IR 05000247/1987004
| ML20204F315 | |
| Person / Time | |
|---|---|
| Site: | Indian Point  |
| Issue date: | 03/16/1987 |
| From: | Norrholm L, Roxanne Summers NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20204F241 | List: |
| References | |
| 50-247-87-04, 50-247-87-4, NUDOCS 8703260171 | |
| Download: ML20204F315 (14) | |
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U.S. NUCLEAR REGULATORY COMMISSION DCS 50247-870203 870210 860923 861020 861106 860916
REGION I
Report No.
50-247/87-04 Docket No.
50-247 License No.
DPR-26 Licensee:
Consolidated Edison Company of New York, Inc.
4 Irving Place New York, New York 10003 Facility Name:
Indian Point Nuclear Generating Station, Unit 2 Inspection at:
Buchanan, New York Inspection-conducted:
February 3,1987 - March 2,1987 Inspectors:
L. Rossbach, Senior Resident Inspector P. Kelley, Resident Inspector G. S. Barber, Reactor Engineer (Examiner)
D, 1. L 4/o Reviewed by:
R. Summe'rs P ect Engineer
/date Re
- tor r j ct Sec 1 28, DRP Approved by:
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LeifNorfolm, Chief
'da te Reactbrlrojects Section 28, DRP Inspection Summary:
Inspection on February 3,1987 - March 2,1987 (Report No. 50-247/87-04)
Areas Inspected: This inspection report includes routine daily inspections, as well as unscheduled backshift inspections of onsite activities, and includes the following areas: operations; maintenance; surveillance, review of 8703260171 870318 PDR ADOCK 05000247 G
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periodic and special reports; licensee event report followup; TI 2500/16 followup, and trip reduction activities. The inspection involved 175 hours0.00203 days <br />0.0486 hours <br />2.893519e-4 weeks <br />6.65875e-5 months <br /> by the inspectors.
Results: The licensee completed a one week maintenance outage (Section 2.3).
During the outage, the motor-driven auxiliary feedwater pumps failed a j
surveillance test and were declared inoperable.
The cause of the test failure i
was determined to be eroded valve seats which allowed flow through two closed valves (Section2.3.1.) A unit trip occurred on February 10, due to operator error (Section 2.3.2.)
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DETAILS 1.
Persons Contacted Within this report period, interviews and discussions were conducted with members of the licensee management and staff to obtain the necessary information pertinent to the subjects being inspected.
2.
Operational Safety Verification 2.1 The inspectors conducted routine entries into the protected area of the plant, including the control room, the containment building, fuel storage building, and auxiliary building. During the inspection activities, discussions were held with operators, technicians (HP & I&C), mechanics, foremen, supervisors, and plant management. The purpose of the inspection was to affirm the licensee's commitments and compliance with 10 CFR, Technical Specifications, and Administrative Procedures.
2.1.1 On a daily basis, particular attention was directed in the following areas:
Instrumentation and recorder traces for
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abnormalities; Adhercnce to LC0's directly observable from the
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control room; Proper control room and shift manning and access
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control; Verification of the status of control room
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annunciators that are in alarm; Proper use of procedures;
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Review of logs to obtain plant conditions; and,
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Verification of surveillance testing for timely
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completion.
2.1.2 On a biweekly basis, the inspectors:
Verified the correct application of a tagout to a
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safety-related system; Observed a shift turnover;
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Reviewed the sampling program including the liquid
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and gaseous effluents; Ver.ified that radiation protection and controls were
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properly established; Verified that the physical security plan was being
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implemented; and, Reviewed licensee-identified problem areas.
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2.1.3 In completing the above inspections, the inspectors reviewed the following documents:
Selected Operators' Logs
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Senior Watch Supervisors (SWS) Log
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Jumper Log
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Radioactive Waste Release Permits (liquid & gaseous)
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Selected Radiation Work Permits (RWPs)
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Selected Chemistry Logs
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Selected Tagouts
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2.2 PRA Based System Walkdowns As discussed in Inspection Report 247/86-25, the inspectors are using probabilistic risk assessment (PRA) based inspection guidance in performing system walkdowns. This guidance helps to focus NRC inspection resources toward risk significant items.
During this inspection period, walkdowns were performed on the cold leg accumulators, auxiliary feedwater, containment spray, containment fan cooling, and safety injection systems.
These systems were found to be properly lined up and operable.
During the walkdown of the cold leg accumulator system, the inspector noted that the handle on motor-operated valve 894A (an accumulator discharge stop valve) was chained. This should not af-fect the operability of the valve, since the handle does not turn when the valve is operated provided the handle's clutch is not engaged.
The clutch spring returns to the disengage position and was, therefore, probably not engaged. The inspector could not verify this due to poor visibility because of wearing a full face mask respirator and the valve location was high in the overhead.
The licensee subsequently removed the chains from the 894 valves.
2.3 Maintenance Outage and Operational Events At the beginning of this inspection period, the plant was in hot shutdown for a scheduled maintenance outage. The main purpose of
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the outage was to inspect the electrical generator.
Prior to the outage, the plant was limited to 97% power in order to limit electrical generator vibrations to 18 mils. The generator inspection identified that several windings were loose; they were then tightened. After the outage, the plant was able to return to 100% power with electrical generator vibrations less than 7.5 mils.
The outage work also included reseating 40 valves in the main steam system and repairing steam leaks.
Post-outage heat balances showed that this work reduced the heat rate by about 100 Btu and increased capacity by about 8 MWe. Also, during the outage, the licensee performed several refueling (18 month) surveillance tests. These tests were done because several surveillance tests will exceed their maximum test interval before the next refueling outage (scheduled to begin about November 1, 1987). On February 3, 1987, the licensee declared auxiliary feedwater pumps #21 and #23 inoperable when they failed to pass their refueling surveillance test. This item is described in more detail below. The maintenance outage was completed and the plant was brought critical at 12:54 p.m. on February 7.
The generator was synchronized to the bus at 8:28 p.m.
and the unit reached 100% power at 12:30 p.m. on February 8.
At 10:03 p.m. on February 10, the unit tripped due to an operator error. This event is described in more detail below.
The unit was brought critical at 3:28 a.m. on February 13 and reached 100% power at 9:50 p.m. on February 15. The unit operated at full power for the remainder of the inspection period.
2.3.1 Auxiliary Feedwater Pumps #21 and #23 Declared Inoperable At 5:30 a.m. on February 3, the licensee declared #21 and
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Pump #21 failed to produce the required differential head of 2675 feet (2642.6 feet was measured).
Pump #22 failed to produce the rcquired flow of 451 gpm (423.8 gpm was measured).
The test, "PT-R7A Motor Driven Auxiliary Boiler Feed Pumps Full Flow," is normally performed each refueling outage; however, it was performed durit;g the February maintenance outage because the interval between refueling outages will exceed the required test interval of 18 months.
To confirm the test results, test PT-R7A wat performed a second time at 11:00 a.m. on February 3.
Again both pumps failed. Although the motor-driven AFW pumps failed to meet the test requirements, they were still able to supply sufficient flow to maintain the plant in hot shutdown. Steam-driven AFW pump #22 remained operable until plant cooldown. At 11:30 p.m. on February 3, the plant was cooled below 350 F. in accordance with Technical Specification g c,,*-
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>n Investig' tions df, the test failures det' ermined that valves a
BFD-77 and 78 were leakir.g by. These manually operated, locked closed valves are in the recirculation line from
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the AFW pumps to the condensate storage tank. These valves are closed during plant operation, but are used to throttle flow for tank heating to the condensate storage
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tanks during' outages in cold weather whan the unit is in cold shutdown. These valves are designea for high pressure v
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drop service and when throttled, they drop the pressure from aucut 1300 psig to 60 psig. The valves were removei
's and replaced with globe valves. The removed valves were
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found to be eroded. After the replacedsisives were pres-
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sure tested,L the AFW pumps were retest @ and declared
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operabley
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2.3.2 UnitTriponFebruary10 N'
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At 10:03 p.m. 'o'n February 10, the' unit tripped from 100%
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power due to an opsrator error. Kt the time of the trip, the operator was returning emergency diesel generator (EDG)
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22 to service following some pre m tive maintenance. The s
operator mVtakenly opened the reactor trip relay circuit s,
insteai;cir. losing the diesel generator D.C. Sower circuit.
L The diese? D.C. power circuit is located in the control room, in @.C. Distribution Panel 22, just behv the reactor trip circuit.
Following the trip, the 6.9 KV non-safe-guards bus 2-5 tie breaker did not close ani transfer bus 2-
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to offsite power. 480V safeguards bus 2A wasideenergized i
'N becaush its normal supply, 6.9 KV bus 2, was deenergized,
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and its emergency supply, diesel 72, was out of service.
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Required minimum engineered safegsards equipment were avail-able from the other three safegua'rds busses. The unit was (s '
stabilized in hot shutdown.
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The operators made four unsucce$s'lui t ek ts to close the bus 2-5 tie breaker from the control room'.' The breaker O
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was then racked out and in and was then gloyid. At i
approximately 11:20 p.m., bus 2A wap reene;'Uzed.
Shortly
thereaftart while the operator.ws matching Ylags on bus
' 'section 3,'tre bus 3-6 tie breaker tripctd, deenergizing bus 3 and' safeguards bus 3A. The bus 3-6 tie breaker was x
immediately reclosed from the contrgl r, nom)lttd bus 3A was v.
reenergized.
.The licensee performed tests and preventive mwintenande,.
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l's, (PM) on tie breakers 3-6 gnd 2-5.
Breaker 3-6hndits e
control switch functionsd properly during tt 9 #r.t ario no problems were found'dur'ing its PM which would /me cd6 sed
_t to open unexpectedly. The licensee concirJed that i
i breaker 3-6 was erroneously opened by the r;erator by
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while matching flags. Tie breaker 2-5 was tested and it failed to close. A faulty cell switch was identified.
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Upon investigation, it was determined that a nut that aligns the cell. switch was missing. The resulting misalignment caused the switch's contacts to not make proper contact.
With the cell switch not properly made up, the breaker control logic assumes that the breaker is racked out, and therefore no closure will occur even if there is a valid
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closure signal. The cell switch was repaired and the bus 2-5 tie breaker closed properly during retest. No O
additional problems were found during the breaker PM which
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would have caused it to fail to close.
The breaker PM procedure does not include an inspection of the cell switch (the cell switch is located in the breaker cubicle). The
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licensee stated that they will revise the PM procedure to include the cell switch. The licensee has also contracted with the breaker manufacturer to upgrade the licensee's PM procedure.
Due to concerns that an operator error caused this event,
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a region based license examiner was dispatched to review the event. The examiner determined that the reactor trip occurred due to operator error while clearing a tagout. A licensed operator was removing tags from the 22 EDG. The operator had just closed breaker No. 8 on DC Power Panel 23 and was moving to position the last breaker of the
tagout. The last breaker to be closed per the tagout was breaker No. 10 on DC Panel 22 for the 22 EDG. However, the
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w operator mistakenly opened breaker No. 8 on DC Panel 22 which de-energized RPS Trip Relay "B" and caused a reactor trip. Annunciators received were consistent with a trip of
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N the "B" RPS channel. Approximately 90 minutes later, this
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same operator erroneously tripped off 6.9 kv bus 3 while attemp-ting to correct existing disagreement lights (matching flags).
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The course of events of both incidents was discussed with the Acting Operations Manager. On the reactor trip,
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operators implemented E-0, Reactor Trip /SI. At Step 3, they exited E-0 since SI was neither actuated or required.
The Reactor Trip Response procedure, ES-0-1, was implement-g3 is ed immediately.
Steps were completed as required. At Step si
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q 14, since a cooldown was not required, the Post Trip Re-
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covery procedure was implemented. This procedure required the realignment of the electrical system breakers. The applicable procedure step was very general in nature and did not provide step-by-step instructions on how to realign
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electric plant breakers. The operator had to rely on past
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3" experience and previous training to properly match flags.
He demonstrated he understood the evolution because he did
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successfully match flags on other 6.9 kv busses prior to
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Followup discussion with Acting Operations Manager supported
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this conclusion.
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The operator's fitness for duty was also reviewed by the
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licensee. The Acting Operations Manager (OH) interviewed the operator after his shift was over. The Acting OM stated
'that he did not observe unusual behavior during his discus-
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'Q sions With the operator.
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The trip occurred on Tuesday, the second day of a 3 day, 7:00 p.m. to 7:00 a.m. shift. On Monday, the operator returned to work after nine days off. After 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> off
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on Tuesday, he returned to work at 7:00 pm. Tuesday even-
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ing. The trip occurred about three hours into the shift.
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No definite conclusions could be reached on the influence
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of the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> v.ork schedule. However, the Acting' 0K and the SRI have interviewed operators regarding their opinion of the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> schedule..
The consensus _is that more per-sonnel favor the schedule, but the operators' optiiions of the schedults is deff nitely polarized.
In conclusion, the apparent actions of the operator caused a reactor trip and a subsequent loss of a 6.9 kv bus. The procedures did direct the operator to establish the proper post trip alectrical alignment, but did not specify the proper sequence. Additionally, the improper manipulation, of the RPS trip relay breaker should have been prevented, since the breaker control switch for the "B" RPS channel was clearly labeled above the switch and by an identifier on the breaker handle.
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~The tagout did clearly define that breaker No. 10 was the only breaker to be manipulated in DC Panel.22 and yet the operator apparently operated the wrong breaker. No firm ps conclusion could be drawn on the effect of: the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> rotating shift on the operator's actions.
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No violations were cited.
3.
Maintenance i
The inspectors observed maintenance in progress and' reviewed completed and ongoing work packages. The inspectors verified that proper administrative approval was. received, equipment was properly tagged out,
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procedures used were adequate, proper radiological precautions were taken, QA/QC holdpoints were established and observed, and equipment was-properly tested before returning to service.
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3 The following maintenance items were observed and reviewed:
y 36-28608, Replace Valve BFD-77, AFW Pump 21 Recirculation Line.
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87-30560, Replace Valve BFD-78, AFW Pump 23 Recirculation Line.
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The previously installed needle valves (1/2" Hancock type 7105 W-1 with 7/16" orifice) were replaced with 1-1/2 inch globe valves. This
is a temporary repair. The valves passed a post-maintenance pressure test. The removed valves were examined and had eroded seats and
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plungers. Valves BFD-77 and 78 had previously been replaced under maintenance procedure 13.1, Rev. 1, issued April 16, 1976. This
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temporary repair may become permanent upon completion of the licensee's
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engineering review.
86-30038, Check Valve BFD-6 Preventive Maintenance.
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The Class 1, BFD-5,.: heck valves form the boundary between the Class 1 and non-Class 1 portions of the main feedwater system. The BFD-6's are 18 inch, Crane List 973, pressure seal, tilting disk check valves.
The BFD-6's are similar to the 20 inch, main feed pump discharge check valves, one of which failed in October, 1986 (Inspection Report 86-28). The internals of both BFD-6's were found intact and operable with the locking plates and bolts in place, although some looseness was found. The locking bolts and one locking plate were replaced. Both valves passed a post-maintenance leak test.
The licensee is performing an engineering evaluation to determine if a F
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permanent preventive maintenance program will be established for these valves and they are also evaluating improved methods for securing the clapper and seat ring.
87-30744, #22 Emergency Diesel Generator Jacket Water Cooling Pump.
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The pump was replaced due to a seal leak. The pump and diesel passed the post-maintenance test.
No violations were identified.
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4.
Surveillance
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The inspector observed surveillance tests in progress and reviewed i
completed surveillance tests. The inspector verified that the test-results satisfied Technical Specification requirements, proper
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administrative approval was received, procedures were adequate, and systems were properly restored at the end of the test.
The following surveillance tests were rev'iewed or witnessed:
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PT-M108, Area Radiation Monitoring System, Revision 15, performed
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February 23, 1987. During this test, R-1, central control room
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monitor, and R-7, incore instrument room monitor, were found out of y
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PT-Q34, Steam Driven Auxiliary Boiler Feedwater Pump Test, performed
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February 18, 1987.
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PT-BW1, Biweekly Rod Exercise Test, performed February 24, 1987.
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This test was performed without moving rod E-9.
Rod E-9 has been declared inoperable per the Technical Specifications since September 22, 1986.
PT-M8, Steam Generator Level Bistable Test, performed February 23,
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1987.
PT-M40, Emergency Fire Pump Diesel Functional Test, Revision 10,
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performed February 27, 1987. Temporary Test Procedure Change (TPC)
86-147T was incorporated 'nto this test in August, 1986. The TPC was issued due to fluctuat *ns in the fire pump pressure gages which
prevents an accurate mea.eran nt of the pump flow rate (differential pressure.) The TPC delet.
ae requirements for measuring flow monthly. The flow rate is required to be measured once every 18 months.
PT-RIS, Hydrogen Recombiner, Revision 6, performed March 4, 1986.
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For_this test, both hydrogen recombiners are ignited and brought up to normal operating temperatures. The test was completed satisfactorily. During the test it was noted that the diluent temperature recorder for recombiner 21 was out of service. A work order, 86-25832, was written on the recorder.
Preventive Maintenance (PM) Package #1244 was reviewed for the hydrogen recombiner. The PM consists of calibrating the hydrogen recombiner instruments. The licensee has stated that the PM is in the process of being changed.
The change will not affect the performance of PT-R15.
On February 3, the licensee declared auxiliary feedwater (AFW) pumps #21 and #23 inoperable after they failed a test performed under test procedure PT-R7A. The problem was traced to leaky recirculation stop valves (BFD-77 and 78). The inspectors observed the retest of the AFW pumps performed under test procedure PT-R7A, " Motor Driven Auxiliary Boiler Feed Pumps Full Flow." The inspectors also reviewed the surveillance test history of these pumps. This included test PT-R7A and PT-Q27, " Motor Driven Auxiliary Boiler Feed Pumps Functional Test." The AFW system was shown to be operable by testing during the last refueling outage.
The AFW pumps also passed all quarterly surveillance tests (PT-Q27) performed since the refueling cutage. The quarterly tests did not indicate any degradation of the AFW pumps since the refueling outage. Tests PT-R7A and PT-Q27 do not obtain trendable data which would indicate that valves BFD-77 and 78 were degrading.
Valves BFD-77 and 78 are also not included in the Section XI Inservice Test program since their only function is to remain closed.
No violations were identified.
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5.
Review of Periodic and Special Reports The Monthly Report for January,1987 was reviewed. The review included an examination of significant occurrence reports to ascertain that the summary of operating experience was properly documented. The report was also reviewed to determine that it included the information required by Technical Specifications 6.9.1.7 and 6.9.1.8.
The inspector has no further questions relating to the report.
No violations were identified.
6.
LER Followup The inspector reviewed the following LER's to determine that reportability requirements were fulfilled, immediate corrective action was taken, and corrective action to prevent recurrence had been accomplished.
86-32
" Missed Surveillance Test" - Due to having 2 out of 3 Technical Specification required leakage detection monitors out of service, a dilly containment air sample was required to be taken. Between September 22, 1986 and September 24, 1986, a period of 26 hours3.009259e-4 days <br />0.00722 hours <br />4.298942e-5 weeks <br />9.893e-6 months <br /> and 40 minutes elapsed between ramples, due to ineffective communications between the chemists.
The chemists have been reinstructed on the importance of effective communications.
In the LER, under " Identification of Occurrence," it is stated:
" Reactor trip due to manual actuation." This is incorrect, since a reactor trip did not occur. The licensee has stated they will revise the LER to remove the erroneous statement.
86-35
" Reactor Trip Due to Reactor Trip Relay De-energizing - On October 20, 1986, a reactor trip occurred due to reactor trip breaker "B" opening. After the trip, motor-driven auxiliary feedwater (AFW) pump #21 tripped and the steam relief valve on the turbine driven AFW pump lifted.
Upon investigation, it was determined that there were several loose connections in the safety injection system relay rack. Over 10,000 screws were checked for tightness. Approximately 0.25% of the terminals required greater than a half turn to tighten the screws. Three relays were replaced because they may have been a contriburing factor to the trip. The relays were sent to Westinghouse to discover the cause of possible faulty operation. Westinghouse reported the relays (Type BFD 66)
functioned a's originally designed, although some dirt and tarnish had accumulated over the 18 years since their manufacture.
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AFW pump #21 was determined to have tripped due to a too low setting of the amptector overcurrent trip device. The amptector device has been reset.
The steam relief valve on the turbine-driven AFW pump was determined to be lifting at 665 psig instead of the designed 700 psig.
Pressure Control Valve (PCV) 1139 was repaired so as to control steam pressure properly. (Refer to Inspection Report 50-247/86-28 for further information.)
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86-37
" Reactor Trip Due to Malfunction of Relay" On November 6,
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1986, during the performance of PT-M2 (Overtemperature Delta T and Overpower Delta T) and PT-M5 (Pressurizer Pressure) surveillance tests, the reactor tripped.
It was determined that faulty relays in the pressurizer pressure logic circuitry caused the trip.
Three relays were replaced. The relays were sent to Franklin Research Center for analysis. The results of the failure analysis revealed no significant problems with the BF66F relays.
They were all in satisfactory condition. One probable cause of failure was the lodging of foreign material in the relays. Some linty material was found near one of the relay contacts. The licensee is studying the options available to reduce relay failures.
86-31
" Control Rod Drop-Reactor Scram /SI Actuation - On September 16, 1986, while preparing to perform the biweekly rod exercise test, 3 control rods dropped. The operators manually tripped the plant.
Per the licensee's abnormal operating procedures, when more than one rod drops, the plant must be manually tripped. After the trip, a safety injection (SI) occurred. The SI resulted from high steam line flow coincident with low average temperature. The low reactor coolant system average temperature was due to the 3 rods dropping. The decrease in measured steam flow due to the trip, lagged sufficiently to make up the required high steam flow logic.
The four roos from shutdown bank A, group 2, were placed on the D.C. hold bus in preparation for the biweekly rod exercise test. Three rods were being removed from the hold bus to allow them to be exercised.
Rod E-9 was to remain on the hold bus since it had been declared inoperable.
During the jumpering of the three rods off the hold bus, the three rods dropped. This was caused by using a jumper which had too high an electrical resistance. The jumper was replaced and the licensee is currently using this jumper successfully during the biweekly rod exercise test.
For further information, see Inspection report 50-247/86-27.
No violations were identified.
7.
TI 2500/16 Potential Seal Table /In-Core Seismic Interaction Information Notice 85-45, " Potential Seismic Interaction Involving the Movable In-Core Flux Mapping System Used in Westinghouse Designed Plants," was reviewed by the licensee. Analysis indicated that a seismic interaction existed. A modification to the seal table supports was then developed and its installation completed during the 1986 refueling outage. The modification (MFI 86-50760, Flux Mapping Frame Seismic Restraint) installed seismic braces on the movable 10 path assembly frame. The inspector has no further questions on this item.
8.
Trip Reduction Activities NRC management reviews of performance indicators raised questions about the number of operational events at the site. As a result, the inspector reviewed the status of the licensee's trip reduction efforts.
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The previous two SALP reports identified the high trip rate as a concern.
NRC management discussed this issue with the licensee in a management meeting on December 17, 1985. At that time, the licensee described plans to form a trip response team to investigate trips and identify, recommend, and track corrective actions to reduce the frequency of trips.
This team was implemented in March, 1986, at the end of the 1986 refueling outage.
The trip response team (the team) reports to the Station Nuclear Safety Committee which is chaired by the G,neral Manager, Technical Support.
The team leader is an engineer in the Technical Support Division who is also an STA and licensed SRO. The team includes the site failure analysis engineer and representatives from engineering, safety assessment, training and operations support. The team member from operations support is also the licensee's representative and participant
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in the Westinghouse Owners Group (WOG) trip reduction sub-committee.
In the past year, team members have completed training in event analysis, human factors, failure analysis, and probabilistic risk assessment.
The team has investigated each trip in the past year, and has produced short-term and long-term corrective actions. These corrective actions are tracked to completion. The team's trip investigations are in addition to the post-trip reviews performed by operations.
The licensee's trip investigations and WOG participation has resulted in many long-term recommendations.
Some of those that are being worked on include:
reducing the steam generator low-low level trip setpoint;
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reducing the steam geneator low level / steam flow, feed flow mismatch trip setpoint; introducing time delays into circuits for the above two trips at low
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power;
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installing a partial turbine runback and condensate pump autostart upon main feed pump trip;
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adding redundancy to 1/1 turbine generator vibration trip system and finding other 1/3 trips; reducing the frequency of turbine stop valve stroke tests;
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justifying elimination of independent electrical overspeed protection system; installing time delay to eliminate false post-trip, short-term, high
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steam flow signals;
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inspecting (and replace if necessary) boiler feed pump thrust bearing
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seals; inspecting (and replace if necessary) the rod E-9 coil stack;
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developing a human factors performance evaluation system which will encourage staff to report on personnel error related near misses; and, upgrading the plant simulator.
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The licensee expects to have several of the above recommendations ready to implement by the next refueling outage (November 1987).
Although the effectiveness of the licensee's trip reduction efforts will have to be shown by improved performanc~e over time, the recent trip
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history shows an improving trend. The trip rate for the first seven months of the current SALP period is 1.31 trips per 1000 hours0.0116 days <br />0.278 hours <br />0.00165 weeks <br />3.805e-4 months <br /> critical (six trips in 4592 hours0.0531 days <br />1.276 hours <br />0.00759 weeks <br />0.00175 months <br /> critical). This compares favorably with the
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trip rate from the previous SALP of 2.13 trips per 1000 hours0.0116 days <br />0.278 hours <br />0.00165 weeks <br />3.805e-4 months <br /> critical (eleven trips in 5175 hours0.0599 days <br />1.438 hours <br />0.00856 weeks <br />0.00197 months <br /> critical).
No violations were identified.
9.
Exit Interview At periodic intervals during the course of the inspection, meetings were held with senior facility management to discuss the inspection scope and findings. An exit interview was held with licensee management at the end of the reporting period. The licensee did not identify any 2.790 material.
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