IR 05000327/1990032
| ML20058F132 | |
| Person / Time | |
|---|---|
| Site: | Sequoyah  |
| Issue date: | 11/01/1990 |
| From: | Harmon P, Little W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20058F116 | List: |
| References | |
| 50-327-90-32, 50-328-90-32, NUDOCS 9011080106 | |
| Download: ML20058F132 (19) | |
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UNITED STATES V
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. REGION 11
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101 MARIETTA STREET,N.W.
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ATLANTA, GEORGI A 30323
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Report Nos.: '50-327/90-32 and 50-328/90-32
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h Licensee: Tennessee Valley Authority.
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6N'38A Lookout Place-
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R 1101 Market Street i
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Chattanooga, TN 37402-2801
s Docket Nos:. 50-327 and 50-328.
License Nos.:
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Facility.Name:.Sequoyah 8l nits--1 and 2
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' Inspection Conducted: Septemb r, 6, 1990 October, 5, 1990
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k Lead Inspector
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. F arthoM 5enior Resident Inspector.
06td Signed
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- Inspectors:7 i Scott Shaeffer,1 Resident Inspector
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W. S.%itt' e Chief, Project.Section 1 Dat V S~1gned l
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iTVA Projects.
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SUMMARY j
1 < jScope:
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'"?This' announced inspection. involved inspection ~ effort.by the Resident Inspectors
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11nL the l arca r of operational, safety verification - including - control room
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- observations.coperations.- performance. systemilineups, radiation.' protection.
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,? safeguards,t and conditions adverse to qualityf;0ther areas inspected included bsurv'eillance; testing observations, maintenance observations'. review of previous s
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w. l iinspectionLfindings,1 follow-up of: eventsi review of licensee identified itw,-
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f and: review of inspec. tor follow-up; items.-
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LResults:-
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One Lviolation was identified which involved a failure"to conduct a proper
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' _~ post-trip' review priorl to starting the -plant; following a reactor trip on.
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E September 119,:1990,
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_ paragraph 6.d.'.
'.1 A/ noncited violation.was-identified for. failure to properly control-
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~ modifications in ; that : the" licensee-. failed toe identify that a power supply
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.deenergization would-result'in the closing of 2-FCV-74-1? and the loss of
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'Imediate action by operations personnel resulted in
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restoring shutdown cooling within five minutes, paragraph ~6.b.
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An unresolved item was identified, pertaining to the ability of the
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computer systems to provice accurate, definitive information to allow
- post-trip reviews in accordance with the requirements of Generic Letter 83-28, iten 1.2, paragraph 6.c.
I An unresolved ' item was identified regarding adequacy f( the fire watch program in light of apparent discrepancies in the roving fire watch log, and a stationary fire watch found less than fully alert, paragraph 2.d.
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Five. events that occurred during the inspection period are described in paragraph 6.
The events were a TS 3.0.3. entry due to finding a large volume of hydrogen gas in'the charging pump suction, a loss of.RHR shutdown cooling, a
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reactor trip from full power. caused by a loss of a vital. inverter, a reactor
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O trip: from 60% power caused by spurious actuation of the main transformer's
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sudden pressure relay, and a' leaking vent line on the Unit 1 positive
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displacement pump's discharge line.
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The areas of. Operations Maintenance, and Surveillance were adequate and
- fully capable to, support current plant. operations.
The observed activities' of-the control' room operators were professional and well
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REPORT DETAILS 1. -
Persons Contacted
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Licensee Employees c
- R. Alsup, Acting Site Audit Manager
- J. Bynum, Vice President, Nuclear Power Production
W. Byrd, Manager, Project Controls / Financial Officer
R. Beecken, Maintenance Manager..
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'L. Bryant, Work Control Superintendent l
- M. Cooper Site Licensing Manager l
- P. Crabtree, Operations Manager
- T..Flippo, Quality Assurance Manager
- J. Gates. Technical. Support Manager G. Hipp, Licensing Engineer
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W. Lagergren, Jr. 0perations Manager
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M. Lorek, Operations Superintendent
- R. Lumpkin, Site Quality Manager
- R. Proffitt, Compliance Licensing Manager
- R. Rogers, Technical Support Program Manager
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- M. Sullivan, Radiological Control Manager
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R. Thompson, Licensing Engineer P. Trudel, Project Engineer
- C. Vondra, Plant Manager
- C. Whi* emore, Licensing Engineer q
NRC Employees j
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- W.
Little, Chief, Project Section 1
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- Attended' exit interview
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Acronyms and initialisms used in this report are listed in the last-
. paragraph.
i 2.
-Operational Safety Verification (71707)
a.
Cor, trol Room Observations.
The inspectors conducted discussions with control room ' operators,
' verified. that proper control room staffing was maintained, verified
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that access' to the control room was properly controlled, and that
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operator attentiveness was commensurate with the plant configuration
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and plant activities in progress, and with on-going ' control room
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operations.
The operators were -observed adhering to appropriate,
approved procedures, including Emergency ' Operating Procedures, for j
the on-going activities. The inspectors observed upper management in
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the control room on' a number of occasions.
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The inspector verified that the licensee was operating the plant in a normal plant configuration as required by TS and when abnormal conditions existed, that the operators were complying with the appropriate LC0 action statements.
The inspector verified that RCS leak rate calculations were performed and that leakage rates were
within the TS limits.
The inspectors observed instrumentation and recorder traces for
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abnormalities and verified the status of selected control room
annunciators to ensure that control room operators understood the status of the plant.
Panel-indications were reviewed for the nuclear instruments. - the emergency power sources, the safety parameter display. system and the radiation monitors to ensure operability and operation within TS. limits.
No violations or deviations were identified, i
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. Control Room Logs i
- The inspectors observed control room operations and reviewed applicable logs including-the' shift logs, operating orders, night
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order book, clearance hold order book, and configuration log to
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obtain information concerning operating trends and activities.
The
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TACF log was reviewed to verify that the use of jumpers and lifted leads - causing equipment to be inoperable was clearly noted and understood.
The licensee is actively pursuing correction to
. conditions requiring TACFs.
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detail where. the status of out of service safety-related equipment was not reflected in the operator log.
The example occurred on.
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. September 24 when Unit 1 safety injection pump 1BB was tagged out.:
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however, the' out of service status was not indicated in the operator's log.
The pump-was ' properly listed on the equipment
i clearance log, the controlling' document, and the operator immediately'
corrected his log after being informed of'the discrepancy.
Plant secondary chemistry reports were reviewed.
The inspector i
verified that primary plant. chemistry was' within TS limits.
I-l In-addition, the implementation of. the licensee's sampling program j
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was observed.
Plant specific monitoring systems. including seismic,
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meteorological and fire detection-indications were reviewed for l
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operability.
A review of surveillance records and tagout logs.was
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performed to confirm the operability of the RPS.
j No violations or deviations were identified, i
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ERCS System Alignment
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The inspectors walked down accessible portions of the Unit 2 RHR system (shutdown cooling mode) to verify operability, flow path, heat sink, water supply, power supply, and proper valve and breaker alignment.
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In addition, the inspectors verified that a selected portion
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of the containment isolation lineup was correct.
No deviations or violations were identified.
d.
Plant Tours Tours of the diesel generator, auxiliary, control, and turbine-
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buildings, and exterior areas were conducted to observe plant
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equipment: conditions, potential fire hazards. control of ignition sources, fluid leaks, excessive vibrations, missile hazards and plant j
housekeeping and cleanliness conditions.
The plant was observed to
be clean and -in adecuate condition.
The inspectors verified that maintenance work orcers had been submitted.as required and that i
followup activities and prioritization of work was accomplished by the licensee.
Fire Watch Program Discrepancies 1.
On September - 20,1990 at 1:00 p.m., a contractor for the
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NRC operator requalification hspection was conducting a i
practical walkdown with an opuator and a simulator instructor
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which tooke them through the un't 16900 volt shutdown board j
room.
The group noticed that 6 fire watch individual, presumed to be on duty, appeared less than fully attentive.
The group
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lef t the area and returned five minutes later to see i.f the j
individual was'actually incapable of performing his duties. The
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individual appeared in the same state as before.
When the.
operator approached the individual, the fire watch raised his
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When questioned, he stated that he was not asleep. The
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operator informed the individual to walk-around in order to remaim alert. and to remain on duty.
During a subsequent
investigation by the licensee, the fire watch stated that he may i
have dozed off for a minute or two. The individual'had been at that specific post for approximately three hours before the event.
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2.
During a tour of the 669 foot elevation of the auxiliary i
building on October 1, 1990, the inspector entered the Unit l'
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turbine driven auxiliary feedwater pump room at 1:30 p.m.
This area was established as requiring an hourly fire watch patrol due to having one or more of the fire barrier
penetrations non-functional.
The inspector observed that the last entry on the posted fire watch room check sheet was-11:36 a.m. Shortly thereaf ter, the inspector observed a member of
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the licensee's fire watch patrol enter the room and log two entries, which brought the log sheet in line with the actual time.
No indication of the missed log entry was annotated on the. log. The individual then left the area.
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The inspector then reviewed the posted fire watch log in the Unit 2 turbine driven auxiliary feedwater pump room. This area was also designated as requiring an hourly fire watch.
The inspector found that the last entry on the log was 2:38 p.m.,
however the actual time was 1:34 p.m.
This indicated that the fire watch log was ahead of schedule by one hour and four minutes.
Tours were then conducted to review other areas under the hourly fire watch criteria.
No further discrepancies were found.
The inspector informed the Shift Supervisor in the control room of the discrepancies in the fire watch logs.
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SOS immediately took actions to relieve the current fire watch
'from duty and to begin an investigation'as to the cause of the.
problem..
Interviews were conducted with the fire watch individuali The fire watch stated that he had made a double entry on the Unit 1 AFW. room log, however, he did not perceive this to be a problem.
He further stated that the fire watch round in question was performed, however. the reason the log
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entry.was omitted was due to other plant individuals questioning
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him at the same time on a possible fire alarm in.another area of the plant.. The licensee's investigation concluded that the j
hourly fire watch had been performed based on the computer
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record of the fire watch building entries, and personal
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intet views conducted with those personnel involved in the fire i
alarm distraction.
At the end of the inspection period, the licensee was continuing-the-investigation into the event.
The inspectors are concerned with the possibility of programmatic problems within the licensee's fire watch program which may inhibit adequate compensatory measures being performed for TS requirements. The
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resolution of the log discrepancies and the'less than fully-y alert' fire watch will be tracked as URI'327,328/90-32-01, Fire Watch Program.
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- The : inspector visually -inspected the major components for leakage, proper lubrication, cooling water supply, and any general condition that might prevent fulfilling their functional requirements.
The inspector observed shift turnovers and determined that necessary
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information concerning the plant systems status was addressed.
No violations or deviations were identified, e.-
Radiation Protection
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The inspectors observed HP practices and verified the implementation of radiation protection controls.
On a regular basis,. RWPs were - reviewed and specific work activities were monitored to ensure the activities were being conducted in
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accordance with the applicable RWPs.
Workers were observed for proper frisking upon exiting contaminated ceas and the radiologically controlled area.
Selected radiation protection
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instruments were verified operable and calibration frequencies were reviewed.
RWP 90-2-20002, General Inspection, was reviewed.
No violations or deviations were identified.
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Safeguards' Inspection
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.In the' course of the monthly activities, the inspectors included a review of the. licensee's physical security program. The performance-
of'various shifts of the security force was observed in the conduct
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of daily activities including: protected and vital area access controls, searching of personnel and packages, escorting of visitors,
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badge issuance and retrieval, and patrols and compensatory posts.
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The' inspectors observed protected. area lighting, and protected and.
vital areas barrier integrity.
The inspectors verified interfaces between the security organization and both operations and maintenance.
The Resident Inspectors visited central alarm stations and verified protection of Safeguards Information.
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No violations or deviat' ions were identified.
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Conditions Adverse to Quality The inspectors reviewed selected items. to determine that the
' licensee's problem identification system as defined in Site Standard Practice SSP-3.2, Problem Reporting, Evaluation, and Corrective
' Action; was functioning. CAQR's were routinely reviewed for adequacy in addressing a, problem or event.
A sample Of the-following
documents were reviewed for adequate handing:
4 Work Requests
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Conditions Adverse to Quality, CAQRs
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Radiological Incident Reports
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Problem Evaluation Reports.
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Correct-on-the-Spot Documents
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Licensee Event Reports
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Of the items. reviewed, each was found to have been identified-
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by the licensee' with immediate corrective action in place.
/ For those. issues that required long term corrective action the~
licensee was making adequate progress.
No violations or deviations were identified.
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No adverse trends were identified in the operational safety verification area. General conditions in the plant were adequate.
Radiation protection and security were adequate.
3.
Surveillance Observations and Review (61726)
Licensee activities were directly observed / reviewed to ascertain that surveillance of safety-related systems and components was being conducted in accordance with TS requirements.
The inspectors verified that' testing was performed in accordance with adequate procedures; test instrumentation was calibrated; LC09 were met; test results met acceptance criteria and were reviewed by personnel other
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than the. individual directing the test; deficiencies were identified, as appropriate, and any deficiencies identified during the testing were properly reviewed and resolved by management personnel; and system restoration was adequate.
For completed tests, the inspector verified that testing frequencies were met and tests were performed by qualified individuals.
The = following activities were observed / reviewed with no deficiencies
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identified except as noted:
a.
51-26.2, Loss of Offsite Power with Safety injection Diesel Generator Test.-
The= purpose of this SI was to perform a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> endurance run of the selected emergency diesel generator.
No problems were identified-with; the perfomance of the test.. 'During the extended run.of the diesel.the inspector noted an undetermined amount of fuel oil which had surfaced.on the reactor side of the diesel building. The spill was in two-locations, each approximately a five by ten foot area and located in. a rain water runoff path downhill from the diesel building.
The -inspector questioned whether the integrity of any underground or DG building -fuel oil tanks had been breached and informed the system engineer of the problem. The licensee was aware
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of the situation and had previously determined that the oil runoff path was following the ground grading from the opposite side of the
diesel building where tank refilling and, transferring takes place.
Prior to the oil surfacing, the licensee had been performing seven day tank. cleaning whichiinvolved numerous transfers of fuel oil between tanks.
During the process, an overflow sump capacity was exceeded and small amounts of excess fuel oil drained into the ground and surfaced on the other side of the building, downhill of the sump.
The licensee had notified the Environmental Protection Agency of the oil released and it was agreed to allow the oil to evaporate.
The inspector had no further concerns.
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SI-40.1, Centrifugal Charging Pump Casing and Discharge Venting, i
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The scope of this procedure was broadened by the licensee due to the accumulation of hydrogen gas recently found in the centrifugal charging pump suction lines as addressed in NRC IR 327,328/90-28.
The procedure now incorporates a process for optional venting of the
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charging pump's suction.
The licensee has been venting the suction lines on a routine schedule and also has been maintaining a special log in the CR for each unit in order to identify any adverse trends in the amount of gas vented.
Since the positive displacement pump has been used only small amounts of gas have been vented, with the majority of the ventings producing zero gas.
The inspectors will continue to monitor the licensee's action until a long term solution
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is in effect.- (See paragraph 6.a.)
No adverse trends were identified in the area of surveillance performance during this inspection period.
The area of surveillance scheduling and management was observed to be adequate.
No deviations or violations were identified.
4.
MonthlyMaintenanceObservationsandReview(62703)
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Station maintenance-activities on safety-related systems and components were observed / reviewed to ascertain that they were conducted in accordance
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with approved procedures, regulatory guides, industry codes and standards,
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and in conformance_with T.S.
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.The following items were considered during this review:
LCOs were met
_while components or systems were removed from-service, redundant components were operable, approvals were obtained prior to initiating the work activities were accomplished-using approved procedures and were inspected as. applicable, procedures used were adequate to control the activity, troubleshooting activities 'were -controlled and the repair records accurf tely - reflected the _ activities, functional testing and/or calibrations vee _ performed prior to ~ returning componentsL or systems to Lservice..QC wrds were maintained, activities -were accomplished by l qualified panonnel, parts and materials used were properly certified, radiological' controls were implemented, QC hold points were established
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where. required and were observed, fire prevention - controls were
implemented. outside : contractor. force activities were controlled in accordance with the-approved QA program, and housekeeping was actively -
pursued.
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WorkT requests MMG/PM-02538-2, CVCS Grinnell Valve Diaphram Inspection, was reviewed..
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No deviations or violations were-id'entified.
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- NRC Inspector Follow-up Items, Unresolved Items, Violations (92701, 92702)
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(0 pen)TMIItemII.F.1,2.FContainmentHydrogenMonitor The outstanding work on this item was being tracked by URI 327/86-62-01, Adequacy of H2 Analyzer to Meet Operability Requirements of Technical Specification (TS) 3.6.4.1.
This issue was originally identified on Unit 2 and was resolved prior to Unit 2 restart. The purpose of this review is to evaluate the corrective actions to resolve this issue on Unit 1.
The issues which. remain outstanding on the Unit 1 installation were discussed in Revision 1 of.LER 87-077.
Those issues involved line slope
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(i.e., traps) and containment isolation.
The licensee committed to correcting the. line slope to meet manufacture requirements and to reevaluate and replace the containment isolation valves for the associated penetrations.
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The inspector reviewed the work plan which rerouted the sample tubing 'd
installed the inside containment solenoid operated isolation valves. This
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WP (229-01):was written to implement the mechanical portions of DCN 229 and the electrical portion was covered by WP 229-02.
Additionally, DCNs
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.152, 230, 231, and 232 were issued to address other modifications associated with-H2 analyzers.
Step 3 of WP 229-01 installed the solenoid
. valves that replaced.the inboard air operated. isolation. valves, the solenoids' for;the outboard isolation valves and the test connections for l,
those valves.
The isolation valves involved were 1-FSV-43-201, -202, l-207, -208, -450 451, -452, and -453.
Step 4 of the WP rerouted the q
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g sample lines to reduce the traps.
L Based'on the above review'the inspector determined that corrective' actions li
. associated with LER 87-077 were implemented.-
However, the inspector
. determined that the control room valve labels. still depicted the
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' containment isolation valves as air operated valves even though step 11 of
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-the -work plan required re-labeling of these valves.
Additionally, WP -
229-011 is still open even though the work.was performed and field
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L completed in the September 1988 timeframe.
Correction of the valve laoeling problem and closure of the workplans i
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' associated with this modification is the only outstanding work to close thisitem(TMIII.F.1.2.F).
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EventFollow-up(93702)
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On September.6, 1990, the licensee entered _T.S. 3.0.3 on unit 1 due-to an unant',yzed condition where the amount'of hydrogen-gas that had accumulated in the suction flowpath;to the centrifugal charging pumps
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exceeded the' maximum amount recommended by the. pump manufacturer.
The abnormal gas entrapment was discovered by the licensee during UT testing of the portions of the RHR discharge to CCP suction lines which were subject to gas buildup.
The occurrence of. hydrogen gas accumulation and generation was previously addressed in NRC IR 327,328/90-28.
Upon identifying the problem, the licensee
.immediately began appropriate venting which included cycling various i
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valves.in the suction flowpath to purge the trapped hydrogen through the RHR spray header to the containment.
The licensee exited the action statement when the venting was completed.
No TS action i
statement time limitations were exceeded.
Since this evert, l
operation of the positive displacement pump has greatly
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reduced the amount of degassing and the gas accumulation as evidenced
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by the reduced need for venting. The licensee will issue a voluntary LER on the event.
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On September 11,1990, Unit 2 was operating in mode 5 on shutdown cooling with two RHR pumps running.
The licensee was performing modifications for the incorporation of the Unit 2 Eagle 21 process instrumentation racks in the auxiliary instrument room. During these modifications, when power to RPS instrument rack 9 was removed -it also removed the power supply to bistable 68-68E which is the bistable for the auto closure interlock function.
This function
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provides overpressure protection for the RHR. system by closing the
! suction valves -from the RCS on receipt of'a.high pressure signal.
When power was lost, the close signal was actuated, shutting
L 2-FCV-74-1.
This-valve is one of two RHR suction valves in series which take suction from the hot leg during the shutdown cooling mode of operation.. The second valve, 2 FCV-74-2, was tagged open during the evolution.
The. loss of RHR suction ~ constituted a loss of shutdown cooling for the reactor.
. At li32 p.m., the operators received the first-indication of the problem through a CR annunciator E
indication of RHR discharge pressure high mini-flow condition,
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indicating =a potential loss of shutdown cooling.
The operators
checked the RHR flowpath andcobserved 2-FCV-74-1 going closed.
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Unable to establish suction, the operators entered A01.14.(a.),
Loss of RHR Shutdown Cooling.
The operators imediately secured both-RHR pumps to mitigate any pump damage due to the lack of RHR suction. _ The operators, aware of-the ongoing. Eagle 21 modifications
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at the time of the event, realized that 2-FCV-74-1 was receiving-a false high pressure closure signal... Consequentt, an operator was
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dispatched to the reactor MOV board room to transfer 2-FCV-74-1 c
control power to auxiliary mode which selected pressure indication from an alternative pressure transmitter.
2-FCV-74-1 was then
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reopened ' and the A RHR pump was started.
After observing appropriate pump operation, the B RHR ' pump-was also started.
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. total time in which a-loss of shutdown cooling existed was from 1:33 p.m.,ito 1:38 p.m.
RCS temperature during the event increased at a rate of'l degree F per minute with a total of 5 degree F increase-over the entire transient.
Unit I remained at 100% power and was not affected throughout the event.
i The licensee determined that the cause of the event was that-i
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2-FCV-74-1 was not identified in the impact review as being
one of the control functions being deenergized and therefore
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was.not tagged open.
Additional information listing the control j
functions for the RPS rack involved in the Eagle 21 modification j
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1 was provided to the control room operators as immediate corrective action by the engineers responsible for the modifications.
Further investigations are still underway.
The auto closure feature of the subject valves was removed on Unit I and is due to be removed from Unit 2 during the current refueling outage.
Following the event, the
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licensee made a 10 CFR 50.72 one hour report to the NRC due to a
declaration of an Alert classification from the loss of capability to
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remain in cold shutdown per EPIP-1, Emergency Plan Implementing Procedure. The licensee will submit an LER on the event.
i-The impact evaluation performed to assure the work plan associated with the modification could be safely implemented did not identify
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the effect on 2-FCV-74-01.
As a result, valve 2-FCV-74-01 received
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an isolation signal that led to the loss of shutdown cooling.
Impact evaluation for implementing a modifications work plan is part of the design change process.
In accordance with 10 CR 50, Appendix B, Criterion III, design changes, including field changes shall be subject to design control measures commensurate with those applied to the originial design and shall be approved by the organization ' that performed the original design.
The work plan information used to perform the impact evaluation indicated the
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I effect: on 2-FCV-74-01, but the impact evaluator. did not recognize and transmit' this information onto the impact evaluation sheet.
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Although the workplan information could have more clearly identified C
the effect on the valve, the incident is considered a result of human error on the part of the impact evaluator. This is identified as; a violation, NCV 327, 328/90-32-04.
This licensee identified
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violation is not being cited because criteria specified in Section
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-V.G.1 of the NRC Enforcement Policy were satified.
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'On September 14, 1990, Unit I tripped from approximately 98% reactor
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At the time of the trip on Unit 1. Unit 2 was in
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mode 5 in preparation for the U2 cycle 4 refueling outage. The trip E
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signal was determined to be from a low-low steam generator level in loop 2.
The cause of the transient which precipitated the trip was the failure of the 1-11 vital instrument inverter, which had just
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L been placed in service after routine. maintenance.
The 1-II vital
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L inverter normally supplies the 1-11 vital. instrument board which
. feeds the protection and control instruments and devices associated L
with protection. set II.
During the maintenance activities on the inverter, power to the vital instrument board was being supplied from the alternate supply, a 480/120 volt transformer.
When the power a
P
'
supply was transferred to the inverter, the inverter failed, resulting in loss of power on the 1-II vital instrument board.
When vital instrument board 1-II was deenergized, several components
'
failed, including the main feedwater regulating valves for all four steam generators.
The feed valve for #2 steam generator had a previously identified air leak on the valve's air positioner.
The feed valves for all steam generators drifted shut on loss of power, but the #2 feed valve shut faster than the others. At the same time, the main feed pumps were reducing speed to a minimum p'>mp
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differential pressure due to a failed input to the pumps' speed control circuit in the form of a failed turbine impulse pressure
_
signal from the vital board.
The combination of decreasing feed pressure and shutting feed valves caused the steam generator levels to drop rapidly.
The #2 S.G. level was later determined to actuate
_
the reactor trip circuit, based on the Sequence of Events and Post-trip Review programs supplied by the Prodac 250 station computer. The alarm annunciator First Out alarm for both the turbine T
trip and the reactor trip was acknowledged and silenced prematurely by the reactor operator before it was determined which of several
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trip alarms was the actual initiator of the turbine and reactor
trips.
As a result, investigation of several key transient charts and review of the Sequence of Events (SOE) printout to determine
,
the trip initiator was required to detennine the actual initiating trip signals.
This took several hours to complete. The licensee is evaluating the operator's response to the ' trip including the premature acknowledging of the alarms before the unit was stabilized
!
and the First Out alarms noted.
l
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The unit responded normally with the exception of a steam Power
!
Operated Relief Valve (PORV) on loop 2 remaining open several seconds j
after the other PORVs had closed.
The valve's setpoint controller was reset by the operator, and the valve tM n closed. Another noted discrepancy )in the' plant's response was actuation of the Main (22.5/S00 kv transformer "A" phase gas. relay.
This relay provides
[
generator protection on' sudden transformer. oil surges, which could
'
indicate phase faults.
The gas relay actuated three minutes after
"
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the trip, according to the SOE program.
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The~SequenceofEvents(SOE)printoutandPost-tripReview(PTR)wert J
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reviewed by;the inspectors and several discrepancies were noted. The
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E
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SOE program records the' sequence of status changes of contacts directly or closely associated with reactor trips.
The' SOE prints.
out the contact status chuges beginning with the first actuatation received.
Both contact closures and openings (set / reset) are
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recorded.
The PTR prints the values of approximately 40 pre-selected system parameters every 8 seconds. sections, the pre-trip set contains +" prog The parameter values for five minutes prior to the trip breakers opening.
The Post-trip section
prints the values of the same parameters for ten minutes after the L
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trip.
This program is extremely helpful in determining the course and cause of a reactor trip.
For the reactor trip in question, the
-
't.
-I, trip occurred at 4:13:06.
The PTR for the pre-trio block ended at
.
f
'4:13:03,'3 seconds prior to the trip.
The Post-trip block began at i
4:13:11, S seconds after the trip. The result was an 8 second gap for o
>
which no parameter values were printed. This period contained vital
information about 'the trip and the progress of several key i
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parameters.
In particular, the parameter determined to initiate the reactor trip. Stean Generator #2 level, exhibited questionable
,
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trends.
At the last available scan in the pre-trip section the #2 levels were at 30%, 32% and 28% on the three levels being monitored.
The previous scans, 8 seconds apart, indicate levels decreasing at
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approximately 1%/sec.
This rate is consistent with a loss of feed
,
event.
The level trend was hand-plotted and indicated that the trip
'
occurred at a level of approximately 25% according to the data from l
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the PTR.
The licensee's investigation into the performance of the SOE and PTR programs indicates the programs may not be capable of
'
receiving, storing end retrieving necessary information when subjected to a transient of this nature.
Namely, the simultaneous receipt of a large number of protection set inputs such as occurs on a loss of a vital inverter.
The programs appeared to become overloaded and resulted in large sections of data being lost.
For instance, the SOE program did not identify. that the reactor trip
.
'
-breakers opened, which in fact the operatort had verified.
Several other. bistable actuations were also not prMed in the SOE.
The
!
other program, the PTR, appears to have a design flaw that initiates memory actuation that coincides with the scan time of the SOE and i
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therefore can have a time lag of as much as 7 seconds.. This time lag is not consistent; and cannot be displaced to correct for the
.j
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difference.
A separate data collection program for trip analysis is
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available' via a program in the Technical Support Center (TSC)-
. computer.
This computer is separate from the Prodac computer, but
,
receives. essentially the same inputs.
The program supplied by the
.TSC com) uter had time gaps of more than 8 minutes, and was useless
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for analysis of the trip.
i The ability of the ' plant computers and the programs = designed to i
provide pre and post trip information is under investigation by the j
L licensee.
CAQR SQP-901514 has been written to describe the problems l
.and prescribe? corrective actions.
The inspector questioned the
. ability'of the computers and' programs to meet the requirements of-Generic Letter 83-28, item 1.2.
This ' item will be tracked as an Unresolved Item URI 327'328/90-32-02.
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d.
On September 19, _ 1990, at 3:57 a.m., Unit ~1 tripped from approximately 60% power.
The:cause.of the trip was determined to be i
l L
an actuation of the main transformer A phase sudden pressure relay,
'
E which actuates the main-generator's protective relays and trips the
,
With power above 50%, the turbine trip initiates a
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The A phase transformer had been replaced by the.
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installed spare trarsformer following the reactor. crip on-September 14, 1990, described above.
The spare transformer had
)
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been placed in service to allow replacement of the low voltage bushings' on the AL phase transformer. :The bushings had: indicated
,
L minor leaks following the September 14 reactor trip.
Operators-
,
responded to the trip and stabilized the plant at normal Hot Standby conditions.-
All protective and control functions operated as-designed.
Operators found the A and B phase sudden pressure relays I
actuated.
Operators were able to reset. the B phase relay
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.immediately, but the A phase relay could not be reset for'
approximately 24 minutes.
The sudden pressure relays function to detect phase to ground faults in the main transformers by sensing either a rapid pressure increase in the transformer oil, or the accumulation of gases, indicative of oil breakdown due to a fault.
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Later investigation of the sudden pressure relays themselves revealed that the terminals of the relay were heavily corroded and caused an intermittent ground path which energized the relay.
This relay and the entire spare transformer had presumably been checked out
prior to - being placed in service, but the degraded terminal connections were not noted in the checkout report. After consulting with the manufacturer, Asea, the licensee implemented a TACF to remove the relay's trip function and wire the trip contacts inte an
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annunciator circuit.
This decision was based on a previously identified problem by the vendor. This involved the oversensitivity of the ' relay to changes in the oil cooling pump status. Turning all the; pumps off at ' once causes the. relay to actuate unnecessarily.
This had been noted at Sequoyah on previous occasions when the cooling pump power supplies were' momentarily lost during bus
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transfers 'following reactor trips from other causes.
Asea had
. notified some licensees, including Brown's Ferry, of this problem and had proposed the elimination of the trip from. the system.
The.
n inspector reviewed the TACF and its' supporting safety evaluation.
Backup protection of the transformer and the generator-remain active in the form of a separate pressure relay.
?
The investigation / post trip review team was assembled at approximately 7:00 a.m.
and was instructed to complete the investigation before peak xenon-occurred, if possible.
This would allow the plant to restart prior to the xenon peak which occurs between 8 and 12. hours after a trip, The team was not able to complete and.present to PORC a post trip report until approximately
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-2:00 p.m. on September 19 and PORC approved the trip report at 2:30 p.m., the' same day.
The Unit 1. reactor was restarted at 8:43 p.m.,
on September 19 based on the completed, PORC approved Post Trip
,
Review.
The Post Trip Review is required to be completed 'and PORC
approved before plant startup. The Post Trip Report for.the trip did'
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not complete a root cause. investigation, and in fact concluded in the
executive summary that the cause for the sudden pressure relay's
actuation was still under investigation.
Although a complete root
~
cause determination is required in several places in the PTRR procedure, AI-18.78, PORC approved the restart of Unit I at approximately 2:30 p.m., and Unit 1 entered Mode 2 at 8:43 p.m.
A revision to the PTRR was completed at approximately 11:00 p.m., and contained a root cause-assessment of the sudden pressure relay's actuation.
The inspector discussed the interpretation of Al-18.78 with the' plant manager regarding the distinction between the plant and the reactor.
Al-18.78, section 6.1.1 states that " Plant Restart shall be authorized upon completion of the PTRR by PORC and the Plant Manager."
The Plant Manager stated that a PORC approved PTRR would be completed prior to starting the reactor.
Following the plant startup, the inspector reviewed the 'PTRR and f
determined that the-reactor had been restarted with a PTRR which had
'
not completed a root cause assessment. The issue was then discussed with the Plant Manager.
The Plant Manager said he had interpreted
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Al-18.78 as allowing the restart of the reactor if the PTRR had i.]
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concluded that only secondary sidt anomalies remained to be resolved, and that open items concerning the secondary side (e.g. the root cause of the sudden pressure relay actuation) could be completed after the reactor side of the plant had been restarted.
The inspector pointed out that the procedure does not make a distinction between plant startup and reactor startup, Further, AI-18.78 requires a root cause determination to be complete and PORC approved prior to authorizing startup.
In any case, the PTP,R approved by PORC did not contain a root cause determination as required by AI-18.78.
Failure to follow procedure AI-18.78, Post '
Trip Review, is a violation and. will be tracked as Vio 327,328/90-32-03.
The Plant Manager informed the inspector that a special review or investigation into the circumstances of the two trips has been requested.
The items to be addressed include the problems the inspector identified with the trip sequence of the first trip, the
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gaps in the computer-generated Post-trip review, performance of the operator who acknowledged the first-out alarms prior to plant stabilization during the first trip. the inadequate checkout of the spare. transformer, and the startup of the reactor af ter the second trip without a. rout cause determination -in.the PTRR.
The Plant Manager requested NMRG to conduct a review of this matter.
e.
On September 24, 1990, Unit l' was operating at 100% power with CVCS flow provided-from the positive displacement pump.. While on routine rounds, an auxiliary operator identified a small leak on a vent line attached to the 3 inch discharge piping of the IC PD pump.
Upon notification of 'the leak, the CR operators started the 1A CCP and secured: the PD pump for repairs.
Due to an ongoing. hydrogen accumulation problem. (see paragraph 6.a.) the licensee was venting the available CCP-suction piping on a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> frequency.
The frequency was adjusted to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> based on the phenomenom of increased gas generation with the operation of.the CCPs-observed earlier by the licensee.
The licensee identified the leak on a welded attachment which secures the vent line to the discharge piping
.(weldolet).
The unit will continue to operate on the 1A CCP until repairs can be completed to the PD pump vent line.
7.
. Exit Interview (30703)
The inspection scope and findings were summarized on October 4, 1990, with those persons indicated in paragraph 1.
The Senior Aesident Inspector described the areas inspected and discussed in detail-the. inspection findings listed below.
The licensee
' acknowledged the inspection findings and did not identify as proprietary any of the material reviesed by the inspectors during
,
the inspection.
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Inspection Findings:
One violation was identified involving the failure to implement a post-trip review as required by AI-18.78.
.VIO 327,328/90-32-03, Failure to implement a Post-Trip Review i
One noncited violation was identified involving an inadequate impact l
review resulting in the loss of shutdown cooling for five minutes.
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'NCV 327, 328/90-32-04, Inadequate ' pact Evaluation.
Two unresolved items were identified.
URI 327,328/90-01, Fire Watch Program
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URI 327,328/90-02, Computer Adequacy to Provide Post-trip Reviews.
During the reporting period, frequent discussions were held with ~
the < Site Director, Plant Manager and other managers concerning
,
- inspection findings.
y
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8.1 List of. Acronyms and'fnitialisms y
ABGTSi LAuxiliary Building Gas Treatment System Auxiliary Building Isolation ABI
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ABSCE-Auxiliary Building Secondary Containment Enclosure Auxiliary Feedwater AFW
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AI-
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Administrative Instruction.
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A01. -
Abnormal Operating Instruction i
AUO' -
~ Auxiliary Unit Operator
.
.
ASOS -
Assistant Shift Operating Supervisor
'
ASTM.--
-American Society-of Testing and Materials Boron Injection Tank BIT
.
-BFN -:
Browns Ferry Nuclear Plant
'
C&A.-
Control-and Auxiliary Buildings
.l CAQR.--
Conditions Adverse to. Quality Report Component. Cooling Water System j
--
,
Centrifugal Charging Pump l
l CCP
-
L CCTS -
Corporate Commitment Tracking System Code of Federal Regulations
CFR
-
COPS -
Cold Overpressure Protection System j
.
CSSC -
Critical Structures Systems and Components
,,
!s
'CVCS -
Chemical and Volume Control System i
Containment Ventilation Isolation
!
k
.CVI
-
'
DC Direct Current
!
-
Design Change Notice
.DCN
-
Diesel Generator-
<
DG-
-
'
Division of Nuclear Engineering DNE
-
ECN -
Engineering Change Notice
.ECCS -
Emergency Core Cooling System Emergency Diesel Generator j
-
Emergency Instructions j
l El
-
q J
__
.,........,,, _.........,,.
n;_4=-
,s m
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'l Emergency Notification System ENS
-
E0P -
, Emergency Operating Procedure
'
Emergency Operationg Instruction E0
--
_
,
ERCW -
Essential :r Cooling Water ESF -
Engineered tafety-Feature
. Flow Control Valve FCV
_
>>
-
m
- FSAR -
Final' Safety Analysis Report GDC. --
General; Design Criteria General Operating-Instruction G0I
-
Generic Letter GL
-
HVAC -
- Heating Ventilation and Air Conditioning g
Hand-operated. Indicating Controller HIC
-
-
-Hold Order H0
-
. HP
'
Health Physics
-
ICF
-
Instruction Change ivrm IDI; -
Independent Design Inspection h3 NRC Information Notice IN
.-
'
IFI -
Inspector Followup' Item
' Instrument Maintenance-IM'.-
-
IMI. -
Instrument Maintenance Instruction
Inspection Report
-
IR
,
_
KVA o -
Kilovolt-Amp ;
KW-
Kilowatt.
-
'
Kilovolt
.
KV
-
'
'
.LER.--
Licensee Event-Report
"
'
,
LCO
-
Limiting Condition for Operation-
<
-
. LIV
-
Licensee Identified Violation
- LOCA,-:
Loss of' Coolant Accident
-
.MCR: -.
Main Control Room
-
MI-
--
. Maintenance Instruction
, -
Maintenance Report
.. f
-
-
v
'hSIV' -
Main" Steam Isolation Valve
NRCLBulletin
NB _-
,
~NOVE--
NQAM
-c
Nuclear Quality Assurance Manual
E
-NRC --'
Nuclear Regulatory Corrmission
.
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y'
OSLA -
. Operations Section Letcer - Administrative
'OSLT -
Operations Section Letter - Training-
-
,
Office'of Special Projects
-
.
-
Precautions', : Limitations, and Setpoints
=
,
Preventive Maintenance
PM'
-
I
PPM 1
Parts Per Million-
--
gm
Post Modification. Test
k
PMT:
-
iPORC -'
qPlant Operations 1 Review Conunittee
h
P0RS -
Plant Operation Revisw Staff
&
u
-
f'
'PRD
Problem Reporting Docunent
-
Potentially Reportable Occurrence-
-
-PR0
-.
_
Quality Assurance-
. A-
Q
--
<
_
LQuality Control
s-
QC=
-
~ Radiation Control Area
_
RCL
-
,
-
RCDT --
Reactor Coolant Drain Tank
- Reactor Coalant Pump
=
-
RCS --
s
Regulatory Guide-
--
_
l
- _
-
-
_
~p
.........
o
.
-
.
.
-
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,.
,
.
-
8 - i
RM'
Radiation Monitor
-
Reactor Operator
R0
-
Rod Position Indication
d
-
_
RPM. -
Revolutions Per Minute
Resistivity-Temperature Device Detector
-
.RWP' -
Radiation Work Permit
-
,
RWST -
Refueling Water Storage Tank
Safety Evaluation Report
-
-
-
~SI
Surveillance Instruction
-
~Special Meintenance Instruction
SMI
-
System Operating' Instructions
S01
-
Shift Operating Supervisor
SOS
-
sam -
Sequoyah Standard Practice Maintenance
'
SQRT -
Seismic Qualification Review. Team
Surveillance Requirements
SR-
-
' Senior Reactor Operator-
-
SR0
'
-
SS0MI-
iSafety Systems Outace Modification Inspection
r
SSQE -
Safety System Quality Evaluation
SSPS
'
-Solid State Protection System
-
STA -
' Shift _ Technical Advisor
.Specia' Test 1 Instruction
-
i TACF -
Temporary Alteration Control Form
.
ETAVE -
Average: Reactor; Coolant Temperature
~
TCAFW-
Turbine Driven Auxiliary Feedwater
Technical Instruction.
TI
-
TREF
.
Reference' Temperature'
-
- TROI
- --.
Tracking Open Items
'TS '.'
Technical: Specifications
sTVA. -
Tennessee' Valley. Authority-
--
UHli -
. Upper-Head Injection
- ~
UOJ
Unit 0perator
-
URI:
'
Unresolved Item
-
-
- g
USQD --
Unreviewed Safety Question Determination
-
VDC1 -
Volts Direct Current -
VAC1.-
Volts Alternating Current
=
'
.WCG' -
Work Control Gro9p
. Work Plan
WP
,
Work Request
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