RS-10-050, License Amendment Request to Remove Operating Mode Restrictions for Performing Division 3 AC Sources Surveillance Testing
| ML103020155 | |
| Person / Time | |
|---|---|
| Site: | Clinton  |
| Issue date: | 10/28/2010 |
| From: | Hansen J Exelon Generation Co, Exelon Nuclear |
| To: | Office of Nuclear Reactor Regulation, Document Control Desk |
| References | |
| RS-10-050 | |
| Download: ML103020155 (48) | |
Text
{{#Wiki_filter:Exelon Generation www.exeloncorp.com 4300 Winfield Road Nuclear Wanenvil1e, IL 60555 RS-10-050 10 CFR 50.90 October 28, 2010 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 Clinton Power Station, Unit 1 Facility Operating License No. NPF-62 NRC Docket No. 50-461
Subject:
License Amendment Request to Remove Operating Mode Restrictions for Performing Division 3 AC Sources Surveillance Testing In accordance with 10 CFR 50.90, "Application for amendment of license, construction permit, or early site permit," Exelon Generation Company, LLC (EGC) requests an amendment to Facility Operating License No. NPF-62 for Clinton Power Station, Unit 1 (CPS). The proposed amendment would modify CPS Technical Specifications (TS) Section 3.8.1, "AC Sources - Operating," by revising certain Surveillance Requirements (SR) related to the Division 3 AC Sources. The Division 3 AC Sources are independent sources of offsite and onsite alternating current (AC) power primarily dedicated to the High Pressure Core Spray (HPCS) system. The TS currently prohibit performing the testing required by SR 3.8.1.8 and SR 3.8.1.12 in Modes 1 or 2, and prohibit performing the testing required by SR 3.8.1.11, SR 3.8.1.16, and SR 3.8.1.19 in Modes 1, 2, or 3. The proposed amendment would remove these Mode restrictions and allow all five of the identified SRs to be performed in any operating Mode for the Division 3 AC Sources. This request is subdivided as follows:
- Attachment 1 provides a description of the proposed changes.
- Attachment 2 provides electrical drawings including protective relaying and their associated setpoints for the Division 3 electrical distribution system.
- Attachment 3 provides the relationship between current and time for the Division 3 overcurrent relays.
- Attachment 4 provides the existing CPS TS pages marked up to show the proposed changes.
- Attachment 5 provides the existing CPS TS Bases pages marked up to show the proposed changes. The TS Bases pages are provided for information only and do not require NRC approval.
The proposed change has been reviewed by the CPS Plant Operations Review Committee and approved by the Nuclear Safety Review Board in accordance with the requirements of the EGC Quality Assurance Program.
U. S. Nuclear Regulatory Commission October 28, 2010 Page 2 EGC requests approval of the proposed amendment by October 22, 2011, in order to support upcoming outage planning activities. Once approved, the amendment shall be implemented within 60 days. There are no new regulatory commitments established by this letter or any of the attachments. In accordance with 10 CFR 50.91, "Notice for public comment; State consultation," paragraph (b), EGC is notifying the State of Illinois of this application for license amendment by transmitting a copy of this letter and its attachments to the designated State Official. Should you have any questions concerning this letter, please contact Mitchel Mathews at (630) 657-2819. I declare under penalty of perjury that the foregoing is true and correct. Executed on the 28th day of October, 2010. UII R/7. Lf1;. ' j,xt~ II Jeffrey t.. Hansen Manager - Licensing and Regulatory Affairs Attachments:
- 1. Evaluation of Proposed Changes
- 2. Clinton Power Station Electrical Single Line Diagrams and Relay Settings Tables
- 3. Plot of the Clinton Power Station Division 3 Overcurrent Relay Settings (Amps versus Time)
- 4. Markup of Existing Technical Specifications Pages
- 5. Markup of Existing Technical Specifications Bases Pages (For Information Only)
Attachment 1 Evaluation of Proposed Changes Page 1 of 25
Subject:
License Amendment Request to Remove Operating Mode Restrictions for Performing Division 3 AC Sources Surveillance Testing 1.0
SUMMARY
DESCRIPTION 2.0 DETAILED DESCRIPTION 2.1 Description of the Proposed Changes 2.2 Background
3.0 TECHNICAL EVALUATION
3.1 General Basis 3.2 Transient Analysis 3.3 Administrative Controls for Online Maintenance 3.4 Online Risk Management 3.5 Online Testing Versus Outage Testing 3.6 Discussions for Individual Surveillance Requirements 3.6.1 SR 3.8.1.8 3.6.2 SR 3.8.1.11 3.6.3 SR 3.8.1.12 3.6.4 SR 3.8.1.16 3.6.5 SR 3.8.1.19
4.0 REGULATORY EVALUATION
4.1 Applicable Regulatory Requirements/Criteria 4.2 Precedents 4.3 No Significant Hazards Consideration 4.4 Conclusions
5.0 ENVIRONMENTAL CONSIDERATION
6.0 REFERENCES
Attachment 1 Evaluation of Proposed Changes Page 2 of 25 1.0
SUMMARY
DESCRIPTION This evaluation supports a request to amend Facility Operating License NPF-62 for Clinton Power Station, Unit 1 (CPS). The proposed changes would revise the Operating License to modify the CPS Technical Specifications (TS) Section 3.8.1, "AC Sources - Operating," by revising certain Surveillance Requirements (SRs) pertaining to the Division 3 AC Sources. The Division 3 AC Sources are independent sources of offsite and onsite alternating current (AC) power primarily dedicated to the High Pressure Core Spray (HPCS) system. The TS currently prohibit performing the testing required by SR 3.8.1.8 and SR 3.8.1.12 in Modes 1 or 2, and prohibit performing the testing required by SR 3.8.1.11, SR 3.8.1.16, and SR 3.8.1.19 in Modes 1, 2, or 3. The proposed amendment removes these Mode restrictions and allows all five of the identified SRs to be performed in any operating Mode for the Division 3 AC Sources only. As discussed in the TS Bases for each of these SRs, the Mode restrictions for performance of these SRs online were put into place because it was believed that performance of these SRs online would:
- 1. Perturb the electrical distribution system,
- 2. Challenge plant safety systems, and/or
- 3. Remove a required offsite circuit from service.
Sections 3.1 through 3.5 contain a detailed evaluation of these concerns for the online performance of these five SRs for Division 3. This evaluation determined that the performance of these SRs online for Division 3 is acceptable. This is due to the fact that the design of the CPS AC Sources does not present any challenge that would result in a perturbation of the electrical distribution system during the online performance of any of these SRs for Division 3. Additionally, the Division 3 safety system, HPCS, is declared inoperable during the performance of SRs 3.8.1.11, 3.8.1.16, and 3.8.1.19, and the remaining two divisions of safety systems remain unchallenged during the performance of all five of these SRs. Moreover, the brief removal of the required offsite circuit for the performance of SRs 3.8.1.11, 3.8.1.16, and 3.8.1.19, impacts Division 3 AC Sources only. As discussed in the Note to the Applicability requirements for TS 3.8.1, if the HPCS system is not Operable, the Division 3 AC electrical power sources are not required to be OPERABLE. Discussions related to the acceptability performing each of the five SRs listed above online for the Division 3 AC Sources can be found in Section 3.6. One-line electrical drawings, including protective relaying and their associated setpoints for the Division 3 electrical distribution system, are included as Attachment 2. The purpose of this attachment is to aid in the understanding of the protective relaying scheme for the Division 3 AC Sources at CPS. Additionally, a plot of the CPS Division 3 overcurrent relay settings (i.e., amps versus time) are included as Attachment 3 to further aid in understanding of the CPS Division 3 protective relaying. The proposed changes will provide greater flexibility in scheduling Division 3 AC Sources activities by allowing the testing to be performed during non-outage times. Having a completely tested Division 3 emergency diesel generator (DG) available for the duration of a refueling
Attachment 1 Evaluation of Proposed Changes Page 3 of 25 outage will reduce the number of system re-alignments and operator workload during an outage. Additionally, performing Division 3 AC Sources activities online increases the Division 3 DG and HPCS system availability during refueling outages and allows the testing of the Division 3 systems to be conducted when both Division 1 and 2 systems are required to be OPERABLE. 2.0 DETAILED DESCRIPTION 2.1 Description of the Proposed Changes The proposed amendment includes the following revisions to TS Section 3.8.1: SR 3.8.1.8: Revise Note 2 to remove the restriction that prohibits performance of the SR in Modes 1 or 2, for Division 3 AC sources only. This SR requires verification of the automatic and manual transfer of unit power supply from the normal offsite circuit to the alternate offsite circuit. SR 3.8.1.11: 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, energizes permanently connected loads in 12 seconds, achieves and maintains the required voltage and frequency, and supplies permanently connected loads for 5 minutes. SR 3.8.1.12: 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. SR 3.8.1.16: 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 3.8.1.19: 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, and supplies permanently connected loads for 5 minutes. provides markups of the existing TS pages to show the proposed changes. Mark-ups of the current TS Bases pages are provided in Attachment 5 for information only and do not
Attachment 1 Evaluation of Proposed Changes Page 4 of 25 require NRC approval. The TS Bases changes will be processed in accordance with the CPS TS Bases Control Program (i.e., TS Section 5.5.11). 2.2 Background CPS Technical Specifications (TS) Section 3.8.1, "AC Sources -Operating," specifies requirements for the Electrical Power Distribution System AC Sources. The Class 1E AC Electrical Power Distribution System AC sources at CPS consist of the offsite power sources and the onsite standby power sources, (i.e., Diesel Generators (DGs) 1A, 1B, and 1C). DGs 1A, 1B, and 1C are also referred to as the Division 1 DG, the Division 2 DG, and the Division 3 DG, respectively. As required by 10 CFR 50, Appendix A, GDC 17, "Electric power systems," 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 Class 1E AC distribution system at CPS supplies electrical power to three divisional load groups, with each division powered by an independent Class 1E 4.16 kV ESF bus. Each ESF bus is capable of being supplied by either of two separate and independent offsite sources of power. Each ESF 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. Offsite power is supplied to the CPS switchyard from the transmission network. As shown in Figure 1 below, the unit auxiliary transformers (UATs) normally supply power to the non-safety related loads using the main generator as a power source. The secondary source of unit auxiliary AC power is the three reserve auxiliary transformers (RATs) (i.e., RAT A, RAT B, and RAT C). Each RAT is rated at 33.3 MVA. RAT A feeds the 6.9 kV switchgear buses and is sized to carry the startup and running load of the unit from these buses. RAT B feeds the 4.16 kV Class 1E Buses 1A1, 1B1, and 1C1 along with 4.16 kV non-Class 1E Bus 1A, and is sized to carry the startup and running loads for these buses as well as the total coincidental LOCA load for the unit. RAT C feeds the 4.16 kV non-Class 1E Bus 1B and is sized to carry the startup and running load of this bus. All three RATs are connected to the 345 kV switchyard through individual high side disconnects by a common overhead transmission line. Alternatively, an electrically and physically independent 138 kV power source can provide AC power to each of the 4.16 kV ESF buses 1A1, 1B1, and 1C1 via the emergency reserve auxiliary transformer (ERAT). The ERAT is normally energized, but unloaded during at-power operations and is rated to carry 30 MVA.
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) SOlE Figure 1: Simplified Drawing of the CPS AC Power Distribution System The offsite AC electrical power sources are designed and located to minimize the likelihood of their simultaneous failure under operating and postulated accident and environmental conditions. A detailed description of the offsite power network and circuits to the onsite Class 1E ESF buses is found in Updated Safety Analysis Report (USAR), Chapter 8.
An 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 1E ESF bus(es). A permanently installed static VAR compensator (SVC) is also available onsite and is normally connected to each offsite circuit to support required voltage for the ESF buses. The onsite standby power source for each 4.16 kV ESF bus is a dedicated DG. A DG starts automatically upon receipt of a loss of coolant accident (LOCA) signal (i.e., low reactor water level signal or high drywell pressure signal) or an ESF bus degraded voltage or undervoltage signal. In the event of a loss of offsite power (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 Design Basis Accident such as a LOCA. Each DG must be capable of starting, accelerating to rated speed and voltage, and connecting to its respective ESF bus on detection of bus undervoltage. Each DG must also be capable of accepting required loads within the assumed loading sequence intervals, and must continue to operate until offsite power can be restored to the ESF buses. The Division 3 DG does not have any auto-connected loads.
Attachment 1 Evaluation of Proposed Changes Page 6 of 25 These capabilities are required to be met from a variety of initial conditions such as DG in standby with engine hot and DG in standby with engine at ambient conditions. Additional DG capabilities must be demonstrated to meet required Surveillances, (e.g., capability of the DG to revert to standby status on an ECCS signal while operating in parallel test mode). The AC Sources in one division must be separate and independent to the extent possible of the AC Sources in the other division(s). For the DGs, the separation and independence are complete. For the offsite AC Sources, the separation and independence are to the extent practical since each power source can provide AC power to each of the 4.16 kV ESF buses 1A1, 1B1, and 1C1. A circuit may be connected to more than one ESF bus, with fast transfer capability to the other circuit Operable, and not violate separation criteria. The Division 3 (i.e., HPCS) power system loads consist of the HPCS pump motor and associated 480 VAC auxiliaries such as motor operated valves, shutdown service water (SX) pump C, and miscellaneous diesel engine auxiliary loads. In addition, the Division 3 DG supplies power to the Division 3 Nuclear System Protection System (NSPS) inverter. This inverter is the normal power supply for Division 3 Reactor Protection System (RPS) instrumentation and Division 3 Source Range Monitor (SRM). The Division 3, HPCS power system is self-contained except for access to both sources of offsite power, directly by connection through the plant AC power distribution system, and for the system initiation signal source. It is operable as an isolated system independent of the electrical connection to any other system by use of the Division 3 diesel generator. Standby auxiliary equipment such as heaters, air compressor, cooling water pumps and battery charger are supplied from the same power source as the HPCS pump motor. The diesel generator is compatible with power available from the plant AC power system. The Division 3 diesel generator (i.e., DG 1C) has the capability to restore onsite power quickly to the HPCS pump motor in the event offsite power is unavailable, and to provide all power for startup and operation of the HPCS system. The Division 3 diesel generator will start automatically on signal from the plant protection system or HPCS supply bus undervoltage, and when both plant offsite sources are not available, will be automatically connected to the HPCS bus. An automatic start signal overrides the test mode. The General Electric HPCS system power supply unit Licensing Topical Report, NEDO-10905, gives the starting and accelerating characteristics of the diesel generator set with the various loads in the proper sequence. Although the voltage and frequency characteristics do not meet NRC Regulatory Guide 1.9, "Application and Testing of Safety-Related Diesel Generators in Nuclear Power Plants," justification for this is given because of the unique requirements of the system. The Division 3 diesel generator is unique in that its load is composed predominantly of one large motor whose horsepower is approximately the same as the diesel-engine. The analytical results from a digital dynamics stability program, and prototype tests performed, demonstrate the capability of the diesel-generator and of the equipment associated with the system to meet all necessary requirements. The NRC has previously accepted this analysis which is contained in the NEDO-10905 document. All safety related continuous duty motors have the ability to deliver their rated horsepower continuously without damage when the voltage at the terminals is 10% above or below rated
Attachment 1 Evaluation of Proposed Changes Page 7 of 25 voltage with rated frequency. These motors can also deliver their full load torque without damage when the voltage at the terminal drops to 75% for infrequent one-minute intervals. The starting sequence provides for containing Division 3 diesel generator voltage drops down to 62% of rated voltage. This dip in voltage lasts for 1 second and would recover to 75% volts after this time frame. This time frame is short enough to prevent the loss of flux to the field. Therefore, no motor damage or malfunction will occur and the present supply to the motor is adequate. The Division 3 diesel generator is capable of starting the HPCS motor within the required time in accordance with NEDO-10905 although voltage and frequency drop will exceed the limits specified in NRC Regulatory Guide 1.9. In addition and as stated in CPS Updated Safety Analysis Report (USAR) Subsection 8.3.1.2.2, the Division 3 diesel generator design includes override capability to ensure automatic switchover from the test mode to ready-to-load operation upon receipt of a LOCA initiation signal consistent with the requirements of IEEE 308 and 387. However, the Division 3 diesel generator is equipped with a mechanical governor that operates only in a droop mode. Normally, the droop setting is set to zero, but during testing (i.e., while the diesel generator is in the test mode) a non-zero droop setting is utilized to support paralleling the diesel generator with the offsite power source. Under such conditions, the droop may be set such that, if a LOCA initiation signal were received concurrent with no offsite power available to the Division 3 bus, operator action may be required to reset the governor and thus ensure bus frequency is within required limits when the diesel generator alone is supplying power to the bus. The droop mode, as described above, is utilized only during testing. Procedural guidance is given to the main control room operator to adjust engine speed if required in order to restore bus frequency to within the required range. In addition, a dedicated operator is assigned to reset the governor in the event of a LOCA concurrent with a LOOP during testing evolutions. As discussed in CPS USAR Section 8.3.1.1.2.1, a risk assessment performed for the LOCA concurrent with a LOOP demonstrates that the risk associated with this system configuration is very small. Additionally, this condition is not unique to the testing proposed in this request. This condition exists any time the Division 3 DG is operated in test mode and in parallel with offsite sources such as during monthly Division 3 DG testing in accordance with SR 3.8.1.2 or SR 3.8.1.3. On this basis, the Division 3 diesel generator design, with respect to automatic switchover capability from the test mode to ready-to-load operation, has been determined to be acceptable. Mechanical safety trips recommended by the Division 3 diesel generator vendor and the electrical protective tripping scheme are consistent with the Division 1 and 2 diesel generator tripping schemes and meet the requirements of Regulatory Guide 1.9. All trips except overspeed and generator differential are bypassed on a LOCA. In this way, the diesel generator availability is fully assured during an offsite power loss. The HPCS power system is capable of performing its function when subjected to the effects of design basis natural phenomena. In particular, it is classified as Class 1E and Seismic Category I and is housed in a Seismic Category I structure.
Attachment 1 Evaluation of Proposed Changes Page 8 of 25 The HPCS power system has its own fuel day tank and storage tank with sufficient capacity to operate the standby power source while supplying maximum post-accident HPCS power requirements for a time sufficient to put the plant in a safe condition. Tank size is consistent with availability of backup fuel sources. A Class 1E DC power supply system provides the HPCS system DC power requirements for control and protection. 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 full-flow test lines to and from the suppression pool and the Reactor Core Isolation Cooling (RCIC) storage tank. Additionally, the HPCS pump is provided with a minimum flow bypass line, which discharges to the suppression pool. The valve in this minimum flow bypass line (i.e., 1E22-F012) automatically opens to prevent pump damage due to overheating when other discharge line valves are closed. When suction is taken from the RCIC storage tank or the suppression pool, the minimum flowpath from the HPCS pump discharge is routed to the suppression pool. The 1E22-F012 minimum flow valve automatically opens when HPCS pump discharge pressure increases above 145 psig, and discharge flow is less than 625 gpm. 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 AC Sources testing pursuant to the subject SRs while in any operational mode. The HPCS system can be tested at full flow with RCIC storage tank water at any time during plant operation except when the reactor vessel water level is low, or when the water level in the RCIC storage tank is low, or when the valves from the suppression pool to the pump are open. If an initiation signal occurs while the HPCS is being tested, the system returns automatically to the operating mode. The two motor-operated valves in the test line to the RCIC storage system are interlocked closed when the suction valve from the suppression pool is open. A design flow functional test of the HPCS system is performed by pumping water from the RCIC storage tank and back through the full flow test return line to the RCIC storage tank.
3.0 TECHNICAL EVALUATION
3.1 General Basis Although the TS Bases, as currently written, state that the reasons for the SR Notes imposing Mode restrictions is to preclude the potential for perturbations of the electrical distribution system during plant operation, challenge to plant safety systems, and removal of a required offsite circuit from service, reconsideration of these bases for the Division 3 AC Sources has determined that the noted concerns are not warranted with respect to requiring the affected SRs to be performed only during shutdown conditions. This conclusion is based on: (1) the CPS AC power system design and associated protection features; (2) plant experience with the performance of testing required in accordance with the affected SRs; (3) administrative controls that minimize plant risks during performance of the affected testing; and (4) the low probability
Attachment 1 Evaluation of Proposed Changes Page 9 of 25 of a significant voltage perturbation during such testing. A detailed discussion of this analysis is contained in Sections 3.2 through 3.5. For each of the independent offsite circuits at CPS, a permanently installed static VAR compensator (SVC) is provided which is normally connected to the secondary side of the associated auxiliary power transformer (e.g., RAT B or ERAT) via two in-series circuit breakers. The ERAT SVC and RAT B SVC provide steady state, dynamic, and transient voltage support to ensure that the Class 1E loads will operate as required during anticipated or postulated events. However, as noted in the Bases for LCO 3.8.1, SVC support of the offsite power sources may not be required at all times, depending on prevailing grid conditions relative to the requirements of the facility. The internal control system for each SVC includes control and protective functions. However, backup protection is provided by a fully redundant and independent protection system, consisting of two redundant subsystems for each SVC, for fail-safe performance of the overall SVC system. Operability of these redundant protection subsystems is addressed by LCO 3.8.11. The redundant protection subsystems are powered from independent DC supplies. Each subsystem activates separate and independent relays, which in turn will automatically open the two main SVC circuit breakers to automatically disconnect the SVC from the 4.16 kV circuit in response to various SVC failure conditions. The SVC main circuit breakers are redundant for increased protection against breaker failure. The SVCs ensure that minor transmission network voltage instabilities do not impact the voltage support for the associated Class 1E loads. However, if the voltage did begin to degrade with a DG operating in parallel with the ERAT or RAT B, the associated SVC would attempt to raise voltage until it reached 28.5 MVar, and then the DG voltage regulator would increase field current in an effort to raise terminal voltage until the voltage regulator reached its limit. CPS declares the Division 3 DG inoperable during the subject surveillance testing due to the DG governor speed droop being set at its midpoint during the test. Additionally, the Division 3 DG and its associated loads are 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, SR 3.8.1.16, is performed by paralleling the DG in test with offsite power, similar to the existing monthly run of the DG (i.e., to meet SRs 3.8.1.2 and 3.8.1.3), which is conducted with the plant online. Furthermore, performance of the required testing online does not challenge the Division 1 and Division 2 safety systems since the combined LOCA loading of all three 4.16 kV buses is well within the capabilities of the ERAT and RAT B and the Division 1 and Division 2 safety systems remain isolated from the power sources undergoing testing. Additionally, performance of the testing online as proposed will not impact the RCIC system, which provides a function similar to the HPCS system as discussed in TS 3.5.3, "RCIC System." The RCIC pump consists of a steam driven turbine pump unit, piping, and valves to provide steam to the turbine, as well as piping and valves to transfer water from the suction source to the core via the reactor head cooling spray nozzle. Since the RCIC steam turbine drives the RCIC pump, and none of the RCIC support equipment is powered from Division 3, the RCIC system will not be impacted by online testing of the Division 3 AC Sources. Finally, testing in the proposed manner does not interfere with normal plant operation.
Attachment 1 Evaluation of Proposed Changes Page 10 of 25 3.2 Transient Analysis Degraded Voltage Prior to commencing testing, CPS procedures require verification that both offsite power sources are in a condition that supports testing. This verification includes confirmation that both SVCs are operable and the 345 kV ring bus is intact prior to initiating the test. If any of the above conditions are not met before or during the testing, the test will be terminated. With the 4.16 kV buses in a normal testing alignment as discussed above, and the Division 3 DG operating in parallel with offsite via RAT B, a degraded voltage condition could not occur, since RAT B is powered from the 345 kV switchyard. With the ring bus intact, the normal operating band for the CPS main generator output (i.e., 359 kV-362 kV as specified in CPS procedure 3005.01, "Unit Power Changes," Section 8.1.19) will maintain grid voltage well above degraded voltage values. Testing would be terminated if the ring bus was opened or normal operating parameters on the main generator could not be maintained. To enter into a degraded voltage condition while performing testing with the Division 3 DG operating in parallel with offsite via the ERAT, extreme conditions would have to exist. The ERAT SVC would have to be at its maximum output of 28.5 MVar and the 138 kV system would have to be below the Real Time Contingency Analysis (RTCA) monitoring value. The reliability coordinator and balancing authority and transmission operator (i.e., MISO and AmerenIP, respectively) continuously monitor the 138 kV and 345 kV systems and alert CPS of degrading grid conditions. The degraded voltage alarm setpoints at CPS were chosen such that CPS is notified before reaching the degraded voltage relay setpoint. If the voltage began to degrade and went unnoticed, the SVC output would increase until it reached 28.5 MVar and the Division 3 DG voltage regulator would increase field current in an effort to raise terminal voltage until the regulator reached its limit. The DG would continue to operate normally with the voltage regulator at maximum output. The frequency would remain within limits and there would be no significant change in the loading on the diesel. This condition would have no impact on the DG or associated loads. If this condition did occur, the second level undervoltage relays would pickup as soon as the DG output breaker is opened, because the DG would no longer be providing reactive power to support system voltage. The Division 3, 4.16 kV bus would then automatically transfer back to the Division 3 DG after the degraded voltage relay time delay expires. Since CPS has SVCs supporting both offsite sources, the conditions necessary for CPS to enter into a degraded voltage condition on the 4.16 kV buses in any operational configuration would be severe to the extent that all AC Sources testing would be terminated. In summary, based on the administrative controls regarding the availability and quality of offsite power sources found in CPS procedures, design of the CPS offsite power systems, the design of the Division 3 electrical power distribution system protective relaying, and the support of 4.16 kV bus voltage provided by the CPS SVCs, there is no additional adverse condition introduced by testing in the proposed manner.
Attachment 1 Evaluation of Proposed Changes Page 11 of 25 Loss of Offsite Power (LOOP) A significant overload of the Division 3 DG could result if operating in parallel with an offsite source that experiences a loss of power. A substantial number of variables must be considered when analyzing scenarios with the Division 3 DG operating in parallel with an offsite source should a LOOP occur. Multiple line-ups, initial loading, and the vast number of potential LOOP scenarios make it difficult to analyze for each possibility. However, there are only three potential outcomes of concern. These outcomes are:
- 1) The diesel is loaded within its capability,
- 2) The diesel is loaded at or near its full fuel rack position, and
- 3) The diesel is loaded beyond its full fuel rack position.
Each of these outcomes is discussed in detail below. First, if the Division 3 DG is loaded within its capability, it will continue operate with no adverse consequences. Secondly, prolonged operation at or near the Division 3 DG fuel rack limit could result in turbo-charger damage due to over-temperature and over-speed. There is no specific guidance on how long this condition must exist before damage occurs. However, according to the vendor for CPS DGs, operating at the Division 3 DG full fuel rack limit for 15 minutes without experiencing damage is reasonable and operation in this condition for up to 30 minutes may be possible. This guidance is based on industry experience including non-nuclear operating experience. This experience has shown that the majority of turbo-charger damage that has been experienced occurred during operation at the DG full fuel rack limit in marine applications, typically poorly maintained tug boats. It should be noted that loading conditions at or near the fuel rack limit would be unlikely. The most likely DG overload scenarios involve transient loading within the Division 3 DG's capability or in excess of its capability. Industry experience also indicates that there is sufficient time for manual operator action to terminate the test and prevent turbo-charger damage in this scenario. Lastly, significant overloading beyond the Division 3 DG capability would begin to stall the DG. At that point, multiple protective relay actuation sequences would begin. Many variables must be considered, and it is difficult to accurately determine which device would actuate first. However, when presented with a load beyond fuel rack limit, the DG would begin to stall within seconds. DG frequency would decay first followed by voltage. At some point, a protective relay would actuate and isolate the Division 3 DG from the offsite source. The DG would rapidly accelerate from a reduced speed to the governor setpoint of 900 RPM due to the DG being unloaded with the DG fuel rack at its full open position. According to the vendor for the CPS Division 3 DG, the inertia and acceleration presented by this instantaneous loss of engine load would most likely carry the DG beyond its overspeed limit before the governor could respond, resulting in a DG lockout. Although the Division 3 DG is designed to withstand a full load rejection without an overspeed, it is conservative to assume the overspeed lockout occurs. No damage is expected to occur to the Division 3 DG in this scenario.
Attachment 1 Evaluation of Proposed Changes Page 12 of 25 All three potential outcomes resulting from a LOOP concurrent with the Division 3 DG paralleled to an offsite source are recoverable with no damage to the DG. Moreover, these scenarios are not introduced by testing in the proposed manner. These scenarios have been previously analyzed and found to be acceptable. The overload conditions described above would not occur if a concurrent LOCA signal is present. LOCA control logic automatically trips the DG output breaker when the DG is paralleled with an offsite source. The LOCA scenario is further discussed below. In summary, while there is a potential for a DG lockout to occur if the DG were to experience an extreme overload condition during online testing, there is no potential to damage the Division 3 DG in any overload condition that might occur during DG testing. Moreover, as described above, none of the outcomes associated with a LOOP are introduced by testing in the proposed manner or made more likely by performing this testing on line. Loss of Coolant Accident (LOCA) Upon receipt of a LOCA signal while the Division 3 DG is operating in parallel with an offsite source (i.e., RAT B or the ERAT), the diesel output breaker, 252-DG1C, will trip open, leaving the 1C1 bus powered solely from the offsite source. The Division 3 DG will remain in a ready-to-load condition. In summary, the system response to the receipt of a LOCA signal will not be changed, nor will any adverse conditions be introduced by testing in the proposed manner. 3.3 Administrative Controls for Online Maintenance The CPS TS impose requirements and restrictions on the amount of equipment allowed out of service at any given time. Inoperable ECCS or RCIC components or DGs on the redundant division would cause entry into other more stringent Required Actions, thus providing further incentive not to perform testing on Division 3 AC Sources with redundant equipment inoperable. Additionally, the Safety Function Determination Program, required by TS Section 5.5.10, "Safety Function Determination Program (SFDP)," ensures that a loss of safety function is detected and appropriate actions taken. The CPS 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. CPS 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 AC Sources in place, it is only possible for one DG to be affected by an unstable offsite power system.
Attachment 1 Evaluation of Proposed Changes Page 13 of 25 In summary, even if a Division 3 power source were adversely impacted while testing in the proposed manner, the impact will be limited to Division 3 AC Sources. Plant safe shutdown capability will continue to be assured by the two remaining divisions of AC Sources. 3.4 Online Risk Management The EGC procedure WC-AA-101, "On-Line Work Control Process," provides requirements to conduct a configuration risk assessment for all maintenance performed while CPS 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. According to WC-AA-101, Section 4.3.3, plant risk shall be managed by the most restrictive risk threshold as defined in WC-AA-101, Attachment 3, "Configuration Risk Management Criteria." The results of this risk evaluation are compared to specific risk thresholds. If these thresholds are exceeded, the schedule must be adjusted and appropriate risk reducing compensatory actions must be implemented prior to beginning work. These administrative controls minimize the potential to allow work on redundant or diverse SSCs such as the DGs or other systems that are similar to those supplied by the affected DG, without appropriate compensatory actions. Allowing this testing to be performed online allows this testing to be performed during a period when all Division 1 and 2 systems are required to be operable, and maximizes the time that the independent HPCS system is available for reactor pressure vessel injection during plant outages. In accordance with WC-AA-101, Section 4.3.4, new plant risk considerations should be implemented as a change to the station's risk assessment model where appropriate. This process ensures that station's risk calculations adequately reflect the unique attributes of the plant configuration. In summary, EGC procedures currently require an evaluation of the unique plant configurations introduced by performing SR 3.8.1.8, SR 3.8.1.11, SR 3.8.1.12, SR 3.8.1.16, and SR 3.8.1.19 online, and where appropriate, an update of the CPS risk management model to include the impact of these configurations prior to their performance while the plant is online. 3.5 Online Testing Versus Outage Testing Due to the relationship between the Division 3 DG and the HPCS system, the TS allow up to 14 days of inoperability for the HPCS system, and consequently allow up to 14 days of inoperability for the Division 3 DG if the RCIC system is operable. Thus, the existing TS 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 16 hours. A comparison of the TS requirements for emergency core cooling systems (ECCS) (i.e., TS 3.5.1 and 3.5.2) and AC Sources (i.e., 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
Attachment 1 Evaluation of Proposed Changes Page 14 of 25 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 HPCS system is a stand-alone system with a dedicated DG and independent electrical distribution system. As discussed in CPS USAR Sections 6.3.1.1.3 and 8.3.1.4, this system is both physically and electrically separated from the other two safety-related divisions. 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 power to the HPCS pump motor and associated support equipment and auxiliaries. In addition, the Division 3 DG supplies power to the Division 3 Nuclear Systems Protection System (NSPS) inverter. This inverter is the normal power supply for Division 3 Reactor Protection System (RPS) instrumentation and Division 3 Source Range Monitor (SRM). The inverter loads are supported by a battery that is designed to carry the loads for up to four hours if the inverter is output voltage is lost. Due to the duration of the testing, loss of these loads is not likely. However, if the NSPS inverter were lost for greater than four hours, the associated Division 3 isolation instruments fail safe, and a loss of power to the Division 3 SRM would have no greater consequence during testing in the proposed manner than if it were lost during plant Modes currently required by TS. The Division 1 and Division 2 safety systems remain isolated from the power sources undergoing testing. Therefore, there is minimal opportunity for the performance of these SRs to have any impact on other safety-related plant equipment. As previously discussed, the HPCS system has a full flow suction line and a return line to both the suppression pool and the RCIC storage tank, and an automatically actuated minimum flow line to the suppression pool. These features allow testing of the system online without discharging into the reactor vessel, while providing protection of the pump from overheating. Additionally, system configuration is such that HPCS system testing can be performed without impacting other divisional safety systems or the RCIC system. During both normal plant operation and during shutdown conditions, the three 4.16 kV emergency buses are normally aligned to RAT B. The likelihood of voltage perturbations on the 4.16 kV buses during testing of the AC Sources with the plant online will not differ from the likelihood of voltage perturbation during testing of the AC Sources with CPS in a shutdown condition since loading on RAT B is not significantly different with the unit online versus during shutdown conditions, and the ERAT is sufficiently rated to preclude any testing-induced voltage perturbations. Safety buses 1A1, 1B1, and 1C1 are normally aligned to RAT B during normal at power operation. RAT B is sized to handle all startup, shutdown, trip, and LOCA loading. Normal safety bus loading on RAT B at power is between 2.19 MW and 2.21 MW. Shutdown loading on RAT B ranges from 1.8 MW to 3.2 MW. As previously discussed, the rating of RAT B is 33.3 MVA. MODE 1 summer operation with Class 1E and non-1E loads fed from RAT B presents a load of 16.13 MVA. Adding 2.02 MW at 0.80 power factor (i.e., 2.53 MVA) for Division 3 AC Sources would result in a load of 18.66 MVA. This is only 56% of RAT B rated capability. In addition, non-1E loads will be powered from UAT 1A, not RAT B, during this testing. The ERAT is normally in a standby alignment during normal plant operation and is sufficiently rated to carry the loads of all three safety buses and to provide all 1E LOCA loads. Normal
Attachment 1 Evaluation of Proposed Changes Page 15 of 25 online safety bus loading for all three safety buses is approximately 2.2 MW. Addition of the Division 3 Class 1E loads will result in an ERAT load of approximately 4.23 MW versus the ERAT rating of 30 MVA. This is well within the rating of the ERAT. The HPCS loads are less than 10% of RAT B and ERAT ratings. Moreover, there is no configuration presented by this testing that would compromise the integrity of either transformer. There are no additional concerns introduced by performing these tests online versus performing offline based on electrical loading. In summary, there is no configuration introduced by testing in the proposed manner that would approach the rating of RAT B or the ERAT. CPS has SVCs installed on the output of the ERAT and RAT B. The purpose of the SVCs is to maintain safety bus voltage, and compensate for any transmission system voltage fluctuations that might occur. This voltage compensation will be available during testing with the Division 3 DG operating in parallel with offsite power in all modes of plant operation. 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, ensuring that no transients will be introduced by the actuation of protective relays at power. The proposed license amendment does not alter any of the TS-required DG surveillance test frequencies; thus, the total number of tests and associated transients would be unchanged by performing this testing online versus during shutdowns. According to the CPS USAR, the maximum total Division 3 DG load for a simultaneous LOCA and LOOP is 2020 kW, with the largest load being the 1838 kW HPCS pump (i.e., approximately 91% of the total Division 3 DG load). As previously discussed, the Division 3 load is a small percentage of the ERAT and RAT B ratings 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 online or during shutdown conditions, creates minimal potential to cause a significant electrical distribution system perturbation. In fact, HPCS pump starts are routinely performed online to satisfy quarterly inservice testing requirements, without disturbing plant operations. In summary, starting the HPCS pump online is a routine evolution; therefore, there is no potential to create an electrical distribution system perturbation introduced by testing the HPCS system in the proposed manner. 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 366 hours for a 24-month rolling period. Based on this criterion, CPS has established an administrative goal of 125 hours of unavailability for the 24- month period. In summary, the addition of 16 hours of unavailability per 24-month period does not challenge achievement of the EGC-established performance criteria for the Division 3 DG.
Attachment 1 Evaluation of Proposed Changes Page 16 of 25 3.6 Discussions for Individual Surveillance Requirements 3.6.1 SR 3.8.1.8 For Division 3, SR 3.8.1.8 requires verification of the transfer of unit power supply from the normal to the alternate offsite circuit in both automatic and manual modes. For Division 3, the verification of the automatic transfer from the normal to the alternate offsite circuit (i.e., RAT B to ERAT) is limited to Bus 1C1, and is accomplished by simulating a loss of RAT B by opening test switches on the Bus 1C1 main feed breaker and verifying that the main feed breaker opens and that the Bus 1C1 reserve feed breaker closes. In addition, an automatic transfer from the normal offsite source to the alternate offsite source for Division 3 is accomplished by: tripping the Bus 1C1 main feed breaker by placing its control switch in the pull to lock position, verifying that the Bus 1C1 main feed breaker opens, and verifying that the Bus 1C1 reserve feed breaker closes and energizes the 1C1 4.16 kV Bus. The performance of SR 3.8.1.8 for Division 3 does not require verification that Bus 1C1 will automatically transfer back to RAT B; however, this test is performed to ensure that RAT B remains operable. This verification is accomplished by: tripping the Bus 1C1 main feed breaker through placement of its control switch in the pull to lock position, verifying that the Bus 1C1 reserve feed breaker opens, and verifying that the Bus 1C1 main feed breaker closes and energizes Bus 1C1. Currently, this SR contains a Note that prohibits performance in Modes 1 or 2. The TS Bases state that the reason for this Note is that, during operation with the reactor critical, performance of this SR could cause perturbations to the electrical distribution systems that could challenge continued steady state operation and, as a result, plant safety systems. First, as previously discussed, the Division 3 electrical loads do not approach the electrical load rating of either RAT B or the ERAT; therefore, there is no impact to the electrical distribution system, and no mechanism for challenging continued steady state operation when performing this SR for Division 3. In addition, buses are manually transferred on a routine basis to support monthly testing of the DG. Lastly, the HPCS system is a stand-alone system with a dedicated DG and independent electrical distribution system (i.e., Division 3). When performing this SR for Division 3, the simulated loss of RAT B signal and the breaker manipulations discussed above are generated only in the Division 3 logic and do not affect the other two safety-related electrical divisions. Furthermore, Division 3 loads such as the Division 3 SRM and RPS isolation features are supported by a battery that is designed to carry these loads for up to four hours. Thus, performing SR 3.8.1.8 for Division 3, whether shutdown or online, affects only the HPCS system. Therefore, the reasons for the mode restrictions stated in the TS Bases for SR 3.8.1.8 are not valid for the Division 3 AC Sources.
Attachment 1 Evaluation of Proposed Changes Page 17 of 25 3.6.2 SR 3.8.1.11 For Division 3, SR 3.8.1.11 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 CPS design for the Division 3 DG does not feature automatic sequencing of loads. With the Division 3, 4.16 kV emergency bus aligned to RAT B, a LOOP is simulated by the use of relay test 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. Currently, this SR contains a Note that prohibits performance in Modes 1, 2, or 3. The TS Bases state the reason for this Note is that performing the surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge plant safety systems. First, although the offsite source of power to the Division 3 emergency bus is disconnected when performing this SR for Division 3, 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. As discussed in the Note to the Applicability requirements for TS 3.8.1, the Division 3 AC electrical power system is not required to be operable when the HPCS system is inoperable. Secondly, due to the relative size of the loads associated with the HPCS system and the Division 1 and Division 2 safety systems remain isolated from the power sources undergoing testing, there is minimal potential when performing this testing for Division 3 to create an offsite power supply perturbation that could affect the Division 1 and 2 safety systems when the Division 3, 4.16 kV emergency bus is de-energized. Lastly, the Division 3 power system is an independent electrical distribution system with a dedicated DG. Division 3 loads such as the Division 3 SRM and RPS isolation features are supported by a battery that is designed to carry these loads for four hours; therefore, there is minimal opportunity for the performance of this SR for the Division 3 DG 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 or their associated loads. Therefore, the reasons for the Mode restrictions stated in the TS Bases for SR 3.8.1.11 are not valid for the Division 3 DG.
Attachment 1 Evaluation of Proposed Changes Page 18 of 25 3.6.3 SR 3.8.1.12 For Division 3, SR 3.8.1.12 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. For Division 3, 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 (i.e., generator output breaker is open) for 5 minutes while acceptable performance parameters (voltage and frequency) are verified. The HPCS pump start is manually overridden by removing the close and trip fuses for the pump motor breaker, and opening of the motor-operated injection valve (i.e., 1E22-F004) 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. Currently, this SR contains a Note that prohibits performance in Modes 1 or 2. The TS Bases state the reason for this 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. First, since this test is conducted with the Division 3 DG unloaded and isolated from its emergency bus when performing this SR for Division 3, there is no impact to the electrical distribution system, and no mechanism for challenging continued steady state operation. Lastly, the Division 3 power system is an independent electrical distribution system with a dedicated DG. Division 3 loads such as the Division 3 SRM and RPS isolation features are supported by a battery that is designed to carry these loads for four hours; therefore, there is minimal opportunity for the performance of this SR for the Division 3 DG to have any impact on other safety-related plant equipment or normal plant operation. When performing this SR for Division 3, the simulated ECCS initiation signal is generated only in the HPCS logic and does not affect the other two safety-related electrical divisions or their associated loads. Thus, performing the SR 3.8.1.12 test for the Division 3 DG, whether shutdown or online, affects only the HPCS system. Therefore, the reasons for the mode restrictions stated in the TS Bases for SR 3.8.1.12 are not valid for the Division 3 DG.
Attachment 1 Evaluation of Proposed Changes Page 19 of 25 3.6.4 SR 3.8.1.16 For Division 3, SR 3.8.1.16 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. The Division 3 test is typically performed following completion of the LOOP test of SR 3.8.1.11 for aligning the Division 3, 4.16 kV emergency bus to RAT B, and following completion of the LOOP/LOCA test of SR 3.8.1.19 for aligning the Division 3, 4.16 kV emergency bus to RAT B. After the Division 3 DG has started and re-energized its associated emergency bus, the HPCS pump is started and placed in the full flow test mode. Actual discharge of water into the reactor vessel by the HPCS system is prevented as discussed under SR 3.8.1.19. 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 is then opened and the DG is verified to return 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 this Note is that performing the surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge plant safety systems. First, although the offsite source of power to the Division 3 emergency bus is disconnected at the beginning of this test when performing this SR for Division 3, the period of time that this condition exists is small and is acceptable since the HPCS system is already declared inoperable for performance of the test; therefore, the Division 3 DG is not required to be operable as discussed in the Note associated with the Applicability requirements for TS 3.8.1. Secondly, the offsite power source for the Division 3, 4.16 kV emergency bus during the test is the ERAT or RAT B, 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 remain within expected limits and no anomalous actions regarding load transfer sequences occur. Conducting this test for Division 3 online is not expected to be more challenging to plant safety systems than performance during shutdown conditions. Additionally, as discussed in Section 3.5, due to the relative size of the loads associated with the HPCS system (i.e., 2020 kW), there is minimal potential for creating an offsite power supply perturbation when shifting the load between the Division 3 DG and the offsite power source. Lastly, the HPCS system is a stand-alone system with a dedicated DG and independent electrical distribution system. The HPCS system has a full flow suction line and a return line to both the suppression pool and the RCIC storage tank, and an automatically actuated minimum flow line to the suppression pool. These features allow testing of the system online without discharging into the reactor vessel, while providing protection of the pump from overheating. Additionally, system configuration is such that HPCS system testing can be performed without impacting other divisional safety systems or the RCIC system. Energizing or de-energizing loads of this size as part of surveillance testing online or during shutdown conditions creates minimal potential to cause an electrical distribution system perturbation. In fact, HPCS pump
Attachment 1 Evaluation of Proposed Changes Page 20 of 25 starts are routinely performed online to satisfy quarterly inservice testing requirements, without disturbing plant operations. In addition, Division 3 loads such as the Division 3 SRM and RPS isolation features are supported by a battery that is designed to carry these loads for four hours. Consequently, there is minimal opportunity for the performance of this SR for Division 3 DG to have any impact on other safety-related plant equipment or normal plant operation. Therefore, based on the above discussion, the reasons for the mode restrictions stated in the TS Bases for SR 3.8.1.16 are not valid for the Division 3 DG. 3.6.5 SR 3.8.1.19 For Division 3, SR 3.8.1.19 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 Division 3, this test is currently performed with the Division 3, 4.16 kV emergency bus aligned to RAT B. A LOOP signal is simulated, causing the Division 3 switchgear to de-energize (e.g., by opening test switches simulating bus undervoltage). Following the DG start signal, 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 RCIC tank, and pump discharge is through the test return line back to the RCIC tank. The HPCS system discharge pathway to the reactor vessel is 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 shutting HPCS manual isolation valve 1E22-F036. However, since 1E22-F036 is in the CPS Drywell and inaccessible during operation at power, the prevention of HPCS system discharge into the reactor vessel could be accomplished by other means such as verifying that motor-operated injection valve 1E22-F004 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. 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. First, although the offsite source of power to the Division 3 emergency bus is disconnected when performing this SR for Division 3, 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;
Attachment 1 Evaluation of Proposed Changes Page 21 of 25 therefore, the Division 3 DG is not required to be operable as discussed in the Note associated with the Applicability requirements for TS 3.8.1. Secondly, as discussed in Section 3.5, there is no configuration introduced by testing in the proposed manner that would approach the rating of RAT B or the ERAT when performing this SR for Division 3. Due to the relative size of the loads associated with the HPCS system (i.e., 2020 kW), there is minimal potential for this testing to create an offsite power supply perturbation when the Division 3 electrical bus is de-energized. Furthermore, HPCS pump starts are routinely performed online to satisfy quarterly inservice testing requirements, without disturbing plant operation. Lastly, as previously discussed, the HPCS system is a stand-alone system with a dedicated DG and independent electrical distribution system. The HPCS system has a full flow suction line and a return line to both the suppression pool and the RCIC storage tank, and an automatically actuated minimum flow line to the suppression pool. These features allow testing of the system online without discharging into the reactor vessel, while providing protection of the pump from overheating. Additionally, system configuration is such that HPCS system testing can be performed without impacting other divisional safety systems or the RCIC system. Energizing or de-energizing loads of this size as part of surveillance testing online or during shutdown conditions creates minimal potential to cause an electrical distribution system perturbation. In fact, HPCS pump starts are routinely performed online to satisfy quarterly inservice testing requirements, without disturbing plant operations. In addition, Division 3 loads such as the Division 3 SRM and RPS isolation features are supported by a battery that is designed to carry these loads for four hours; therefore, there is minimal impact resulting from the performance of this SR for Division 3 on other safety-related plant equipment. The simulated LOOP and ECCS initiation signals associated with this SR for Division 3 affect only the HPCS system and do not affect the other two safety-related electrical divisions. Based on the above discussion and plant experience related to performing this test, conducting this test online for the Division 3 DG is no more challenging than conducting the test while shutdown; therefore, the reasons for the mode restrictions stated in the TS Bases for SR 3.8.1.19 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;
- 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
Attachment 1 Evaluation of Proposed Changes Page 22 of 25 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 (i.e., HPCS) AC Sources 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 CPS electrical distribution system, disrupt power operation, or challenge plant safety systems. For these same reasons, the proposed changes do not alter CPS's compliance with the requirements of GDC 17 and GDC 18. 4.2 Precedents The NRC has approved similar license amendments to remove operating mode restrictions for performing Division 3 DG surveillance testing. Recent examples include:
- Nine Mile Point Nuclear Station, Unit No. 2 (License Amendment No. 133 issued by NRC letter dated March 18, 2010 - ADAMS Accession No. ML100460016)
- 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. ML011440088).
- Grand Gulf Nuclear Station (License Amendment No. 155 issued by NRC letter dated September 10, 2002 - ADAMS Accession No. ML030760726).
Similar to CPS, all 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 No Significant Hazards Consideration Exelon Generation Company, LLC (EGC) is requesting an amendment to Facility Operating License NPF-62 for Clinton Power Station, Unit 1 (CPS). The proposed amendment would modify Technical Specifications (TS) Section 3.8.1, "AC Sources - Operating," by revising certain Surveillance Requirements (SRs) pertaining to the Division 3 AC Sources. The Division 3 power system is an independent source of onsite alternating current (AC) power
Attachment 1 Evaluation of Proposed Changes Page 23 of 25 primarily dedicated to the High Pressure Core Spray (HPCS) system. The TS currently prohibit performing the testing required by certain SRs in either Modes 1 or 2, or in Modes 1, 2, or 3. The proposed amendment would also remove these Mode restrictions and allow certain SRs to be performed in any operating Mode for the Division 3 AC Sources. EGC 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:
- 1. Does the proposed amendment involve a significant increase in the probability or consequences of an accident previously evaluated?
Response: No The Division 3 (i.e., HPCS) diesel generator (DG) and its associated emergency loads are accident mitigating features, not accident initiators. Therefore, the proposed TS changes to allow the performance of certain Division 3 AC Sources 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 AC Sources to respond to a design basis accident will not be adversely impacted by the proposed changes. Testing procedures include steps to ensure that injection into the reactor vessel is precluded. The proposed changes to the TS surveillance testing requirements for the Division 3 AC Sources do not affect the operability requirements for the AC Sources, as verification of such operability will continue to be performed as required. Continued verification of operability supports the capability of the Division 3 AC Sources to perform their required functions of providing emergency power to HPCS system equipment, consistent with the plant safety analyses. Limiting testing to only one AC Source at a time ensures that design basis requirements are met. Should a fault occur while testing the Division 3 AC Sources, there would be no significant impact on any accident consequences since the other two divisional AC Sources 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 AC Sources surveillance testing is conducted. Performance of these surveillances tests while online will continue to verify operability of the Division 3 AC Sources. The proposed amendment does not impact any
Attachment 1 Evaluation of Proposed Changes Page 24 of 25 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.
- 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 AC Sources do not affect the operability requirements for the AC Sources, as verification of such operability will continue to be performed as required. Continued verification of operability supports the capability of the Division 3 AC Sources to perform their 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. Further, performing Division 3 AC Sources surveillance activities online increases the Division 3 DG and HPCS system availability during refueling outages and allows the testing of the Division 3 systems to be conducted when both Division 1 and 2 systems are required to be OPERABLE. Therefore, the proposed amendment does not involve a significant reduction in a margin of safety. Based on the above, EGC 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.
Attachment 1 Evaluation of Proposed Changes Page 25 of 25
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 a 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.
6.0 REFERENCES
- 1. Letter from R. V. Guzman (NRC) to S. L. Belcher (Nine Mile Point), Nine Mile Point Nuclear Station, Unit No. 2 - Issuance of Amendment Regarding Removal of Operating Mode Restrictions for Performing High Pressure Core Spray Emergency Diesel Generator Surveillance Testing (TAC No. ME1042), dated March 18, 2010
- 2. Letter from C. F. Lyon (NRC) to J. V. Parrish (Energy Northwest), Columbia Generating Station - Issuance of Amendment Re: Removal of Operating Mode Restrictions for Performing Emergency Diesel Generator Surveillance Testing (TAC No.
MD2113), dated March 23, 2007
- 3. Letter from D. Jaffe (NRC) to W. A. Eaton (Entergy Operations, Inc.), Grand Gulf Nuclear Station, Issuance of Amendment Re: Removal of Operating Mode Restrictions for Performing High Pressure Core Spray Emergency Diesel Generator Testing (TAC No. MB4261), dated September 10, 2002
Attachment 2 Clinton Power Station Electrical Drawings Clinton Power Station Electrical Single Line Diagrams and Relay Settings Tables E02-1AP01, Sheet 4, Single Line Diagram Part 4 E02-1AP01, Sheet 5, Single Line Diagram Part 5 E02-1AP01, Sheet 1, Single Line Diagram Part 1 E02-1AP04, Sheet 1, 4160V and 6900V SWGR Relay Settings E02-1AP04, Sheet 17, Diesel Generator 1A, 1B, and 1C Relay Settings
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Attachment 3 Clinton Power Station Current Versus Time Overcurrent Relay Settings Plot of the Clinton Power Station Division 3 Overcurrent Relay Settings (Amps versus Time)
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Attachment 4 Markup of Existing Technical Specifications Pages Clinton Power Station, Unit 1 Facility Operating License No. NPF-62 License Amendment Request to Remove Operating Mode Restrictions for Performing Division 3 Emergency Diesel Generator Surveillance Testing MARKUP OF EXISTING TECHNICAL SPECIFICATIONS PAGES 3.8-6 3.8-8 3.8-9 3.8-11 3.8-13
AC Sources Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued) SURVEILLANCE FREQUENCY SR 3.8.1.7 -------------------NOTE------------------ All DG starts may be preceded by an engine prelube period. Verify each DG starts from standby 184 days condition and achieves:
- a. In 12 seconds, voltage 4084 V and frequency 58.8 Hz; and
- b. Steady state voltage 4084 V and 4580 V and frequency 58.8 Hz and 61.2 Hz.
SR 3.8.1.8 ------------------NOTE-------------------- This Surveillance shall not be performed in (not applicable to MODE 1 or 2. However, credit may be taken Division 3 AC sources) for unplanned events that satisfy this SR. Verify automatic and manual transfer of 24 months unit power supply from the normal offsite circuit to the alternate offsite circuit. (continued) CLINTON 3.8-6 Amendment No. 169
AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued) SURVEILLANCE FREQUENCY SR 3.8.1.11 -------------------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. (not applicable to However, credit may be taken for the Division 3 DG) unplanned events that satisfy this SR.
Verify on an actual or simulated loss of 24 months offsite power signal:
- a. De-energization of emergency buses;
- b. Load shedding from emergency buses for Divisions 1 and 2; and
- c. DG auto-starts from standby condition and:
- 1. energizes permanently connected loads in 12 seconds,
- 2. energizes auto-connected shutdown loads,
- 3. maintains steady state voltage 4084 V and 4580 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.
(continued) CLINTON 3.8-8 Amendment No. 169
AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued) SURVEILLANCE FREQUENCY SR 3.8.1.12 -------------------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, (not applicable to credit may be taken for unplanned the Division 3 DG) events that satisfy this SR.
Verify on an actual or simulated Emergency 24 months Core Cooling System (ECCS) initiation signal each DG auto-starts from standby condition and:
- a. In 12 seconds after auto-start and during tests, achieves voltage 4084 V and frequency 58.8 Hz;
- b. Achieves steady state voltage 4084 V and 4580 V and frequency 58.8 Hz and 61.2 Hz; and
- c. Operates for 5 minutes.
SR 3.8.1.13 ------------------NOTE-------------------- Credit may be taken for unplanned events that satisfy this SR. Verify each DG's automatic trips are bypassed on an actual or simulated ECCS initiation signal except: 24 months
- a. Engine overspeed;
- b. Generator differential current; and
- c. Overcrank for DG 1A and DG 1B.
(continued) CLINTON 3.8-9 Amendment No. 169
AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued) SURVEILLANCE FREQUENCY SR 3.8.1.16 -------------------NOTE-------------------- This Surveillance shall not be performed in (not applicable to MODE 1, 2, or 3. However, credit may be the Division 3 DG) taken for unplanned events that satisfy this SR. Verify each DG: 24 months
- 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.
SR 3.8.1.17 -------------------NOTE------------------- Credit may be taken for unplanned events that satisfy this SR. Verify, with a DG operating in test mode and connected to its bus, an actual or simulated ECCS initiation signal overrides 24 months the test mode by:
- a. Returning DG to ready-to-load operation; and
- b. Automatically energizing the emergency loads from offsite power.
(continued) CLINTON 3.8-11 Amendment No. 169
AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued) SURVEILLANCE FREQUENCY SR 3.8.1.19 -------------------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. (not applicable to However, credit may be taken for the Division 3 DG) unplanned events that satisfy this SR.
24 months 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; and
- c. DG auto-starts from standby condition and:
- 1. energizes permanently connected loads in 12 seconds,
- 2. energizes auto-connected emergency loads,
- 3. achieves steady state voltage 4084 V and 4580 V,
- 4. achieves steady state frequency 58.8 Hz and 61.2 Hz, and
- 5. supplies permanently connected and auto-connected emergency loads for 5 minutes.
(continued) CLINTON 3.8-13 Amendment No. 169
Attachment 5 Markup of Existing Technical Specifications Bases Changes (For Information Only) Clinton Power Station, Unit 1 Facility Operating License No. NPF-62 License Amendment Request to Remove Operating Mode Restrictions for Performing Division 3 Emergency Diesel Generator Surveillance Testing MARKUP OF EXISTING TECHNICAL SPECIFICATIONS BASES PAGES (FOR INFORMATION ONLY) B 3.3-121 B 3.8-18 B 3.8-21 B 3.8-22 B 3.8-27 B 3.8-30
ECCS Instrumentation B 3.3.5.1 BASES SURVEILLANCE SR 3.3.5.1.5 REQUIREMENTS (continued) 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 3.7.2, LCO 3.8.1, and LCO 3.8.2 overlaps this Surveillance to provide complete testing of the assumed safety function. The Self Test System may be utilized to perform this testing for those components that it is designed to monitor. Those portions of the solid-state logic not monitored by the Self Test System may be tested at the frequency recommended by the manufacturer, rather than at the specified 24-month Frequency. The frequencies recommended by the manufacturer are based on mean time between failure analysis for the components in the associated circuits. (except for the The 24 month Frequency is based on the need to perform this Division 3 diesel Surveillance under the conditions that apply during a plant outage and the potential for unplanned transients if the generator, which Surveillance were performed with the reactor at power. can be tested in Operating experience has shown these components usually pass any MODE) the Surveillance. REFERENCES 1. USAR, Section 5.2.2.
- 2. USAR, Section 6.3.
- 3. USAR, Chapter 15.
- 4. NEDC-30936-P-A, "BWR Owners' Group Technical Specification Improvement Analyses for ECCS Actuation Instrumentation, Part 2," December 1988.
CLINTON B 3.3-121 Revision No. 10-7
AC Sources Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.8 REQUIREMENTS (continued) Transfer of each 4.16 kV ESF bus power supply from the normal offsite circuit to the alternate offsite circuit demonstrates the OPERABILITY of the alternate circuit. The 24 month Frequency of the Surveillance is based on engineering judgment taking into consideration the plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths. Operating experience has shown that these components usually pass the SR. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint. This SR is modified by a Note. The reason for the Note is that, during operation with the reactor critical, performance of this SR could cause perturbations to the electrical distribution systems that could challenge (The Note is not continued steady state operation and, as a result, plant safety systems. Credit may be taken for unplanned events applicable to Division 3 that satisfy this SR. Examples of unplanned events may AC Sources) include:
- 1) Unexpected operational events which cause the equipment to perform the function specified by this surveillance, for which adequate documentation of the required performance is available; and
- 2) Post maintenance testing that requires performance of this Surveillance in order to restore the component to OPERABLE, provided the maintenance was required, or performed in conjunction with maintenance required to maintain OPERABILITY or reliability.
SR 3.8.1.9 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 a load equivalent to at least as large as the largest single load while maintaining a specified margin to the overspeed trip. (continued) CLINTON B 3.8-18 Revision No. 13-2
AC Sources Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.11 (continued) REQUIREMENTS 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 is consistent with the refuel cycle recommendations of Regulatory Guide 1.9 (Ref. 16), takes into consideration unit 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 1 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. Standby conditions mean that the lube oil is heated by the jacket water and continuously circulated through a portion of the system as recommended by the vendor. Engine jacket water is heated by an immersion heater and circulates through the system by natural circulation. This allowance is not intended to impose a maximum limit on engine temperatures. The reason for Note 2 (Note 2 is not is that performing the Surveillance would remove a required applicable to the offsite circuit from service, perturb the electrical distribution system, and challenge plant safety systems. Division 3 DG) Credit may be taken for unplanned events that satisfy this SR. Examples of unplanned events may include:
- 1) Unexpected operational events which cause the equipment to perform the function specified by this Surveillance, for which adequate documentation of the required performance is available; and
- 2) Post maintenance testing that requires performance of this Surveillance in order to restore the component to OPERABLE, provided the maintenance was required, or performed in conjunction with maintenance required to maintain OPERABILITY or reliability.
(continued) CLINTON B 3.8-21 Revision No. 13-2
AC Sources Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.12 REQUIREMENTS (continued) This Surveillance demonstrates that the DG automatically starts and achieves the required voltage and frequency within the specified time (12 seconds) from the design basis actuation signal (LOCA signal) and operates for 5 minutes. The 5 minute period provides sufficient time to demonstrate stability. With regard to DG start time, required voltage and frequency values obtained pursuant to this SR, as read from plant indication instrumentation, the specified limit is not considered to be a nominal value with respect to instrument uncertainties. This requires additional margin to be added to the limit to compensate for instrument uncertainties, for implementation in the associated plant procedures (Refs. 17, 18, 19, 22, 23). The Frequency of 24 months takes into consideration plant conditions required to perform the Surveillance and is intended to be consistent with the expected fuel cycle lengths. Operating experience has shown that these components usually pass the SR. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint. This SR is modified by two Notes. The reason for Note 1 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. Standby conditions mean that the lube oil is heated by the jacket water and continuously circulated through a portion of the system as recommended by the vendor. Engine jacket water is heated by an immersion heater and circulates through the system by natural circulation. This allowance is not intended to impose a maximum limit on engine temperatures. The reason for Note 2 is that during operation with the reactor critical, performance of this SR could cause perturbations to the electrical distribution systems that could challenge continued steady state operation and, as a result, plant (Note 2 is not safety systems. Credit may be taken for unplanned events that satisfy this SR. Examples of unplanned events may applicable to the include: Division 3 DG) (continued) CLINTON B 3.8-22 Revision No. 13-2
AC Sources Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.16 (continued) REQUIREMENTS This Note This SR is modified by a Note. The reason for the Note is that performing the Surveillance would remove a required (This Note is not offsite circuit from service, perturb the electrical distribution system, and challenge safety systems. Credit applicable to the may be taken for unplanned events that satisfy this SR. Division 3 DG) Examples of unplanned events may include:
- 1) Unexpected operational events which cause the equipment to perform the function specified by this Surveillance, for which adequate documentation of the required performance is available; and
- 2) Post maintenance testing that requires performance of this Surveillance in order to restore the component to OPERABLE, provided the maintenance was required, or performed in conjunction with maintenance required to maintain OPERABILITY or reliability.
SR 3.8.1.17 Demonstration of the test mode override is consistent with the recommendations of Regulatory Guide 1.108 (Ref. 10), paragraph 2.a.(8)and ensures that the DG availability under accident conditions is not compromised as the result of testing. Except as clarified below for the Division 3 DG, 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. 14), paragraph 6.2.6(2), as further amplified by IEEE 387, sections 5.6.1 and 5.6.2. (Clarification regarding conformance of the Division 3 DG design to these standards is provided in the USAR, Chapter 8 (Reference 2).) Automatic switchover from the test mode to ready-to-load operation for the division 3 DG is also demonstrated, as described above, by ensuring that DG control logic automatically resets in response to a LOCA signal during the test mode and confirming that ready-to-load operation is attained (as evidenced by the DG running with the output breaker open). However, with the DG governor initially operating in a droop condition during the test mode, operator action may be required to reset the governor for (continued) CLINTON B 3.8-27 Revision No. 13-2
AC Sources Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.19 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 3.8.1.11, during a loss of offsite power actuation test signal in conjunction with an ECCS initiation signal. For load shedding effected via shunt trips that are actuated in response to a LOCA signal (i.e., "ECCS initiation signal"), this surveillance includes verification of the shunt trips (for Divisions 1 and 2 only) in response to LOCA signals originating in the ECCS initiation logic as well as the Containment and Reactor Vessel Isolation and Control System actuation logic. 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 of 24 months. This SR is modified by two Notes. The reason for Note 1 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. Standby conditions mean that the lube oil is heated by the jacket water and continuously circulated through a portion of the system as recommended by the vendor. Engine jacket water is heated by an immersion heater and circulates through the system by natural circulation. This allowance is not intended to impose a maximum limit on engine temperatures. The reason for Note 2 is that performing the Surveillance would remove a required (Note 2 is not offsite circuit from service, perturb the electrical distribution system, and challenge plant safety systems. applicable to the Credit may be taken for unplanned events that satisfy this Division 3 DG) SR. Examples of unplanned events may include: (continued) CLINTON B 3.8-30 Revision No. 10-7}}