IR 05000440/1993011
| ML20045H295 | |
| Person / Time | |
|---|---|
| Site: | Perry  |
| Issue date: | 07/12/1993 |
| From: | Lanksbury R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20045H293 | List: |
| References | |
| 50-440-93-11, NUDOCS 9307200058 | |
| Download: ML20045H295 (21) | |
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U. S. NUCLEAR REGULATORY COMMISSION
a REGION 111 Report No. 50-440/930ll(DRP)
Docket No. 50-440 License No. NPF-58-Licensee:
Cleveland Electric illuminating Company Post Office Box 5000 Cleveland, OH 44101 Facility Name:
Perry Nuclear Power Plant inspection At:
Perry Site, Perry, Ohio j
Inspection Conducted: May 1 through June 23, 1993
Inspectors:
D. Kosloff A. Vegel E. Duncan
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i Approved By:
7/tdG m
R.' D. LanksburyA+efA Date Reactor Projecis Saction 38 inspection Summary Inspection on May 1 throuah June 23. 1993 (Recort No. 50-440/930ll(DRP))
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Areas Inspected: Routine unannounced safety inspection by resicent and region based inspectors of licensee act-ion on previous inspection findings, surveillance observations, maintenance observations, operational safety verification, and event followup.
Results:
In the five areas inspected, two apparent violations, one with three i
examples were noted.
The three examples of an apparent violation were of l
failure to adequately identify and correct con _ditions in the drywell, j
containment, and suppression pool to preclude fouling and deformation of emergency core cooling system (ECCS) strainers (paragraph 2).
The second apparent violation was of failure to have an adequate procedure for testing the "B" residual heat removal pump (paragraph 2). Two unresolved items were identified.
The first concerned the effects that concrete in,the containment
rattle space" had on the operability of the containment vessel (paragraph 2);
the second involved piping support spring cans in the drywell.and containment'
(paragraph 4). One Inspection Followup Item was also identified and involved leak rate testing of the inclined fuel transfer system containment penetration two-ply bellows (paragraph 5.e).
The following is a summary of the licensee's performance during this inspection period:
9307200058 930712 PDR ADOCK 05000440
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Plant Operations
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The plant was shut down for repairs to the service water system and the ECCS strainers. The plant was started up on June 2,-1993, and remained at or near full power operation for the duration of the inspecticn peri od.,
Operator control of the plant startup and response to an inadvertent injection of the high pressure core. spray system was excellent.
Maintenance / Surveillance The quality of observed maintenance and surveillance activities was generally good. However, inadequate post maintenance restoration resulted in several pipe support spring cans being improperly configured. Work order instructions for taking data during a residual-heat removal pump test were inadequate, resulting in an. apparent violation.
Quality verification of drywell and containment clearliness was inadequate, resulting in an apparent violation.
Engineering and Technical Support Engineering and technical support of outage activities and plant startup was good.
Inspector review of the strainer event identified weaknesses in the engineering staff's ability to promptly identify and ade'quately assess potential safety significant deficiencies.
This resulted in two apparent violations.
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DETAILS 1.
Persons Contacted Cleveland Electric Illuminatina Comnany i
- R. Stratman, Vice President - Nuclear
- D. Igyarto, General Manager, Perry Nuclear Power Plant (PNPP)
- K. Donovan, Manager, Licensing and Compliance i
M. Bezilla, Operations Manager, PNPP J
- S. Kensicki, Director, Perry Nuclear Engineering
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Department (PNED)
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F. Stead, Director, Perry Nuclear Support Department (PNSD)
H. Hegrat, Compliance Engineer, PNSD E. Riley, Director, Perry Nuclear Assurance Department (PNAD)
W. Coleman, Manager, Quality Assurance Section, PNAD
- V. Concel, Manager, Technichl Section, PNED
- D. Conran, Compliance Engineer, PNSD M. Cohen, Manager, Maintenance Section, PNPP
- P. Volza, Manager, Radiation Protection Section D. Cobb, Superintendent, Plant Operations, PNPP
- W. Wright, Manager, Instrument & Control Section
- H. Reppert, Senior Project Engineer, Mechanical Support Unit
- J. Eppich, Manager, Mechanical Design Section, PNED
- J. Lausberg, Supervisor, Technical Quality Unit, PNAD
- R. Schrauder, Director, Perry Nuclear Services Department
- B. Beyer, Director, Perry Administrative Services
- D. Graneto, Superintendent, Maintenance, PNPP
- N. Bonner, Director, PNED
- K. Pech, Director, PNAD
- P. Roberts, Manager, Instrument & Control Section
- R. Gaston, Compliance Engineer, PNSD
- Denotes those attending the exit meeting held on June 23, 1993.
2.
Licensee Action on Previous Inspection findinas (40500. 71707. 92701.
92702)
(00en) Inspection Followuo Item (50-440/93004-01(DRP)): As previously documented in inspection reports 50-440/92026, 50-440/93004, and 50-440/93005, the licensee identified that the accumulation of debris on the emergency core cooling system (ECCS) suppression pool suction strainers may have degraded the ability of the residual heat removal (RHR) system to perform 5ts intended post accident function.
The licensee initiated an iniident response team (IRT) to investigate the circumstances surrounding repeated accumulation of debris on ECCS strainers and developed corrective actions to prevent recurrence.
During this inspection period the licensee implemented the corrective actions and restored the ECCS systems to service.
Licensee efforts to prevent recurrence included the development of enhanced cleanliness
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criteria, cleaning of the drywell and containment to the new standards, installation of redesigned strainers, development of a strainer backflush capability and the development of a monitoring program for strainer performance.
- Drywell and Containment Cleanliness The licensee performed an extensive cleanup of the drywell and containment. This cleanup effort minimized the potential for debris dropping into the suppression pool and potentially fouling the ECCS strainers. As discussed in a response to confirmatory action letter (CAL) RIII-93-007, dated May 9, 1993, the licensee committed to obtaining acceptable levels of cleanliness in the suppression pool, containment, and drywell prior to plant startup.
In the letter, the licensee defined acceptable levels of cleanliness with the following standards:
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Ensuring no accumulation of loose dirt or dust under floor gratings, on top of angle irons, and on top of components and piping.
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Ensuring no debris (e.g. loose tape, metal tags, or fibrous material) were present.
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Ensuring tools, hoses, materials, equipment, etc. were eit+ or removed, seismically restrained, or properly eva aated as a mechanical foreign item in accordance with pla~L procedures.
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Ensuiing no accumulation of loose corrosion or paint chipping existed.
The licensee cleanup effort was a multi-step process.
First, the ECCS strainer IRT inspected the drywell and containment to identify areas requiring cleaning.
Next, cleanup was conducted by the plant maintenance organization.
The area was then inspected to the criteria established by the IRT, which included a quality
assurance organization inspection.
In addition, management
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conducted independent inspections, and operations personnel
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performed final inspections prior to plant startup.
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The licensee's efforts to clean the drywell, the containment, and the suppression pool were personnel and exposure intensive. The effort resulted in approximately 7500 person-hours and 17 person-rem being expended. As a result of this effort, a large amount of debris was removed from areas of concern (approximately seven 55-
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gallon drums of radioactive waste were generated).
The radioactive waste included cleaning materials such as rags and plastic bags that were not part of the debris.
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To assess the adequacy of the cleanup effort, the resident staff
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inspected the drywell and containment on May 25, 1993.
Prior to
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the inspection, the drywell had been inspected by the licensee and was considered ready for closecut in preparation for plant startup.
In containment, areas requiring cleanup had been identified, most cleaning had been completed, and final licensee inspection of the cleaned areas was in progress.
In the drywell, the inspectors identified numerous discrepancies which included:
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dirt and dust accumulation behind drywell ventilation units
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numerous tools, nuts and bolts, a poly bottle, and a tube of lubricant
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plastic bags, rags, an abandoned radiation sign, and a roll of duct tape Based upon these observations, the inspectors concluded that the acceptable standard of cleanliness in the drywell had not been achieved.
In addition, several spring cans were found pinned.
(The spring can issue is discussed in paragraph 4 of this report.)
In response to the. inspectors concerns, additional cleanup and inspection was conducted.
On May 27, 1993, the inspectors reinspected the drywell and concluded that cleanliness was consistent with the licensee's cleanliness standards.
In the containment, the inspectors noted that generally the cleanliness appeared good, though cleaning activities were still-
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in progress.
The inspectors observed debris, plastic sheeting, a 2" x 4" piece of wood, and an unintended small extension of the drywell concrete structure into the 3-inch seismic separation
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space (rattle space) between the drywell concrete structure and the containment vessel wall. The inspectors were concerned that initiation of containment spray could wash the debris into the suppression pool and foul the ECCS strainers. Also, the concrete appeared to be in direct contact with-the containment vessel wall.
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The updated safety analysis report (USAR), Section 3.8.2.1.1
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. states, in part, that the interior structure (except for grating supports) did not contact the free standing section of the containment vessel and that sufficient clearance was provided to
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ensure that contact did not occur during any of the postulated
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load combinations.
In response to the inspectors concerns, the licensee conducted
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further inspections of the rattle space and identified additional debris and concrete. The licensee noted three additional extensions of concrete into the rattle space, one of which was not in contact with the containment vessel. The concrete extensions were found to be firmly attached to the drywell concrete
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structure.
The rattle space area was cleaned and the. concrete extensions removed. About 200 pounds of material in all was removed. Material removed from the rattle space included the
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concrete extensions, dirt, paper, gloves, plastic sheeting, and a
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wooden 14-foot extension ladder apparently left over from plant construction.
Licensee evaluation of the effect that the concrete in the rattle space had on containment operability was in progress at the end of this inspection period.
Pending inspector review of
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the licensee's operability evaluation, this will remain an unresolved item (50-440/930ll-01(DRP)).
On May 31, 1993, the resident staff reinspected the containment, including the' rattle spaces, and concludM that containment cleanliness was consistent with the licensee'; cleanliness standards.
Appendix B of 10 CFR Part 50, Criterion XVI, Corrective Action, required, in part, that measures be established to assure conditions adverse to quality are promptly identified and corrected..In the case of significant conditions adverse to quality, the measures shall assure that the cause of the condition is determined and corrective action taken to preclude repetition.
Based on the inspectors observation of debris in the drywell and the containment rattle space on May 25, 1993, the licensee failed to assure that corrective actions had been taken to assure that the drywell and containment were sufficiently clean to preclude fouling of the ECCS suppression pool suction strainers.
This is an example of an apparent violation (50-440/93011-02a(DRP)).
Redesianed Strainer and Testina To reduce the effects of strainer fouling, the licensee redesigned and installed new strainers. The new ECCS strainer design was a
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truncated cone featuring larger diameter holes, increased total surface area, a larger flow area, and increased capacity for external pressure loading compared to the original design.
In addition, the new strainer design was reviewed for backflush capability.
During installation of the new ECCS strainers on May 9, 1993, gaps were observed between the strainer and penetration flanges. A flush fit of the flanges was prevented by flange distortion caused by heat produced during welding.
As a result, the ECCS strainers had to be removed and fitted with thicker flanges. Upon completion of modifications, the strainers
were installed and tested. On May 19, 1993, during RHR "B" system
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performance testing, a higher than expected differential pressure was indicated across the strainer.
Troubleshooting revealed the pressure indicating instrument was not properly filled and vented.
The problem was corrected and the test was performed with satisfactory differential pressure being indicated.
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visual inspection identified that debris had collected on the strainer.
Subsequent inspection revealed that a thin layer of fibers was trapping debris on the strainer.
The inspectors observed that the pool was generally clean with the strainers and floor visible.
However, some turbidity was visible in the pool.
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pool until they collected on the strainer.
The licensee concluded
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that cleaning activities in the containment had. contributed to the
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debris in the suppression pool. The suppression pool floor, wall, and horizontal vents were cleaned and a 12-hour test of the RHR
"B" system was conducted on May 25, 1993, with satisfactory results. The inspectors observed that the pool water was clear.
All ECCS were tested with the new suction strainers with baseline strainer differential pressure being recorded for future performance trending.
With the exception of the debris collected on the RHR "B" strainer on May 19, 1993, only minor instances of debris collection on the strainers were noted during or after the test runs.
On May 26,.
1993, following successful testing, all ECCS strainers were considered operable. The reactor core isolation cooling (RCIC)'
strainer was considered operable based on the satisfactory testing of the other strainers.
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Strainer Backflush Capability To maximize the availability of the RHR "A" and "B" systems in case of strainer fouling during an event, the licensee developed and tested a backflush capability.
The backflush flow path utilized suppression pool water from the high pressure core spray suction line, through the suppression pool clean up pump into the fuel pool cooling header. The water would then be directed into the RHR suction piping via the RHR fuel pool cooling assist.
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suction valve, flowing back through the RHR suppression pool suction valve, and then through the strainer.
The licensee anticipated that this procedure would only be used during emergency response and not during normal operation. During normal plant operation, a fouled strainer would be cleaned instead of backflushed.
e Monitorina of Strainer Performance To enhance the detection of conditions which may lead to potential strainer fouling, the licensee developed and implemented improved inspection and surveillance techniques.
Some of the improvements included the revision of ECCS pump technical specification (TS)
surveillance procedures to include the monitoring of' pump suction pressures. Criteria were established, based on baseline data, to more accurately assess strainer performance. The RHR system operating instructions were revised to monitor suction pressure during suppression pool to suppression pool modes of operation.
Visual inspections of the strainers will also be conducted after the strainers have been used. -In addition, plant chemistry and j
administrative procedures were modified to enhance the control and
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identification of fibrous material in the containment. The containment and drywell were designated Zone III housekeeping areas (except during outages) which required, in part, that a
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written record of the entry and exit of all personnel and material be established and maintained.
Event Review Though the licensee eventually took adequate corrective action to address the strainer fouling issue, as discussed above, review of the event history indicated that on several occasions the licensee had the opportunity to identify the susceptibility of the ECCS strainers to fouling and take corrective action.
In addition, the licensee failed to ensure that adequate testing was being performed to detect potential strainer fouling problems to verify that the ECCSs could function as designed.
Also, procedural inadequacies became apparent during licensee troubleshooting efforts.
The inspectors reviewed historical licensee documentation of ECCS performance and suppression pool and ECCS strainer cleanliness.
Based on the review, the cleanliness of the suppression pool was questioned on several occasions. On July 17, 1989, during the first refueling outage (RF01), during performance of a suppression pool cleanliness inspection, the condition of the suppression pool was poor.
The record of repetitive task (RT) #R86-11784 included the comments that, "Much debris & sediment in water and on walls.
There is not much direction what to use i.e. underwater lights,
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etc. Water was dark and murky.
Could not view bottom." On May 22, 1992, during RF03, debris was noted on the suppression pool floor and on the RHR strainers.
(See inspection report 50-
440/92026(DRP), dated February 12,1993.)
In January 1993 during a review of the May 22, 1992, video tapes of the strainers, deformation between the strainer stiffener plates was evident, but had not been previously identified. A work request (WR) had been initiated on July 29, 1992, to clean the strainers after RF03.
On July 31, 1992, the WR was assigned a work priority of SA, which indicated that an outage was required to accomplish the work.
The fouling described in the WR was not considered to have an impact on system operability. Work Order (WO) numbers were assigned for the work.
The system engineer requested that the work be accomplished prior to an outage, but on September 3,1992, the W0s were deferred until the next refueling outage due to safety concerns related to cleaning the strainers while the plant was
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operating at power.
No documented engineering evaluation was conducted'concerning the cleanliness of the strainers or the deformation.
Appendix B of 10 CFR Part 50, Criterion XVI, Corrective Action, required, in part, that in the case of significant conditions adverse to quality, the measures shall assure that the cause of conditions is determined, and corrective action taken to preclude repetition.
The identification of the significant condition adverse to quality, the cause of the condition, and the corrective action shall be documented and reported to appropriate levels of
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management. On July'17, 1989, and May 22, 1992, following the
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identification of debris in the suppression pool, and on May 22, 1992, following. observation of debris on the RHR "A" and "B" strainers, the licensee failed to identify the cause for the poor cleanliness of the suppression pool and strainer fouling and failed to take action to clean the suppression pool to prevent the fouling from recurring. The occurrence of strainer fouling and i
deformation on May 22, 1992, was not documented and reported to the appropriate levels of management. This is an example of an apparent violation (50-440/930ll-02b(DRP)).
Ventilation System Rouchina Filters On February 11, 1993, the licensee took samples of material laying on the floor of the suppression pool. The samples consisted of fibrous material and other debris.
Licensee video tapes of the deformed RHR "A" and "B" strainers taken in February 1993 showed debris entangled in or attached to fibrous material.
In February 1993 the licensee failed to determine the source of the fibers and failed to adequately evaluate the potential impact of these fibers on ECCS strainer performance. The licensee later determined that
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fibrous material from the containment and drywell ventilation system roughing filters were the major threat to clogging the ECCS strainers and subsequently removed them from the drywell and containment prior to plant startup in June 1993.
Appendix B of 10 CFR Part 50, Criteria XVI, Corrective Action, required, in part, that measures be established to assure that conditions adverse to quality, such as deficiencies and nonconformances, are promptly identified and corrected.
In the case of significant conditions adverse to quality, the measures shall assure that the cause of the condition is determined and corrective action taken to preclude repetition.
The licensee failed to identify the presence of fibrous material in the suppression pool as a significant contributor to the strainer deformation (identified on January 16,1993), the strainer fouling phenomenon identified during review of video tapes taken in February 1993, and during subsequent investigations prior to.
April 14, 1993.
Following the identification of fibrous material in February 1993, the licensee failed to take adequate correctiva action to remove the fibrous material from the pool which resulted in the recurrence of the RHR "B" strainer fouling and deformation identified on April 14, 1993. This is an example of an apparent violation (50-440/930ll-02c(DRP)).
As discussed in inspection report 50-440/93005(DRP), dated May 19, 1993, the drywell and containment ventilation roughing filters represented a major potential debris source in the event of a loss of coolant accident (LOCA). Had a LOCA occurred, it was possible that most of the filter material would have ended up in the suppression pool, presenting a major clogging threat to the-ECCS strainers.
The roughing filters were included in the design of
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Sections 9.4.6.2.1 and 9.4.6.2.2.
The inspectors verified that the licensee had removed the roughing filters prior to plant restart in June 1993.
Strainer Testina Since initial plant startup the licensee had conducted surveillance testing of the ECCS systems to evaluate operability.
The surveillance tests monitored suction pressure and other parameters to assess operability.
Section 6.2.2.2 of the USAR stated that the ECCS strainer area was selected so that in the event that a strainer becomes 50 percent plugged, the minimum net positive suction head (NPSH) would still be provided to the RHR
pumps during low pressure core injection and suppression pool cooling modes. At the design flow rate of 8,500 gallons per minute (gpm), the large strainer had a maximum design pressure.
drop of 1 psid with 50 percent of the strainer plugged.
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surveillance tests required evaluation of differential pressure across the pump and not across the strainer.
Had this parameter been evaluated the licensee might have identified that the i
pressure drop obtained during testing was greater than 1 psid, that it indicated greater than 50 percent fouling, and that it indicated a reduction of NPSH available to the pump.
As documented in inspection report 50-440/93005(DRP), the inspectors reviewed the licensee performance of a test of the "B" RHR system on April 15, 1993. The test was being performed following the identification of debris and deformation on the
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RHR strainer. The inspectors identified several inadequacies during the performance of the test, including poor communication and inadequate instructions. Appendix B of 10 CFR Part 50, Criterion V, Instructions, Procedures and Drawings, required, in part, that activities affecting quality be prescribed by documented instructions, procedures or drawings of a type appropriate to the circumstance. On April 15, 1993, Work Order (WO) 930011944 did not specify expected suction pressure values or what action to take upon indication of abnormal values even though fouling of the strainers was a known possibility.
The inadequate WO resulted in the running of the RHR "B" pump with indicated suction pressure less than 0 psig (off-scale-low) for approximately 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.
Due to the omission of acceptable values of suction pressure and the lack of guidance on what action to take upon receipt of abnormal values, WO 930011944 was inappropriate for the circumstances.
This is an apparent violation (50-440/930ll-03(DRP)).
The inspectors concluded that the licensee was slow to identify the safety significance of the strainer fouling and did not take prompt corrective action.
The licensee did not take corrective action appropriate to the safety significance of the event until the recurrence of strainer fouling and deformation in April 1993.
No deviations were identified. One unresolved item and two apparent
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violations, one with three examples, were identified.
3.
Monthly Surveillance Observations (61726)
For the surveillance activity listed below, the inspectors verified one or more of the following:
testing was performed in accordance with procedures; test instrumentation was calibrated; limiting conditions for operation were met; removal and restoration of the affected components were properly accomplished; test results conformed with technical i
specifications, procedure requirements, and were reviewed by personnel other than the individual directing the test; and any deficiencies identified during the testing were properly reviewed and resolved.by appropriate management personnel.
Surveillance Activity Title SVI-E12-T2003 RHR "C" Pump and Valve Operability. Test SVI-E51-T2001 RCIC Pump and Valve Operability Test PTI-E22-P0006 Division III High Pressure Core Spray Diesel Generator Auxiliary System Monitoring PTI-R43-P0002 Division 11 Diesel Generator Monthly Auxiliary System Monitoring No violations or deviations were noted.
4.
Monthly Maintenance Observation (62703)
Station maintenance activities of safety-related systems and components listed below were observed and/or reviewed to ascertain that activities-were conducted in accordance with approved procedures, regulatory guides and industry codes or standards, and in conformance with technical specifications.
The following items were considered during this review:
the limiting conditions for operation were met while components or systems were removed from service; approvals were obtained prior to initiating the work; activities were accomplished using approved procedures and were inspected as applicable; functional testing and/or calibrations were performed prior to returning components or systems to service; quality control records were maintained; activities were accomplished by qualified personnel; parts and materials used were properly certified; radiological controls were implemented; and fire prevention controls were implemented.
Work requests were reviewed to determine status of outstanding jobs and to assure that priority was assigned to safety-related equipment maintenance which may affect system performance.
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Specific Maintenance Activities Observed
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Division 11 Diesel Generator Quarterly Maintenance
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Turbine Power Complex Painting and Preservation
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Containment and Drywell Cleaning i
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Emergency Service Water Pump House Conduit. Plugging
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Containment Rattle Space Debris Removal I
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Pipe Support Sprina Can Restoration As discussed in paragraph 2, during drywell and containment inspections ~
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the resident staff identified several pipe support spring cans-l improperly configured. Spring cans were installed on system piping to
provide support while allowing for some pipe movement to compensate for expansion and contraction of the piping due to normal system operation.
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During maintenance activities, the spring cans were pinned with pre-set
bars to prevent pipe movement when the fluid was removed from the system.
or the piping was disconnected.
Following maintenance activities, the pre-set bars were to be removed to permit the spring cans to function.
On May 25, 1993, the inspectors identified two improperly configured -
spring cans in the drywell; one on the. reactor water cleanup (RWCU)
system and one on the nuclear closed cooling system.
In addition, following the inspectors observations, the licensee identified an additional spring can on the RWCU system with pre-set bars still installed.
In response to the above identified deficiencies, the licensee removed the pre-set bars from the affected spring cans, conducted an engineering evaluation to assess system operability, and conducted an inspection of other spring cans in the drywell. The licensee's engineering evaluation concluded that system operability was not affected by the pinned spring cans and inspection of affected piping revealed no damage or deformation.
Subsequent inspections of the drywell by the licensee did not identify any additional pinned spring cans.
The licensee initiated condition report CR-93-102 to document
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investigation of this event and track corrective actions.
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On May 28, 1993, during containment inspection, the inspectors identified two additional spring cans with pre-set bars installed.
The spring cans in question were installed on piping for the liquid radwaste disposal and mixed-bed demineralizer systems.
Following the identification of these discrepancies, the licensee removed the pre-set bars. An engineering evaluation was conducted and determined that system operability was not affected. The licensee established inspection teams to inspect all the spring cans in containment to verify that they were not pinned. As_ a result of this inspection effort, no other pinned spring cans were identified.
The licensee initiated condition report CR-93-107 to document investigation of the event and track corrective actions.
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The improperly configured spring cans were weakness in the licensee's
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post-maintenance restoration practices. Specifically, it appeared that the licensee's work procedures were either inadequate in controlling system configuration to ensure'that systems were properly restored or
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the procedures in place were not-being followed.
Pending inspector i
review of licensee investigation and root cause determination efforts with respect'to the improperly configured spring cans, this item will remain an unresolved item (50-440/930ll-04(DRP)).
q No violations or deviations were identified.
One unresolved item was identified.
5.
Operational Safety Verification (71707)
The inspectors observed control room operations, reviewed applicable logs, and conducted discussions with control room operators during this inspection period. The inspectors verified the operability of selected emergency systems, reviewed tagout records, and verified tracking of limiting conditions for operation associated with affected components.
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Tours of the pump houses, control complex, the intermediate, auxiliary, reactor, radwaste, and turbine buildings were conducted to observe plant equipment conditions including potential fire hazards, fluid leaks, and excessive vibrations, and to verify that maintenance requests had been initiated for certain pieces of equipment in need of maintenance.
The inspectors by observation and direct interview verified that the physical security plan was being implemented in accordance with the station security plan, i
The inspectors observed plant housekeeping, general plant cleanliness conditions, and verified implementation of radiation protection
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a.
Service Water System Reoairs
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Licensee response to service water pipe breaks was discussed in inspection report 50-440/93005(DRP), (Paragraph 5.a.).
During this inspection period the licensee completed repairs of the service water pipe, installation of manholes, and pressure testing of the service water piping. The inspectors verified that conduit sealing was completed, that flood protection sand bags were in place, and that covers for manholes and emergency core cooling system room ceiling plugs were in place prior to plant startup.
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Plant Startuo Observations On June 1,1993, upon completion of maintenance and repair activities, reactor startup from the service water and ECCS strainer forced outage was commenced.
The ascension to power operation was smooth with no major equipment problems. On June 2 the main generator was synchronized to the grid.
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The inspectors observed control room activities during the startup
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to assess control room decorum and operator control of startup
evolutions. The inspectors concluded that the operators performed the startup slowly and deliberately, demonstrating positive control of the evolution. Control room decorum was professional with proper management presence being provided as additional oversight of activities. 0/erall performance of the startup was evaluated as excellent.
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Reactor Water level Instrumentation Errors (Tl 2515/119)
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During this inspection period, the licensee's implementation of operator guidance and training with respect to reactor pressure vessel (RPV) water level indication following rapid
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depressurization transients was inspected.
In addition, the
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guidance and training was assessed for consistency with current plant emergency operating procedures'(EOPs).
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Based on discussions with plant operators and the licensee training staff, adequate training and guidance concerning operator actions after a depressurization event had been provided. The operators appeared knowledgeable of the guidance.
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Perry specific guidance is contained in a Standing Instruction (SI) dated November 19,1992 (this SI was re-issued clarifying an
SI dated September 11, 1992).
Licensed operators were knowledgeable of the guidance outlined in the boiling water reactors owners group (BWROG) letter dated October 16, 1992. The operators were currently not capable of executing the guidance in the October 16, 1992, letter because the procedure directing operator actions under these conditions had not successfully passed validation. Until the Perry procedure is effective, the November 19, 1992, Standing Instruction guidance will be followed by the operators.
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Training concerning this issue included the use of the BWROG support videos.
Also, Lesson Plan OT-3058-004-03E was used to provide operators with training and guidance on this issue. The lesson plan included a review of the fundamentals of level
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indication system operation and discussion of the Perry _ level instrumentation configuration and operation.
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Concerning simulator training on the effects of rapid depressurization on level indication, no simulator training had been conducted on this guidance. All licensed operators were to
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receive simulator training on this guidance during the first requa.
. ation training cycle following the successful validation of the Percy procedure addressing this issue.
Since the licensee
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did not have quantitative data to model this phenomenon, this reactor water level instrumentation failure was not available on i
the Perry simulator.
However, component failures that were
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available on Perry's simulator could be used in combination to simulate the phenomenon. The simulator model provided modeling of adverse containment condition effects on RPV water level instrumentation to the degree that the operators were led to enter the E0P contingency for RPV flooding.
In reviewing site E0Ps for inconsistencies with the BWROG's guidance, some problems were identified.
Resolution of the inconsistencies was incorporated into the Perry procedure which was under validation.
To minimize the likelihood of level indication errors, the licensee planned to monitor reactor water indication during plant startups and shutdowns specifically looking for level' differences between channels.
In addition, during a RPV hydrostatic test, the
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Inservice Inspection (ISI) group performed.a walkdown of the
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reactor coolant system piping. This included instrument sensing-lines from the vessel to the instrument racks.
Any leaks were noted and corrected.
This walkdown has been performed every refuel outage.
The licensee had previously experienced reactor level instrumentation anomalies during depressurization. On September 14, 1992, during a plant shutdown, " notching" of both the narrow and wide range channel A (common reference leg) level indication was noted.
The cause for the " notching" was a leaking fitting associated with level transmitter C61N010. The leaking fitting was replaced and during a subsequent plant shutdown on
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January 9,1993, no further level indication problems were observed.
d.
NRC Bulletin 93-03:
Resolution of Issues Related to Reactor
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Vessel Water level Instrumentation in BWRs The inspectors verified that the licensee had developed short term compensatory actions as requested by the Bulletin.
This included operator training which was observed by the inspectors.
The compensatory actions appeared appropriate.
However, since no inspection guidance had been received, additional inspection will be required to verify compliance.
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e.
Incline Fuel Transfer System Penetration Bellows On March 3, 1992, the NRC issued Information Notice.(IN) 92-20,
" Inadequate Local Leak Rate Testing," to alert licensees to problems involving local leak rate testing (LLRT) of containment penetrations.
One of the problems discussed in IN 92-20 involved i
the LLRT of two-ply steel expansion bellows.
An event at the Quad
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Cities Nuclear Power Station revealed that an LLRT performed by applying pressure between the two plies could not be used to accurately measure the leak rate that would occur through the
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bellows under accident conditions.
The two plies of the bellows were in contact, restricting the flow of the test medium to crack locations that were discovered later. The NRC found that this
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problem was not isolated to the bellows manufactured by the vendor
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at Quad Cities. Any two-ply bellows of similar construction may be susceptible to this problem.
The licensee's initial review of IN 92-20 determined that the problem was not applicable to the site.
This determination was based on the conclusion that the types of bellows used on site were not of the type susceptible to the problem. On May 26, 1993, the licensee re-evaluated IN 92-20 after a similar BWR-6 licensee identified its susceptibility to the problem.
During this re-evaluation, the licensee discovered that the inclined fuel transfer system (IFTS) containment penetration bellows was of the two-ply type discussed in IN 92-20.
On May 28, 1993, a discussion was held between the NRC staff and the licensee regarding past bellows LLRT and containment integrated leak rate test performance. As a result of these discussions, it was determined that, based on pren ous testing, no significant problems with the_ bellows integrity was evident.
However, a confirmatory visual inspection of the bellows diaphragm should be conducted.
In addition, the NRC staff indicated that a long term inspection plan should be developed to test the penetration.
The licensee committed to develop and document long term actions to address possible leakages prior to restart from the fourth refueling outage scheduled for February 1994.
On May 29, 1993, a visual inspection (VT) of the IFTS bellows identified several areas of surface scratches and one dent approximately 1/32 M.ch deep.
No signs of crack-like indications emanating free, any of the scratch areas were identified.
To conf um the findings of the VT, a-liquid penetrant inspection (PT)
of the dent and some of the scratch areas was also conducted with no relevant indications noted.
Based on the above inspections and previous LLRT results, the licensee concluded that the bellows was capable of performing its design function of ensuring containment integrity.
The inspectors reviewed the VT and PT test records.
Pending NRC staff review of licensee long term actions to develop a confirmatory test methodology to confirm bellows integrity, this item will remain open (IFI 50-440/93011-05(DRP)).
I No deviations or violations were identified. One Inspection Followup Item was identified.
6.
Onsite followup of Events at Operatina Power Reactors (93702)
a.
General
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The inspectors performed onsite followup activities for events
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which occurred during the inspection period.
Followup inspection included one or more of the following:
reviews of operating logs, procedures, and condition reports; direct observation of licensee actions; and interviews of licensee personnel.
For each event,
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the inspectors reviewed one or more of'the following:
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sequence of actions, the functioning of safety systems required by plant conditions, licensee actions to verify consistency with
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plant procedures and license conditions, and verification of the nature of the event. Additionally, in some cases, the inspectors verified that the licensee's investigation identified root causes of equipment malfunctions and/or personnel errors and the licensee was taking or had taken appropriate corrective actions'
Details
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of the events and licensee corrective actions noted during the inspector's followup are provided below, b.
Details (1)
Residual Heat Removal System Room Cooler Failure -
On May 19, 1993, at about 9:00 a.m. (EDT), the licensee shut down the room cooler for residual heat removal (RHR) pump
"A" to investigate unusual vibrations and noises from the room cooler fan. Subsequent investigation identified damage to the-fan housing. RHR train "A" was considered inoperable even though there were no significant changes in equipment or room temperature.
The licensee inspected other ECCS room coolers for.similar problems.
On May 20, 1993, at about
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2:00 p.m., during inspection of the cooler for the RHR pump
"B" room, the licensee discovered that a support plate was missing from the room cooler housing. After an initial
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evaluation, RHR train "B" was declared inoperable at 7:25 p.m., even though the train "B" room cooler was operating with no abnormal vibration. At 9:51 p.m.,
the licensee notified the NRC Operations Center of the event via the ENS. The inspectors verified that room and equipment temperatures were normal in both rooms and verified'that the
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room cooler in RHR pump room "B" was operating normally.
After further evaluation the licensee concluded that the RHR
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pump "B" room cooler had not been inoperable and retracted its ENS notification.
The inspectors will complete their review of this event in a later inspection.
(2)
Loss of Hiah Pressure Core Sorav Minimum Flow Valve Position Indication On May 26, 1993, at about 2:32 a.m., while in Operational Condition 4, COLD SHUTDOWN, remote position indication for the high pressure core spray (HPCS) minimum flow valve was lost while shutting down the HPCS pump to standby readiness.
Following testing as HPCS was being secured, the control room operators noticed that the green closed indicating light did not come on as the valve was stroking closed. The valve was verified closed locally, and. fuses were verified to be good. To support further troubleshooting, the pump breaker was racked out and the HPCS system was declared
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inoperable at 3:10 a.m.
At 5:44 a.m., the licensee notified
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I the NRC Operations Center of the event via the ENS.
Subsequent investigation by the licensee determined that the cause for the loss of valve position indication was a dirty contact on the valve operator limit switch. These contacts only provided circuit continuity to illuminate the closed indicating light. The contacts were cleaned and the valve
was retested satisfactorily.
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I event notification based on the evaluation that the HPCS l
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Though the valve closed position indication failed, the valve was still capable of functioning.
The licensee initiated condition report CR-93-013 to document the event and track corrective-actions. The inspectors will review the event and assess licensee corrective actions in future reviews of the licensee's motor-operated valve maintenance program.
(3)
Inadvertent Hiah Pressure Core Soray Initiation On June 7, 1993, at about 4:24 a.m., while operating at 82 percent reactor power, a high pressure core. spray (HPCS)
initiation signal was received. As a result, the Division III diesel generator and emergency service water pump auto-started and the HPCS pump injected into the reactor vessel.
The operators responded by entering 0NI-E12-1, " Inadvertent Initiation of ECCS/RCIC." The operators verified that the initiation was inadvertent and proceeded to secure the HPCS pump at approximately 4:25 a.m.
Based on post event review of computer data, the HPCS system injected into the reactor vessel for approximately 25 seconds, resulting in an approximate 2-percent decrease in reactor power and an approximate 7-inch increase in reactor level.
Reactor pressure control and level control sysia ns responded as expected restoring plant parameters to ' pre-transient conditions.
At 4:30 a.m., the licensee simultaneously declared and exited an UNUSUAL EVENT.
The event was declared in accordance with emergency action level initiating. condition A.I.1, " Initiation of an Emergency Core Cooling system (ECCS) with flow to the Reactor Pressure Vessel (RPV)."
Local, state, and county authorities were notified of the event at 4:40 a.m.
The licensee informed the NRC Operations Center at 4:43 a.m. via the ENS.
The licensee notified the I
inspectors of the event and the inspectors responded to the site to observe the licensee's recovery from the event.
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Based on licensee investigation of the event, the apparent
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cause was the failure of the Division 3 reserve battery charger which resulted in a false RPV low water level signal.
Prior to this event, the Division III reserve charger and the Unit 2, Division III battery were aligned to supply the Unit 1, Division III,125 Volt. DC (Vdc) bus in preparation for a load test on the Unit 1, Division III
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battery.
Due to an apparent failure of the reserve battery charger voltage control circuitry, output voltage increased to greater than 150 Vdc.
The resultant high voltage on the Division III DC distribution bus resulted in a trip of the Division III instrument power supply on high voltage. This caused a HPCS initiation signal.
The licensee initiated condition report CR 93-114 to document investigation of this event and track corrective actions.
The licensee planned to submit an LER in accordance with 10 CFR 50.73.
The inspectors will review that report in a future inspection period.
In addition, the inspectors will review the failure of the Division 3 reserve battery charger and reactor protection instrumentation response to the event in a future inspection.
4)
Control Room Ventilation Failure - TS 3.0.3 Entry On June 8, 1993, at about 3:45 a.m., while operating at 95 percent reactor power, both trains of the control room emergency recirculation system were inoperable resulting in a TS 3.0.3 entry.
Prior to the event, the "B" train of the control room ventilation system and chilled water system was tagged out-of-service for scheduled maintenance.
The event occurred when, following the receipt of a 480 volt bus ground alarm on the Division 1 bus, the "A" control room j
supply fan tripped.
Immediate investigation indicated that
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all three main power fuses had blown.
Post-event investigation determined that the motor had shorted to ground, blowing the fuses. With both trains of control room emergency recirculation inoperable, TS 3.0.3 was entered and action was initiated to restore the
"B" train.
At 4:41 a.m., the licensee informed the NRC Operations Center of this event via the ENS. The licensee notified the inspectors.
The resident inspector responded to the site to observe the licensee's recovery from to the event.
The licensee cleared all of the "B" train tagouts and attempted to start the
"B" train. The "B" train supply fan tripped within a few seconds.
Immediate troubleshooting of this fan indicated that the
"B" phase main power fuse had blown and the overload relay had tripped. A resistance test of the motor was performed and indicated that the motor and cables were not shorted. Three new fuses were installed and the "B" supply fan was restarted successfully.
To verify
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proper operation of the "B"Lsupply fan, running amperage
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readings were taken and found to be within normally expected
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operating values.
In addition, the blown fuse was x-ray inspected to determine-the cause of activation.
The j
inspection determined that the "B" phase fuse had tripped on
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the instantaneous overcurrent element.
The failure appeared to be a " minor activation" of the fuse, since the silica
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filler and insulating material in the fuse did not melt to produce a large amount of insulating glass as would be expected for a fault condition.
Based on the above preliminary inspection results, the licensee declared the
"B" train operable at 7:30 a.m. and TS 3.0.3 was. exited.
The licensee issued a management preliminary report documenting initial investigation results and recommended corrective actions.
In addition, condition report CR-93-115 was initiated to document and track corrective actions. The licensee planed to submit an LER for this event.
The inspectors will complete their review of this event after the LER is submitted.
No violations or deviations were identified.
7.
llanagement Meetings On June 7 and 8, 1993, Mr. John Martin, Regional Administrator, i
Region III, visited the Perry plant.
During the visit, Mr. Martin toured the facility observing plant conditions and on-going plant operations.
Mr. Martin met with members of the licensee staff to discuss recent plant performance.
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8.
Inspection Followuo items An Inspection Followup Item is a matter which has been discussed with
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the licensee, which will be reviewed further by the inspectors, and
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which involve some action on the part of the NRC or licensee or both.
Inspection followup items disclosed during the inspection were discussed in paragraph 5.e.
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9.
Unresolved items An Unresolved Item is a matter about which more information is required in order to ascertain whether it is an acceptable item, a violation, or a deviation. Unresolved items disclosed during the inspection are
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discussed in paragraphs 2 and 4.
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10.
Exit Interviews The inspectors met with the licensee representatives denoted in l
paragraph I throughout the inspection period and on June 23, 1993. The inspectors summarized the scope and results of the inspection and i
discussed the likely content of the inspection report.
The licensee did
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no't indicate that any of the information disclosed during the-inspection
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could be considered proprietary in nature.
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