05000530/LER-1989-001, :on 890303,electrical Grid Disturbance Resulted in Main Generator Output Breakers Opening,Resulting in Reactor Power Cutback & Steam Bypass Control Sys Actuation. Caused by Malfunction in Subj Control Sys
| ML17305A505 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 01/28/1990 |
| From: | Bradish T, James M. Levine ARIZONA PUBLIC SERVICE CO. (FORMERLY ARIZONA NUCLEAR |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| References | |
| 192-00624-JML, 192-624-JML, LER-89-001, LER-89-1, NUDOCS 9002120163 | |
| Download: ML17305A505 (34) | |
text
.. 'ACCELERATED QSTRJBUTION DEMONSATION SYSTEM REGULATORY INFORMATION DISTRIBUTION SYSTEM (RIDS)
ACCESSION NBR:9002120163 DOC-DATE-90/01/28 NOTARIZED: NO DOCKET FACIL:STN-50-530 Palo Verde Nuclear Station, Unit 3, Arizona Publi 05000530 AUTH.NAME AUTHOR AFFILIATION BRADISH,T.R.
Arizona Public Service Co. (formerly Arizona Nuclear Power LEVINE,J.M.
Arizona Public Service Co.
(formerly Arizona Nuclear Power RECIP.NAME RECIPIENT AFFILIATION
SUBJECT:
LER 89-001-03:on 890303,reactor trip due to low steam generator level.
W/8 DZSTRZBUTZON CODE:
ZE22T CORTES RECEZVED:LTR t ENCL i SZZE:
TITLE: 50.73/50.9 Licensee Event Report (LER), Incident Rpt, etc.
NOTES:Standardized plant.
05000530 A
RECIPIENT ID CODE/NAME PD5 LA PETERSON,S.
INTERNAL: ACRS MICHELSON ACRS WYLIE AEOD/DSP/TPAB DEDRO NRR/DET/EMEB9H3 NRR/DLPQ/LHFB11 NRR/DOEA/OEAB11 NRR/DST/SELB 8D NRR DS PLB8Dl EG~~>L 02 RGN5 FILE 01 EXTERNAL: EG&G WILLIAMS,S LPDR NSIC MAYS,G NUDOCS FULL TXT NOTES:
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1 RECIPIENT ID CODE/NAME PD5 PD ACRS MOELLER AEOD/DOA
'EOD/ROAB/DSP NRR/DET/ECMB 9H NRR/DET/ESGB 8D NRR/DLPQ/LPEB10 NRR/DREP/PRPB11 NRR/DST/SICB 7E NRR/DST/SRXB 8E RES/DSIR/EIB L ST LOBBY WARD NRC PDR NSIC MURPHY,G.A COPIES LTTR ENCL 1
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NOTE TO ALL"RIDS" RECIPIENTS:
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PLEAS/ HELP US TO REDUCE WASTE! CONTACI'HE DOCUMENT CONTROL DESK, ROOM P 1-37 (EXT. 20079) TO ELIMINATEYOUR NAMEFROM DISTRIBUTION LISTS FOR DOCUMENIS YOU DON'T NEED!
FULL TEXT CONVERSION REQUIRED TOTAL NUMBER OF COPIES REQUIRED:
LTTR 38 ENCL 38
Arizona Public Service Company PALO VERDE NUCLEAR GENERATING STATION P.O. BOX 52034
~
PHOENIX. ARIZONA85072-2034 JAMES M. LEVINE VICE PRESIDENT NUCLEAR PRDDUCTIDN 192-00624-JML/TRB/DAJ January 28, 1990 U.
S. Nuclear Regulatory Commission Document Control Desk Washington, DC 20555
Dear Sirs:
Subj ect:
Palo Verde Nuclear Generating Station (PVNGS)
Unit 3 Docket No.
STN 50-530 (License No. NPF-74)
Licensee Event Report 89-001-03 File'0-020-404 Attached please find Supplement Number 3 to Licensee Event Report (LER) No.
89-001-00 prepared and submitted pursuant to 10CFR50.73.
In accordance with 10CFR50.73(d),
we are herewith forwarding a copy of the LER to the Regional Administrator of the Region V office.
If you have any questions, please contact T. R. Bradish, (Acting) Compliance Manager at (602) 393-2521.
Very truly yours, JML/TRB/DAJ/kj Attachment CC:
W. F.
Conway (all w/a)
E.
E. Van Brunt J.
B. Martin D.
Coe M. J.
Davis A. C. Gehr INPO Records Center 9002120163 5'00128 PDR ADOCK 05000530 9
NRC FORM 365 (SJ)9f U.S. NUCLEAR REGULA'TORY COMMISSION LICENSEE EVENT REPORT (LER)
APPROV ED OMB NO. 3'l504))04 EXPIRES: 4i30i92 ESTIMATED BURDEN PER
RESPONSE
TO COMPLY WTH THIS INFORMATION COLLECTION AEGUEST.'0.0 HRS. FORWARD COMMENTS REGARDING BURDEN FSTIMATE TO THE RECOADS AND AEPORTS MANAGEMENTBRANCH IP630), U.S. NUCLEAR REGULATORY COMMISSION, WASHINGTON, DC 20555, AND TO THE PAPERWOAK REDUCTION PROJECT (31500104).
OFFICE OF MANAGEMENTAND BUDGET, WASHINGTON, DC 20503.
FACILITYNAME (I)
Palo Verde Unit 3 TITLE (4)
Reactor Tri Due to Low Steam Generator Level OOCKF7 NUMBER (2) 0 5
0 0
0 PA E
3 1
OF
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EVENT DATE(5)
LER NUMBER (5)
REPORT DATE (7)
OTHER FACILITIES INVOLVED(5)
MONTH OAY YEAR YEAR BEDUsrrTIAL NUMSEII rrcvrcrorr
'UMBER MONTH OAY YEAR FACILITYrrAMES N/A DOCKET NUMBFRISI 0
5 0
0 0
0 3 038989 0
0 1
0 3
0 1
2 8 9 0 N/A 0
5 0
0 0
OPERATING MODE (5)
POWER LEUEL 0
9 8
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THIS REPORT IS SUBMITTED PURSUANT T 73.71(5) 73.71(cl OTHER fSpecrfy in Arrrtrect trerow erxf in Text, HitC Form JSSAJ NAME Thomas R. Bradish (Actin ) Com liance Mana er TELEPHONE NUMBER AREA CODE 6 023 9
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COMPLETE ONE LINE FOA EACH COMPONENT FAILURE DESCRIBED IN THIS REPORT (13)
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X NO ABSTRACT (Limit to 1400 rpecer, ieepproximeteiy fifteen rinpie rpece typewritren iinni 115)
MONTH OAY EXPECTFD SUBMISSION DATE (15)
YEAR On March 3, 1989 at approximately 0102 MST Palo Verde Unit 3 was operating at approximately 98 percent power when an electrical grid disturbance resulted in the Main. Generator output breakers opening.
This resulted in a Reactor Power Cutback (RPCB) and Steam Bypass Control System (SBCS) actuation.
An SBCS malfunction resulted in a Steam Generator (S/G) number 2 low pressure reactor trip, turbine trip, Main Steam Isolation Signal, and Containment Isolation Actuation Signal at approximately 0103 MST.
Approximately six seconds later, a Safety Injection Actuation Signal occurred as a result of low pressurizer
'ressure,
à Control Room personnel attempted to remove decay heat and control S/G pressure utilizing the Atmospheric Dump Valves (ADV's).
Control Room personnel could not remotely operate the ADV's from the Control Room or Remote Shutdown Panel.
Heat removal was subsequently established by manually opening the ADV's.
In the interim, one Main Steam Safety Valve cycled to remove decay heat and control S/G pressure.
The cause of the reactor trip was a malfunction in the SBCS.
An independent investigation has been conducted to determine the causes of the problems occurring 'during the event.
Based upon the investigation, appropriate corrective measures have been developed.
This submittal also provides a Special Report in accordance with Technical Specification 3.5.2 ACTION b.
N AC Form 355 (5691
NAC FORM 366A (669)
~
LICENSEE EVENT REPORT ILER)
TEXT CONTINUATION APPAOVEO OMB NO. 31500104 EXPIRES: 4/30I92 ESTIMATED BURDEN PEA RESPONSE TO COMPLY WTH THIS INFORMATION COLLECTION AEQUESTI 500 HRS, FORWARD COMMENTS REGARDING BURDEN ESTIMATE TO tHE RECORDS AND REPORTS MANAGEMENTBRANCH (P.530I. U.S. NUCLEAR REGULATORY COMMISSION, WASHINGTON, OC 20555, AND TD THE PAPERWORK AEOUCTION PROJECT (31500I04), OFFICE OF MANAGEMENTAND BUDGET, WASHINGTON.OC 20503.
FACILITYNAME (II Palo Verde Unit 3 TEXTIIImoro Spooo r'4 rorXdrod. Pro oddIP'orNI IVRC Form 36649) (17)
DOCKET NUMBER (2) 5 3089 LEA NUMBER (6)
Sg SEQUENTIAL NUMEER 0 0 1
'(IS REVISION 4 NUMSER 030 OF 1
5
DESCRIPTION
OF WHAT OCCURRED:
A.
Initial Conditions:
Prior to the event described in this LER, Palo Verde Unit 3 was operating in Hode 1
(POWER OPERATION) at approximately 98 percent power.
In-plant non-Class 1E electrical loads were being supplied by the Hain Turbine-Generator (EL)(TG) via the Unit Auxiliary Transformer (EA)(XFHR).
In-plant Class 1E electrical loads were being supplied by off-site power via the Startup Transformers (EA)(XFMR).
B.
Reportable Event Description (Including Dates and Approximate Times of Major Occurrences):
Event Classification:
Engineered Safety Features Actuation.
Condition Prohibited by the Plant's Technical Specifications.
At approximately 0102 HST on March 3, 1989 a fault occurred near the Devers, California switchyard which resulted in an electrical disturbance in the off-site power supply system.
The electrical disturbance resulted in the operation of the sub-synchronous oscillation protective relaying (RLY) for the Unit 3 Hain Turbine-Generator (TA)(TB) which caused the main generator output breakers to open.
This large load rejection resulted in the automatic actuation of the Steam Bypass Control System (JI),
Reactor Power Cutback System (JD),
and Power Load Unbalance circuitry in the Hain Turbine Control System (JJ).
The Main Turbine-Generator continued to supply in-plant non-Class 1E loads as designed.
The Steam Bypass Control System and Reactor Power Cutback System work together following a large load rejection to allow the Unit to remain at power.
The Steam Bypass Control System functions'o bypass steam around the Hain Turbine (TA)(TRB) during situations requiring the removal of excess Nuclear Steam Supply System energy.
The Reactor Power Cutback System rapidly reduces core (AC)(RCT) thermal power output by dropping preselected Control Element Assembly (AA)(ROD) subgroups and rapidly reducing Hain Turbine power output if required.
The power load unbalance circuitry initiates the fast closing of the turbine control valve (FCV) and turbine intercept valve (FCV) under load rejection conditions that might lead to rapid acceleration, overspeed, and consequent tripping of the turbine.
Once the power load unbalance is cleared, the control and intercept valves reopen.
None of these systems are Engineered Safety Features.(689)
FACILITYNAME III U.S. NUCLEAR REGULATORY COMMISSION LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION DOCKET NUMSER (21 APPROVEO OMS NO. 3150010E EXPIRES: S/30/92 ESTIMATED 8URDEN PEA AESPONSE TO COMPLY WTH 'THIS INFOAMATION COLLECTION REQUEST: 50.0 HAS. FORWARD COMMENTS REGARDING SURDEN ESTIMATE TO THE RECORDS AND REPORTS MANAGEMENT8AANCH (P.5301. U.S. NUCLEAR REGULATORY COMMISSION, WASHINGTON. DC 20555, AND TO THE PAPERWOAK REDUCTION PROJECT (3150010SI. OFFICE OF MANAGEMENTANO SUDGET, WASHINGTON,DC 20503.
LEA NUMBER (SI YEAR gg SEQUENTIAL:PM REVISION NUMSEA ls NVMOEA Palo Verde Unit 3 TEXT ///'mom spsso is IOOoiod. oss odd/oooo/
/SAC Foms 366A's/ I IT(
0 5
0 0
0 5
3 0 8 9
00 1
0 3
0 3 1
5 During the reactor power cutback, the control system for four (4) of the eight (8) steam bypass control valves (JI)(V) did not operate properly.
The control system malfunction caused these four Steam Bypass Control Valves to cycle from fully open to fully closed.
This cycling resulted in a reduction of secondary pressure due to excessive steam demand.
The secondary pressure reduction eventually resulted in a Steam Generator (AB)(SG) number two (2) low pressure trip signal.
The low pressure trip signal resulted in a reactor trip, Hain Turbine trip, and Main Steam Isolation Signal (HSIS)(JE)
Engineered Safety Feature (ESF) actuation at approximately 0103 HST.
Approximately six seconds after the reactor trip, Safety Injection Actuation Signal (BP)(Bg)(JE) and a
Containment Isolation Actuation Signal (JM)(JE)
ESF actuations occurred due to low pressurizer (AB)(PZR) pressure resul'ting from the Reactor Coolant System (AB)(RCS) cooldown.
In accordance with approved procedures for the Safety Injection Actuation Signal, a Control Room operator (utility, licensed) stopped two (2) of the four (4) Reactor Coolant Pumps (RCP's)(AB)(P).
Control Room personnel (utility, licensed) monitored safety functions and the Assistant Shift Supervisor (utility, licensed) diagnosed the event as an excessive steam demand pursuant to approved procedural controls.
During the monitoring of safety functions, Control Room personnel observed that the Safety Equipment Status System (IU) indicated that the following valves and dampers had not fully reached their actuated positions:
HPA-UV-001, "Containment Hydrogen Control System 'A'upply Isolation" (BB)(ISV);
SGA-HV-0201, "Steam Generator 2 Chemical Injection Isolation" (KD)(ISV);
SGA-UV-0223, "Steam Generator 2 Cold Leg Blowdown Downstream" (WI)(V);
SGA-UV-0225, "Steam Generator 2 Hot Leg Blowdown Downstream" (WI)(V)'GA-UV-1134, "Steam Trap SGN-H23 Isolation" (SB)(ISV);
SGA-UV-0227, "Steam Generator 2 Downcomer Blowdown DownstreamA (WI)(V);
NAC FORM SSSA ISSS)
U.S. NUCLEAR REGULATORY COMMISSION LICENSEE EVENT REPORT (LERI TEXT CONTINUATION APPAOVFO DMS NO. 31500104 EXPIRES: l/30/02 ESTIMATED BURDEN PFR
RESPONSE
TO COMPLY WTH THIS INFORMATION COLLECTION REOUESTI 50)3 HRS. FORWARD COMMENTS REGARDING BURDEN EST)MA'TE TO THE RECORDS AND AEPOA'TS MANAGEMENTBRANCH IP-530). U.S. NUCLEAR REGULATORY COMMISSION, WASHINGTON. OC 20555, AND TO THE PAPERWORK REDUCTION PROJECT (31500)OSI. OFFICE OF MANAGEMENTANDBUDGET,WASHINGTON,OC20503.
FACILITYNAME III DOCKET NUMBER I2)
LER NUMBER (5)
YEAR ymca SEOUENTIAL @$
'ASF NUMSS4 REVISION NUM554 PAGE LSI Palo Verde Unit 3 TEXT N mors spsoo r's rsorrwod. oso sddio'oos) iVRC Form 3054'sl II2) o s
o o
o 5
3 0 8 9
001 0
3 0 4 OF 1
5 SGB-UV-1135, "Steam Tap SGN-M02 Isolation" (SB)( ISV);
HFA-H06, "Auxiliary Building Essential Exhaust Air Filtration Unit Damper."
Control Room personnel also noted that the Radiation Honitoring System (RMS) displays were not available in the Control Room (NA),
and that the Containment temperature (IK)(TR) and humidity recorders (IK)(MR) and sump level indicators (IK)(LI) were not available (per design) due to the loss of non-Class lE power.
Following the Hain Turbine trip, a Fast Bus Transfer of the in-plant non-Class 1E electrical loads did not occur since the conditions for initiating the automatic transfer were not present at the time of the turbine trip.
Normally after a turbine trip, the main generator trips when a reverse power condition is sensed and the fast transfer of the in-plant non-Class 1E loads to the Startup Transformer occurs.
As described
- above, the main generator was already separated from off-site power, so no reverse power condition was sensed.
The main generator began to coast down after the turbine trip while still carrying in-plant non-Class lE loads.
When the generator was at a frequency of approximately 30 Hertz (approximately two minutes after the turbine trip), it tripped on Hi Volts/Hertz and initiated a Fast Bus Transfer signal.
In accordance with the design, the Fast Bus Transfer signal was blocked due to the in-plant non-Class lE loads not being in synchronization with the off-site power.
Therefore, a loss of power to the in-plant non-Class 1E electrical busses (3E-NAN-SOl and 3E-NAN-S02) occurred.
This resulted in the other two (2) RCP's being deenergized.
As a result of the Hain Steam Isolation System actuation, steam flow to the main condenser (SG)(COND) through the Steam Bypass Control Valves was terminated.
In order to remove decay heat without relying on the Main Steam Safety Valves (SB)(RV) or Primary Safety Valves (AB)(RV), remote operation of the Atmospheric Dump Valves (ADV's)(SB)(V) was attempted.
Operation of the ADV's could not be accomplished remotely from the Control Room or the Remote Shutdown Panel (JL).
Therefore, manual operation of the ADV's was attempted utilizing the valves'anual operators in the Hain Steam Support Structure (HSSS).
Additionally, Control Room personnel manually started the Turbine Driven Auxiliary Feedwater Pump (BA)(P) at approximately 0107 HST in order to provide an additional source of decay heat removal.
Operations personnel (utility, non-licensed) were sent to the HSSS to attempt to manually open an ADV on each steam generator (there are two ADV's on each of the two S/Gs).
Normal lighting (FF) in NRC FOIm 355A )589)
I(689)
U.S. NUCLEAR REGULATORY COMMISSION LICENSEE EVENT REPORT ILER)
TEXT CONTINUATION APPROVEO OMB NO.3)50010C E XPI R 55 I A/30/92 ESTIMATED BURDEN PER
RESPONSE
TO COMPLY WTH THIS INFORMATION COLLECTION REQUEST: 500 HRS. FORWARD COMMENTS REGARDING BURDEN ESTIMATE TO THE RECORDS ANO REPORTS MANAGEMENTBRANCH (PJ)30). U.S. NUCLEAR REGULATORY COMMISSION, WASHINGTON. OC 20555, ANO TO THE PAPERWORK REDUCTION PROJECT (31500104).
OFFICE OF MANAGEMENTANO BUDGET, WASHINGTON,OC 20503.
FACILITYNAME (1)
Palo Verde Unit 3 TEXT ///IIRNP CPPCP /S IPCVPPd. IIWAdds(PIN/ A'RC Form 35649/ I)2)
DOCKET NUMBER (2) 53 08 9
LER NUMBER (6)
SCOVCNZIAL
';. d NVM CR 001 REVISION NVMSCR PAGE (3) oFS 5
the HSSS was unavailable due to the loss of power to the in-plant non-Class.
1E electrical busses.
The single Essential Lighting fixture (FG)(LF) in the Steam Generator number 2 side of the MSSS was not functioning which resulted in almost total darkness in the area of the Steam Generator number 2 ADV manual operators.
Operations personnel utilized flashlights to provide lighting while manual ADV operations were performed.
At approximately 0137
- MST, a
steam generator number 1
ADV was opened to approximately 7 percent open.
At approximately 0141 HST, operations personnel attempted to establish a steam flow path for steam generator number 2 via ADV-185.
The manual handwheel for ADV-185 came off; therefore, operations personnel attempted to open ADV-179 on Steam Generator number 1.
During the attempt to manually open ADV-179, the handwheel was turned in the wrong direction due to a non-standard design and the valve was damaged.
Another attempt to remotely control ADV-185 was made at approximately 0200 HST.
This attempt
. was unsuccessful.
Valve control for ADV-185 was returned to
- manual, the handwheel reinstalled, and subsequently opened by operations personnel in the HSSS at approximately 0221 MST.
Additionally, one Hain Steam Safety Valve was cycling open and shut to control steam generator pressure.
(It was noted by Control Room personnel that the safety was lifting approximately 30 pounds per square (psi) inch below its setpoint of 1250 psi.)
Normal pressurizer (AB)(PZR) spray was unavailable since no RCP's were running.
This required the utilization of charging pumps to provide auxiliary pressurizer spray (CB).
Although RCP seal injection (CB) was still being supplied by the charging system (CB), Control Room personnel isolated RCP seal bleed-off (CB) in response to the loss of Nuclear Cooling Water System (CC)(as a
result of the loss of non-Class 1E power).
Bleed-off flow was reestablished after it was secured by Control Room personnel, Later, Control Room personnel secured charging to prevent pressurizer level from exceeding the maximum allowed by Technical Specifications, This allowed hot reactor coolant to circulate up through the RCP seals (SEL).
RCP 1B seal became degraded and began leaking prior to the restoration of seal injection.
At approximately 0139 HST on March 3,
- 1989, a Notification of Unusual Event (NUE) was declared pursuant to EPIP-02, "Emergency Classification,"
due to the loss of power to the in-plant non-Class 1E electrical busses and the Safety Injection System actuation.
At approximately 0149 MST on March 3, 1989 the appropriate state and local agencies were notified via the Notification and Alert Network (NAN).
The Nuclear Regulatory Commission (NRC) Operations Center was notified at approximately 0203 HST on March 3, 1989.
NRC FORM 368A (689)
UA. NUCLEAR REGULATORY COMMISSION LICENSEE EVENT REPORT (LERI TEXT CONTINUATION APPROVED OMB NO. 31500104 EXPIRES: 4/30/92 ESTIMATED BURDEN PER RFSPONSE TO COMPLY WTH 'THIS INFORMATION COLLECTION RFQUEST: 500 HRS. FORWARD COMMEN'TS REGARDING BURDEN ESTIMATE TO THE RECORDS AND REPORTS MANAGEMENTBRANCH (P 530), U.S. NUCLEAR REGULATORY COMMISSION, WASHINGTON, OC 20555, ANO TO THE PAPERWORK REDUCTION PRO/ECT (31500104).
OFFICE OF MANAGEMENTAND BUDGET,WASHINGTON,DC 20503.
FACILITYNAME (I)
DOCKET NUMBER (2)
LER NUMBER (8)
YEAR yMrEj SEQUENTIAL ON.
NVMSER REVISION NVMSER PAGE LS)
Palo Verde Unit 3 TEXT /I/more s/reee is rer)rrr)ed. Iree eddie'ooe/ S/RC Forrrr 3//64'4/ ( )2) 0 5
0 0
0 5
3 0
8 9
I 001 0
3 0
6oF 1
5 At approximately 0222 MST on March 3,
- 1989, a Steam Generator number 1-Hain Steam Isolation Valve (HSIV)(SB)(ISV) bypass valve (V) was manually opened after unsuccessfully attempting to open it remotely from the Control Room.
Subsequently, the two Atmospheric Steam Bypass Control Valves (SBCV's) were opened which provided an alternate steam flow path for decay heat removal.
At approximately 0224 MST, Control Room personnel verified that natural circulation conditions were established.
At approximately 0230
- HST, a Steam Generator number 2 MSIV bypass valve was also opened which allowed decay heat removal via both steam generators.
Following the establishment of decay heat removal via the SBCV's, both open ADV's were manually closed by approximately 0239 HST.
Plant recovery operations commenced.
Off-site electrical power was restored to one of the in-plant non-Class IE electrical busses (3E-NAN-S01) at approximately 0232 MST on March 3, 1989.
At approximately
The Hain Steam Isolation Signal was reset at approximately 0238 HST.
The Safety Injection Actuation Signal (SIAS) and Containment Isolation Actuation Signal were reset at approximately 0241 HST.
- Also, off-site power was restored to the other in-plant non-Class 1E electrical 'bus (3E-NAN-S02) at approximately 0243 HST restoring power availability to all in-plant non-Class 1E electrical loads.
At approximately 0300 HST on March 3,
- 1989, Control Room personnel observed an abnormal increase in the Containment Building Sump level.
A Shift Technical Advisor (STA)(utility, non-licensed) performed a calculation and determined that there was an approximate 6 gallon per minute in-leakage into the sump.
This was subsequently determined to be caused by the degraded RCP 1B seal and identified leakage from a charging line check valve (V).
As a result of restoring power to the in-plant non-Class IE electrical busses and resetting the SIAS, the Notification of Unusual Event was terminated at approximately 0252 HST on March 3, 1989.
RCP seal injection was restored at approximately 0341 MST.
At approximately 0424 HST, the non-essential auxiliary feedwater pump (P) was started in order to allow securing the essential auxiliary feedwater pump.
However, the Steam Generator number 1
downcomer isolation valve (V)(SGA-UV-172) could not be opened so the non-essential auxiliary feedwater pump was secured.
Auxiliary feed was maintained utilizing the essential auxiliary feedwater pump.
Forced circulation was re-established at approximately 0449 MST when one RCP was started.
A second RCP was started at approximately 0455 MST and the event was terminated as the normal operating procedure for shutdown//'cooldown from Mode 3
(HOT STANDBY) to Mode 5
(COLD SHUTDOWN) was entered.
NRC Form 368A (689)
NRC FORM 3SSA (549)
U.S. NUCLEAR REGULATORY COMMISSION LICENSEE EVENT REPORT ILER)
TEXT CONTINUATION APPROVED 0MB NO. 31500)OS EXPIRFS: S/30/92 ESTIMATED BURDEN PER
RESPONSE
TO COMPLY WTH THIS INFORMATION COLLECTION REOUESTJ 500 HRS. FORWARD COMMENTS REQARDINQ BURDEN ESl'IMATE TO THE RECORDS ANO REPORTS MANAGEMENTBRANCH IPS)30). U.S. NUCLEAR REGULATORY COMMISSION, WASHING'TON, OC 20555, ANO TO THE PAPERWORK REDUCTION PROJECT (31500)OS), OFFICE OF MANAGEMENTANO BUDGET,WASHINGTON.DC 20503.
FACILITYNAME (11 Palo Verde Unit 3 TEXT ///more s/rose/s rer/oaed, o>> edd/doos/HRC Form 355l's/(IT)
DOCKET NUMBER (2) 0 5
0 0
0 5
0 LER NUMBER (5)
)y.': aaava>>waL yg< AaveaN
.9 NUMSER NUMaarl PAGE (3)
OF 1
5 At approximately 0815 (MST) on March 3, 1989, Control Room personnel-discovered that Technical Specification Surveillance Requirement 4.5.2.g.
1 had not been performed in a timely manner.
Surveillance Requirement 4.5.2.g. 1 states, "Each ECCS [Emergency Core Cooling System (BP)(Bg)] subsystem shall be demonstrated OPERABLE'
..By verifying the correct position of each electrical and/or mechanical stop for [specified]
ECCS throttle valves...Within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> following completion of each valve stroking operation or maintenance on the valve when the ECCS subsystems are required to be OPERABLE."
The above requirement should have been performed by implementing 73ST-3SI01, RECCS Throttle Valve Testing 4.5.2.GR within four (4) hours of resetting the Safety Actuation Injection System and closing the throttle valves at approximately 0245 MST.
Following the discovery that 73ST-3SI01 had not been performed as
- required, Limiting Condition for Operation (LCO) 3.0.3 was entered as a late entry at approximately 0645 MST.
Surveillance Test Procedure 73ST-3SI01 was completed satisfactorily on the ECCS Train RAR throttle valves and LCO 3.0.3 was exited at approximately 0907 MST on March 3, 1989.
C.
Status of structures,
- systems, or components that were inoperable at the start of the event that contributed to the event:
There were no structures,
- systems, or components inoperable at the start of the event which contributed to the event.
D.
Cause of each component or system failure, if known:
The cause of the ADV,malfunction is described in LER 528/89-005.
The cause of the sub-synchronous oscillation (SSO) protective relaying has not been determined.
Investigation and analysis of simulated conditions at the time of the event indicate that the SSO relay should not have operated.
Functional tests performed on the SSO relay and bench tests of relay circuit boards at PVNGS indicated no apparent failures or malfunctions.
APS investigated possible sources of erroneous input signals to the SSO relay and could not determine the cause of the relay operation.
If I
information is developed which would lead to a determination of the
- cause, a supplement to this report will be submitted to describe the results of the investigation.
The cause of the Steam Bypass Control System (SBCS) malfunction described in Section I.B has been determined to be a failed auto permissive delay timer card (69) in the SBCS control circuitry.
NAC FORM 366A'689)
U.S. NUCLEAR REGULATORY COMMISSION LICENSEE EVENT REPORT ILERI TEXT CONTINUATION APPROVED OMB NO. 31500104 EXPIRES) 4/30/92 ESTIMATED BURDEN PEA AESPONSE TO COMPLY WTH THIS INFORMATION CO(.LECTION REOUEST: 50.0 HRS. FORWARD COMMENTS REGARDING BURDEN ESTIMATE TO THE RECORDS ANO REPORTS MANAGEMENTBRANCH (P 530). U.S. NUCLEAR REGULATORY COMMISSION, WASHINGTON, OC 20555, ANO TO THE PAPERWORK AEOUCTION PROJECT (31504104),
OFFICE OF MANAGEMENTAND BUDGET, WASHINGTON,OC 20503.
FACILITYNAME (I)
DOCKET NUMBER (2I LER NUMBER (6)
"'PAGE (3)
Palo Verde Unit 3 TEXT ///mdst SPJSP iS Sttidisd, IISP sddi5ons//YRC Fdsm 36//4's) ()2)
YEAR;gg 0
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OF The timer card failure was caused by a malfunctioning integrated circuit on the card.
With the exception of damper HFA-M06, the cause of the Safety Equipment Status System (SESS) indication that the valves and dampers described in Section I.B had not fully reached their actuated positions could not be determined.
Troubleshooting performed in accordance with an approved work authorization document on damper HFA-M06 determined that the damper operated properly;
- however, a position indicator limit switch (ZIS) was out of adjustment.
The limit switch was readjusted and satisfactorily tested.
Troubleshooting performed in accordance with approved work authorization documents determined that SESS and the other individual components listed in Section I.B operated properly.
No component failures to actuate were discovered.
The cause of the Main Steam Safety Valve (MSSV) lifting approximately 30 psi below its setpoint could not be determined.
The valve was removed and sent off-site for setpoint adjustment, rework and root cause analysis.
The valve was sent to Wyle Laboratories and a representative from the valve manufacturer (Dresser) was present, No cause for the valve lifting below its setpoint could be established by Dresser and Wyle.
Several hypotheses were provided concerning why the valve may have lifted early;
- however, none provide a supportable, definitive reason for the valve's operation.
It should be noted that 30 psi is within the valve manufacturer's specifications for setpoint tolerance.
The manufacturer's specification for the sepoint is +/- 3 percent.
Additionally, Dresser stated that field testing to a +/-
1 percent tolerance is not practical.
The cause of RCP seal bleed-off flow being re-established could not be determined.
Troubleshooting on CHA-UV-S07, "Seal Bleed-off Isolation Valve," determined that the valve performs as designed.
The cause of Steam Generator No.
1 Isolation Valve SGA-UV-172 not opening is indeterminate.
APS engineering performed an investigation in accordance with the APS Root Cause of Failure Program.
During subsequent troubleshooting and investigation, the valve operated properly.
No deficiencies or malfunctions were noted with any of the valve's components.
The cause of not being able to operate the Steam Generator Number 1
MSIV bypass valve remotely from the Control Room could not be
'etermined.
APS engineering performed an investigation of the valve's operation in accordance with the APS Root Cause of Failure Program.
During subsequent troubleshooting and investigation of(669)
U.S. NUCLEAR REGULATORY COMMISSION LICENSEE EVENT REPORT {LER)
TEXT CONTINUATION APPROV ED 0MB NO. 31500104 EXPIRES: 4/30/92 ESTIMATED BURDEN PER
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OFFICE OF MANAGEMENTANO BUDGET, WASHINGTON,OC 20503.
FACILITYNAME (II DOCKET NUMBER (2)
LER NUMBER (6)
PAGE IS)
Palo Verde Unit 3 TEXT/lfmoro 4poro /4 raaa/rorL aro or/rH/orM/HRCFarm 366ASI (12) o s
o o
o 530 YEAR TS 8
9 SCQVCNTIAL @()
NVM CR 001 REVISION NVMOCA 0
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9 OF 1
5 the valve's operation from the Control Room, the valve operated properly E.
Failure
- mode, mechanism, and effect of each failed component, if known:
The failed auto permissive delay timer card in the Steam Bypass Control System (SBCS) control circuitry resulted in several successive "quick open" and rapid closures of the SBCS valves.
The valve cycling resulted in periodic excessive steam demand which caused steam generator pressure to decrease.
The decreasing steam generator pressure resulted in the reactor trip, main turbine trip, and ESF actuations described in Section I.B.
The failure of the Atmospheric Dump Valves (ADV's) to operate properly from the Control Room or the Remote Shutdown Panel resulted in one Hain Steam Safety Valve lifting to control steam generator pressure and remove decay heat.
The failure mode and mechanism are described in LER 528/89-005.
The failed light bulb in the Hain Steam Support Structure Essential Lighting described in Section I.B resulted in inadequate lighting in the area of the Steam Generator number 2
ADV manual operators.
This contributed to operators turning the handwheel the wrong way and damaging AOV-179.
The failure of the Steam Generator number 1 downcomer valve to open
)
resulted in the inability to utilize the non-essential auxiliary feedwater pump to feed the steam generators for decay heat removal.
It should be noted that use of the non-essential feedwater pump is an elective measure and is not credited in the safety analysis for safe shutdown.
The failure of the Steam Generator number 1 HSIV bypass valve to open remotely from the Control Room resulted in the inability to utilize this flowpath for decay heat removal.
It should be noted that use of this flowpath is an elective measure and is not credited in the safety analysis for safe shutdown.
F.
For failures of components with multiple functions, list of systems or secondary functions that were also affected:
Not applicable
- - no component failures had multiple functions which affected other systems or components.
G.
for failures that rendered a train of a safety system inoperable, estimated time elapsed from the discovery of the failure until the train was returned to service:(669)
US. NUCI.EAA REGULATORY COMMISSION LICENSEE EVENT REPORT (LERI TEXT CONTINUATION APPROVED OMS NO. 3')600'I04 EXPIRES! 4/30/92 ESTIMATED SUADEN PER
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SEQUENTIAL NUMSER REVISION NVMSEA PAGE (3)
Palo Verde Unit 3 TEXTfllmoro Epo(O /4 OJJIIIOd. Pro oddr'O'OIMJHRC Forrrr 36643/(IT) 0 5
0 0
0 5 3 0 8 9 0 0 1
OF 1
5 2.
3.
The failure of the auto permissive delay timer card in the Steam Bypass Control System (SBCS) did not render a train of a safety system inoperable (the SBCS is not a safety system).
.The failed light bulb in the Hain Steam Support Structure Essential Lighting was discovered at approximately 0130 HST on March 3, 1989, during the event as discussed in Section I.B.
The light bulb was replaced on March 10, 1989.
Therefore, the Essential Lighting was out of service for approximately 7 days from the time of discovery until it was returned to service due to equipment in the area being quarantined.
The Atmospheric Dump Valves (ADV's) were discovered to be inoperable at approximately 0105 HST on March 3, 1989 as described in Section I.B.
The AOV's remained inoperable following this event as Unit 3 began a refueling outage.
Modifications to the ADV's have been completed.
The AOV's were restored to service following completion of the appropriate retesting (Reference LER 528/89-005).
H.
Method of discovery of each component or system failure or procedural error:
The Steam Bypass Control System auto permissive time delay timer card failure was discovered as a result of troubleshooting performed after the event.
2.
The Atmospheric Dump Valve malfunctions were discovered by Control Room personnel during the event as described in Section I.B.
3.
4.
5.
Evidence of the Reactor Coolant Pump seal degradation was observed by Control Room personnel during the event.
Subsequent investigation confirmed that RCP seal degradation was the cause of the Reactor Coolant System leakage.
The failed light bulb in the Hain Steam Support (MSSS)
Essential Lighting was discovered during the post-event investigation of the cause of inadequate lighting in the HSSS during the event.
The Steam Generator No.
1 Oowncomer Isolation Valve, SGA-UV-172, malfunction was discovered during the event as described in Section I.B.
6.
The Steam Generator number 1 HSIV bypass valve malfunction was discovered during the event as described in Section I.BE NAC Form 366A (669)
l
NRC FORM 3SSA (SJ>9)
U.S, NUCLEAR RFGULATORY COMMISSION LICENSEE EVENT REPORT ILER)
TEXT CONTINUATION APPROVED 0MB ND. 3>500104 EXPIRES: 4/30/92 ESTIMATED BURDEN PER
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TO COMPLY WTH THIS INFORMATION COLLECTION REOUEST: 500 HRS. FORWARD COMMENTS REGARDING BURDEN ESTIMATE TO THE RECORDS AND REPOR'TS MANAGEMENTBRANCH IPEl30>, U.S. NUCLEAR REGULATORY COMMISSION, WASHINGTON, DC 20555, ANDTO THE PAPERWORK REDUCTION PROJECT (31504)08>. OFFICE OF MANAGEMENTAND BUDGET WASHINGTON DC 20503r FACILITYNAME (II Palo Verde Unit 3 TE>(T/nm<<r Space/S~.
8 On<<~//RC Fo 3>JI/AB)(IT)
DOCKET NUMBER (2) 0 5
0 0
0 5
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Q LER NUMBER (Sl SEQUENTIAL..S+I) s~Y.
NUMSSR REVISION NUM888 PAGE (3)
OF ]
5 7.
8.
There were no procedural errors which contributed to the reactor trip or ESF actuations described in Section I.B;
- however, based upon the APS post-event investigation of the event several procedure enhancements were deemed appropriate.
The procedures for recovering from a Safety Injection System actuation did not provide guidance for performing the surveillance in a timely manner.
This procedural deficiency was discovered during a
Human Performance Evaluation System (HPES) performed as a result of this event.
I.
Cause of Event
The cause of the reactor trip and Engineered Safety Features actuations described in Section I.B was a malfunction of the Steam Bypass Control System (SBCS).
Further information concerning the cause of the SBCS malfunction is contained in Sections I.D. through I.H.
The cause of the condition prohibited by the plant's Technical
,Specifications wherein Control Room personnel (utility, licensed) did not perform Surveillance Requirement 4.5.2.g.
1 in a timely manner is a personnel error resulting from the complex sequence of
- events, the need for Control Room personnel to ensure that the plant was in a stable condition, and that the procedures for recovering from a Safety Injection System actuation did not specifically address the surveillance requirement (i.e.,
the recovery procedures did not provide guidance for performing the surveillance in a timely manner).
Other than discussed in Section I.B, there were no unusual characteristics of the work location (e.g.,
- heat, noise,
- smoke, poor lighting, etc.) which contributed to this event.
J.
Safety System
Response
The following automatic and manual safety system responses occurred during this event:
1.
Containment Isolation System (automatic)(JH).
2.
Low Pressure Safety Injection Trains RAR and RBR (automatic)(BP) 3.
High Pressure Safety Injection Trains "AR and RBR (automatic)(Bg) 4.
Hain Steam Isolation System (automatic) 5.
Emergency Diesel Generators Trains RA" and "BR (automatic)(DG)(EK) 6.
Essential Spray Pond System Trains RAR and RBR (automatic)(BS) 7.
Essential Chilled Water System Trains RAR and RBR (automatic)(KH)
NRC Fono 3SSA (SJ>9)
l
NRC FORM 35SA ISSS)
FACILITYNAME 11)
U.S. NUCLEAR REGULATORY COMMISSION LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION DOCKET NUMBER 12)
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OFFICE OF MANAGEMENTAND BUDGET. WASHINGTON,DC 20503.
LER NUMBER IS)
SEQVSNTIAL S>~. 4SVISION NUMBER TJH NVMBSN Palo Verde Unit 3 TEXT///moss sisssois ssouiNL oss WdiI/oos/NRC Foms 35SA'4/ II2) 0 5
0 0
0 5 3 0
8 9 001 0
8.
Essential Cooling Mater System Trains RAR and RBR (automatic)(BI) 9.
Condensate Transfer System Trains RAR and "BR (automatic)(KA)
- 10. Containment Spray Trains RAR and RBH (automatic)(BE)
- 11. Auxiliary Feedwater System Trains RAR and RBR (automatic and manual)(BA)
K.
Failed Component Information:
The malfunctioning Atmospheric Dump Valves were manufactured by Control Components Incorporated.
They are model number B3G9-10-12P8-31NAS1.
The failed auto permissive delay timer card in the Steam Bypass Control System is manufactured by Allen-Bradley Company.
The card model number is 1720-L410.
The failed light bulb in the Main Steam Support Structure was manufactured by (SR Industrial.
The light bulb model number is 500 watt permalux.
I I.
ASSESSMENT OF THE SAFETY CONSE(UENCES AND IMPLICATIONS OF THIS EVENT:
This assessment addresses the impact of the Unit 3 load reject/low steam generator pressure reactor trip event described above from the perspective of compliance with the design bases events presented in Chapters 6 and 15 of the PVNGS Final Safety Analysis Report (FSAR).
This event was first characterized as an "increase in heat removal by the secondary system" due to the Steam Bypass Control System (SBCS) valves cycling.
Later the event progressed to a "decrease in heat removal by the secondary system" type event caused by the Main Steam Isolation Signal (MSIS) with inoperable Atmospheric Dump Valves (ADV).
The design criteria of concern for an increase in heat removal by the secondary system event would be a violation of the Specified Acceptable Fuel Design Limits (SAFDL's).
These events
cause
a decrease in the temperature of the reactor coolant, an increase in reactor power due to the negative moderator temperature coefficient and a decrease in reactor coolant system and steam generator pressures.
A review of the transient data for the period during the transient demonstrated that no violation of the SAFDL's occurred.
Sufficient conservatisms were applied in the limiting design bases event to adequately bound the Unit 3 transient.
The most limiting conservatism is that the overcooling due to heat removal through the SBCS valves was less than the heat removal that is assumed in either the Main Steam Line Break design bases event or the Inadvertent Opening of a Steam Generator Safety Valve anticipated operational occurrence.
NRC FORM 358A (BSN U.S. NUCLEAR REGULATORY COMMISSION LICENSEE EVENT REPORT ILER)
TEXT CONTINUATION APPROVED 0MB NO, 31504104 EXPIRES: 4/30/52 ESTIMATED BURDEN PER
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TO COMPLY WTH THIS INFORMATION COLLEC('ION REQUEST.'00 HRS. FORWARD COMMENTS REGARDING BURDEN FSTIMATE TO THE RECORDS AND REPOATS MANAGEMENTBRANCH IPS301, U.S. NUCLEAR AEQUI.ATOAYCOMMISSION, WASHINGTON, DC 20555, AND TO THE PAPERWORK REDUCTION PROJECT 131500104I. OFFICE OF MANAGEMENTANO BUDGET, WASHINGTON,OC 20503, FACILITYNAME (1)
DOCKET NUMBER (2I LEA NUMBER (51 PAGE (31 Palo Verde Unit 3 TEXT ///mnP 4P>>44/4 mquiraL P44 afdiVonal ///IC FPnn 3FBA'4/ (IT(
YEAR
@g 530 89 SEQUENTIAL /<8 NUMPtn 001 AEVOION NUMBER OF For an event characterized by a decrease in heat removal by the secondary
- system, the design criterion of concern is a violation of the reactor coolant system (RCS) and steam generator design pressure limits.
The decrease in the heat removal event
causes
an increase in RCS temperature and pressure.
The Unit 3 heat-up event described in Section I.B was initiated after the reactor tripped on low steam generator pressure with a concurrent HSIS.
The transient data indicates that main steam flow stopped for a brief period of time during which primary pressure increased (as expected).
Review of this pressure spike confirmed that Unit 3 did not experience a heat-up event greater than those previously analyzed and documented in the FSAR.
The maximum RCS pressure remained well below the design limit.
Overall, the response of the Unit was complicated due to the malfunctioning of the SBCS and the AOV's.
The effects of these malfunctions did not cause the Unit to experience initial conditions or consequences any more adverse than those previously analyzed in the PVNGS FSAR.
The SBCS and Reactor Power Cutback System (RPCS) are not safety grade systems and are therefore not credited in Safety Analyses.
- Thus, the steam relief that the SBCS provided in combination with the reduced reactor power due to the proper functioning of the
- RPCS, only served to move the unit further away (i.e. in a more conservative direction) from the initial conditions assumed in the Safety Analyses.
The PVNGS Safety Analysis assumes operation of the ADV's for long term heat removal and cooldown and the AOV's are not credited in Chapter 15 events until 30 minutes after the initiating event.
For long term cooling, only one ADV per steam generator is assumed available for the duration of the event in the safety analysis.
The Unit 3 Operations personnel were able to open one ADV per steam generator.
Had the operators not been able to open the ADV's, the Hain Steam Safety Valves (HSSV) would have prevented overpressurization of the steam generators and increased heat-up of the RCS.
(Note:
One of the twenty (20)
HSSV's actuated to prevent overpressurization during the Unit 3 event described in this LER.)
During an analyzed transient, the HSSV's are assumed to operate and provide secondary heat removal.
Reactor decay heat is removed through the cycling of the HSSV's.
The HSSV's will continue to cycle in this manner keeping the RCS in a hot standby condition.
The fact that the HSSV first lift setpoint was lower than expected was in the conservative direction.
Also the safety grade steam turbine driven auxiliary feedwater pump which was started aided in the heat removal process.
If Control Room personnel had not initiated feed to the steam generators, the auxiliary feedwater actuation signal (AA)(JE) would have occurred and initiated feed to the steam generators.
Both essential auxiliary feedwater trains were operable and fully available.
N AC Form 355A (BSBI
NRC FORM 368A (64)9)
U.S. NUCLEAR REGULA'TORY COMMISSION LICENSEE EVENT REPORT ILER)
TEXT CONTINUATION APPROVED OMB NO. 31500104 EXPIRES: 4/30/92 ESTIMATED BURDEN PER
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OFFICE OF MANAGEMENTAND BUDGET, WASHINGTON,OC 20503.
FACILITYNAMEl(l DOCKET NUMBER (21 LER NUMBER (6)
SEQUENTIAL NUMSER r RP REVISION 4??r: NUMSER PAGE (3)
Palo Verde Unit 3 TEXT/I/more opere
/4 required. uee eddro'one///RC /rorm 3MA'4/I'l) 0 s
0 0
0 5
3 0 8 9 0 0 1 0 3
14oF 1 5 Oue to the relief of secondary side steam to the atmosphere, there is a
potential for-releasing radioactive material to the environment.
For the event described in Section I.B, the most probable source would have been a primary to secondary steam generator tube leak.
All analyses that evaluate for off-site dose criteria assume as initial conditions one percent fuel failure and a minimum Technical Specification primary to secondary leak of 1 gallon per minute (gpm).
Prior to the Unit 3 event there was no identified leakage greater than 1
gpm and present chemistry data estimates only 1-2 failed fuel pins.
- Also, an analysis of data obtained during the event determined that no releases in excess of Technical Specification limits occurred.
Therefore, the off-site dose consequences of the Unit 3 event are bounded by analyzed events documented in the PVNGS FSAR.
In summary no violations of the fuel design limit, primary pressure boundary limit, and 10CFR100 off-site dose limit criteria were exceeded.
Therefore, there were no safety consequences or implications resulting from the event described above.
I I I.
CORRECTIVE ACTIONS
A.
Immediate:
Immediate corrective actions
taken by Operations personnel to stabilize the plant are described in Section I.B.
B.
Action to Prevent Recurrence:
As described in Section I.O and I.I, the cause of the reactor trip and ESF actuations was a malfunction in the Steam Bypass Control System (SBCS).
As corrective action, the malfunctioning component has been replaced.
Additionally, an engineering evaluation of the SBCS was conducted.
APS engineering concluded that, although the SBCS in use at PVNGS is somewhat unique in the industry, it is performing as designed and the design utilized is consistent with the overall design objectives of the plant.
The results of the engineering evaluation were provided with APS's response to the PVNGS March 1989 Augmented Inspection Team Report dated Hay 18, 1989 (Reference:
102-01285-WFC/TOS/SCT/RAB dated May 29, 1989) and describe additional corrective measures which are being implemented in accordance with pre-established schedules.
As described in Section I. I, the cause of the condition prohibited by Technical Specifications wherein a Surveillance Requirement was not performed in a timely manner was a personnel error.
As corrective action, the appropriate procedures for recovering from a Safety Injection System actuation have been revised to provide guidance for performing the surveillance in a timely manner.
NRC Form 368A (669)
0 C
NRC FORM 355A (54)0)
US. NUCLEAR REGULATORY COMMISSION LICENSEE EVENT REPORT ILERI TEXT CONTINUATION'PPROVEO OMB NO. 3)504))04 EXPIRES: 4/30/02 ESTIMATED BURDEN PER
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OFFICE OF MANAGEMENTAND BUDGET, WASHINGTON. OC 20503.
FACILITYNAME II)
DOCKET NUMBER (2)
LER NUMBER (5) me) SEOVSNTIAL
@Ye( REVISION NVM 54 s'2 NVMSSR PAGE (3)
Palo Verde Unit 3 TEXT ///mare space /4 seeewaf, use etio'ons/J/RC Focm 3////A'4/ ()7) 0 5
0 0
0 5 3 0 8 9
0 0 1 0 3
1 5 oF 1
5 An independent investigation of this event was conducted in accordance with the PVNGS Incident Investigation Program.
The results of this investigation were provided with APS's response to the PVNGS March 1989 Augmented Inspection Team Report dated May 18, 1989 (Reference:
102-01285-WFC/TDS/SCT/RAB dated Hay 29, 1989).
The investigation describes the corrective actions for the concerns which arose as a result of the event.
The corrective actions a'e being implemented in accordance with pre-established schedules.
Due to concerns about Emergency and Essential Lighting System operation, an engineering evaluation of the Emergency and Essential Lighting System was performed.
The results of this evaluation were provided with APS's response to. the PVNGS March 1989 Augmented Inspection Team Report dated Hay 18, 1989 (Reference:
102-01285-WFC/TDS/SCT/RAB dated May 29, 1989).
Based upon the results of this investigation, enhancements and corrective actions were developed and are being implemented in accordance with pre-established schedules.
Additionally APS discovered that the Emergency Lighting System did not meet the design bases in the PVNGS Updated Final Safety Analysis Report (UFSAR) and was reported in LER 528/89-012.
Further corrective actions are described in LER 528/89-012.
As a result of the ADV malfunctions described in Section I.B, engineering evaluations of the Compressed Gas System and ADV's were performed.
The results of these investigations were provided with APS's response to the PVNGS March 1989 Augmented Inspection Team Report dated May 18, 1989 (Reference:
102-01285-WFC/TDS/SCT/RAB dated Hay 29, 1989).
Based upon the results of these evaluations,
corrective actions
were developed and are being implemented in accordance with pre-established schedules'dditionally during the investigation of the ADV problems, APS became aware of a defect reportable pursuant to 10CFR21 which was reported in LER 528/89-005.
Further corrective actions are described in LER 528/89-005.
IV.
PREVIOUS SIMILAR EVENTS
V, There have been previous reactor trip events reported pursuant to 10CFR50.73 contributed to or caused by malfunctions occurring in the Steam Bypass Control System;
- however, none of the previously reported events involved a failure of the auto permissive delay timer card.
ADDITIONAL INFORMATION
There has been one accumulated actuation cycle of the Emergency Core Cooling System to date.
This report satisfies the requirements of Technical Specification 3.5.2 ACTION b.
NRC Form 355A (04)9)