IR 05000440/1993014
| ML20024J020 | |
| Person / Time | |
|---|---|
| Site: | Perry  |
| Issue date: | 08/20/1993 |
| From: | Lanksbury R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20024J015 | List: |
| References | |
| 50-440-93-14, NUDOCS 9308310160 | |
| Download: ML20024J020 (20) | |
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U. 5. NUCLEAR REGULATORY COMMISSION
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I RF.GION Ill i
Report No. 50-440/93014(DRP)
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Docket No. 50-440 License No. NPF-53 Licensee:
Cleveland Electric Illuminating Company I
Post Office Box 5000 i
Cleveland, OH 44101 Facility Name:
Perry Nuclear Power Plant
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Inspection At:
Perry Site, Perry, Ohio
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i Inspection Conducted: June 23 through July 30, 1993
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Inspectors:
D. Kosloff A. Vegel
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E. Duncan
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T. Tella R. Westberg
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J. Guzman
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Approved By:
'dc i $ ' ' ' E ' 4 A% 0L i
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R. D. Lanksburf, Chief Date Reactor Projects Section 3B
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i Inspection Sumary
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Inspection on June 23 throuah July 30. 1993 (Report No. 50-440/93014(DRPil i
Areas Inspected:
Routine unannounced safety inspection by resident and region
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based inspectors of licensee event report followup, surveillance observations,
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maintenance observations, operational safety verification, event followup, engineered safety features system walkdown, and followup of concerns.
Results:
In the seven areas inspected, three non-cited violations (NCVs)
were identified. One was in the area of licensee event report followup i
(paragraph 2.a) and two were in the area of operational safety verification (paragraphs 5.a and 5.b).
The following is a summary of the licensee's performance during this inspection period:
l Plant Operations
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The plant operated at full power until July 9, 1993, when both reactor recirculation pumps automatically shifted to low speed, placing the plant in a region of potential instability. Operator response to the event was good.
Operators manually tripped the plant and placed the plant in cold shutdown.
The plant was restarted on July 25 and synchronized to the grid on July 27.
At the end of the inspection period, power had been increased to 47 percent.
gRO9310160 930820
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G ADOCK 05000440 PDR
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The licensee identified two operator errors during the performance of I
surveillance testing.
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Maintenance
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The quality of observed maintenance and surveillance activities was generally good; however, post maintenance cleanup remained a problem.
In addition, e
contract maintenance personnel struck an overhead wire during crane operations
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which indicated that improvements may be needed in the licensee's program for i
electrical equipment protection.
f Enaineerina
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Good engineering support and management oversight was noted during the
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licensee's investigation of the cause of an unexpected recirculation pump downshift, the licensee's evaluation of a loose parts monitor indication, and i
the licensee's evaluation of a main steam bypass valve control system i
malfunction. The formation of a restart readiness review team prior to a
reactor startup was an excellent management initiative.
Plant Support
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l The quality of observed activities was generally good. Some problems l
continued to be observed in the area of housekeeping, particularly in the i
radiologically controlled area.
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DETAILS j
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Persons Contacted i
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l Cleveland Electric Illuminatino Company f
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l R. Stratman, Vice President - Nuclear I
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D. Igyarto, General Manager, Perry Nuclear Power Plant (PNPP)
i K. Donovan, Manager, Licensing and Compliance l
- M. Bezilla, Operations Manager, PNPP l
- N. Bonner, Director, Perry Nuclear Engineering
Department (PNED)
- R. Schrauder, Director, Perry Nuclear Support Department
(PNSD)
i H. Hegrat, Compliance Engineer, PNSD l
K. Pech, Director, Perry Nuclear Assurance Department
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(PNAD)
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V. Concel, Manager, Technical Section, PNED
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- V. Sodd, Manager, Maintenance Section, PNPP l
- P. Volza, Manager, Radiation Protection Section i
D. Cobb, Superintendent, Plant Operations, PNPP
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L. Teichman, Plant Unit Supervisor, Plant Maintenance Section
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P. Roberts, Manager, Instrument & Control Section
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F. Von Ahn, Unit Lead, Mechanical Engineering Unit
- Denotes those attending the exit meeting held on July 30, 1993.
i 2.
Licensee Event Report (LER) Followup (90712. 92700)
i Through review of records, the following event reports were reviewed to
determine if reportability requirements were fulfilled, immediate
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corrective actions were accomplished in accordance with Technical
t l-Specifications (TS), and corrective actions to prevent recurrence had
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been established
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a.
(Closed) LER 50-440/92020-00 and 50-440/92020-01:
Inadequate containment airlock retests resulted in the submittal of the
subject LERs which stated.that violations of TS Limiting Condition
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for Operation (LCO) 3.6.1.1.1 and 3.6.1.3 Action a.1 had occurred.
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A licensee investigation discovered that 14 airlock system l
components had inco e t identification tags.
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On October 21, 1992, the lower. containment airlock was declared i
inoperable for maintenance to investigate seal inflation light I
indication problems for the inner door. A faulty pressure switch was identified as the root-cause and the pressure switch was i
replaced. A retest, which consisted of a soap bubble test and-l cycling of the airlock inner door three times while verifying l
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proper operation of the door, lights, and pressure switch, was performed. On October 23, at 3:15 a.m., the lower containment airlock was-declared operable.
On.0ctober 23, at 10:00 a.m., the licensee determined that the retest performed earlier was inadequate because the pressure integrity of the lower containment airlock door seal pneumatic
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l system was broken when the maintenance was performed. As a l
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result, the licensee conservatively concluded that TS surveillance requirement 4.6.1.3.e (conducting a seal leak pneumatic test every 18 months) was not met. Consequently, the airlock was again declared inoperable. On October 24, the airlock was declared operable following successful performance of surveillance SVI-P53-T7305, " Lower Containment Airlock Pneumatic System Leak Test, Pen #305."
On November 12, 1992, the licensee identified a discrepancy.
between the piping system diagram, the electrical elementary diagram, and the pressure switch as installed in the field, for the lower containment airlock.
Further investigation determined that the retest on October 24 was performed on the incorrect pneumatic system which rendered the retest invalid. As a result, the lower containment airlock inner door was again declared inoperable. On November 13, the surveillance test of the seal pneumatic system associated with the pressure switch was completed satisfactorily and the lower containment airlock was declared operable.
A review of containment and drywell airlock door seal pneumatic system pressure switch work history revealed that a work order for the same pressure switch for the same door was performed on August 22, 1987, without the appropriate retest.
In this case, the containment lower airlock inner door seal pneumatic system was not tested satisfactorily until January 19, 1988.
Work orders were generated to inspect all four containment airlock l
doors and both drywell airlock doors to ensure that components l
were appropriately labeled in accordance with the piping system diagram. The inspection resulted in the identification of the following discrepancies:
Upper containment airlock inner door pressure switches IP53-
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N702B and IP53-N703B were reversed.
Upper containment airlock inner door test valves IP53-F599.
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and IP53-F600 were reversed.
. Upper containment airlock inner door test valves IP53-F5898
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and IP53-F590B were reversed.
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l Upper containment' airlock outer door pressure switches IP53-
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l N702A and IP53-N703A were reversed.
l Lower containment airlock inner door pressure switches IPS3-
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l N700B and IP53-N701B were reversed.
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Lower containment airlock outer door pressure switches IP53-
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N700A and IP53-N701A were reversed.
Drywell containment airlock inner door pressure switches -
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IP53-N707B and IP53-N708B were reversed.
On February 17, 1993,- an extensive review of the work history for the containment upper airlock inner door indicated that two-
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previous airlock pneumatic system leak tests (one on March 1,
1991, and one on March 13, 1991)-were performed on the wrong seal-l pneumatic systems due to the mislabeled test valves.
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l The February 17, 1993, review also indicated that an airlock pneumatic system leak test on September 19, 1992, was performed on j
the wrong seal pneumatic system. On September 19, 1992, a j
containment upper airlock inner door ball valve for the large seal
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was replaced under a work order; however, due to the test valve identification tags being reversed, the leak test was performed on
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the small seal pneumatic system. On December 16, 1992, the same l
airlock door was declared inoperable and maintenance was performed
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on the door components. Both seal pneumatic systems were successfully tested on December 24, 1992. However, because the wrong seal pneumatic systems were tested between March I and
June 18, 1991, and between September 19 and December 16, 1992, the j
licensee concluded that TS LCOs 3.6.1.1.1 and 3.6.1.3 Action a.1 l
were not met.
Licensee's investication of Root Cause and Corrective Actions j
Root Cause i
The licensee determined the root cause for this event was improper f
labeling of plant equipment which caused the associated drawing to l
be in error. The airlocks_ were originally tagged and labeled by-l the vendor and "as-built" drawings were supplied which were verified by engineering personnel. However, due to the difficulty in visually verifying the tubing, piping, and components associated with the penetration pressurization seal pneumatic
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system, this verification was improperly performed since the j
drawing errors were not identified.
Corrective Actions Engineering personnel have performed equipment inspections to l
ensure that all appropriate components of the penetration-l
' pressurization seal pneumatic systems have identification tags properly installed in_ accordance with the piping system diagram.
This event was reviewed by all responsible' system engineers and al ternates. Additionally,- as part of the established requal_ification training program, all plant licensed operators were to be instructed on the lessons learned from this event.
i Inspector Review Initial inspection of this event was documented in-inspection report (IR) 50/440-92022 and updated in IR-50/440-92024 which i
followed up on LER 50-440/92020-00. During this inspection R
period, the inspectors reviewed licensee documentation,. discussed
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this event with licensee management'and-the vendor, and reviewed
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corrective action plans.
During all but the September 19 through December 24 timeframe, the
' licensee produced. records to show that a satisfactory pneumatic seal leak test had been performed at a later date. During the September 19 through December 16 timeframe, a TS 4.6.1.3.a surveillance test which verified that.both seals were seating-
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properly (by pressurizing the volume between the seals) was successfully performed every 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
Although the licensee conservatively determined that the failure i
to perform a pneumatic seal leak test following maintenance violated TS 3.6.1.3 Action a.1 and TS 3.6.1.1.1, it appeared that
this determination may have been more than conservative.
Technical Specifications did not appear to specifically require a i
i seal pneumatic leak test. However, a satisfactory soap bubble test was performed following the maintenance, which indicated that
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the system was leak tight.
Finally, in an August 3,1993, memorandum, the containment airlock vendor stated that one of the objectives behind using a dual inflatable door seal was to provide redundancy so that the failure of one seal would not cause a breach of containment.
Therefore, even if the licensee could not determine the operability of one seal due to maintenance, the redundancy feature of the second seal ensured that the airlock door could fulfill its safety function in the event of a design basis event.
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10 CFR 50, Appendix B, Criterion VI, requires that measures be established to control the issuance of documents, such as
instructions, procedures, and drawings, including changes thereto, l
which prescribe all activities affecting quality.
These measures are also to assure that documents, including changes, are reviewed for adequacy and approved for release by authorized personnel and are distributed to and used at the location where the prescribed activity is performed.
In this case, drawing D-302-762 was i
inadequate in that the drawing incorrectly labeled 14 airlock door
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components.
This violation will not be subject to enforcement action because the licensee's efforts in identifying and correcting the violation met the criteria specified in Section VII.B of the " General Statement of Policy and Procedure for NRC Enforcement Actions." LERs 50-440/92020-00 and 50-440/92020-01 are closed.
b.
(0 pen) LER 50-440/93-012-00: On June 7, 1993, the high pressure core spray (HPCS) system inadvertently initiated due to a failure l
of the division III reserve battery charger.
Licensee's Investiaation of Root Cause and Corrective Actions Root Cause l
The licensee determined the root cause for this event was the I
failure of the division III reserve battery charger to maintain a stable output voltage. Testing following the event identified erratic charger output and internal voltages. As a result, all'
charger components which were considered capable of causing
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voltage fluctuations were replaced. The reserve battery charger was retested satisfactorily and returned to service.
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Corrective Actions l
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l Licensee corrective actions to prevent recurrence included
replacement of suspect battery charger components and submittal of
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the components to the vendor for analysis.
In addition, i
inspection and maintenance procedures were to be revised to
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include inspection and cleaning of float voltage adjustment and equalizing potentiometers.
Long term corrective actions in j
progress included evaluation of the need for the installation of a
high voltage shutdown circuit, and evaluating the effects of the voltage level increase during the transient on divisional j
instrumentation and power supplies.
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Insoector Review
i The inspectors initial review of this event was documented in IR 50-440/93011, dated July 12, 1993. During this inspection i
period, the inspectors reviewed applicable licensee _ documentation
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and discussed the event with the licensee's engineering-staff to
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assess corrective action _ efforts in progress. As a-result, the
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inspectors noted that a simi_lar event occurred on July 31, 1986, i
for which LER 86-041 was issued.
In addition, based on a review of the battery charger work history, the inspectors discovered -
that several voltage oscillations on.the battery chargers had.
occurred since 1986. The inspectors were concerned that
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corrective actions for previous events may not have been adequate.
Pending review of the licensee's long term corrective actions, l
this item will remain open.
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i One non-cited violation was identified. No deviations were identified.
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l 3.
Monthly Surveillance Observations (61726)
For the surveillance activity listed below, the inspectors verified one l
L or more of the following: ' testing was' performed in accordance with j
l procedures; test instrumentation was calibrated; LCOs were met; removal
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and restoration of affected components were properly accomplished; test l
results conformed with TS, procedure requirements, and were reviewed by
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personnel other than the individual directing the test; and. deficiencies
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identified during testing were properly reviewed and resolved by appropriate management personnel.
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Surveillance Activity Title
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SVI-B21-T0189L Emergency Core Cooling System /High Pressure _ Core Spray Drywell Pressure i
High Channel Functional-
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SVI-C21-T0039 Main Steam Isolation Valve Closure Channel Functional-SVI-E21-T1196 Low Pressure Core Spray Pump Discharge Low Flow (Bypass) Channel functional for IE21-N651
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SVI-E12-T2003 Residual Heat Removal (RHR)
"C" Pump and Valve Operability Test SVI-E12-T2002 RHR "B" Pump and Valve Operability Test PTI-R43-P0002 Division II Diesel Generator Monthly Auxiliary System Monitoring PTI-R43-P0001 Division I Diesel Generator Monthly Auxiliary System Monitoring One non-cited violation was identified (paragraph 5.a).
No deviations were identified.
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Monthly Maintenance Observation (62703)
Station maintenance activities of safety-related systems and components listed below were observed and/or reviewed to ensure that activities were conducted in accordance with approved procedures, regulatory guides, industry codes and standards, and were in conformance with TS.
The following items were considered during this review:
the LCOs were met while components or systems were removed from service, approvals were obtained prior to initiating 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, l
activities were accomplished by qualified personnel, parts and materials i
used were properly certified, radiological controls were implemented, and fire prevention controls were implemented.
Work requests were reviewed to determine the status of outstanding jobs and to assure that priority was assigned to safety-related equipment
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maintenance which may affect system performance.
Specific Maintenance Activities Observed Repair Control Rod Drive (CRD) Pump Oil Leaks at Motor / Reducer
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Bearing (
Repair CRD Seal Water Leak at Check Valve
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Scram Discharge Volume Vent and Drain Valve Troubleshooting and
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Reactor Recirculation Loop Resistance Temperature Detector Replacement Planting of Trees Near the Training Center. During this activity
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a contractor moved a hose protection ramp using a small mobile crane. While moving the ramp the crane boom struck and severed a 480 volt overhead power line that supplied power to a guardhouse near the training center. No one was injured and there was no impact on plant operations.
The inspectors reviewed this event l
and determined that although the licensee's program to protect important electrical equipment was adequate, there were aspects of l
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the program that could be improved. Concurrent with the inspectors' review the licensee was evaluating its program for improvements. The inspectors will review the licensee's program in a future inspection.
No violations or deviations were 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 LCOs 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, fluid leaks, and excessive vibrations, and to verify that maintenance requests had been initiated for 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.
The inspectors observed plant housekeeping, general plant cleanliness conditions, and verified implementation of radiation protection controls, a.
Low Pressure Core Spray (LPCS) Valve Mispositionina On June 26, 1993, with the plant in Operational Condition 1, operators performed surveillance instruction SVI-E21-T1196, "LPCS Pump Discharge Low Flow (Bypass) Channel Functional For IE21-N651." During the surveillance, the procedure directed the Instrumentation and Control (I&C) technicians to request the Supervising Operator (50) to place IE21-F0ll, the LPCS pump minimum flow valve, to the desired position with regard to current plant conditions. The S0 instructed the I&C technician to leave the valve in whatever position it was in. The 50 was not aware of what that position was (closed).
Following completion of the surveillance test portion of the procedure, operators restored the LPCS system to standby readiness and incorrectly declared the system operable since the minimum flow valve was closed instead of open as required.
During an oncoming operator control room panel walkdown, it was discovered that 1E21-F011 was closed. The valve was immediately opened, restoring the system to a proper standby readiness lineup.
The shift supervisor verified from electrical schematics that the minimum flow valve was designed to automatically open when the system was initiated, and determined that the mispositioning was not safety significant.
A discussion with the S0 determined that he incorrectly believed the surveillance procedure would direct operators to reposition the LPCS minimum flow valve to open when the system was placed in standby readiness.
In addition, the 50 stated that he was
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distracted by other events during the shift, and could not give-
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his full attention to the surveillance test.
The licensee initiated condition report CR-93-125 to document the
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event investigation and track corrective actions. As a result of
the event, the 50 in charge of the surveillance test was l
decertified and placed on a remedial training program.
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10 CFR 50, Appendix B, Criteria V, requires that activities.
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affecting quality be prescribed by documented procedures and be
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accomplished in accordance with those procedures. The LPCS
minimum flow valve was not placed in the correct position with regard to current plant conditions as required by SVI-E21-T1196.
l This violation will not be subject to. enforcement action because
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the licensee's efforts in identifying and correcting the violation
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met the criteria specified in Section VII.B of the " General
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Statement of Policy and Procedure for NRC Enforcement Actions."
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Incorrect Control Rod Inserted Durina Surveillance Test On July 3,1993, with the plant at 100 percent-power, control room operators were performing SVI-Cll-T1022, " Rod Pattern Control System - Rod Withdrawal Limiter." The SVI involved inserting a
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control rod and then attempting to withdraw the rod past the limiting. position. The SVI contained two subsections for
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performing the test. The appropriate subsection was to be
selected based on reactor power.
Each subsection had a list of J
rods for the operator to select from. The sign off sheets for the-j test were included in an attachment to the SVI.
The operator i
began the test in the correct-subsection.(5.1.2), but after
initialing the first step he completed the second and third step
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following the incorrect subsection-(5.1.1). The independent
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verifier verified that the rod that the operator moved was the rod that he had selected, but did not verify that the operator was following the correct step in the procedure. When the operator turned to the sign off attachment to initial the third step he
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identified his error, notified the shift supervisor, and restored the rod to a proper red configuration. The licensee notified the senior resident inspector who reported to the site to review the error and evaluate the licensee's immediate corrective actions.
The licensee initiated a human factors evaluation and directed a procedure change to eliminate the sign off attachment and relocate the initialing blanks to the body of the procedure. The licensee had already begun a long term program to reduce personnel errors and a long term program to eliminate sign off attachments from SVIs by relocating initialing blanks to the bodies of procedures.
The inspector verified that, due to the rod selected for inclusion in the SVI and the limited rod movement directed by the SVI,:the mispositioning event was not safety significant.
i 10 CFR 50, Appendix B, Criteria V, requires that-activities
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affecting quality be prescribed by documented procedures and be accomplished in accordance with those procedures. A control. rod was moved in a manner not prescribed by SVI-Cll-T1022. This 10'
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violation will not be subject to enforcement action because the
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licensee's efforts in identifying and correcting the violation met the criteria specified in Section VII.B of the " General Statement of Policy and Procedure for NRC Enforcement Actions."
c.
Unexpected Reactor Recirculation Pumo Downshift Event On July 9, 1993, while operating at 100 percent power, an unexpected recirculation pump downshift from fast to slow speed occurred. The resultant decrease in flow and power placed the plant in the potential instability region of the power to flow map. As a result, the operators manually tripped the reactor as i
required by plant off normal instruction ONI-C51, " Unexplained Power Changes." For the most part, plant equipment response to the trip was as expected.
Problems were encountered with slowly
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opening scram discharge volume (SDV) vent and drain valves, the
"A" hydrogen analyzer which incorrectly indicated a high hydrogen concentration in the drywell, and operation of the controls for
i the turbine control valves. The licensee initiated an investigation into the recirculation pump downshift and the i
equipment problems.
To determine the cause for the recirculation pump downshift, the licensee established an incident response team (IRT).
The purpose i
of the team was to review the event, evaluate possible causes of the event, and determine corrective actions to prevent recurrence of the event. On July 14, the IRT presented the results of their
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investigation to the licensee's on-site review committee. The j
l team concluded there were four possible causes for the pump downshift; however, no definitive cause was identified.
Following
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on-site review committee and management review, further investigation was directed to more firmly determine the cause.
The incident response team re-evaluated their efforts and conducted further troubleshooting. As a result, the team concluded that the probable cause for the event was the failure of both recirculation pump suction resistance temperature detectors (RTDs). The failure of the RTDs resulted in the trip logic for
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pump downshifting to slow speed being satisfied on steam dome / pump suction differential temperature being less than 8 fahrenheit degrees (2 out of 2 logic).
Initial IRT investigation did not consider this cause as viable as only one RTD, IB33N028B, was found to have failed. However, subsequent troubleshooting of the other RTD, IB33N028A, concluded that an intermittent fault r mld be developed with minor movement and/or_ vibration of the R'2 when tested under simulated plant conditions.
Licensee corrective actions included replacement of the RTDs, development of an action plan with the vendor for future efforts in determining the root cause for RTD failures, and the addition of an alarm in the control room to actuate on a single differential temperature signal.
In addition to the failed RTDs, the IRT also addressed other possible causes for the downshift event. The team recommended the installation of on-line time event monitors to enhance the ability to isolate the cause of a future spurious downshift' event, should it occur.
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I The inspectors monitored the licensee's investigation and
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troubleshooting efforts by reviewing documents, observing l
meetings, and conducting discussions with the engineering staff.
Based on the inspectors' observations, it appeared that the licensee's investigation for the cause of the recirculation pump l
downshift event effectively evaluated potential causes and
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corrective actions taken were thorough.
A particular strength noted was the independent assessment of the adequacy of the IRT's efforts by the on-site review committee and management. Overall, the inspectors assessed the engineering evaluation of the pump t
l downstift event as thorough with good management oversight.
l During the event, following startup of the hydrogen analyzer in accordance with plant procedures, hydrogen analyzer "A" indicated between 1.5 and 2.0 percent hydrogen concentration, while the
"B' analyzer indicated zero percent hydrogen concentration.
Following verification of zero percent hydrogen concentration in l
the containment and drywell, the
"A" hydrogen analyzer was declared inoperable.
Subsequent investigation determined that the erroneous reading on the "A" hydrogen analyzer was due to instrument drift. The analyzer was subsequently re-calibrated and returnod to service.
l During the event, after resetting the reactor scram logic, the operators noted that the first vent and drain valves did not re-open as required until about 14 minutes after the trip was reset.
Subsequent troubleshooting determined that the slow opening times l
were due to excess leakage past an air supply / exhaust valve common l
to both valves. The air supply / exhaust valve was replaced and l
returned to the vendor for failure analysis. The inspectors l
review of licensee investigation efforts and repairs concerning the SDV vent and drain valves were in progress at the end of this
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inspection period and will be documented in a future inspection report.
The licensee received assistance from General Electric (GE) and the vendor, Combustion Engineering (CE), for its evaluation of the valid indication detected by the loose parts monitor during plant cooldown on July 10, 1993. A valid indication is a noise detected l
by the loose parts monitor that is strong enough and has the
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appropriate frequency characteristics to be considered to have i
been caused by a loose part.
The noise was detected by.the i
reactor pressure vessel-(RPV) lower head detectors.
General
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Electric and CE both stated that the noise did not have the characteristics that they would expect from a loose part. Only a single impact was detected and a loose part usually has multiple impacts as it moves. Another single impact valid indication was
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i detected on July 12, 1993, after the plant was cooled down.
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During the outage, the licensee shifted the recirculation pumps to fast speed to determine if increased flow would cause additional valid indications since increased flow might cause a quiescent loose part to move and be detected.
Flow changes did not induce a valid indication. The licensee also inspected the area under the l
RPV because the loose parts monitor can detect noises from outside j
the vessel. Although some evidence of rubbing between the shoot-
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I out steel and the RPV pedestal was observed, there was no
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indication of metal-to-metal contact. The licensee concluded that the valid indications were probably not caused by loose parts in
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the RPV, but may have been caused by some type of thermally l
induced metal-to-metal rubbing or by metal-to-metal contact associated with control rod drive components.
Based on the observations made and the possible sources of the valid indications, the licensee concluded that the possibility of adverse safety consequences resulting from whatever caused the valid indications was extremely remote. The licensee decided to start up the plant with additional recording and analytical equipment and onsite expert assistance provided by GE. During the
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plant heatup, two additional valid indications were recorded.
They were similar to the earlier indications and were not related l
to changes in flow within the RPV.
In addition to the evaluations l
conducted during the outage and startup, the licensee had several long-term evaluation activities in progress. The inspectors will I
review the results of those activities in a future inspection.
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l The abnormal operation of the turbine control valves was corrected
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by calibrating portions of the electronic valve controls to
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correct control signal drift.
d.
Plant Startuo Observations
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Preparations for the startup were thorough.
In addition to j
i performing substantive evaluations of problems identified during l
l the trip and cooldown, the licensee formed a restart readiness review team to identify additional problems which could have
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affected the startup or subsequent plant operation.
Items reviewed by the team were evaluated to identify activities to be done prior to startup and to prioritize items to be done after startup. Hold points were established during the startup to evaluate information related to the loose parts monitoring system indications and for verification of the performance of the j
recirculation pumps and turbine control valves. A management oversight team was formed to provide 24-hour coverage and, since the entire startup was considered an " infrequently performed test i
or evolution" (IPTE), an IPTE oversight team was formed to provide 24-hour coverage.
On July 25, 1993, reactor startup from the recirculation pump downshift forced outage was commenced. On July 27, the main generator'was synchronized to the grid.
Later that day, during the power ascension, the operators noted that the #1 main steam bypass valve indicated slightly open. To correct this unexpected condition, the operators raised the load setting.
Troubleshooting revealed that an isolation amplifier in the valve control circuit required a gain adjustment, even though the gain was within the tolerances allowed by the vendor.
Following a thorough
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evaluation, the licensee adjusted the gain of the isolation amplifier on July 28. On July 29, as power was being increased again, operators observed that the servo-current for the #1 main steam t,ypass valve was becoming less negative than normal, and the licensee halted the power ascension.
Had the servo-current l
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increased until it was positive, the bypass valve would have i
l opened. The licensee formed a team to perform a root cause analysis and develop short term and long term corrective actions.
At the end of the inspection period, power was being held at 46 percent while the team continued its analysis.
The inspectors observed control room activities during the startup i
to assess control room decorum and operator control of startup l
evolutions. The inspectors concluded that the operators performed the startup slowly and deliberately, demonstrating positive i
control of the evolution. Control room decorum was professional with prompt and correct response to abnormal conditions. Overall i
performance of the startup was evaluated as excellent.
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Two non-cited violations were identified.
No deviations were identified.
6.
Onsite Followuo of Events at Operatina Power Reactors (93702)
a.
General 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,
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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:
the sequence of actions, the functioning of safety systems required by i
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 l
of the events and licensee corrective actions noted during the inspector's followup are provided below.
b.
Details
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(1)
Loss of Control Room Ventilation Envelope Due to Stuck Open Door
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On July 2,1993, at about 10:12 a.m., while in Operational i
Condition 1, site security was notified that control complex door CC-517 failed to close and was stuck open. As a result, the control room envelope was breached and entry into TS 3.0.3 was made.
That TS required that within I hour action be initiated to place the unit in an operational condition in which the TS did not apply and at least startup j
within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. At 10:32 a.m., the door was closed and locked, re-establishing control room integrity.
Subsequently, the TS 3.0.3 action statement was exited at 11:34 a.m.
The cause for the door being stuck open was a jammed linkage on the door. At 1:14 a.m., the licensee
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notified the NRC Operations Center of the event via the Emergency Notification System (ENS). The inspectors verified that the door was closed.
The licensee initiated condition report CR-93-127 to document investigation of this event.
In addition, the licensee performed a calculation to verify allowable control room envelope leakage.
The study allowed a more precise calculation of the expected dispersion of radionuclides in the control room and showed that a higher air inleakage rate (1375 cfm vice 90 cfm) could be allowed into the control room without exceeding radiation dose limits for the control room staff during a design basis accident..The change in allowable leakage allowed for temporary degradations of the control room envelope to exist without affecting the operability of the control room envelope and therefore the
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control room ventilation system.
Based on the above calculations, on July 31, 1993, the licensee retracted the July 2 and July 16 (paragraph 6.b.(4)) notifications concerning the loss of control room integrity.
At the end of the inspection period, NRC staff review of the licensee's retraction of.the ENS notification was in progress. The results of the staff's evaluation will be documented in a future inspection report.
(2)
Rod Control and Information System (RCIS) Lockup and Accumulator Out of Specification Alarms On July 3,1993, at 3:30 p.m., a power supply monitor in the RCIS detected a low power supply voltage which caused a loss of control rod position indication, scram accumulator fault indication, and the ability to move control rods using the normal insert and withdrawal method. All control rods remained trippable. Without scram accumulator indication the licensee entered TS LCO 3.1.3.3.
Action statement a.2.a required operators to insert at least one control rod at least one notch to verify a control rod drive pump was operating. Although a control rod drive pump was operating, this action could not be performed due to the inability to insert or withdraw control rods. Therefore the Unit Supervisor entered TS 3.0.3.
The licensee notified the NRC via the ENS and notified the senior resident inspector. The inspector came to the site to observe licensee activities.
Work was authorized on the system and instrument and control-technicians adjusted the circuitry to clear the alarm.
The system was restored to operable status and the applicable TSs were exited at 5:31 p.m.
Later that night, an RCIS power supply failed, causing. a loss of control rod position indication and the ability to move control rods using the normal insert and withdrawal method.
Scram accumulator fault indication was not lost.
The power supply was successfully replaced. The inspectors-15
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will complete their review of this event after the LER is issued.
(3)
Manual Reactor Trio
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l On July 9, 1993, at 5:37 a.m., with the reactor at 100 percent power, both recirculation pumps unexpectedly downshifted from fast to slow speed.
The resultant flow decrease lowered reactor power to 52 percent and placed the reactor in the potential instability region of the power to flow map. As a result, operators manually tripped the reactor at 5:44 a.m.
While in the potential instability region, no power perturbations or oscillations occurred.
l Following the reactor trip, the motor-driven feedwater pump
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(MFP) was placed in service to establish a feedwater lineup while both turbine-driven reactor feed pump (RFPTs) were
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being secured. The feedwater pump transfer and water l
inventory expansion due to heatup, caused the reactor water level 8 (219 inches) setpoint to be exceeded. As a result, the MFP and the "A" RFPT tripped. Upon restoring reactor water level below the level 8 setpoint, the MFP was restarted and reactor water level was stabilized.
Plant equipment response to the transient and licensee investigation of the cause for the recirculation pump
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downshift is discussed in section 5.c of this report.
The licensee informed the NRC Operations Center of this event via the ENS at 6:00 a.m. and again at 8:12 a.m. to
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provide additional details. The resident inspectors responded to the site to observe the licensee's recovery j
from the event.
The licensee initiated condition report CR-93-133 to j
document their investigation into' this event and corrective
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actions taken.
In addition, LER 93-015 was to be submitted in accordance with 10 CFR 50.73.
The inspectors will review
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that report in a future inspection period.
(4)
Loss of Control Room Envelope Due to leakina Door Seal On July 16, 1993, at about 10:15 a.m., while in Operation Condition 4, the rubber seal around control complex door CC-517 was found torn, resulting in a breach of control room integrity. The torn rubber seal was identified by the system engineer conducting a walkdown inspection of the control room doors.
Since the plant was in cold shutdown, the TS action requirements could be met and an entry into TS 3.0.3 was not warranted.
At 12:48 p.m., the licensee notified the NRC Operations Center of the event via the ENS.
The licensee initiated condition report CR 93-144 to document the investigation of this event. As discussed in paragraph 6.b.(1) of this report, the licensee retracted the ENS notification on July 31, 1993.
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(5)
Hiah Pressure Core Soray Water Lea Pumo Surveillance Failure On July 22, 1993, at about 11:40 p.m., while in Operational Condition 4, the HPCS keep fill pump failed to achieve an acceptable flow rate during surveillance testing. As a result, the HPCS system was declared inoperable although it remained functional. The licensee reported this via the ENS
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because HPCS is a single train system. The HPCS keep fill
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pump flow rate measured during the test was 20.2 gpm.
An acceptable flow rate in accordance with surveillance instruction SVI-E22-T2002 was 28.9 to 33.0 gpm. When j
measured again with a newly calibrated flow meter, flow' was 28.1 gpm. The licensee then performed an engineering analysis and concluded that the pump was capable, of performing its safety function and would not have to be replaced before the next refueling outage provided it was monitored more frequently to assure that rapid degradation did not occur. The HPCS system was declared operable and the ENS notification was retracted. The inspectors verified that additional monitoring was being performed and that the pump was continuing to perform its safety function. The'
licensee was procuring parts so that the pump could be replaced in August 1993.
The licensee initiated condition report CR 93-155 to document the results of their investigation into the cause of this event and corrective actions taken.
No violations or deviations were identified, i
7.
Enaineered Safety Features System Walkdown (71710)'
In addition to routine observations made during regular plant tours, the inspectors conducted walkdowns of the accessible portions of selected safety-related systems. During this inspection period,.the inspectors
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conducted a walkdown of the residual heat removal (RHR) "A" system.
The j
inspectors verified system operability through reviews of valve lineups, i
system prints, equipment conditions, and control room indications.
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As a result of the walkdowns, the inspector noted that the general (
condition of the RHR "A" system was adequate. The system was aligned in L
accordance with the appropriate valve lineup sheet,. hangers 'and supports L
were made up and aligned. correctly, and major system components were properly labeled. However, in the RHR "A" pump and valve rooms, several-general housekeeping deficiencies were identified. These included:
pipe supports being used as staging locations for materials'such
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I as tools, tie wraps,- valve locking tabs, etc.
post maintenance debris such as tools, wire, duct tape, nuts, I
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screws, bolts, and tie wraps in various locations The inspector identified a packing leak on the RHR "A" heat exchanger outlet valve which was accumulating on the floor below the grating. 'In addition, the inspector identified three junction boxes in the RHR "A"
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pump room with covers either removed or ajar.
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The inspectors informed the licensee of the above noted discrepancies.
The licensee stated that the deficiencies would be corrected and that
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efforts were in progress to improve the housekeeping condition of the plant. The inspectors will continue to assess the adequacy of.the
housekeeping improvement effort in progress in future routine resident
inspection reports.
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8.
On-site Review Committee During the report period, the inspectors observed On-site Review Committee meetings to evaluate the organization's effectiveness.
For the meetings attended, the inspectors considered the following
attributes: degree of plant management involvement and/or domination of i
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discussions; if constructive discussion occurred; if the majority of the l
committee consistently voted the same as the chairman; if the committee
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was biased toward operation or safety; and, if the committee used the i
design basis, updated safety analysis report, or vendor technical
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manuals for their determinations in addition to the TS.
t In preparation for the attended meetings, the inspectors reviewed draft submittals of items that were submitted for the On-site Review l
Committee's approval.
Items presented to the On-site Review Committee included safety evaluations, temporary changes to procedures, setpoint
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change requests, procedural revisions, and design change packages.
i During this report period, the following On-site Review Committee meetings were observed by the inspectors:
Meetina No.
Date
93-089 7/15/93 93-092 7/23/93
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9.
Manaaement Meetinas On July 1,1993, Mr. W. L. Axelson, Deputy Director, Division of Radiation Safety and Safeguards, and on July 7,1993, Mr. Edward G. Greenman, Director, Division of Reactor Projects, visited the Perry pl ant. During the visits, the NRC managers toured the facility-observing plant conditions-and on-going plant operations.
In addition, the managers met with members of the licensee staff to discuss recent plant. performance.
10.
Followup of Concerns (62703)
Three concerns related _to the service water (SW) fiberglass pipe rupture of March 1993 have been reviewed.
The first concern was whether the SW. fiberglass piping had any post installation test requirements,~such as hydrostatic testing, to ensure-pressure integrity.
Design requirements, such as hydrostatic testing of piping, were based on applicable industry codes and standards. The Perry SW system used j
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l fiberglass for underground yard piping which was designed in accordance with ASCE MEP-37 (Design and Construction of Sanitary and Storm Sewers)
and with Section X of the ASME Boiler and Pressure Vessel Code
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(Fiberglass-Reinforced Plastic Pressure Vessels).
Although the quality requirements of the SW fiberglass piping were not as demanding as for ASME Section III piping, the piping system was designed to the industry standards prevailing at the time. A review of i
the procurement specification for the fiberglass piping (Spec. SP-349-02-4549-00, Par. 2:07.5) revealed that the piping was designed for hydrostatic testing at 1.5 times the pipe's design pressure of 100 psig l
(however, hydrostatic leak test records have not been found).
Leakage due to overpressure would not be a concern since normal operating
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pressure of the fiberglass pipe was in the 40 psig range with a maximum pressure of about 60 psig.
A second concern stemming from the SW fiberglass pipe break event was
l whether the plant emergency instructions (PEls) addressed plant flooding
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resulting from failure of non-seismic systems concurrent with a loss of offsite power (LOOP) or a loss of coolant accident (LOCA).
Perry's PEls did not address the direct impact of flooding on the plant, but did provide guidance to the operators on responding to symptoms that indicated that the plant was being affected.
For example, entry conditions for PEIs included reactor water level and pressure, and l
containment parameters out of the normal range. Therefore, if a flooding event did occur and did negatively impact reactor or containment parameters, the PEls would guide the operators to place the reactor plant in a safe condition concurrent with other events such as a l
In the case of a LOOP or LOCA occurring in conjunction with a seismic event, the LOOP would result in the loss of non-essential electrical loads, including the service water pumps. Without the driving head of the pumps, flooding from a break in the SW line would be minimized.
The design bases of all engineered safety features (ESFs) designed to mitigate accidents assumed no operator action was taken for the first i
10 minutes of the event.
Following a LOOP or LOCA, all protective
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actions required under accident conditions were automatic, and redundant such that reactor operator intervention was unnecessary for the first 10 minutes to allowed for operator assessment and decision. This time period also allowed operators to respond to other urgent events that may occur concurrent with a LOOP or LOCA.
Additionally, as discussed in the next section, the plant had several design features to minimize and control ingress of water into safety-related structures.
A third concern raised was whether a break in the non-seismic, nonsafety-related SW fiberglass piping could affect plant safety i
systems.
The Perry Service Water (SW) system is a cooling water system that is not required for the purpose of emergency core cooling, post accident l
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containment heat removal, post accident containment atmospheric cleanup, residual heat removal from the reactor, or cooling the spent fuel
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i storage pool. Therefore, per Regulatory Guide 1.26 (Quality Group Classification), it was correctly designated as a nonsafety-related j
system and the use of fiberglass material was appropriate.
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Similarly, using the guidance of Regulatory Guide 1.29 (Seismic Design Classification), the SW system is correctly designated as non-seismic.
Portions of the SW system that run through safety-related structures
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such as the Control Complex and the Auxiliary Building were designated as seismic category I (but not safety-related) due to their potential to
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impact safety-related components should they fail during a seismic event.
The Perry USAR analyzed and evaluated the effects on safety-related j
equipment due to failure of nonsafety-related piping systems including i
subsequent flooding conditions. The USAR stated that piping failures in yard piping had been found to result in conditions that did not i
jeopardize. safe plant shutdown or adversely affect operation of safe j
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shutdown systems.
The design criteria for ensuring the prevention of damage to safety-
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l related equipment by internal flooding due to the failure of non-seismic
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l category I piping were:
a)
Plant layout using separation of seismic category I and non-i seismic components by locating them, where possible, in separate j
buildings.
b)
Emergency core cooling system equipment located in separate, water tight compartments.
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c)
Small leaks will be handled by the floor drain system.
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The fact that water from yard piping was able to enter safety-related structures during the SW piping break was not a basis for requiring that the SW fiberglass piping be safety-related or seismic category I.
During the SW pipe break, flood water levels in safety-related structures did not go above the maximum levels discussed in the USAR.
It is clear, however, that the primary point of water ingress, the j
electrical manholes, must be properly sealed in order to minimize the volume that is to be handled by the floor drain system.
The licensee was currently evaluating methods of preventing flood waters from entering the manholes.
10.
Items For Which A " Notice of Violaticn" Will Not Be Issued During this inspection, certain licensee activities, as described in
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paragraphs 2.b, 5.a, and 5.b, appeared to be in violation of NRC
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requirements. However, the licensee identified these violations and they are not being cited because the criteria specified in Section VII.B of
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l the " General Statement of-Policy and Procedure for NRC Enforcement j
Actions," (Enforcement Policy, 10 CFR Part 2, Appendix C) were l
satisfied.
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11.
Exit Interviews l
The inspectors met with the licensee representatives denoted in
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paragraph I throughout the inspection period and on July 30, 1993. The inspectors summarized the scope and results of the inspection and
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discussed the likely content of the inspection report. The licensee did not indicate that any of the information disclosed during the inspection could be considered proprietary in nature.
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