IR 05000324/1993041
| ML20059K593 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 11/04/1993 |
| From: | Christensen H, Prevatte R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20059K524 | List: |
| References | |
| 50-324-93-41, 50-325-93-41, NUDOCS 9311160108 | |
| Download: ML20059K593 (37) | |
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UNITED STATES
_jP NUCLEAR REGULATORY COMMISSION i
'k REGION ll
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101 MARIETTA STREET, N.W., SUITE 2900
. 7.
j ATLANTA, GEORGIA 303234199
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Report Nos.:
50-325/93-41 and 50-324/93-41 Licensee:
Carolina Power and Light Company
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P. O. Box 1551 Raleigh, NC 27602
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Docket Nos.:
50-325 and 50-324 License Nos.: DPR-71 and DPR-62'
Facility Name:
Brunswick I and 2
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Inspection Conducted:
September 4 - Octo er 8, 1993
Lead Inspector:
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R. L. Prevatte, Senior
'sidptInspector Date ' Signed Other Inspectors:
P. M. Byron, Resident Inspector i
M. T. Janus, Resident Inspector
G. A. Harris, Project Engineer Approved By:
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f H. O. Christensen,6 thief Ddte Signed Reactor Projects Section IA
Division of Reactor Projects SUMMARY Scope:
This routine safety inspection by the resident inspectors involved the areas of maintenance observation, surveillance observation,- operational safety'
verification, Three-Year Plan review, Unit 1 outage and restart activities, action on previous inspection findings, and review of licensee event reports.
Results:
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In the areas inspected, two violations were. identified. One violation involved inadequate storage and handling of safety-related material (paragraph
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2). The second violation involved two examples of failure to establish and i
implement procedures (paragraph 4).
l Two weaknesses were also identified. The first weakness involved minor
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flooding which resulted from poor communications and inappropriate operator.
j actions (paragraph 4). The second weakness involved poor design review of.
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problems associated with the control building emergency air filtration filter system.(paragraph 8). A strength involving the calibration of the.feedwater
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flow transmitters was also noted (paragraph 3).
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9311160108 931104
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PDR ADDCK 05000324 G
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Unit I remained in the forced outage that-began on' April 21, 1992. Unit 2 operated at essentially full power with the exception of six days at-.
approximately 54% power due to; emergent maintenance activities on six control rod drive units.
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REPORT DETAILS f
1.
Persons Contacted l
Licensee Employees
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K. Ahern, Manager - Operations Support and Work Control R. Anderson - Vice-President, Brunswick Nuclear Project
- G. Barnes, Manager - Operations, Unit 1
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E. Blackmon, Manager - Radwaste/ Fire Protection
- M. Bradley, Manager - Brunswick Project Assessment
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M. Brown - Plant Manager, Unit 1 (Acting)
- R. Godley, Supervisor - Regulatory Compliance
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R. Grazio, Manager - Brunswick Engineering Support Section J. Heffley, Manager - Maintenance, Unit 2
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G. Hicks, Manager - Training
- C. Hinnant - Director of Site Operations
- P. Leslie, Manager - Security
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- W. Levis, Manager - Regulatory Affairs (Acting)
- R. Lopriore, Manager - Maintenance, Unit 1 G. Miller, Manager - Technical Support
- C. Robertson, Manager - Environmental & Radiological Control
- J. Titrington, Manager - Operations, Unit 2
C. Warren, Plant Manager - Unit 2
G. Warriner, Manager - Control and Administration i
- E. Willett, Manager - Project Management Other licensee employees cona.cted included construction craftsmen,
engineers, technicians, operators, office personnel and security force members.
NRC Personnel
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- H. Christensen, Chief, Reactor Projects Section IA, RII
- Attended the exit interview.
Acronyms and initialisms used in the report are listed in the last paragraph.
2.
Maintenance Observation (62703)
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The inspectors observed maintenance activities, interviewed personnel,
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and reviewed records to verify that work was conducted in accordance with approved procedures, Technical Specifications, and applicable
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industry codes and standards. The inspectors also verified that:
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redundant components were operable; administrative controls were followed; tagouts were adequate; personnel were qualified; correct
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replacements parts were used; radiological controls were proper; fire
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protection was adequate; quality control hold points were adequate and l
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observed; adequate post-maintenance testing was performed; and
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independent verification requirements were implemented. The inspectors.
independently verified that equipment was properly returned to service t
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after maintenance.
Outstanding work requests were reviewed to ensure that the licensee gave priority to safety-related maintenance. The inspectors observed / reviewed portions of the following maintenance activities:
Transformer Yard Coatina Proiect
On March 16, 1993, the licensee declared an Unusual Event when both units experienced a loss of off-site power.
Subsequent investigation revealed that salt buildup on the switchyard and transformer yard components during a storm caused this event. The salt residue provided a grounding path which affected the PCBs and transformers.
To prevent a recurrence of the problem the licensee contracted a vendor to apply a silicon based coating to the 230 KV switchyard
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porcelain components (e.g., insulators, coupling capacitors,
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etc.). The selected contractor had performed this project for switch and transformer yards at other nuclear stations. The process uses an atomized spray to apply a 20 mil silicon coating to the component surfaces. A micrometer is then used to verify the coating thickness. The coating thickness was independently
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verified by a licensee transmission engineer.
The coating task required that a large motorized mobile platform be used to elevate personnel to the working height of the insulators and coupling capacitors. The contractor reviewed procedure 0-AI-118, Switchyard and Transformer Yard Vehicle
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Access, Rev. O, as part of a required pre-job brief.
In addition,
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the inspector observed this work in progress and verified that l
appropriate steps had been taken to ensure personnel safety during e
these evolutions.
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i The 230 KV transmission lines were removed from service one at a
time to support the coating project. The coating of the Unit I switchyard components was completed on September 9.
Unit 2 switchyard components are scheduled to be coated during the next refueling outage. The inspector observed selected portions of the
coating activities and reviewed thickness data. This process was
conducted in accordance with the required procedure.
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_ Service Water Solenoid Valve Replacement Unit 2 experienced high HPCI room temperatures due to the summer heat load on the reactor building closed cycle cooling system. These temperatures were identified during the completion of the auxiliary
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building operators daily check sheet. The increase in the heat load l
caused HPCI room temperatures to increase above the administrative limit j
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of 104*F. Qualified life assessments of the environmentally qualified I
equipment in the reactor building are based upon on an average
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temperature of 104*F. Operating Instruction 03.4, RHR/HPCI Room l
Temperatures, was recently revised from 133*F to the above value because
of this concern. The instruction requires operators to start room
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t coolers when temperatures increase above this value. On September 3, HPCI room temperatures reached 105*F; however, a cooler could not be started due to the malfunction of service water cooling supply valve
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2-SW-V141-SV3.
r An emergent work ticket (WR/JO 93AYXQl) was written to repair the valve.
Due to inaccuracies in the licensee's Equipment Database System (EDBS),
a solenoid valve with a DC coil (instead of an AC coil) was installed.
j This error was detected during post maintenance testing activities. A
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suitable replacement valve was obtained from the Harris plant and
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installed.
Post maintenance testing was conducted satisfactorily and
the valve was returned to service. This effort caused a 24-hour delay I
in restoring HPCI room cooling. After restoring the HPCI room cooler, temperatures decreased to an acceptable level.
Although HPCI room temperature was in excess of the administrative limit for a period of five days, an evaluation by the licensee determined that-
this had minimal effect on equipment life. Room cooling was; started and temperature decreased, but remained elevated for three days until cooler ambient conditions assisted the effort. This problem was documented by
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the licensee in minor adverse condition report MM-93-178. The licensee
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has counseled personnel to verify EDBS information prior to implementation to prevent recurrence. The licensee has also initiated EDBS improvements as part of the Three-Year Plan.
LPRM Cable Installation Followuo During a previous inspection it was determined that LPRM cables had been installed in the Unit 1 drywell and not protected from
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moisture intrusion. The cables were installed under WR/JO AMCMI
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and several supporting work tickets. As stated in Inspection i
Report 325,324/93-33, the licensee's failure to implement measures to preclude moisture intrusion after the cables were installed
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resulted in extensive troubleshooting efforts which caused a three week delay in completion of the project.
Because of the moisture intrusion concern, the inspector performed an inspection of the i
storage of the LPRM cables and other safety-related equipment in the warehouse.
t Procurement and Material Control Procedure 0-PMC-03, Storage, Rev.16, and BSEP Specification 113-030 require that instrument cables be stored
under Class C conditions. The cables in the warehouse were stored under
class B conditions which require that measures be taken for protection from the effects of temperature extremes, humidity and vapors. As
documented in Inspection Report 325,324/93-33 moisture intrusion into the LPRM cables can cause lower than desired insulation resistance readings and cable degradation. The LPRM cables were purchased under
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P.O. 6Q3566C using BSEP No. 113-030, Specification for Procurement of-Silicon Dioxide Insulated Cable and Connectors, Rev 0.
Step 2.10.3 of
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this document requires the vendor to supply and the licensee to
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implement receiving, handling and storage instructions that affect
warranties / guarantees, and to preserve the integrity of the cable while
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in storage.
The inspectors reviewed the contents of several boxes containing
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LPRM cables. The vendor procedure, Field Installation Procedure for LPRM System and QLN connectors, Doc. No. FIP-9233, Section.4.0 requires that the cable end openings, connectors and fitting be
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capped with metal or halogen free plastic caps and that desiccant
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HUMI-SORB per MIL-D-3464-D or equivalent be attached to each connector on cable ends and the cable assemblies be sealed in heat sealable polyethylene packaging.
i Contrary to the above, the inspectors found that several cables were stored in polyethylene packages which had been opened and
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were not properly resealed.
In addition, several of the packages containing cables appeared not to be adequately heat sealed prior
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to shipment from the vendor. Also, desiccant material had not i
been placed in each cable package. The inspectors found one cable end connector cap cover missing.
Subsequent contact with the i
vendor revealed that their procedure had been recently revised,
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but this had not changed the cable storage requirements. This i
discrepancy was recorded in MAC No.93-087.
In addition, the inspectors examined warehouse storage conditions
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for two electrical penetrations were less than the posted minimum
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value of 15 psig.
PMC-03, Rev. 16, Section 6.10.3 requires that
gas pressures be maintained between posted minimum and maximum
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values. A review of the available last three months weekly I
warehouse inspection reports showed that the cover gas pressure had been below its minimum value for an extended period of time.
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In addition, this discrepancy was not noted on the past quarterly
inspection reports performed by QC personnel. During an interview
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with a warehouse supervisor, the inspector learned that he was not aware of this discrepancy. When notified, warehouse personnel
recharged the nitrogen pressure to the correct value. Several threaded rods and two large safety-related breakers 'were found partially uncovered; thus, exposing these components to~ dust and
moisture. The above discrepancies were verified and corrected by-
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the licensee. The warehouse supervisor stated that the licensee
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plans to conduct an engineering evaluation to determine the proper
cover gas pressure and to modify the weekly inspection report process to ensure deficiencies are identified and corrected in a timely manner.
In Warehouse H, the inspectors found several desiccant indicators for control rod drive piston rods to be expired.
In addition',
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one piston rod which had been tagged as "On Hold" for several months because its desiccant had expired, had not been moved to a Hold Area, nor had its desiccant been replaced. The licensee i
agreed with the above observations and they were immediately
corrected.
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In Warehouse A, some labels on containers of Q class enamel
coatings prohibited exposure of its contents to temperatures in excess of 85*F.
The warehouse is not air conditioned and relies on a single force-i -ecirculation unit to maintain environmental
temperatures at acceptable levels. The temperature limits for
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Class B storage is 95*F.
Summer ambient conditions may make these
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conditions difficult to achieve. The inspectors performed a j
review of the temperature charts for warehouse A.
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temperatures routinely remained at or above 85'F, with several
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days reaching 94*F.
The licensee has performed an engineering r
evaluation and determined that Q class coatings from at least one manufacturer can be stored in temperatures up to 120*F. The licensee stated they would perform an evaluation of the other coatings stored in this warehouse.
The inspectors noted that the air conditioning unit for the Sea
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Van was not operating. The Sea Van provides an environmentally
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controlled storage facility for some safety related items. The
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licensee indicated that the unit had failed on the day of the
inspection.
it was repaired and returned to service on the same
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day. Temperature limits were not exceeded during this time
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period. Minor adversa condition reports have documented similar occurrences on at least three other occasions.
This event was
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In addition to the areas discussed above, the inspectors reviewed
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warehouse environmental controls, housekeeping and cleanliness, storage and separation of Q and non-Q material, fire protection, i
rodent control, access control, foreign material exclusion, motor t
storage conditions, stacking requirements, item labelling and identification, and chemical controls. The inspector found that
overall, the warehouse facilities were adequate for storing Q and
non-Q materials.
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i 10 CFR 50, Appendix B, Criterion XIII states that the licensee
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shall establish and implement measures in accordance with approved
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instructions to control the storage of equipment that is important to plant safety and to prevent deterioration of safety-related
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components. Contrary to these requirements, the licensee failed
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to implement those storage instructions contained in BSEP 113-030 t
and 0-PCM-03 stated in the above examples. This is a violation:
Inadequate Storage of Safety-Related Equipment (325,324/93-41-01).
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In addition to the maintenance activities above, the inspectors observed
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portions of the following maintenance activities:
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PM 93-031 Reactor Water Level Instrumentation Modification
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PM 82-220L Service Water Pump Replacement 2A NSW Pump
PM 89-001 Digital Feedwater Control System
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Modification
PM 92-103 Unit 1 Service Water Traveling Screen f
Modification WR/JO 93-BBRI-l Troubleshooting and Repair of. Unit 2
Hydraulic Control Units l
B The inspector observed portions of the above work activities and nc.ted
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that the work was performed by knowledgeable and professional personnel,
current revisions of procedures were in use and available at the work
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site, there was adequate craft and engineering support for these activities, and all work was completed in a timely manner.
One violation was identifi.. f 3.
Surveillance Observation (61726)
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The inspectors observed surveillance testing required by Technical
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Specifications. Through observation, interviews,.and record review the inspectors verified that:
tests conformed to Technical Specification requFements; administrative controls were followed; personnel were qualified; instrumentation was calibrated; and data was accurate and q
complete. The inspectors independently verified selected test results
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and proper return to service of equipment. The inspectors witnessed /
reviewed portions of the test activities addressed below.
Hardened Wetwell Vent
The inspector witnessed the performance of system acceptance test AT-1A, CAC V216 and CAC V7 Valve Operation and Logic Test, on September 9,
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1993.
Following some minor delays in establishing reliable communications from the control room to the technician in the field, the test was performed satisfactorily. The successful completion of this-test was the last of the acceptance tests which can be completed until drywell closure and unit start-up.
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The operability turn over sheets were completed on September 15, i
1993, with one remaining acceptance test being noted as a turn over exception. The inspector verified that the one remaining
procedure required for operability (Operating Procedure OP-46,
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Instrument and Service Air System) had been approved. The one remaining test noted above (AT-4C, Nitrogen System Hardened Wetwell Vent Valve Operational Test), will be completed during the unit start-up, i
feedwater Flow Nozzle Recalibration Inspection Report 325,324/93-33 addressed the non-conservative feedwater flow errors revealed by sodium trace testing. During this inspection period, the licensee evaluated the test results
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and discussed the recalibration of the feedwater flow nozzles with GE. GE calculated a new set of feedwater flow. transmitter differential pressure span adjustments to improve the accuracy of the plant's indicated feedwater flow and provided it to CP&L for
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evaluation. The licensee's evaluation of the new span values is documented in licensee Engineering Evaluation Report (EER) 93.
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0545.
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On September 12, 1993, the licensee implemented Special Procedure
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2-SP-93-061, Calibrating Feedwater Flow Transmitters 2-032-FT-N002A(B) at power. The special procedure required steady state conditions, feedwater flow control in single element, the.
recirculation pump scoop tubes locked out to avoid runback, and
the adjustment of one transmitter at a time. These special precautions were taken due to the instrument sensitivity and the pot rntial for a unit SCRAM.
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Once the desired conditions were established, the licensee
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performed OPIC-DPT006, Calibration of Rosemount Model 1151 Differential Pressure Transmitter. This procedure recalibroted
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the A and B loop feedwater flow transmitter differential pressure span adjustments using the new values provided by GE.
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the completion of the recalibration, the plant process computer /ERFIS reactor power calculations were corrected to.
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indicate appropriate reactor power. The GAFs were also reset to
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the correct value at this. time. The inspector reviewed the EER and the special procedures, as well as discussed the recalibration process with the system engineer. This process was accomplished-
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on September.12, 1993, without incurring any problems. This was
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an example of a well planned / executed task and is considered a strength, q
Violations and deviations were not identified.
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4.
Operational Safety Verification (71707)
The inspectors verified that Unit 1 and Unit 2'were operated in compliance with Technical Specifications and other regulatory
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requirements by direct observations of activities, facility tours,
discussions with personnel, reviewing of records, and independent
verification of safety system status.
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The inspectors verified that control room manning requirements of
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10 CFR 50.54 and the Technical Specifications were met.
Control operator, shift supervisor, clearance, STA, daily and standing
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instructions, and jumper / bypass logs were reviewed to obtain information
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concerning operating trends and out-of-service safety systems to ensure that there were no conflicts with Technical Specification Limiting.
Conditions for Operations. Direct observations of control room panels
and instrumentation and recorded traces important to safety were conducted to verify operability and that operating parameters were L
within Technical Specification limits. The inspectors observed shift turnovers to verify that system status continuity was maintained. The inspectors also verified the status of selected control room
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t Operability of a selected Engineered Safety Feature division was
verified weekly by ensuring that: each accessible valve in the flow path was in its correct position; each power supply and breaker was closed for components that must activate upon initiation signal; the RHR
subsystem cross-tie valve for each unit was closed with the power
removed from the valve operator; there was not leakage of major
components; there was proper lubrication and cooling water available;
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and conditions did not exist which could prevent fulfillment of the system's functional requirements.
Instrumentation essential to system actuation or performance was verified operable by observing on-scale
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indication and proper instrument valve lineup, if accessible.
i The inspectors verified that the licensee's HP policies and procedures
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were followed. This included observation of HP practices and a review of area surveys, radiation work permits, posting and instrument calibration.
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The inspecow, verified by general observations that:
the security i
organization was properly manned and security personnel were capable of
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performing their assigned functions; persons and packages were checked prior to entry into the PA; vehicles were properly authorized, searched
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and escorted within the PA; persons within the PA displayed photo
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identification badges; personnel in vital areas were authorized;
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effective compensatory measures were employed when required; and i
securitv's response to threats or alarms was adequate.
The inspectors also observed plant housekeeping controls, verified position of certain containment isolation valves, checked clearances and i
verified the operability of onsite and offsite emergency power sources.
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Unplanned Insertion of Control Rods j
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On September 27, 1993, the licensee made a report to the NRC in accordance with the requirements of 10CFR 50.72(b)(2)(ii) for an l
engineered safety feature (ESF) actuation on Unit 1.~ ie ESF Unit I was
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shutdown and defueled in mode 5 during the event.
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9 actuation involved the unplanned insertion of 39 control rods on September 24.
Initial screening of the event classified it as non-reportable. However, after further investigation, the licensee determined the event to be reportable.
To facilitate inspection of the Unit I reactor shroud, 68 control rods located at the periphery of the vessel were withdrawn with
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their blade guides removed, tagged out under clearance 1-93-2488, and had their accumulators depressurized. The purpose of this clearance was to prevent these withdrawn control rods from
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responding to a planned or unplanned scram signal. and to maintain cooling water flow to the drive mechanisms. The decision to
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maintain cooling water flow to the drive mechanisms was made in
accordance with a vendor recummendation to prevent the depositing
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of silt or crud in the drives. While the above noted activity was in progress, the Inservice Inspection (ISI) group was preparing to
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perform Special Process Procedure OSPP-HYDR 0500, Hydrostatic Test Of The Scram Discharge Volume (SDV). One of the prerequisites for the performance of this test was the initiation of a manual scram
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to depressurize the -emaining 69 charged Hydraulic Control Unit (HCU) accumulators and to assist in filling the SDV. When the manual scram was initiated, 50 of the 68 control rods tagged out under clearance 1-93-2488 partially inserted into the core. Of i
these 50 rods, 39 were inserted from the fully withdrawn position.
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to various partially inserted positions, while the other 11 initially moved inward, but settled back to the fully withdrawn r
positions.
Under this clearance, the water sides of the accumulators were drained; however, the nitrogen sides of the accumulators were not depressurized.
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Due to the clearance established, leakage past the 1-011-113 valves into the water side of the accumulators resulted in the repressurization of the accumulators. The clearance had accounted for this leakage in the special instructions which required the Auxiliary Operator (AO) to l
periodically verify and make an entry into the Reactor Building A0 log -
that the HCUs remain depressurized. The use of the 1-C11-107. valve to
drain down and depressurize the HCUs was also specified in-the special
instructions.
The leakage past the 113 valves and the resultant.
.i repressurization of the HCUs under clearance caused some of the
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periphery control rods to insert as noted above.
t In their investigation, the licensee discovered that this
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alignment did not follow the recommendations provided in vendor i
procedure GEK-9582A, which discussed the Control Rod Drive (CRD).
i Hydraulic System.
Per section 3-25 of procedure GEK-9582A, HCU Isolation with Cooling Water Flow, the gas side of the j
accumulators was required to be discharged in order to prevent CRD
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movement in response to RMCS or Reactor Protection System (RPS)
i signals. Operating Procedure 1-0P-08, Control Rod Drive Hydraulic i
System Operating Procedure, section 8.13, Removing a HCU From i
Service, also described the discharging of the gas side of the
accumulator. The decision to not discharge the gas side of the j
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accumulators was made based on_ past plant experience involving bottoming out accumulator pistons, ALARA concerns, and past
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experience where this set-up was successful.
Clearance 1-93-2488
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was not intended to completely isolate the accumulators as
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described in the above noted procedures, as cooling water was still being maintained for the drive mechanisms..
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Based on an investigation of the incident, 'the licensee determined that the control rod insertion was caused.by the following two factors, either independently or acting in combination. First,
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the accumulators under clearance 1-93-2488 were not maintained.
.i drained /depressurized low enough to ensure no scram action motion would occur when the scram signal was inserted. Second, the
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system configuration allowed for instantaneous pressure spikes in-
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the cooling water header sufficient enough to cause drifting of the control rods following the scram signal.
The inspector reviewed the licensee's investigation and concluded
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that the cause of the event above was the failure to properly establisn and provide necessary guidance and precautions for clearance 1-93-2488. Administrative Instruction 0-AI-58, Equipment Clearance Procedure, Revision 42, Section 3.4, requires that persons involved in the clearance process ensure that equipment clearance procedures are properly executed. Contrary to
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this requirement, clearance 1-93-2488 was implemented on i
September 3,1993, to prevent 68 withdrawn control rods from
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inserting on a scram signal. The clearance was inadequate in that 50 control rods partially inserted on a manual scram. This is identified as the first example of a Violation of Technical Specification 6.8.1.a:
Failure to Implement Procedures (325,324/93-42-02).
l The licensee initiated an Adverse Condition Report (ACR) to document this event.
The inspector will continue to follow and evaluate the licensee's corrective actions as they are
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. implemented.
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Group 1 Isolation On September 28, 1993, the licensee made a report to the NRC in accordance with the requirements of 10 CFR 50.72(b)(2)(ii) for ad engineered safety feature (ESF) actuation on Unit 1.
Unit I was shutdown and defueled in mode 5 at.the time of the event. The ESF actuation involved an unplanned Group 1 valve isolation signal.
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The event occurred while the licensee was in the process of performing the steam turbine electro hydraulic control (EHC)
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system field lineup.
This lineup was being performed using a
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reviewed and approved vendor procedure, FP-82236, Steam Turbine
EHC System Field Lineup Instructions. One of the steps in the
performance of this lineup required the stroking of the main steam-
control valves. To accomplish this task, the main turbine trip-l
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logic was reset to allow the opening of the control valves for the
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stroke test. During the performance of this test, the plant's electrical system lineup had the Unit Auxiliary Transformer (UAT)
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backfeeding from the grid, with the generator circuit breakers (PCBs) closed.
In the electrical alignment described above, backfeed through the UAT with the PCBs closed resulted in the EHC logic automatically selecting 1800 rpm as the turbine set speed when the turbine trip I
was reset. The auto selection of 1800 rpm initiated the control logic which resulted in opening of the main turbine stop valves.
c The opening of the main turbine stop valves in conjunction with low condenser vacuum completed the logic for a Group 1 Isolation.
i The Group 1 Isolation initiated a close signal for the Main Steam
Isolation Valves tMSIVs), which were already _in the _ closed position, and closed the main steam line drain valves.
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The generation of the Group 1 Isolation signal was not expected or anticipated during this evolution. The personnel performing the
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test had discussed the evolution with the ccntrol; room staff prior to performing the test.
The operators were aware of the' fact that
had they manually selected the turbine speed and performed the -
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turbine trip reset, the stop valves would come open'. The control room operators were not aware that in the given plant conditions (backfeed through the UAT and PCBs closed), the turbine control e
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logic would automatically select an 1800 rpm turbine speed.
Information concerning this event, or stipulating required plant conditions prior to performing the.est was not contained in j
either the approved vendor EHC lineup procedure being used at the l
time nor in any of the other procedures which may have been
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performed while the plant was in this condition.
Information which may have prevented this event is also missing from 1-0P-50, Plant Electrical System Operating Procedure, which describes UAT
backfeed. This lack of information covering prerequisite plant
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conditions in the procedures is identified as the second example of a Violation of Technical Specification 6.8.1.a.:
Failure to Establish and Implement Procedures (325,324/93-41-02).
j The licensee initiated an ACR to document this event.. Pending
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further investigations and the impicmentation of corrective
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actions, the licensee placed a cau', ion tag on tha-turbine trip l
reset switch warning of the potenial for a Group -1 isolation while in UAT backfeed with the PCBs closed. The inspector will
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continue to follow and evaluate the licensee's corrective actions as they are implemented.
floodina of RHR Room Floqr
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On September 26, 1993, an A0 responded to a Unit'1 South RHR Room-Sump High Level alarm and discovered approximately one inch of
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water on the floor.
Investigation revealed that water had i
overflowed from the RCIC barometric condenser vent.
The licensee
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determined that 1-MST-RCIC-41R, RCIC Auto Actuation and Isolation i
logic System Functional Test, Revision 8, was in progress, causing
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cooling water supply valve E51-F046 to open..The barometric condensate pump started on a level signal, but due to a faulty.
level. switch, would not shut off on a low level signal. The pump circuit breaker was opened to prevent pump cavitation. The RCIC
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keep fill system filled the barometric condenser because the
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cooling water valve was open and the condensate pump was not
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operating. The barometric condenser filled until it spilled on
the floor of the RHR room.
Subsequent investigation by the licensee revealed that the MST.was
continued when the condensate pump was rendered inoperable. No
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action was taken to evaluate the effects of the inoperable pump.
The area had recently been painted and painters had covered the floor drains, removed the hose from the vent line to the floor drain, and removed the dike surrounding the barometric condenser.
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This event initially received little attention from licensee personnel because of poor communications.
The C0. informed the SCO of the spill, but stated that there were only small puddles on the
floor. The C0 had not investigated the spill, but rather had l
relied on his memory of the presence of a dike which would contain
the spill. The licensee has documented this.in ACR 93-318, and is still investigating the event. The inspector considers the failure to stop the MST and evaluate the conditions after the
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condensate pump failed to be a weakness. The inspector will
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review and verify the licensee's corrective actions on this item as they become available.
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One violation (with two examples) and one weakness were identified.
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5.
Three-Year Plan Review (40500)
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The inspector reviewed the licensee's August status report on the Three-l Year Plan. Twenty-two activities were scheduled for completion in
August and thirty were actually completed. Ten milestones were
completed early and two previously late activities were also completed.
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One initiative action and three project phases were delayed. Those
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delayed included the Operations radio communications system,. the L
chlcrination alarm system which indicates remote isclation of the
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chlorine system, and the initiative action on additional API positions i
for Operations.
Some of the key initiatives completed during the month
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included: implementation of a procedure to track and control regulatory
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commitments, initiation of the backlog reduction plan, finalization of
the master facilities plan, and the replacement of the RHR F003A/B and j
F0024A/B valves. Changes to the Three-Year Plan in August resulted in
accelerating six projects, deleting twelve initiatives, and rescheduling eight projects. A review of the overall status found that 23
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initiatives and 69 procedures were in progress. The licensee appe rs to be making satisfactory progress on the Three-Year Plan. Changes i.
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scope, schedules, and priorities continue to be made as the licensee
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evaluates each project and makes adjustments as needed.
The inspector reviewed the licensee's Three-Year Plan for improvements to the cooling water reliability program initiative TY 505.
This
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initiative will develop and implement a program to predict, identify, repair, and protect the CW, RBCCW, TBCCW, and SW systems from degradation caused by erosion and corrosion.
It will also identify
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material substitutions to improve system resistance to corrosion. This project is scheduled for completion in December 1996. The scope and systems involved in this project are extensive.
Since the service water system has the largest safety significance and has experienced several
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recent leaks, it was selected for review. To date, three projects have
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been identified and are underway to improve the material condition of t
the service water system. These include:
PID 84070A Service Water System repairs,_ Phase II. This project is designed to provide for periodic inspection and upgrade of the service water.
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system.
In the past, portions of the system have degraded to a point that resulted in_ plant shutdown. This item will respond to concerns addressed in NRC Generic Letter 89-13. The work involved with this project will provide repair
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or replacement of deteriorated structures and components, as well as remove marine growth and debris from SW piping.
Planned modifications will include the addition of access points for inspections and the installation of rigging points for maintenance. This project is scheduled for completion in 1996. To date, considerable progress has been made in repair and replacement of deteriorated components, as
well as painting and preservation to prevent further corrosion.
- PID 01538A Service water system piping, Phase III. This
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project replaces and upgrades portions of the service water system large bore piping and valves. The RBCCW heat exchanger and associated inlet SW piping are to be replaced due~to
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plugged tubes and degraded heat exchanger-performance. The SW pumps will be upgraded for long-term seismic qualification with pumps-that t
have self-lubricated thrust bearings. To date, one pump has been replaced and work has started l
on the second pump. A Technical 3pecification
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change has.been approved that will permit taking one SW pump out of service at a time for pump repl acement. The portion of cement lined piping-
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-that.cannot be inspected and maintained will be
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replaced with corrosion resistant copper. nickel piping. This project ;is. scheduled for completion in 1995..for both units.,'When
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completed, this project will result in improved
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l service water system availability and'
reliability.
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e PID G0050lJ Diesel generator service water: supply and
l discharge piping replacement. This.. project will replace the' existing cement lined. carbon. steel service water piping to and from:the diesel l
generator jacket water. heat exchangers with-l
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L copper _ nickel piping. 'It will.also-throttle
service water flow to' the diesel in order to~
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balance flow to 'ather service water _ cooling l
equipment. The current schedule calls for
completion of piping installation by-the end of.
l Unit I refueling outage B111R1, currently;
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scheduled for November 1996. This system piping-q is not conducive to-extensive piping interior inspection due to its size.
It-has also
experienced several pin hole. leaks in the'past._
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several years. Therefore, c'ompletion of this
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modification should result in a significant d
reduction in leaks and improved system-l reliability.
The cement lined carbon steel ~ service water piping _has experienced 30 leaks since April 1989. As a result of-these previous leaks the~
licensee conducted a review of past failures and performed extensive-UT examinations to identify any additional areas where erosion or corrosion
may have resulted in pipe wall thinning. These examinations did not'
j identify any additional leaks._ However, two cases-of wall thinning were
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identified. One involved a six-inch discharge line which was evaluated; _
a as acceptable for continued operations,'and;a second: thinning area which
was. repaired.
Based on the above inspections.and due to theffact that
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all past-leaks had been very small.with no -symptoms _of catastrophic failure, the-licensee. concluded; that this was. acceptable for continued operation with a minimal-risk of failure.
Since that inspection, six additional leaks.have occurred.
Five have; been in weld areas and the sixth was:in a valve body. 'None of these failures were catastrophic.and-temporary repair methods were used to stop or reduce the-leakage until permanent repairs could be completed.
In all cases, the licensee's repair efforts were within the-guidelines of Generic Letter 90-05. The licensee's Three-Year _P1an; improvement
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. project,.when completed, should significantly ' reduce _the potential for
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these occurrences.'
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6.
Unit 1 Outage / Restart (71707)
(NOTE: Asterisked items are restart issues from CP&L's letter dated
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July 23, 1992.)
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(Closed) CP&L Item PM 92-91, RHR Service Water Booster Pumn improvement l
The licensee upgraded the RHR service water booster pumps for Unit 1 by I
replacing the four installed custom pumps with standard pumps for which
replacement parts can be easily attained. This included new impellers,
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larger shafts, and improved bearings and couplings.
In addition, the
assembly bed plates and skids were replaced with ones made of corrosion
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resistant materials (stainless steel) to correct anchoring and corrosion
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problems. The work was accomplished by Plant Modification 92-91 and
completed on September 7, 1993.
The above changes were implemented to reduce vibration problems and reduce maintenance. The inspector observed the disassemtly of the four
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units; installation of the bedplates, pumps, and motors; optical alignment of the units; and post modification testing, including vibration runs. The inspector observed that there were significantly.
fewer problems with the Unit 1 modification than with that for Unit 2.
l It appeared that the lessons learned from Unit 2 were effectively implemented in Unit 1.
The inspector noted that procedures and
applicable paperwork were at the job site and the craft appeared to be knowledgeable. The machining of the motor feet substantially reduced-i motor vibration and the time required for vibration testing. The
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testing demonstrated that the pumps will supply sufficient flow. The i
effort to reduce vibration has been successful. The closure of PM 92-91 completed the Three-Year Plan Project G0212A for Unit 1.
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- (Open) CP&L Item B-9. Repair of the IB Control Rod Drive Pump j
The licensee had committed to repair the IB control rod drive
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(CRD) pump prior to Unit 1 startup. They had identified that the i
pump had been operating at a low flow and reduced discharge
pressure. Subsequent pump head curve testing found the IB CRD
pump to be operating below the pump head curve. Based on the
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results of the testing, the licensee decided to replace the IB CRD
pump with a spare.
Replacement activities were completed on August 16, 1993. The initial operational runs following testing, indicated that the newly installed pump was operating at a higher than normal
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discharge pressure.
The new discharge pressure was 1600 psig rather than 1510 psig as designed.
The licensee operated the pump for a three week break in period in an attempt to resolve or gain a better understanding of the problem.
Following this period, the I
pump discharge pressure was still high, and they began trouble i
shooting activities.
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Initial troubleshooting focused on isolating the cause of the prob 1L1. The results of a rotational speed test confirmed that
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the problem was in the pump and not in the motor or speed
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increaser.
The licensee then performed testing to quantify the flow characteristics of the new pump. Using these results, they
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calculated a new pump head curve. The new curve was determined to
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be parallel to the vendor supplied curve, but approximately 70 psig higher.
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In an effort to determine the cause of the problem, the licensee has been reviewing this item with the vendor, Union Pumps. The i
licensee and the vendor believe the cause of the problem is
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Previous weld repair and
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machining performed on the casing may have changed the t
hydrodynamics of the casing. At the close of this inspection
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period, the licensee was performing further testing and
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measurements.
The inspector will continue to follow the testing
and repair activities as they are accomplished.
This item remains open and is required to be completed prior to Unit I restart.
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- (Closed) CP&L Item D-4, Unit 1 Corrective Maintenance Backloa Reduction
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The following are the corrective maintenance backlog categories, gcals,-
and status as of October 8:
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Change In t
Indication Goal Status 10/8 Past Month l
Focus systems
<650 397
1 (on line WR/J0s)
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t Focus Systems
<80 106 110
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(Priority 1-4
WR/J0s)
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Other Systems (80
44 (Priority 1-4 i
WR/J0s)
j Control Room
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20
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r Operator Work
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40
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Arounds
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Caution Tags
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Change In Indication Goal Status 10/8 Past Month (cont'd)
f STSI Items
<25
222
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Temporary Mods
<20
3 A review of the above items indicates that good progress has been made over the past month.
The licensee currently has less than 350 remaining _
WR/J0s scheduled to be completed prior to Unit 1. restart. They have completed over 32,000 WR/J0s since shutdown on April 21, 1992. Of this number, over 17,000 have been on Unit 2, over 13,000 on Unit 1, and the remainder were common to both units. This has resulted in a significant improvement in plant material condition and should contribute significantly to improved performance and reliability. The majority of the WR/J0s left to be completed prior to Unit I restart are associated with core shroud inspections, core reload, reactor vessel reassembly, and outage clean up prior to restart. Considering the current two month delay in restart, this apears to be easily achievable.
The inspector conducted a review of the IBIR for the RHR, Core Spray,
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Service Water, HPCI, RCIC, and ADS systems to gain a better
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understanding of the WR/J0s that remain open and are scheduled to be completed after restart of Unit 1.
After discussion with the System
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Engineers on each of the above systems, the inspector agreed that these
open items would not have an adverse impact on safe operation of each system.
Based on a review of the existing backlogs and a detailed review of the above six systems, it appears that this issue has been satisfactorily resolved for Unit I restart.
- (Closed) CP&L Item D-3. Reduction of Operator Work Arounds
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On May 17, 1993, there were 122 Unit I cperator work arounds and by
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August 25, 1993, the licensee had reduced this number to 105 work
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arounds. The Unit 1 goal is less than 25 by startup. On August 25, the
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licensee issued Operation Ir.struction, 01-70, Operator Work Around Identification and Tracking, Revision 0, which revised the makeup of work arounds. 01-70, Section 4.1 defines a work around as "anything other than the initial response to an event or equipment failure that requires an operator to perform additional work or to take compensatory _
action because something does not work as it should." Section 5.1
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states that active LCOs, Clearances, and Temporary Caution Tags directly
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related to the outage should not be tracked. Active LCOs, Clearances,
Temporary Caution Tags, RTGB WR/J0s and increased frequency pts should not be considered as operator work arounds unless they are greater than
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30 days old or are excessively burdensome to shift operations.
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Based on the above criteria, Operations reviewed the Operator Work Around List and determined that 36 items were related to planned outage work, 5 items were related to long-term modifications or decommissioning
work, and 24 items were redundant to the RTGB WR/JO tracking system.
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These items were deleted from the system. This reduced the number of Operator Work Arends to 39 items. They also reduced the goal for work.
arounds to 20. On October 8, 25 items remained. The Unit 1 Operations Manager stated that 16 of these items. are startup related and will be closed out at startup.
The licensee has significantly reduced the backlog through administrative changes.
The inspector reviewed the revised list and did not identify any which affected safety and could not be worked on line.
The Unit 1 operator work around backlog is acceptable.for startup.
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- (Closed) CP&L ltem A3 - Seismic Instrument Rack Corrosion Repairs
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As a result of concerns identified by the NRC in early 1992, the Unit 1
and Unit 2 instrument racks were inspected and evaluated for corrosion and seismic concerns. This evaluation resulted in upgrades.on 21-of the 24 instrument racks on Unit 1 and 24 instrument racks in Unit 2.
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work on the Unit 2 instrument racks was performed under Plant Modification (PM)92-071 and was closed in Inspection Report 325,324/
93-17.
The work on the Unit 1 instrument racks was performed under PM 92-070.
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Three racks on the -17 ft. elevation, 1-H21-P014 (HPCI), 1-H21-P018 (RHR
A), and 1-H21-P021 (RHR B), were replaced with corrosion resistant
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stainless steel racks. The remaining five instrument racks on the -17 ft. elevation had seismic restraints added and are scheduled to be replaced during the next refueling outage. The remaining racks had conduit supports and/or flexible conduit added. The inspector observed the disassembly of the old racks, construction and assembly of the new racks, and testing of the following racks during the course of the implementation of the PM 92-070:
1-H21-P014
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1-H21-P018
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RHR A 1-H21-P017
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RCIC 1-H21-P009 and P010
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Jet Pumps 1-H21-P015
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Main Steam Flow A 1-H21-P025
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Main Steam Flow B
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1-H21-P004 and P005
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Rx Protection and NSSS The inspector observed that work procedures and packages were at the job i
site and used. Work practices and housekeeping were adequate throughout i
the duration of the project. The inspector observed pressure testing i
and calibration of the instrumentation after reinstallation. There was adequate craft, supervisory, and QC support during the testing phases.
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No significant problems occurred during this modification.
All work on the Unit 1 instrument racks has been completed and all work packages have been closed. The racks have not yet been declared operable since the support systems are not op..able. The completion of the Unit 1 instrument rack modification (PM 92-070) completes this item.
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- (Closed) CP&L Item 02 - Reduction of Temporary Conditions
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The licensee previously used the temporary condition list as a tracking j
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system for items in such categories as operator work arounds, RTGB
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WR/J0s, Control Room Annunciators, permanent caution tags, and Temporary Modifications. The temporary condition list did not have any real value
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as the items were carried on other more complete lists. The licensee decided to change the way it compiled lists. They evaluated the various
lists and assigned responsibility for each list to a single organization
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(i.e., NED for STSIs, Technical Support for Temporary Modifications, and
Operations for Operator Work Arounds).
In the past, there were frequent
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examples of double and triple counting of items when several
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organizations provided input, and no single organization assumed
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j responsibility for administering a given list. This made it difficult
to determine the work required to correct and close the item.
Defining j
the list and assignment of responsible organizations resulted in the
elimination of the temporary condition list. The inspector reviewed the i
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the items on these individual lists and found them acceptable for
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startup.
l (0 pen) NRC Bulletin 93-03. Resolution of Issues Related to Reactor
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Vessel Water level Instrumentation in BWRs l
The licensee met the reporting requirements of the bulletin in a i
response to the NRC dated July 21, 1993.
In this response, the i
licensee documented their completion of the requested short-term
action and provided a description of the requested hardware
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modifications that would be implemented on Unit 1 prior to restart
from the current outage and during the next Unit 2 cold shutdown
following July 30, 1993. The licensee has implemented the requested short-term actions and is in the process of installing the requested hardware modifications on both units.
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In response to NRC Bulletin 93-03, the licensee has initiated action on the implementation of plant modifications 93-031/93-032, which will install the requested hardware on Units 1 and 2, i
respectively. These modifications will install a low flow j
backfill installation to serve each of the seven cold reference
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leg condensing pots per unit. A water source will be injected l
into each reference leg piping, such that the constant flow l
through the reference leg will prevent the migration of non-
condensible gases down into the reference leg from the condensing
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chambers.
This constant flow water source will be taken from the
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Control Rod Drive (CRD) system charging header which is capable of
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overcoming reactor pressure. The components of this system
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consist of instrument tubing, flow control devices, flow measurement devices, manual isolation and test valves, check
valves, flow restricting orifice, and an inline filtering
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mechanism.
The design of the system is similar to that used in
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the backfill modification testing conducted by the BWR Owners
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On September 28, the inspector verified the stitus of the installation on the two units by performing a system walkdown.
Previously, the inspector had performed a system walkdown with the system engineer and discussed the system design and installation.
The inspector observed that the licensee had completed the
hardware installation and required connections to the charging water header and instrument legs on Unit 1.
The licensee had
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completed the system flush and was in the process of performing-i the initial system hydrostatic test. The initial test is performed with 50 psi of air pressure, followed by a slow
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pressurization with water to 2000 psi. The licensee expected to complete the testing and have the system ready for turn over for preoperational testing by the end of the week of October 4,1993.
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The inspector observed that the only remaining work to be completed on Unit 2 was the connections to the charging water header and the instrument legs. The system engineer informed the v
inspector that Unit 2 status would remain unchanged pending a unit
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shutdown to cold shutdown when the remaining work would be j
completed. The inspector will continue to follow the installation
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of these two plant modifications; the procedural revisions; and
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the site acceptance, pre-operational and operational testing of l
the systems as they are performed. The completion of the installation on Unit 1 is a startup requirement.
(0 pen) P2191-07, Crackina Of Sulzer Binaham Recirculation Pump
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Shafts On September 9 and 10, 1993, the licensee performed a shaft integrity test on the Unit I recirculation pumps. This action was performed in
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response to a Sulzer Bingham letter dated January 18, 1992, which informed the licensee that their recirculation pumps were included in 'a group of pumps noted for potential shaft cracking and advised inspection of the pump shafts at the earliest opportunity.
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The licensee had previously performed this same testing on the Unit 2 recirculation pumps in February 1993 (see Inspection Report
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325,324/93-16). As with Unit 2, the licensee contracted with ENPROTECH j
Corporation to perform the insitu pump shaft integrity test via their modal method, rather than remove the pumps shafts to support a liquid-
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penetrant test. The inspector observed in the pre-job briefings and witnessed the initial equipment setup in preparation for the testing.
The inspector also discussed the test methodology and theory with the engineer from ENPROTECH who was performing the test.
The test methodology is discussed further in the above mentioned inspection
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report.
The licensee received a preliminary analysis report from ENPROTECH which did not identify any indications of cracking in either of the pump-shafts. The licensee expects the final test analysis report by the end j
of October. The inspector will review the results of this report and a
forward a copy of the results to the appropriate regional personnel when
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Resolution of this issue is required for restart
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of Unit 1.
This issue will remain open pending NRC review of CP&L's
final resolution report.
i (0 pen) PM 89-01 Diaital Feedwater Control System The licensee has implemented a plant modification to upgrade and replace the existing feedwater control system for Unit I with a digital feedwater control system (DFCS). The new digital system will be bei er l
able to respond to and recover from plant transients that had previously
presented challenges to the plant's operators and protective systems.
It is designed to accommodate the following dynamic responses:
e Maintain reactor water level within acceptable limits to prevent a reactor scram on the trip of one feedwater pump at full power.
e Maintain reactor water level above the setpoint for initiation of emergency core cooling, accounting for
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the shrink effects, following a reactor scram from i
full power.
e Maintain reactor water level below the high level trip setpoint, either recovering from shrink effects
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following a reactor scram, or on the trip of one recirculation pump at full power.
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e Stabilize reactor water level at any new steady state after level change in single and three element control mode.
The DFCS equipment was installed in panel H12-P612 in the back
panel area, with indication and operator interfaces located on panel H12-P603 in the control room. The equipment was installed in the space vacated by the analog equipment. The associated transmitters, controllers, indicators, converters and switches l
were one for one replacements of the existing components. All
equipment addressed by the modification package is nonsafetya related (Non-Q), with the exception of the reactor coolant level transmitters which are safety-related (Q), since they are part of the reactor coolant pressure boundary.
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Installation of this plant modification in Unit 1 began on September 9, 1992. The licensee completed the entire installation process and performed an installation walkdown on August 9,1993.
Following the completion of the system installation, the system
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was turned over for the performance of the site acceptance test.
The test, which was designed to demonstrate that all hardware was properly configured and that the input / output subsystem was l
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functional, commenced on August 24, and was completed satisfactorily on August 28. The inspector reviewed and discussed the test results with the system engineer and found them to be acceptable.
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The next process necessary to complete the modification package involves i
the performance of the Pre-Operational Test. The objective of the Pre-
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Operational Test is to demonstrate acceptable functional operation of the DFCS, including: controllers, annunc utors, ERFIS and process
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computer points, indicators, and controllers. The inspector witnessed l
portions of the pre-operational test on September 3 and 8.
On
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September 23, the licensee started the loop calibrations associated with this modification.
The licensee expects to complete all the required
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preoperational testing during the week of October 4,1993. Along with
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the performance of the preoperational testing, the licensee is also in i
the process of revising the various documents and drawings associated
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with the installation of the modification. The licensee expects to have i
all changes / revisions required prior to system operability to be l
completed during the week of October 4,1993.
Following the successful
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completion of the Pre-Operational Test, the system will then be declared i
operable and turned over to Operations for operational testing during l
the Unit 1 startup. The system has already been installed on the l
simulator and the crews are currently being trained and evaluated on its
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use.
The inspector discussed the results of the testing and procedure revisions completed to date with the project engineer and found no discrepancies or problems.
The inspector will continue to follow the status of the testing and procedure revisions as they
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are completed.
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Action on Previous Inspection Findings (92701) (92702)
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(Closed) Deviation 325,324/92-04-01, Failure to Meet NRC Commitment Related to Post Maintenance Testing Requirements (PMTRs). The f
licensee's April 11, 1991, response to Violation 325,324/91-02-02 stated that " Improved guidance with respect to determination and conduct of l
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Post Maintenance Testing Requirements will be developed by August 19, 1991." On March 12, 1992, the inspector determined that improved PMTR guidance had not been developed nor had the NRC been notified that the i
licensee would not meet their August 19, 1991 commitment. A deviation
was issued for the missed commitment.
i The licensee's corrective actions were to review the Facility Automated Commitment Tracking System (FACTS) to determine if regulatory
commitments had exceeded their committed dates.
Also, a review of NRC correspondence for the previous three years is in progress to identify
commitments, ensure they are captured in FACTS, and they are identified
as being regulatory based. The review of FACTS determined that two-l FACTS items had exceeded their regulatory commitment dates.
Both of the items involved changes to NED procedures. The inspector reviewed the changes and verified that they had been incorporated.
The licensee's review of docketed correspondence for the previous three years is not j
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i complete. They have completed their review of all inspection reports
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and most of the LERs. The LER review is scheduled to be completed by
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November 15, 1993, and the review of miscellaneous correspondence is scheduled to be completed by December 31, 1993. The licensee is also enhancing its commitment tracking system. The inspector has concluded that the licensee has addressed outstanding items and implemented -
adequate corrective actions.
In September, NAD completed a detailed
audit of the tracking system, reports and other correspondence. They determined that the licensee's commitment had been met.
Based on the above, and the fact that the majority of the licensee's corrective actions have been completed, this item is closed. The inspector will follow the licensee's remaining effort and the effectiveness of the
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enhanced tracking system in future inspection reports.
(Closed) ORAT Item 93-201-03, Unauthorized Operator Aids in Cabinets.
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The ORAT inspection prior to the restart of Unit 2 found unauthorized
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operator aids such as handwritten tags on the main control-panels,-
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drawings inside of the back panels, and information taped to the remote shutdown panel. The aids referenced clearance numbers, engineering documents, and work requests. This information appeared to have been.
intended to assist operators and technicians in the conduct of their duties. The licensee's corrective action for this item included an evaluation of the effectiveness of Operations Instruction 01-41, Operator Aids. This instruction was reviewed by the licensee against i
the requirements of INP0 84-005, Control of Operator Aids, and updated
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in Revision 10 to correct the identified deficiencies. The inspector reviewed the revised instruction and determined it to be satisfactory.
i Training has been scheduled for all groups with a completion date of December 31, 1993. This item is being tracked for completion by
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Regulatory Compliance under FACTS 93B1180. The licensee also conducted
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an inspection of Unit 1 and Unit 2 cabinets and removed uncontrolled operator aids such as prints, procedures, references, hand sketches, and foreign objects.
In some cases, labels considered essential were documented and allowed to remain until permanent labels can be installed.
Some of these consisted of dyna-tape labels in the backpanels that need to be replaced with permanent labels.
To confirm completion of the above, the inspector reviewed licensee documentation associated with the corrective action for this item and
conducted a walkdown inspection of the backpanels, remote shutdown panel, 120 VAC and 125/250 VDC panels, and a random selection of other
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panels in Unit I and Radwaste. The remote shutdown panel and a small
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selection of other panels were additionally inspected to ensure that
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" aids" had not been returned to these panels since Unit 2 restart.
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Overall, the panels were found to be clean and free of drawings or any other type of operator aids. However, a high voltage safety mat was found in the Unit I remote shutdown panel and some " marking pen" load
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listings were found on two breakers in Unit 1 UPS Distribution Panel 1A-HG8.
In the Radwaste Control Room several temporary jumper labels
dated 1978 were found on wiring in back of the control panel-.
It was
also noted that spare parts, hoses, tool boxes, file cabinets, a duplicating machine, and other miscellaneous equipment was stored behind l
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the main control panel and in many cases, near exposed electrical wiring and terminal boxes. The above-items were discussed with the licensee and they corrected / removed the marking pen labels in the UPS panel and
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the electrical safety mat from the remote shutdown panel. Additionally, i
the licensee conducted an inspection of the radwaste area and-removed unnecessary equipment and the temporary jumpers from the back of the control panel. The inspector conducted a reinspection of these deficiencies on October 3, and found that they had been satisfactorily
corrected. This item is closed.
.j (Closed) Violation 325,324/91-02-02, Activities Affecting Quality Were
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Not Properly Described by Documented Instructions. The licensee's
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maintenance organization had decided that it would be a good practice to
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install new packing, of known and preferred design, in new valves prior-
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to installation.
This resulteo in new valves being purchased without stem packing. The packing of new valves had not been proceduralized and-it was left to the maintenance planner to determine whether to include packing instructions when planning replacements with new valves.
In January 1991, an I&C technician's clothing was contaminated in Unit 1 when he opened the 3/4-inch drain valve E11-V89 (RHR Heat Exchanger Inlet Drain Valve).
E11-V89 is installed in series with a second valve, E11-V90. The RHR system was not pressurized or in service at the time
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of the event. Disassembly of V89 and V90 revealed that neither had stem t
packing installed. Subsequent investigation revealed that the valves were replaced during the 1988/89 Unit I refueling outage under DRs 88--
340 and 341. The inspector concluded that the lack of packing would have been obvious during a leak test and the valve had not been opened to perform post maintenance testing. A review of the completed DR package revealed that the PMTR for V89 required a leak test in accordance with ANSI B31.1. However, the PMTR was not specific as to what was to be inspected, the test pressure, or the acceptance
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criteria. The PMTR for V90 required a verification that there was no leakage at system pressure. The inspector concluded that the operators who performed the test were inadequately trained and the PMTR was
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inadequate in that it did not adequately describe what was to be
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accomplished.
l The licensee added Step 4.2.7.13 in OMMM-003, Corrective Maintenance (Automated Maintenance Management System), Revision 11, which provides valve replacement information. A procedure governing post-maintenance testing has been written and implemented which lists PMTRs by equipment
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and maintenance activity.
In addition, the licensee performed a review of replacement valves for both units to determine if any valves may not
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have received an adequate pressure test. WR/J0s 91-APPS1 and 91-APZC1 were written to test those valves which met that criteria.
The inspector reviewed the above documents and verified that the corrective actions had been completed. Similar events have not been reported and the corrective action appears to be adequate. This item is close.
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(Closed) Violation 325/92-04-02, Failure to Perform 10 CFR 50.59 Evaluation and ASME Code Required Testing.
In January 1992, preventative maintenance was performed on the IB RHR Service Water booster pump.
There are two RHR SW trains and each contain two RHR SW booster pumps. Work on either pump requires common isolation valves to be shut which renders the train inoperable and places the unit in a seven day LC0.
The work effort required the IB booster pump to be physically removed which would have exceeded the seven day LCO. The licensee made a decision to blank off the pump connections, open the isolation valves, and regain the use of the third booster pump. This action extended the LC0 to 31 days.
Engineering Evaluation Report (EER)92-004 was written to evaluate this condition. The EER was inadequate in that it did not evaluate the temporary change in the system fluid boundary.
Properly engineered flanges and appropriate gaskets and fasteners were selected to blank off the pump, but no consideration was given to any code required testing as a result of the temporary flanges becoming part of the system fluid boundary. Subsequent to the flange installation, but within seven days of the B RHR SW train being inoperable, the inspector inquired of the licensee as to the testing which had been performed and the results of the safety analysis. The licensee did not consider that either was required as it was a maintenance activity and a PMTR would be performed prior to restoring the pump to operation. The licensee documented this event in ACR 92-016. An acceptable pressure boundary test was subsequently performed on the system within the seven day LCO.
The licensee identified several causes of the event, most of which related to training and procedural adequacy.
Engineering addressed the removal of the pump as a structural issue, but not as a temporary condition. Neither NED nor Technical Support engineers were familiar with the difference in the makeup of an STSI verses temporary condition issue.
In addition, the licensee determined that the description on the WR/JO was inadequate as was procedural guidance for the maintenance planner.
The following corrective actions were initiated:
Engineering Procedure - ENP-12, Engineering Evaluation Procedure,
Revision 30, added in Section 2.4.3 the requirement of a safety evaluation for all planned temporary changes.
Technical Support and NED training was evaluated and Section XI e
training was given September 14-18, 1992. Qualified Safety Reviewer Requalification Training included training in 10CFR50.59 evaluations.
Training was given to maintenance planner / analysts, E&RC planners, e
and ISI/PMTR planners on the temporary change process and control of temporary modifications.
This training was completed in December, 1992.
The event was reviewed with the appropriate groups which
controlled work processes.
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The inspector reviewed ENP-12, Revision 30, applicable training records
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and lesson plans and verified that the corrective actions had been completed.
The inspector has not observed the recurrence of similar situations.
Technical Support performed a self-assessment of the Temporary Modifications Program in July 1993.
This self-assessment focussed on programmatic issues and identified weaknesses involving the completion of some temporary modifications included in the Three-Year Plan which extended completion beyond the next refueling outage, as well as administrative issues concerning modification tracking for expiration and the posting of temporary modification drawings. No examples of failure to perform an evaluation were identified.
Based on the inspector's review and the results of the licensee's self-assessment,
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this item is closed.
(0 pen) IFI 325,324/93-33-03, Cracks in Core Support Shroud.
Inspection Reports 325,324/93-30 and 93-33 discussed the cracks which had been identified in the Unit I core support shroud.
CP&L determined through trial and error that in order to perform an effective in-vessel visual inspection, it was necessary to remove the outer control rod blade guides for adequate access, pre-clean inspection areas, and obtain improved resolution for a VT-1 examination of a "l-mill wire" (in lieu of the code presented resolution). They also determined that camera
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placement and. view angle, as well as lighting positioning were critical attributes. As a result of these lessons learned, many areas were re-examined and the films re-reviewed. Suspicious areas were digitally enhanced to provide better definition. The inspector viewed many of the films, including re-examined areas.
On September 12 and 13, 1993, GE demonstrated the use and qualification
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of the UT scanners at their California facility. The demonstrations, which were observed by an NRC consultant and a Region II specialist, included deep water testing (51 ft.) and the use of time of flight (T0F)
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transducers. Two scanners arrived at the site on September 18. A spare unit arrived two days later. Scanning was delayed because of the unavailability of the T0F transducers and the difficulty in setting up the equipment.
Initial scanning of the H-3 weld commenced on September 24, and continued through September 28. The NRC consultant and the Region II specialist were on site September 20-26, to observe the scanning and review the data. The licensee was unable to obtain adequate data from the T0F transducers and all data was obtained from the 45 degree and 60 degree transducers. The initial data indicated
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crack depths of up to 1.7 inches.
NRC personnel reviewed the licensee's data and concurred with their analysis of the results. The NRC
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specialist and consultant believed that the techniques and data evaluations were adequate. This is described in more detail in Inspection Report 325,324/93-43. The licensee took data from four
quadrants with 11 eight-inch scans and obtained crack' depths that ranged I
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from 0.8 to 1.7 inches. These depths were greater than the maximum crack depth allowed by the GE analysis for continued operation. On
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September 23, the licensee met with NRC at NRC Headquarters to discuss the testing ar.d proposed repair option for H-3.
On September 28, the licensee made a decision to repair the core support
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shroud.
On October 1, the scope of the repair was increased to include r
both the H-2 and H-3 welds. GE is in the process of designing the repair which presently consists of twelve equally spaced clamps around the shrouds. They are also designing and manufacturing the tooling necessary to implement the repair. The repair is currently scheduled to be completed by November 28, 1993.
l The licensee continues to perform UT and VT inspections of both the ID and OD of the shroud. Many of these inspections are repeat efforts
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using improved techniques.
Two boat samples from the OD of the H-2 weld
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have been taken to validate the UT results and technique. The boat i
samples will be sent to GE for analysis.
- The NRC issued Information Notice 93-79 dated September 30, 1993, and GE issued SIL No. 572 dated October 1, 1993, concerning the shroud cracks identified in Unit 1.
The inspector-will continue to follow this issue and address it further in subsequent inspection reports.
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(0 pen) IFI 325,324/92-22-01, Weakness in the Control and Issuance
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of Documents.
The inspector has identified that procedures were
in use with outstanding "must have" revision requests (Inspection i
Report 325,324/92-04). The inspector also found out of date drawings and procedures in control room cabinets (Inspection l
Report 325,324/92-11) and identified that NED provided advance copies of drawing changes directly to the control room, rather than through document control. The inspector had previously discussed these concerns with the licensee, and subsequently NAD
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l performed an assessment of Document Control (Report No. B-DC-92-
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01). This assessment identified eleven performance and three
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resource issues, and concluded that document control performance
was marginally acceptable.
Six ACRs were written as a result of
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the findings identified during the NAD assessment.
In addition to these, the NRC identified that uncontrolled documents were being used by NED and being maintained in the NED library (Inspection Report 325,324/93-25),
i The licensee has taken some corrective actions for the above t
identified weaknesses. The Three-Year Plan has two initiatives
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which should also contribute to the overall improvement in i
Document Control.
These initiatives are TY301 (Improve Procedure i
Control Process and Procedure Content) and TY308 (Develop Centralized Document Control Program).
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The licensee has closed the NED library and consolidated all activities into the maintenance and TAC libraries. The libraries were staffed and monitoring of the duplication of documents has increased. These and
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other actions taken with respect to document control, have ensured that the program is acceptable for Unit I restart.. However, this item will
remain open as some corrective actions have not been defined, nor have
all the defined corrective actions been implemented.
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8.
Review of Licensee Event Reports (92700)
i (Closed) LER l-93-09, Possible SBGT Damage During a LOCA. On April 21, 1993, the licensee was performing a design basis documentation review of
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the Standby Gas Treatment (SBGT) system when they discovered that the
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existing drywell venting procedures were non-conservative. The
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procedures required the use of the large 18-inch Containment Atmospheric
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Control (CAC) butterfly valves as the exhaust pathway through the SBGT trains to the plant stack.
In utilizing this vent path, the licensee determined that the SBGT trains were not protected from over
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pressurization damage in the event a Loss of Coolant Accident (LOCA)
were to occur while primary containment was being vented.
t The licensee investigated the cause of this procedural deficiency and determined that the 18-inch butterfly valves and the 2-inch
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bypass valves had been used for drywell venting through SBGT since initial unit operations.
Early correspondence between the licensee and the NRC during the early 1980's indicated that this issue had been previously discussed in relation 'to Branch Technical Position CSB 6-4 on Containment Isolation issues and Standard Review Plan Section 6.2.4 (Rev.1).
In a letter dated
November 2, 1979, between CP&L and the NRC, CP&L incorrectly identifies that only the two one half inch post-LOCA valves were used for periodic containment venting.
The use of these valves
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provided protection for the SBGT system from damage associated-with a LOCA during containment venting. This letter was later incorporated into the Updated Final Safety Analysis Report -(Rev.
0) and issued during July 1982. A January 20, 1983, letter from
CP&L to the NRC indicated that the use of the one half inch valves had been shown by testing to be inappropriate for power
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containment venting.
In response to these test results, CP&L was l
pursuing the use of intermediate size valves, such as the drywell
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head vent in lieu of the larger valves. This issue was later lost i
in the overlapping CAC valve operability issues of the time and not tracked to final resolution.
As noted above, the issue was rediscovered during the design
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basis documentation review. On April 21, 1993,- the issue was i
documented in LER 93-09. Given the current procedures and vent path, calculations revealed that the SBGT filters.would be
subjected to 5.4 psig one second following the LOCA and a maximum pressure of 23.3 psig, well in excess of the SBGT filter design
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pressure of 2.0 psig. Use of the two-inch bypass lines. for i
venting has been shown by calculations to limit pressure at the
SBGT inlet to 0.35 psig following a LOCA.
This value is within.
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the 2.0 psig design pressure of the filters. Additional
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calculations indicated that venting from the drywell, the torus l
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and the drywell head vent would only yield a SBGT inlet pressure of 0.37 psig following a LOCA. The inspector discussed and
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reviewed these calculations with the system engineer.
The licensee has completed its corrective actions associated with
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this LER. The licensee has revised operating procedures for both
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Units 1 and 2 to correct this procedural deficiency. OP-10,
Standby Gas Treatment System Operating Procedure, was revised to allow primary containment venting through the SBGT system only via
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the two-inch bypass lines or when the reactor is depressurized.
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OP-24, Containment Atmosphere Control System Operating Procedure,
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was revised to ensure that the primary inerting/deinerting path is
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through the purge fans, rather than SBGT if radiological conditions are acceptable. The inspector has reviewed these
corrective actions and finds them acceptable for unit start-up.
While in the process of addressing this issue, the inspector
became aware of a concern with SBGT system operability at another site. The issue involved the control of the heaters in the SBGT trains. The relative humidity heaters were controlled by a sensor which would cycle them to maintain the relative humidity between 50 and 70 percent. Humidity greater than 70% sdversely effects the efficiency of the SBGT charcoal adsorption beds. The concern i
was that the relative humidity sensors were not included in the
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calibration of the relative humidity heater controllers.
Calibration of the sensors was indicated in the vendor manual to account for degradation of the sensors due to normal aging of the
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lithium chloride used in the sensors.
Potential failure or i
degradation of the sensors which could have impacted the
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operation of the SBGT system went unnoticed.
Based on the potential impact to safety of this issue, the
inspector irvestigated this issue at Brunswick. The Brunswick SBGT system consists of two parallel 100% capacity filter trains
and fans with the necessary ducting and dampers to provide a
suction path to the filters and an exhaust path from the fan to the plant stack.
Each train consists of the following components:
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moisture separator, heater, prefilter, HEPA filters, carbon
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filters, and a fan and motor. The current design of the heater and its controls is such that the heater is normally de-energized -
and in AUT0; the heater is energized when the fan is energized on
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a system start.
The previous design was such that the heaters were energized continuously with the heater full on in the run
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mode and thermostatically controlled in the standby mode to prevent a high temperature condition and possible ignition of the
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charcoal filters.
This design was modified on both units during
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the last refueling outage. The new design contains a heater-interlock with the fan' to prevent heater burnout with no airflow
and a thermal cutout de-energizes the heater if a high temperature exists which could possibly ignite the charcoal filters. A direct reading relative humidity indicator mounted in the inlet to the
first HEPA filter is provided for local indication only. The l
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system may be manually started in accordance with Operating
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Procedure OP-10, Standby Gas Treatment System, Rev. 28, Section 8.3, SBGT System Startup to Reduce Humidity.
Based on a review of the system design and discussion:, with the cognizant system engineer, the inspector concludes that the above noted concern is not an issue at this site.
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(Closed) LER 1-93-001, CAC Radiation Monitors Not Seismically Qualified.
Regulatory Guide 1.45 " Reactor Coolant Pressure Boundary (RCPB) Leakage Detection Systems," dated May 1973, states that leakage detection-
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systems should be' capable of performing their functions following
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seismic events that do not require plant shutdown and the airborne particulate reactivity monitoring system should remain functional when subjected to the Safe Shutdown Earthquake. The licensee committed to-provide a continuous monitor capable of detecting particulates,
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halogens, and noble gases in Amendment 15 to the FSAR (Section M4.18-1).
CAC monitors 1260, 1261, and 1262 were installed to meet this requirement.
As previously discussed for Unit 2 in Inspection Report 325,324/93-19,a history of inadequate licensee reviews has lead to confusion over the seismic qualification of radiation monitors CAC-1260,1261, and 1262.
The licensee determined through design documentation research and review
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that the monitors were not being controlled as Q-class. On January 21, 1993, ACR 93-033 was generated to identify this as a TS operability
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concern, following a NED determination that the monitors did not meet
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the seismic requirements. LER 93-001 was issued on February 22, 1993,
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to report this condition.
On September 16, 1993, the licensee issued a supplemental report to LER 93-001.
In this report, the licensee states that the event was caused by the failure to identify and clarify the inaccurate SER statement that i
the major components of the RCPB Leakage Detection System were in
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conformance with the provisions of-RG 1.45.
The licensee states that subsequent references to conformance with RG 1.45 were based on.
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referrals to the original SER statement without validation of its accuracy. The design basis reconstitution of Brunswick safety-related systems requires a review of the SER and other regulatory documents to
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capture commitments and requires a validation of the commitments subsequent to the reconstitution. The Radiation Monitoring Design Basis t
Document had not been completed prior to the identification of this issue. As part of the correttive actions, the licensee states that the
reconstitution effort will be used to identify any additional deviations
and will implement ACRs for corrective action.
l As part of the licensee's corrective action, the licensee elected to
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modify the system to meet the seismic qualification requirements..The.
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Unit 1 CAC-1260 and 1262 monitors have been modified to seismically.
qualify the monitors and associated piping by PM 93-013. The CAC-1260 and 1262 monitors are each located on the 20 foot elevation. The CAC-1261 monitor is located on the 50 foot elevation, making it more
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difficult to seismically modify.
Completion of the seismic qualification of the CAC-1260 and CAC-1262 monitors meets the requirements of TS 3.3.5.3 (Accident Monitoring Equipment).therefore the licensee elected not to modify the CAC-1261 monitor and removed it from
the list of equipment used to meet TS 3.4.3 (Leakage Detection Systems).
The inspector reviewed the modifications to the system to meet the i
seismic requirements and discussed the changes with the system engineer.
l The inspector reviewed the required modifications and support
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documentation and found it to be satisfactory.
Based.on this review,
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the Unit 1 CAC-1260 and 1262 monitors seismic modifications meet the
requirements of RG 1.45 and are acceptable for Unit 1 startup. This LER
is closed.
(Closed) LER l-91-003, Fail As-Is Position of CBEAF System Inlet and Outlet Dampers Not Evaluated With Respect to a Chlorine Event, and
LER l-92-018 (Supplement 1), Loss of Power to the Control Logic for the
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Preferred CBEAF System Would Prevent It or the Standby From Automatically Starting Upon Radiation or Smoke Detection.These two LERs
are addressed together since they are inter-related.
In 1990, while dispositioning open items which were identified in a contractor supplied commitment verification of the UFSAR, the licensee identified several deficiencies. One of these related to how the automatic isolation initiation of the Control Building Intake dampers met-single active failure criteria.
Section A.2.1 of the Control Room Habitability
Evaluation (NUS-3697, Revision 0, 1983) stated that damper 2L-D-CB did
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not meet the single failure criteria, but failed in the safe position.
The system engineer reviewed the control room ventilation ystem for
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applicability of the single failure criterion. On May 11, 1990, a field response test (WR/JO 90-AIQY1) was performed which verified that the
CBEAF inlet damper (2L-D-CB) failed as-is instead of to the safe
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position on the loss of power to the damper's solenoid valve. LER l-90-007 informed the NRC of this item. The corrective actions for this c
event were to implement Plant Modification 90-036 which ~made the damper i
fail safe on loss of power to the damper's solenoid valve..The
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corrective actions also directed NED to perform a validation of the as-
designed system to the as-designed basis (0VA-0010).
It also directed
NED to determine the correct failure position of safety-related dampers
and compare the as-designed configuration to the correct failure
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position.
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On January 23, 1991, the Control Building HVAC System Engineer identified three potential design problems with the habitability
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protection system. These issues were sent to NED for evaluation and
comparison to the system design basis. NED's evaluation, as a part. of i
the Design Basis Reconstitution (DBR) effort, resolved the three r
potential problems; however, during the research two new issues were-
.i identified. On January 31, 1991, NED identified a third issue as part
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of the DBR and implementation of the corrective action for LER 1-90-007.
The identified items are:
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Inlet and outlet dampers (2-VA-2A,B,C,D-EAD-CB) for the CBEAF
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trains fail as-is on loss of power.
If either CBEAF train is in operation and a power failure occurs.with a simultaneous chlorine event, the dampers will not close causing the operating dampers to remain open providing an air flow path to-the control room. The differential pressure between the two air plenums will provide the motive force for chlorine entrance to the control room.
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e The failure of a single relay (2-VA-3-50A) would prevent automatic initiation of the radiation isolation mode of the CBEAF system.
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All equipment required to start and isolate the CBEAF is controlled by this relay.
Either a loss of power or the failure to actuate when given a valid signal would prevent any control room isolation or CBEAF train start from occurring.
The emergency recirculation damper which is used to recirculate i
e control room air through the CBEAF is not redundant. The damper
is normally closed except during a fire or radiation event and failure during these operational modes simultaneous with a
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chlorine event would allow chlorine to be recirculated.
The first of the above items was documented in ACR 91-055 and reported
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to the NRC by LER l-91-003.
EER 91-005 was written to evaluate this
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condition. A design change replaced the dual four way solenoid valve
with a single four way solenoid valve. This makes the damper fail
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closed on a loss of power.
The failure of the single relay issues was corrected by adding a second relay (2-VA-3-75A) which changed the logic so that both relays are in parallel.
This eliminated the single failure condition. Both of the corrective actions were implemented by PM 91-055.
The lack of a redundant recirculation damper had been identified in 1983 I
I and was accepted by the NRC (Safety Evaluation, dated October 18,1983)
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as part of the licensee's response (Control Room Habitability i
Evaluation, NUS-3697, Revision 2) to NUREG-0737, III.D.3.4.
The failure l
of this damper to close in a chlorine event was evaluated by the licensee as acceptable since there was no differential pressure across the damper when in the chlorine isolation mode.
The licensee determined that a more severe condition had previously been evaluated and found that the lack of redundant dampers was acceptable.
In 1992, the system engineer, while reviewing an operating experience report on problems with the preferred / standby logic for SBGT, decided that this item could be applicable to the CBEAF and he expanded the review to include that system. He identified that the loss of 2A CBEAF
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control logic power would prevent automatic or manual starting of both CBEAF trains upon a smoke or radiation detection initiation signal and that the loss of 2B CBEAF control logic when the 2B control switch is in the " preferred" position would prevent automatic starting of either train upon a smoke or radiation detection signal.
LER l-92-18 was issued to notify the NRC. However, manual start of the 2A CBEAF train i
was possible. A single failure in the chlorine detection system / logic i
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prevents both CBEAF trains from starting automatically.
The corrective
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actions were to replace the loss of power relays in the chlorine
detection system and perform a desige review of the CBEAF to determine
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the design basis for the system and to verify that it would perform its
intended safety and protection functions under single failure analysis.
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The review, which was performed by a contractor, revealed another single
failure condition. A failure of the smoke and radiation (42) relay in one CBEAF train would prevent that train from starting and the redundant j
train would also not receive a start signal. While reviewing CBEAF
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logic in September 1993, the STA discovered another single failure which j
would result in the CBEAF train continuing to run after a chlorine or
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manual shutdown signal. The licensee implemented a design change to
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bypass the blocking relay for each CBEAF train and prevent the failure
of the chlorine or manual shutdown relays from bypassing a stop command.
This work was completed by Field Revision 16 to PM 92-108.
l The inspector reviewed the above ACRs, EERs, PM packages, and the control room habitability evaluation design criteria (NUS-3697 Rev. 2)
and found them to be adequate. The completion of the licensee's
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corrective action closes both LERs.
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The inspector con iders the inadequacy of the original review and the
length of time to identify all the single failure issues with the CBEAF
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system to be a weakness.
Recent changes in the engineering i
organ % tions have signaled new and more thorough approaches to
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resol 4ing problems such as this.
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9.
Exit Interview (30703)
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l The inspection scope and findings were summarized on October 8 with those persons indicated in paragraph 1.
The inspectors described the j
areas inspected and discussed in detail the inspection findings in the i
summary and listed below. Dissenting comments were not received from i
the licensee.
Proprietary information is not contained in this report.
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Item Number Descriotion/ Reference Paraaraph
e 325,324/93-41-01 Violation for Inadequate Storage of Safety-Related
Equipment, paragraph 2.
- 3 325,324/93-41-02 Violation of Technical Specification 6.8.1.a for Failure to Establish and Implement Procedures (two l
examples), paragraph 4.
10.
Acronyms and Initialisms AC Alternating Current ACR Adverse Condition Report ADS Automated Depressurization System ALARA As Low As Reasonably Achievable A0 Auxiliary Operator API Authorized Personnel Inventory
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.o O
ASME American Society of. Mechanical Engineers BSEP Brunswick Steam Electric Plant
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BWR Boiling Water Reactor CAC Containment Atmospheric Control CBEAF Control Building Emergency Air Filters
CO Control Operator
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CP&L Carolina Power & Light Company CRD Control Rod Drive
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CW Cooling Water DBR Design Basis Reconstitution DC Direct Current-DFCS Digital Feedwater Control System DG Diesel Generator DP Differential Pressure'.
DR Direct Replacement E&RC Environmental and Radiation Control EDBS Engineering Data Base System EER Engineering Evaluation Report
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