ML17312B037
| ML17312B037 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 11/13/1996 |
| From: | Clifford J NRC (Affiliation Not Assigned) |
| To: | NRC (Affiliation Not Assigned) |
| References | |
| NUDOCS 9611190156 | |
| Download: ML17312B037 (50) | |
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UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 2055&4001 November 13, 1996 go -5> <
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LICENSEE:
Arizona Public Service Company FACILITY:
Palo Verde Nuclear Generating Station, Unit Nos.
1, 2, and 3
SUBJECT:
HEETING SUHHARY The NRC staff met with representatives of the Arizona Public Service Company (APS) on September 18, 1996, at NRC Headquarters in Rockville, Haryland, to discuss issues related to degraded grid voltage concerns and grid stability at the Palo Verde Nuclear Generating Station.
The list of at'tendees is provided in Enclosure 1.
The presentation material used by the licensee is provided in Enclosure 2.
The licensee's presentation covered issues associated with the electrical design of Palo Verde, including recent issues of degraded grid voltage and a potential unreviewed safety question related to the number of required off-site power sources.
In addition, the licensee provided the staff with information related to the August 10, 1996, western electrical grid disturbance.
The licensee provided a detailed discussion of the electrical design issues discovered during their investigation of the potential impact of degraded grid voltage on safety-related components at the facility.
The licensee first identified concerns with the design for degraded grid voltage during its e]ectrical design calculation reconstitution program in 1992.
The licensee identified potential problems that may have affected the ability of some safety-related equipment to operate under postulated design basis accident conditions.
The licensee instituted changes to address the identified concerns in 1993, changing the allowed voltage range to assure availability during postulated design-basis accident conditions.
Subsequent evaluations led the licensee to propose additional interim corrective actions, including manual block of the off-site power fast bus transfer on one train's electrical supply within one hour, and starting and loading the diesel generator (alternatively, block fast bus transfer) for the other train's electrical supply.
This action was incorporated into the licenses by amendment to the plants'echnical specifications in November 1995.
The general approach the licensee took with this issue was to try to modify the facility to conform to the design basis, rather than revise the design basis through license amendment to address an unreviewed safety question.
The licensee performed additional studies to determine if blocking fast bus transfer on one train, with the other train unblocked for some period of time (up to two hours) would have a deleterious effect on safety-related equipment.
This effort is described in detail in the meeting minutes from a June 26, 1996, meeting with the licensee.
The licensee determined that under specific postulated conditions of voltage and design-basis accident conditions, at j
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least one safety-related system (auxiliary feedwater) could be affected.
The licensee's risk analysis determined that additional restrictions were appropriate to assure the availability and operability of safety-related equipment for postulated accident sequences under degraded grid voltage conditions.
These restrictions included an immediate block of fast bus transfer for both trains within one hour of the onset of degraded grid voltage conditions.
Once both trains of safety-related equipment are protected from the degraded voltage condition, the operators are directed to start and load the DG for one train to isolate one train from offsite power.
This action is consistent with the current TS, but is the more restrictive option available to the operators.
The actions are currently defined in plant operating procedures, and will be codified in an amendment to the plants'echnical specifications (TS) in the near future.
The NRC staff provided a list of questions to help its understanding of this analyzed condition.
The questions, presented by the staff as a request for additional information, are provided in Enclosure 3.
The licensee agreed to respond to the questions, pending receipt of the questions as part of this meeting summary.
The second issue the licensee discussed was their recent recognition of the effect of the installation of a new transmission line on the Palo Verde design basis.
Another utility in Arizona had installed a new transmission line over two existing transmission lines that supply the Palo Verde plant site.
The licensee had assessed the impact of the new line when it was proposed by the other utility, but at the time had failed to identify the impact of the new line on the Palo Verde plant licensing basis.
The licensee had recently reviewed this condition, and determined that their updated final safety analysis report (UFSAR) analysis only assumes loss of one offsite transmission line (also a supply line in the case that a unit is shutdown).
The licensee performed an analysis pursuant to 10 CFR 50.59, and determined that this condition constituted an unreviewed safety question.
The licensee's conclusion is based on this condition resulting in an increase in the probability of an existing accident (loss of offsite power),
and potentially a
new or different kind of accident.
The licensee further stated that their subsequent analysis against the criteria in NUREG-0800 and Regulatory Guide 1.70 determined that the condition was acceptable from a safety perspective.
The licensee estimated that they would submit a request for amendment to the operating license to address the unreviewed safety question (US()
as required by 10 CFR 50.59 by September 30, 1996.
The licensee subsequently deferred submittal of this amendment to complete their work on the improved standard TS submittal.
The licensee expects to submit the US( amendment in the near future.
The final issue the licensee discussed was an overview of the western states'rid disturbance that occurred on August 10, 1996.
The licensee described the transmission system in the Western States Cooperative Council (WSCC).
The licensee then described the conditions in the western states, and the operation of other generation sites that contributed to the initiation of loss of power.
The licensee further discussed the effects of the disturbance on the three Palo Verde units.
The licensee's analysis of the event determined that the relatively large moderator temperature coefficient (MTC) in Units I and 3 contributed to these two plants tripping in response to the feedback of the voltage and frequency transients from the grid into the main turbine control systems, and subsequently through plant. dynamics to the reactor.
Unit 2 had recently started up from a refueling outage, and its lower MTC served to dampen the magnitude of the feedback, allowing the plant to remain operating throughout the event.
The NRC staff expressed an interest in having the licensee keep the staff informed of proposed actions by the WSCC.
The staff also expressed interest in attending future WSCC meetings.
The licensee stated they would keep the NRC staff informed of WSCC activities, and would bring up the potential for NRC staff attendance with the Council.
Docket Nos.
STN 50-528, STN 50-529, and STN 50-530 Jam s
W. Cliffor, Senior Project Manager Project Directorate IV-2 Division of Reactor Projects III/IV Office of Nuclear Reactor Regulation
Enclosures:
1.
Attendance List 2.
Licensee's Handout 3.
Staff guestions cc w/encls:
See next page that the relatively large moderator temperature coefficient (MTC) in Units 1
and 3 contributed to these two plants tripping in response to the feedback of the voltage and frequency transients from the grid into the main turbine control
- systems, and subsequently through plant dynamics to the reactor.
Unit 2 had recently started up from a refueling outage, and its lower MTC served to dampen the magnitude of the feedback, allowing 'the plant to remain operating throughout the event.
The NRC staff expressed an interest in having the licensee keep the staff informed of proposed actions by the WSCC.
The'staff also expressed interest in attending future WSCC meetings.
The licensee stated they would keep the NRC staff informed of WSCC activities, and would bring up the potential for NRC staff attendance with the Council.
Original signed by:
Docket Nos.
STN 50-528, STN 50-529, and STN 50-530
Enclosures:
l.
Attendance List 2.
Licensee's Handout 3.
Staff guestions cc w/encls:
See next page DOCUMENT NAME:9-18-96.SUM James W. Clifford, Senior Project Manager Project Directorate IV-2 Division of Reactor Projects III/IV Office of Nuclear Reactor Regulation DISTRIBUTION: (Hard Copy)
Docket Files PUBLIC PDIV-2 Reading OGC ACRS E-MAIL FMiraglia/AThadani RZimmerman JRoe EGA1 WBateman JClifford CThomas EPeyton EJordan NRC Participants JMitchell
- DKirsch, RIV WCFO OFC NAME DATE PDIV-2 PDIV-2 JC
'%ford
'Epoeyon 117 96 Il/G 96 OFFICIAL RECORD COPY PDIV-2 WBatema 11 l3 96 gaol I
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l II that the relatively large moderator temperature coefficient (HTC) in Units 1
and 3 contributed to these two plants tripping in response to the feedback of the voltage and frequency transients from the grid into the main turbine control systems, and subsequently through plant dynamics to the reactor.
Unit 2 had recently started up from a refueling outage, and its lower HTC served to dampen the magnitude of the feedback, allowing the plant to remain operating throughout the event.
The NRC staff expressed an interest in having the licensee keep the staff informed of proposed actions by the WSCC.
The staff also expressed interest in attending future WSCC meetings.
The licensee stated they would keep the NRC staff informed of WSCC activities, and would bring up the potential for NRC staff attendance with the Council.
Original signed by:
Docket Nos.
STN 50-528, STN 50-529, and STN 50-530
Enclosures:
l.
Attendance List 2.
Licensee's Handout 3.
Staff guestions cc w/encls:
See next page DOCUHENT NAME:9-18-96.SUH James W. Clifford, Senior Project Hanager Project Directorate IV-2 Division of Reactor Projects III/IV Office of Nuclear Reactor Regulation
~OSiRIB TION:
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Docket Files PUBLIC PDIV-2 Reading OGC ACRS
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FHiragl i a/AThadani RZimmerman JRoe EGA1 WBateman JClifford CThomas EPeyton EJordan NRC Participants JHitchell DKirsch, RIV WCFO PDIV-2 OFC PD IV-2 NAHE JC 'ord e
on DATE 11 7 96 11 G 96 OFFICIAL RECORD COPY PDIV-2 WBatema ll 1$
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cc w/encls:
Hr. Steve Olea Arizona Corporation Commission 1200 W. Washington Street Phoenix, Arizona 85007 Douglas Kent Porter Senior Counsel Southern California Edison Company Law Department, Generation Resources P.O.
Box 800
- Rosemead, California 91770 Senior Resident Inspector USNRC P. 0.
Box 40 Buckeye, Arizona 85326 Regional Administrator, Region IV U. S. Nuclear Regulatory Commission Harris Tower
&, Pavillion 611 Ryan Plaza Drive, Suite 400 Arlington, Texas 76011-8064
- Chairman, Board of Supervisors ATTN:
Chairman 301 W. Jefferson, 10th Floor Phoenix, Arizona 85003 Hr. Aubrey V. Godwin, Director Arizona Radiation Regulatory Agency 4814 South 40 Street Phoenix, Arizona 85040 Hs. Angela K. Krainik, Manager Nuclear Licensing Arizona Public Service Company P.O.
Box 52034 Phoenix, Arizona 85072-2034 Mr. John C. Horne, Vice President Power Supply Palo Verde Services 2025 N. Third Street, Suite 220 Phoenix, Arizona 85004 Hr. Robert Burt Los Angeles Department of Water
& Power Southern California Public Power Authority 111 North Hope Street, Room 1255-B Hr. David Summers Public Service Company of New Mexico 414 Silver SW, 80604 Albuquerque, New Mexico 87102 Mr. Brian Katz Southern California Edison Company 14300 Mesa Road, Drop D41-SONGS San Clemente, California 92672 Hr. Robert Henry Salt River Project 6504 East Thomas Road Scottsdale, Arizona 85251 Mr. James M. Levine Executive Vice President, Nuclear Arizona Public Service Company Post Office Box 53999
- Phoenix, Arizona 85072-3999
Enclosure I G WITH ONA U
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OMPANY UCLEAR G
T G STAT 0 UN TS JU 996 NDANCE ST ND 3 o
1 Ser Com an Steve,Kesler Scott Burns Scott Bauer Jack Bailey Harvey Leake Don Lamontagne gRC Jim Clifford Bill LeFave Bill Bateman Dale Thatcher Jim Lazevnick Gus Lainas Brian Sheron Jack Roe Elinor Adensam Chu-yu Liang Dyle Acker
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Enclosure 2
MEETING WITH ARIZONAPUBLIC SERVICE COMPANY PALO VERDE NUCLEAR GENERATING STATION UNITS 1, 2, AND 3 VOLTAGEISSUES September 18, 1996 HANDOUT MATERIALUSED AT THE MEETING
NRC Presentation September 18, 1996
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ime ine 1992 1993 1994 1995 1996 J ASOND J F MAMJ J ASOND J F MAMJ J A SOND J F MAMJ J A SOND J F MAMJ Substan rd Voltage Double S quencing Plant Modifi ations Approved Temp T.S. Change Train interaction valuation
Palo Verde Offsite Power - Normal Operation Westwing 1 525 KVEast Bus Westwing 2 Kyrene North Gila Devers 525 KVWest Bus Unit1 Start Up Transformer Unit 2 Start Up Transformer Unit 3 Start Up Transformer 1XC KV ~ CSern nCKV
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~ ssjas unn Aux 1XC KV 1%4 KV SX4 KV 1XC KV
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- 14 KV House House Load Lead 4.14 KV
- 16 KV House House Lead Load 4.16 KV 4.14 KV House House Load Load 4.16 KV Q 44g V Emergency Qesel Unit 1 Unit 2 Unit 3
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+ Reconstitute Design Basis Calculations
~ 3 phase system, 480 VAC and above
~ 320 VAC Distribution
~ 120 VAC Control
+ E-CALC distribution system analysis program
~ Replaced A/E calculations
~ Modeled entire onsite system
~ Evaluated several modes of plant operation
~ Analyzes steady state and in-rush currents
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+ High impedance Startup transformers
+ Large load transfer following plant trip
+ As-,built distribution system loading more extreme than original design calculation assumptions
+ Two voltage transformation levels between switchyard and 4.16 kV Class 1E systems
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SWITCH YARD 13.8 KV BUS 4160 V BUS
+ At 95% Switchyard voltage and heavy distribution system loading
+ DVRs may actuate 480 V BUS 480 V LOAD 70 90 110
+ Minimum load voltages too low Percent of nominal Bus/Load voltage
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+ Modifications Considered
~ Revise DVR setpoints
~ Block automatic Fast Bus Transfer
~ Revise station normal electric lineup
+ Modifications Implemented
~ Restrict switchyard normal operating range
~ Replace DVR's with more accurate relays
~ Revise transformer tap settings
I
ime ine 1992 1993 1994 1995 1996 JASONDJ FMAMJ JASOND J FMAMJ JASOND J FMAMJ JASOND J FMAMJ Substan rd Voltage Double S quencing Plant Modifi ations Approved Temp T.S. Change Train interaction valuation
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e uencin 4200 Pre-LOCA voltage (Depends on system loading and switchyard voltage) 4100 4000 0
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Voltage drop due to Fast Bus Transfer
+ Minimum voltages Degraded voltage Relay Setpoints Dropout Reset Relay Tolerance 5
10 t 5 20 25 30 Sequencer Steps (seconds)
Fast Bus Transfer occurs
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+ Split strategy - Manual Block FBT/Load EDG
~ Prompt restoration of Operability
~1 Train w/in 1 Hour, 2nd Train wiin 2 Hours
~ Low probability of degraded voltage coincident with LOCA/ESFAS
~ Maintains forced circulation for higher probability events
~ Voltage monitored by APS Load Dispatch and Unit 1
~Prompt corrective actions to restore voltage
ime ine 1992 1993 1994 1995 1996 J ASOND J FMAMJ J ASOND J FMAMJ J ASOND J FMAMJ J ASOND J F MAMJ Substan rd Voltage Double S quencing Plant Modifi ations Approved Temp T.S. Change Train Interaction valuation
orrec ive c ion an-
+ Manual FBT block when below allowable switchyard voltage range
+ Re-establish operating range of 98 to 102%
~ Upgraded accuracy of Unit 1 525Kv meter
~ Complete analysis of distribution system voltages
~ Trip WRF on SIAS 8 low switchyard voltage
~ Complete component fixes in 2R6, 1R6, 3R6
~ Submit Tech Spec change
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+ 1995 temporary Tech Spec assumed blocking FBT resulted in operability of blocked train
+ PVNGS review of Tech Spec submittal assumed unblocked train could be disregarded
~ Accepted industry standards for safety related train separation adequate justification for not analyzing further
~ Opposite train not "credited" for safe shutdown/accident mitigation
+ Is blocked train free from adverse system interactions from unblocked train'?
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Auxiliary Feedwater Schematic (Essential Trains)
Faulted Generator CONDENSATE STORAGE TANK Intact Generator VO79 VO80 TURBINE DRIVEN PUMP V137 V015 HV32 UV36 HV33 UV37 MOTOR DRIVEN PUMP V138 V024 HV31 UV35 HV30 UV34 Valves MAYfail under degraded voltage
I
n crim om ensa or c ions
+ Maintain switchyard voltage range 100% - 102%
+ For sustained voltages of <100%:
~ Block Fast Bus Transfer in both trains within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />
- THEN-
'tart and load the DG and isolate from offsite power in the selected train
+ Implemented procedure changes
~ Minimize risk of double sequencing in inoperable train
orrec ive c ion an-
+ Lower minimum switchyard voltage
~ Complete plant modifications (R6)
~Water reclamation facilitytrip on SIAS coincident with low switchyard voltage conditions
~ Complete electric distribution system reanalysis (05i97)
~ Tech Spec change (11l97)
~Add operability and surveillance requirements for WRF trip logic
~Widen the acceptable switchyard voltage operating range
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ri ta ii na sis e Uirements
+ NUREG-0800 (SRP) requires the analysis of:
~ Loss of the largest generator on the grid,
~ Loss of the largest load on the grid,
~ Loss of the most critical transmission line to the nuclear unit, and
~ Acceptable frequency decay rate (RCP slowdown)
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+ New analyses demonstrates Standard Review Plan, CESSAR, and RG 1.70 criteria met for simultaneous failure of Westwing 1
and Westwing 2.
~ Voltage and frequency
+ USQ analyses will be submitted by 9/30/96.
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REQUEST FOR ADDITIONAL INFORMATION OFFICE OF NUCLEAR REACTOR REGULATION DIVISION OF SYSTEM SAFETY AND ANALYSIS PLANT SYSTEMS BRANCH DOUBLE SEQUENCING AND AUXILIARY FEEDWATER PALO VERDE NUCLEAR GENERATING STATION, UNITS 1, 2, AND 3 DOCKET NOS. 50-528, 50-529, AND 50-530 As a result of its review of Supplement 2 to License Event Report (LER)93-011 related to "double sequencing" of safety-related equipment the staff has determined that there is a need for additional information to understand the potential effects on the auxiliary feedwater (AFW) system and to evaluate other potential AFW failure modes.
In that LER, the licensee postulated a
scenario which could potentially result in uncontrolled AFW flow to the faulted and/or intact steam generator (S/G) during secondary system line breaks.
This scenario could result in the failure of both of Train B's (safety-related motor-driven AFW pump) discharge motor operated valves (HOVs) to close, affecting the ability to isolate AFW flow to the faulted S/G, as well as overfilling the intact S/G, which may result in a water hammer condition which could damage steam lines associated with the intact S/G.
The staff's review of the AFW system identified the following issues associated with this scenario.
l.
It is the staff's understanding that the AFW discharge MOVs are normally closed and receive a signal to open on an auxiliary feedwater actuation signal (AFAS). It is also our understanding that if there is a secondary line break associated with the AFAS, the HOVs to the affected (faulted)
S/G will not open due to pressure differentials between the two S/Gs.
Given this is the case, how can the scenario result in uncontrolled AFW
.flow to the faulted S/G when the MOVs to that S/G should remain closed?
2.
3.
The Train 8 discharge HOVs (4 total) receive alternating current (ac) power from the same ac bus while the Train A (turbine-driven AFW pump)
MOVs (4 total) receive direct current (dc) power from the same dc bus.
Therefore, it appears that the single failure of the associated dc or ac bus could result in all four Train A or Train B discharge HOVs failing open (or closed if they are already closed) resulting in the same uncontrolled AFW flow situation to the faulted and/or. intact S/G as described in the LER scenario even without a double-sequencing event.
Please explain how this bus failure scenario is prevented by the AFW system design, and how the design meets the single failure criterion for all scenarios where the single failure assumed is that of the ac or dc bus supplying these valves.
There
- appear, to be no check valves between AFW Trains A and 8 such that 5
if all the OVs in one train are assumed to be failed open (as in the LER scenario or due to bus failure) uncontrolled flow would 'occur from both trains to a faulted S/G during a secondary line failure.
Similarly, if there was no secondary line failure, uncontrolled flow to an intact steam generator (overfill potential) could occur from both trains due to backflow conditions between.trains.
Please explain how this cross-connect scenario is prevented and how adequate independence between AFW trains is maintain for other AFW scenarios.
Also, could this affect the ability of the automatic AFW flow control system to maintain S/G levels
(and, hence the minimum time for operator intervention) under conditions where the difference in pressure between steam generators may be significant but less than that required to isolate the S/G with the lower pressure?