RBG-43328, Application for Amend to License NPF-47,requesting Mod to Surveillance Requirement 3.8.1.14 to Allow 24-hour Diesel Generator Maint Run While Unit Is in Either Mode 1 or Mode 2
| ML20134M011 | |
| Person / Time | |
|---|---|
| Site: | River Bend  |
| Issue date: | 11/15/1996 |
| From: | Mcgaha J ENTERGY OPERATIONS, INC. |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| Shared Package | |
| ML20134M014 | List: |
| References | |
| RBEXEC-96-178, RBF1-96-0403, RBF1-96-403, RBG-43328, NUDOCS 9611220162 | |
| Download: ML20134M011 (14) | |
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Entsrgy Opsrstions, Inc.
Ther Bend Stat,on 5485 US. H,ghway 61
" ENTERGY S" 220 St. Francisv$e, LA 70775 (504) 38 t 4374 FAX (504) 381-4872 JOHN R. McGAHA, JR.
Vce Pres' dent Operates November 15,1996 U. S. Nuclear Regulatory Commission Document Control Desk.
Mail Station PI-37 Washington, DC 20555
Subject:
River Bend Station - Unit 1 Docket No. 50-458 License No. NPF-47 License Amendment Request (LAR) 96-31, Change to Technical Specification 3.8.1,"AC Sources Operating" File Nos.:
G9.5, G9.42 RBEXEC-96-178 RBF1-96-0403 RBG-43328 Gentlemen:
In accordance with 10CFR50.90, Entergy Operations, Inc. (EOl) hereby applies for amendment of Facility Operating License No. NPF-47, Appendix A - Technical Specifications, for River Bend Station (RBS). The proposed change to the Technical Specification modifies Note 2 to Surveillance Requirement 3.8.1.14. Presently, Note 2 prohibits the performance of the 24-hour emergency diesel generator (EDG) maintenance run while the unit is in either Mode 1 or Mode 2. The proposed change would remove this restriction, thus allowing the 24-hour mn to be performed during any mode of operation (i.e., Mode 1,2,3,4 or 5).
l The NRC staff has previously expressed concern about the performance of the 24-hour EDG load test while paralleled to the offsite power systems. This concern, based on the common-mode vulnerability of the offsite and onsite sources during testing, led to restricting the performance of the test during periods when the reactor was shutdown (i.e., Mode 3,4 or 5).
Specifically, the staff was' concerned that if a fault or grid disturbance were to occur while an EDG was connected in parallel with the offsite systems, the availability of the EDG for subsequent emergency operation could be adversely affected.
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\\I 9611220162 961115 PDR ADOCK 05000458 P
PDR 220034
License Amendment Request (LAR) 96-31, Change to Technical Specification 3.8.1, "AC Sources Operating" November 15,1996 RBEXEC 178 RBF1-96-0403 RBG-43328 i
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Recently the staff approved several licensee requests (e.g., Grand Gulf Nuclear Station, PP&L and Niagara Mohawk Power) to eliminate the Mode 1 and 2 restrictions associated with the 24-hour EDG run. The Grand Gulf Nuclear Station submittal was used as the basis for this submittal. NRC approval has been based on the existence of unique EDG design features and/or special provisions that ensure paralleled operation of the EDG with offsite sources will not prevent the EDG from performing its assumed safety functions. Attachment 2 provides similarjustification for RBS.
As outage schedules continue to be optimized, it is increasingly likely that requiring this surveillance to be performed only during outages will needlessly impact outage critical path. In addition, the performance of these surveillances is very operator intensive thus placing additional strain on a limited resource during refueling outages. Performance of these tests at times other than during refueling outages lessens both the complexity of the outages and the demands for limited operations' resources. The current outage critical path cost exceeds
$500,000 per day or $20,000 per hour. Therefore, Entergy Operations, Inc. believes the approval of the proposed change will result in expected benefits well in excess of $100,000 over the remaining life of the plant. Consequently, the proposed amendment is being submitted as part of the cost beneficial licensing action (CBLA) program.
EOI requests that the NRC staff complete its review and approval of this application on a schedule suflicient to support the seventh refueling outage (RF-7) currently scheduled to commence September 12,1997.
Based on the guidelines in 10 CFR 50.92, Entergy Operations has concluded that this proposed amendment involves no significant hazards considerations. Attachment 2 provides the basis for this determination with a detailed description of the proposed changes, justification and the No Significant Hazards Considerations. Attachment 3 is a copy of the marked-up TS pages.
Entergy has reviewed the proposed change against the criteria of 10CFR51.22 for categorical exclusion from environmentalimpact considerations. The proposed change does not involve a significant hazard consideration or significantly increase individual or cumulative occupational radiation exposures. Based on the foregoing, Entergy concludes that the proposed change meets the criteria given in 10CFR51.22(c)(9) for a categorical exclusion from the requirement for an Environmental Impact Statement.
License Amendment Request (LAR) 96 31, Change to Technical Specification 3.8.1,"AC Sources Operating" November 15,1996 RBEXEC 178 RBF1-96-0403 RBG-43328 Page 3 of 3 This request has been discussed with the NRR project manager for RBS. It has also been reviewed and approved by the RBS Facility Review Committee and the Nuclear Review Board. If you have any questions regarding this request or require additional information, please contact Mr. T. W. Gates at (504) 381-4866.
Sincerely, N
bJRhi MB/mjr attachments cc:
Mr. David L. Wigginton U. S. Nuclear Regulatory Commission M/S OWFN 13-H-15 Rockville,MD 20852 NRC Resident inspector P. O. Box 1050 St. Francisville, LA 70775 U. S. Nuclear Regulatory Commission Region IV 611 Ryan Plaza Drive, Suite 400 Arlington,TX 70611 l
Department of Environmental Quality
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Radiation Protection Division
- P. O. Box 82135 Baton Rouge, LA 70884-2135 Attn: Administrator l
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r
BEFORE THE UNITED STATES NUCLEAR REGULATORY COMMISSION LICENSE NO. NPF-47 l
IN THE MATTER OF i
ENTERGY GULF STATES, INC.
4 CAJUN ELECTRIC POWER COOPERATIVE AND ENTERGY OPERATIONS, INC.
AFFIRMATION l
1, John R. McGaha, state that I am Vice President-Operations of Entergy Operations, Inc., at River Bend Station; that on behalf of Entergy Operations, Inc., I am authorized by Entergy Operations, Inc., to s:~.. and file with the Nuclear Regulatory Commission, this River Bend Station License Amendment Request (LAR) 96-31, Change to Technical Specification 3.8.1, "AC Sources Operating;" that I signed this letter as Vice President-Operations at River Bend Station of Entergy Operations, Inc.; and that the statements made and the matters set forth therein are tme and correct to the best of my knowledge, information, and belief.
John Il McGaha STATE OF LOUISIANA PARISH OF WEST FELICLANA SUBSCRIBED AND SWORN TO before me, a Notary Public, commissioned in the Parish above named, this I 64^-
day of %QurwdLtA
.1996.
' (SEAL)
&& AIM Claudia F. Hurst Notary Public My Commission expires with life
ENTERGY OPERATIONS INCORPORATED RIVER BEND STATION DOCKET 50-458/ LICENSE NO. NPF-47 AC Sources - Operating (LAR 96-31)
A.
AFFECTED TECIINICAL SPECIFICATIONS The following Technical Specification is affected by the proposed change.
Surveillance Requirements (SR) 3.8.1.13 AC Sources - Operating The proposed Technical Specification and the associated Technical Specification Bases changes to be implemented following NRC approval are detailed in Attachment 3.
B.
BACKGROUND At River Bend Station (RBS), the Class IE AC electrical power distribution system consists of offsite sources (two incoming lines) and onsite sources (two redundant -- Divisions I & II, and one high pressure injection -- Division III, emergency diesel generators). As required by 10 CFR 50, Appendix A, GDC 17, the design of the AC electrical power system provides independence and redundancy to ensure an available source of power to the Engineered Safety Feature (ESF) systems.
The Class IE AC distribution system supplies power to three divisional ESF load groups (i.e.,
Divisions I, Il and III), with each division powered by an independent Class IE 4.16 Kv ESF bus.
Each ESF bus receives power from either offsite sources or a dedicated onsite emergency diesel generator (EDG). During normal operations, the Division I & II ESF buses are aligned to their preferred offsite sources with the Division III ESF bus powered from the normal 4.16 Kv switch gear which can be powered from either preferred station service transformer. In the event that the preferred offsite source is lost or degrades, the affected ESF bus is automatically trar.sferred to an alternate standby onsite source.
Offsite power is supplied to RBS via two 230 Kv lines. From the switchyard, two electrically and physically separate circuits provide AC power to each 4.16 Kv ESF bus. The offsite AC electrical power sources are designed and located to minimize to the extent practical the likelihood of their simultaneous failure under operating and postulated accident conditions. A complete description of the offsite power system can be found in the RBS's Updated Safety Analysis Report (SAR)
Section 8.2.
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The onsite standby power source for each 4.16 Kv ESF bus is a dedicated EDG. These standby EDGs (i.e., Divisions I, Il and III) automatically start following generation of either a loss of coolant accident (LOCA) signal (i.e., low reactor water level or high drywell pressure) or an ESF bus degraded voltage or undervoltage signal (refer to Technical Specification 3.3.8.1 - LOP Instrumentation). The automatic transfer ofeach ESF bus to its standby EDG occurs only after generation of a bus degraded voltage or undervoltage signal, as measured on the 4.16 Kv bus.
Transfer is accomplished by first opening the incoming offsite feeder breakers and subsequently closing the EDG feeder breaker when the generator has reached rated speed and voltage. This arrangement lessens the likelihood that the offsite source (i.e., the grid) and the onsite sources will remain paralleled during periods of degraded grid conditions.
For Divisions I and II, prior to auto-connecting the EDG to the ESF bus (i.e., closing the EDG output breaker), the breakers connecting the buses to the offsite sources are opened and all bus i
l loads except ESF 480 volt load center feeders are tripped. The signal that trips the offsite feeder breakers also initiates the load shedding process for the 4.16 Kv bus. Loads are sequenced back onto the bus following closure of the EDG breaker to the ESF bus in a predeterntined sequence in order to prevent overloading the standby emergency power source. Load shedding and sequencing for Divisions I and II is discussed in the RBS's SAR Section 8.3.1.1.3.6.1.
For Division til (High Pressure Core Spray - HPCS) only the standby service water pump and associated valve loads are shed and sequenced back onto the bus. The design of the HPCS system ensures that the offsite and onsite sources will not continue to operate in parallcl mode following receipt of either a LOCA or loss of offsite power (LOP) signal. Ifin parallel operation prior to the occurrence of either signal, the HPCS EDG output breaker will trip open and will not be automatically reclosed unless the preferred offsite source of power is lost similar to the l
Division I and II designs. Starting and loading for Division III is discussed in RBS's SAR Section 8.3.1.1.3.6.2.
Currently, the RBS Technical Specifications require that the operability of each EDG be demonstrated every 18 months by operating the EDG for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> at specific load conditions. In order to achieve the required load conditions, the selected EDG is operated in parallel with offsite sources. The current Technical Specifications prohibit these tests from being performed while the unit is in Mode 1 or 2. The staff s concern, as expressed in Information Notice 84-69, is that a possible fault on the offsite system could lock out the ESF bus or trip the EDG itself. This lockout could render the EDG unavailable for service when otherwise capable of supplying power. In such cases, the ability of the unit to respond to an emergency could be reduced.
- The Technical Specification Bases denotes the reason for Note 2 as being a concern for potentially tripping the plant if the surveillance were performed during Modes I and 2. While performance of this suncillance could present a potential challenge to the continued operation of the unit, it doesn't present a greater challenge than j
many other surveillances performed on a more frequent basis (e.g., SR 3.8.1.3). The decision of whether to perform this surveillance during power operation should be madejust as with any other surveillance that presents a potential trip of the unit. It is EOl's opinion that the more important concerns with SR 3.8.1.14 are as expressed in IN 84-69 and not whether performance of the surveillance represents a challenge to continued steady state operation.
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C.
PROPOSED TS CHANGES The proposed change to the Technical Specification is to modify Note 2 to Surveillance l
Requirement (SR) 3.8.1.13. Presently Note 2 prohibits the performance of the 24-hour diesel maintenance run while the unit is in either Mode 1 or 2. The proposed change would remove this i
restriction thus allowing the 24-hour mn to be performed during any mode of operation (i.e.,
Modes 1,2,3,4 or 5).
i The second part of Note 2 would remain, providing clarification that credit could be taken for l
unplanned events to satisfy the requirements of SR 3.8.1.13.
D.
JUSTIFICATION The Staff previously expressed concern about the performance of the 24-hour EDG load test while paralleled to the offsite power system. This concern, which is based on the common-mode winerability of the offsite and onsite sources during the test, led to restricting the performance of the test to periods when the reactor was shutdown (i.e., Modes 3,4 or 5).
This request will allow the 24-hour test of the EDGs to be performed during power operations.
The configuration of the test is the same as that for the one-hour test which is performed monthly on each EDG. The resuhing increase of time in this configuration during an 18-month cycle, with a one-month outage, is from 17 to 41 hours4.74537e-4 days <br />0.0114 hours <br />6.779101e-5 weeks <br />1.56005e-5 months <br /> per division. While this does increase the time in the configuration, additional precautions will be taken as described below, during the 24-hour test to decrease the likelihood of an EDG trip during the test.
The specific Staff concern was that if a fault or grid disturbance were to occur while an EDG is connected in parallel with the offsite system, the availability of the EDG for subsequent emergency operation could be affected. Specifically, the EDG or its generator breaker could trip and thus require local operator action to restore. In these instances, the response of the ESF systems could be slower than assumed in the accident analyses.
The risk of operating during the 24-hour EDG test is certainly less than the current 72-hour allowed outage time for an inoperable EDG because the EDG being tested is not actually failed.
There will be no increase in frequency of design basis events. Therefore, the incorporation of this change can have little impact on current safety margins.
Recently, the NRC staff has approved several licensees' requests for eliminating the Mode 1 and 2 restrictions when performing the 24-hour EDG runs. This approval has been based on the existence of unique EDG design features and/or special provisions which ensure that paralleled operation of the EDG with offsite sources will not prevent the EDG from performing its assumed safety functions. In particular, NRC recently approved this change for Grand Gulf Nuclear Station. While the design of the River Bend AC Distribution System is not identical to the Grand Gulf system, the two designs are substantially the same. Therefore, the basis of the NRC approval of the change to the Grand Gulf operating license is largely applicable to River Bend.
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g RBS has evaluated the performance and interaction of the Standby Pow;r Sources (Divisions I, II q
and III) while operating in parallel with the offsite power distribution system during a test. This evaluation included such factors as the type of signal received and type of protection (e.g., under-voltage, voltage fault or current directional phase) available to the diesel generators. Of particular i
~ interest are the responses of a paralleled EDG to a LOCA signal, a LOP signal or concurrent LOP i
and LOCA signals. Each unique situation is discussed in detail below.
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i RESPONSE TO LOCA a
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At the generation of a LOCA signal, the EDG output breaker opens and all loads, except feeders j
to 480-volt load centers, are shed from the ESF buses (Divisions I and II only). Loads are i
sequenced back onto the ESF bus once appropriate bus voltage and frequency is confirmed. As discussed above, the Division III bus only sheds the standby service water pump and the associated valves. These loads are automatically sequenced back on the ESF bus when the appropriate bus conditions exist. The timing of the sequencing is the same regardless of whether j
the ESF buses are energized from offsite or onsite sources. This makes the LOCA sequencing a function solely of when ESF bus voltage becomes available without memory of past conditions or j
knowledge of present power source.
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Regardless of whether the EDGs are in parallel operation or in normal standby mode, the i.
generation of a LOCA signal is an emergency start signal for the three EDGs. In either case (i.e.,
j paralleled or normal standby), an emergency start signal automatically bypasses selected EDG l
trips. For all three Divisions, a LOCA signal retains only two EDG trips active -- engine
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overspeed and generator differential. Interlocks te the LOCA-sencing circuits cause the EDG to automaticall> reset to ready-to-load ' operation if a.,0CA signal is received during operation in the test mode. Reaciy-to-lead operation is defined as the EDG running at rated speed and voltage l
with the EDG output breaker open. If otTsite power is available, the EDO will continue to mn in j
the ready-to-!oad condition.
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l Of significance is that all three EDGs respond to a LOCA signal as an emergency start thus j
overriding the test start signal and removing selected engine / generator trips from the active trip circuitry. In addition, as discussed above, the EDG output breaker opens separating the EDG i
from the ESF bus and is prepared to repower the ESF bus as necessary. - As a result, concurrent operation of the EDGs in parallel with offsite sources is automatically terminated following j
receipt of a valid LOCA signal, thus preventing subsequent failure of offsite sources from affecting performance of the EDGs' safety function.
l' RESPONSE TO LOSS OF OFFSITE POWER Each 4.16 Ky ESF bus has its own independent loss of power (LOP) instrumentation and j
associated trip logic. For Divisions I, II and III buses the voltage is monitored at two leve, j
which can be considered as two different undervoltage '
tions: 1) loss ofvoltage and 2)
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. degraded voltage. See Technical Specifications 3.3.8.1 (LOP Instrumentation) for actual setpoints.
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t Actuation of the LOP instrumentation results in an automatic start signal for its associated EDG.
For Divisions I and II, prior to connecting the EDG to its appropriate bus, all loads are shed except feeders to 480 volt load centers. Provisions are built into the automatic sequences to recognize a grid undervoltage condition and to automatically place the EDG on the bus after tripping the incoming offsite source feeder breaker. Should the grid go to an undervoltage condition while the EDG is being operated i" oarallel, the incoming offsite feeder breakers would open and the EDG would switch from paraE operation to isochronous mode picking up the loads on the bus sequentially.
As discussed above Division III does have a limited automatic load shedding. In addition, as with Divisions I and II, Division III does have undervoltage protection which activates to open incoming feeder breakers thus separating the onsite source from a degraded grid condition.
j For all three EDGs, the auto-start due to the actuation of LOP instrumentation is an emergency start and thus only the emergency EDG protective trips remain active; (See Sections 8.3.1.1.4.1 and 8.3.1.1.4.2.10 of the RBS SAR). This design was reviewed and approved by the Staff as documented in their Safety Evaluation Report and Supplement 3 dated May 1984 and August 1985, respectively.
In accordance with the RBS system design, it is possible that a normal operation protective trip could result in the actuation of a generator lockout. In this instance, local operator action would be required (i.e., resetting the lockout) prior to the EDG restarting and/or resequencing onto the bus following a subsequent signal (either emergency or non-emergency). For emergency starts (LOCA, LOP or emergency manual), local operator action would only be required if a generator lockout protective trip had actuated before the emergency start signal.
One of the concerns expressed by the NRG mtThas been that a possible fault on the offsite system could lockout the ESF bus or trip the EDG itself and, as a result, delay the unit's response to an emergency condition. While it is possible to postulate that some type of grid or bus fault could result in the actuation of an EDG protective trip / lockout, it is EOI's opinion that any delay 2
in EDG response time would be considered acceptable due to:
the less critical nature of EDG start / load times for LOP, the low probability of subsequent events occurring following the initial LOP and procedural requirements that would tend to minimize EDG response times.
2 In proposing the subject Technical Specification change request, the approach taken is to confirm the possibility that an EDG lockout could occur, then, assuming a worst case that the lockout actuated, determining whether this was an acceptable condition. As a consequence, it is EOl's opinion that the likelihood of such 'n event occurring is low, based on our past experience of operating in a similar configuration when perfonning surveillance requirement 3.8.1.3 on at least a monthly basis.
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A LOP, unlike a LOCA, does not present an immediate challenge to the fuel cladding integrity, reactor water level control or to containment parameters, as demonstrated by the bounding four-hour station blackout coping analysis contained in RBS's station blackout conformance report.
Finally, any potential delay in EDG response time would be minimized by the way in which the test is performed. Per procedural requirements, prior to beginning the test suitable communications between the Control Room and the local EDG Room must be established. Also, during the 24-hour run, the EDG must be closely monitored by collecting local data. These a
procedural requirements help ensure timely local operator response to any abnormal EDG 2
conditions and subsequent recovery from any such event.
4 RESPONSE TO LOC' CONCURRENT WITil LOSS OF OFFSITE POWER In accordance with SAR Chapter 15 analysis, the design basis accident (DBA)is the occurrerce of a LOCA coincident with a LOP. The event is initiated by the occurrence of the LOCA; the simultaneous LOP is assumed to ensure a bounding case for the subsequent single failure (i.e.,
loss of one ESF division).
Consistent with the Chapter 15 analysis, any EDG test would be terminated by the receipt of the LOCA signal. In this instance, the LOCA signal takes precedence resulting in sys, tem response as previously described to the receipt of a LOCA signal singularly. However in this case, sinc-offsite power is lost concurrent with the LOCA signal, the EDG will automatically be transferred back onto the ESF bus following the tripping of offsite feeder breakers. The bus, once isolated from the offsite grid, would be reenergized by the EDG output br eaker reclosing. In this instance, the reenergization of the ESF bus will actually be slightly faster than the assumed UFSAR time since the EDG would already be at rated speed and voltage and thus need only have its output breaker reclosed to energize the bus.
As noted in the discussion concerning LOP, a possible fault on the offsite system could lockout the ESF bus or trip the EDG itself; and, as a result, delay the unit's response to an emergency condition. It is EOl's opinion that the likelihood of such an event occurring is low, based on our past experience of operating in a similar configuration when performing surveillance requirement 3.8.1.3 on at least a monthly basis. Also, the risk of operating during the 24-hour EDG test is certainly less than the current 72-hour allowed outage time for an inoperable EDG because the EDG being tested is not actually failed.
This review demonstrates that the EDGs will not stop or be rendered inoperable with a concurrent LOP /LOCA signal. The review also demonstrates that the EDGs are designed to withstand the stresses generated by any credible offsite fault. Finally, the review demonstrates that paralleled operation of the EDGs will be terminated prior to any credible fault causing the EDG to trip or be locked out.
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i ADDITIONAL CONSIDERATIONS
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In addition to the existing system design features, there are other factors that should be
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considered when evaluating the acceptability of this proposed Technical Specification change.
There are other Technical Specification Surveillance Requirements that are of particular interest 1
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as they relate to the proposed change.
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- Current surveillance testing required by SR 3.8.1.3 results in the EDGs being operated in
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parallel with the grid. This al!owance is restricted to one EDG at a time. Therefore, this j
request will not result in a new configuration of the plant, it will only increase the time this L
configuration is allowed to exist. Any risk associated with the additional time is reduced by l
the administrative provisions noted below.
The ability of each EDG to survive a load reject without tripping is currently verified every 18
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i months by SR 3.8.1.9. This surveillance simulates an EDG being operated in parallel with the -
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grid, and following receipt of a LOCA signal the EDG output breakers trip, separating it from
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paralleled operation with the grid. This surveillance will remain and thus continue to confirm i
the ability of the EDGs to survive a total load reject.
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i Current surveillance testing required by SR 3.8.1.16 demo'nstrates on an 18-month frequency e
l' the capability of the EDG :o revert to the ready-to-load status following a LOCA signal while j
operating !n the parallel test mode. Demonstration of the test mode override ensures that the -
l EDG avadmility under accident conditions is not compromised as a result of testing.
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To identify the nsk of this additional testing, the unavailability for all three EDGs was j
increased in the probabilistic safety analysis (PSA) model to correspond to an additional i
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> per year of out-of-service time. This analysis conservatively assumed that the
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EDG is unavailable during the surveillance time. [During an actual surveillance, the EDG will be available.] The result of this evaluation was that the core damage frequency (CDF) l increased from 1.895E-6/yr. to 1.897E-6/yr. or about 2E-9/yr. increase in CDF. Note that additional conservatism exists here because, while the EDG is running during the i
surveillance, certain failure mechanisms, such as a failure to start, are eliminated.
As an additional consideration, the Technical Specifications provide ; 72-hour allowed outage time for an inoperable EDG. This allows 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> if the EDG is actually unavailable. In this situation, the risk would be higher than during the 24-hour diesel run because the EDG being tested is not actually failed.
Finally there are special administrative provisions that may be taken to more appropriately manage any risk presented by performing the EDG 24-hour test during Modes 1 and 2:
- i. Only one EDG will be tested in parallel to the offsite grid at a time, in accordance with SR 3.8.1.13.
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Appropriate precautions / limitations will be provided that caution against conducting the 24-i hour test during periods of severe weather or other events which could result in unstable j
offsite grid conditions as determined by EOI.
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- 3. With an EDG under test, administrative controls will be established to maintain required i
features supported by the remaining EDGs available. Specifically, no maintenance or testing 1
l will be planned for these features for the duration of the test. Should the need arise to
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l perform emerent work on these features during the 24-hour test, the decision whether to interrupt or continue the test will be based on the nature of the deficiency and the action times j-provided in the Technical Specifications for one EDG out of service and required redundant 4
features inoperable.
J Each of the above precautions / limitations will be included in appropriate procedural guidance following approval of this Technical Specification change request by the Staff and prior to performing the 24-hour run with the unit in either Mode 1 or 2.
E.
CONCLUSION In conclusion, the performance of the 244our diesel mai u.e lance m. while the unit is in Modes 1 or 2 will not adversely affect the ability of either of the ti..a EDGno respond to design basis events per the SAR. Following generation of either a LOCA or LOP signal, occurring individually or concurruntly, the system design will terminate continued paralleled operation with offsite sources.
This design prevents the paralleled mode of operation from introducing a new or different failure from those previously assumed in the accident analysis. Since the response of an EDG in test is essentially identical to that of a EDG in normal standby, the unit will continue to satisfy the single failure criteria and remain within the assumed design basis during the performance of the 24-hour EDG test, regardless of the unit's mode of operation.
F.
SIGNIFICANT HAZARDS CONSIDERATION EOI proposes to change the current RBS Technical Specifications. The specific change is to modify Note 2 to SR 3.8.1.13. Presently, this note prohibits the performance of the 24-hour diesel maintenance run while the unit is in either Mode 1 or Mode 2. The proposed change would remove this restriction, thus allowing the 24-hour run to be performed during any mode of operation (i.e., Modes 1,2,3,4 or 5).
The Commission has provided standards for determining whether a no significant hazards consideration exists'as stated in 10 CFR 50.92 (c). A proposed amendment to an operating license involves no significant hazards consideration if operation of the facility, in accordance with the proposed amendment, would not: (1) involve a significant increase in the probability or consequences of an ac :ident previously evaluated; (2) create the possibility of a new or different kind of accident from any accident previously evaluated; or (3) involve a significant reduction in a margin of safety.
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E01 has evaluated the no significant hazards consideration in its request for this license amendment and determined that no significant hazards result from th's change. In accordance with 10 CFR 50.91(a), EOl is providing the analysis of the proposed amendment against the three standards in 10 CFR 50.92(c). A description of the no significant hazards consideration determination follows:
I.
The proposed change does not significantly increase the probability or consequences of an accident previously evaluated.
The RBS SAR assumes that the AC electrical power sources are designed to provide sufficient capacity, capability, redundancy and reliability to ensure that the fuel, reactor coolant system and containment design limits are not exceeded during an assumed design basis event. Specifically, the SAR assumes that the onsite EDGs provide emergency power in the event offsite power is lost to either one or all three ESF buses. In the event of a loss of preferred power, the ESF electrical loads are automatically connected to the EDGs in suflicient time to provide for safe reactor shutdown and to mitigate the consequences of a design basis accident such as a LOCA.
The proposed change to permit the 24-hour testing of the EDGs during power operation does not significantly increase the probability or consequences of any previously evaluated accident. The capability of the EDGs to supply power in a timely manner will
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not be compromised by permitting performance of EDG testing during periods of power operation. Design features of the EDGs and electrical systems ensure that if a LOCA or LOP signal, either individually or concurrently, should occur during testing, the EDG would be returned to its ready-to-load condition (i.e., EDG running at rated speed and voltage separated from the offsite sources) or separately connected to the ESF bus providing ESF loads. An EDG being tested is considered to be operable and fully capable of meeting its intended design function. Additionally, the testing of an EDG is not a precursor to any previously evaluated accidents.
If, during the test period, the EDG were to receive a normal operation protective trip resulting in the actuation of a generator lockout signal, the lockout could be reset by the operators monitoring the test. The resulting delay does not present an immediate challenge to the fuel cladding integrity, reactor water level control or to containment parameters, as demonstrated by the bounding four-hour station blackout coping analysis contained in RBS's station blackout conformance report.
Therefore, the proposed change allowing testing of EDGs during power operation will not significantly increase the probability or consequences of an accident previously evaluated.
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II.
The proposed change does not create the possibility of a new or different kind of accident from any accident previously evaluated.
As previously discussed, the proposed change to permit the performance of EDG testing during power operation will not affect the operation of any system or alter any system's response to previously evaluated design basis events. The EDGs will automatically transfer from the test configuration to the ready-to-load configuration following receipt of a valid signal (i.e., LOCA or LOP). In the ready-to-load configuration the EDG will be j
running at rated speed and voltage, separated from the offsite source and capable of automatically supplying power to the ESF buses in the event that preferred power is actually lost.
The proposed change is also the same configuration currently used for the monthly one-hour test. Therefore, testing during power operation will not create the possibility of a new or different kind of event from any previously evaluated.
SR 3.8.1.16 demonstrates that the EDG will automatically override the test mode following generation of a LOCA signal. In addition, the ability of the EDGs to survive a full load reject is verified by the performance of SR 3.8.1.9. These existing surveillance requirements, along with system design features, ensure that the performance of EDG testing during power operation will not create the possibility of a new or different kind of accident from any previously evaluated.
III.
The proposed change does not involve a significant reduction in a margin of safety.
The AC electrical power sources are designed to provide sufficient capacity, capability, redundancy, and reliability to ensure the availability of necessary power to ESF systems so that the fuel, reactor coolant system and containment design limits are not exceeded.
Specifically, the EDGs must be capable of automatically providing power to ESF loads in sufficient time to provide for safe reactor shutdown and to mitigate the consequences of a design basis accident in the event of a loss ofpreferred power.
Testing of EDGs durir.g power operation will not affect the availability or operation of any offsite source of power. In ac.'dition, the EDG being tested remains capable of meeting its intended design functions. Tharefore, the proposed change to the Technical Specification Surveillance Requirement 3.8.1.13 will not result in a reduction in a margin of safety.
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