IR 05000440/1993005
| ML20044G176 | |
| Person / Time | |
|---|---|
| Site: | Perry  |
| Issue date: | 05/19/1993 |
| From: | Lanksbury R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20044G173 | List: |
| References | |
| 50-440-93-05, 50-440-93-5, NUDOCS 9306020123 | |
| Download: ML20044G176 (14) | |
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U. S. NUCLEAR REGULATORY COMMISSION REGION 111 Report No. 50-440/93005(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 Inspection Conducted: March 20 through April 30, 1993
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l Inspectors:
D. Kosloff
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A. Vegel M. Huoer
J. Kudrick
Ry n4ky
\\EV 7[.
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Approved By:
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R. D. Lanksbury Ti'ef Date
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Reactor Projects ection 3B l
i Inspection Summarv i
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Inspection on March 20 throuch April 30. 1993 (Report No. 50-440/93005(DRPH
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Areas Inspected: Routine unannounced safety inspection by resident, region
based, and headquarters based inspectors of licensee action on previous
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. inspection findings, surveillance observations, maintenance observations.
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operational safety verification, and event followup.
Results:
In the five areas inspected, no violations or deviations were noted.
The following is a summary of the licensee's performance during this i
inspection period
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t Plant Operations
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The plant operated at full power until March 26, 1993, when an
underground service water pipe ruptured.
The reactor was tripped and-
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subsequently placed in cold shutdown.
Due to the service water rupture,
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flooding in the plant resulted in an Alert declaration.
Operator response to the event was excellent.
Maintenance / Surveillance The quality of observed maintenance and surveillance activities was I
generally good.- However, coordination of residual heat removal punp testing was poor.
9306020123 930519 PDR ADDCK 05000440 G
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Enoineerino and Technical Support
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Engineering and technical support of outage activities was good. The.
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incident response team formed in response to the suppression pool strainer fouling issue was aggressive and thorough in evaluating
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strainer performance.
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t Safety Assessment and Ouality Verification
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Management support of the fouled suppression pool strainer incident l
response team was appropriate.
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DETAILS 1.
Persons Contacted Cleveland Electric 111uminatino Company
- R. Stratman, Vice President - Nuclear D. Igyarto, General Manager, Perry Nuclear Power Plant (PNPP)
K. Donovan, Manager, Licensing and Compliance M. Gmyrek, Operations Manager, PNPP
- S. Kensicki, Director, Perry Nuclear Engineering Department (PNED)
j F. Stead, Director, Perry Nuclear Support Department (PNSD)
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H. Hegrat, Compliance Engineer, PNSD E. Riley, Director, Perry Nuclear Assurance Department (PNAD)
- W. Coleman, Manager, Quality Assurance Section, PNAD
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B. Walrath, Manager, Nuclear Engineering Section, PNED
- V. Concel, Manager, Technical 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 L. Teichman, Plant Unit Supervisor, Plant Maintenance Section
- M. Bezilla, Manager, Operations
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W. Wright, Manager, Instrument & Control Section F. Von Ahn, Unit Lead, Mechanical Engineering Unit H. Ruppert, Senior Project Engineer, Mechanical Support Unit
- Denotes those attending the exit meeting held on May 3, 1993.
- Denotes those attending the management meeting held in Region III on
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April 2, 1993.
2.
Licensee Action on Previous Inspection Findinas (40500. 71707. 92701.
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92702)
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(00en) Inspection Followup Item (50-440/93004-Ol(DRP)):
As previously
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documented in inspection reports 50-440/92026 and 50-440/93004, in January 1993, the licensee identified deformation of the residual heat i
removal (RHR) "A" and "B" suppression pool suction strainers. As part of the licensee's corrective action plan, the strainers'were replaced and the suppression pool was cleaned during the mid-cycle maintenance outage in February 1993.
Subsequently, on April -14,1993, while
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performing a video inspection of the RHR "A" and "B" strainers, the
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licensee again identified accumulated debris on the "B" suction strainer. The "A" strainer did not show any indication of fouling. The licensee initiated condition report CR-93-085 to document investigation l
findings and track corrective actions.
In addition, an incident
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response team was formed to investigate the circumstances surrounding j
the repeated accumulation of debris on the RHR "B" suction' strainer.
To assess the impact of the debris on pump performance, on April 15 the licensee initiated a planned 72-hour test run of the "B" RHR pump. The pump was lined up for suppression pool cooling, and an additional j
pressure gauge was installed to monitor suction pressure.
Initially, suction pressure indicated 9.25 pounds.per square inch gauge (psig).
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After 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> suction pressure dropped to approximately 0.5 psig.
Eight hours into the test run indicated suction pressure dropped to less than 0 psig and the pump was secured. Evaluation of licensee conduct of this pump performance test is further discussed in section 3 of this report.
Though the minimum net positive suction head (NPSH) required for pump i
operation, about 20 inches mercury vacuum as indicated at the pump suction pressure instrument, was not reached, the test run indicated that substantial fouling of the strainer had occurred. Additional inspection of the "B" RHR strainer was conducted and some deformation was identified.
In addition, all other ECCS strainers were inspected
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and found to be clean. On April 17, the RHR "B" pump was run for l
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to monitor suction pressure.
Initial suction pressure was
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i 9.25 psig, and eventually dropped to approximately 0 psig after 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> of operation. Suction pressure remained at 0 psig for the remainder of
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the test.
i Following the second RHR "B" test run, an inspection of the strainer i
verified it was deformed between the stiffener plates, similar to the
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deformation previously identified in January 1993. However, no cracks
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were identified. The debris on the strainer was collected and samples
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were shipped offsite for analysis. The debris on the strainer consisted i
primarily of interwoven fibrous materials with dirt and corrosion l
products trapped in the fibers. Subsequent evaluation identified that i
the fibers predominately present were similar to the fiberglass material
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contained in the drywell ventilation system roughing filters.
Some
fibers similar to the containment ventilation system roughir.g filters (a
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woven cotton material) were also noted.
In addition, on April 28, the
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licensee identified a piece of drywell ventilation roughing filters
approximately 1 foot x 1 foot in the weir area of the suppression pool j
inside the drywell.
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The roughing filters were installed on the intake of the air handling units (AHus) to prevent the accumulation of dust on the cooling coils.
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The roughing filters were made of 24 inch x 24 inch x 2 inch loose mats of fiberglass strands. Three AHUs are installed in the drywell, each
contained 18 filter mats. The filters were held in place on the AHUs by a wire mesh with spacing approximately 4-inch square. The inspectors i
were concerned that such non-safety fibrous material represented a major
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potential debris source in the event of a loss of coolant accident
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(LOCA). Had a LOCA occurred, it was possible that most of the filter l
material would have ended up in the suppression pool.
Because of the
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amount and construction of the fibers, it would have been a major threat to clog the strainers.
This appeared to be a significant generic issue i
requiring the attention of all boiling water reactor owners.
The
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licensee had initiated action to remove the roughing filters from the
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drywell and the containment prior to plant startup.
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Licensee corrective action in response to these events was directed by an incident response team (IRT) comprised of engineering and operations
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personnel.
Following review of strainer inspection results and pump l
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performance data, a corrective action plan was initiated. Corrective actions to prevent recurrence included:
Inspection and cleaning of the drywell and containment Evaluation and redesign of suppression pool strainers
Evaluation of strainer backflushing capability
Analysis of debris sources At the end of this inspection period, corrective actions were in progress.
The NRC's response to the identification of fouling and deformation of the RHR strainer included the issuance of a Confirmatory Action Letter (CAL) on April 16, 1993.
In addition, a special review group (SRG) was initiated on April 24 to address programmatic issues related to the suppression pool suction strainers.
In support of the SRG, a site review team (SRT) conducted an onsite inspection of licensee investigation and corrective action efforts on April 27 through April 30. The SRT, consisting of regional and headquarters based inspectors, conducted a walkdown of the containment and drywell to
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assess cleanliness and material condition, reviewed documentation, and discussed investigation results with licensee IRT members to evaluate the adequacy of corrective action efforts in progress.
Licensee cleanup efforts, which consisted of vacuuming floors and gratings to remove dust and dirt, and the removal of loose materials such as tape, paper, and plastic, were in progress during the SRT onsite inspection. The SRT observed very little dirt and debris in areas that had been cleaned by the licensee; however, areas that had not been cleaned contained significant quantities of dust, dirt, and light debris (duct tape, nylon cable ties, plastic fragments, etc.).
The suppression pool itself was clear, with only a few small objects floating on the surface. Overall, the inspectors concluded that licensee efforts in progress to clean the containment and drywell were effective.
The inspectors also conducter a review of the licensee's new strainer design and supporting calculations.
In addition, a review of pump net
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positive suction head (NPSH) requirements was conducted.
The site team reviewed design criteria for and specifications of the previous and planned design for the ECCS suction strainers.
General Electric (GE) specified that the suction piping from the suppression pool be designed so when any one suction strainer is 50 percent plugged (unless the strainers can be designed specifically to prevent plugging or fouling), adequate NPSH would still be available. Additionally, the system suction strainer was to be designed such that it does not become more than 50 percent plugged following 100 days of post-LOCA operation.
The strainer mesh openings were also to be capable of screening effectively all foreign particles of sufficient size to clog the pump cyclone separators or containment spray nozzles (greater than a 3/32-
inch sphere).
The suction strainer design specification written by the engineer at the time of construction indicated that the flow rates for the RHR strainers
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were 8500 gallons per minute (gpm) and shall be designed to pass the design flow rates with a maximm pressure drop of 1 psi when 50 percent of the strainer surface was blocked from flow.
The NRC inspectors noted differences between the current design and the new design of the strainers.
It appeared that the licensee redesigned the strainers using the original specifications with the following changes:
1) The new design flow rate for the RHR strainers was 7800 gpm vice 8500 gpm; and 2) The new strainers would be capable of meeting their design flow rates with a pressure drop of 4 pounds-per-square-inch-differential (psid) vice 1 psid when 50 percent plugged.
In addition to the criteria specified by the original design, the NRC reviewed the extent to which the licensee evaiuated the new strainer design by the guidelines established in Regulatory Guide 1.82, " Water Sources for Long-Term Recirculation Cooling Following a Loss-of-Coolant Accident," revision 1.
The plant was not licensed using the guidance in Regulatory Guide 1.82, however the licensee indicated that the new strainer was designed using Regulatcry Guide 1.82 as a guide. The licensee indicated that the new strainer design met all of the criteria of Regulatory Guide 1.82, except the requirement that the flow velocity at the strainer be less than 0.2 feet-per-second (fps).
The redesigned strainers were being constructed in conjunction with the effort to properly qualify the design. Based on the design parameters provided, the strainer area had more than doubled from the current design and the flow velocity was decreased from 2.27 fps to 0.98 fps.
The strainer redesign appeared adequate, however, the approved strainer design calculations were not yet available for the site team to review.
The licensee reviewed the available NPSH with the degraded strainers and calculated the maximum differential pressure across the strainer before adequate NPSH was no longer available. The strainer redesign appeared adequate with respect to NPSH, but the calculations of the-available NPSH were still under review.
Based on a review of the circumstances involving the suppression pool suction strainer fouling issue and licensee efforts in progress in response to the events, the inspectors concluded the following:
Licensee efforts planned or in progress to prevent recurrence appeared effective. Positive initiatives included:
Developing a strainer backflush capability
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Cleanup of the containment and the drywell
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Development of enhanced inspection criteria to maintain a
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high level of cleanliness in containment and the drywell Strainer redesign
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Developing a monitoring program for ECCS strainer
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differential pressure
Non-safety fibers similar to roughing filter material represented a major potential debris source in the event of a LOCA and appeared to be a generic safety significant issue.
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Proper understanding of NPSH performance must consider the
combination of insulation and operational debris to properly assess pump performance.
The NRC's review of licensee investigation efforts was in progress at the end of this inspection period. Final assessment of the adequacy of licensee corrective actions will be documented in a future inspection report.
In addition, the information collected during this inspection period will be incorporated into an overall program effort to analyze generic strainer performance by the Office of Nuclear Reactor Regulation.
No violations or deviations were identified.
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3.
Monthly Surveillance Observations (61726)
for the surveillance activity listed below, the inspectors verified one
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or more of the following:
testing was performed in accordance with
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procedures; test instrumentation was calibrated; limiting conditions for operation were met; removal and restoration of the affected components
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were properly accomplished; test results conformed with technical specifications, procedure requirements, and were reviewed by personnel
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other than the individual directing the test; and any deficiencies l
identified during the testing were properly reviewed and resolved by appropriate management personnel.
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Surveillance Activity Title SVI-Cll-T5376D Scram Discharge Volume Level High
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Channel-D Functional
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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 j
were implemented.
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E Work requests were reviewed to determine the status of outstanding jobs and to assure that priority was assigned to safety-related equipment maintenance which may affect system performance.
Specific Maintenance Activities Observed e
Service Water Pipe Repair e
Offgas System Charcoal Drying e
Adjust and Repack Valve IN36F0250A i
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"A" and "B" RHR Pump Performance Testing
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Containment and Drywell Cleaning e
Turbine Building Closed Cooling Heat Exchanger Cleaning
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a)
Residual Heat Removal Pump Test Coordination On April 15, 1993, following identification of residual heat
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removal (RHR) "B" suppression pool suction strainer fouling, the licensee initiated work order 93001194 to install a more accurate temporary pressure gauge to monitor suction pressures for a planned 72-hour pump test run. The gauge was installed to supplement the permanently installed suction pressure gauge. The new gauge was placed in service at 9:43 p.m. and indicated i
9.25 psig, the static head of the suppression pool. At 10:30 p.m., the pump was started and indicated suction pressure dropped to 6.4 psig. For the 72-hour test run, the work order directed technicians to record pressure readings ever) 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> or
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as otherwise directed by the system engineer or unit supervisor.
No guidance was provided to the technician regarding expected values or what action to take if an abnormal value was obtained.
On April 16, at 3:06 a.m.,
indicated suction pressure was 0.5 psig.
The technician recorded this value in the work-in-progress log as required by the procedure. At 6:30 a.m., the technician recorded that the test gauge indicated less than 0 psig (off scale low) and that the permanently installed gauge indicated 0 psig. At about 8:00 a.m., the ;ystem engineer observed the low suction pressure indication and became concerned that the pump may approach minimum NPSH limits and cavitate. Since the temporary test gauge had an indicated range of 0 - 15 psig, the system engineer realized that the actual suction pressure was not known.
Even though the permanently installed suction pressure gauge indicated 0 psig, he could not rely on the accuracy of that gauge.
l Consequently, upon the system engineers' request, the "B" RHR pump was secured at 8:24 a.m.
Neither the shift supervisor or unit supervisor were made aware of the low indicated suction pressure until the shift supervisor further pursued the reasons for securing the pump prior to conclusion of the planned 72-hour test run. The shift supervisor then notified the operations manager of the event at approximately 9:45 a.m.
As a result, the operations manager directed the formation of an incident response team to investigate the RHR strainer fouling issue and RHR "B" was j
declared inoperable in the low pressure coolant injection mode at i
3:10 p.m. until further testing could be completed.
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This event was of concern to the inspectors due to the apparent inadequacies of the work order in providing specific guidance to i
the technician on what action *,o take when abnormal readings were
obtained. More fundamentally, the work order failed to identify j
the expected range of indicated suction pressures.
In addition, i
the inspectors were concerned with the poor communication of l
system status during the event, since control room operators were
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not cognizant of the status of the testing. The failure of i
personnel in the field to properly communicate the indicated low j
suction pressure to control room operators prevented the
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opportunity for an independent assessment of system availability.
Though there were no consequences as a result of this event, the
event indicated a lack of coordination between the control room
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and operators in the plant. Of particular concern was the failure
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of the operations staff to aggressively pursue system testing l
status so that the capability of the system could be promptly assessed.
j The newly assigned operations manager, who assumed his duties after this event, acknowledged the inspectors concerns. He stated
that one of his goals was to establish a plant culture that i
insures thorough planning and communications related to plant evolutions. He stated that he plans to be directly involved in improving r -.unications and helping personnel develop the ability j
to plan e lively and communicate appropriate information.
t The inspet. ors will review the licensee's performance in this area
in future inspections.
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No violations or deviations were identified.
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5.
Operational Safety Verification-(71707)
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The inspectors observed control room operations, reviewed applicable
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logs, and conducted discussions with control room operators during this
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inspection period. The inspectors verified the operability of selected i
emergency systems, reviewed tagout records, and verified tracking of limiting conditions for operation associated with affected components.
Tours of the pump houses, control complex, and the intermediate,
auxiliary, reactor, radwaste, and turbine buildings, were conducted to observe plant equipment conditions including potential fire hazards,
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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 l
verified that the physical security plan was being implemented in
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accordance with the station security plan.
The inspectors observed plant housekeeping, general plant cleanliness
conditions, and verified implementation of radiation protection l
controls.
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a.
Service Water Leak l
On March 26, 1993, at about 3:22 p.m. (EST), a nonsafety-related
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30-inch fiberglass reinforced plastic (FRP) pipe carrying service
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s water (SW) from the SW pump house to the Unit I turbine building
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catastrophically failed approximately 13 feet underground near the l
water treatment building. Water from the pipe break flooded the western portion of the site and entered various plant buildings causing minor flooding. Reactor operators commenced a fast reactor shutdown and manually scrammed the reactor from about
66 percent power. Under the licensee's emergency plan, an Alert
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was declared at 3:35 p.m. due to the flooding. The SW leak was
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stopped about 16 minutes after the pipe ruptured when operators (
stopped the SW pumps. The plant was placed in cold shutdown at
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10:10 p.m. on March 26, and the Alert was terminated on March 27 at 1:05 a.m.
The resident inspectors responded to the event and observed water pouring from electrical conduits into the control
complex. The inspectors then observed the licensee's response in the control room, technical support center, and operations support center. The inspectors also toured the plant to determine the
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e.xtent and immediate effects of the flooding. An augmented i
inspection team (AIT) was formed to gather information on the event. Details of the event and the licensee's response to the
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event are discussed in AIT inspection report 50-440/93006(DRS).
l After the AIT was terminated on April 2,1993, the resident I
inspectors continued to monitor and observe the licensee's event i
response activities and recovery plan. During the inspection period, the licensee completed cleaning and inspecting the supply i
and return lines except for smaller diameter (8,14, and i
24-inch) piping. The inspections were performed by contract (FRP)
piping inspectors working inside the pipe.
Inspections of the 24-inch diameter piping had begun using remote-operated cameras.
The licensee was not planning to inspect the 8-inch and 14-inch
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piping. The licensee was adding three manways (one was complete)
to the existing piping to facilitate future inspections and
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repairs. A fourth manway was added in the pipe used to replace the broken section of pipe. The licansee indicated that the repairs should provide a high degree of confidence that no leaks
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would occur before the sixth refueling outage (RF06) scheduled to
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begin March 1, 1997. The licensee indicated that further l
engineering evaluations would be performed to determine if additional long-term corrective actions were warranted to ensure
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satisfactory performance past RF06. The licensee identified 27 areas, including one leak, to be repaired. At the end of the
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inspection period, 24 areas had been repaired.
Installation of the replacement for the broken section of piping had also been
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completed. The licensee also decided to close the supply and
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return lines to the Unit 2 turbine building closed cooling heat exchangers.
While responding to the event, an operator misinterpreted a step t
in procedure ONI-P41. As a result, steam jet air ejector exhaust
steam was discharged into the offgas system without being
condensed. This had the potential to damage the offgas charcoal beds.
The inspectors observed the licensee's procedure for drying
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the charcoal beds. Charcoal testing indicated that the charcoal had not been damaged.
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During the event, electrical conduits allowed water to enter the l
control complex.and the emergency SW pump house.
The inspectors
observed work in progress to seal those. conduits.
The licensee
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planned to complete that work prior to plant startup.
b.
Feedwater Flow Anomalies at low Power
i On November 1,1992, during a plant startup, the licensee.
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identified that feedwater flow, as determined by the differential-
pressure across the feedwater venturis, was indicating lower than
expected at low power levels. Following initial troubleshooting i
to determine the cause for the flow disparity, the licensee placed i
a 99 percent administrative limit on reactor power until a more
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indepth evaluation of the problem could be performed.
Initial
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inspector followup of the feed flow indication problem was
documented in inspection report 50-440/92022(DRP) dated
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December 10, 1992.
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During the mid-cycle maintenance outage in January 1993, the i
I licensee conducted further investigation into the cause of the problem. The feedwater flow instrumentation loops were verified-
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to be functioning properly and in calibration. The transmitter
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equalizing valves were inspected for leakage and no problems were
identified.
In addition, the feedwater venturis and flow i
straighteners were disassembled, inspected, and cleaned.
-t Inspection of flow straighteners found a slight buildup of iron-j oxide. This was expected because of the carbon steel materials used in the flow straighteners. The flow straightener tubes were
.1 clean-and there was no blockage.
Instrument taps.and sensing
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lines were also found to be clean. Following cleaning of the
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venturis, 3 millimeter deep _ indications were observed on the "A" l
venturi and 1 millimeter deep' indications were observed on the
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venturi.
Based on licensee and vendor analysis of the oxide layer and indications found during the inspections, no definitive
correlation to the lower indicated feed' flow at' low power was i
established.
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Prior to the startup from the mid-cycle outage, the process computer was reprogrammed to have the feed pump flow-to-the-vessel i
signal be automatically substituted as the feedwater flow signal
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when it was a higher value than the main feedwater flow signal j
obtained from the venturi. The alternate ard/or redundant i
indication of feedwater flow taken from the pumps did not exhibit the low power flow anomaly and therefore indicated a higher'value (more conservative) than the venturis at low power. During the'
q subsecuent startup.from the outage in March 1993, at low power levels, the feed pump flow was used for the heat balance. Above 40 percent power,:when the venturis indicated a higher, more conservative flow rate, the flow rate obtained from the venturis was used for the heat balance.
On March 17, following review of the data obtained during the startup and based on comparison to other indications of power, including steam flow and electrical output, the licensee -
determined that the feed flew indication at high power levels was
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accurate. As a result, the 99 percent administrative power limit was lifted and 100 percent power operation was authorized.
f Although the licensee expended extensive inspection and analysis efforts in determining the cause for the feedwater flow anomalies l
at low power, the root cause for the problem was not identified.
Licensee efforts to determine the cause for the problem were in progress.
Future activities planned included continued
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investigation and collection of feed flow data, with a tracer method being considered for measuring actual flow across the venturis. The licensee initiated condition report CR 93-24 to document investigation results and corrective actions. The inspectors will continr to assess licensee efforts with respect
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to this issue during r. Jtine inspector followup of plant activities.
No deviations or violations were identified.
6.
Onsite Followup of Events at Operatina Power Reactors (93702)
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General l
The inspectors performed onsite followup activities for events
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, 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 plant procedures and license conditions, and verification of the
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nature of the event. Additionally, in some cases, the inspectors
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verified that the licensee's investigation identified root causes
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of equipment malfunctions.and/or personnel errors and the licensee
was taking or had taken appropriate corrective actions. Details i
of the events and licensee corrective actions noted during the inspector's followup are provided below.
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Details (1)
Containment and Drywell Purae System Isolation On March 25, 1993, at approximately 5:28 p.m., while in
Operational Condition 1, POWER OPERATION, the containment
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i and drywell purge system isolated as a result of alarms received on the containment ventilation radiation monitors.
The containment and drywell purge system was running in support of a reactor water cleanup filter demineralizer backwashing evolution. After initiating the backwashing, increased radiation levels were detected by the containment vent exhaust plenum radiation monitor. Upon reaching the high-high alarm setpoint, the containment and drywell purge system automatically isolated as designed.
Immediate corrective actions included entering the off normal instruction (0NI) for the alarms, evacuation of containment,
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and verification that the containment purge system isolated as required. The licensee informed the NRC Operations Center of this event via the Emergency Notification System (ENS) at about 8:00 p.m. on March 25.
The licensee initiated condition report CR 93-072 to document the investigation of root cause for the high radiation signal. The licensee also submitted licensee event report (LER) 93-09 on April 26, 1993, in accordance with 10 CFR 50.73, documenting this event.
The inspectors will complete their review of that report in a future inspection period.
(2)
Service Water Pine Break. Manual Scram. and Alert On March 26, 1993, at about 3:22 p.m., while operating at
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100 percent power, a 30-inch reinforced fiberglass pipe in the SW system failed. The failure location was underground
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about 50 feet south of the water treatment building in the plant yard inside the protected area.
In anticipation of
the loss of SW, plant operators initiated a rapid power
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reduction and manually scrammed the reactor from 66 percent i
power in accordrnce with plant procedures. As a result of the break, approximately 1.7 million gallons of water were
released from the SW system. Subsequently, reports of water
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intrusion into some of the plant buildings including the i
auxiliary building, intermediate building, and the turbine
power complex, were received. At 3:35 p.m., the shift l
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supervisor declared an Alert due to the flooding.
The plant was placed in cold shutdown at 10:10 p.m. on March 26, and
the Alert was terminated on March 27 at 1:05 a.m.
Specific
details of the NRC followup of the event are contained in
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AIT inspection report 50-440/93006(DRS) dated April 15, t
1993.
The licensee notified the NRC of the event and
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maintained communications with the NRC throughout the
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duration of the Alert. The licensee submitted LER 93-10 on
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t.pril 26, 1993, in accordance with 10 CFR 50.73 documenting this event. The inspectors will complete their review of
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that report in a future inspection period.
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3)
Oil Spill l
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On April 8,1993 at approximately 8:30 a.m., the licensee discovered an oil spill path to an off-site stream.
While pumping down the service water (SW) system to the storm l
drain system in preparation for a SW pipe inspection, oil
!
was identified in the service water weir structure and in
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the hose discharging to the storm drain. Upon noticing the
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f oil, pumping was secured. Subsequent investigation identified that the oily water was discharged to an off-site
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stream. A skimmer in the stream blocked the oil from j
flowing into Lake Erie. The licensee estimated that the i
release occurred for approximately 50 minutes and that 100 to 150 gallons of oil were discharged. The apparent cause for the oil release was a main lube oil cooler leak.
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The licensee initiated condition report CR 93-081 to document the event and track corrective actions. The licensee notified local and state authorities of the oil
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release in accordance with PAP-0806, " Oil / Chemical Release
Contingency Plan." On March 8, 1993, at 10:45 a.m., the i
licensee informed the NRC Operations Center of the event via the ENS.
l 4)
Suporession Pool Strainer Desian Reauirements
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i On April 19, 1993, at approximately 3:55 p.m., the licensee determined, based on an engineering evaluation of the residual heat removal suction strainer deformation and fouling identified on January 16, 1993, that'the strainers potentially did not meet design requirements. Vendor design i
specifications required that the strainers not become more
,
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than 50 percent fouled following 100 days of post-LOCA operation. Due to Perry strainer design, a 50 percent fouled strainer corresponds to about 1 psid at design flow.
The engineering evaluation determined that the maximum i
strainer differential pressure would n:ost likely have exceeded the 1 psid design limit during the 100 days of
continuous post-LOCA operation. The engineering evaluation
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was documented in condition report (CR) 93-0022. The
licensee planned to submit a licensee event report on this i
event at a later date. The licensee informed the NRC Operations Center via the ENS at 6:30 p.m. on April 19, 1993.
Inspector review of the suppression pool strainer
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issue was in progress as documented in paragraph 2.a of this
report.
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No violations or deviations were identified.
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7.
Manacement Meetinos On April 2, 1993, a management meeting between Mr. R. Stratman, Vice i
President, Nuclear - Perry, and the NRC staff was held at the NRC Region III office in Glen Ellyn, Illinois. The purpose of the meeting was to discuss planned reorganization and organizational structure, and current
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performance of the Perry facility. At the conclusion of the meeting, NRC management acknowledged the licensee's efforts and planned
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activities.
l 8.
Exit Interviews
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The inspectors met with the licensee representatives denoted in paragraph I throughout the inspection period and on May 3, 1993. The i
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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not indicate that any of the information disclosed during the inspection was proprietary.
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