IR 05000324/1993001
| ML20034G131 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 02/26/1993 |
| From: | Christensen H, Prevatte R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20034G123 | List: |
| References | |
| 50-324-93-01, 50-324-93-1, 50-325-93-01, 50-325-93-1, NUDOCS 9303090105 | |
| Download: ML20034G131 (21) | |
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UNITED STATES j..
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NUCLEAR REGULATORY COMMisslON f
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REGION 88
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g 101 MARIETTA $TREET, N.W.
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f ATLANTA GEORGIA 30323 o,
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Report Nos.: 50-325/93-01 and 50-324/93-01 Licensee:
Carolina Power and Light Company i
P. O. Box 1551
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Raleigh, NC 27602 i
Docket Nos.: 50-325 and 50-324 License Nos : DPR-71 and DPR-62 Facility Name: Brunswick 1 and 2 i
Inspection Conducted: January 1 - February 5, 1993 I
i Lead Inspector: i$[as f[ be
<&l2 /] 2>
R.~ L'.
Prevatte, Senio Esideptinspector Dite igned Other Inspectors:
D. J. Nelson, Resident Inspector P. M. Byron, Resident Inspector R.
Carroll, Project Engineer d(-[9.3 Approved By:
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AAtd La H. O. Christensen, Chief
Date Sfgned Reactor Projects Section lA Division of Reactor Projects SUMMARY
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l Scope:
This routine safety inspection by the resident inspectors involved the areas of i
maintenance observation, surveillance observation, operational safety verification,
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engineered safety feature system walkdown, outage work activities, plant specific startup issues, onsite followup of events, onsite review committee, review of licensee event reports, action on previous inspection findings, and information meeting with local officials.
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r Results:
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In the areas inspected, no new programmatic weaknesses, significant safety matters,
violations or deviations were identified. A strength was identified in the area of
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ongoing maintenance activities on the diesel generators, paragraph 6.
A weakness was identified in the area of housekeeping, paragraph 4.
Continuing programmatic
weaknesses exist in the licensee's temporary modification program,
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9303090105 930226 PDR ADOCK 05000324 G
PDR l
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a paragraph 5.
A significant operator work-around was identified regarding design deficiencies with the residual heat removal service water booster pumps, paragraph 7.
i Both units remained in cold shutdown for the entire' reporting period.
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l REPORT DETAILS i
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1.
Pe sons Contacted
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Licensee Employees l
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K. Ahern, Manager - Operations Unit 2 l
R. Anderson,- Vice-President - Brunswick Nuclear Project l
G. Barnes, Operations Manager - Unit 2 I
- M. Bradley, Manager - Brunswick Assessment Project
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M. Brown - Interim Plant Manager, Unit 2 l
- S. Callis - Onsite Licensing Engineer
- R. Godley, Supervisor - Regulatory Compliance
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- M. Jackson, Manager - Maintenance, Unit 2 i
M. Jones, Manager - Training i
J. Leininger, Manager - Nuclear Engineering Department (0nsite)
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P. Leslie, Manager - Security
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- G. Miller, Manager - Technical Support j
- D. Moore, Manager - Maintenance, Unit 1
- R. Morgan - Interim Plant Manager, Unit 1 l
- C. Robertson, Manager - Environmental & Radiological Control
J. Simon, Operations Manager - Unit 1
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J. Titrington, Manager - Operations, Unit 1 j
G. Warriner, Manager - Control and Administration
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E. Willett, Manager - Outage Management & Modifications (OM&M)
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t Other licensee employees contacted included construction craftsmen, engineers, technicians, operators, office personnel and security force members.
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- Attended the exit interview.
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Acronyms and initialisms used in the report are listed in the last paragraph.
l 2.
Maintenance Observation (62703)
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The inspectors observed maintenance activities, interviewed personnel, and l
reviewed records to verify that work was conducted in accordance with approved-l procedures, Technical Specifications, and applicable industry codes and
standards.
The inspectors also verified that: redundant components'were i
operable; administrative controls were followed; tagouts were adequate; j
personnel were qualified; correct replacements parts were used; radiological
controls were proper; fire protection was adequate; quality control hold j
points were adequate and observed; adequate post-maintenance testing was
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performed; and independent verification requirements were implemented. The
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inspectors independently verified that selected equipment was properly
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returned to service.
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I Outstanding work requests were reviewed to ensure that the licensee gave
priority to safety-related maintenance. The inspectors observed / reviewed portions of the fcilowing maintenance activities.
I OPM-ENG-504 Emergency diesel generator flex drive dowel pin l
inspection - backlash adjustment t
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92-BDZB1 Replace zinc anode - DG No. 3
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92-BFRAI Inspect No. 9 bearing - DG No. 3
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92-ASSZ1 Flex drive-inspection.- DG No. 3
.i 92-BAYQ1 SBGT 2A relay replacement
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92-BAXB1 Troubleshooting Unit 2 APRM channel C neutron detector i
for high resistance j
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93-ADAll Doweling generator stator on DG No. 3 92-ASSZ1 Flex drive piping installation and inspection on DG i
No. 3 l
92-ASSZ3 Rebuild engine driven jacket water pump on DG No. 3
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PM 91-064 Unit I refueling bridge upgrades Strengths were identified in DG work activities as noted in paragraph 6.
No weaknesses were identified in the remaining activities.
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j Violations or deviations were not identified.
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3.
Surveillance Observation (61726)
j The inspectors observed the surveillance testing required by Technical l
Specifications. Through observation, interviews and record review, the i
inspectors verified that:
tests conformed to Technical Specification l
requirements; administrative controls were followed; personnel were qualified; i
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instrumentation was calibrated; and data was accurate and complete. The
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inspectors independently verified selected test results and proper return to
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service of equipment.
l The inspectors witnessed / reviewed portions of the following test activities:
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OPT 12.14L DG No. 4 local control operability test
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PM 91-051 Revised Unit 2 CAC V-5 and V-6 Logic - PMTR 93-ACEZ1 Unit 2 main steam line C high flow differential l
pressure
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93-ACEY1 Unit 2 main steam line B high flow transmitter
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i calibration Procedural requirements were followed during the above testing.
Personnel were knowledgeable on the aspects, requirements and acceptance criteria for the above tests.
Violations and deviations were not identified.
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4.
Operational Safety Verification (71707)
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The inspectors verified that Unit 1 and Unit 2 were operated in compliance l
with Technical Specifications and other regulatory requirements by direct observations of activities, facility tours, discussions with personnel, reviewing of records and independent verification of safety system status.
l The inspectors verified that control room manning requirements of 10 CFR 50.54
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and the Technical Specifications were met.
Control operator, shift supervisor, clearance, STA, daily and standing instructions and jumper / bypass logs were reviewed to obtain information'concerning operating trends and out
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of service safety systems to ensure that there were no conflicts with
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Technical Specification Limiting Conditions for Operations. Direct j
observations of control room panels, instrumentation and recorder traces important to safety were conducted to verify operability and that operating i
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parameters were within Technical Specification limits. The inspectors
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observed shift turnovers to verify that system status continuity was j
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maintained.
The inspectors also verified the status of selected control room
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j Operability of the ESF system used for shutdown cooling was verified weekly by i
ensuring that:
each accessible valve in the flow path was in its correct i
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l position; each power supply breaker was closed for components that must l
l activate upon an initiation signal; there was no significant leakage exhibited
by major components; proper lubrication and cooling water was available; and
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conditions which could prevent fulfillment of the system's functional
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requirements did not exist.
Instrumentation essential to system operation or i
actuation was verified operable by observing on-scale indication and proper j
instrument valve lineup.
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The inspectors verified that the licensee's HP policies and procedures were
followed. This included observation of HP practices and a review of area i
surveys, radiation work permits, postings and instrument calibration.
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The inspectors verified by general observations that: the security l
i organization was properly manned and security personnel were capable of j
i performing their assigned functions; persons and packages were checked prior i
to entry into the PA; vehicles were properly authorized, searched and escorted
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within the PA; persons within the PA displayed photo identification badges;
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personnel in vital areas were authorized; effective compensatory measures were i
employed when required; and security's response to threats or alarms was l
adequate.
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The inspectors also observed plant housekeeping controls, verified position of l
certain containment isolation valves, checked clearances and verified the
operability of onsite and offsite emergency power sources.
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Housekeepina l
During a routine plant tour on January 13, the inspector observed tools,
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various equipment, replaced material, used tape and discarded tie wraps on the l
l floor in the SW Intake Structure. There were no work activities in progress
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and the above items appeared to have been discarded after the completion of
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maintenance activities in this area. On the same day he observed two cans of
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WD-40, two coils of rope, and discarded tape and tie wraps around the base of
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the 2A Reactor feed Pump. The licensee was informed of the above conditions, which were subsequently corrected.
On January 27, the inspector, a regional l
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structural inspector, and the Unit 2 Plant Manager toured the Unit 2 drywell.
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The lower elevation of the drywell was heavily cluttered with discarded tools, i
weld rods, scrap material, ropes, nuts, bolts and washers, welding and j
grinding face shields, and discarded work and inspection paperwork. Tool s,
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flashlights and other miscellaneous components, as well as structural
inspection forms were found on other elevations. There was evidence of j
workers walking and climbing on rigid and flexible ventilation ducting, as
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well as other disregard for equipment adjacent to these work locations.
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Several areas that needed cleaning, preservation and reapplication of
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protective coatings were also identified.
Some of these were for attachments
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l on the drywell liner plate. The inspector also noted that very little cleanup l
or pickup of tools and parts had been done after the completion of work i
activities.
The inspector considered that the majority of the above
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deficiencies resulted from maintenance and modification work, as well as from i
the inspection and repair of miscellaneous structural steel. After
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e discussions with plant management about the need for improved housekeeping, i
the licensee directed that the last hour of each work shift be used for the
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cleanup of work activities and areas.
An additional tour of the Unit 2
drywell by the Resident Inspector and Deputy Director of Reactor Projects for i
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Region II on the following week noted that some of these deficiencies had still not been fully corrected. Management again emphasized that a thorough
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cleanup would be conducted.
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j The inspector informed plant management that he would continue to monitor this l
item and will perform a detailed walkdown of each drywell prior to final
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closeout.
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i DG Service Water Cooling l
l During the 24-hour endurance run of DG No. 1, the inspector observed that the alternate service water supply valve from Unit 2 (2-SW-V210) was open and
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supplying service water cooling loads to the engine instead of the normal
i supply valve from Unit 1, (1-SW-V210).
Each diesel has two service water
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Water header and DGs 3 and 4 normally supplied from the Unit 2 Nuclear Service
Water header. The opposite unit Nuclear Service Water header is the alternate
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j supply source.
In the event that the normal source is unable to supply
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service water to an engine, its two valves automatically reposition to the
i alternate configuration. This condition is sensed by a pressure switch on the
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service water line just upstream of the jacket water cooler.
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At the time of the inspector's observation, DG No. I had been running for i
approximately thirteen hours. The auxiliary operator monitoring the engine operation was not aware of the alternate configuration. This could have been
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detected by the local valve position indicators (the valves are located in the j
DG cell), remote position indicating lights on the MCC adjacent to the local control panel, and by the cool feel of the supply piping adjacent to the
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Unit 2 valve. The endurance run was completed with the service water alternate configuration, with no adverse effects.
j Subsequent to the endurance run, the valves' controlling pressure switch j
(2-SW-PS-1999) was determined to have contacts stuck closed, which falsely sensed a low service water pressure.
Indicative of a failure of the Unit 1 i
supply source, this caused the alternate (Unit 2) valve to open. Upon j
opening, an interlock between the two valves caused the Unit 1 valve to shut.
j Since the contacts weie stuck shut, this condition likely existed at the start of the endurance run and for an indeterminant time since the last pressure switch calibration check on June 8, 1992.
DG No. I was in a maintenance i
outage from September through December 1992.
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The inspector concluded that ample opportunity existed for operators to detect the alternate service water valve lineup. Even though no violation occurred,
this represents an example of a configuration / system status error that
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warrants management attention. 0perators routinely identify miscellaneous i
deficiencies during engine runs, as was the case during the this endurance run.
Specifically, ten other WR/J0s were generated for various deficiencies.
PT 12.4(A-D), DG Fuel Oil and Service Water Test, has provisions for testing
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j the automatic switch to the alternate service water source. This is conducted quarterly by actuating a relay in the control circuit, simulating engine
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starting conditions. A portion of the test duplicates a failed normal SW
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supply causing the valves to reposition. This test was performed prior to returning DG No. 1 back to service on January 1, 1993.
As written, the test
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i would not necessarily have identified the faulty pressure switch if the condition had then existed.
The inspector identified a, potential procedure
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i enhancement opportunity in that if the designed-in 25 second time delay for i
the normal supply valve to pressurize the system was challenged, then the
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actual failure could have been identified. The licensee is considering this
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issue.
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l On January 13,1993, an OG-8 (Mechanical Jumper) temporary modification
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installed on the Unit 2 CRD system was unintentionally disabled by maintenance
personnel. This temporary modification consisted of a hose connection between i
the demineralized water system and the CRD system to provide CRD makeup flow
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while CRD maintenance was underway.
Continuous CRD flow is desired to i
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maintain control rod drive mechanism flushing. A flow rate of approximately i
l 30 gpm is maintained, as the flow ultimately enters the reactor vessel. At i
the time of the event, reactor vessel level was being maintained constant by
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RWCU reject to balance the CRD addition. Maintenance workers inadvertently
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shut the demineralized water supply valve to the CRD hose.
This valve wa<.
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j mistakingly shut instead of an adjacent, identical service air salve supplying i
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service air in support of drywell maintenance activities.
The desineralized i
water supply valve had been only slightly open.
Reconstruction of the event
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by the licensee concluded that the valve may have only been bumped or snagged
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by workers' anti-contamination clothing.
Control room operators observed the
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very slow level decrease that resulted from the interruption of reactor water
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addition with continuing FWCU rejection, lhe operators quickly diagnosed the
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problem and the level decrease was stopped.
ERFIS data indicated that the
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level decreased from 212 to 206 inches over approximately twenty minutes. The desired control band was 200 to 220 inches.
The inspector concluded that the
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operators' recognition of the small level decrease within twenty minutes was indicative of alert watch standing.
In this event the operators were prepared
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to secure RWCU reject which would have stopped the decrease if the CRD
addition could not be quickly restored.
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i In July 1992, the demineralized water supply to a temporary modification for RHR SW booster pumps was inappropriately secured by an unrelated clearance.
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Inspection Report 325,324/92-21 documented that occurrence.
Effective steps j
have not been taken to enhance the preservation of temporary modifications e
after installation.
Following the January 13, 1993 event, the licensee j
placed a caution tag on the demineralized water supply valve to indicate its j
function with the temporary modification. The January 13 event demonstrates
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the continuing programmatic weaknesses of the licensee's temporary modifica-l
tion process which has been discussed.in previous reports, beginning with Inspection Report 325,324/92-04. Additionally, this represents another I
exarf.t of a configuration / system status error. The licensee intends to complete all necessary improvements to the temporary modification process prior to Unit 2 startup.
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Violations or deviations were not identified.
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ESF Walkdowns (71710)
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On February 1, 1993, the inspector observed a reactor operator perform the pre-startup electrical and valve lineup for Division I of the Unit 2 core j
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spray system in accordance with operating procedure 2-0P-18, Core Spray System
Operating Procedure. The lineup did not include valves in the drywell.
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l operator was able to verify or position all but four valves which were within
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a clearance boundary. The operator was not able to manipulate Penetration
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X61-B Manual Isolation Valve B21-V43 and Test Valve B21-V117 for Excess Flow l
Check Valve E21-F054, because of construction activities in the area.
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j inspector observed that the operator used the current procedure.
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of the procedures were utilized and left within contaminated area boundaries
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after transposing the data. The operator was thorough and verified that he
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was checking the correct equipment and equipment status or position.
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The operators access to valves was hindered.
The inspector observed the
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operator climbing on pipes, pipe supports and instrument racks to reach many
j valve locations. This appears to be an area that needs additional management
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and supervisory standards / attention.
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DrYWell/ Torus Vacuum Breakers
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The inspector walked down accessible portions of the drywell to torus vacuum
breakers including the pneumatic actuator air / nitrogen system.
No deficiencies were identified.
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j The inspector observed the existence of Parker /Hannafin compression tube fittings in the lines. This was unexpected, since the vacuum breaker i
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pneumatic system was not identified during the licensee's attempt to locate
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via EDBS review, all plant installations utilizing Parker /Hannafin fittings
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(see Inspection Report 325,324/92-44).
Based on the inspector's observation, the licensee identified an error in their EDBS query and were subsequently able to identify additional installations needing field verification.
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The inspector checked the adjustment collar on each vacuum breaker actuator for tightness.
All were tight and secured by a set screw. A forced unit
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outage occurred several years ago due to a loose adjustment collar which
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required to resolve the problem.
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Violations or deviations were not identified.
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Outage Work Activities (62703)(37828)
l The DG No. 4 outage commenced on January 1, 1993. The licensee removed four cylinder heads, liners and pistons.
The cylinder liners were Magnafluxed.
Three of the four liners had indications on the outside surface.near the i'
i seating ring. The inspector also inspected the indications.
Subsequent investigation by a licensee Level III NDE Specialist and destructive i;.
examination determined that the indications were not cracks, but casting
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blemishes.
The inspector observed the inspection of the outside surface of the No. I main bearing cap. A visual inspection was performed and surface l
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l imperfections were observed. The licensee lightly tapped the bearing cap face l
with a hammer and a piece of metal approximately 1/2 inch in diameter flaked i
off during this inspection. The affected area was determined by the licensee j
to have been from previous weld repairs during fabrication. The surface
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defect was polished out and examined with no additional indications found. On l
January 19, the inspector observed the performance of the local control i
operability test (0PT-12.14L) and the final maintenance test runs which were
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completed satisfactory.
DG No. 4 was returned to service on January 19.
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DG No. 3 was placed under clearance on January 21, 1993. The inspector
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observed the inspection of the No. 9 main bearing, adjustment of the flex
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drive gear WHash and replacement of the turbocharger intercooler's zinc anode. A mechanic found that one of the sensor lines to the intercooler cover had an unusual configuration and noted that one of the bosses in the cast
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cover was broken. The defective cover was replaced and the correct tubing
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fitting configuration was reinstalled.
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This effort was well coordinated and well supported by technical support,
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planning, QC and maintenance. The inspector observed that procedures were.in place and conscientiously used. The maintenance team appears motivated, j
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exhibiting a high work quality. The improvement in work quality on this project is now considered a strength, serving as a good example and standard
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for other maintenance crews.
7.
Plant Specific Startup Issues (Note: CAL Items are addressed in Enclosure 3 of CP&L's letter dated July 23,
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1992.)
CAL Item B8. Reactor Feed Pumo Wear Rina Fasteners The 2B RFP was disassembled to inspect for the condition that caused the 2A RFP to seize following a scram in early 1992. The cause was an incorrect
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capscrew material used to secure the wear rings.
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The 2B pump was found to be in the same condition as the 2A pump with regard i
to the wear rings' capscrews.
Each of the two wear rings are secured by three capscrews. On the 2B pump, one wear ring had all three capscrews' heads missing and the other wear ring had only one intact capscrew. The material was the same as that of the 2A pump capscrews, a medium carbon steel. This condition indicates that a similar failure of the 2B RFP was likely.
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J licensee corrected this and other deficiencies under WR/JO 92-AEKul. The replaced capscrews are of the required A193 Grade B6 material (a wrought
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martensitic stainless steel.) The Unit 1 pumps were inspected and no failed
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capscrews were identified although the material was of a different series
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stainless steel than required. Capscrews of the correct specified material were reinstalled.
This item has been completed satisfactorily for Unit 2 restart.
CAL Items D4 and DS, Reduction in Corrective and Preventive Maintenance
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Backlogs The inspector attended a portion of the Backlog Review Committee (BRC) and PNSC meetings conducted during the month of January when system engineers made
presentations on the readiness for restart of their assigned systems. The BRC
meetings covered the following systems:
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e Units I and 2 Core Spray System Units 1 and 2 Reactor Recirculation System e
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Units 1 and 2 Service Water System e
Service Water Intake Structure o
Units 1 and 2 Condensers t
Unit 2 Turbine Building Closed Cooling Water a
Units 1 and 2 RCIC System o
Unit 2 RHR System
Units I and 2 ADS System Units 1 and 2 Seismic Monitoring System o
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e Units 1 and 2 Neutron Monitoring System e
Unit 1 HPCI System
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In addition to the above, PNSC meetings were attended for the following system
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reviews:
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Units 1 and 2 Emergency Diesel Generator
Units 1 and 2 Recirculation MG Sets
Units 1 and 2 Recirculation System
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Units I and 2 24V DC Battery Charger e
Units 1 and 2 24V DC Distribution System
e Units 1 and 2 48V DC Distribution System
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Units 1 and 2 208/120V AC Distribution System
Units 1 and 2 Uninterruptable AC System e
Units 1 and 2 Communication System e
Units 1 and 2 Commercial Phones
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e Units 1 and 2 FCC Licensed Base Stations
Units I and 2 Licensed Portable Radio e
Units 1 and 2 Microwave
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e Units 1 and 2 Caswell Beach Supervisory and Control System i
e Units 1 and 2 Core Spray System
Units 1 and 2 Condensers
Units 1 and 2 Plant Computer
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e Units 1 and 2 CAC System
Units 1 and 2 Turbine Building
Units 1 and 2 Control Buildings
Units 1 and 2 Service Water Buildings
Units 1 and 2 Service Air System o
Diesel Generator Building e
Unit 2 SBGT System e
Unit 2 Generator / exciter System o
Unit 2 Feedwater System e
Unit 2 Reactor Building HVAC System The inspector noted that the procedural requirements specified in PN-30 were being followed by the System Engineer, the BRC and PNSC members.
The inspector noted that deficiencies with safety significance which could impact
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on safe operation of systems, structures or components of safety and non-safety systems were being scheduled to work prior to startup. Many work items
that fell into the need versus required category were also being scheduled for
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work prior to startup. The majority of deferred exceptions were items that required the plant to be in Mode 5, parts were not available, engineering design work could not be completed prior to startup or the item could safely be worked later while the unit was on line. Throughout this review the
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inspector did not identify any major safety significant items that were being deferred that, in his professional opinion, could have a serious impact on safe plant operation. However, it is apparent that a significant amount of the work is being rescheduled due to the inability of engineering and i
planning / scheduling to provide work packages to plant maintenance and OM&M craft personnel.
The window of opportunity to correct plant deficiencies still continues to be less than fully effectively utilized. The inspector
will continue to follow this item and evaluate the adequacy of maintenance
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backlog.
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l CAL Item El. Hot Side Walkdown Inspection For Unit 2, the licensee has completed material condition walkdown inspections
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in accordance with Special Procedure OSP-92-767, Material Condition Walkdowns, Rev. 3.
Spaces included for these inspections, with the number of t
deficiencies identified for each are as follows:
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Control Room 49 foot elevation 1209 2A and 2B RWCU pump rooms
2A and 2B Feed pump rooms 269 2A and 2B Feedwater heater rooms 151 2A and 2B SJAE Rooms 114 Penetration Room
20 Foot Floor Elevation Mini Steam Tunnel
TIP Room
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Main Steam Line Tunnel
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Heater Drain Pump Room
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50 Foot Elevation MSIV Pit
77 Foot Elevation Pump and Valve Room 204
Torus
20 and 45 Foot Elevation Condenser 1290 l
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RWCU Heat Exchanger Roam
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Condensate Booster Pumps Room 121 20 Foot Elevation Condensate Pit 267 East and West 70 Foot Elevation MSR 161 Drywell 189
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Spent Fuel Pool Heat Exchanger Room
TOTAL 4280
Of these, none were obvious inoperabilities.
However, as of February 1, 1993, 30 were indeterminate, requiring engineering review to determine operability.
In addition, there were 859 Engineering Work Requests (EWRs) initiated to
request analysis or repair information.
Most of these areas were originally included in the " Hot Side" walkdowns, but the OSP-92-767 walkdowns were intended to be more detailed and include a wider
,
!
scope than civil / structural related issues.
Consequently, many more
'
deficiencies were identified.
The inspector observed the " management review" portion of the Unit 2 Torus
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material condition walkdown. The first OSP-92-767 walkdown identified no
deficiencies for this space. The second walkdown confirmed that no major deficiencies existed, although some minor problems were identified.
The inspector considered the walkdown to be thorough. Additional discussion of this item is included in Inspection Report 325,324/93-02.
CAL Item B5 Unit 2 Partial Arc Modifications CAL ltem B6, Unit 2 CV and EHC Accumulator Refurbishment
!
These items were identified due to problems that occurred in the EHC system
and CVs after the Unit 2 turbine was modified to permit partial Arc admission
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operation during the 1991-1992 refueling outage.
As the result of wrong
,
curves for CV operation being provided by the vendor, this modification did not work as planned. After startup, the turbine controls were unstable above 80 percent power. This instability resulted in almost continuous small I
oscillations in the EHC system and CVs.
This caused excessive wear on the
seals in the EHC accumulators.
Diagnostic testing and analysis by the r
licensee and vendor prior to and after shutdown were able to determine the cause of these problems.
After unit shutdown in April, extensive rework was completed on the CVs, BPVs, CIVs and the EHC mechanical and electrical systems. This work included but was not limited to the following items:
j Hydraulic Power Unit
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Installed new Fullers earth filters j
e Installed new 1/2 micron filter
i e
Added new vent lines to oil reservoir
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1
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- Replaced EPT-6 pressure switch e
Rebuilt one and replaced one accumulator on hydraulic power unit e
Replaced hydraulic pump compensators e
Cleaned all strainers e
Drained and cleaned hydraulic power unit reservoir Calibrated FCV on hydraulic power unit and replaced relief valves e
Control Valves, Bypass Valves, Combined Interceptor Valves and Front Standard i
e Overhaul.'d CV actuators e
Added 4 CV accumulators per vendor recommended modifications e
Inspected and rebuilt No. 4 CV
o Checked and adjusted CV stroke settings
e Rebuilt CV accumulators
'
Installed 17 new Servo valves on CVs, SVs and BPVs e
Reworked or replaced EHC system stop valves
,
e Installed new orifices for CVs, SVs and CIVs to reduce effects of hydraulic system surges
Replaced solenoid valve on No. 3 BPV e
Replaced and calibrated the reactor protection system switches on the EHC system e
Changed out "0" rings to Viton type per SIL 456 e
Replaced and adjusted primary and secondary master trip valves and
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cables on the front standard e
Replaced damaged and deteriorated wiring on CVs and CIVs
,
e Installed and adjusted new relay trip valves on front standard Repaired drain collection tank leaks on front standard e
Electric / Electronic System Controls
Replaced cables to eccentricity probe Isolated grounds between turbine supervisory instruments and EHC cabinet
e Installed optical isolators for test points e
Removed 1KHZ oscillations and upgraded 3KHZ oscillators e
Installed second steam resonance compensator Upgraded EHC electronic cards e
e Performed electronic lineup verification on EHC control cabinet e
Vendor checkout and adjustments of EHC electronic system
Installed partial arc 3 admission curves
e e
Performed scheduled maintenance on system The inspector reviewed the above completed work activities with the system
,
engineers and assigned project manager. A walkdown on selected portions of the system with the above individuals was accomplished on January 21, 1993.
The inspector observed EHC system alignment and startup on the above date. An EHC leak on No. 5 BPV aborted further system venting and checkout.
The inspector had previously, during the outage, observed selected work activities
,
on this system during routine plant inspection activities.
He additionally attended various vendor and plant meetings involving system upgrades, rework
]
and modifications.
Based on the above, the inspector concluded that
'
significant improvement and upgrades have been accomplished on the EHC system CVs, CIVs, BPVs and SVs during the current outage. These improvements should
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result in an increase in system operating reliability. The inspector will continue to follow the remaining work and testing activities that remain as a
part of the routine inspection program and special monitoring activities that are planned for unit restart. Since the majority of work in the EHC and turbine control system is completid, Item B-6 is considered satisfactory for Unit 2 restart.
The inspectors will continue to follow item B-5 as the unit is restarted and steam is available to perform the required turbine testing.
CAL Item F2, Unit 2 Repair of Neutron Monitorino Detectors This item was identified as a result of past failures in various components of the system.
These failures involved detector problems, various power supply failures, problems in signal cables and electric / electronic spiking problems.
The inspector reviewed all WR/J0s that have been completed since the units were shutdown in April 1992 and those WR/J0s that are scheduled to be completed prior to restart. These items were also reviewed with the system engineer to gain an understanding of system readiness for plant restart.
To date, 71 WR/J0s have been completed on Unit I and 55 WR/J0s have been completed on Unit 2.
The majority of these items were for corrective maintenance identified during system operation or surveillance testing. The repairs range from replacement of missing screws to signal cable replacement, amplifier replacement, power supply repairs and repairs to drive motors.
A significant amount of the work was done in an attempt to alleviate signal spiking. The source and intermediate range noise spike problem has been determined to be caused by low level noise introduced into the SRM/IRM cabling between the pre-amp cabinets and the drywell penetration. After comprehensive testing, a project to resolve this problem has been identified and is contained in the licensee's three year business plan under PID07250A. This project is presently scheduled for completion in 1996 on Unit 1 and 1997 on Unit 2.
The inspector reviewed the current backlog of scheduled and deferred work contained in the Integrated Backlog Item Report (IBIR) for Unit 2 and attended the BRC meeting on this system on January 28, 1993. These items have been reviewed and categorized under Plant Notice, Integrated Recovery Methodology PN-30, Revision 1.
A large portion of the remaining work involves performance of MSTs and alignment checks and adjustments that will be accomplished prior to or during plant startup and other minor corrective maintenance. An emergent item has been identified involving repairs to conduit support in the vicinity of SRM/IRM/LPRM conduits. This work is scheduled to be completed under Plant Modification 91-041 in February. A review of the work items that have been deferred until after startup did not identify any item that the inspector feels may have an adverse effect on safe system operation.
If additional items emerge that must be added to or deleted from the IBIR these items will be addressed under the PN-30 process. The inspector's attendance at backlog review meetings, PNSC meetings, interviews with system engineers and independent review of the PN-30 process has concluded that this process is effective and should result in all significant safety discrepancies being corrected on the neutron monitoring system prior to Unit 2 restart.
The inspector will additionally monitor the IBIR on this system to ensure that the
A
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I l
remaining critical work is accomplished prior to Unit 2 restart.
Based on the
above, this item is considered satisfactory for Unit 2 restart.
l Plant Modification 92-092, Unit 2 RHR SW Booster Pumps Upgrade i
The RHR SW Rooster Pumps are essential for post accident' containment control l
and for shudown cooling capability. The four pumps in each unit are arranged l
with two p mps per RHR SW train in parallel. Historically, these pumps have l
been plagued by numerous problems, including:
short service life following i
overhaul; elevated vibration levels; short mechanical seal and bearing life; j
and pump-to-motor alignment problems. These problems resulted in high -
!
maintenance demands which was exacerbated by parts procurement problems due to i
the Brunswick " custom" pump design.
Following the shutdown in April 1992, both units' pumps incurred extended
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running times due to the continuous shutdown cooling requirements associated j
with not de-fueling the reactors. During this period the existing problems l
worsened and major pump maintenance was necessitated. High vibration levels l
could not be corrected due to repetitive alignment problems. Ultimately, the licensee discovered that the carbon steel pump / motor baseplates were flexing.
i due to lost rigidity caused by salt water corrosion (from chronic mechanical i
seal leakage) and due to insufficient filler grout under the baseplates, i
Additionally, the B train pumps (B and D) were found to carry dead weight I
loads on the suction side flanges, contributing to the alignment problems.
!
These deficiencies did not represent inoperable conditions, but did_ constitute previously unknown degradation.
Past inoperabilities had been effectively recognized in the ASME code required vibration monitoring program.
j l
Plant Modification 92-092 for Unit 2 was developed to correct these deficiencies.
For the A train pumps (A and C) the carbon steel baseplates
-
were replaced with stainless steel and the rotating elements / bearing housings were replaced with upgraded standard designs.
For these two pumps, only the
,
pump casings and motors were reused.
The upgraded rotating elements
incorporate improved hydraulic characteristics at low flow conditions.
The i
'
standard design will permit easier parts procurement.
l The existing B train pumps' baseplates were stiffened by addition of welded i
structural braces to restore the original rigidity. The dead weight loads mentioned above were removed by hanger / support modifications on the suction piping. These two pumps were the first to be repaired during the forced outage and were returned to service with the original custom design rotating
!
elements / bearing housings.
At the close of the inspection period, installation of the upgraded standard design internals and bearing housings
'
was in progress. The Three Year Plan includes provisions to replace the baseplates with stainless steel to be identical to the A and C pumps.
The stainless steel baseplates have already been procured.
In addition, all four pump motors underwent ten year interval inspections and preventive maintenance.
The Inspector inspected the installation / modification of the pumps at various
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stages of the lengthy process. A comparison was made of the characteristic j
curves between the original and upgraded rotating assemblies. No significant
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differences exist between the old and new head / flow or raouired NPSH curvar.
Before and after vibration readings for the A and C pumps indicate improvement for both pumps and motors.
Significant improvement is evident for the C pump.
For example, the C pump inboard horizontal vibration improved from
0.338 in/sec to 0.082 in/sec. The A pump improvement is less significant but
was one of the best performing pumps prior to the modification.
Similar improvements should be realized for the B and D pumps.
,
The condition of the RHR SW Booster Pumps is an example of how an accommodated
design deficiency and operator work-around can adversely affect other systems i
or components.
This situation also represents an example of tolerated high maintenance demands without identification of root cause. The Inspector i
concluded that the root cause of the historical RHR SW Booster Pump problems
!
could be associated with the poor flow throttling capability of the reactor
'
coolant side of the RHR/RHR SW shutdown cooling arrangement.
During outages, once cold shutdown is achieved, the decay heat loads quickly become much less
!
than the heat removal capacity of the RHR/RHR SW systems (i.e., design
capacity is based on post accident containment heat removal). This j
necessitates reduction in RHR and/or RHR SW flow rates through the heat
!
exchanger following reduction to single RHR and RHR SW pumps. The heat exchanger bypass valves are routinely opened allowing parallel flow around the i
heat exchanger.
Until several years ago, further reduction of RHR flow was j
accomplished by throttling RHR Ell-f017 LPCI Inboard Injection Valve, but
!
these valves were not adequately designed for this application and severe l
internal erosion resulted.
Currently, the licensee still throttles RHR flow
!
with the Ell-F017 valves, but a minimum flow has been procedurally established j
to minimize the erosion problem. Needed additional throttling to control
shutdown cooling temperatures is accomplished by manual manipulation of the l
heat exchanger outlet valve E11-F003. These are motor operated gate valves i
and are not ideal throttle valves. Throttling these valves does not reduce total RHR flow, but limits the portion passing through the heat exchanger by forcing more flow through the bypass. Manual manipulation is required since l
the current control circuit is a seal-in open/close type with no remote mid-i positioning possible.
This represents a significant operator work-around.
l
The high heat removal capacity of the system in conjunction with the limited throttling capability of the RHR side requires significant flow reduction on j
the RRR SW side.
This is accomplished by throttling the SW return valves, SW-t F068, resulting in the booster pumps, rated at 4000 gpm each, operating at as
!
little as 1000 gpm. At this near shut-off head condition, as indicated by the j
flatness of the pumps head / flow curves, the stresses are maximized on the i
bearings and shaft mechanical seals.
The bearings and seals deteriorate much j
quicker than their expected lifetimes resulting in vibration and seal leakage.
t
,
l The chronic seal leakage has led to corrosion and loss of rigidity of the
!
baseplates, contributing to further alignment and vibration problems. The j
l result vas an average three year interval of limited operation between
overhauls compared to an expected three to five year overhaul interval with j
i near continuous operation.
[
!
l Exacerbating the requirement to maintain a flowrate above the 1000 gpm value, i
!
control room operators were limited to the use of a 0-5,000 gpm flowrate meter
!
l that would be barely on-scale where the pumps routinely operated.
The
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t inspector identified that use of pump discharge pressure, with a linear scale, i
would be more accurrate and readily available to protect the pump from adverse
!
!
conditions. The licensee is considering this observation for action.
!
I
'
The hydraulic characteristics of the new standard rotating elements should
L result in improved low flow performance, and hence better pump reliability.
i
Complete enhancement of the RHR SW Booster Pumps requires improvements to the
!
.
throttling capability of the RHR flow. The licensee plans to modify / replace
l the Ell-F003 valves to provide better flow control with remote positioning
capability. A commitment in this regard has previously been made associated with Generic Letter 89-10. As indicated in the Three Year Plan, this is-
'
>
scheduled for completion by mid-1994 for both units. This item is considered
!
>
q satisfactory for Unit 2 restart.
l Startup Readiness Assessment (40500)
i f
NAD is currently performing an independent startup readiness assessment of f
Unit 2 to evaluate the effectiveness of the Integrated Startup Plan and i
determine if people, processes and plant equipment are ready for the plant' to i
restart and operate in a safe and reliable manner. The Startup Readiness
!
Assessment (SRA) has been subdivided into three phases:
l
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i Phase I to cover plant material condition, personnel / program readiness l
'
e and NRC/NAD issues.
This started on November 2, 1992, and was completed j
on January 31, 1993.
j
Phase 11 will cover people, procedures and processes and plant system
!
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and component readiness and will be performed from February 1-14, 1993.
{
t i
Phase III will be the followup and resolution of emergent issues in f
l addition to monitoring of startup activities.
}
On January 20 and 21, the inspector attended the briefing for the Phase II l
'
assessment team. The briefings focused on Phase I assessments. The inspector i
considered the briefings beneficial to the non-site team members.
It provided l
f the Phase II team with information on past problems on which the assessment
,
was intended to focus.
i l
The briefings were detailed and informative. They appeared to focus on i
i problems identified in the last two quarters of 1992. This appears to be the l
time period that will be used by the team to assess if improvements have been
,
'
made since that time. The Phase I assessment has alse identified continuing training problems.
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+
From the NAD briefings, the inspector concluded that the licensee has not made l
significant progress in the procedures and people / process issues that existed j
'
prior to April 21, 1992. The prime examples are procedural upgrades and
,
!
maintenance work controls. Although some slight improvement has been noted in planning and scheduling, this process is still ineffective.
Work is not
'
planned and accomplished by an established priority system. Management does j
not appear to currently have adequate expertise to address and correct these
'
j problems in a timely manner.
!
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The inspector attended the daily internal briefs of the Phase 11 assessment l
that began on February 1.
This team appears to have broad based experience l
'
and consists of Brunswick NAD personnel, NAD and other CP&L personnel from the
other nuclear units and corporate.
This group also has two consultants, an
'
INPO representative, the plant manager from Grand Gulf and a manager from
"
Virginia Power. The inspector's observation is that these people are
!
I l
conducting a detailed evaluation of hardware and people readiness, it is very evident that they have been presented with a challenge to complete this task
'
in a timely, highly professional and credible manner. The results of this
,
assessment will be summarized in the next month resident inspection report.
.
j 8.
Response to Onsite Events (93702)
l On January 15,1993 at 9:35 a.m.,
an Unusual Event was declared as a result of a
maintenance workers smelling chlorine and observing bubbling underwater in the vicinity of the chlorine diffusers in the service water intake bays.
The
.
licensee evacuated personnel in the immediate and downwind areas and mobilized i
!
the Chlorine Emergency Response Team.
Chlorination had been in service so the
.
'
railroad tank car was quickly isolated to secure any leak in progress.
No activities had been underway that could have inadvertently created a chlorine-
,
leak.
Following negative chlorine samples, the Unusual Event was terminated
at 10:57 a.m.
The licensee determined that no chlorine leak had existed. The
,
observed bubbling was caused by entrained air discharging from the diffusers l
'
introduced via a vacuum breaker into the chlorine injection system. This was
'
not normal and was the result of an off-normal chlorination system lineup.
This configuration which created the bubbling together with the normally
present faint smell of chlorine resulted in the false impression that a chlorine leak was in progress. The inspector observed the event response in
'
the control room and concluded that all actions taken were appropriate. The
,
identifica-tion of the potential problem and the activation of the emergency
,
i plan were prudent actions given the hazards associated with chlorine leaks.
!
l On February 2,1993, at 5:33 p.m.,
the operating Unit 2 main circulating water
'
pumps tripped due to high traveling screen differential pressure.
This was
caused by sudden clogging of the screens by debris agitated by momentary
opening of a large backwash valve. One pump was restored within three i
minutes. No =ffect was apparent on the condensate / feed side of the condenser
-
cooling arrangement. The licensee's and inspector's evaluation of this event r
i were still in progress at the close of the inspection period. Additional
'
j documentation of the issue will be included in a future Inspection Report.
i j
On February 3,1993, at 3:08 p.m.,
an unusual event was declared as the result
of transporting a potentially contaminated injured person from the site to i
Doshar Hospital in Southport. This person had been struck on the head by a i
large hex nut that had fallen from approximately 30 feet in the overhead. The injury occurred-in a contaminated area and was serious enough to require
!
offsite medical attention.
The injury prevented thorough frisking prior to transporting him to the hospital.
Further frisking at the hospital
determined that he was not contaminated and the Unusual Event was terminated.
The required notifications were made for this event.
I
'
Violations or deviations were not identified.
j
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9.
Onsite Review Committee (4050s)
l The inspectors attended selected Plant Nuclear Safety Committee meetings
!
conducted during the period. The inspectors verified that the meetings were
!
conducted in accordance with Technical Specification requirements regarding i
,
quorum membership, review process, frequency and personnel qualifications.
!
"
Meeting minutes were reviewed to confirm that decisions and recommendations
!
.
were reflected in the minutes and followup of corrective actions was i
i completed.
i i
There were no concerns identified relative to the PNSC meetings attended. The
,
j resolution of safety issues presented during these meetings was considered to
be acceptable.
r
!
10.
Review of Licensee Event Reports (92700)
l the following LERs were reviewed for potential generic impact, to detect
!
I trends, and to determine whether corrective actions appeared appropriate.
Events that were reported immediately were reviewed as they occurred to
,
determine if the TS were satisfied.
LERs were reviewed in accordance with the
current NRC Enforcement Policy.
!
,
(Closed)
LER 2-90-008, Scram Resulting From Turbine Trip On High Level Due To f
j A Blown Feedwater (FW) Logic Fuse. This August 16, 1990 Unit 2 reactor scram
!
occurred when primary power fuse C32-F5 (power supply to steam flow inputs of
three element FW control logic) blew, causing a maximum demand signal to the
.
i I
i reactor feed pumps. This resulted in a rapid increase in reactor level up to j
the high level turbine trip, which caused a reactor scram on turbine stop
!
valve position / closure.
Finding no reason for this Gould %awmut fuse to
blow, another was installed and the unit subsequently restaried. A similar
.
reactor water level induced scram occurred on October 12, 1990, when a i
!
different Gould Shawmut fuse in the FW control logic (C32-F3) blew.
Following
.
'
this latter event (discussed belcw under LER 2-90-016) all Gould Shawmut fuses i
in the Unit 2 FW control circuitry were permanently replaced with Bussman Min
fuses, and no further problems have occurred.
With regard to the August 16, l
,
1990 event, the Unit ? bottom head drain was modified / unclogged in refueling
!
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l outage 9.
Though further testing is planned, temperature data taken prior to t
the dual unit shutdown on April 21, 1992, indicates that.the drain was
!
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j successfully modified / unclogged. Accordingly, further reactor recirculation
!
pump recovery problems due to delta temperature requirements should be f
I precluded. The HPCI turbine stop valve cycling encountered during manual
!
recovery operations was also confirmed to be subsequently corrected by adjustment of the woodward governor's needle valve.
In addition, the major i
,
j source of the observed water intrusion in the HPCI oil (i.e., rain water in-l leakage) was identified and eliminated in February 1992.
j
,
.
(0 pen) LER 2-90-16, Unit 2 Reactor Scram On Turbine Stop Valve Fast Closure j
Caused By A Reactor High Level When A Fuse Failed In The FW Control System i
g Circuitry. This October 12, 1990 reactor scram occurred when the Gould i
Shawmut fuse C32-F3 in the FW control system blew. As this caused a false low j ~
until a high level turbine trip / reactor scram resulted. During subsequent reactor level signal to the B reactor feed pump, the pump's output increased l
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recovery of the A reactor feed pump, the reactor operat v incorrectly held the pump's trip reset switch in the reset position and cau.c.:d reactor feed pump lockout circuit fuse C32-F2 to blow.
This blown C32-F2 Gould Shawmut fuse, i
along with the C32-F3 fuse and the C32-F5 fuse discussed above under LER 2-90-
_
008, were sent to the Harris Energy and Environmental Center (E&EC) for
!
!
further testing and evaluation. Although the Harris E&EC concluded that all
!
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j three fuses blew from an overcurrent condition, only the cause of fuse C32-F2
'
could be determined / explained. Reflactive of Unit 1, all Gould Shawmut fuses
>
in the Unit 2 FW control circuitry were permanently changed to Bussman Min
-
fuses. No further problems have been identified since.
The inspector also
.
confirmed that additional training was provided to operators on proper reactor
feed pump recovery, as well as startup level control valve operation.
Remaining corrective action involves the search and initiation of any required
,
action for other single failure point fuses which could result in a scram.
!
Accordingly, as this corrective action item has yet to be accomplished, LER 2-90-016 will remain open.
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11.
Action on Previous Inspection Findings (92701) (92702)
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i (Closed) Unresolved Item 325,324/92-34-02, Service Water Leaks. This item was l
opened following a through wall leak in a cement lined service water pipe
!
J section.
The inspector's review cf the past cement lined service water piping inspections by the licensee revealed that almost all service water i
piping within the diesel building was cement lined, but had not been inspected
{
for internr.1 corrosion.
In response to the NRC questions raised by this item, j
the licensee conducted ultrasonic inspections of accessible diesel building l
l service water piping on a sampling basis of susceptible areas. One area of a potential wall thickness problem was identified.
EWR 09344 evaluated this
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condition as acceptable until all cement lined piping is replaced by copper-l
'
nickel, which is scheduled to be completed in 1996. The thin area was 0.110 j
]
inches with the nominal wall thickness of 9.280 inches.
The licensee j
j considers this thinning to be the result of a pipe mismatch during j
construction and not due to erosion / corrosion.
The inspector concurred with
.
<
l this conclusion.
This section is in the atmospheric pressure portion of the j
l system, downstream of a jacket water cooler. The inspector reviewed
!
documentation which evaluated that adequate structural integrity existed at
this location. Additionally, past leaks have not been catastrophic failures
q but have resulted in only minor spray leakage that have not created a l
condition that prevented the service water system from performing its design l
function.
l
i (Closed) 325,324 P21 91-05, Potential failure Of Limitorque SMB 00 Torque i
Switch Roll Pins. This issue concerns possible CMB 00 torque switch failure when an SMB 00 actuator, equipped with a heavy spring pack, is declutched
,
j under rated load while in the torque seated condition. The failure is j
attributed to the large impact lord of the heavy spring pack when released by
declutching and the rather large mass of the nuclear torque switch that must l
be actuated. This impact tends to shear the roll pins at each end of the j
torque switch shaft, thus preventing the torque switch contacts from opening
]
as the valve disc is torqued into the seat. Therefore, the motor would continue to be energized until the breaker tripped, or a failure of the motor
,
or actuator occurred.
Accordingly, the licensee identified the following l
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safety-related valves which are equipped with SMB 00 actuators and heavy
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spring packs:
1&2 E41-F041 Suppression Pool Suction Valve
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1&2 E41-F042 Suppression Pool Suction Valve
!
1&2 G31-F001 RWCU Inboard Isolation Valve j
1&2 G31-F004 RWCU Outboard Isolation Valve i
j 1&2 SW-V3 SW Header Outboard Supply Valve
!
to Turbine Building
!
1&2 SW-V4 SW Header Inboard Supply Valve
!
to Turbine Building t
,
From the above group of valves, only the E41-F041 and F042 valves were t
j
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identified as potential problems. The others were not considered potential problems since SW-V3 and V4 are limit switch seated valves and G31-F001 and
<
F004 would fail in their safety-related/ closed position. The inspector
.
confirmed that the torque switches associated with the E41-F041 and F042
!
.
i valves in both units have been replaced with the new design SMB 00 torque
switch. As none of the 12 valves identified above are declutched under rated
!
load as part of any normal valve operating evolution, the inspector had no
further questions.
l
.
l (Closed) Violation 325,324/92-11-02, Failure Of NAD To Maintain Independent f
Assessments.
Specifically, this violation involved NAD's participation in j
'j
" hot side" equipment condition walkdowns while responsible for independent
assessment of the overall activity.
Following NRC intervention, NAD
!
i terminated it's involvement in the walkdowns and a standing instruction was
entered into the NAD procedure's manual with respect to the need for strict l
!
independence.
Similar guidance on independent assessments has since been
incorporated in the Corporate Quality Assurance Manual (Revision 16) and no further such problems have occurred.
i t
12.
Information Meeting With Local Officials (94600)
l On January 14, 1993, following the Brunswick SALP presentation, the NRC met
!
with local officials in order to:
(1) acquaint local officials with the j
mission of the NRC; (2) introduce NRC officials and resident inspectors; (3) discuss lines of communication between local officials, NRC and CP&L; and i
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(4) address any related concerns about the plant. Among the attendees were l
representatives from NRC (Region Il and NRR) and FEMA; local officials from
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r i
Southport, Brunswick County, Yaupon Beach, Long Beach, Carolina Beach, Boiling
[
]
Springs Lake and New Hanover County; state officials from the Public Utilities
!
Commission and the Divisions of Emergency Management and Radiation Protection;
.
and members of the local news media.
,
j Reflecting on the earlier SALP presentation, local officials expressed some
!
concern over safe operation of the Brunswick units and questioned the
!
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I feasibility of a March 1993 restart date for Unit 2.
In response, the j
Regional Administrator briefly described the efforts being taken by NRC and
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j CP&L to assure Brunswick's operational readiness.
He also reinforced the
!
notion that although the presented SALP ratings were identical t the previous J
ones, recent improvements have been encouraging. Acknowledging the i
,
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l I
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feasibility of a March 1993 Unit 2 restart date, the Regional Administrator
i encouraged the local officials to become more actively involved through
!
j interaction with the licensee's new senior management team and participation l
'
in future public meetings regarding restart of the Brunswick units.
!
Accordingly, the respective Mayors of the City of Long Beach and the City of i
Boiling Springs Lake requested to be put on the mailing list for future public
!
.
meetings which are conducted at the site. At the meetings end, the Regional
State Liaison Officer agreed to provide the New Hanover County Emergency l
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i Management Director a copy of the final FEMA special assessment relative to l
off-site preparedness for the Turkey Point facility when it became available.
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j 13.
Exit Interview (30703)
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The inspection scope and findings were summarized on February 5, 1993 eth
,
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those persons indicated in paragraph 1.
The inspectors described the areos t
inspected and discussed in detail the inspection findings in the summary.
'
j Dissenting comments were not received from the licensee.
Proprietary i
information is not contained in this report.
j 14.
Acronyms and Initialisms i
i AC Alternating Current ADS Automated Depressurization System
,
,
APR Average Power Range
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APRM Average Power Range Monitor ASME American Society of Mechanical Engineers l
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BPV Bypass Valve
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j BRC Backlog Review Committee
~
CAC Containment Atmospheric Control
,
CAL Confirmation of Action Letter
!
CFR Code of Federal Regulations j
]
CIV Containment Isolation Valve i
,
CP&L Carolina Power & Light Company l
!
CRD Control Rod Drive
!
CV Control Valve
,
j DC Direct Current l
{
DG Diesel Generator i
j E&EC Energy and Environmental Center
]
EDBS Engineering Data Base System
j EHC Electro Hydraulic Control System j
ERFIS Eraergency Response Facility Information System L
ESF Engineered Safety feature EWR Engineering Work Request i
'
FEMA Federal Emergency Management Agency I
FCV Flow Control Valve FW Field Weld
,
GPM Gallons Per Minute i
HP Health Physics j
HPCI High Pressure Coolant Injection
IBIR Integrated Backlog item Report
!
1&C Instrumentation and Control
- i INPO Institute of Nuclear Power Operations
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IRM Intermediate Range Monitor
!
LER Licensee Event Report
.
LPRM Local Power Range Monitor l
j MCC Motor Control Center i
"
MG Motor Generator MSIV Main Steam Isolation Valve MSR Moisture Separator Reheater
,
MST Maintenance Surveillance Test i
NAD Nuclear Assessment Department
!'
NDE Non-Destructive Examination NOV Notice of Violation i
NPSH Net Positive Suction Head NRC Nuclear Regulatory Commission NRR Nuclear Reactor Regulation OM&M Outage Management & Modification OP Operating Procedure PA Protected Area
PMTR Post Maintenance Testing t
PNSC Plant Nuclear Safety Committee j
PS Pressure Switch i
PT Periodic Test
!
QC Quality Control
!
RCIC Reactor Core Isolation Cooling i
RFP Reactor Feed Pump
!'
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RWCU Reactor Water Clean Up SALP Systematic Assessment of Licensee Performance
,
SBGT Standby Gas Treatment SIL Service Information Letter SJAE Steam Jet Air Ejector
,
SRA Startup Readiness Assessment i
SRM Source Range Monitor l
TIP Traversing Incore Probe
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WR/JO Work Request / Job Order
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l i
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