IR 05000293/1989006
| ML20245F184 | |
| Person / Time | |
|---|---|
| Site: | Pilgrim |
| Issue date: | 07/20/1989 |
| From: | Blough A NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20245F179 | List: |
| References | |
| 50-293-89-06, 50-293-89-6, NUDOCS 8908140199 | |
| Download: ML20245F184 (55) | |
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- U. S. NUCLEAR' REGULATORY COMMISSION Region I ! Docket No.: .50-293 ! Report No,: 50-293/89-06 Licensee: Boston Edison Company 800 Boyiston Street Boston,' Massachusetts 02199 Facility: Filgrim Nuclear Power Station
Location: Plymouth, Massachusetts Dates: April 11 .May 24, 1989 Inspectors: C. Warren, Senior Residerit Inspector and Restart Manager T. Kim, Resident Inspector, Pilgrim Station C. Carpetiter, Resident-Inspector, Pilgrim Station T,. Johnson, Senior Resident Inspector, Peach Bottom F. Young, Senior Resident Inspectar, Three Mile Island T..Rebelowski, Senior Reactor Engineer, Region I (RI) A. Asars, Resident Inspector, Haddam Neck M. Evans, Resident Inspector, Limmerick M. Kohl, Acting Resiaent Inspector, Verraont Yankee L. Thonas, Projecc Manager, Office of Nuclear Reactor Regulation (NRR) D. Persinko, Senior Technical Assistant, NRR A. Mendfola, Technical Assistant, NRR L. Zerr, Project Engineer, NRR M. Good, NRC Contractor F. McManus, NRC Contractor G. Bethke, NRC Contractor Approved by: 7-D~D A. Randy Bloysyf7 Chief Date Reactor Projects Section No. 3A Division of Reactor Projects 890sj aoj 99 890732
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_ _ _ - _ _ _ _ - , , Inspection Summary: Areas Inspected: Restart staff inspections were conducted to assess licensee management controls, conduct of operations and the licensee's approach to in-vestigation and resolution of events during the 5 - 25% power plateau of the l Pilgrim Power Ascension Program.
This report documents the closecut of NRC , Bulletin 88-07 and NRC Bulletin 88-07, Supplement 1, " Power Oscillations in ! Boiling Water Reactors (BWR's)" (Section 6.0).
This report also documents in- , spector followup to portions of the April 12, 1989, Reactor Core Isolation l Cooling (RCIC) Overpressurization event (Section 4.2).
! Results: The report documents a non-cited violation where, on April 21-22, 1989, three reactor operators exceeded the NRC overtime guidelines of 24 hours in a 48 hour period by four hours without prior management review and approval as required by licensee procedure.
Other than this isolated case, licensee overtime controls were appropriate. (Section 2.4).
! Strengths: 1.
The licensee exhibited an excellent approach to problem investigation and resolution in response to the May 3, 1989, turbine trip / reactor scram (Section 2.3.3).
2.
Licensee Event Reports continue to exhibit detailed, thorough and clear description of avents 6nd root cause analyses (Section 7.0).
Weaknesses: None ! Observations: I j 1.
Following completion of the replacement of the RCIC pump suction switch, miscellaneous debris was lef t in the immediate job site area, in contrast to the normally clean condition of the plant and to other clean work areas that had been observed (Section 4.2.2).
2.
During the conduct of the RCIC injection test, an excessive number of personnel were noted in the control room causing a potential distraction.
(Section 2.3.2).
l 3.
Although overall operator response to the May 3,1989, turbine trip /reac-tor scram was excellent, two instances of inattention-to-detail by lic- . ensed operators were noted (Section 2.1).
The event itself was caused, in part, by performance of unscheduled backshift troubleshooting, which , could have been better planned using dayshift technical staff (Section 2.3.3).
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_ - _ _ _ _ - _ . . ! TABLE OF CONTENTS Page 1.
S umm a ry o f Fa c i l i ty Ac t i v i t i e s...................................... I 2.
Operations (Modules 71707,71715,71710,40500,62703,61726)........
3.
Surveillance (Module 61726)..........................................
4.
Maintenance and Modifications (Modules 37700, 62700, 62702, 62703, 62705)................................................... .........
i 5.
Radiological Controls (Module 71707)............................ ....
6.
NRC Bulletin 88-07 (Module 25599),.................. ...............
7.
Review of Licensee Event Reports (Module 90712)......................
8.
Followup on Previous Inspection Findings (Modules 92701,93702)......
9.
Management Meetings (Modules 30702, 30703)..........................
Attachment I - Persons Contacted I Attachment II - Licensee Handout from May 8, 1989 BECo Presentation to Region I Management .
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_ _ _ _ _ _ _ ., s l DETAILS 1.0 Summary of Facility Activities At the beginning of this report period,.the plant was operating at approx-imately 24% power while the licensee was awaiting NRC approval to proceed with power ascension from 25% to 50% power.
At approximately 8:45 a.m. on April 12, 1989, the licensee experienced an inadvertent Reactor Core Isolation Cooling (RCIC) suction piping over-pressurization during the conduct of a RCIC Logic System Functional Test.
The duration of the event was approximately two minutes and involved the spill of approximately 100 gallons of water onto the RCIC quadrant room floor.
In response to this event, NRC Region I dispatched an Augmented Inspection Team (AIT) to Pilgrim on April 13, 1989. The six member AIT was led by Mr. Eugene Kelly, Chief, Technical Support Section, Division of Reactor Projects, and the team consisted of two technical specialists from NRC Region I, plus members of the Pilgrim resident staff and the Office of Nuclear Reactor Regulation.
The inspection focused on the sequence of events, the causes and the licensee's response to the event.
By April 16, 1989, the licensee had completed those portions of their investigation which could be done with the reactor at normal operating pressure.
The licensee then commenced a reactor shutdown at 1:35 p.m. on April 16, 1989, to continue investigation and repair of the possibly inoperable check valve in the RCIC system.
The shutdown was initiated because it was projected the RCIC would not be returned to service in the seven days allotted by the technical specification limiting condition for operation.
An Unusual Event was declared from 1:35 p.m.
to 8:50 p.m.
during the plant shutdown required by technical specifications.
The Augmented Inspection Team held an exit meeting at the NRC Region I Office in King of Prussia, pennsylvania, with licensee management on April 19, 1989. A representative of the Commonwealth of Massachusetts was also in attendance at the exit meeting.
Results of the AIT were docu-mented in Inspection Report No.
50-293/89-80 which was issued on May 9, 1989.
Following completion of troubleshooting and repairs associated with the RCIC overpressurization event, at 7:45 p.m. on April 28, 1989, the licen-see brought the reactor critical.
The turbine generator was synchronized ' to the grid at 7:28 a.m. on April 30, 1989.
At 3:25 a.m. on May 3, 1989, while licensee personnel were troubleshooting the "B" Feedwater Regulating Valve (FRV), the "B" FRV opened unexpec-tedly, causing reactor vessel water level to reach the turbine trip set-point.
The reactor automatically scrammed as designed from about 25% power.
The plant responded normally to the scram with the exception of five containment isolation valves which unexpectedly went closed.
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licensee performed troubleshooting of the FRV. and the containment isola-
tion valve closures.
Licensee management presented the results of their investigation of. the May 3,1989, turbine tPip/ reactor. scram at a manage-ment meeting conducted on Nay 8, 1989,'at NRC Region I. -The handouts from that~ meeting are included as Attachment II to this report.
i < The plant remained in cold shutdown throughout the remainder of the period I while licensee personnel continued to investigate the events of the reactor scram on May 3, 1989.
NRC inspection activities during this report period were conducted by.the ensite Pilgrim. Restart Staff led by Mr. Clay C. Warren, Senior Resident . Inspector and Restart Manager. The Pilgrim Restart Staff is composed of the Pilgrim resident inspectors, resident inspectors from other plants, NRC. regional-based and headquarters-based inspectors and NRC contractors.
At the beginning of this report period, the Pilgrim Restart Staff was I maintained on extended shift coverage.
The Pilgrin' Restart Staff began around-the-clock shift coverage at 6:30:a.m. on April 24, 1989.
This coverage was reduced to extended shift coverage at midnight on May 3, 1989, concistent with reduced testing activity and -plant conditions.
On May 23,1989, around-the-clock shift coverage resumed and was maintained through the end of this report period.
2.0 Operations 2.1 Sustained Control Room Observ_ations Based on around-the-clock and extended shift observations of control
room activities including shift briefings and turnovers, the inspec-tors determined that control room activities were conducted in a for-mal and professional manner.
The inspector verified that operating shift crews met Technical Specification (TS) manning requirements during shutdown, startup and routine operations. _ The oncoming shift reviewed plant instrumentation and status prior to assuming the watch.
Communications in the control roem were noted to be formal and repeat-backs were routinely used for clarity.
Pre-shift brief-ings were conducted in a formal manner.
The Nuclear Watch Engineers ensured all personnel were present prior to the briefings and ques-tioned watchstanders to obtain additional details on work and evolu-tions in progress.
The inspectors noted however, that watch relief turnover status sheets and discussions were not always thorough in covering maintenance status information and did not include all major - maintenance work requests that were being worked.
This observation was brought to the licensee management's attention. The inspectors i will continue to review this area in future inspections.
The inspectors also observed "on shift" training in the control room on changes to system lineup and tagging procedures. The changes were instituted as a result of the April 12, 1989, Reactor Core Isolation i _ - -_. - _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ - _
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' L Cooling (RCIC) overpressure'ization event. The procedural changes were ' , for. procedure 1.4.5, "PNPS Tagging Procedure," procedure 2.1.11,
" System 1.ineup File," and pr:ocedure 1.3.34, " Conduct of Operations."- -j l.
-The training addressed component isolation for maintenance and test- .
ing, system lineup and restoration, plus-independent verification and .. equipment tagging, The purpose of the training was to emphasize the-i l . intent and' purpose of the' changes and to ensure clea'r understanding
by involved personnel.
The. inspector noted that thE discussion:; ' between the control room crew and instructor were productive in pro-i 'ducing several postulated scenarios where additional guidance might i ,. be appropriate for the' independent verification and tagging' process.
The inspector concluded that the training had been conducted in a formal, professien41 manner and was ef fective. During the inspection period,'the licensee processed additional changes to the P.NPS Tagging procedure and the Conduct of ' Operations procedure to incorporate changes from training and operator comments' Additional training was . then-conducted.on the new changes.
> , The inspector observed centrol room activities during the reactor l scram on May 3,1989. - Overall operator-response was. adequate. How-ever, the inspector noted two instances of inattention-to-detail by , the operators. The operators failed to notice until after pointed l out by the inspector that the number 3 Turbine Intercept Valvo had.no . ' position indication - due to a burned-out bulb.
Also, the partial , Group 2 isolation was roticed after the inspector questioned.whether any other isolations had occurred (in addition to the "A" inboard Main Steam Isolation Valve (MSIV)). The delay in noticing these in-dications did not impact or interfere with operator response to the-event and did not degrade plant safety in any way.
The inspectors noted that this slowness to notice.these indications was a departure from the operators' ncrmally good attention to their licensed duties.
The inspectors routinely observed implementation of the independent verification and tagging requirements of procedure 1.4.5, "PNPS Tag-ging Procedure."
The inspector observed _ two operators conducting isolaticn, tagging and verification of components under maintenance work requests 89-13-36, "RCIC Pump Suction Relief," and 89-13-35, "RCIC Check Valve Repair."
Verification activities were performed appropriately. The operators were observed to pay particular atten-tion to valve identification and positioning.
On May 1,1989, the inspector accompanied a Nuclear plant Operator during the tagout of the mechanical vacuum pump for repair. The operator noted a discrep-ancy between the tag and the nomenclature on the name plate of the i power supply brea~ker for the mechanical vacuum pump.
The operator returned to the control room and with the assistance of the Nuclear Operating Supervisor (NOS), resolved the discrepancy. The system was then properly tagged out.
The inspector also observed isolation, tagging and independent verification activities under Maintenance Work Request 89-23-51 " Hydrodynamic Test of HPCI Injection MOV." The inspector had no further questions.
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L 2.2 Plant Tour Observations The inspectors routinely conducted plant tours and noted that in I general, plant cleanliness remained outstanding. During these tours, i the inspectors made the following observations.
'
Fire doors were always found closed and logs of their hourly checks t were maintained and up-to-date. Access to fire hose reels and other
fire equipment was unimpeded.
Emergency lighting was fully charged l .and provided an open view. of the area to be lighted. The fire bri-U gade was assigned to qualified individuals in operations and secur-ity.
2.3 Review of Plant Events 2.3.1 Reactor Core Isolation Cooling (RCIC) Overpressurization Event At 8:45 a.m. on April 12, 1989, the licensee experienced an
overpressurization transient condition of the RCIC system suction piping during the conduct of a RCIC logic system functional test. The RCIC discharge check valve failed to properly seat, allowing the backleakage of feedwater to the low pressure RCIC suction. piping, resulting in the liftino of a pressure relief valve on the suction piping. An Aug- > mented Inspection Team was dispatched to Pilgrim to review this event and licensee actions.
Detailed results of this event,' licensee actions and NRC review are contained in the AIT Report 50-293/89-80.
! i 2.3.2 Reactor Core Isolation Cooling Injection Test ! On May 1, 1989, the licensee conducted a RCIC discharge-l check valve test in accordance with. Temporary Procedure (TP 89-38), "RCIC Vessel Injection" to verify that the repairs to the RCIC discharge check valve M0-1301-50 were satis-factory.
TP 89-38 was to demonstrate that the check valve would allow forward flow and also properly seat to prevent reverse flow.
The reactor was operating at about 25 per-cent power at the time of the test.
Routine surveillance tests had been conducted satisfactorily to verify RCIC system operability during the reactor heatup of April 29-30, 1989.
A pre-test briefing was conducted by the test director and the Nuclear Watch Engineer (NWE) in the control room just prior to the test.
The briefing was detailed and in suf-ficient depth for the test to be conducted. Following com-l pletion of the forward flow injection portion of the test, the test was terminated by the NWE due to a perceived prob-
lem with the RCIC flow controller.
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With the floa controller switched to the man-r ual mode, the.RCIC system experienced flow and pressure oscillations and alarms "RCIC Pump Hi/ Low" and'"RCIC Suc-tion High - Pressure" were received.
The test was termin-ated,~ as specified by the procedure, by closing 'the injec- < tion' valve M0-1301-49 and the steam supply valve MD-1301-61.
It was observed, however, that ' the valve MO-1301-49 did not full close..The NWE directed' the reactor operator to shut the RCIC pump discharge valve MOV-1301-48 to pre-vent the possibility of reverse flow to the low pressure suction side'of the pump.
' The RCIC system was properly declcred inoperable and appro- ' priate actions in accordance with :the : Technical-Specifica-tions were taken. :The licensee conducted an immediate- ' investigation supported by the station systems engineering group.and the engineering department.
A walkdown of the RCIC system piping was conducted to ensure structural integrity.
No defects were noted during this wallkdown.
The licensee determined that the observed flow and pressure oscillations of the RCIC system were probably due to rapid closure of the turbine governor valve because of the. step change in controller demand.when the system was transferred to manual control without nulling -the demand signal.
The-RCIC turbine was operating at a flew of 200 gallons per minute (gpm) and speed of 4000 revolutions per minute (rpm) when it switched to the manual mode with lower speed demand of about 2000 rpm.
The instantaneous speed reduction from 4000 rpm to 2000 rpm coincident with the instantaneous flow reduction from 200 gpm to 0 gpm resulted in a pressure spike back across the pump impeller. The pressure spike was minimized by closure of check valve 1301-50 and the fact that the RCIC pump is a
muitistage pump.
The - RCIC pump suction pressure gage was noted pegged high at 85 psig but the pressure relief valve which was set at 100 psig did not lift.
The licensee's engineering department determined that a structural analysis was not necessary since a recont analysis of the RCIC sytem (Engineering Response Memorandum 89-312 and 89-338) enveloped the May 1, 1989, transient conditions.
The RCIC injection valve MO-1301-49 was tested via the Motor Operated Valve Analysis and Test system (MOVAT's) and found to have excessive packing resistance to valve stem travel.
The valve was repacked and MOVAT's tested satis-factorily.
MOVAT's tests were also conducted on the RCIC is _ _ _ _ _ - _ _ - _ - _ _ _ _ - - $
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h flL pump discharge ~ valve M0-1301-48,_ HPCI injection valve MO-2301-8 and HPCI pump discharge valve M0-2301-9 with no , noted discrepancies.
The licensee' is investigating the cause of the excessive packing resistance.
The licensee discussed the response of the turbine to flow-demand changes during injection with the RCIC turbine ven-dor.
The vendor confirmed that the turbine speed would-change very little with flow demand changes during-injec- ! < tion, especially in an unstable' region of the pump curve.
i The test erroneously specified that the speed reduction from 4000 rpm would result when changing flow from 400 gpm ._ ' to 100 gpm; The licensee determined that.the turbine speed response that occurred during.the conduct of TP 89-38 was correct. As prt of the corrective actions, the licensee retired the ' procedure, TP 89-38 and initiated a new ' pro-cedure. to demonstrate the check valve operability.
The licensee re-trained all operators on the operation and characteristics of RCIC flow controller on the simulator as
part~of the operator requalification training.
l The inspectors noted during the test that an excessive number of Deeple were in the control room observing the test.
There were about 15 individuals in the control room-who were not.directly involved with the test. The inspec-tor determined that excessive numbers of people did not directly impact the test evolution; however, the traffic and background noise in the control room could have dis-tracted operators during the test. The inspector discussed that observation with licensee management. Licensee man-agement stated that they had identified the same concern through their internal peer evaluator review process and have instructed NWE's to improve their control of the con-trol room traffic.
The inspectors will monitor this area in future inspections.
! 2.3.3 Followup to Turbine Trip / Reactor Scram Event j On May 3,1989, at 3:26 a.m., a high reactor vessel water , level occurred that resulted in an automatic turbine trip l and reactor scram. The event also included a designed fast ! transfer of the power source for the 4160 VAC busses. Con- ! trol room operator performance during the reactor scram is ' discussed in Section 2.1 of this report.
With the reactor at 2d% power and reactor water level being automatically controlled by the "A" Feedwater Regulating - Valve (FRV), Instrumentation and Control (I&C) personnel were performing troubleshooting on the "B" FRV to resolve l l ! ! !
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<..< .c i f' ' flow oscillations experienced with the valve. Air is sup-plied to the top of the valve diaphragm' to position the valve; a spring' causess the valve to open on loss of air pressure. The valve is also equipped with a handwheel which can mechanically block the valve in position for mainten-E ance.= On loss of the. controller output, signal,- a sole-noid-operated valve depositions to lock air pressure on the dome of the valve actuator to fail "as-is".. > With the "B" FRV closed and the. valve mechanically blocked with the handwheel, troubleshooting of the valve consisted y of placing -an ammeter. in the current loop at the electro- '~ pneumatic (I/P.) converter and a.' pressure gage in the pressure loop to determine the relationship between oscil-lations.of the valve and its controller. As ' the handwheel was backed off to place the valve back into service, ~the - valve ' quickly came off the seat.
Reactor vessel water level was the'n~ noted by the control room operator to. be . increasing rapidly.
The turbine tripped when reactor - vessel water level reached the turbine trip 'setpoint (+48 inches), causing a reactor scram in response to the turbine trip.
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On the turbine trip, the supply of AC power to station busses fast-transferred as designed (i.e., the. 4160 KV loads transferred from the Unit Auxiliary Transformer (UAT) to the Startup Transformer (SVT)). The plant responded normally to the event with the exception of the 1A inboard Main Steam Isolation Valve (MSIV) and four Group 2 ,' (sampling system) isolation valves which went closed unexpectedly.
The positions of the Primary Containment Isolation Control (PCIS) system control switches were left as-is to facili-tate reconstruction of the event.
The licensee then as-sembled a multi-disciplinary team of senior engineers to investigate this event.
The team was divided into two i groups; one group to investigate the behavior of the FRV l and one group to investigate the unexpected closing of the ! containment isolation valves.
Licensee investigation of the FRV problem revealed the pri-E mary cause for the high reactor vessel water level to be the use of general troubleshooting procedure 3.M.3-8, Inspection / Troubleshooting Electrical Circuits.
This pro-cedure did not require a detailed work plan which would have reset the valve's air lockout prior to moving the ! handwheel.
This was due to the performance of unscheduled j troubleshooting -- the onshift NWE decided to work the job on his shift rati > than to await more detailed planning and technical review that could be done by plant technical !
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m l: 8' staff on dayshift.
'Although this decision was clearly . within the NWE's authority, better results were likely to have been achieved by using dayshift staff.
The licensee determined that contributing' causes to this event included (1) the dome air lockout. feature and the actuator diaphragm were not functioning as designed due to excessive air leak-age (the diaphragm leakage was due to normal wear); (2) the dome pressure gage was mis-oriented relative to other simi-lar gages such that at a glance, the. gage could be inter-preted as reading normal pressure when it actually read 0 psig; and -(3) there was insufficient FRV control system technical information, leading to a lack of understanding of the operation of the valve.
Licensee corrective actions with respect to the FRV problem included: (1) both A and B FRV actuators were rebuilt and have. demonstrated acceptable air lock times (approximately one hour); (2) upgrading the FRV technical manual as' part , of the licensee's Vendor Manual Upgrade program and (3) all
work must be. authorized by the Plan-of-the-Day and perform-ance of unscheduled tasks require the approval of the Main-tenance Manager, Operations Manager or Plant Manager (if safety-related).
In parallel, the licensee also performed troubleshooting to determine the cause for the spurious closure of the 1A inboard MSIV and four sampling system isolation valves.
The licensee performed a detailed walkdown of PCIS control switches and an analysis of plant conditions prior to and following the trip using the EPIC computer system.
The licensee then developed a fault / logic tree analysis of the a'fected equipment to determine common links between the devices. The results of the analysis identified that 'only the AC power supply was common to all devices.
The licensee tested the relays of the affected components.
l Testing included measurement of the coil dropout voltages for the relays, contact resistance and timing measurements.
The timing of the VAT to SVT transfer was also tested.
This timing test was initially run on a dead bus so that accurate timing measurements could be made without the risk of damage to station equipment.
Sirce the test showed the transfer scheme operated properly, the licensee performed an additional test on May 13,1989, simulating the actual fast transfer of the A5 and A6 busses from the VAT to SUT.
The test' results revealed that the time from the transfer initiating signal to the closing of the SVT/ Bus A5 breaker was within the expected range of 7 to 9 cycles (i.e.,117 to 150 milliseconds), providing high confidence that the VAT / Bus A5/A6 and SVT/ Bus A5/A6 breakers operated as designed during the event.
After the test, PCIS relays i < _. _. _ _ _ _._____.__ ____._._____.____. _ _
- _ _ _ - _ _ - - - _ _ _ = - _ _ - _._ - ___. _ _ _ - _ . _ _ - _ _ _ - _ . m l 9-that were found in the~ tripped condition after the-May 3,1989, event were again. found tripped as a result'of , these tests.- The licensee concluded that the partial actuations of the- ~ PCIS relays were caused by a reduction of electrical dis-tribution bus voltage during fast transfer of buses A5 and A6 from the. UAT to the SVT. The voltage decrease was'suf- - ficient (close to the coil dropout voltage ~of the 1 relays) 'i.
to de-energize the 120 VAC coils of PCIS trip and/or con- . trol relays.that were associated with the four ' sampling ~ system isolation valves.
The 1icensee also considered that runni.ng; the plant at a. low power level (25%) with light loads on the AS -and A6 buses added to the bus voltage degradation during the fast.
transfer. Additional large motor loads.on the buses would tend to-. hold the voltage 'at a higher level during the transfer, reducing the risk of a low voltage situation and subsequently the risk of dropping out PCIS relays.
The licensee determined the root cause for the - spurious closure of the inboard MSIV 203-1A to be a random failure of the DC pilot solenoid coil together with the transient voltage decrease that de-energized the 120.VAC coil of the PCIS control relay associated with the valve's AC pilot solenoid.
The MSIV is designed to close automatically if both of the valve's pilot solenoids (one AC and one. DC) become de-energized.
The licensee's investigation also determined that all of the MSIV inboard and outboard AC pilot solenoids became de-energized because the control relays became de-energized due to the fast transfer.
Licensee corrective actions with respect to the spurious valve closures included: (1)' replacement of the failed DC pilot solenoid. assembly; (2) inspection and testing of all inboard and outboard MSIV DC pilot - solenoids; (3) adjust-ment of the coil dropout voltage for the inboard and out-board PCIS relays, 16A-K14 and 16A-K16, to reduce the like-lihood of an actuation of the relays; (4) replacement of the 120 VAC coil with a 115 VAC coil for the inboard and outboard PCIS relays 16A-K17 and 16A-K18 to decrease the dropout voltage by approximately five volts, reducing the likelihood of an unnecessary actuation of the relays on fast transfer, and (5) revision of the reactor scram pro-cedure, 2.1.6 to include operator guidance if a loss of power to the 120 VAC portion of the MSIV logic circuitry occurs.
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As a long-term item, the licensee has written an Engineer-ing Service Request to evaluate the potential need for additional protective devices, such as faster breakers or an uninterrupted power supply for those items which have the potential to drop cut on a fast transfer. The licensee is also evaluating the possibility of permanently powering the safety busses from the SVT to eliminate the need to fast transfer these safety busses on a turbine generator trip.
The inspector concluded that the licensee's investigation of this event was conservative and thorough in all aspects.
As stated above, immediately following the plant trip and after the plant had been stabilized, operations personnel left plant controls and resulting valve positions in the as-found condition.
This action was noteworthy in that it facilitated the reconstruction of the event.
The licensee also used the EPIC computer to analyze plant conditions prior to and following the reactor scram.
The analysis of the f ast transfer and resultant reduction of electrical distribution bus voltage was exhaustive, demon-strating the licensee's excellent approach to problem investigation and resolution.
The inspector determined that appropriate corrective actions were taken.
The inspector had no further questions.
2.3.4 Degraded Cables in the Main Steam Tunnel On May 9,1989, the licensee discovered five cables in the main steam tunnel that were in a degraded condition.
These five cables were located in a single cable tray approxi-mately 20 feet above floor level and spanned the width of the main steam tunnel.
The cable tray held thirteen cables, five of which were degraded.
These five cables included the MSIV actuator AC solenoid control cable for the "A", "B" and "D" MSIV's, the "C" MSIV position limit switch signal cable and a nor-Q power supply cable to the traversing incore probe room.
The other cables in the cable tray were still flexible and showed no evidence of cracked sheathing.
The most extensively degraded cable had sections of outer cable sheath up to 12 inches in length missing (i.e., cracked and fallen away).
On these cables, the outer i sheathing on the individual conductors was circumferen-l tially cracked about every linear inch. All of the affec- ' ted cables were Okonite. The other cables in the tray were flexible and showed no evidence of cracked sheathing.
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k unaffected cables were either Vuikene or Rockbestos. Four of the five cables were ' determined to be Environmentally Qualified (EQ) cables.
The licensee performed megger checks of all of the affected' j cables with the results showing all resistances to ' ground { -higher than 800 megohms (minimum required per the licen- ' see's cable installation specification E347A is
megohms).
The licensee replacec: the damaged MSIV actuator AC solenoid cables with new Kerite cables.
The slightly damaged "C" MSIV limit switch cable was reinsulated with a Raychem zipper.
In addition, the licensee conservatively replaced the MSIV actuator DC solenoid control cables.
Analysis indicated that the cable degradation in the steam tunnel was thermal degradation of Okonite/0kopreme 600V cable and conductive jacket material due to excessive heat generated by main steam lines at or near the MSIV's.
Because of the occurrence of heat damaged cable, the licen-see initiated a walkdown program to determine if the prob-lem existed anywhere else in the plant susceptible to ele-vated temperature conditions. The results of this Walkdown Program were summarized in a Nuclear Engineering Department (NED) summary report issued on May 19, 1989. The inspector reviewed the summary report, interviewed participants in the walkdowns and discussed the report findings with NED.
The inspector concluded that the areas of the plant covered by the walkdowns were adequate, the walkdown process thorough and the corrective actions initiated appropriate.
The areas included in the walkdowns encompassed all "Q" tray and conduit within about six feet of the main steam lines, and the RCIC and HPCI steam lines in the reactor building, drywell and condenser bay.
Only one abraded cable sheath and one heat damaged conduit were discovered during the walkdowns.
Both the cable and the conduit are related to signal cables for main steam relief valve acou- . stic monitors. The abrasion will be sleeved and the flex-l.
ible conduit replaced or repaired at the mid-cycle outage.
The inspector verified that both maintenance items have been submitted to the licensee's outage planning depart-ment.
All follow-up actions related to the heat damaged I main steam tunnel cable are considered satisfactory.
( As a temporary modification, the licensee installed special ' temperature monitoring instrument (thermocouple) in the vicinity of the steam tunnel cable tray to monitor ambient and localized temperatures. The licensee plans to evaluate ___--_ _ -
__ _ _ _ _ _ _ . ., 12- ! the ventilation in the steam tunnel based on the results of the temperature monitoring.
The inspector had no further questions.
! 2.3.5 Reactor Water Cleanup (RWCU) Regenerative Heat Exchanger Leak On May 15,1989, an auxiliary operator conducting routine rounds identified a small leak (approximately 15 drops / minute) on the shell side of the reactor water cleanup sys-tem regenerative heat exchanger (RWCU Regen Hx)..The leak was on the top head of Hx "A" and was dripping from a head bolt.
The shell side has a welded 1/8 inch diaphragm that acts as a head seal which is backed by a bolted carbon steel strongback; this provides the necessary structural support.
'Upon removal of the support, the licensee identified ' several areas of pitting corrosion in the weld heat affec-l ted zone of the diaphragm plate.
How e r, the leak path was not identifiable with the Hx drained.
The licensee decided to install a full face, soft metal gasket under a . temporary modification to control the leak until permanent repairs could be affected in the mid-cycle outoge.
After replacement of the gasket material the licensee refilled .the system and found that the leak still existed.
The i engineering decision to install a full face gasket was con- ' sidered acceptable by the inspector despite the lack of success achieved in this case.
The licensee subsequently developed a work package to cut the pitted diaphragm from the Hx, prepare all affected sur-faces for repair and weld in a new stainless steel seal membrane. A firm that specializes in automated cutting and welding processes performed the work.
The inspector reviewed the licensee's processes to develop and implement all aspects of this evolution including the . work package, cutting procedures, welding procedures, qual-ity control requirements, contractor personnel qualifica-i tions, health physics and ALARA (As Low as Reasonably Achievable) radiation exposure controls.
The licensee's I approach to the repair showed that deliberate, thorough methods were employed in all phases of the work.
Health physics controls of the work were very good and the ALARA goals aggressive.
. The final repair was successful and the Hx placed back in service on May 24, 1989.
The inspector had no further questions.
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, L 2.3.6 Scram Discharge Volume High Level Scram At 10:09 p.m.
on May 18, 1989, while licensee personnel were attempting to clear a rod block, an unexpected reactor-scram occurred when the mode' switch was taken from the REFUEL to the' STARTUP position due to a scram discharge , sJf volume (SDV) high level trip that' existed, y [ The licensee h3J inserted a manual reactor scram in. con-y junction with. the replacement of an Intermediate Range Monitor (IRM) bypass switch.
Upon, completion of the IRM bypass switch replacement, the licensee reset the reactor scram in accordance with Procedure 2.1.6, " Reactor Scram."
When the " discharge volume high water level scram - bypass switch" is in the bypass position, the discharge volume . high water level scram is bypassed and it also gives a con-l- tro'l rod block.
The SDV high level scram signal is generated on a sensed ' high level in the SDV by resistance temperature detectors (RTD's). Normally, these RTD's will heat back up to. RTD operating temperature in five minutes, thereby clearing the SDV high level scram alarm approximately five minutes after the SDV ' vent and drain ' valves are opened. Procedure 2.1.6 l also states that when " SCRAM DISCH VOLUME HI LEVEL' SCRAM .i ... alarm clears, wait 5 minutes (this allows time for the RTD's to' heat to operating temperature).
After 5 minutes have elapsed, return the DISCHARGE VOL HIGH LEVEL SCRAM BYPASS. SWITCH TO NORMAL)."
The mode switch was in the REFUEL position to perform rod tests and the SDV vent and drain valves were opened.
At this time, a rod block existed due to the SDV bypass switch being in the bypass position.
After approximately 40 minutes had elapsed, the operator noted the rod block alarm still existed but did not notice that the SDV high level scram alarm had not yet cleared as expected.
The operator didn't recognize the SDV bypass switch position as the source of the block and in an at-tempt to clear the rod block,.the mode switch was taken to the STARTUP position.
The SDV high water level scram is not bypassed in the STARTUP or RUN mode.
This caused an inadvertent reactor scram. The licensee attributed the SDV high level scram alarm not clearing in the expected five minutes to the colder moderator temperature (about 80 - 90 degrees F), in that it would take much longer after draining to sufficiently reheat the RTD's to clear the alarm.
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l The licensee reported thit to the NRC via ENS.
Since the plant was. still in cold shutdown at the time, no rod move-I ment occurred, and the event was therefore of very minor L safety significance.
The inspector had no-further ' questions.
l, 2. 3.7 - Engineered Safety Feature (ESF) actuations during Surveillance Testing ' L At 10:15 p.m.
on May.20,1989, and again at 8:25-p.m. on May 21, 1989, while Instrumentation and Control (I&C) per-sonnel were performing a surveillance test on the recircu-lating motor generator set. lockout relays in accordance with Procedure 3.M.3-37,. Reactor Recirculating MG sets A&B Lockout Relay and 4150 V Drive Motor Breaker Trip Controls Testing, the licensee experienced an ESF actuation.
Resi-dual Heat Removal (RHR) system valve M0-1001-29A unex-pectedly closed and MO-1001-29B unexpectedly opened during the surveillance.
The actuations occurred when a; relay was inadvertently actuated during.the surveillance test. The first actuation occurred when the electrical tape used to insulate the. con-tacts, fell off when the relay was subsequently actuated during the test.
The procedure was revised tc identify 'f.
heat' shrink tubing to be used to boot the contacts.. After the second ESF actuation, the licensee suspended conduct of the surveillance and performed troubleshooting,. including a detailed review of the wiring drawings and the procedure, and continuity checks of the ' wiring to deterrr.ine the cause of the inadvertent relay actuations. No discrepancies were noted. The surveillance-was subsequently successfully com-pleted on May 24, 1989.
The licensee attributed the actu-ations to failure of licensee personnel to properly insu-late (boot) the contacts to prevent relay actuation. Fac-tors that contributed to the error were the type and loca-tion of the relay. This relay is a General Electric type HGA relay. The relay is flush mounted and is located ap-proximately six inches above floor level on Panel C-933.
With the relay cover removed, the pair of normally open contacts of the relay were to be insulated.
The moveable.
contacts together with the relay location, made it dif-ficult to insulate the contacts without causing an inad-vertent actuation of the related circuitry.
As long-term corrective action the licensee plans to revise the pro-cedure where possible to provide an alternate method of testing without insulating relay contacts.
The inspector had no further questions.
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15 2.4L Review of Overtime Records On' April 30, 1989, the inspector reviewed.the records of hours worked 'for the operators for the period April 1 through. April 29,-1989.
Procedure No.1.3.67, "Use and Control of Overtime at PNPS," Rev. 2 describes the use of overtime and the controls to ensure compliance > with NRC. Generic Letter 82-12, Nuclear. Power. Plart Staff Working Hours. This procedure requires that overtime for safety-related work be limited to:16 hours in a 24. hour period, 24 hours in a 48 hour period, and 72 hours. in a seven day ' period, excluding shift turnover time.
Specific' controls are established to allow an individual to exceed these limits with prior app'roval of the Station Director _ or his designee. This approval is documented on Attachment A to 1.3.67, Request to Exceed NRC Overtime Guidelines.
The inspector verified the hours worked by ' review of' employee payroll sheets composing approximately 248 records. The inspector found -that' on April 21-22, 1989, three operators exceeded the NRC-overtime guidelines of 24 hours in a 48 hour period by four hours withcut prior - review and approval in accordance with Procedure -1.3.67. - The ' plant was in cold shutdown at the time. The three operators exceeded ' overtime guidelines due to the fact that in a four~ watch rotation, - Saturday B,a routine twelve hour day.
The licensee is now in a six-watch rotation.
This violation is not being cited because-the criteria specified in Section V. A of the Enforcement Policy were satisfied (NCV 89-06-01).
Specifically, the licensee has taken prompt corrective actions.
Licensee review of previous overtime exception reports for the months l,' of March and April determined additionally, that o'n two occasions an
operator exceeded an overtime guideline by one hour to cover a meal.
) Corrective. steps to prevent recurrence by the licensee include: '( 1) the licensee will continue to monitor overtime usage closely dur-ing the next quarter, and 2) a night-order has been issued to high-p' light overtime guidelines.
Finally, inspector review of this issue has noted no additional problems, indicating that the licensee is now in full compliance with their procedure.
Based on close NRC over-view, the inspector considers this to be an isolated incident and notes that management tracking of overtime has greatly improved over the past two years. The inspector had no further questions.
2.5 Failure and Malfunction Reports (F&MR) The Failure and Malfunction Report (F&MR) is used to document and evaluate failures, n. malfunctions and abnormal operating events.
A sample of recently closed F&MR's showed those F&MR's to be appropri-ately dispositioned with appropriate management review.
No inade-quacies were identified with respect to open or recently closed F&MR's.
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3.0 Surveillance 3.1 Routine Surveillance Tests 'The inspector observed the following surveillance tests.
8.M.1-3.1 APRM Setdown Functional 8.9.1 Manually Start and Load Each D/G Once Per Month 2.1.12.1 Emergency Diesel Generator Daily Surveillance 8.5.4.8 Hydrodynamic Test for Measuring Leakage thru HPCI System 8.7.1.7 Local Leak Rate Test of Personne1' Airlock 8.M.2-2.10.4-2 High Pressure Coolant Injection Logic Test 8.M.1-12 Main Steam Line High Radiation 8.M.2-3.6.3 Con;rol Rod Blocks (A) System Logic Test (Startup i or Refuel Mode) 8.M.1-1.i Turbine Stop Valve Closure Functional Test 8.5.5.3 RCIC Flow Rate Test at less Than 150 PSIG 8.5.6.2 ADS Subsystem Manual Opening of Relief Valves 8.7.4.?. Primary Shift Containment Atmospheric Control Valve Quarterly Surveillance 8.1.1.20 Feedwater Perturbations 8.M.2-2.10.11.1 RCIC High Water Level Turbine Trip / Auto Restart Logic Test 8.M.1-3 APRM Functional 8.M.1-1 IRM Functional / Calibration 8.A.1 Drywell to~ Torus Vacuum Breaker Operability Surveillance During performance of these tests, the inspector noted pre-test briefings were adequate, Quality Control personnel were present if required, sufficient personnel were available for testing, control room personnel were aware of test status and procedures were adhered to.
Personnel performing the surveillance were very knowledgeable about the procedures and the equipment.
One materie(; deficiency was identified by a plant equipment operator during the testing of the "A" Emergency Diesel Generator. The diesel had been removed from service for planned maintenance on the SL and 7L cylinders.
During the start, the SL cylinder pressure test tap blew air.
The operator immediately secured the diesel and notified the control room.
Maintenance was called to tighten the fitting.
The diesel was restarted and the testing successfully completed. The inspector had no further questions.
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, 4.0 Maintenance and Modifications 4.1 Inspection of Motor Operated Valves Due to a ' failure of motor operated valve MO-2301-3 from an over torque condition, safety-related motor operated valves were inspected by the licensee to ensure torque switch set screws were properly torqued.
Engineering Service Request (ESR) 89-243 was written for the Nuclear Engineering Department to evaluate this failure and provide recom-mendations for corrective action.
The corrective action was to inspect 40 safety-related valves and extend the sample to 100% if one or more valves were found to have inadequately tightened torque switch set screws. Because'one valve of the initial 40 valves failed to meet the acceptance criteria, the sample was extended to all safety-related valves.
The inspector accompanied the valve inspection team during the inspection of five safety-related valves.
The valve inspection con-sisted of checking the torque on the torque switch set screws and performing the environmental qualification inspection of - the valve.
The valves inspected included M0-1400-4A, A Core Spray Full Flow Test to Torus: MO-1001-7A, RHR PP A Suction From Fuel Suppression Pool; MD-1001-18A, RHR Loop A & C Minimum Flow; MO-1001-28A, A Loop LPSI Injection No.1; and MO-1001-28A, A Loop LPSI Injection No. 2.
The inspector concluded that the inspections were detailed, thorough and conducted in accordance with the maintenance work order and refer-enced procedures.
j Minor deficiencies were noted by the inspector on several MOV's, such as excessive wire bend radius, loose conduit clamps on EMT and a loose lock washer. These were discussed with the licensee and turned over to maintenance for evaluation and correction.
The inspector had no further questions.
4.2 Investigative and Repair Work Associated with RCIC Overpressure Event During this report period, the inspector observed portions of the leak rate testing of the RCIC check valve as well as the replacement of the RCIC pump suction switch performed in response te the April 12, 1989, RCIC overpressurization event.
Detailed results of this event and licensee actions are detailed in the AIT Report 50-293/89-80.
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L p 4.2.1-RCIC Check Valve Leak Rate Testing The inspector observed portions of the leak. rate' test on l RCIC check = valve 1301-50.
A leak check was performed on RCIC check valve 1301-50 in an "as-found" condition and then as post-maintenance testing due -to repair work on the check valve, as described in AIT Inspection Report 50-293/ 89-80.
The -leak. testing was conducted in' accordance with procedure 8.5.5.7, " Hydrodynamic Test For. Measuring Leakage Through.RCIC." The test provided for pressurization of the . -downstream side of the check valve and measuring check valve leakage through collection of water on the upstream side.
Discussions with the Test Director and test personnel indi-cated -that they were knowledgeable of the test procedure and test details such as test boundaries, limits and acceptance criteria.
The inspector noted a satisfactory pre-briefing for the test for all involved personnel.. Approved test procedures were -available and in use. 'The calibrations of test gages and relief valves were current.
Examination ' of the hydro unit by the inspector indicated test gages in the proper range, proper pressure hoses and satisfactory hookup.
The test was stopped prior to com-pletion-due to a packing leak.
The oacking, was tightened and the test was continued. Both leak tests were completed satisfactorily. and met the acceptance criteria.. No defi-ciencies were noted with the testing.
4.2.2 Replacement of the RCIC Pump Suction Switch During the RCIC overpressurization event on April 12, 1989, ,. the.RCIC system suction high pressure alarm,13-PS-1360-21 l (setpoint 70 psig) was received at the onset of the event.
-l As delineated in the NRC AIT report (50-293/89-80 dated May 8, 1989), the alarm remained actuated after the event L was terminated even though local indication showed that the I-suction pressure had returned to normal.
Investigation by the licensee showed that the pressure sensing device had been dar;; aged by the pressure transient.
The inspector reviewed Plant Design Change (PDC) 89-24, Replacement of the RCIC Pump Suction Switch.
This plant design change package replaced the RCIC pump suction pressure switch PS 1360-21.
The original multiple function pressure switch was replaced with two separate pressure switches since a qualified ' "i n-ki nd" switch was not available.
The modification involved minor mounting, electrical and tubing changes to
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- - support the new pressure switches but did not. involve any. functional change to the RCIC system.
The inspector , reviewed the modification package, observed portions of the i modification work and performed an installation inspection of the completed modification.
The physical installation work was found to.be generally good quality exce'pt as noted below.
While4 observing the RCIC pump suction switch replacement, several instances of worker inattention-to-detail were noted by the inspector. First, micrometer readings for the pressure switch wire diameter were incorrectly written down in Attachment G to ' procedure 3.M.3-17.1, " Field Splice, Repair, and Sealing of Safety-Related Cables (1000V and under) RayChem WCSF-N Sleeve and NPK, NPKV, NMCK, NCBK, and NESK Kits Installation." The diameter of the detector wire was listed as 0.19 inches instead ' of 0.119 inches.
The splice data sheet was subsequently corrected. Second, the inspector noted the newly insta11ed' 1-1/2 inch conduit "T" fitting was loose and was in hard contact with-an instru-ment line adjacent to the root valve for pressure Switch PS 1360-21A and B.
Field Revision Notice (FP.N) 89-29-01 was written and implemented to correct the deficiencies.- The inspector also noted that the carbon steel mounting plate for the pressure switches was not painted as specified in the modification package.
A work request was prepared to paint the mounting plate.
Finally, miscellaneous debris from the modification work was left in the work area. The debris included bolts from the old pressure switch mount-ing, 1/2 inch stainless steel tubing cutoffs, cutoff ter-minals, and a Swagelock tubing cap.
The inspector dis-cussed this observation with the licensee and the work area was promptly cleaned up.
These instances illustrate in-attention-to-detail by the personnel performing the work.
The quality of the work, overall however, was good and the inspector had no further questions.
The inspector also reviewed temporary procedure TP89-40, "Preoperational Test RCIC Pump Suction Pressure Switches 13-PS-1360-21A & B."
The inspector had no questions with regards to the test procedure.
5.0 Radiological Controls J t The inspector observed health physics practices in conjunction with inspection of the modification of the RCIC suction line pressure switches i and maintenance on the RCIC suction relief valve. The RCIC room had con-l- tamination levels of 10,000 to 20,000 dpm/100cm, hot spots up to
400 mrem / hour and general area dose rates of less than 5 mrem / hour. The
inspector noted the pre-entry briefings in the health physics office were ' i l
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detailed and thorough and included the use of recent survey maps to point out hot spots.
The central dress out area for the process building was ' cl ea n ', organized and facilitated dressing out.
Access and egress for personnel and equipment was prompt and orderly.
During observation of work activities, the inspector noted proper concern for contamination, . general dose - and hot spots within the RCIC room.
Removal of anti-contamination clothing and step off pad procedures were observed for personnel.
No deficiencies were noted.
The inspector did note that anti-contamination clothing removal instruc-tions were. not posted adjacent to the step off pad.
Discussion with health physics personnel indicated the controlled area had just been reduced in size and the instructions were not moved when the step off pad was moved.
The health physics watch technician immediately corrected the deficiency.
During a tour.of the refueling floors the area around the ' spent fuel pool was noted to be well maintained. However, ~many unlabeled ropes were ob-served to be tied to the sides of the pool. Unlabeled ropes present the possibility of inadvertently raising incorrect items when retrievina equipment from the pool. This practice cculd lead to unexpected personnel exposure. The licensee is evaluating this item. The inspector will fol-lowup this' item in a future inspection.
6.0 NRC Bulletin 88-07 The inspector had previously reviewed NRC Bulletin 88-07 and NRC Bulletin 88-07, Supplement-1, " Power Oscillations in Boiling Water Reactors (BWR's)," using Temporary Instruction TI 2515/99 in Inspection Report 50-293/89-05. The inspector concluded that the licensee adequately imple-mented the requested actions of the NRC Bulletin and supplement. The NRC concluded in a letter to BECo dated April 25, 1989, that actions necessary to provide reasonable assurance that uncontrolled power oscillations will not occur at Pilgrim have been taken, and that the licensee fulfilled the requirements of the. bulletin and supplement.
As described in Inspection Report 50-293/89-05, the licensee committed to complete followup training for two active and three inactive licensed operators.
This followup training has been completed for all active licensed operators; two inactive operators remain to have the followup training.
This will be completed during the current training cycle.
Additionally, the licensee committed to re-assess the knowledge level of the shift regarding power oscillations and perform remedial training if needed.
Remedial training has been performed for all personnel. Based on the licensee's response and inspector review, this bulletin and TI 2515/99 l are closed.
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{ 7.0 Review of Licensee Event Reports (LER's) s L LER's submitted to NRC:RI were reviewed to verify that the details were clearly reported, including causal description and adequacy of corrective action.
The inspector determined whether further information was required from the licensee, whether generic implications were indicated and whether the event warranted onsite followup.
The following LER's were reviewed: ! LER No./. ' . Event Date Subject 89-008-00/ A momentary breach of primary containment integrity 02/16/89 due to both personnel airlock doors being open.
The cause was due to slack in the tie rod roller chain assembly for the interlock mechanism on the inner door which allowed the mechanical interlock for the airlock doors to be satisfied without the inner door being closed.
This was due to improper tightening of the jam nuts during previous maintenance activities.
A i contributing factor was the lack of preventive main-tenance. on the personnel airlock doors. The inspec-tor's review of this event is documented in Inspection Report 50-293/89-01.
89-009-00/ Isolation of Reactor Water Cleanup System (RWCJ).
02/16/89 The cause of the event was a RWCU system flow fluct'ua-tion that occurred due to a personnel error when a RWCU system suction valve was throttled to the closed position, causing a sensed system high flow and a trip signal.
The inspector's review of the actuation is documented in Inspection Report 50-293/89-01.
89-010-00/ Loss of preferred offsite power due to a failed feeder 02/21/89 cable.
The cause of the loss of preferred offsite power was due to a fault on the "C" phase power feeder cable between the startup transformer and the auxili-ary power distribution system.
The root cause of the cable failure could not be determined with certainty; however, preliminary examination indicated that the failure may have been related to cable jacket damage during original cable installation.
The inspector's review of this event is described in Inspection Report 50-293/89-01.
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, , LER No./ Eventpate-Subject 89-011-00/- Automatic closing of the Main Steam Isolation Valves 03/04/89 (MSIV) and subsequent reactor scram. This was.' caused by a pressure decrease in the main steam system due to the automatic closing and re-opening of the turbine bypass valves as a result-of a bypass valve vacuum trip and reset of the vacuum. trip. The root ca'use for the vacuum trip and trip reset could not be deter-mined.
Inspector review of this event is contained in Inspection Report 50-293/89-01.
Review of these LER's revealed that the description of the events and root cause analysis was detailed, thorough and clear.
LERs continue to be a , licensee strength. The inspector had no further questions.
8.0 Followup on previous Inspection Findings (Closed) Violations (87-30-01, 87-30-02, 87-50-02) Degraded Vital Area Barriers.
These items were addressed and licensee corrective actions were reviewed -in Inspection Report 50-293/88-16.
These items were left open pending an NRC decision regarding escalated enforcement actions. A civil penalty was issued in October,1988 and paid by the licensee.
Based on all-actions being complete, these items are closed.
(Closed) Unresolved Item (86-36-02) Fire Barrier Operability Evaluations to be Performed by the Licensee.
This item was reviewed and resolved in Inspection Report 50-293/88-19. However, it remained open pending further NRC review to determine the appropriate enforcement action.
By letter dated October 13, 1989, the NRC advised BECo that enforcement discretion was being exercised on this issue and therefore no Notice of Violation would be issued.
Based on-the above, this item is closed.
9.0 Management Meetings ! ' The Augmented Inspection Team held an exit meeting at the NRC Region I office with licensee management on April 19, 1989.
A representative of the Commonwealth of Massachusetts was also in attendance at the exit meeting.
On May 8, 1989, a licensee-requested meeting was held at the NRC Region I office where licensee management presented the results of their investiga-tion of the May 3,1989, turbine trip / reactor scram (see Section 2.3.3).
The licensee's handout for the presentation is included as Attachment II to this report.
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23 , At periodic interval' Juring the inspection period, m'eetings were held by i the restart inspection staff with senior facility management to discuss the inspection scope and preliminary findings of the inspectors. A final exit interview was conducted on June 2,1989.
No written material was given to the' licensee that was not previously available to the public.
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i l \\ i j ATTACHMENT I Persons Contacted f R. Bird, Senior Vice President - Nuclear
- K. Highfill, Site Director
,- R. Anderson, Plant Manager D. Eng, Outage and Planning Manager E. Kraft, Deputy Plant Manager D. Swanson, Nuclear Engineering Department Manager D. Long, Plant Support Department Manager J. Alexander, Training Department Manager J. Jens, Radiological Section Manager J. Seery, Technical Section Manager R. Sherry, Maintenance Section Manager L. Olivier, Chief Operating Engineer J. Neal, Security Division Manager W. Clancy, Systems Engineering Division Manager B. Sullivan, Fire Protection Division Manager
- Senior licensee manager present at the exit interview
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NWE requested !&C investigate B FRV g problems g s A 3.M.3 8 used to investigate ' \\ E B FRV sticking s
Rx higklevel Turbine trlp - tdp/ clear 3.M.2-7.2 used to attempt B FRV calibration
- Load reje'et scram tdp B1/A1-tdp Calibration unsuccessful s
B FRV oscillated, turned . Load reject stram trip B2/A2-trip 22:08 over to 11-7 shift ( ,
- Reactor scram lyA-trip 03:05 B FRV closed &
, blocked ' . Reactor full scramyrip(03:26:35) 03:20 eo""
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- All 3 bypass valves in opening ck
- Peak Rx pressure 958.$psig goes n enseday 03:25 FRV station a
(n c . Peak Rx level 48.46 in.
\\ Received B FRV signal failure y@E s 03:25:15 alarm,(ammeter hooked into the g
- MSIV 1 A begins to close(03:26:36)
current loop) < g \\ Bypass valves full open \\ critique Panel 905 operatorinformed that 5 Em " O"9 Rx pressure 948 psig \\ Operator backed off FRV hand - in s $ = Bypass VLV #3 closed \\ 03:25:42 wheel 21/2 turns. l&C tech $ observed 1/2" travel-heard MSlV 1 A full closed \\ pop.
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- Rx pressure 938 psig
\\03 25:49 B FW flow increase step #1 beg!n.e s , Bypass M #2 closM 03I25:51 B FW flow increase step l l Mode switch to startup(03:26:45) \\
- 1 end.
s \\ B FW flow increase step #2
- Bypass VLV #171/2% open 03:26:01 begins
. Rx level 16 In ..- - B FW flow increase step #2 end.
i y ' ~63:27:30 ,,,,,,_.. ,. - g 03:30 Rx pressure 896 psig $ Notes: 3.M 3-8, inspectionfiroubteshooting - l
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CONTROL SWITCH TO CLOSE I POWER 18A-K18X2 Coll SUPPLY I FAILURE FAILURE 16A K18X2 DE-ENERGlZED LOSS' OF BKR FU'SE I 18A-K'18X2 l l LOSS OF RELAY SEAL IN FAILURE BUS Y31 TRIPPED BLOWN FAILURE POWER 16A-K18X4 DE-ENERGlZED I I LOSS BRKR FUSE OF Y31 TRIPPED DLOWN g g RELAY 18A K18X LOSS OF FAILURE POWER I BKR FU'SE I . LOSS OF TRIPPED SLOWN I . l BUS Y41 RELAY LOSS OF SECOND i FAILURE POWER CONT LOOL 0 TRIP l I f { l l l ! E6#:0Z60Lil ~010
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LOSS OF BKR FUSE RELAY, FAILURE G2ED ' ' - BUS D37 TRIPPED BLOWN MECHANICAL l l l ELECTRICAL RELAY 18A-K17X LOSS OF FAILURE POWER lI i l LOSS OF BKR FUSE g l BUS Y31 TRIPPED BLOWN RELAY LOSS OF SECOND FAILURE POWER CONT LOGIC TRIP l I I LOSS OF BKR FUSE RPS BUS TRIPPED BLOWN Zl# 0Z694tL
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i LOSS OF BKR FUSE BUS Y31 TRIPPED BLOWN .I I l , RELAY 16A-X18X4 16A-K18Xb LOSS OF FAILURE SEAL-IN POWER I FAILURE MECHANICAL l ELECTRICAL i , FUSE LOSS BRKR , OF Y31 TRIPPED BLOWN r i LOSS OF 16A K18X RELAY POWER FAILURE SEE ABOVE LOS!S OF BKR FU'SE BUS Yet TRIPPED BLOWN , -s , LL# 0Z69Ltl
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