IR 05000397/1989027
| ML17285A860 | |
| Person / Time | |
|---|---|
| Site: | Columbia  |
| Issue date: | 11/06/1989 |
| From: | Johnson P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17285A859 | List: |
| References | |
| 50-397-89-27, NUDOCS 8911290045 | |
| Download: ML17285A860 (23) | |
Text
Report No:
Docket No:
Licensee:
Faci 1 i.ty Name:
U.S.
NUCLEAR REGULATORY COMMISSION REGION V
50-397/89-27 50-397 Washington Public Power Supply System P. 0.
Box 968 Richland, WA 99352 Washington Nuclear Project No.
(WNP-2)
Inspection at:
WNP-2 Site near Richland, Washington Inspection Conducted:
August 21 - October 1, 1989 Inspectors:
Approved by:
Summary:
C. J; Bosted, Senior Resident Inspector R.
C. Sorensen, Resident Inspector P.
H.
J hnson, C ief React Projects Section
f~ a~q Date Signed Ins ection on Au ust 21 - October 1,
1989 50-397/89-27 Areas Ins ected:
Routine inspection by the resident inspectors of control room operations, licensee actions on previous inspection findings, engineered safety feature (ESF) status, surveillance program, maintenance program, reactor feed water lubrication oil, emergency lighting, licensee event reports, and review of periodic reports.
During this inspection, Inspection Procedures 30703, 61726, 62703, 71707, 71710, 90712, 90713, 92700, 92701 and 92702 were covered.
Results:
No violations or deviations were identified.
Four followup items and twenty LERs were closed:
one new item was opened.
A weakness was observed in the timely corrective actions taken to correct the introduction of water into the reactor feedwater pump lubricating oil system.
This problem was identified following a 1985 event that resulted in the destruction of the reactor feedwater pump thrust bearing.
This same condi-tion was observed after the latest event that also involved failure of the same thrust bearing.
Water in the lube oil was identified as a contributing cause of failure but had not been fully corrected.
A strength was identified in changes made during the recent refueling outage to enhance the emergency lighting system.
891129004 ( sygg()q PDR ADOCK 0 00039"
DETAILS Persons Contacted
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3.
C. McGilton, Manager, Safety and Assurance C. Powers, Plant Manager
- J. Baker, Assistant Plant Manager K. Cowan, Nuclear Safety Assurance Manager C. Edwards, Ouality Control Manager
- R. Graybeal, Health Physics and Chemistry Manager J.
Harmon, Maintenance Manager,
"A. Hosier, Licensing Manager D'. Kobus, Ouality Assurance Manager R. Koenigs, Technical Manager S. NcKay, Operations Manager
- J. Peters, Administrative Manager
- G. Gelhaus, Assistant Technical Manager
- W. Shaeffer, Assistant Operations Manager
- R. Webring, Assistant Maintenance Manager The inspectors also interviewed various control room operators, shift supervisors and shift managers, and maintenance, engineering, quality assurance, and management personnel.
- Attended the Exit Meeting on October 2, 1989.
Plant Status At the start of the inspection period, the plant was operating at 71%
power.
Power level had been limited due to ongoing repairs on reactor feedwater pump "B" which had failed a thrust bearing on August 18.
Power remained at that level through September 9, when the feedwater pump was repaired.
Power was increased to 100% and remained at that-level until September 19, when feedwater heater 4A level started oscillating.
This prompted a reduction in power to 94'i, where power remained until September 21 when a condenser tube leak required a forced outage.
The plant was restarted on September 28 after repairs were made to the bellows on the extraction steam lines from the second stage of the "A" low pressure turbine.
Several main condenser tubes were also plugged during this outage (leaks were found on only two tubes, but an additional number were plugged as a precautionary measure).
At the end of the reporting period, the plant was at 75K and increasing power in accordance with the fuel preconditioning guidelines.
Previousl Identified NRC Ins ection Items 92701, 92702)
The inspectors reviewed records, interviewed personnel, and inspected plant conditions relative to licensee actions on previously identified inspection findings:
Closed Enforcement Item 397/88-40-02:
Timely Actions Not Taken for De snquent Survei ance on Degraded Voltage.
The surveillance requirements for the degraded voltage sensing relays were not met for the three-second time-delay relays.
The licensee declared them to be inoperable at ll:00 a.m.
on November 21, 1988, but did not enter the action statement for Technical Specification 3.0.3 until 2:00 p.m.
The licensee initially denied this violation, but subsequently agreed with it following additional correspondence with the NRC.
Corrective actions were undertaken by the licensee to increase'he sensitivi ty of staff and plant management to entering the action statements in a timely manner and then pursuing any relief that may be available.
The licensing manager was asked to prepare a
guidance document to assist the plant in obtaining relief from Technical Specification shutdown requirements when needed.
These corrective actions were reviewed by the inspector and found to be appropriate.
The inspector also noted that the Technical Specifications were followed in a conservative manner during a
subsequent event.
This item is closed.
Closed)
Enforcement Item 397/89-13-01:
Entry Into Radiologically Contro e
rea RC The inspector observed a barrier that had not been fully placed across an access into a radiation area and saw a contract worker entering the area.
'Hhen the inspector questioned the on-duty radiation protection technician (RP tech) at that location, the RP tech correctly installed the barrier and the contract worker told the inspector that he was not supposed to enter the area.
The licensee's corrective actions included the immediate removal of the individual from the RCA, and enhanced posting in the plant.
All postings were changed to barriers approximately chest high.
The contract labor force was also retrained on the Supply System's posting requirements.
No additional posting problems were encountered.
This item is closed.
(Closed)
Enforcement Item 397/89-13-03
Failure to h1ake Report it in
>me equsrements.
A four hour report was not made following discovery of a failed socket weld on the high pressure core spray flow test line into the containment wetwell.
The weld failure was discovered at approximately 3: 15 a.m.
on May 12, 1989 and was not reported until after discovery by the inspector at approximately 12:05 d.
The licensee conducted a training program for all operators, shift technical advisors, and technical staff to review the requirements of 10 CFR 20, 50.36, 50.9, 50.72, 50.73, and 73.
A discussion of this event and reporting requirements was also included.
This item is closed.
Closed Followu Item 397/89-13-04
Followup on Number of S utdown Coo sng Iso ations.
A number of events occurred during the 1989 refueling outage which resulted in tripping shut the isolation valves for the shutdown cooling system, stopping system flow.
Although these events were not a safety concern, they did reflect adversely on the control of evolutions in the plant.
The licensee undertook an investigation into this concern and performed an Incident Investigation (Root Cause)
which resulted in several generic causes for the shutdown cooling trips.
The investigation revealed that all the events fell into one of three categories.
The three root causes for the isolations were found to be less then adequate design/equipment, personne'1 performance/
management, and procedure weaknesses.
The report recommended several improvements to upgrade trip logic (identified in NRC inspection report 397/89-13 as being one-out-of-two taken once),
upgrade the power supply for the trip logic, improve procedures, validate existing procedures, and establish a dedicated group to perform infrequent surveillance tests.
Plant management indicated during discussions with the inspector that the plant will pursue the modifications and the.procedure enhancements, and that manage-ment would consider establishment of a dedicated procedure perfor-mance group.
Based on this discussion, the inspector concluded that this concern was being addressed.
This item is therefore closed, and future losses of shutdown cooling will be monitored pursuant to the ongoing inspection program.
0 en) Followu
1 lcatlons.
e.
The following items were reviewed, but the licensee was not ready to close them at the time of the inspection:
Item 397/88-32-01
- Discrepancies Regarding ATMS (0 en) Unresolved Item (397/88-32-04
- Review of How Changes Are a
e to Data on urve>
ances.
4.
0 erational Safet Yerification 71707)
a
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Plant Tours The following plant areas were toured by the inspectors during the course of the inspection:
Reactor Building Control Room
Diesel Generator Bui1 ding Radwaste Building Service Water Buildings Technical Support Center Turbine Generator Building Yard Area and Perimeter b.
'The (4)
(5)
(s)
(g)
following items were observed during the tours:
0 eratin
.Lo s and Records.
Records were reviewed against Technical Specification and administrative control procedure requirements.
Nonitorin Instrumentation.
Process instruments were o serve or corre ation etween channels and for conformance with Technical Specification requirements.
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i
. <<1 d
hfdf ig for conformance with 10 CFR 50.54.(k), Technical Specifica-tions, and administrative procedures.
The attentiveness of the operators was observed in the execution of their duties, and the control room was observed to be free of distractions such as non-work related radios and reading materials.
E ui ment Lineu s.
Yal ves and electrical breakers were veri-te to e
>n t e position or condition required by Technical Specifications and administrative procedures for the applicable plant mode.
This verification included routine control board indication reviews and conduct of partial system lineups.
Technical Specification limiting conditions for operation were verified by direct observation.
E ui ment Ta in
.
Selected equipment, for which tagging requests a
een initiated, was observed to verify that tags were in place and that the equipment was in the condition specified.
General Plant E ui ment Conditions.
Plant equipment was o served or sn scatsons o
system leakage, improper lubrica-tion, or other conditions that would prevent the system from fulfilling its functional requirements.
Annunciators were observed to ascertain their status and operability.
Fire Protection.
Fire fighting equipment and controls were i
h administrative procedures.
Plant Chemistr
.
Chemical analyses and trend results were reviewe or conformance with Technical Specifications and admi ni s tra tive control procedures.
Radiation Protection Controls.
The inspectors periodically o serve radio ogsca protect>on practices to determine
whether the licensee's program was being implemented in conformance with facility policies and procedures and in compliance with regulatory requirements.
The inspectors also observed compliance with radiation exposure permits, proper wearing of protective equipment and personnel monitoring devices, and"personnel frisking practices.
Radiation monitoring equipment was frequently monitored to verify operability and adherence to calibration frequency.
(10) Plant Housekee in
.
Plant conditions and material/equipment storage were o served to determine the general state of cleanliness and housekeeping.
Housekeeping in the radio-logically controlled area was evaluated with respect to controlling the spread of surface and airborne contamination.
( 11) ~Securi t
.
The inspectors periodically observed security practices to ascertain that the licensee's implementation of the security plan was in accordance with site procedures, that the search equipment at the access control points was opera-tional, that the vital area portals were kept locked and alarmed, and that personnel allowed access to the protected area were badged and monitored and the monitoring equipment was functional.
No violations or deviations were identified.
5.
En ineered Safet Feature S stem Walkdown 71707, 71710 Selected engineered safety feature systems (and systems important to safety)
were walked down by the inspectors to confirm that the systems were aligned in accordance with plant procedures.
During the walkdown of the systems, items such as hangers, supports, electrical power supplies, cabinets, and cables were inspected to determine that they were operable and in a condition to perform their required functions.
The inspectors also verified that the system valves were in the required position and locked as appropriate.
The local and remote position indication and controls were also confirmed to be in the required position and operable.
Accessible portions of the following systems were walked down on the indicated dates.
~Sstem Diesel Generator Systems, Divisions 1, 2, and 3.
Hydrogen Recombiners Low Pressure Coolant Injection, (LPCI)
Trains "A", "8", and
"C" Low Pressure Core Spray (LPCS)
Dates September 7,
September 4,
September 4,
September 4,
High Pressure Core Spray (HPCS)
Reactor Core Isolation Cooling (RCIC)
Residual Heat Removal (RHR), Trains IIAII and II8 II September
September 4,
September
Scram Discharge Yolume System Standby Liquid Control (SLC) System Standby Service Mater System 125Y DC Electrical Distribution, Divisions 1 and
September 8, 22 September
September
September 8, 13,
250Y DC Electrical Distribution No violations or deviations were identified.
September 8, 13,
6.
Surveillance Testin 61726 Surveillance tests required to be performed by the Technical Specifica-tions (TS) were reviewed on a sampling basis to verify that:
( 1) the surveillance tests were correctly included on the facility schedule; (2)
a technically adequate procedure existed for performance of the surveillance tests; (3) the surveillance tests had been performed at the frequency specified in the TS; and (4) test results satisfied acceptance criteria or were properly dispositioned.
Portions of the following surveillance tests were observed by the inspectors on the dates shown:
Procedure Descri tion Dates Performed 7.0.0 Shift 8 Daily Instrument 7.4.3. 1.1. 14D High Drywell Pressure 7.4.3.2.1.22B Main Steam Line High Flow 7.4.9.7 Reactor Building Crane Interlock Operability Test 7.4.6.5.3.6 Standby Gas Treatment (SGT)
Adsorber Bypass Leakage Test 7.4.3.6.20 Recirculation Flow Rod Block Channel Functional Test September
September
September
September
September
September
While observing performance of procedure 7.4.9.7 above, the inspector noticed that-both mechanics conducting the test were riding within the overhead crane cab.
This appeared to be inappropriate since the
procedure involved measuring distances of a few feet from the edge of the spent fuel pool to the crane hook.
He noted that one individual should be on the refueling floor taking accurate measurements while the other individual operates the crane.
This was brought, to the attention of maintenance management, who agreed to take action to correct the problem.
Ho violations or deviations were identified.
7.
Plant Maintenance 62703 During the inspection period,,the inspectors observed and reviewed documentation associated with maintenance and problem investigation activities to verify compliance with regulatory requirements and with administrative and maintenance procedures, required OA/OC involvement, proper use of safety tags, proper equipment alignment and use of jumpers, personnel qualifications, and proper retesting.
The inspectors verified that reportabi lity for these activities was correct.
The inspectors witnessed portions of the following maintenance activities:
Descri tion Dates Performed Replacement of Reactor Feedwater (RFW)- Pump "B" Thrust Bearing August 21-September
Troubleshooting for fuse blowing in September
RFW, MO 112B per AT 1796 Troubleshooting for Downscale Alarm on IRN Channel D
Correct DIY II Emergency Diesel Generator (EDG) lube oil leaks per AS 724 5 AS 725 September
September
Fill DIV II EDG with lube oil per AS 1735 No violations or deviations were identified.
8.
Reactor Feedwater Pum Lube 0~i 1 62703)
September
At the start of this report period, the reactor power was limited to 7li due to single reactor feedwater pump (RFP) operation necessitated by a failed thrust bearing in the "B" RFP.
The cause of failure was determined to be a single small piece of foreign material that was believed to have become detached from the inside of the oil piping.
Filtering of the lube oil>> after this event produced additional materials believed to be iron rust, paint chips, and the expected babbitt'material from the failed bearin A formal Inc ident Inves tigati on (root cause) of the bearing failure was undertaken shortly after 'the event, but the results were not finalized before the end of the inspection period.
The inspector did review a previously completed engineering review of a similar failure of the thrust bearing in 1985 and made comparisons between the two thrust bearing failure events.
Although this equipment is not considered safety related, the methodology used by the licensee to investigate and correct such a significant problem would appear to be indicative of how the licensee would handle a safety related equipment malfunction.
A total of three thrust bearing failures have occurred on the "B" RFP since startup in 1984.
The second failure, which occurred at the end of the 1989 refueling outage, was caused by improper assembly of the bear-ing following maintenance.
An out of date assembly instruction was used by the maintenance department that did not contain revised instructions from the vendor.
After this failure, the vendor was contacted and revised instructions were provided for the reassembly of the pump.
The first failure, in 1985, was caused by oil strainers becoming partially plugged and starving the bearing for oil flow, resulting in bearing failure and a subsequent fire.
During startup efforts in 1983, the system startup engineer was apparently not satisfied with the cleanliness of the oil in the lube oil systems and had additional oil strainers installed on a number of lines in the lube oil system.
During operation of the system during 1984 and 1985, the strainers removed debris from the oil and slowly became plugged.
At the time of the. first thrust bearing failure in June 1985, the system engineer had left the Supply System and his successor was not aware of the oil strainers.
After the cause of the bearing oil starvation was determined, the other strainers were found arid removed.
The "Failure Analysis Report" for this event, No.72-001, attributed the cause of failure to oil starvation, with contributing causes listed in the report as:
"Excessive water in lubricating oil sump allowing excessive amounts of water and water borne debris to be discharged into the oil distribution system.
Failure to remove startup strainers.
(It must be recognized that if the startup strainers had been removed prior to the incident there is a very good chance that more damage could have been caused to other bearings as well as the control oil components)."
At that time, it was recognized that water was getting into the RFP lubricating oil system, resulting in rust and loss of the paint from the interior of the piping and tanks, and that the most probable cause of the water was from the shaft seal water system.
Other system design questions were also raised during the 1985 event investigation.
Con-cerns included a single piping line to and from the lube oil purifier (such that clean oil was sent back to the lube oil sump via the same line that sent the dirty oil to the purifier) and poor filters on the oil pump discharge.
When these filters are removed, debris could fall down the filter discharge side, increasing the chance of introducing previously filtered foreign material back into the oil syste As a result of the 1985 event, modifications to the lube oil system included the provision of a water separator on the oil sump.
The single supply/return pipe and the lube oil filters remained unchanged.
Following the recent event (August 1989), the filter configuration was modified to minimize the opportunity for foreign'material to. be reintroduced to the oil system when removing a filter.
On several occasions, since startup, water was discovered in the RFP oil sumps after unusual evolutions on the RFPs.
During normal RFP startups and shutdowns, water was not found in the lube oil sumps.
Water was determined to be in the "8" sump following maintenance during the 1989 refueling outage and again following the maintenance outage in August 1989 to repair the failed thrust bearing.
Operations and Technical Staff engineers again determined that the water was leaking past the seal water return and into the lubricating oil return lines.
This phenomenon had been understood after the event in 1985, but was not corrected at that time.
The inspector's impression following discussions with several indivi-duals associated with the 1985 event and with the latest event was that the corrective actions taken in 1985 were not complete and thorough.
Although the 1989 event was not caused by foreign debris generated by water in the oil system, material was found in the oil lines that could cause line plugging in the future.
Since the licensee's root cause was not completed by the end of the reporting period, licensee corrective actions have not yet been, reviewed.
The corrective actions will be followed up during a future inspection (Followup Item 397/89-27-01).
Emer enc Li htin (62703 In response to inspection findings at another facility, the inspector reviewed the lighting system used to evacuate the plant and to safely shut down the plant during a loss of electrical power.
Two potential plant conditions have been identified during which emergency lighting must be operable.
The first involves the safe shutdown of the plant and the second deals with the evacuation of personnel during an emergency.
These conditions are discussed in section 9.5.3 of the WNP-2 FSAR, which indicates that approximately 15% of the station lighting is to be designated emergency use and be capable of being supplied by a diesel generator.
Three areas needed for plant safe shutdown are the control room, remote shutdown room, and the access to the remote shutdown room.
These areas are also equipped with battery powered lights.
The other battery backup lighting is required by the NFPA Code, to provide for building evacuation.
The safe shutdown battery lighting is required to be operable for 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> and the evacuation batteries are required to function for two hours.
The inspector reviewed PPM 4.7. 1.10,
"Loss of All Off-Site Electrical Power"; 5.4. 1, "Station Blackout"; and 10.25.63,
"Emergency Lighting Inspection", to compare the implementation with the requirements.
No discrepancies were identified.
A review of the surveillance performed under PPM 10. 15.63 during the recent refueling outage indicated that all battery powered lighting was well within requirement i
The inspector noted that the licensee had replaced all of the-battery lighting units during the past year.
'o violations or deviations were identified.
.10.
Licensee Event Re ort LER Followu 90712, 92700 The following LERs associated with operating events were reviewed by the inspectors.
Based on the information provided in the report it was concluded that reporting requirements had been met," root causes had been identified, and corrective actions were appropriate.
The below LERs are considered closed.
LER NUMBER LER 88-24-01 LER 89-07-00 LER 89-08-00 LER 89-10-00 LER 89-11-00 DESCR IPTION Special Report for Containment Temperatures Greater Than 150 Degrees For Greater Than Eight Hours.
Failure to Comply With Fire Protection Surveillance Requirements.
Missed HPCS Diesel Generator Surveillance Due to Programmatic Deficiencies.
Partial Nuclear Steam Supply System (NSSS)
Actuation Due to Loss of Power to Reactor Protection System (RPS)
Bus "A".
Missing Limitorque Motor Operator torque Bypass Switch Due to Plant Design Documentation Deficiencies.
LER 89-12-00 LER 89-13-00 LER 89-14-00 LER 89-15-00 LER 89-16-00 RPS Actuation During Functional Testing While the Reactor Was Shutdown.
Potential Inoperability of Redundant 120 Volt Electrical Busses Due to Degraded Voltages.
Reactor Protection System Actuation Caused by Moving LPRM Cable While Shutdown.
HPCS 3/4 Inch Line Break During Surveillance Testing While Plant Was Shutdown.
Engineered Safety Features (ESF)
System Actuation Caused by Fuse Removal Due to Personnel Error.
LER 89-22-'00 L'oss of Security and Containment Integrity During Core Alterations Due to Unisolatable Line LER 89-24-00 Secondary Containment Bypass Leakage Greater Than Allowed Due to Equipment Design Deficiency.
Reactor Scram During Turbine Throttle Valve Testing Due to Procedure Deficiency.
The following licensee event reports were due to loss of shutdown cooling during the 1989 refueling outage, and were followed up at.that time.
These items were also discussed in paragraph 3.d and are considered closed.
LER 89-17-00 Residual Heat Removal (RHR) System Shutdown Due to Containment Isolation Caused by Personnel Error.
LER 89-18-00 ESF Isolation Due to Failure of RPS Motor
'Generator (Component Failure).
LER 89-19-00 LER 89-20-00 LER 89-21-00 RHR Isolation Due to Personnel Error.
RHR Isolation Due to Procedure Inadequacy.
ESF Isolation and Actuation Due to RPS Electrical Protection Assembly Breaker Trip Cause Unknown.
LER 89-23-00 LER 89-25-00 ESF Actuation Due to Loss of RPS Bus During Testing.
ESF Actuations During Excess Flow Check Valve Testing Due to Procedural Inadequacies.
No violations or deviations were identified.
11.
Review of Periodic and S ecial Re orts 90713 Periodic and special reports submitted by the licensee pursuant to Technical Specifications 6.9.1 and 6.9.2 were reviewed by the inspector.
This review included the following considerations:
the report contained the information required to be reported by NRC requirements; test results and/or supporting information were consistent with design predictions and performance specifications; and the reported information was valid.
Vithin the scope of the above, the following reports were reviewed by the inspectors.
o Monthly Operating Report for August 1989.
No violations or deviations were identifie ce 12.
Exit Meetin 30703 The inspectors met with licensee management representatives periodically during the report period to discuss inspection status, and an exit
'eeting was conducted with the indicated personnel (refer to paragraph 1)
on October 2, 1989.
The scope of the inspection and the inspectors'indings, as noted in this report, were discussed and acknowledged by the licensee, representatives.
The licensee did not identify as proprietary any of the information reviewed by or discussed with the inspector during the inspectio j,
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