ML20024G449
| ML20024G449 | |
| Person / Time | |
|---|---|
| Site: | Monticello  |
| Issue date: | 07/20/1972 |
| From: | Mayer L NORTHERN STATES POWER CO. |
| To: | Anthony Giambusso US ATOMIC ENERGY COMMISSION (AEC) |
| References | |
| NUDOCS 9102120488 | |
| Download: ML20024G449 (8) | |
Text
s D@litory N
N 5TATES POWER COMPANY 4
N N s A p o t.i s. M I N N E S OTA 35400 l
July 20, 1972 4,,,
% My1976 e
wh~4 0L 6
Mr A alambusso Deputy Director for Reactor Projects Directorate of Licensing United States Atomic Energy Commission Washington, D. C.
20545 raear Mr Gicmbusso:
MONTICELLO NUCLEAR GENERATING PLANT Docket No. 50-263 License No. DPR-22 Turbine Trip at 100% Power and Subsequent Events A condition occurred at the Monticello Nuclear Generating Plant recently which we are reportin6 in accordance with provisions of 6.6.B.3 of Appendix A, Tech-nical Specifications of the Provisional Operating License DPR-22.
The Region III Regulatory Operations Office has been notified of the occurrence.
At 1549 hours0.0179 days <br />0.43 hours <br />0.00256 weeks <br />5.893945e-4 months <br /> on July lo,1972, the geaerator loss of field relay tripped initiat-ing a turbine lockout and, subsequently, a reactor scram fmm 100% power.
Initial Conditions
~
Prior to the trip the reactor was operating at 10@ power vith the following conditions existing:
1.
Nitrogen was being added to the dryvell and torus with the Standby Gas Treatment System in operation and lined up to take suction on the 2 inch vent bypass lines.
2.
'Ihe High Pressure Coolant Injection (HPCI) System was out of service vi th the monthly high steam flow isolation surveillance tes t in pmgress.
Prior to removing the HPCI System from Service the Core Spray, low Pressure Coolant Injection, and Reactor Core Isolation Coolant System were demonstrated operable.
3 Routine Traversing Incore Probe (TIP) traces were being taken.
Sequence of Events the following events took place during and subsequent to the trip as determined by interviews with the operators on duty, computer monitoring of plant parameters, control room indication, recorders and annunciators.
9102120400 720720 goo gDR ADOCK 05000263 PDR j
NOI HERN OTATES POWER C iPANY Ms A Giambusso July 20,1972 1.
Generator loss of field relay tripped causing the turbine lockout relay to t ri p a t t ime ze ro.
2.
Turbine lockout relay tripped the generator field breaker, both recire-ulation pump motor-generator set supply breskers, and initiated an auto-matic closed transfer of station auxiliary pcwer from 11 auxiliary trans-former to 1R transformer. Also, the turbine master hydraulic trip solenoid
- 3 was actuated thereby initiating closing the s team inlet valves and tripping the control valve fast closure pressure switches. Both diesel generators were started by the power transfer relays.
3 A reactor scram was received at 0.151 seconds by control valve fast closure as determined from the computer sequence of events loc.
Control rod drive 22-31 stopped at notch '02' and was manually inserted to the full in position, af ter the scram.
4.
Primary containment isolatlon Group I valve closure was initiated shortly af ter the scram. All MSIV's reached the 90% open position within 1.170 seconds af ter the turbine lockout relay trip as determined from the sequence of events log.
~
5 All high reactor pressure scram relays tripped within 1.210 seconds af ter the turbine lockout relay trip.
6.
The low reactor water level scram relays tripped within 1.837 seconds af ter the turbine lockout relay trip.
This initiated the following:
a.
Drywell vent, purge and isolation valve Group II closure b.
Isolation valve Group III closure Start standby gas treatment system c.
d.
Isolate 02 analyzer c.
TIP withdrawal f.
Reactor building sentilation isolation TIP #1 did not full retract and isolate.
Reactor water level stabilized above the low-low level trip point and was returned to near normal.
7 As reactor pressure continued to increase at least 3 of the relief valves and one of the safety valves lif ted.
Kulmum reactor pressure was 1141 psig.
8.
Between 8.035 seconds and 8 538 seconds af ter the turbine lockout relay trip, channels D and C of the primary containment isolation and reactor protection system tripped on high drywell pressure.
The plant evacuation siren was ini tiated.
Separate containment pressure switches initiated the Daergency Core Cooling System, starting the Iow Pressure Coolant Injection and Core Spray pumps.
HPCI System was initiated but did not start since the HPCI steam line isol-ation valves were closed for surveillance testing.
The LPCI loop selection logic selected recirculation loop B for injection and shut its suction and discharge valves.
The autcentic blowdown system high drywell pressure relay sealed in.
NO HERN GTATE@ POWER C APANY Mr A G.lambtisco July 20, 1972 A 0.85 psi drywell pressure increase was recorded.
9 Both channels noted in (8) above, reset within 12 754 seconds af ter the j
turbine lockout relt.y trip.
he time interval each channel was tripped is given below:
I t
Channel Interval Actuated 5
D 5.619 seconda C
3 954 seconds 2he evacuation ciren automatically reset.
10.
The high reactor pressure scram relays reset after approximately 12 seconds in the tripped condition.
11.
The control room operators observed that reactor pressure continued to decrease, and ' A' relief valve was not fully closed.
The relief valve control switch was manually operated and the valvo closed. Minimwu reactor pressure was approximately 600 psi.
12.
Af ter observing that a non ECCS condition existed, the ECCS pumps were stopped about 5 minutes after the turbine lockout relay tripped.
13 After obcerving a Group I non isolation condition existed, the MSIV's were opened about 8 minutes af ter the turbine lockout relay trip.
- 14. I-lant conditions were stabilized following scram recovery procedures.
Analysis and Corrective Action I
After plant conditions were stabilized it was decided to place the plant in a cold shutdown condition, de-inert the drywell, and make a thorou6h investigation into all events associated with the shutdown.
The following information was determined and corrective action initiated:
Generator Excitation It was found that a poorly solderet transistor in the voltage error si nal 6
amplifier of the generator amplidyue control circuit caused the loss of generator I.
field.
The amplifier was repaired and returned to service. Testin6 conducted prior to and during the generator startup verified proper amplidyne operation.
Failure of Control Rod Drive at Location 22-31 to Fully Insert During the scram control rod drive at location 22-31 was automatical3y scranced from notch 'h8' (full out) to notch ' 2' (6" from full in).
The control room operator af ter observing the '02' notch indication, manually inserted the drive to the '00' notch position (full in).
This event is similar to that observed during the May 23, 1972 scrum, and reported to you in a letter dated June 19, 1972.
i
NOl HERN STATES POWER C iPANY Mr A Giambasso h-July 20,1972 The scram time data as detennined from the scram timing recorder fo r control rod drive 22-31 verified that the Tbehnical Specification scram insertion time for the 10%, 50%, and 90% insertion was satisfied.
Prior to plant restart the drive vas exercised.
Normal operation was verified by withdrawing and inserting the contml rod drive using nonnal drive water pres sure.
Main Steam Isolation Valve Closure A Group I isolation valve closure was automatically initiated during the turbine trip and scram.
The Group I valves consist of the main steam line isolation valves, the main steam line drain isolation valves and the recirc loop sample isolation valves.
A review of the sequence of events log determined that the main steam line isolation valves we<e less than 90% open approximately one second af ter the turbine lockout was received. There was no indication in the sequence of events log or computer alarm record that any of the five isolation signals actuated. A review of plant charts indicated that none of the isolation trip levels should have been reached.
Interviews with the control room operators did not disclose that any of the isolation parameters had actually tripped. A test was condbeted to verify that the computer alarm points were operable by shorting the alarm contacts at the isolation relays. All points tested satisfactorily.
To insure that the Group Iisolation logic system operates properly, surveillance tests were performed to test each of the five iso 3ation parameters.
The tests verified proper instrument cetpoints, relay operation, annunciator operation and computer printout.
In the Group I isolation logic, trip signals are generated by contacts which open when the trip relay is de-energized, whereas inputs to the compter program are derived from closing back-contacts of these relays.
Therefore it is possible, under a rapid trip-and-rese t, to initiate the isolation without obtaining an event-sequence record of the initiating parameter. A review of startup test records con-firmed that similar action had occurred during the 75% IcVer trip test.
Present conclusions are that a rapid trip-and-reset did occur, most probably from post-trip disturbance of main steam line high flow switches.
Computer inputs from these relays are being revised to actuate from front contacts, to improve identification of the initiating parameter.
TIP Machine #1 Failure to Retract and Isolate During the Group II isolation TIP machine #1 did not withdraw into the shield chamber and isolate. This was a result of two failureu associated with the instrumen tation of machine #1. A position programmer card ano a limit switch, both of which sense the TIP probe position, fhiled to provide the proper logic to allow automatic TIP vithdrawal at the time of the isolation.
No
'HERN STATES POWER C APANY
.I
'Mr A Giambbcco July 20, 1972
%e position programmer card was replaced and the limit switch adjusted. Pmper l
TIP withdrawal and isolatjon was verified.
Relief Valves Based on the recorded response of the thermocouples located in the relief valve discharge piping and the peak reactor pressure of 1141 psig, it appeared that i
j the "D" relief valve did not open properly. Also, as previously noted, the "A" relief valve did not resent properly.
The thermocouple data is given below:
f Relier Valve hmperature Rise ('F)
A 135 l
B 105 C
92 D
2 All relief valves were inspected in place. A manufacturer's representative was on site to assist in the relief valve inspection.
he results of the inspection t.re discussed below:
'A' Relief Valve he main stem and piston were found to move freely with no sign of binding.
l Le second stage piston and stem were inspected and found in good condition.
Le pilot disc was found free with no signs of galling.
Rast particles were found in the second stage piston chamber.
It is probable that rust had lodged across the orifice and prevented dissipation of pressure from the piston chamver when the pilot was closed. The activation of the air operator (manual opening from the control room switch) could have dislodged the rust particle.
Eere were no signs of second stage stem leakage, that is, no scars on the seat or disk, no corrosion and no wire drawing was evident.
The second stage discharge line was inspected and found to be clear.
%e set pressure was checked and found to be correct.
'B' and 'C' Relier Valves The second stage piston chambers were examined for rust. Both were clean.
The set pressures were checked and found to be correct.
' D' Valves The main stem and piston were found to move freely with no sign of binding.
he second stage piston and stem were found in good condition.
he pilot dice was free with nocigns of galling.
%e pilot filter was clean. No signs of bellows or pilot gasket leakage were evident.
The set pressure could not be determined prior to valve disassembly due to excessive leakage of a nitrogen test fitting. No reason for the apparent valve malfunction was found.
l
NOR 4ERN STATES POWER CC PANY
~
Rt A Clun.buhco July 20, 1972 All of the thermocouplec in the valve discharge pipec were checked and proper recponse wac verified. Following reaccembly all valvec were tested with ni trogen and correc t pressure ce ttings were verified.
Prior to plant startup, pressure switches were installed in each of the relief valve discharge lines and wired to plant process computer cequence of events log.
'lhis will provide a confirming cignal of relier valve actuation and will indicate the exact time of actuation.
During the plant restart all relier valves were operated at approximately 150 poig and again at 1000 psig reactor precoure.
All valves operated properly.
The valves will be tested again within approximately one month.
Safety Valve Momentary Actuation After the ceram and isolntion, recorded drywell preocure increased frcm 14 7 to 15 55 psia.
Thermocouplec located in the discharge noczle of the safety valvec indicated a 120* F rice for ' A' valve and a 30' F rise for 'D' valve.
A drywell inspection revealed no damage. Both ' A' and ' D' safety valvec were set to relieve at 1210 poig.
A aimilar cafety valve actuation event occurrea on February 26, 1972 as reported to you in a letter dated June 2,1972. Ibring the outage of June 3,1972 carety valve ' A' vac replaced wi th a factory tested opare.
Additional monitoring of cafety valve actuation is being installed. A rupture link was placed on each of the four safety valve discharge nozzles prior to plant startup. When the viring is completed to the plant process computer the time of safety valve lifting vill be recorded on the cequence of events log.
In addition to the invectigation program undertaken by General Electric on this matter, ceparate effort by NSP includes:
1.
A technical consultant has been retained to develop an analytical model of the s team lines to provide pressure trancient information in responce to turbine-trip events and valve interaction influences. A preliminary report is expected Auguct 15 and final report by late September.
2.
The cafety valve which lif ted February 26, 1972 has been removed and returned to the manufacturer for a specific test program. These tecta are now in progress and should be completed before August 1,1972.
3 We have retained technical assistance to design a field test to measure trancient preocures in response to turbine trip or isolation along the length of a steam line.
The intent of such test is to corroborate conclusionc of the analytical study.
Dryvell Preocure Instrumentation During the ceram and isolation the maximum dryvell preccure increase, as noted l
by the recorder in the control room was 0.85 poi; however, the 2 poi dryvell i
high pressure switchec were actuated. The sequence of evente log from the i
procesc computer indicated that only two channels of dryvell high precoure instru-mentation were ac tuated.
7hece channels are connected to the drywell penetration
1 NOR 4ERN OTATED POWER CC.PANY Mr A Giambu'sso July 20,1972 X-29
'Ibe untripped channels (A and B) are connecte.1 to drywell penetration X-$0.
The control room recorder is connected to the same penetration that supplice the A channel.
An inspection of the drywell revealed duct tape covering both drywell pressure tapa on the X-D penetration.
Examination of the inpc covering the pressure taps i
showed small holea in the tape which allowed response to slow pressure changes but apparently acted to damp response to rapid changes.
The drywell pressure recorder is used during normal operation to determine the need for venting the drywell and monitoring pressure during inerting and venting operations. No unusual recorder response had been noticed during past operations.
Ihring the February 26, 1972 scram and subsequent momentary lif ting of the ' A' safety valve, the recorder did indicate an increase in drywell pressure. No ECCS initiation occurred at that time.
The tape was removed from both lines.
Testing of all four ECCS and RPS sensing lines, and all other dryvell and torus pressure sensing and sampling lines was conducted to verify that the lines were not plugged or restricted. All sensing lines in the dryvell were visually inspected to assure no obstructions existed.
All pressure switches which initiate action on high drywell pressuro were checked and found to be in calibration.
Dryvell Ventinc Prior to the Group II isolation, nitrogen was being added to the drywell and torus, vith the 2 inch vent lines open and exhausting through the Standby Gas Treatment Sys tem. When the isolation was reset the vent and purge valves opened since the control switches had been lef t in the "open" position.
They remained open for about one minute before they were manually closed.
'Ihe estimated activity release during the time the valves were open af ter the isolation was reset was insignificant.
All release rates were within the Technical Specification limits.
Recirculation Pump Discharge Valve Problem When #11 recirculation pump was restarted, the discharge valve would not open.
Following drywell entry the valve was manually opened.
The valve was stroked electrically and a limit switch was found out of adjustment which allowed the valve to seat with excessive force.
Subsequent valve operations resulted in the valve sticking at approximately 5" from the fully closed position.
The valve stem threads were found damaged in this e.rea.
'Ihe threads were repaired and subsequent operation of the valve was satisfactory.
Yours very truly, h.
L 0 Mayer, P.E.
Director Nuclear Support Services LOM/ma ec: B H Grier
AEC DIsrRIBUr10N FOR PART 50 DOCKET MATERIAL (ThMIVRARY FORM)
CONTROL NO: 4040 FROM: Northern States Power Co.
DATE OF DOC:
DATE REC'D LTR MEMO RPf CTHER Minneapolis, Minn.
55401 L.O. Mayer 7-20-72 7-24-72 X
'IO :
[
Mr. A. Giambusso 1 signed 39 SENT LOCAL PDR V
h' ROP INFO CLASS:
INFUI NO CYS REC'D DOCKET NO:
40 50-263 DESCRIPIION: Ltr rpt a problem on 7-10-72 ENCLOSURES:
when the generator loss of field relay tripped initiatin;; a turbine lockout 6 subsequently a reac tor scram fm 100% power.......
PLANT NAMES:
Monticello Plant L-" ?
~
,An DJ AM F 1" FOR ACTION /INFORMATION
'""'~ '"~
BUTLER (L)
KNIEL(L)
VASSALLO(L)
VI,IEMANN(L )
KNIGEf0N(ENVIR W/ Copies W/ Copies W/ Copies W/ 9 Copies W/ Copies CIJJ1K(L)
SCHWENCER(L)
H. DENTON CHTIVOOD(FM)
W/ Copies V/ Copies W/ Copies W/ Copies W/ Copies GOLLER(L)
STOLZ(L)
SCHEMEL(L)
DICKER (ENVIRO)
W/ Copies W/ Copies W/ Copies W/ Copics W/ Copies IkmtNAL DISPRIBUTION m
SEREG FILP O V5fELLO-L OLLMER-L KARAS-L L/A FWR M4. STEELE C FDR d400RE-L DENTON-L %
MASON-L L/A BWR H R. RENDRIE OPER (2) $ LANGE-L GRIMES-L BROWN-L L/A PWR C-RM P-506 WLICKI-L GAMMILL.L WILSON-L L/A PWR 4UEf3ING & STAFF,,
10MPSON-L KNJGHTON-ENVIRO KARI-L L/A BWR pIAMBUSS0-L ESCO-L DICKER-ENVIRO S41TH-L L/A BWR VBOYD-L-BWR ONG-L PROJ LDR ENVIRO:
GEARIN-L L/A BWR DEYOUNG-L-IVR
/d\\INAS-L DIGGS-L L/A y LLER-L-ENVIRO SHAO-L SALT &A N-IND.
TEETS-L L/A F'KOVHOLT-L-OFER J NAROYA-L MCDONALD-PLANS WADE-L L/A ENVIRO fH-L FMORRIS-RO NUSSPAUMER-FM BRATD4AN-A/T
%CCARY-L DUBE-L S4ILEY-FM RARLESS-ENVIRO 3CHROEDER-L
/E. CASE-L P. COLLINS-L C. MILES Y1-LOCALPDR Minneapolis, Minn.
1-SAN /LA/NY--FDR
-ITTIE-(LAUGHLIN) 9-NATIONAL LAB'S 1-CHIEF WATER REACTORS yl-NSIC-(BUCHANAN)
ANL/ORNL/B.YdL 1-RD....E. HALL F-309 GT 1-ASLB-YORE /SARYE l-R. CARROLL-0C, GT e
WOO 7dARD/H. 87.
1-R. CATLIN, A-170, QT j 1-C. MILES-C-459, GT l-CONSULTARI'S y16 CYS ACRS-HOLDING NEWMARK/ELUME/AGBABIAN 1-DR. LEVINE BROOKBAVEN NATIONAL LAB l
I
_