ML20133P851
| ML20133P851 | |
| Person / Time | |
|---|---|
| Site: | Rancho Seco |
| Issue date: | 10/25/1985 |
| From: | Reinaldo Rodriguez SACRAMENTO MUNICIPAL UTILITY DISTRICT |
| To: | Thompson H Office of Nuclear Reactor Regulation |
| References | |
| RJR-85-531, TAC-59691, NUDOCS 8511010230 | |
| Download: ML20133P851 (53) | |
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(lSMUD SACRAMENTO MUNiclPAL UTILITY DISTRICT O 6201 S Street. P.O. Box 15830, Sacramento, CA 95813; (916) 452-3211 RJR 85-531 AN ELECTRIC SYSTEM SERVING THE HEART OF CALIFORNIA October 25, 1985 blRECTOR OF NUCLEAR REACTOR REGULATION ATIN HUGH L THOMPSON JR DIVISION OF LICENSING U S NUCLEAR REGULATORY COMMISSION WASHINGTON DC 20555 DOCKET NO. 50-312 LICENSE NO. DPR-54
SUMMARY
AND SUPPLEMENTAL INFORMATION FROM TRANSIENT OF OCTOBER 2, 1985
References:
R. J. Rodriguez to H. L. Thompson 10/14/85 (RJR 85-514)
R. J. Rodriguez to H. L. Thompson 10/18/85 (RJR 85-520)
During an NRC/SMUD meeting on October 23, 1985 concerning the Rancho Seco Auxiliary feedwater system (AFW), the District assented to supply the NRC with additional and sumraary information on the October 2,1985 transient, and a description of the District's actions concerning plans to upgrade the AFW system.
The references described certain items the District is pursuing and will continue to pursue as a result of its systematic program to resolve concerns from the October 2, 1985 t ansient. The items in the District's plan include both pre and post startup actions to determine root cause of the October 2, 1985 event, and to ins +1tute corrective programs to significantly reduce the likelihood of similar reoccurrences.
On October 25, 1985, the District in a teleconference call with various NRC
, staff, including Region V, NRR and I&E, agreed to submit information on 11 items of interest. These items are attachments to this letter.
1 8511010230 851025 PDR S
ADOCK 05000312 PDR A
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RJR 85-531 Hugh L. Thompson October 25, 1985 The following briefly describes the 11 items the District is submitting:
(1) Main Feedwater Pumo Trips - Analysis and Findings Af ter an intensive investigation, the District has determined the probable cause of the MFP trips. The District used not only key District personnel, but also the resources of INPO, Arkansas Power and Light and vendor representatives. The team concluded:
. The A-MFP trip was caused by a defective High Discharge Pressure Switch.
. The most probable cause of the B-MFP trip was an operator manual trip.
. The MPFs, their controls and operator training, are adequate to support power operation.
. The addition of trip monitoring circuitry to the NFPs will significantly enhance future efforts to investigate MFP trips.
(2) HPI "A" Flow Anomaly:
As a result of analysis, testing and surveillance, the District has traced the HPI "A" flow anomaly to a characteristic of the Rosemount transmitters used to provide HPI flow indication.
As part of the investigation, the District confirmed through special functional flow testing that flow was always available as designed in the HPI "A" line. Radiography, in conjunction with the functional tests of the HPI "A" control valve, verified that the source of the anomaly was instrumentation and not mechanical.
(3) Heat Balance for Cooldown of 10/2/85 Transient The District performed a quasi steady state energy balance that showed good agreement between RCS heat removal and the observed cooldown. The analysis used heat removed from the OTSG's, based on AFW flow, OTSG level and assumed steam loads.
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l RJR 85-531 Hugh L. Thompson October 25, 1985 (4) Evaluation of the Reactor Vessel Cooldown The RCS cooldown caused by the transient of October 2, 1984 was within the analytical limits meeting the requirements of 10 CFR 50 Appendix G. ,
(5) Auxiliary feedwater Control Loaic Modification The District is modifying, prior to startup, the AFW valve control logic. The initiation of ICS controlled AFW valves will be off of Main feedwater Pump discharge pressure. This is the same parameter that initiates the start of AFW pumps. This change has been made to ensure AFW flow into the steam generators should the need arise. We have not identified any failure that would cause both a loss of main feedwater and prevent AFW from being available to cool the steam generators. This applies to the specific concern of a failure closing all four main feedwater valves and preventing the ability to supply AFW.
(6) Auxiliary Feedwater Pump Surveillance Testina The District has scheduled the Rancho Seco Auxiliary feedwater Pump Surveillance from a quarterly to a monthly test period. During testing, an operator is stationed at and observes the test valve. Additionally, the District will submit a Technical Specification Change Request within 60 days to reflect this increased testing frequency.
(7) Review of Operatina Procedures The District has reviewed the Emergency Operating Procedures (EOP) in light of the October 2, 1985 event. The review has determined that the E0P's are appropriate and correct. The District will incorporate, prior to startup, an enhancement to the excessive heat transfer procedure (main steam line break, overfeed). Feedwater pumps will be tripped to terminate overcooling should closure of FW valves fail to terminate excessive FW regardless of OTSG 1evel.
(8) 011 Levels on Safety Related Pumps The District is upgrading the training of operators to assure oil levels in all safety related rotating equipment is properly maintained. The program includes:
- Review of training practices relating to oiling.
- Upgrading oiling instructions for consistency.
- Confirming proper slinger ring configuration. '
- Insta11aticn of new oilers where appropriate.
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RJR 85-531 Hugh L. Thomps:3 Octcb2r 25, 1985 (9) NSCW Pumo Surveillance Failure The District has evaluated the Nuclear Service Cooling Water system. The attachment provides a description of the system balancing performed to optimize a nominal system flow rate.
(10) Housekeepina and General Surveillance in Safety Related Areas The District is conducting a housekeeping review in safety related areas. Management has directed that walkdowns be used to observe evidence of oil leaks, covers in place, fasteners properly engaged, etc.
The District will use these walkdowns to document and evaluate any findings to confirm that operability is not degraded.
(11) Valve Configuration Walkdown The Rancho Seco Operations Department has conducted walkdowns of selected systems to verify valve configurations. This walkdown includes assuring that valves required in the procedures are tagged and identified. The P&ID's were compared for correctness and any discrepancies were dispositioned by a non conformance report. Other than the valve on the MSR that initiated this effort, the walkdown team found only one nonconforming valve, associated with a steam trap, that could affect system function.
The District is also including the latest revision of the Action 1.ist that identifies the resolution program. As noted in the status column, almost all the items the District identified to close prior to criticality are indeed complete. The remaining startup required tasks will be closed prior to power escalation. Also, as discussed in the October 14 letter, the District will submit its status of the ideritified short range items as well as the schedule for completion of the long term tasks by November 18, 1985.
At the conclusion of the October 23 meeting, the District agreed to describe its actions to further enhance the reliability of the Rancho Seco feed Water systems. The District will:
. Perform a reliability study of the Rancho Seco AFW system. The District and other utilities with similar AFW configurations, will meet with NRC staff to agree on the methodology and schedule. The District anticipates this initial meeting will occur within the next several weeks. The projected completion of the reliability study has a tentative date of mid-1986.
. Scrutinize priorities, using its Living Schedule program, in an attempt to accelerate the implementation of Emergency feedwater Initiation and Control (EFIC). This is a full safety grade initiation and control AFW system. Although scheduled in two phases with final implementation by Cycle 9 startup, the District believes it can complete a majority of the EFIC modifications during the next refueling outage. To accomplish this, the District will adjust the Living Schedule by deferring items that do not significantly affect the safety or reliability of the plant.
RJR 85-531 Hugh L. Thompson October 25, 1985
. As discussed during the October 23 meeting, the District has committed to the development of a preventative and predictive maintenance program for the secondary side of the plant. The District has also embarked on a
" root cause" program that will investigate significant failures of the MfW and AFW systems. These investigations will result in corrective actions to reduce challenges to the AFW system.
. Other areas along the above lines that the District is pursuing include:
- Instrumenting the MFP's to determine the root cause of trips.
- Participating in the B&W Owner's Group MfP reliability program.
- Tuning the ICS to allow it to run more efficiently.
- Engineering studies to determine possible enhancements to the main feed pump control system.
The District believes the information being provided as attachments to this letter completes our response to all requests for information related to the concerns over the October 2, 1985 Reactor Trip at Rancho Seco. The Confirmatory Action Letter of October 4, 1985, requested a briefing of our assessment of the root cause and justification as to why the Rancho Seco facility is ready to resume power operation. We have held numerous telephone conversations with Region V, NRR, and I&E; have participated in several inspections on site; have met with NRC' staff on October 10,11 and 16,1985 at Rancho Seco, and on October 23 in 8ethesda, M0; and have submitted correspondence dated October 14 and October 18, 1985, plus.this letter. We are satisfied all commitments have been met and that Rancho Seco is ready to resume power operations.
R. J. RODR UEZ -
ASSISTANTG(ENERALMA GER, NUCLEAR Attachments
ATTACHMENT 1 Main Feedwater Pump Trips - Analysis and Findings s
- 1. Introduction -
On October 2,1985, the day of- the event, a program of detailed investigation into the causes of both Main Feedwater Pumps (MFPs) tripping was initiated. This effort took advantage of,the following sources of information:
. Memory T. rip. Review, computer data showing alarms and logs of selected parameters,
. Operator logs and reports.
. Operator interviews, -
. As found calibrations of trip devices,
.- Plant design and. configuration data,
. Relevant operating procedu'res;
- Equipment Supplier Field Engineers,
. Nuclear Utility Industry Consultants,
. Plant maintenance history,
. Plant history and reliability data Due to the complex nature of the event, which at one time or another, included the combined effects of a " Loss of Condenser Vacuum," " Loss of Main Feedwater," and " Rapid Cooldown" events, it was necessary to proceed in a number of simultaneous invest *gations so as to gain a full understanding of the, expected behavior of the MFPs, and determine the cause of their tripping. This effort was necessary, and made quite complex, as a result of only one of the potential tripping parameters having been provided with a " seal in" indication requiring a conscious act to reset. That one was the " Turbine Thrust Bearing" trip with the other trips self resetting. The following report summarizes the activities of.the investigating team and presents their findings.
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Main Feedwater Pump Trips - Analysis and Findings (Continued)
- 2. MFP Trips, Interlocks, and Alarms The following are automatic MFP Turbine trips which operate through the MFP control scheme:
..tpoint Pump High Discharge Pressure, Instantaneous 1650 10 psig Pump Discharge Pressure, Time Delay 1575 5 psig for 5 sec ,
Thrust Bearing Wear, Normal 0.040 0.001 inches Thrust Bearing Wear, Reverse 0.007 0.001 inches Low Lube Oil Pressure 10.5 0.5 psig Manual (Remote, or Local) Pushbutton Contact The following. trips are mechanically operated at the MFP turbine:
Overspeed 5800 20/-100 RPM Mechanical Lever All trips function by dumping AUT0STOP OIL pressure to the reservoir, '
depriving the stop valves of pressure necessary to hold them open, and the governor-valves of the CONTROL OIL pressure necessary to position the gov'ernor valves.
There are no condenser vacuum, vibration, or low pump suction pressure trips. Low pump suction pressure does auto start an additional condensate pump. Low autostop oil pressure gives the " Tripped" indication, closes the MFP turbine stop valves, and initiates a reactor anticipatory trip signal. ARTS trip blocked at <20% power. Any of the MFP control scheme trips also sends a permissive signal to the ICS allowing automatic control of the auxiliary feedwater control valves.
Vibration, bearing temperatures, and a number of autostop oil, lube oil.
. system, and control system parameters are alarmed either in the Control Room, or on the computer.
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w Main Feedwater Pump Trips - Analysis and Findings (Continued) ;
- 3. Scenarios Considered in MFP Trip Investigation A summary of the major scenarios considered as possibly creating the trip condition follows. It was always considered a "given" that both MFPs did in fact " trip," and that the trip condition was real. This was due to the observation that upon trip of the second MFP, i.e B-MFP, the ICS controlled auxiliary feedwater valves immediately began delivering AFW to the OTSGs. The only way this signal can be generated is for a trip signal to each MFP's AUT0STOP OIL DUMP solenoid to exist and be " latched" by the in-parallel holding coil, thus both MFPs were " tripped."
- a. MFW Pressure Spikes to > 1575 psig
- 2. Water hammer in secondary plant feedwater piping.
- b. Autostop, Control, Bearing 011 System Pressure Transients
- 1. Rapid demand changes in Governor Valve position.
- 2. Setpoint overlap and correctness.
- 3. " Trip Signal" to Stop Valves without trip of Autostop 011.
- 4. A-MFP Trip Investigation A review of each of -the trip parameters follows:
- a. Pump / Turbine Over;p?ed Trip Prior to the A-MFP tripping, it had been in manual control maintaining approximately 3450 rpm. Six minutes prior to the A-MFP trip, the generator DCBs were opened followed by the loss-of-vacuum event. Within two minutes, vacuum had dropped to approximately 20 inches'Hg and the Turbine Bypass Valves locked out, steam header pressure control transferred to the Atmospheric Dump Valves. Steam header pressure immediately began rising to the correspondingly 4
higher controlling setpoint which resulted in an increase in A-NFP speed of approximately 400 rpm. This suggests that the steam supply to the A-MFP was at that time coming through nearly full open LP l
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Main Feedwater Pump Trips - Analysis and Findings "iiSth ?
- 4. a. (Continued)
Governor Valves from the Auxiliary Steam System. Coincident with the shift from bypass to atmospheric valve control of header. pressure, the 4A Feedwater Heater shell reliefs had opened releasing approximately 280,000 lbm/hr to atmosphere at a pressure of approximately 150 psig. The source of this steam was primarily from Main " Pegging" steam, while the auxiliary steam load was carrying the balance of plant steam loads. Since the LP Governor valves were nearly full open, any change in auxiliary steam pressure would result in a corresponding change in steam available to the A-MFP LP Steam chest. Approximately two and one half minutes after the Bypass / Atmospheric valve transfer, the LP Governor valves were full open and condenser vacuum had further degraded to approximately 15 inches Hg. This resulted in a rapid coastdown of the A-MFP Turbine, as it was still under load. A-MFP delivery of feedwater to the OTSGs had dropped to zero by the time the A-MFP Turbine tripped at 01:32:01. At the time the A-MFP Turbine tripped, its speed had decayed to approximately 2500 rpm.
Review of the MFP control scheme also shows that the overspeed trip of the MFP does not initiate a trip of the autostop oil trip solenoid, thus the signal to the ICS permitting automatic control of the Auxiliary Feedwater Control Valves is not operated.
For the above reasons, it is concluded that the A-MFP did not trip on overspeed.
- b. Instantaneous Pump Discharge Pressure > 1650 psig At the time of the A-MFP trip, the feedpump was delivering water at a pressure less than that necessary to inject water into the OTSGs.
OTSG Steam Header pressure was approximately 925 psig at this time.
During the preceding minutes, in which there had been sizeable feedwater flow oscillations, the feedwater control valves had seen differential pressure of as much as 300 psi. If an allowance for OTSG and piping losses of 75 psi is added the maximum possible feedwater header pressure would not have exceeded 1300 psig, well below the 1650 10 psig trip setpoint. With the pump speed down to approximately 2500 rpm, it is not possible for the pump to generate pressure of this magnitude. Alternative events were considered, specifically, water hammer caused by rapid closure of the FW control valves, or block valves, cavitation or flashing at the pump suction, and instrument failures.
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. Main Feedwater Pump Trips - Analysis and Findings (Continued) i
- 4. b. 1. Rapid Closure of FW Control or Block Valves At reactor power of approximately 15%, the ICS will transition from the Main to Startup FW Control Valves, and close the Main Block Valve. For the three minutes prior to the A-MFP failing to develop flow into the OTSGs, a relatively smooth increase in FW flow was observed. This suggests that the main to startup transition had already occurred and that there were no significant oscillations occurring, certainly none which could be categorized as " water hammer" due to control valve transients; secondly, as a result of the low MFP discharge
- pressure at the time of the trip, the MFPs were " isolated" from the control valves by the discharge check valves. Since this pressure switch is located on the open cross-tic between the A and B MFPs, downstream of the MFP Check Valves, and the B-MFP did not experience a coincident trip, pressure spikes could not have caused the trip.
- 2. Cavitation or steam flashing events likewise could have caused pressure spikes, but for the reasons above, these did not trip the MFPs.
. Independently, the A-MFP suction temperature was observed to
-increase from a value of approximately about 205'F fif teen minutes before the A-MFP trip to a steady 360*F at the time of the trip. At this temperature, 160 psia is required to maintain subcooled satuiated water, also, about 40 psia is required to assure NPSH requirements for the pump. The system is provided with an autostart of a condensate pump at a low MFP suction pressure of 230 psig. Neither of the standby condensate pumps autostarted, hence, it is concluded that adequate suction pressure existed to preclude flashing or steam binding as a source of pressure spikes. Furthermore, operators and engineers present in the turbine building and MFP vicinity, did not observe water hammer or unusual noises other than those expected for the existing conditions.
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- 3. Instrumentation Following the event, several calibration checks were performed i on the A-MFP high dishcarge pressure (instantaneous) pressure switch and all were within specification. Later, in the process of installation of trip parameter contact monitoring devices, it was noted that the pressure switch which developed this signal was in a " tripped" condition. At the time, the
Main Feedwater Pump Trips - Analysis and Findings (Continued) '
- 4. , b. 3. (Continued)
A-MFP was on clearance for control system troubleshooting.
Investigating the cause of the intermittent switch condition determined that corrosion was present at the terminals of the pressure switch assembly. This could have provided a path for the 125 vdc power to bypass the actual bourdon tube actuated microswitch. The initial failure was random although the combined vibrations from nearby relief valve operations i probably accounted for the A-MFP trip on an " apparent" instantaneous high discharge pressure.
- c. Time Delayed High Discharge MFP Pressure All of the factor: and events imparting the likelihood of the instantaneous high discharge pressure are appropriate to this trip parameter. They are located adjacent to each other and sense the same source of pressure. This switch was found to have similar corrosion, although.there is no' indication that a trip signal was generated by this device. This parameter was not considered to be a source of the trip.
- d. Low Lube Oil Pressure Several hours following the A-HFP trip, it was noticed that both the lead and backup AC Lube Oil Pumps were operating. A single pump is normally sufficient to provide the autostop, control, and bearing lube oil requirements. Queries to the operators determined that the second pump was not manually initiated. Since the low lube oil pressure trip of the A-MFP is associated, a detailed investigation was pursued to determine if this was a likely source of the actual A-MFP ~ trip. By comparing these actuations to the diverse alarms or actuations which actually occurred, it is possible to determine whether or not this was the source of the trip. Note that a check of the setpoints of these devices found them to be in specification.
-The backup lube oil pump starts on autostop oil pressure decreasing to 160 2.5 psig. Efforts to simulate rapid governor valve motion did create oil pressure fluctuations which were sufficient to autostart the backup oil pump. This condition has been observed in other facilities with similar arrangements. .Given the complexity of events preceding the A-MFP trip, it is likely that the backup pump did autostart as a result of rapid governor valve motion and not as a result of.the failure of the lead pump.
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~ Main Feedwater Pump Trips - Analysis and Findings (Continued)
- 4. d. (Continued)
The DC Lube Oil Pump was not found to be inservice. It autostarts at 10.5 psig and insures that the turbine bearings are not damaged due to insufficient lubrication. There is an alarm on the Lube Oil System at 15 psig. It was not received. It is concluded that there was no failure of the AC Lube Oil Pumps.
The operators observed the A-MFP " Trip" light illuminate at their Control Room panel. .This was recorded by the computer alarm monitor as was the coincident event of'all four ARTS. trip switches signaling their respective Reactor Protection System channels.
The A-MFP Low Lube Oil Trip occurs at 10.5 0.'5 psig. The alarm on Low Lube Oil Pressure was not observed by the computer, nor was the DC Lube Oil Pump autostarted. From this, it is concluded that there were pressure fluctuations in the autostop oil system sufficient to autostart the backup AC Lube Oil Pump, but that the A-MFP trip occurred prior to any Low Lube Oil Alarm, or condition,
- which would autostart the CC Lube Oil Pump. The A-MFP did not trip on Low Lube Oil Pressure,
- e. ' Thrust Bearing Wear, Normal or Reverse Direction The degrading vacuum condition on the A-MFP turbine exhaust would cause a shift in thrust as seen at the thrust bearing, compounded by the changes in steam flow, and supply pressures, and the balancing thrust generated by the main feedwater pump itself.
Thrust bearing trips are the only. trips which have a " seal-in" feature requiring operator action prior to allowing the MFPs to be reset. No such operator action was required in this event. While this precluded a thrust bearing trip, an investigation was carried out to determine the thrust bearing condition and the viability of the " seal-in" feature. Disassembly of the thrust bearing housing sufficient to allow inspection and thrust bearing " trip" verification was done. Operation was as expected, although the as found settings of the trip probes were found to require adjustment.
This did not change the observation that a valid trip had not, nor should not have occurred, nor that if one had, it would " seal-in."
Thrust bearing wear did not cause the A-MFP to trip during the event.
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Main Feedwater Pump Trips - Analysis and Findings (Continued)
- 4. f. . Manual Trip The A-MFP Autostop 011 System can be electrically tripped from the Control Room or from the local control panel. It can also be tripped by manually actuating the overspeed trip device on the NFP Turbine. Interviews with both licensed and non-licensed operators and observers confirms that the A-MFP was not manually tripped.
- g. A-MFP Seal Water 4
Several minutes prior to the A-MFP trip, an operator called the Control Room and reported that the A-MFP was blowing " steam" from its bearing glands. The Control Room Operator immediately began increasing B-MFP speed in preparation for placing the B-MFP inservice and tripping the A-MFP. This was not completed prior to the actual A-MFP trip; thus, when the trip came, the B-MFP was still at_ idle speed. Prompt action by maintenance personnel repaired the seal water regulator control linkage which had lost a pivot pin.
This incident complicated the overall event, but did not damage _the pump or impact the outcome.
- 5. B-MFP Trip Investigation A review of each of the trip parameters follows:
- a. Pump / Turbine Overspeed Trip
- Seven minutes prior to the Main Generator being taken off-line,
- adjustments were made in attempt to increase the B-MFP turbine i speed. These adjustments were not effective in increasing the unit's speed, which continued at a nominal 2450 rpm, and seemed to be matched to parallel changes in the steady state speed of the
'A-MFP. It is likely that these changes in speed are the result of changes in the auxiliary steam supply pressure which was being driven by concurrent changes in the main ~ steam header. pressure. At the time of the A-MFP trip, the B-MFP speed began to decrease below its idle speed. Attempts by the operator to increase its speed had not produced observable results, although the LP governor valve was caused'to drive full open by the speed demand. B-MFP tripped approximately 30 seconds after the A-MFP. Both pumps show a fairly extended coastdown to turning gear speed which is attributed to leakage past the stop valves.
There was insufficient energy available to the B-MFP to accelerate it above its idle speed at the time of its trip. The B-MFP did not trip on overspeed.
Main Feedwater Pump Trips - Analysis and' Findings (Continued)
- 5. b. Instantaneous Pump Discharge Pressure > 1650 psig The discussion in 4.b above, applicable to the A-MFP, is directly applicable to the B-MFP with the exception that no problems have been found in its pressure switches. In adddition, since the pump was at only idle speed, it could not have generated overspeed conditions commensurate .with a high discharge pressure trip.
- c. Time Delayed High Discharge MFP Pressure As discussed above, this trip could not be generated by the pump.
Only instrumentation problems, which were not observed, could cause this parameter to trip. Based upon this analysis, the B-MFP did not trip as a result of this parameter.
- d. Low Lube Oil Pressure Only one lube oil pump was inservice and neither the AC or DC backup-pumps were found on. Likewise, there were no pressure alarms 4 received prior to the trip. The instruments were found to be properly calibrated.
The investigations into the autostop, control, and lube oil systems' done on the A-MFP are applicable to the B-MFP and support that the B-MFP did not. trip on low lube oil pressure during the event on October 2.
- e. Thrust Bearing Wear, Normal or Reverse Direction The B-MFP turbine exhaust steam discharges into the same condenser vacuum as does the A-MFP turbine. If the significant degradation of vacuum (increase in backpressure) caused the trip, then it would be expected to have caused the trips on both units. Although the trips occurred only 30 seconds apart, the fact that a detailed inspection of the A-MFP Thrust Bearing, and its associated trip device, did not suggest the generation of a thrust bearing wear trip can likewise be excluded from having occurred on the B-MFP. In addition, the operators did not reset any thrust bearing trips in their efforts to reset the B-MFP following its trip on October 2. Finally, the running speed and degraded steam supply at the time of the trip were .
such as to preclude significant thrust loads of the nature which would be necessary to cause a thrust bearing wear trip.
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Main Feedwater Pump Trips - Analysis and Findings (Continued)-
- 5. f. Manual Trip Several minutes prior to the MFP trips, the operators had faced several episodes of main feedwater oscillations, followed by a call from a. plant operator that the A-MFP was blowing steam from its gland seals. The operators were attempting to bring the speed of the B-MFP up to the point where it could supply feedwater to the OTSGs in preparation to tripping the A-MFP. Several relief valves in the secondary plant were noisily blowing, the main generator had been manually tripped, and condenser vacuum was rapidly decreasing.
At this point, the A-MFP tripped and the operator noted that both Auxiliary Feedwater Pumps had autostarted (on Main Feedwater Header Pressure < 850 psig) and that OTSG levels were rapidly falling in
- . response to the large steam loads then existing (the main turbine had not tripped on low-vacuum) and the reactor was still at a nominal 15% FP. The B-MFP was not responding to operator inputs to increase its speed and a Reactor / Turbine trip then occurred.
Operator training in ICS operation tells them that upon tripping of both MFPs, or all four Reactor Coolant Pumps, the ICS controlled auxiliary feedwater control valves will operate to maintain OTSG level. With an immediate need to provide feedwater to the OTSGs, with the knowledge that both Auxiliary Feedwater Pumps are operating, and prior training that tripping both MFPs will' provide auxiliary feedwater to the OTSGs, the operator probably tripped the B-MFP manually from the Control Room.
Post trip discussions with the operators did not get a definitive
"...I tripped the B-MFP..." response. Rather it was "...I may have tripped the B-MFP..." Subsequently, the operator said that, "...I probably tripped the B-MFP..."
This lack of clear memory is not considered to be inappropriate. At the point when the B-MFP tripped, there was a lot happening in the plant with the immediate need being to get feedwater into the OTSGs. It is in such situations that the benefit of training is most important, and immediate action to trip the recalcitrant B-MFP and obtain the needed feedwater from an available, and diverse, auxiliary feedwater system is entirely appropriate. In fact, a similar situation is a part of the operator training syllabus on the plant simulator. Manually tripping the B-MFP was not a " memorable" action, it was a trained response- to the conditions the operator faced.
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Main Feedwater Pump Trips - Analysis and Findings (Continued)
- 6. ,
Auxiliary-Steam Supply Each of the MFP Turbines are provided with two sources of driving steam, identified as to the steam chest they supply, the LP (Low Pressure) and HP (High Pressure) steam chests.
LP steam is the perferred source. It is used during startups and'for operation up to the' normal full load, as each MFP is rated for about
" half capacity" of plant demand. Should only a single MFP be available, it can supply feedwater demands up to at least 80% full power by the addition of steam from the HP chest. HP steam is taken directly from the main steam lines at a nominal 885 psig and admitted through the HP governor to the MFP. As HP steam is high valued economically, generating '
- considerable revenue when expanded in the main turbine, the HP~ chest is not intended for use during normal operation.
LP steam comes from the auxiliary steam header during startups, shutdowns, and during periods of lower power operation. When the main turbine / generator is on-line, hot reheat steam is drawn from the moisture separator reheaters and routed to the MFP Turbine LP steam chest. A
-pressure regulator reduces the demand for auxiliary steam as the hot reheat steam pressure increases with main turbine load. At about 40%
full power, hot reheat steam is entirely sufficient to provide the demands of the MFPs and the use of auxiliary steam is curtailed. Upon power reductions, the auxiliary steam regulator will open to maintain the supply to the LP chests between 150 to 250 psig as set by the operator.
During the October 2 event, the HP steam chest's steam supplies were manually isolated. This condition has existed since plant heatup the week before as a method for minimizing leakage through the HP stop valves and thereby enabling the plant to sustain a " Hot Shutdown" condition. As described above, the HP steam would not have been needed until the plant was to be escalated above 50% FP.
The supply of auxiliary steam was coming from one of the main steam headers via a pressure reducing and desuperheating station. Normal auxiliary steam header pressure is 250 psig. Although no actual data is available on auxiliary steam pressure up to the time of the MFP trips, there were no low pressure alarms so it can be assumed that adequate steam was available, at least up to the controller to the MFPs.
From this review it is apparent that the MFP LP Governor Valves were properly responding by stroking full open just prior to the MFP trips, and that the MFP Turbines were not able to develop accelerating torque in the existing conditions.
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Main Feedwater Pump. Trips - Analysis and Findings (Continued)
- 7. Effect of Resetting a MFP Turbine Trip Following the MFP trips, the operators attempted to reset the trip. The efforts were unsuccessful until about twenty minutes later when the 8-MFP was reset and immediately, the auxiliary feedwater valves closed.
Investigation into these two conditions showed that both were appropriate and could have been anticipated.
The MFPs will not reset unless both of the governor steam stop valves are closed, and there is no "deinand" signal to the governor which would c&use it to be open when steam is again supplied. After several attempts to
" reset," the operator drove the speed " demand" to zero and the reset was subsequently effective. The demand signal was that which had existed at the time the NFP had tripped.
A successful " reset" removes from the ICS the indication that the MFPs are tripped, thus returning the auxiliary feedwater control valves to "zero" or closed. This requires the operator to take the valves in
" manual," which was done, and appropriate feedwater flow continued.
Prior to plant restart, the AFW control logic will be modified to initiate ICS control ~of AFW valves on the same parameter as that which initiates AFW pumps, low MFP discharge pressure.
- 8. ICS Performance Several of the occurrences during the transient initially suggested that the Integrated Control System (ICS) may have been a source of the problems observed. Those modules which were suspect were checked and found to be properly calibrated and serviceable. Analysis shows that, as a system, the ICS performed as expected, including its interface with the MFPs through the Lovejoy controllers. Likewise, the investigation into the operation of the Lovejoy controls verified that they operated correctly.
A recommendation coming from this investigation is that during power escalation, a program to " tune" the ICS/MFPs be implemented to validate the interface and improve operator confidence in automatic control of the MFPs.
- 9. Conclusions
- a. The A-MFP trip was caused by a defective High Discharge Pressure Switch. Switch actuation coincident with the event was probably the result of vibrations due to the transients in progress.
Main Feedwater Pump Trips - Analysis and Findings (Continued)
- 9. . Conclusions
- b. The most probable cause of the B-MFP trip was an operator manual trip so as to obtain auxiliary feedwater flow to the OTSSs during a period when the secondary plant was in a complex upset condition.
- c. The MFPs, their' controls and operator training, are adequate to support power operation.
- d. The addition of trip monitoring circuitry to the NFPs will significantly enhance future efforts to investigate MFP trips.
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ATTACIMENT 2 HPI "A" FLOW ANOMALY As prescribed by plant operating procedures for pressurizer level decreasing below 100 inches, the operator started the High Pressure Injec-tion (HPI) pump (P-238 B) lined up to the borated water storage tank and opened loop "A" HPI valve. The loop "A" nozzle is also the path for normal additions necessary to maintain pressurizer level. Although the above actions increased flow to the reactor coolant system (RCS), the pressurizer level continued to decrease. The operator opened the remain-ing three loop HPI valves, allowing HPI flow through all four paths to the RCS. At this point, he observed "zero" flow on the "A" HPI flow indicator. To further augment the HPI supply, he started the third HPI pump and the loop "A" HPI flow increased to about 80 gpm. Subsequent analysis of plant computer data verified this phenomenon and showed a recovery of flow indication-in about 30 seconds, coincident with start of the third HPI pump.
.The District has performed an' exhaustive investigation consisting of system flow testing, non-destructive examination and formal analysis.
This investigation led us to the root cause; a shift in the zero point of the flow transmitter. This shift occurs as the device is calibrated with the system depressurized and then brought to system operating pressure.
In the case of these transmitters, this shift can result in no flow indi-cation with as much as 75 gpm of actual flow. Note that, although this problem creates imprecise indication to the operator, it did not affect the ability of the HPI system to perform its safety function. Hydraulic calculation showed that, for the period of "zero" flow indication, the expected loop "A" HPI flow would be nearly identical to the measured zero shift.
Review of literature and discussions with the manufacturer of the transmitter has shown that this shift is not an equipment failure but inherent with the device. We are currently evaluating the implication of this finding with regard to this application and all other safety related applications of this transmitter at Rancho Seco.
Both the initial flow indication problem and the generic implications of our findings will be resolved, including an acceptance by the Plant Review Committee prior to plant restart. A followup report will be sub-mitted to the NRC.
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ATTACl#ENT 3 HEAT BALANCE FOR C00LDOWN OF 10/2/85 TRANSIENT Subsequent to the Reactor Trip, the temperature decrease of.the Nuclear Steam Supply System (NSSS) was greater than~ normal.
When steam flow through the main turbine decreases to the point that insufficient extraction steam flow is available to maintain feedwater inlet temperatures to the steam generators, the pegging .
steam control valves are automatically enabled. The pegging steam lines direct steam from the main steam line to the two second point feedwater heaters and the two fourth point heaters.
The primary cause of the rapid cooldown was steam exhausting from two pressure relief valves on one of the fourth point feedwater heaters. The setpoints of the relief valves and the heating steam supply regulator to the feedwater heater overlap. This overlap of the inlet steam setpoint and the relief valve setpoint, resulted in an open pathway between the main steam header and the atmosphere.
This pathway allowed approximately 285,000 lbm/hr of steam to escape
.from the main steam header and thus remove heat from the NSSS.
The plant operators entered the Emergency Operating Procedure for overcooling and identified and isolated the pegging steam line, ending the transient.
L The normal post trip steam loads are the pegging steam, the condenser air ejectors, the main feedwater pumps and the gland or sealing steam for the turbine seals. In addition to the normal plant steam loads, several other abnormal steam or heat loads were associated with this reactor trip.
The estimated steam loads are listed below:
Main Air Ejectors 1,560 lbm/hr Hogging Air Ejectors 13,800'1bm/hr Gland Steam Condenser 9,600 lbm/hr Auxiliary Feedpump Turbine 32,500 lbm/hr Pegging Steam Condensation 109,000 lbm/hr Pegging Steam Relief Valve 285,000 lbm/hr NOTE: Actual-average pegging steam load was limited to 360,000 lbm/hr by the maximum flow capacity of the pressure control valve on the 4A feedwater heater which is less than the relief valve capacity and condensation rate at main steam pressures less than 852 psig.
The overall steam load on the NSSS after the trip was calculated to be about 417,000 lbm/hr, of which 86% was the pegging steam load.
Without the relief valves opening on the 4A heater, there would not have been a rapid cooldown.
An engineering evaluation verified that the estimated steam loads were consistent with'the Auxiliary Feedwater flow rate and the Steam Generator level following the transient. This engineering evaluation also considered the depressurization of the secondary steam system.
This depressurization from 945 psig.to 622 psig in seven minutes would indicate a loss of approximately 83,250 lbm/hr from the secondary steam system over the calculated steam generation rate of 300,000 lbm/hr. -This system has a total volume of approximately 12,500 Ft3 ,
The engineering evaluation also verified that the observed steaming rate ~was consistent with the heat removed from the primary system.
The calculated heat removal rate from the primary system was based on cooling down the RCS, excluding the pressurizer, from 553.4 F to 501.1*F in seven minutes. The principal results of this calculation were:
Average Decay Heat 58 MBtu/hr Pump Heat Input 82 MBtu/hr Net Heat From Coolant 141 MBtu/hr Net Heat From Metal 103 MBtu/hr TOTAL 384 MBtu/hr Average Heat Removed by Letdown 3 MBtu/hr Heat Transfer to OTSGs 381 MBtu/hr li d
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ATTACHMENT 4 EVALUATION OF THE REACTOR VESSEL C00LDOWN Following;the transient of October 2, 1935, the effect of the rapid cooldown on the Rancho Seco NSSS integrity was analyzed. The Babcock and Wilcox (B&W)-Company, manufacturers of the Rancho Seco NSSS, were contracted to perform the engineering evaluation. Their investigation showed that the structural integrity of the pressure boundary components has not been-impaired and that they are suitable for continued power operation. The B&W letter, dated October 4, 1985, is attached to document this analysis.
The transient has also been compared to the transient of March 20, 1978.
A graphical presentation of RCS temperature data for the two transients is also attached. The results of detailed engineering analyses of this event were submitted to the Commission in LER 78-1.
Post trip reactor coolant temperatures continued to drop from a normal post trip value of =550 F to 490 F in about 20 minutes. This cooldown did result in exceeding the 100 F per hour cooldown rate associated with Figure 3.1.2-2 of the Technical Specification for Rancho Seco. The temperature did not deviate from the acceptable operation region of the figure for any pressure. This ensures that the requirements of 10CFR50, Appendix G, are met.
It must be understood that immediately following the transient, the Wide Range Cold Leg Temperature recorder was used for some of the analyses. This temperature recorder has since been found to be in error and recalibrated. The computer compiled data has been determined to be more accurate.
The District, having reviewed the B&W evaluation, has concluded that there is no concern with system integrity.
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' f pv .m Babcock & Wilcox noci , re-- os.i.a a McDermott company 3315 Old Foren Road P.O. Box 10935 Lynchburg, VA 24506-0935 (804) 385 2000 October 4, 1985 SMUD-85-222 Mr. R.J. Rodriquez Executive Director, Nuclear Sacramento Municipal Utility District 6201 S Street Sacramento, CA 95813-Attention: Mr. George Coward Manager, Nuclear Operations
Subject:
Evaluation of 10/2/85 Rancho Seco Transient for Return to Power Operation
Reference:
- 1) Rancho Seco Nuclear Generating Station, Unit 1 B&W Master Services Contract Dated January 1, 1984 SMUD Contract 9759 - B&W Contract 582-7165 Task 552 - Evaluation of October 2, 1985 Transient at Rancho Seco
- 2) B{iW Letter: Burke to Rodriguez, " Initial Evaluation of 10/2/85 Rancho Seco Transient",
SMUD-85-217, October 3, 1985
Enclosure:
Dear Mr. Rodriguez:
B&W has performed an evaluation of the Reactor Coolant System (RCS) components .for ,the transient which occurred at Rancho Seco Nuclear Generating Station on October 2, 1985. This evaluation -
was performed in two parts: (1) a brittle fracture / thermal shock evaluation of the reactor vessel . (RV) beltline region and (2) an ASME Code,Section III evaluation of the primary system components. The brittle fracture / thermal shock evaluation was based on analyses previously performed for another utility. The primary system component evaluation was based on analyses performed for the rapid cooldown transient at Rancho Seco on March 20, 1978. Based on these evaluations, B&W has concluded i
that the structural integrity of the pressure boundary components has not been impaired and that they are suitable for continued power operation.
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On October 3, 1985, we discussed with Mr. George Coward the need to perform additional fracture mechanics and fatigue analyses to more quantitatively assess the potential impact of the October 2, 1985 transient. We planned to have this quantitative evalua-tion completed by October 18, 1985, and Mr. Coward authorized B&W to proceed with this work. After our initial fatigue evaluation based on the March 20, 1978 transient,'we no longer feel the quantitative fatigue evaluation is necessary especially if future work is contemplated to relax the operating envelop.
1 However, since the RCS pressure did not drop in the October 2, 1985, transient as it did in March 20, 1978, we feel the fracture mechanics evaluations to specifically address the October 2, 1985 transient should still be performed. Unless you direct us otherwise, we are proceeding on that basis.
If you have any questions or need additional support from B&W, please call me at (804) 385-2308 in Lynchburg.
Very truly yours,
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F.R.. Burke Manager of Contract Engineering A Nuclear Engineering Services FRB/rlb cc: L.R. Keilman J.V. McColligan Steve Redeker -
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ATTACHMENT 5 Part I: Auxiliary Feedwater Control Logic Modification I. Purpose of Design Change A. Initiate ICS control of AFW valve on same parameter as that which initiates AFW pumps, low MFWP discharge pressure.
B. Reduce probability of loss of AFW during re-establishment of MFW.
II. Summary of Change A. Scope The work to be performed is entirely in the ICS cabinets. This change will modify relay logic for initiation of AFW auto flow '
control and MFW block valves. No other systems are affected.
Wiring will be removed from contacts of 86-1/AFWPT and 86-1/BFWPT and added to spare contacts of 86/AFWPL and 86/BFWPL.
B. Design Basis Improve probability of AFW successfully completing its design function on demand.
C. Equipment Class & Power Requirements SMUD QA Class 2. No modifications to existing power is required.
D. Testing A special test procedure has been written and approved by the Plant Review Committee. Testing was completed on October 25.
III. Calculations and Design Informatioa A. Design Features l
Currently, "A&B MFW pump tripped" affects three ICS functions:
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- MFW Block Valve
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This modification has the following impact:
Pseudo Auto Control - No change.
MFW Block Valves - The "A&B MFW pumps tripped" signal will be replaced with the "MFW pumps discharge pressure low" signal. The remainder of the logic.will remain the same (1 RCP tripped to close the block valve).
AFW Valve Control - The "A&B MFW pumps tripped" signal will be replaced with the "MFW pumps discharge pressure low" signal. This signal will allow the ICS to control the AFW valves on low OTSG 1evel.
B. Functional Description The two functional signals associated with this ECN are "MFWP low discharge pressure" and "MFW pumps tripped." "MFWP low discharge pressure" provides the best indication of MFW status. "MFWP trip" provides the best indication of MFWP not running.
- Signal to initiate ICS control of AFW flow valves will-be "MFWP low discharge pressure" vs. current "MFWP trip" signal.
- Signal to MFW block valve logic will be MFWP low discharge pressure-vs. current MFWP trip signal; however, it shall require at least 1 RCP tripped to activate this function, as at present.
- Signal to pseudo auto logic which is used to run MFWP speed demand to minimum will still_ require the MFWP trip signal in order that the MFW pumps may be started without requiring the logic to be disabled.
- Signal to ICS runback logic will remain MFWP low discharge pressure.
IV. Logic Diagram The logic diagram from the Design Basis Report is attached. (See Figure A) 1 L
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I ATTACHMENT 5 Part II: Auxiliary Feedwater/ Main Feedwater Failure Analysis The NRC requested information regarding single failures as relating to MFW/AFW during the phone conversation of October 25, 1985. A particular question raised was: "Is there a scenario in which one failure in the ICS could close all four MFW valves, interrupting MFW to both OTSG's, and not result in automatic start of AFW flow?"
The ICS controls the MFW valves and the automatic OTSG level control AFW valves. Since the ICS is control grade and not designed to single failure criteria, it cannot be conclusively stated that the above scenario is impossible. The following discussion, however, shows that there is no single failure which can interrupt MFW flow and result in the inability to manually from the control room, provide AFW flow in a timely manner using class 1 equipment which is completely independent of'the ICS.
~The design of the AFW system was presented in detail to the NRC staff during the October 23, 1985, meeting in Bethesda. It was clearly shown that there are two separate and distinct activate / control systems and flow paths-within AFW (see Figure B attached). Either system can supply AFW to the OTSG's regardless of failures in the other. The systems are briefly described below.
- 1) The first system is the ICS Control / Class 1 Pump Start System.
It automatically starts and controls 0TSG level when loss of feedwater/ main feedwater pumps is sensed by low main feed pump discharge pressure or when all four (4)'RCP's trip. Manual start and flow control is available in the control room.
The control grade ICS, which also controls MFW, operates one of two parallel flow path valves to each OTSG (FV 20527 OTSG A, FV 20528 OTSG B). The other flow path to each OTSG is a class 1 safety feature (SFAS) valve (SFV 20577 OTSG A, SFV 20578 OTSG B).
The ICS controlled FV's automatically operate to control OTSG level once main feed pump discharge pressure drops below 700 psig.
A class 1 circuit (independent of SFAS) automatically starts both AFW pumps (P319 motor and P318 turbine drive) when main feed pump discharge pressure drops below 850 psig. The pumps and valves also automatically operate when all four (4) RCP's are not running, as sensed by class 1 underpower/ phase imbalance monitors.
i 2) The second system is the Class 1 Safety Feature Activation System (SFAS). This system provides automatic AFW pump start and flow to the OTSG's when LOCA conditions are sensed. Class 1 manual start and flow control is available in the control. room.
The SFAS system operates the second of two parallel flow path valves to each OTSG (SFV 20577 OTSG A, SFV 20578 OTSG B). The other flow
. path to each OTSG is through an ICS controlled valve described above.
The SFAS valves automatically fully open and the AFW pumps automat-ically start to provide AFW flow to the OTSG's upon low RCS pressure (1600 psig) or high reactor LJilding pressure (4 psig).
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The SFAS system is completely independent of the ICS/ Class 1 Pump Start l -System. Thus,.it follows that there is no single failure which could.cause l . loss of main feedwater flow (for example,' closure of all ICS controlled main
with the SFAS system. SFAS system AFW flow would reytiire manual control room pump. start and flow control since SFAS does not detect loss of main feedwater.
Manual AFW flow start will be rapid and effective because there are specific symptom based Emergency Operating Procedures (E0P's) and extensive operator simulator training regarding loss of main feedwater events. The loss of main feedwater would result in a reactor trip on either anticipatory trip on loss of main feedwater pump control oil pressure or high RCS pressure due to reduced primary to. secondary heat transfer. Upon reactor trip, the operators immediately implement the E0P's which require them to constantly monitor for three main symptoms of off-normal conditions:
a) Lack'of subcooling b) Lack of primary to secondary heat transfer (overheating)
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c) Excessive primary to secondary heat transfer (overcooling) y Rapid-identification of-loss of main feedwater (overcooling) will occur because there are numerous alarms and indicators which will alert the operator. The operators receive extensive simulator training in recognizing the three main off-normal symptoms. Among t'he main annunciator audible alarms and other indicators are MFP discharge pressure low alarm, MFP low flow alarm, MFP trip alar.n, MFP zero speed alarm, SPDS post trip RCS pressure 4 - temperature. display, MFP control panel indication of MFP turbine trip, speed,
. turbine governor valve position, and panel indication of feedwater flow and 0TSG levels.
',s The E0P for overheating gives specific direction to establish feedwater to the OTSG's using AFW. Additionally the abnormal operation procedure for AFW t directs the operator to use the SFAS control valves whenever ICS control is unavailable or undesirable.
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ATTACHMENT 6 AUXILIARY FEEDWATER PUMP SURVEILLANCE TESTING Based on reconsideration of the guidance provided in Generic Letter 83-37, the District has concluded that the Rancho Seco Technical Specifications relating to Auxiliary Feedwater would be improved by incorporation of the sample Auxiliary Feedwater Technical Specifications contained in Enclosure 3 of the letter.
Within 60 days, the District will submit an amendment to the Technical Specifications that will incorporate these portions of the generic letter.
For the past six years, plant procedures have required that an operator, in constant communication with the control room, be stationed at the manual test line isolation valve when it is open.
- The frequency for surveillance testing of the auxiliary feedwater pumps has been increased from quarterly to monthly.
Between now and when the new Technical Specifications are approved, the plant will be operated as if the sample specifications of Generic Letter 83-37. apply in cases where they are more conservative than the present Rancho Seco Technical Specifications.
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ATTACHMENT 7 REVIEW 0F OPERATING PROCEDURES The Emergency Operating Procedures were reviewed in light of the October-2, 1985, event and were determined to be appropriate and correct.
It was noted, however, that an improvement couldbe made to the excessive heat transfer-procedure.ta more rapidly terminate the overcooling should feedwater valves fail to close upon demand. This change requires feed-water pump trip should closure command to the feedwater valves fail to terminate feedwater flow. The procedure was originally correct and adequate in that it called for OTSG isolation by closing the feedwater valves. -However, it did not include the contingency for feed pump trip should the valves fail to close.
Step 3.1 requires a MFP trip if OTSG levels exceed 95%. High OTSG levels during overcooling will occur-during overfeed events, not during
.oversteaming events, and it is for the case of overfeed that this step is in the procedure. The purpose of the step is.to prevent OTSG overfill and comes before the steps which close feedwater valves because overfill could be rapid and could require main feedwater pump trip to terminate overfill in a timely manner.
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Attachments 8 and 10 "'11 be submitted on Monday, October 28, 1985, L
ATTACIMENT 9 NSCW PUMP SURVEILLANCE FAILURE The Nuclear. Service Cooling Water'(NSCW) System removes heat from the
' decay heat' removal coolers and the reactor building emergency cooling units during post-accident (LOCA) conditions. The NSCW System then
. transfers this' heat to the Nuclear Service Raw Water (NSRW) System.
During a normal plant shutdown,'the NSCW System removes reactor decay
. heat from the decay heat removal coolers and transfers that decay heat to the NSRW System. System configuration is shown on the attached figure.
During the refueling outage in May of this year, the flow through the "A" loop of the.NSCW system was adjusted to clear high flow alarms on the system. This was accomplished by repositioning the outlet valves on each Reactor Building Emergency cooler. The redistribution of flow throughout the system resulted in a slight increase in pump differen-tial pressure and a corresponding reduction in total system flow as determined by the pump curve.
The surveillance testing done in June prior to plant restart, produced a pump differential pressure in the alert range, as defined by Section XI of the ASME Code. The frequency of the testing was doubled. The results remained consistent until the test on October 23rd when test results indicated a slightly higher differential pressure, on the order of 1%. The pump and valve inservice inspection program required that corrective action be taken.
The cooler outlet valves have been adjusted to increase flow, and a successful pump surveillance test was completed on October 24th. The present flow rate of 6200 GPM is consistent with that measured prior to May and greater than the minimum design rate of 6000 GPM.
The flow in the "B" loop of the NSCW System has repeatedly been sub-stantiated to be acceptable by surveillance testing.
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ATTACHMENT 9
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ATTAC K NT 11 VALVE CONFIGURATION WALKDOWN The Rancho Seco Operations Department has conducted walkdowns of selected systems to verify valve configurations. These walkdowns included assuring that valves required in the procedures are tagged and identified.
The P&ID's were compared for correctness and any discrepancies were dis-positioned by a -nonconformance report. Other than the valve on the MSR that initiated this effort, the walkdown team found only one nonconforming valve, associated with a steam trap, that could affect system function.
The systems which were walked down were secondary systems and their support systems which could affect the operation of the OTSG's, such as feedwater, condensate, plant air, auxiliary steam, etc. The 16 systems walked down included approximately 10,000 items assigned plant identifi-cation numbers, of which a large portion are valves. A total of 116 valves were found which were not in the procedures nor on the P&ID's. Of these valves, only one, if mispositioned, could have adversely affected system function without providing indication of the problem which would alert the operator to take corrective action. The one valve was an inlet valve to
- a steam trap on the main turbine. There would be no indication to the operator that the trap was not in service. A large portion of the remain-
- ing 115 valves were instrument root valves, vent and drain valves, and large process line valve bypass valves. It has been District policy not to individually show these valves on the P&ID nor place them on the valve lineups, however in its commitment to excellence, the District has taken advantage of this walkdown effort to change its policy and include these valves on system lineups.
6
m ----- --...
I
- l. LEGEND: SU = Start:p Requirtd i
l LT = Long Term -
STATUS DATE 10-25-85
,i PE = Power Escalation OCTOBER 2, 1985 TRANSIENT TIME 1200
, NA = Not Applicable ST = Short Term - ACTION LIST -
- j DESCRIPTION RESPONSIBILITY SCHEDULE STATUS WP. No./NCR/ COMMENTS 2 ETC.
l I Post Trip Report J. Field SU In Progress NA Initial draft completed.
PRC comments to be incorporated -
t
, II Root Cause Analysis S. Crunk SU Completed NA Reviewed by Management-Review Team. Comments to be incorporated.
- i
! a. Verify calibration of N. Brock SU Completed 104969, 104972 Completed 10/07/85 j appropriate modules. 104973, 104974 i . 104975 4
l i b. Reset of Aux FW Valves B. Spencer SU Completed NA Crews were trained.
! on MFWP Reset.
ll- I
- c. Revise procedures for III,b.
B. Spencer SU Completed S0-20-85 Temporary change to Operating Procedure A.51 jj done 10/13/85.
1 4 I d. Evaluate design of AFW V. Lewis ST In Progress NA l valve reset on restart j of MFW Pump or RCP.
i
}.
1 ;
l 1. Rev.ise AFW valve N. Brock SU In Progress R-0196 2 control logic for
! loss of MFW pumps. a
! a, ,
l .
I I
-.e._, - _. . . _ . ..
s LEGEND: SU = Startup R;quircd ~
LT = Long Term STATUS DATE. 10-25-85 PE = Power Escalation OCTOBER 2, 1985 TRANSIENT TIME 1200 NA = Not Applicable :
ST = Short Term - ACTION LIST -
DESCRIPTION RESPONSIBILITY SCHEDULE STATUS WR No./NCR/ C0f91ENTS '
ETC.
l IV HPI "A" Inject Line flow
- indication
- a. Write and perform J. Field SU Completed STP-180 Results approved. See IV d.
Special Test Procedure.
b .' Perform calibration N. Brock SU Completed 105228 Completed 10/04/85.
. check of FT-23807. Found OK.
- c. Resolve flow anomaly and s J. Field SU In Progress S-5103, S-5150 NCRs require closure. -
prepare Summary Report.
- d. Write and perfonn a 2nd J. Field SU Test STP-184 . Reviewing resul ts.
I Special Test Procedure. Performed V Pegging Steam Controls i a. Determine adequacy of J. Field SU Completed NA Nuclear Engineering pegging steam setpoints (S. Rutter) Support and FW hester relief valve setpoints.
- b. 1. Verify setpoints of R. Lawrence SU Completed 104541, 104544 All setpoints as per
- 2nd and 4th Point 104542, 104543 Process Standards.
j heater shell relief 104562, 104563 valves.
1
= g
] 2. Reset 4th point R. Lawrence SU Completed 104581, 104583 Revised setpoint values % 2 l} heater shell reliefs 104582, 104584 per V a. .m j 4 to new setpoint o m
{
values. ] 5 1
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t__- - _ - - - _ _ _ _ , . _ . - _ _ _ _ . - . . . . .
g i.
! LEGEND: .SU = St:rtup Required ,
LT = Long Term -
STATUS DATE 10-25-85 PE = Power Escalation OCTOBER 2, 1985 TRANSIENT TIME- 1200 NA = Not Applicable ST = Short Tem - ACTION LIST -
DESCRIPTION RESPONSIBILITY SCHEDULE STATUS WR No./NCR/ COMMENTS ETC.
IV c. Verify setpoints of all secondary system relief R. Lawrence PE Planning Will require use of hydro assist on valves without valves which could recent setpoint history.
, cause rapid cooldowns/
other FW heater shell i rel iefs.
- d. Determine appropriate R. Lawrence LT To be done as part of PM periodic test program program upgrade.
(i.e., either PM or SP i Program) and implement
, same for all secondary l relief valves.
! e. Resolve report of MSR J. Field SU Completed NA Resolved that MSR Relief's Reliefs lifting after did not lift.
Rx/ Turbine trip.
- f. Establish criteria for V. Lewis LT process setpoint determination.
. g. Review plant for proper V. Lewis LT j application of criteria.
} h. Add setpoints for R. Colombo LT AP.152 FSL-32243, 32244, and l ?
- 32453 to Process
! Standards. % h w
l O l a Y
l
__ ~- --. .
LEGEND: SU = Startup Required LT = Long Tem i STATUS DATE 10-25-85 l- PE = Power Escalation OCTOBER 2,1985 TRANSIENT . TIME- 1200
!- NA = Not Applicable ST = Short Tem - ACTION LIST -
DESCRIPTION RESPONSIBILITY SCHEDULE STATUS WR No./NCR/ COfMENTS
. ETC.
VI "A" Main Feedwater Pump seal
! water and controls
- a. Repair linkage on N. Brock SU Completed 104965 Connpleted "immediate" controller. repairs 10/02/85.
!' Completed 105378 Proper pin installed.
!l b. Check comunon mode N. Brock LT Reviewing NA Looking for common mode failure possibility on relations to VI a.
j controller linkage.
I 4 :
)i VII Main Feed Pump Trip Event
]! a. Perform test to duplicate J. Field NA Deleted NA Test not required.
i7 l:' low vacuum condition.
i;8'
- b. Install monitoring N. Brock SU In Progress "A" Pump instrumented. "B" l
I instrumentation. to be done.
1l Plant drawings accurately
- i c. Verify "as built" wiring C. Linkhart SU Completed 102722
- I of "A" FWP trip circuits. show "as built" configuration.
J' '
- d. Check setpoints of trip N. Brock PE Hold 102716, 102721 Requires WR 102716 to be j devices. 102718, 103272 closed out.
102720, 103273 1
u :n, I
- I c, %
i1 m ij =
1
- I
. ~ . . - .
n 1
1 4
LEGEND: SU = St:rtup Required ,
! LT = Long Tem -
STATUS DATE 10-25-85 i OCTOBER 2, 1985 TRANSIENT 1200 PE = Power Escalation TIME
, MA - Not Applicable
- ST = Short Tem - ACTION LIST -
1
- DESCRIPTION -RESPONSIBILITY SCHEDULE STATUS WR No./NCR/ COMENTS ETC.
}
\
i VII e. Compile history of FW N. Brock ST. Completed NA I pump control problems.
- f. Check end play on main R. Lawrence SU Completed 102719 Acceptable.
] shaft of "A" WW Pump.
- g. Obtain LO sample from R. Lawrence SU Completed 103269, 102719 Normal.
) "A" and "B" W W Pump and have analysis perfomed.
'! Acceptable; elementaries
- h. Verify "as built" wiring C. Linkhart SU Completed 105686 l of "B" FWP trip circuits. are correct. - S-5119 written.
}
- 1. Install Trip Circuit C. Linkhart LT Preparing Requires pump out of Alam Lights. ECNs service.
l l VIII Main Condenser loss of Vacuum 1,
Event
- a. Update drawings to R. Lawrence SU Completed R-0177 reflect "as built"
- conditions of MSR relief j sealing steam.
- b. Revise procedure (s) to B. Spencer SU Completed NA Temporary change to show MSR relief sealing Operating Procedure A.49 l
steam valves. written.
1 a ,.
I -
~
i i
m
LEGEN0: SU = Startup Required LT = Long Term 1 STATUS DATE 10-25-85
ST = Short Term - ACTION LIST -
DESCRIPTION RESPONSIBILITY SCHEDULE STATUS WR No./NCR/ COMENTS ETC.
VIII c. Detemine whether B. Spencer SU Completed NA Temporary change to sealing steam procedures Operating Procedure A.49 are adequate and usable. written.
' d. Review / analyze perform- J. Field LT Holding NA Long term item.
ance of the gland steam condenser.
! e. Investigate when/why MSR B. Spencer SU Completed NA Investigation unable to l sealing steam valve was to ascertain when/why cl osed. valve was closed.
- f. Detemine whether MSR R. Lawrence LT Completed NA Review shows adequate Relief Sealing Steam for restart.
System works as designed.
- g. Initiate WR for rework R. Lawrence LT Schedule 104113 Next refueling.
' of leaking MSR relief l valve.
! h. Resolve setpoint error S. Carmichael SU Completed 105116 Reset to proper value.
i of main turbine low .
vacuum trip.
- i. Correct / upgrade docu- R. Lawrence LT mentation for maintenance on turbine trip block, y >
l
- m o o
j -
m U c 1
1 -- -
,1 e i LEGEND: SU = Stcrtup Required ~
LT = Long Ters -
STATUS DATE 10-25-85' PE = Power Escalation OCTOBER 2, 1985: TRANSIENT TIE 1200 NA = Not Applicable ST = ,Short Ters - ACTION LIST -:
DESCRIPTION RESPONSIBILITY SCHEDULE' STATUS WR No./NCR/ CO M NTS.
ETC.
t VIII j. Include placement / B. Spencer SU. . . Completed Temporary change to removal of MSR relief Operating Procedure B.3 written.
valve covers in procedures.
valve covers. Designed-
- 1. Include main turbine R. Colombo ST
, trip setpoints in Process Standards.
i m. Develop design improve- V. Lewis LT ment to reduce leakage
~
of MSR relief valves.
IX Condensate /FW Oscillation J. Field SU Completed NA t
X ICS Tuning
tuning STP.
I b. Perform tuning as plant N. Brock PE Engineering l
conditions permit. Required ,
, a g
- c. ATc Control N. Brock .LT Engineering 'f5 g i
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~
t N i
i
'i t
i 1
LEGEND: SU = Startup Required J STATUS DATE 10-25-85' LT = Long Term PE - Power Escalation OCTOBER 2, 1985. TRANSIENT TIME 1200 NA = Not Applicable ST = Short Tem - ACTION LIST -
DESCRIPTION RESPONSIBILITY SCHEDULE STATUS WR No./NCR/ COMMENTS ETC.
! XI Valve Identification Program
. a. Develop list of selected B. Spencer SU Completed To include Operating systems for Operations Procedures A.37, walkdown. A.49,A.41, A.42, A.50, A.46, A.34, A.38, A.40, i A.51, A.47, A.28, A.39, 1 A.53, A.6.
- b. Operations crew to walk B. Spencer SU Completed
. down systems to identify valves not on prints.
I
- c. Prepare NCRs on findings B. Spencer SU Completed NCRs written. Temporary
! and revise procedures as changes to procedures i necessary. written.
- d. Update drawings and B. Spencer LT In Progress DCNs to be generated.
l; place ids on valves.
I
! e. QA Surveillance H. Canter SU Completed No's. 492,
! 488 1
! XII "B" Feedwater Line Leak R. Lawrence SU Completed 104548, 104564 Report addressing the
} Reactor Building. 104560, 104572 cause and the repair done.
i 102095, 104569 Material meets applicable j 104567, S-5090 code. , 3,
- S-5111, S-5093 jg g I
- R
. a .ll
-4
,1
~
c
'1
i i
LEGEN0: SU = Stirtup Required LT = Long Tern -
STATUS DATE 10-25-85 PE = Power Escalation OCTOBER 2, 1985 TRANSIENT TIME 1200 NA = Not Applicable ST = Short Ters - ACTION LIST -
DESCRIPTION RESPONSIBILITY SCHEDULE STATUS WR No./NCR/ COWiENTS
- ETC.
XIII P-319 Bearing Failure
- a. Pump Repair R. Lawrence SU Completed SP run and passed on 10/10/85.
I
- b. Maintenance History R. Lawrence SU Completed Surveillance History and
. Cause of Failure / Post Repair Test Corrective Action
- c. QA Surveillance J. Jewett SU Completed No. 485 i
- d. Provide oiling B. Rausch SU Completed TS 85-1033 To include safety related instructions pumps. How to determine
! level. How to maintair. 011 1evel. Pump specific
'{-
instructions.
- e. Past practice on LO B. Spencer SU In Progress Level .
- f. Investigate whether R. Lawrence SU Completed HLC 85-067 No level change was made.
" Normal" level was changed.
l g. 48-Hour Endurance Run J. Field SU Completed STP-181 I h. Identify all safety R. Lawrence SU Completed NA related pumps which y >
}
utilize slinger rings. g h l e
,O .
j a Y
l' i
l ,
_ m _.
i LEGEND: SU = Startup Required '
LT = Long Term, I STATUS DATE 210-25-85 PE = Power Escalation OCTOBER 2, 1985 TRANSIENT TIME 1200 NA = Not Applicable ST = Short Ters - ACTION LIST -
DESCRIPTION RESPONSIBILITY SCHEDULE STATUS WR No./NCR/ COMENTS ETC.
XIII 1. 011 level indication for V. Lewis SU In Progress S-5120, S-5124 NCRs require closeout.
P-318, 319, 482 A and B, S-5114, S-5115 and 261 A and B. S-5117, S-5118
- j. Root Cause S. Crunk SU Completed Included as subsection of Item II.
. k. Inspect rings in pumps R. Lawrence SU Completed 102096, 102097-which have been 102099 previously disassembled.
XIV Loss of Aux Steam Event '
- a. Prepare Report M. Nickerson SU Completed TS 85-1021
- b. Root Cause S. Crunk LT To be NA RC 85-021 Completed 11/30/85
- c. Investigate Aux Boiler C. Linkhart SU Completed NA Power Supply.
- d. I and C analysis of N. Brock LT To be XIV c. Completed 11/15/85
! Z' g
+ %' >
n 5
i s e a
a n I
1
v- ,
I LEGEND: SU = Startup Required LT = Long Term STATUS DATE 10-25-85 PE = Power Escalation OCTOBER 2, 1985 TRANSIENT TIME Izuu NA = Not Applicable
- ST = Short Tem - ACTION LIST -
DESCRIPTION RESPONSIBILITY SCHEDULE' STATUS WR No./NCR/ COPMENTS ETC.
XV Training
- a. Lessons Learned F. Thompson LT Reviewing NA
- b. Training on Item III.b B. Spencer SU Completed NA SO 20-85 (Instructions / ,
Recommendation) 4
- c. Training on pumps / motor M. Hieronimus SU In Progress NA oiling i
j d. Training on Item III.d.l. B. Spencer SU NA Crews to be trained prior
- to going on shift.
I XVI Procedure Adequacy
[ a. E0Ps D. Comstock SU Completed NA Rule 4 revised.
- b. Normal Procedures D. Comstock LT In Progress NA l c. Identify operator actions M. Hieronimus LT Active NA Requires input / feedback
- not specifically Program from A0's, EA's, etc.
- addressed in procedures. Memo to SS of 10-10-85 <
- " Problem Feedback Report."
! procedures during SU. Validation of procedures j will be perfomed.
l e. Evaluate operator D. Comstock SU Completed NA $ h
] performance during the 3 y trip. -
, g l -+, -
1 1
-%. . . . . . m. a . .. . . , ,
LEGEND 8 SU = Startup Required LT = Long Tern .
I STATUS DATE 10-25-85 PE = Power Escalation OCTOBER 2, 1985 TRANSIENT TIME 1200 NA = Not Apolicable ST = Short Tem - ACTION LIST -
DESCRIPTION RESPONSIBILITY SCHEDULE STATUS WR No./NCR/ COMENTS ETC.
XVII Health Physics / Emergency Plan
- a. Health Physics aspects. F. Kellie SU Completed FWK 85-202 No Health Physics impact.
- b. Emergency Plan B. Spencer SU Completed NA Emergency Plan did not utilization. M. Heironimus require activation.
to B. Spencer memo XVIII RCS Overrooling
- a. Tech Spec Review R. Colombo SU Completed NA
- b. B and W Evaluation J. Field SU Completed NA B and W. letter, SMUD-85-222, dated Oct. 4, 1985, " Structural Integrity of Pressure Boundary Components are Suitable for.
Continued Power Operation.
XIX Preventive Maintenance Program for Non-safety Related Equipment
- a. Description of existing R. Lawrence SU Completed NA program. y
<o
]
2
- b. Planned improvements. R. Lawrence LT R ufres NA m 1 30/85 N k
-l response to ,,
5
- NRC. m m l
N m l
4
_ _ _ _