the preferred source). The Division 3 (HPCS) 4.16 kV emergency bus can be supplied from either of the two independent offsite sources. Each 4.16 kV emergency bus also has a dedicated onsite DG. The ESF systems of any two of the three divisions provide for the minimum safety functions necessary to shut down the unit and maintain it in a safe shutdown condition in the event of a design basis accident (DBA).
2 of 15
ENCLOSURE EVALUATION OF THE PROPOSED CHANGE Offsite power is supplied to the NMP2 switchyard from the transmission network. From the switchyard, three qualified, electrically and physically separated circuits provide AC power to the Division 1, 2, and 3 4.16 kV emergency buses. Offsite power source A (reserve station service transformer A [RSST-A])
provides power to the Division 1 4.16 kV emergency bus and also is the preferred power source for the Division 3 4.16 kV emergency bus. Offsite power source B (RSST-B) provides power to the Division 2 4.16 kV emergency bus, and is also capable of providing power to the Division 3 4.16 kV emergency bus.
In addition, either the Division 1 or Division 2 emergency buses can be powered from a third qualified source, the auxiliary boiler transformer (2ABS-X 1). The offsite AC electrical power sources are designed and located to minimize, to the extent practical, the likelihood of their simultaneous failure under operating and postulated accident and environmental conditions. A qualified offsite circuit consists of all breakers, transformers, switches, interrupting devices, cabling, and controls required to transmit power from the offsite transmission network to the onsite Class 1 E 4.16 kV emergency bus(es).
The onsite standby power source for each 4.16 kV emergency bus is a dedicated DG. A DG starts automatically on a loss of coolant accident (LOCA) signal (refer to TS 3.3.5.1, "Emergency Core Cooling System (ECCS) Instrumentation") or on an emergency bus degraded voltage or undervoltage signal (refer to TS 3.3.8.1, "Loss of Power (LOP) Instrumentation"). After the DG has started, it automatically ties to its respective 4.16 kV emergency bus after offsite power is tripped as a consequence of emergency bus undervoltage or degraded voltage, independent of or coincident with a LOCA signal. The DGs also start and operate in the standby mode without tying to their emergency buses on a LOCA signal alone. In the event of a LOOP, the ESF electrical loads are automatically connected to the DGs in sufficient time to provide for safe reactor shutdown and to mitigate the consequences of a DBA such as a LOCA. The three divisional 4.16 kV emergency buses are electrically independent and physically isolated from each other so that any failure in one division will not jeopardize the safety function of the other divisions. The emergency buses are located in separate rooms in the seismic Category I control building.
The Division 3 (HPCS) DG has the capability to restore power quickly to the Division 3 4.16 kV emergency bus in the event of a LOOP and to provide all required power for the startup and operation of the HPCS system (see USAR Table 8.3-3 for a listing of HPCS system loads). There is no provision for automatic paralleling of the Division 3 DG with the offsite power source or with other standby power sources. Provisions for manual paralleling with offsite power sources are made for loading the DG during the test mode. If a LOOP occurs, a parallel-loaded DG would attempt to supply power to the offsite test loads through the closed feed breakers. A set of three directional overcurrent relays will trip the offsite power feed breakers when the overcurrent exceeds a preset value. The DG would continue to power the Division 3 emergency bus. If a LOCA signal occurs while the Division 3 DG is running in parallel with the offsite power source, the DG feed breaker will automatically trip. The LOCA signal would override the test start signal during auto mode and the DG would continue running unloaded. The HPCS pump motor and associated HPCS loads would automatically start, with the Division 3 emergency bus being powered from the offsite power source.
As discussed in USAR Section 6.3, the HPCS system is designed and constructed to allow all active components to be tested during normal plant operations. The system has a full-flow test line to either the suppression pool or the condensate storage tank (CST) and a minimum flow bypass line to the suppression pool. These features allow system testing without discharging into the reactor vessel and, along with the design of the electrical distribution system, facilitate safe performance of Division 3 DG testing pursuant to the subject SRs while in any operational mode.
3 of 15
ENCLOSURE EVALUATION OF THE PROPOSED CHANGE
3.0 TECHNICAL EVALUATION
3.1 General Basis Although the TS Bases, as currently written, state that one of the reasons for the SR Notes imposing Mode restrictions is to preclude the potential for perturbations of the electrical distribution system during plant operation, reconsideration of this basis for the Division 3 DG has determined that the noted concern is not warranted with respect to requiring the affected SRs to be performed only during shutdown conditions. This conclusion is based on: (1) the NMP2 AC power supply and associated protection features; (2) industry and plant experience with the performance of testing required per the affected SRs;
,(3) administrative controls that minimize plant risks during performance of the affected testing; and (4) the low probability of a significant voltage perturbation during such testing.
The subject surveillance testing makes the Division 3 DG and its associated loads unavailable for responding to an accident during portions of the testing. The effect on safety of performing the subject SRs for the Division 3 DG during plant operation is not significantly different than the effect on safety associated with the performance of other DG surveillances required by the TS that are not prohibited from being performed during plant operation. For example, SRs 3.8.1.7, 3.8.1.8, and 3.8.1.15 are performed by paralleling the DG in test with offsite power, similar to the existing monthly run of the DG (to meet SRs 3.8.1.2 and 3.8.1.3), which is conducted with the plant online. Further, performance of the required testing online does not challenge the Division 1 and Division 2 safety systems or the Reactor Core Isolation Cooling (RCIC) system (which provides a function similar to the HPCS system - refer to TS 3.5.3, "RCIC System"), and doesnot interfere with normal plant operation.
3.2 Administrative Controls for Online Maintenance The NMP2 TSs impose requirements/restrictions on the amount of equipment allowed out of service at any given time. Required Action B.2 of TS 3.8.1, "AC Sources-Operating," requires identification of inoperable required features that are redundant to required features supported by the inoperable DG. This Required Action is applicable throughout the entire period of DG inoperability. Inoperable features on the redundant division would then cause entry into other more stringent Required Actions, thus providing further incentive not to make another DG inoperable. Additionally, the Safety Function Determination Program, required by Technical Specification 5.5.11,, ensures that a loss of safety function is detected and appropriate actions taken.
The NMPNS approach to performing maintenance requires a protected division concept. This means that without special considerations, work is only allowed on one division at a time. Additionally, access to areas of the plant containing protected equipment is restricted. These administrative controls provide additional assurance that work is performed on. only one division at a time. NMPNS procedures contain precautions to minimize risk associated with surveillance testing, maintenance activities, and degraded grid conditions when paralleling a DG with offsite power. For example, during testing, only one DG at a time is operated in parallel with offsite power. This configuration provides for sufficient independence of the onsite power sources from offsite power while still enabling testing to demonstrate DG operability. In this configuration and with the administrative controls for DG testing in place, it is possible for only one DG to be affected by an unstable offsite power system. Even if this unlikely scenario were to occur, plant safe shutdown capability would still be assured with the two remaining DGs.
4 of 15
ENCLOSURE EVALUATION OF THE PROPOSED CHANGE 3.3 Online Risk Management The NMPNS integrated risk management procedure provides requirements to conduct a risk assessment for all maintenance performed while in the Unit is online. This procedure implements the requirements of paragraph (a)(4) of 10 CFR 50.65, "Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants." As required by this procedure, a PRA-based risk evaluation tool is used to quantify the potential risk implications of planned or emergent work activities. Based on this evaluation, if specific risk thresholds are exceeded, work management or operations must adjust the schedule or select appropriate risk reducing compensatory actions that are implemented prior to beginning work.
These administrative controls minimize the potential to allow work on redundant DGs or other systems that are similar to those supplied by the affected DG without appropriate compensatory actions.
3.4 Online Testing Versus Outage Testing Due to the relationship between the Division 3 DG and the HPCS system, the TSs allow up to 14 days of inoperability for the Division 3 DG if the RCIC system is operable. Thus, the existing TSs provide ample time for the online performance of the SRs that this request proposes to revise. The actual time needed to perform these SRs is approximately 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br />. A comparison of the TS requirements for emergency core cooling systems (TS 3.5.1 and 3.5.2) and AC sources (TS 3.8.1 and 3.8.2) indicates that the TS requirements are more restrictive during Modes 1, 2, or 3 than the requirements during Modes 4 or 5.
Thus, due to the redundancy and diversity of the ECCS, adequate accident mitigation equipment will be available if an event occurs while performing the subject surveillance testing during Modes 1, 2, or 3.
The Division 3 (HPCS) system is a stand-alone system with its dedicated DG and independent electrical distribution system. As discussed in NMP2 USAR Sections 6.3.1.1.3 and 8.3.1.4, this system is separated from the other two safety-related divisions both physically and electrically. All controls, wiring, and other components are separated to prevent common cause failures and cross-divisional damage due to external events such as fires, pipe ruptures, falling objects, etc. The Division 3 DG supplies only the HPCS pump and associated support equipment and auxiliaries (as listed on USAR Table 8.3-3). Therefore, there is minimal opportunity for the performance of these SRs to have any impact on other safety-related plant equipment.
As described in NMP2 USAR Section 6.3, the HPCS system has a full flow test line to either the suppression pool or the CST and a minimum flow bypass line to the suppression pool. These features allow system testing without discharging into the reactor vessel. System configuration is such that HPCS system testing can be performed without impacting other divisional safety systems.
During both normal plant operation and during shutdown conditions, the three 4.16 kV emergency buses are normally aligned to the two RSSTs, with the Division 3 emergency bus normally supplied by RSST-A (see Figure 1). Voltage transients on these buses during online testing will likely be less than those experienced when testing during shutdown conditions. During normal power operation, the voltage at the 4.16 kV emergency buses is near nominal or slightly above 1.0 per unit (pu). One reason for this is the low loading factor for the RSSTs. The RSST loading is approximately 3.5 MVA during normal plant operation and approximately 10 MVA during shutdown conditions, versus a rating of 70 MVA. As discussed in USAR Section 8.2.2, the minimum anticipated grid voltage for the 345 kV sources to the Scriba switchyard is 0.950 pu, with the RSSTs regulating secondary and tertiary winding voltages to approximately 1.0 pu at the minimum voltage condition. This establishes margin between the available bus voltages and the degraded voltage trips. The time delay features of the degraded voltage sensors are designed to allow small, brief perturbations to settle out well before actual trips would occur.
5 of 15'
ENCLOSURE EVALUATION OF THE PROPOSED CHANGE A tabulation of the loads powered by the Division 3 DG is provided in NMP2 USAR Table 8.3-3. As shown in this USAR table, the maximum total Division 3 DG load for a simultaneous LOCA and LOOP is 2540 kW, with the largest load being the 2435 kW HPCS pump (approximately 96% of the total Division 3 DG load). The Division 3 load is a small percentage of the RSST rating and would be considered a normal load for the offsite power system. Energizing or de-energizing a load of this size as part of DG surveillance testing (either online or during shutdown conditions) creates minimal potential to cause a significant power distribution system perturbation. In fact, HPCS pump starts are routinely performed online to satisfy quarterly inservice testing requirements, without disturbing plant operation.
The on-line performance of the subject SRs for the Division 3 DG will have little effect on managing equipment unavailability goals described in 10 CFR 50.65(a)(3). The maintenance rule unavailability performance criterion for the Division 3 DG is set at 262.79 hours9.143519e-4 days <br />0.0219 hours <br />1.306217e-4 weeks <br />3.00595e-5 months <br /> for a 24-month rolling period. Based on this criterion, NMPNS has established an administrative goal of 210 hours0.00243 days <br />0.0583 hours <br />3.472222e-4 weeks <br />7.9905e-5 months <br /> of unavailability for the 24-month period. The addition of 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> of unavailability per 24-month period does not challenge achievement of the established performance criteria.
3.5 Discussion for Individual Surveillance Requirements 3.5.1 SR 3.8.1.7 and SR 3.8.1.8 SR 3.8.1.7 requires verification that following rejection of a load greater than or equal to the associated single largest post-accident load for the Division 3 DG (i.e., the 2435 kW HPCS pump), the frequency remains within specified limits. SR 3.8.1.8 requires verification that following a full load rejection (a load
> 2600 kW), the Division 3 DG does not trip and voltage is maintained within specified limits. Currently, these SRs contain a Note that prohibits performance in Modes 1 or 2. The TS Bases state the reason for the Note is that performing the surveillances could cause perturbations to the electrical distribution systems that could challenge continued steady state operation and, as a result, plant safety systems.
SR 3.8.1.7 and SR 3.8.1.8 are performed by paralleling the Division 3 DG with offsite power, similar to the existing monthly run of the DG that is conducted with the plant on line. For performance of the load rejection tests per SR 3.8.1.7 and SR 3.8.1.8, the typical approach taken is to load the Division 3 DG to the required load (via offsite power) and then open the DG output breaker (102-1). Opening the DG output breaker separates the DG from its associated emergency bus and allows the offsite power source to continue to supply the bus. This evolution has little impact on the plant electrical distribution system. The power system loading during such testing is within the rating of all transformers, switchgear, and breakers, both before and after the load rejection, and as further explained below, performance of the load rejection SRs does not cause any significant perturbations to the electrical distribution systems as the DG is separated from the bus.
During plant operation, the 4.16 kV emergency buses are normally aligned to the two reserve station service transformers, each of which is fed from a 115 kV offsite line (RSST-A and RSST-B, see Figure 1). This is the same configuration maintained during plant shutdown when the load rejection testing is currently conducted. The probability for a grid disturbance to occur during the timeframe of a test performed per SR 3.8.1.7 or SR 3.8.1.8 is low since the occurrence of a grid disturbance is independent of the testing. Protective relaying for the DG would be available to protect the DG while it is connected to the offsite power source. In addition, the protective instrumentation for sustained offsite power low-voltage conditions, required to be operable per TS 3.3.8.1, "Loss of Power (LOP) Instrumentation,"
would be available to respond to such a condition.
6 of 15
ENCLOSURE EVALUATION OF THE PROPOSED CHANGE Historical bus voltage data from testing performed pursuant to these SRs for the Division 3 DG full load rejection test, with the unit in a shutdown condition, has shown that the generator voltage change which occurs during the transient is about 9 percent (383 volts) at the 4.16 kV level, with voltage recovery within approximately three seconds. Thus, the voltage transient experienced by loads on the bus is minor and would not challenge the loss of voltage or degraded voltage relays.
Starting the HPCS pump motor is actually a more limiting transient than a Division 3 full load rejection due to the presence of the pump motor starting transient. HPCS pump starts are routinely performed online, with offsite power supplying the Division 3 emergency bus, to satisfy quarterly inservice testing requirements. These tests have not disturbed plant operation.
Based on the above discussion, the reasons for the mode restrictions stated in the TS Bases for SR 3.8.1.7 and SR 3.8.1.8 are not valid for the Division 3 DG.
3.5.2 SR 3.8.1.9 SR 3.8.1.9 requires verification that the Division 3 DG automatically starts from the standby condition on an actual or simulated LOOP signal, achieves the required voltage and frequency, and supplies permanently connected loads for > 5 minutes. Note that the NMP2 design for the Division 3 DG does not feature automatic sequencing of loads. Currently, this SR contains a Note that prohibits performance in Modes 1, 2, or 3. The TS Bases state the reason for the Note is that performing the surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge plant safety systems.
With the Division 3 4.16 kV emergency bus aligned to an RSST, a LOOP is simulated by the use of key-operated switches that cause the Division 3 emergency switchgear to de-energize, thereby isolating the Division 3 electrical subsystem from the other two safety-related electrical subsystems. The Division 3 DG starts, re-energizes its associated emergency bus, and runs for at least 5 minutes. Since. this test does not involve an ECCS initiation signal, the HPCS pump does not automatically start; however, following the 5-minute run, the HPCS pump is manually started for the purpose of performing testing per SR 3.8.1.14.
Because the HPCS system is a stand-alone system with a dedicated DG and independent electrical distribution system, there is minimal opportunity for the performance of this SR to have any impact on other safety-related plant equipment or normal plant operation. The simulated LOOP signal is generated only at the Division 3 switchgear and does not affect the other two safety-related electrical divisions.
Additionally, due to the relative size of the loads associated with the HPCS system (2540 kW), there is minimal potential for this testing to create an offsite power supply perturbation when the Division 3 4.16 kV emergency bus is de-energized. Although the offsite source of power to the Division 3 emergency bus is disconnected for this test, the period of time that this condition exists is small and is acceptable since the HPCS system is already inoperable for performance of the test (see the Note to the Applicability requirements for TS 3.8.1). Therefore, the reasons for the mode restrictions stated in the TS Bases for SR 3.8.1.9 are not valid for the Division 3 DG.
7 of 15
ENCLOSURE EVALUATION OF THE PROPOSED CHANGE 3.5.3 SR 3.8.1.10 SR 3.8.1.10 requires verification that the Division 3 DG automatically starts from the standby condition on an actual or simulated ECCS initiation signal, achieves the required voltage and frequency within the specified time, and operates for > 5 minutes. Currently, this SR contains a Note that prohibits performance in Modes 1 or 2. The TS Bases state the reason for the Note is that performing the surveillance could cause perturbations to the electrical distribution system that could challenge continued steady state operation and, as a result, plant safety systems.
This test is performed by inserting an ECCS initiation signal into the Division 3 control logic (e.g., by arming and depressing the HPCS manual initiation pushbutton on the main control room panel). With the ECCS initiation signal present, the Division 3 DG starts and runs unloaded (generator output breaker (102-1) is open) for >_ 5 minutes while acceptable performance parameters (voltage and frequency) are verified. The HPCS pump start is manually overridden by placing the pump control switch in pull-to-lock, and opening of the motor-operated injection valve (2CSH*MOV107) is prevented by verifying the valve is closed and de-energized (by placing the breaker for the valve motor in the OFF position). These steps are taken to prevent an actual discharge of water into the reactor vessel by the HPCS system, which could cause unwanted effects on reactor vessel water level. Similar steps would likewise be taken when performing this test online to preclude unwanted effects on reactor vessel water level and core reactivity due to a HPCS system injection. Following the test, restoration of all safety-related functions, including restoration of the HPCS system to operable status, are independently verified. Similar methods and procedural controls would be employed when performing the surveillance test online.
The HPCS system is a stand-alone system with a dedicated DG and independent electrical distribution system. The simulated ECCS initiation signal is generated only in the HPCS logic and does not affect the other two safety-related electrical divisions. Thus, performing the SR 3.8.1.10 test for the Division 3 DG, whether shutdown or online, affects only the HPCS system. In addition, since this test is conducted with the Division 3 DG unloaded and isolated from its emergency bus, there is no impact to the electrical distribution system, and no mechanism for challenging continued steady state operation. Therefore, the reasons for the mode restrictions stated in the TS Bases for SR 3.8.1.10 are not valid for the Division 3 DG.
3.5.4 SR 3.8.1.11 SR 3.8.1.11 requires verification that the Division 3 DG automatic trips are bypassed on an actual or simulated loss of voltage signal on its associated 4.16 kV emergency bus concurrent with an actual or simulated ECCS initiation signal, except for critical protective trip functions (engine overspeed and generator differential current). Currently, this SR contains a Note that prohibits performance in Modes 1, 2, or 3. The TS Bases state the reason for the Note is that performing the surveillance removes a required DG from service.
Performance of testing required per SR 3.8.1.11 in Modes 1, 2, or 3 is justified on the basis that: (1) this SR is not performed with the DG paralleled to offsite power; and (2) unavailability of the DG during the conduct of this test is minimal. Unavailability of the DG mainly occurs when the DG is tripped to complete the surveillance. Availability is restored once the DG trip is reset.
Verification that the Division 3 DG automatically trips on engine overspeed and generator differential current is performed with the Division 3 DG operating unloaded and isolated from its 4.16 kV emergency bus. Manual action is required to reset the emergency trips so that the DG can then be placed in a normal standby lineup.
8 of 15
ENCLOSURE EVALUATION OF THE PROPOSED CHANGE Verification that the non-emergency automatic trips are bypassed on a LOOP signal concurrent with an ECCS initiation signal is performed using the same test procedure that performs the SR 3.8.1.17 test (the Division 3 DG automatic start on an actual or simulated LOOP signal in conjunction with an actual or simulated ECCS initiation signal). These tests are conducted with the Division 3 4.16 kV emergency bus energized by the Division 3 DG and with the HPCS system in operation, with pump suction from the CST and discharge through the minimum flow bypass line to the suppression pool. Actual discharge of water into the reactor vessel by the HPCS system is prevented as discussed under SR 3.8.1.17. With the DG operating at rated frequency and voltage, actuation of the non-emergency trips is simulated electrically within the Division 3 control circuitry (e.g., by jumpering appropriate terminals in Division 3 electrical panels).
The HPCS system is a stand-alone system with its dedicated DG and independent distribution system.
Performing the SR 3.8.1.11 tests for the Division 3 DG, whether online or shutdown, affects only the HPCS system, and there is minimal opportunity for the performance of these tests to have any impact on other safety-related plant equipment. As noted previously, the unavailability of the Division 3 DG that occurs during the conduct of these tests and the other SRs that are proposed to be performed online is well within the 14 days of inoperability that is allowed by the TS, and also does not challenge achievement of the administrative goal that has been established for Division 3 DG maintenance rule unavailability.
performance. Therefore, the reason for the mode restrictions stated in the TS Bases for SR 3.8.1.11 is not valid for the Division 3 DG.
3.5.5 SR 3.8.1.14 SR 3.8.1.14 requires verification that the Division 3 DG can be synchronized with the offsite power source while loaded with emergency loads, and upon a simulated restoration of offsite power, all loads are transferred to offsite power and the DG returns to ready-to-load operation. Currently, this SR contains a Note that prohibits performance in Modes 1, 2, or 3. The TS Bases state the reason for the Note is that performing the surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge plant safety systems.
This test is typically performed following completion of the LOOP test of SR 3.8.1.9 (for aligning the Division 3 4.16 kV emergency bus to one of the two RSSTs), and following completion of the LOOP/LOCA test of SR 3.8.1.17 (for aligning the Division 3 4.16 kV emergency bus to the other RSST).
After the Division 3 DG has started and re-energized its associated emergency bus, the HPCS pump is started and placed in either the full flow or minimum flow test mode. Actual discharge of water into the reactor vessel by the HPCS system is prevented as discussed under SR 3.8.1.17. The Division 3 emergency bus is then paralleled to offsite power and the bus loads are transferred to the offsite power source. The DG output breaker (102-1) is then tripped open and the DG is verified to return to ready-to-load operation.
The HPCS system is a stand-alone system with a dedicated DG and independent electrical distribution system; thus, there is minimal opportunity for the performance of this SR to have any impact on other safety-related plant equipment or normal plant operation. Although the offsite source of power to the Division 3 emergency bus is disconnected at the beginning of this test, the period of time that this condition exists is small and is acceptable since the HPCS system is already inoperable for performance of the test (see the Note to the Applicability requirements for TS 3.8.1). Additionally, the relative size of the loads associated with the HPCS system (2540 kW) presents minimal potential for creating an offsite power supply perturbation when shifting the load between the Division 3 DG and the offsite power source. The offsite power source for the Division 3 4.16 kV emergency bus during the test is an RSST, 9 of 15
ENCLOSURE EVALUATION OF THE PROPOSED CHANGE regardless of whether the test is performed online or during shutdown conditions. Completed test results performed during shutdown conditions have shown that the required bus voltage parameters stay within expected limits and no anomalous actions regarding load transfer sequences occur. Based on past experience, conducting this test online is no more challenging to plant safety systems than performance during shutdown conditions.
Based on the above discussion, the reasons for the mode restrictions stated in the TS Bases for SR 3.8.1.14 are not valid for the Division 3 DG.
3.5.6 SR 3.8.1.15 SR 3.8.1.15 requires verification that, with the Division 3 DG operating in the test mode and connected to its 4.16 kV emergency bus, an actual or simulated ECCS initiation signal overrides the test mode by returning the DG to ready-to-load operation and automatically energizing the emergency loads from offsite power. Currently, this SR contains a Note that prohibits performance in Modes 1, 2, or 3. The TS Bases state the reason for the Note is that performing the surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge plant safety systems.
This test is performed by paralleling the DG in test with offsite power, similar to the existing monthly run of the DG that is conducted with the plant online. The performance of the test mode override test per SR 3.8.1.15 ensures that the availability of the Division 3 DG under accident conditions is unaffected during the performance of the surveillance test. This test is typically performed in conjunction with the load rejection tests (SR 3.8.1.7 and SR 3.8.1.8). With the DG manually started in the test mode and paralleled to its emergency bus, an ECCS signal is inserted by arming and depressing the HPCS manual initiation pushbutton on the main control room panel. This causes the DG output breaker (102-1) to open, and return of the DG to a ready-to-load condition is verified. Opening the DG output breaker separates the DG from its associated emergency bus and allows the offsite power source to continue to energize the bus.
Consequently, performance of testing pursuant to SR 3.8.1.15 does not cause any significant perturbations to the electrical distribution system as the DG is separated from the bus. In addition, similar to testing performed for SR 3.8.1.7 and SR 3.8.1.8, the power system loading for this test is within the rating of the affected transformers, switchgear, and breakers. Therefore, the reasons for the mode restrictions stated in the TS Bases for SR 3.8.1.15 are not valid for the Division 3 DG.
As noted in the TS Bases for this SR, the requirement to automatically energize the emergency loads with offsite power is essentially identical to that of SR 3.8.1.10. The intent of the requirement associated with SR 3.8.1.15.b is to show that the emergency loading is not affected by DG operation in the parallel test mode. In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the AC electrical power system to perform these functions is acceptable. This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified. On this basis, performance of routine testing required pursuant to SR 3.8.1.15 does not require separating the Division 3 emergency bus from offsite power. Consequently, performance of this surveillance for the Division 3 DG does not require removing an offsite circuit from service, as currently indicated in the Bases for SR 3.8.1.15.
3.5.7 SR 3.8.1.17 SR 3.8.1.17 requires verification that the Division 3 DG automatically starts from the standby condition on an actual or simulated LOOP signal in conjunction with an actual or simulated ECCS initiation signal, achieves the required voltage and frequency within the specified time, and supplies permanently connected loads for > 5 minutes. Currently, this SR contains a Note that prohibits performance in Modes 10 of 15
ENCLOSURE EVALUATION OF THE PROPOSED CHANGE 1, 2, or 3. The TS Bases state the reason for the Note is that performing the surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge plant safety systems.
This test is performed with the Division 3 4.16 kV emergency bus aligned to one of the two RSSTs (see Figure 1). A LOOP signal is simulated, causing the Division 3 switchgear to de-energize (e.g., by placing the control switch for breaker 102-4 or 102-5 in the trip position). Simultaneously, an ECCS initiation signal is inserted into the Division 3 control logic (e.g., by arming and depressing the HPCS manual initiation pushbutton on the main control room panel). The Division 3 DG starts, re-energizes its.
associated emergency bus, and powers the HPCS pump and other permanently connected loads. For this test, the HPCS pump suction is from the CST, and pump discharge is through the minimum flow bypass line to the suppression pool. The HPCS system discharge pathway to the reactor vessel isolated.
Actual discharge of water into the reactor vessel by the HPCS system is prevented during the current performance of this test during shutdown conditions in order to preclude unwanted effects on reactor vessel water level. Discharge into the reactor vessel would likewise be prevented when performing this test online to preclude unwanted effects on reactor vessel water level and core reactivity. The current method of preventing HPCS system discharge into the reactor vessel is by verifying that the motor-operated injection valve (2CSH*MOV107) is closed and de-energized (by placing the breaker for the valve motor in the OFF position). Following the test, restoration of all safety-related'functions, including restoration of the HPCS system to. operable status, are independently verified. Similar methods and procedural controls would be employed when performing the surveillance test online.
As previously discussed, the HPCS system is a stand-alone system with a dedicated DG and independent electrical distribution system; thus, there is minimal impact from the performance of this SR on other safety-related plant equipment. The simulated LOOP and ECCS initiation signals affect only the HPCS system and do not affect the other two safety-related electrical divisions. Although the offsite source of power to the Division 3 emergency bus is disconnected for this test, the period of time that this condition exists is small and is acceptable since the HPCS system is already inoperable for performance of the test (see the Note to the Applicability requirements for TS 3.8.1). Additionally, due to the relative size of the loads associated with the HPCS system (2540 kW), there is minimal potential for this testing to create an offsite power supply perturbation when the Division 3 electrical bus is de-energized. HPCS pump starts are routinely performed online to satisfy quarterly inservice testing requirements, without disturbing plant operation.
Based on the above discussion and past experience performing this test, conducting this test online is no more challenging than conducting the test while shutdown; therefore, the reasons for the mode restrictions stated in the TS Bases for SR 3.8.1.17 are not valid for the Division 3 DG.
4.0 REGULATORY EVALUATION
4.1 Applicable Regulatory Requirements/Criteria 10 CFR 50, Appendix A, General Design Criteria (GDC) 17, "Electrical Power Systems," requires, in part, that:
An onsite and offsite electrical power system shall be provided to permit functioning of structures, systems, and components important to safety; 11 of 15
ENCLOSURE EVALUATION OF THE PROPOSED CHANGE The onsite electric power supplies, including the batteries, and the onsite electric distribution system, shall have sufficient independence, redundancy, and testability to perform their safety functions assuming a single failure; Electric power from the transmission network to the onsite electric distribution system shall be supplied by two physically independent circuits (not necessarily on separate rights of way) designed and located so as to minimize to the extent practical the likelihood of their simultaneous failure under operating and postulated accident and environmental conditions; and Provisions shall be included to minimize the probability of losing electric power from any of the remaining supplies as a result of, or coincident with, the loss of power generated by the nuclear power unit, the loss of power from the transmission network, or the loss of power from the onsite electric power supplies.
10 CFR 50, Appendix A, GDC 18, "Inspection and Testing of Electrical Power Systems," requires, in part, that electrical power systems important to safety be designed to permit appropriate inspection and testing of important areas and features.
The proposed TS changes affect only the plant operating conditions during which certain Division 3 (HPCS) DG surveillance tests can be performed. The technical evaluation of the proposed changes demonstrates that performing these surveillance tests while online will not create a transient that could cause perturbations to the NMP2 electrical distribution system, disrupt power operation, or challenge plant safety systems. For these same reasons, the proposed changes do not alter NMP2's compliance with the requirements of GDC 17 and GDC 18.
4.2 Precedent The NRC has approved similar license amendments to remove operating mode restrictions for performing HPCS DG surveillance testing. Recent examples include:
Columbia Generating Station (License Amendment No. 203 issued by NRC letter dated March 23, 2007 - ADAMS Accession No. ML070640060; and License Amendment No. 173 issued by NRC letter dated May 18, 2001 - ADAMS Accession No. MLO 11440088).
River Bend Station, Unit 1 (License Amendment No. 133 issued by NRC letter dated March 14, 2003
- ADAMS Accession No. ML030760726).
Similar to NMP2, both of the above plants have a stand-alone HPCS system with a dedicated DG and independent electrical distribution system, and with a motor-driven HPCS pump as the largest load.
4.3 Significant Hazards Consideration Nine Mile Point Nuclear Station, LLC (NMPNS) is requesting an amendment to Renewed Facility Operating License NPF-69 for Nine Mile Point Unit 2 (NMP2). The proposed amendment would modify Technical Specification (TS) 3.8.1, "AC Sources - Operating," by revising certain Surveillance Requirements pertaining to the Division 3 emergency diesel generator (DG). The Division 3 DG is an independent source of onsite alternating current (AC) power dedicated to the High Pressure Core Spray (HPCS) system. The TSs currently prohibit performing the DG testing required by the subject Surveillance Requirements in either Modes 1 or 2 or in Modes 1, 2, or 3. The proposed amendment would 12 of 15
ENCLOSURE EVALUATION OF THE PROPOSED CHANGE remove these Mode restrictions and allow all of the subject surveillances to be performed in any operating Mode for the Division 3 DG.
NMPNS has evaluated whether or not a significant hazards consideration is involved with the proposed amendment by focusing on the three standards set forth in 10 CFR 50.92, "Issuance of Amendment," as discussed below:
I1.
Does the proposed amendment involve a significant increase in the probability or consequences of an accident previously evaluated?
Response
No.
The Division 3 (HPCS) DG and its associated emergency loads are accident mitigating features, not accident initiators. Therefore, the proposed TS changes to allow the performance of Division 3 DG surveillance testing in any plant operating mode will not significantly impact the probability of any previously evaluated accident.
The design of plant equipment is not being modified by the proposed changes. As such, the ability of the Division 3 DG to respond to a design basis accident will not be adversely impacted by the proposed changes. The proposed changes to the TS surveillance testing requirements for the Division 3 DG do not affect the operability requirements for the DG, as verification of such operability will continue to be performed as required. Continued verification of operability supports the capability of the Division 3 DG to perform its required function of providing emergency power to HPCS system equipment, consistent with the plant safety analyses. Limiting testing to only one DG at a time ensures that design basis requirements are met. Should a fault occur while testing the Division 3 DG, there would be no significant impact on any accident consequences since the other two divisional DGs and associated emergency loads would be available to provide the minimum safety functions necessary to shut down the unit and maintain it in a safe shutdown condition.
Therefore, the proposed amendment does not involve a significant increase in the probability or consequences of an accident previously evaluated.
- 2.
Does the proposed amendment create the possibility of a new or different kind of accident from any accident previously evaluated?
Response
No.
No changes are being made to the plant that would introduce any new accident causal mechanisms. Equipment will be operated in the same configuration with the exception of the plant operating mode in which the Division 3 DG surveillance testing is conducted. Performance of these surveillances tests while online will continue to verify operability of the Division 3 DG.
The proposed amendment does not impact any plant systems that are accident initiators and does not adversely impact any accident mitigating systems.
Therefore, the proposed amendment does not create the possibility of a new or different kind of accident from any accident previously evaluated.
13 of 15
ENCLOSURE EVALUATION OF THE PROPOSED CHANGE
- 3.
Does the proposed amendment involve a significant reduction in a margin of safety?
Response
No.
Margin of safety is related to confidence in the ability of the fission product barriers (fuel cladding, reactor coolant system, and primary containment) to perform their design functions during and following postulated accidents. The proposed changes to the TS surveillance testing requirements for the Division 3 DG do not affect the operability requirements for the DG, as verification of such operability will continue to be performed as required. Continued verification of operability supports the capability of the Division 3 DG to perform its required function of providing emergency power to HPCS system equipment, consistent with the plant safety analyses. Consequently, the performance of the fission product barriers will not be adversely impacted by implementation of the proposed amendment. In addition, the proposed changes do not alter setpoints or limits established or assumed by the accident analysis.
Therefore, the proposed amendment does not involve a significant reduction in a margin of safety.
Based on the above, NMPNS concludes that the proposed amendment does not involve a significant hazards consideration under the standards set forth in 10 CFR 50.92(c), and, accordingly, a finding of "no significant hazards consideration" is justified.
4.4 Conclusions In conclusion, based on the considerations discussed above, (1) there is reasonable assurance that the health and safety of the public will not be endangered.by operation in the proposed manner, (2) such activities will be conducted in compliance with the Commission's regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.
5.0 ENVIRONMENTAL CONSIDERATION
A review has determined that the proposed amendment would change a requirement with respect to installation or use of a facility component located within the restricted area, as defined in 10 CFR 20, or would change an inspection or surveillance requirement. However, the proposed amendment does not involve: (i) a significant hazards consideration, (ii) a significant change in the types or significant increase in the amounts of any effluent that may be released offsite, or (iii) a significant increase in individual or cumulative occupational radiation exposure. Accordingly, the proposed amendment meets the eligibility criterion for categorical exclusion set forth in 10, CFR 51.22(c)(9). Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the proposed amendment.
14 of 15
ENCLOSURE EVALUATION OF THE PROPOSED CHANGE Figure 1: Simplified One Line Diagram - NMP2 Emergency 4.16 kV Distribution 115kV Line.#5 115kV Line #6 115kV Line #5 or #6 RSST-A 42/56/70 MVA OA/FA/FOA RSST-B 42/56/70 MVA OA/FA/FOA 4,16 kV To 13.8kV Busses To 13.8kV Busses Aux Boiler Tx 16.6/22.08/27.56 MVA OA/FA/FA 4.16 kV
,16 kV 13.
2-5 101-10 102-5 I
101-13 1 I I
102-4 103-2 I
103-4 I
F 101-1 Div 1 Loads DIV 1 EDG 4400 KW 102-2 102-1 HPCS Pump Div 3 Loads 2435 KW DIV 3 EDG 2600 KW 103-14 Div 2 Loads DIV 2 EDG 4400 KW
- Normally Closed Breaker
-TNormally Open Breaker 15 of 15
ATTACHMENT 1 NINE MILE POINT UNIT 2 PROPOSED TECHNICAL SPECIFICATION CHANGES (MARK-UP)
The current versions of the following Technical Specification pages have been marked-up by hand to reflect the proposed changes:
3.8.1-8 3.8.1-9 3.8.1-10 3.8.1-11 3.8.1-12 3.8.1-15 3.8.1-17 Nine Mile Point Nuclear Station, LLC March 30, 2009
AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)
SURVEILLANCE FREQUENCY SR 3.8.1.7 NOTES----------------
- 1.
This Surveillance shall not be performed in MODE 1 or
- owever, credit may be taken for unplanned events that satisfy this SR.
- 2.
If performed with DG synchronized with offsite power, it shall be performed within the power factor limit.
However if grid conditions do not permit, the power factor limit is not required to be met.
Under this condition the power factor shall be maintained as close to the limit as practicable.
Verify each required DG rejects a load greater than or equal to its associated single largest post-accident load, and following load rejection, the frequency is
< 64.5 Hz for Division I and 2 DGs and
< 66.75 Hz for Division.3 DG.
2 n,4.4
,i 3ont h
24 months (continued)
NMP2 3.8.1-8 Amendment41!-
AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)
SURVEILLANCE FREQUENCY SR 3.8.1.8 NOTES----------------
- 1.
This Surveillance shall not be performed in MODE 1 or
- owever, credit may be taken for nplanned events that satisfy this SR.
- 2.
If grid conditions do not permit, the power factor limit is not required to be met.
Under this condition the power factor shall be maintained as close to the limit as practicable.
Verify each required DG operating within the power factor limit does not trip and voltage is maintained:
- a.
< 4576 V during and following a load rejection of a load > 4400 kW for Division 1 and 2 DGs; and
- b.
< 5824 V during and following a load rejection of a load > 2600 kW for Division 3 DG.
6(04 C~l"~C 4le-.1-1 P)i~'fn3 QieD) 24 months (continued)
NMP2 3.8.1-9 Amendment 9)
AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)
SURVEILLANCE FREQUENCY SR 3.8.1.9 NOTES----------------
- 1.
All DG starts may be preceded by an engine prelube period.
- 2.
This Surveillance shall not be.
performed in MODE 1, 2, or 3.
However, credit may be taken for unplanned events that satisfy this SR.
Verify on an actual or simulated loss of offsite power signal:
- a.
De-energization of emergency buses;
- b.
Load shedding from emergency buses for Divisions 1 and 2 only; and
- c.
DG auto-starts from standby condition and:
- 1. energizes permanently connected loads in < 13.20 seconds,
- 2.
energizes auto-connected shutdown loads for Division 1 and 2 DGs only, through the associated automatic load sequence time delay
- relays,
- 3.
maintains steady state voltage
> 3950 V and < 4370 V,
- 4.
maintains steady state frequency
> 58.8 Hz and < 61.2 Hz, and
- 5.
supplies permanently connected and auto-connected shutdown loads for
> 5 minutes for Division 1 and 2 DGs and supplies permanently connected shutdown loads for
> 5 minutes for Division 3 DG.
3 iD) 24 months (continued)
NMP2 3.8.1-10 Amendment -91
AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS.
(continued)
SURVEILLANCE FREQUENCY SR 3.8.1.10 NOTES---------------
- 1.
All DG starts may be preceded by an engine prelube period.
- 2.
This Surveillance shall not be performed in MODE 1 or 2
- However, credit may be taken for unplanned events that satisfy this SR.
Verify on an actual or simulated Emergency Core Cooling System (ECCS) initiation signal each required DG auto-starts from standby condition and:
- a.
In
- 10 seconds after auto-start, achieves voltage > 3950 V for Division 1 and 2 DGs and > 3820 V for Division 3 DG, and frequency > 58.8 Hz for Division 1 and 2 DGs and > 58.0 Hz for Division 3 DG;
- b.
Achieves steady state voltage > 3950 V and < 4370 V and frequency > 58.8 Hz and
- 61.2 Hz;
- c.
Operates for > 5 minutes;
- d.
Permanently connected loads remain energized from the offsite power system for Divisions 1 and 2 only; and
- e.
Emergency loads are auto-connected through the associated automatic load sequence time delay relays to the offsite power system for. Divisions I and 2 only.
24 months (continued)
NMP2 3.8.1-11 Amendment-94 )
AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)
SURVEILLANCE FREQUENCY SR 3.8.1.11 NOTE----------------
This Surveillance shall not be performed in MODE 1, 2, or 3 However, credit may be taken for unplanned events that satisfy this SR.
Verify each required DG's automatic trips are bypassed on actual or simulated loss of voltage signal on the emergency bus concurrent with an actual or simulated ECCS initiation signal except:
- a.
Engine overspeed; and
- b.
Generator differential current.
24 months (continued)
NMP2 3.8.1-12 Amendment 4+-
AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued).
SURVEILLANCE FREQUENCY SR 3.8.1.14 ------------------- NOTE-----------------
This Surveillance shall not be performed in MODE 1, 2, or 3."
However, credit may be taken for unplanned events that satisfy this SR.
Verify each required DG:
- a.
Synchronizes with offsite power source while loaded with emergency loads upon a simulated restoration of offsite power;
- b.
Transfers loads to offsite power source; and
- c.
Returns to ready-to-load operation.
24 months SR 3.8.1.15 NOTE-----------------
This Surveillance shall not be performed in MODE 1, 2, or 3.__However, credit may be taken for unplanned events that satisfy this SR.
4 months 2
Verify, with a DG operating in test mode and connected to its bus, an actual or simulated ECCS initiation signal overrides the test mode by:
- a.
Returning DG to ready-to-load operation; and
- b.
Automatically energizing the emergency load from offsite power.
(continued)
NMP2 3.8.1-15 Amendment
-+.
AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)
T SURVEILLANCE FREQUENCY
- 1~
SR 3.8.1.17 NOTES----------------
- 1.
All DG starts may be preceded by an engine prelube period.
- 2.
This Surveillance shall not be performed in MODE 1, 2, or However, credit may be taken for unplanned events that satisfy this SR.
Verify, on an actual or simulated loss of offsite power signal in conjunction with an actual or simulated ECCS initiation signal:
- a.
De-energization of emergency buses;
- b.
Load shedding from emergency buses for Divisions 1 and 2 only; and
- c.
DG auto-starts from standby condition and:
- 1. energizes permanently connected loads in < 10 seconds,
- 2.
for Divisions 1 and 2, energizes auto-connected emergency loads through the associated automatic load sequence time delay relays and for Division 3, energizes auto-connected emergency loads,
- 3.
maintains steady state voltage
> 3950 V and < 4370 V,
- 4.
maintains steady state frequency
> 58.8 Hz and < 61.2 Hz, and
- 5.
supplies permanently connected and auto-connected emergency loads for
> 5 minutes.
24 months (continued)
NMP2 3.8.1-17 Amendment-@-I-
ATTACHMENT 2 NINE MILE POINT UNIT 2 CHANGES TO TECHNICAL SPECIFICATION BASES (MARK-UP)
The current versions of the following Technical Specifications Bases pages have been marked-up by hand to reflect the proposed changes. These Bases pages are provided for information only.
B 3.3.5.1-39 B 3.5.1-12 B 3.8.1-20 B 3.8.1-22 B 3.8.1-23 B 3.8.1-25 B 3.8.1-28 B 3.8.1-29 B 3.8.1-30 Nine Mile Point Nuclear Station, LLC March 30, 2009
ECCS (exe~~e.~~rF f,,;
)- Lv*cýr 3~
eavi Instrumentation B 3.3.5.1 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.3.5.1.6 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required initiation logic for a specific channel.
The system functional testing performed in LCO 3.5.1, LCO 3.5.2, LCO 3.8.1, and LCO 3.8.2 overlaps this Surveillance to provide complete testing of the assumed safety function.
The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outag, and the potential for unplanned transients if the Surveillance were performed with the reactor at power.
Operating experience has shown these components usually pass the Surveillance when performed at the 24 month Frequency.
REFERENCES
- 1.
USAR, Section 5.2.
- 2.
USAR, Section 6.3.
- 3.
USAR, Chapter 15.
- 4.
- 5.
NEDC-30936-P-A, "BWR Owners' Group Technical Specification Improvement Analyses for ECCS Actuation Instrumentation, Part 2," December 1988.
- 6.
NEDC-30851-P-A, Supplement 2, "Technical Specifications Improvement Analysis for BWR Isolation Instrumentation Common to RPS and ECCS Instrumentation," March 1989.
NMP2 B 3.3.5.1-39 Revision 11-2
ECCS-Operating (E~X~~,+/-
~r 3~L'4B 3.5.1 BASES SURVEILLANCE SR 3.5.1.5 (continued)
REQUIREMENTS The 24 month Frequency is based on-the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.
Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency, which is based on the refueling cycle.
Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
This SR is modified by a Note that excludes vessel injection/spray during the Surveillance.
Since all active components are testable and full flow can be demonstrated by recirculation through the test line, coolant injection into the RPV is not required during the Surveillance.
SR 3.5.1.6 The ADS designated S/RVs are required to actuate automatically upon receipt of specific initiation signals.
A system functional test is performed to demonstrate that the mechanical portions of the ADS function (i.e.,
solenoids) operate as designed when initiated either by an actual or simulated initiation signal, causing proper actuation of all the required components.
The LOGIC SYSTEM FUNCTIONAL TEST performed in LCO 3.3.5.1 overlap this Surveillance to provide complete testing of the assumed safety function.
The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.
Operating experience has. shown that these components usually pass the SR when performed at the 24 month Frequency, which is based on the refueling cycle.
Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
This SR is modified by a Note that excludes valve actuation.
This prevents an RPV pressure blowdown.
(continued)
NMP2 B 3.5.1-12 Revision-,',-,
AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.8.1.7 Each DG is provided with an engine overspeed trip to prevent damage to the engine.
Recovery from the transient caused by the loss of a large load could cause diesel engine overspeed, which, if excessive, might result in a trip of the engine.
This Surveillance demonstrates the DG load response characteristics and capability to reject the largest single load without exceeding predetermined frequency and while maintaining a specified margin to the overspeed trip.
The load referenced for Division 1 DG is the 1125 kW low pressure core spray pump; for Division 2 DG, the 750 kW residual heat removal (RHR) pump; and for Division 3 DG the 2435 kW HPCS pump.
The specified load values conservatively bound the expected kW rating of the single largest loads under accident conditions.
This Surveillance may be accomplished by:
- a.
Tripping the DG output breaker with the DG carrying greater than or equal to its associated single largest post-accident load while paralleled to offsite power, or while solely supplying the bus; or
- b.
Tripping its associated single largest post-accident load with the DG solely supplying the bus.
Consistent with Regulatory Guide 1.9 (Ref. 11),
the load rejection test is acceptable if the diesel speed does not exceed the nominal (synchronous) speed plus 75% of the difference between nominal speed and the overspeed trip setpoint, or 115% of nominal speed, whichever is lower.
This corresponds to _< 64.5 Hz for the Division 1 and 2 DGs and < 66.75 Hz for the Division 3 DG, which is the nominal speed plus 75% of the difference between nominal speed and the overspeed trip setpoint.
The 24 month Frequency takes into consideration the plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.
(~ic e.o ' f5 ot This SR has been modified by two Notes.
The reason for 0i,9C0"ab)e
-$ e Note I is that during operation with the reactor critical, 9performance of this SR could cause perturbations to the electrical distribution systems that could challenge continued steady state operation and, as a result, plant safety systemsl Credit may be taken for unplanned events that satisfy this SR.
In order to ensure that the DG is (continued)
NMP2 B 3.8.1-20 Revision t,
AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.8 (continued)
REQUIREMENTS representative of the actual design basis inductive loading that the DG would experience.
The 24 month Frequency takes into consideration the plant conditions required to perform theSurveillance, and is intended to be consistent with expected fuel cycle lengths.
This SR has been modified by two Notes.
The reason for Note I is that during operation with the reactor critical,
.5, Y-1 4+performance of this SR could cause perturbation to the electrical distribution systems that could challenge Of i
-continued steady state operation and, as a result, plant 3 514) safety system.
Credit may be taken for unplanned events that satisfy is SR.
Note 2 is provided in recognition that since the offsite electrical power transmission network is not balanced, it may not be possible to raise DG voltage sufficiently to meet the power factor limit without one phase of the DG exceeding the current limit.
Therefore, to ensure the DG is not placed in an unsafe condition during this test, the power factor limit does not have to be met if the offsite grid phase imbalance does not permit the power factor limit to be met when the DG is tied to the grid.
When this occurs, the power factor should be maintained as close to the limit as practicable.
SR 3.8.1.9 Consistent with Regulatory Guide 1.9 (Ref.
11),
paragraph C.2.2.4, this Surveillance demonstrates the as designed operation of the standby power sources during loss of the offsite source.
This test verifies all actions encountered from the loss of offsite power, including shedding of the nonessential loads (Divisions 1 and 2 only) and energization of the emergency buses and respective loads from the DG.
It further demonstrates the capability of the DG to automatically achieve the required voltage and frequency within the specified time.
The DG auto-start and energization of permanently connected loads time of 13.20 seconds is derived from the 3.20 second Loss of Voltage-Time Delay Function Allowable Value (LCO 3.3.8.1) and the requirements of the accident analysis for responding to a design basis large break LOCA (Ref.
14).
The Surveillance should be continued for a minimum of (continued)
NMP2 B 3.8.1-22 Rev i s i on 4K
AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS SR 3.8.1.9 (continued) 5 minutes in order to demonstrate that all starting transients have decayed and stability has been achieved.
The requirement to verify the connection and power supply of permanently connected loads and auto-connected loads (Division 1 and 2 only) is intended to satisfactorily show the relationship of these loads to the DG loading logic.
In certain circumstances, many of these loads cannot actually be connected or loaded without undue hardship or potential for undesired operation.
For instance, ECCS injection valves are not desired to be stroked open, systems are not capable of being operated at full flow, or RHR systems performing a decay heat removal function are not desired to be realigned to the ECCS mode of operation.
In lieu of actual demonstration of the connection and loading of these loads, testing that adequately shows the capability of the DG system to perform these functions is acceptable.
This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.
The Frequency of 24 months takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.
This SR is modified by two Notes.
The reason for Note I is to minimize wear and tear on the DGs during testing.
For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coolant (Division 1 and 2 DGs only) and lube oil being continuously v, 4e-icirculated and temperature maintained consistent with manufacturer recommendations.
The reason for Note 2 is that CY I 6
-V-4tke-performing the Surveillance would remove a required offsite
, q*
circuit from service, perturb the electrical distribution 3 3)4 sysem, and challenge plant safety systemsk Credit may be taken for unplanned events that satisfy this SR.
SR 3.8.1.10 Consistent with Regulatory Guide 1.9 (Ref.
11),
paragraph C.2.2.5, this Surveillance demonstrates that the DG automatically starts and achieves the required voltage and frequency within the specified time (10 seconds) from the design basis actuation signal (LOCA signal).
In addition, (continued)
NMP2 B 3.8. 1-23 Revision.1
AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.10 (continued)
REQUIREMENTS this SR could cause perturbations to the electrical distribution systems that could challenge continued steady state operation and, as a result, plant safety systeml" Credit may be taken for unplanned events that satisfy his SR.
e Consistent with Regulatory Guide 1.9 (Ref. 11),
paragraph C.2.2.12, this Surveillance demonstrates that DG non-critical protective functions (e.g., high jacket water temperature) are bypassed on a loss of voltage signal concurrent with an ECCS initiation test signal and critical protective functions (engine overspeed and generator differential current) trip the DG to avert substantial damage to the DG unit.
The non-critical trips are bypassed during DBAs and provide an alarm on an abnormal engine condition.
This alarm provides the operator with sufficient time to react appropriately.
The DG availability to mitigate the DBA is more critical than protecting the engine against minor problems that are not immediately detrimental to emergency operation of the DG.
The 24 month Frequency is based on engineering judgment, taking into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.
The SR is modified by a Note.
The reason for the Note is Sthat erforming the Surveillance removes a required DG from Aservice.
Credit may be taken for unplanned events that sQsjcvi 3 J')
atisfy this SR.
SR 3.8.1.12 Consistent with Regulatory Guide 1.9 (Ref.
11),
paragraph C.2.2.9, this Surveillance requires demonstration that the DGs can start and run continuously at full load capability for an interval of not less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br /> of which is at a load equivalent to 90% to 100% of the continuous rating of the DG and 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of which is at a load equivalent to 105% to 110% of the continuous rating of the DG.
The DG starts for this Surveillance can be performed (continued)
NMP2 B 3.8. 1-25 Revision -9.
/
AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.14 (continued)
REQUIREMENTS and can receive an auto-close signal on bus undervoltage, and the individual load timers are reset.
The Frequency of 24 months takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycles.
This SR is modified by a Note.
The reason for the Note is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems.
Credit may be taken for unplanned events that satisfy t s SR.
(No~e_ is Y1,+0o, SR 3.8.1.15 4,
S Consistent with Regulatory Guide 1.9 (Ref.
11), paragraph C.2.2.13, demonstration of the parallel test mode override ensures that the DG availability under accident conditions is not compromised as the result of testing.
Interlocks to the LOCA sensing circuits cause the DG to automatically reset to ready-to-load operation if an ECCS initiation signal is received during operation in the test mode.
Ready-to-load operation is defined as the DG running at rated speed and voltage with the DG output breaker open.
These provisions for automatic switchover are required by IEEE-308 (Ref.
17), paragraph 6.2.6(2).
The requirement to automatically energize the emergency loads with offsite power is essentially identical to that of SR 3.8.1.10.
The intent in the requirement associated with SR 3.8.1.15.b is to show that the emergency loading is not affected by the DG operation in parallel test mode.
In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the emergency loads to perform these functions is acceptable.
This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.
The 24 month Frequency takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.
(continued)
NMP2 B 3.8.1-28 Revision t
AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.15 (continued)
REQUIREMENTS This SR has been modified by a Note.
The reason for the Note is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety
~i -ie.
~yb t systems Credit may be taken for unplanned events that 4-4 satisfy this SR.
~jWIJ~l3 J~)6 SR 3.8.1.16 Under accident conditions loads are sequentially connected to the bus by the automatic load sequence time delay relays.
The sequencing logic controls the permissive and starting signals to motor breakers to prevent overloading of the DGs due to high motor starting currents.
The -10% load sequence time interval limit ensures that a sufficient time interval exists for the DG to restore frequency and voltage prior to applying the next load.
There is no upper limit for the load sequence time interval since, for a single load interval (i.e., the time between two load blocks), the capability of the DG to restore frequency and voltage prior to applying the second load is not negatively affected by a longer than designed load interval, and if there are additional load blocks (i.e., the design includes multiple load intervals), then the lower limit requirements (-10%)
will ensure that sufficient time exists for the DG to restore frequency and voltage prior to applying the remaining load blocks (i.e., all load intervals must be
> 90% of the design interval).
Reference 2 provides a summary of the automatic loading of emergency buses.
Since only the Division 1 and 2 DGs have more than one load block, this SR is only applicable to these DGs.
The Frequency of 24 months takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.
This SR is modified by a Note.
The reason for the Note is that performing the Surveillance during these MODES would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge plant safety systems.
Credit may be taken for unplanned events that satisfy this SR.
(continued)
NMP2 B 3.8.1-29 Revi si on 4 ;
- 1 AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.17 REQUIREMENTS (continued)
In the event of a DBA coincident with a loss of offsite power, the DGs are required to supply the necessary power to ESF systems so that the fuel,
- RCS, and containment design limits are not exceeded.
This Surveillance demonstrates the DG operation, as discussed in the Bases for SR 3.8.1.9, during a loss of offsite power actuation test signal in conjunction with an ECCS initiation signal.
Since the Loss of Voltage-Time Delay Functions are bypassed during an ECCS initiation
- signal, a 10 second DG start time applies.
In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the DG system to perform these functions is acceptable.
This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.
The Frequency of 24 months takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with an expected fuel cycle length.
This SR is modified by two Notes.
The reason for Note I is to minimize wear and tear on the DGs during testing.
For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coolant (Division I and 2 DGs only) and lube oil being continuously circulated and temperature maintained consistent with manufacturer recommendations.
The reason for Note 2 is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge plant safety systems.
Credit may be taken for unplanned events that satisfy t is SR.
SR 3.8.1.18 e- 'i ýISi'r i JJ)6 This Surveillance demonstrates that the DG starting independence has not been compromised.
Also, this Surveillance demonstrates that each engine can achieve proper frequency and voltage within the specified time when the DGs are started simultaneously.
(continued)
NMP2 B 3.8.1-30 Revisiont