IR 05000324/1993010
| ML20035D346 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 04/02/1993 |
| From: | Christensen H, Prevatte R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20035D337 | List: |
| References | |
| 50-324-93-10, 50-325-93-10, NUDOCS 9304130101 | |
| Download: ML20035D346 (32) | |
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NUCLEAR REGULATORY COMMisslON
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o REGION 11 l-5
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101 MARIETTA STREET.N.W.
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's ATLANT A. GEORGI A 30323
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Report Nos.:
50-325/93-10 and 50-324/93-10
.f Licensee:
Carolina Power and Light Company 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 1 and 2
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Inspection Conducted:
February 6 - March 5, 1993 Lead Inspector:
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R'."L. Prevatte, Senior Resident Inspector Date Signed Other Inspectors: D. J. Nelson, Resident Inspector P. M. Byron, Resident Inspector
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R. E. Carroll, Project Engineer
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L. Garner, Senior Resident Inspector, Robinson
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C. R. Ogle, Resident Inspector, Robinson
Approved By:
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b H.'{hristensen, Chief Date Signed i
Reactor Projects Section 1A i
Division of Reactor Projects
i SUMMARY Scope:
This routine safety inspection by resident inspectors and the region-based j
project engineer inspector involved the areas of maintenance observation,
surveillance observation, operational safety verification, onsite review
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committee activities, onsite followup of events, plant specific startup
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issues, plant outage activities, emergency preparedness program
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implementation, review of Licensee Event Reports, an engineered safety feature
system walkdown, and action on previous inspection findings.
l Results:
I In the areas inspected, no programmatic weaknesses, significant safety matters, or deviations were identified. Two NRC identified non-cited violations were identified. The first involved the failure to post violations involving radiological working conditions within two working days of receipt, paragraph 4.
The second involved the failure to properly calibrate core spray system instrumentation, paragraph 7.
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9304130101 930402 PDR ADOCK 05000324 G
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One unresolved item in the area of deferred preventive maintenance on Q class
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equipment was identified, paragraph 7.
Four inspector followup items were l
identified in the areas of:
seismic qualification of the containment atmospheric control monitoring system and containment sump level and flow
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equipment, paragraph 4; replacement of Westinghouse molded case circuit breakers, paragraph 4; Technical Support Center / Emergency Operations Facility
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diesel generator deficiencies, paragraph 9; and the need to followup on potential disc and stem separation on residual heat removal valves 1-E11-F017 A and B, paragraph 7.
l A strength was identified in the area of manager / peer observations, paragraph
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6.
Weaknesses were identified in the areas of engineering evaluation request
action items, risk assessment, instrument rack replacement, and control of plant activities, paragraphs 4 and 5.
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REPORT DETAILS 1.
Persons Contacted
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Licensee Employees
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- K. Ahern, Manager - Operations Support and Work Control G. Barnes, Manager - Shift Operations, Unit 2
- M. Bradley, Manacer - Brunswick Assessment Project
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- M. Brown - Interim Plant Manager, Unit 2
- S. Callis - Onsite Licensing Engineer
- R. Godley, Supervisor - Regalatory Compliance
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- J. Heffley, Manager - Maintenance, Unit 2 C. Hinnant - Director of Site Operations i
- M. Jones, Manager - Training
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- J. Leininger, Manager - Nuclear Engineering Department (0nsite)
P. Leslie, Manager - Security t
- G. Miller, Manager - Technical Support (Interim)
- D. Moore, Manager - Maintenance, Unit 1
- R. Morgan - Interim Plant Manager, Unit 1
R. Poulk, Manager - License Training C. Robertson, Manager - Environmental & Radiological Control J. Simon, Manager - Operations Unit 1 (Interim)
i R. Tart, Manager - Radwaste/ Fire Protection
J. Titrington, Manager - Operations, Unit 2 l
C. Warren, Pla it Manager - Unit 2 l
G. Warriner, Kanager - Control and Administration
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- E. Willett, Manager - Outage Management & Modifications (OM&M)
Other licensee employees contacted included construction craftsmen,
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engineers, technicians, operators, office personnel and security force members.
- Attended the March 5, 1993 exit interview.
- Attended the March 12, 1993 exit interview.
Acronyms and initialisms used in the report are listed in the last paragraph.
2.
Maintenance Observation (62703)
The inspectors observed maintenance activities, interviewed personnel, and reviewed records to verify that work was conducted in accordance with approved procedures, Technical Specifications, and applicable industry codes and standards. The inspectors also verified that:
redundant componer,ts were operable; administrative controls were followed; tagouts were adequate; personnel were qualified; correct replacements parts were used; radiological controls were proper; fire protection was adequate; quality control hold points were adequate and observed; adequate post-maintenance testing was performed; and independent verification requirements were implemented.
The inspectors independently verified that equipment was properly' returned to service after completion of maintenance.
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Outstanding work requests were reviewed to ensure that the licensee gave
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priority to safety-related maintenance.
The inspectors
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observed / reviewed portions of the following maintenance activities.
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93-AGFS1 Replace Various Control Rod Select Switches On Unit 2 Rod Select Matrix i
The inspector observed I&C technicians removing several control j
rod select. switches on the RTGB and the installation and soldering
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of replacement switches. The technicians used the appropriate procedure and were cautious in this work activity.
The inspector
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noted that the work was especially tedious, requiring use of a magnifying glass while soldering.
Each of the 137 select switches had six soldered connections resulting in a large mass of wiring
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in a relatively small space.
- 92-BHPEl LPCI Outboard Injection Valve 2-Ell-F017B, Motor
Operator Repair The inspe tor observed the removal of the valve motor operator.
No deficiencies were noted.
I PM 92-071 Instrument Rack Replacement Fabrication Of Rack
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2-H21-P009, Jet Pump Instruments The inspector observed the fabrication of this rack during the inspection period. The modification package and necessary
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drawings were present and used during fabrication.
Required
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radiological control guidance and procedural controls were
followed.
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The inspector did not observe poor or improper work practices.
I Violations or deviations were not identified.
3.
Surveillance Observation (61726)
The inspectors observed selected portions of the Technical Specification j
surveillance test listed below.
Through observation, interviews, and record review the inspectors verified that:
the test conformed to
Technical Specification requirements; administrative controls were followed; personnel were qualified; instrumentation was calibrated; and data was accurate and complete. The inspectors also verified that the equipment was properly returned to service.
I PT 12-2B DG No. 2 Monthly Test - 24 Hour Run j
The licensee agreed to perform a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> duration run to verify the reliability of each DG. The normal duration of. PT12.2A-D is two hours, but section 7.11.31 allows runs of longer duration at j
the discretion of the shift supervisor. The inspector observed j
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that engineering and maintenance support was available to
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This test was deemed satisfactory.
l The 24-hour runs on DG Nos.1, 3 and 4 had previously been
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completed with satisfactory results.
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Violations or deviations were not identified.
4.
Operational Safety Verification (71707)
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The inspectors verified that Unit I and Unit 2 were maintained in compliance with Technical Specifications and other regulatory
requirements by direct observations of activities, facility tours,
discussions with personnel, reviewing records, and independent
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verification of safety system status.
The inspectors verified that control room manning requirements of 10 CFR
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50.54 and the Technical Specifications were met.
Control operator, i
shift supervisor, clearance, STA, daily and standing instructions, and jumper / bypass logs were reviewed to obtain information 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, instrumenta-i tion, and recorder traces important to safety were conducted to verify
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operability and that operating parameters were 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 annunciators.
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Operability of the ESF system used for shutdown cooling was verified i
weekly by ensuring that:
each accessible valve in the flow path was in i
its correct position; each power supply and breaker was closed for components that must activate upon initiation signal; there was no-
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significant leakage of major components; proper lubrication and cooling water was available; and conditions which could prevent fulfillment of the system's functional requirements did not exist.
Instrumentation l
essential to system operation or actuation was verified operable by
observing on-scale indication and proper instrument valve lineup.
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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
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calibration.
Through general observations, the inspectors verified that:
the security organization was properly manned and security personnel were capable of performing their assigned functions; persons and packages i
were checked prior to entry into the PA; vehicles were properly i
authorized, searched and escorted within the PA; persons within the PA
displayed photo identification badges; personnel in vital areas were
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authorized; effective compensatory measures were employed when required;
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and security's response to threats or alarms was adequate.
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The inspectors also observed plant housekeeping controls, verified l
position of certain containment isolation valves, checked clearances and verified the operability of onsite and offsite emergency power sources.
Loss of RHR Shutdown Coolina I
The Unit 2 Inboard RHR Shutdown Cooling Isolation Valve, 2-E11-F009, required maintenance during the current outage.
Repair efforts on this valve rendered both RHR trains inoperable for shutdown cooling.
This resulted in condenser cooling becoming the primary _means of shutdown cooling with no normal backup. 'An alternate method of backup decay heat removal (DHR) was CRD injection, discharging through safety relief valves D, E and.L.
Engineering Evaluation Report (EER) 92-0540, Rev. O, was written to evaluate the alternate DHR method and an emergency course of action which injected water into the reactor vessel via the Core Spray pumps. The inspector reviewed the EER and found it to be acceptable. The EER described both primary and emergency actions-and
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included a vessel heatup chart.
Seven action items were identified, six of which needed to be completed prior to entry into the dual RHR loop outage.
The inspector determined that only two had been formally closed out prior to beginning the dual loop outage.
Discussions with the system engineer revealed that he had verified that the other four required items had been completed, but this had not been documented.
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The inspector determined that each item had a stated completion date,
but this did not necessarily coincide with the needed date. The
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licensee does not procedurally require that EER action items be formally
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closed prior to a needed date. They also have no process that connects
action item response with the EER.
The inspector also reviewed the Shutdown Risk Assessment (SRA) of BNP
Unit 2 (B210F6), schedule period January 18, 1993, through Power
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Ascension, dated January 21, 1993. This assessment identified a
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weakness in contingency planning and also contained several concerns and i
recommendations for planned maintenance on valve 2-Ell-F009.
It was difficult to determine what action had been taken to address the concerns, since the licensee did not have a system to formally address
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SRA concerns and recomniendations, and make them a part of the SRA.
These responses to concerns addressed by the PNSC were contained in the PNSC minutes.
The inspector discussed this concern with the licensee.
The licensee is developing a Safe Shutdown Risk Procedure.
It had not been issued at the end of the inspection period.
The lack of a formal method of addressing EER action items, SRA concerns
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and recommendations, as well as making them a part of the original
document, is considered to be a weakness. As such, the compilation of
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information is people dependent rather than a part of the process.
The licensee is reviewing this concern.
The inspector also reviewed the contingency plan for condenser cooling
failure during the 2-E11-F009 valve repair as required by Plant Program, i
PLP-17, Identification, Development, Review and Conduct of Infrequently Performed Tests or Evolutions, Rev. 002. The inspector verified that c
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training was given to the craft including the installation of the
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temporary bonnet used in the contingency effort. Operators were briefed in all phases of the evolution including contingencies. The inspector considered the evaluation, preplanning and contingency planning adequate.
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On February 2, 1993, Unit 2 had an unexpected interruption of condenser cocling. As discussed above, the backup DHR system (i.e., CRD injection) was the alternate method. The interruption of candenser cooling occurred as a result of automatic tripping of the two operating
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Unit 2 Circulating Water Intake Pumps, which removed cooling water from the main condenser.
Just prior to when the pumps tripped, an A0 partially opened, then shut, a seldom used Condenser 2A Backwash Valve
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(2-CW-V9) as a part of post preventive maintenance test on the above valve motor's 480 volt breaker.
Opening the above valve diverted a
large amount of circulating water through the backwash line back to the intake canal.
This agitated silt and debris in the canal as well as
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flushed out line debris. The debris was quickly collected on the circulating water traveling screens causing high differential pressure i
and CWIP trips. Control Room personnel took appropriate actions and restarted a CWIP within three minutes.
A second pump was restarted and
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condenser cooling was re-established.
No effects were noted on the condensate, feed, vessel, or main steam systems, and no increase in reactor vessel temperature was observed.
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The safety significance of this event was minimal because of the low
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decay heat level and the fast restoration of circulating water.
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However, the intentional entry into configurations with a single normal
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DHR method should include control of all known threats to maintaining core cooling.
The licensee attempted to guard all systems needed for condenser cooling, but their efforts did not prevent the breaker
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preventive maintenance and post maintenance testing. As originally
scheduled, this work should have been completed prior to condenser cooling becoming the sole DHR means. A late critical path schedule
change negated the planned sequence. A decision was made by Outage
Planning and Scheduling to allow the preventive maintenance to proceed i
while condenser cooling was guarded.
Planning and Scheduling did not consider the breaker work as a threat to condenser cooling.
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The preventive maintenance on the breaker was accomplished using a general procedure for breakers of this type, without specific considerations for individual situations. The procedure, OPM-BKR003, Preventive Maintenance of GE 480 VAC MCC Compartments, Rev. 12, has steps to operate the equipment powered by the breaker following the maintenance as a post maintenance test.
However, the procedure allows this to be waived if conditions are not appropriate.
The WR/JO (93FCC06) required post maintenance testing.
f The post maintenance test for this breaker was appropriately determined to be operation of valve 2-CW-V9.
This was attempted on the morning of February 2.
Prior to the attempt, the A0 assigned to operate the valve l
questioned the wisdom of opening the valve based on what he had heard of
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spraying water all the way across the intake canal.
This valve was no longer used for backwashing. The SCO considered that the only threat of opening the valve was during power operations when condenser vacuum could be adversely affected, therefore opening the valve to test the breaker was authorized. On the attempt, the valve motor energized, but the valve did not open. Upon observing this, the A0 requested that maintenance initiate a WR/JO for this deficiency. A new WR/JO was not generated, but maintenance personnel investigated and discovered that the valve operator manual override was not fully in the auto position due to paint binding. The override handle was loosened and the full auto position was obtained. A second attempt was made to operate the valve by the subsequent Operations shift personnel.
On this attempt the valve opened, initiating the transient.
The SCO authorized operation of the valve based primarily on his knowledge that the previous shift SCO had also authorized it. He cited competing demands for his attention and stated that a lot of time was not spent en this
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decision.
This event revealed several problems:
Guarding of Condenser Cooling Systems did not prevent all work e
from taking place.
Operations considered loss of offsite power to be the major threat and was not sufficiently sensitive to subtle, internally generated challenges.
Emphasis was placed on contingency plans for losing condenser cooling over emphasis to prevent losing condenser cooling.
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Consideration of potential consequences of operating the CW-V9 e
valve was limited to at-power situations.
The CW-V9 valve is no longer used for any system operation e
although its breaker is normally energized.
The administrative workload of the SCO may have lessened the
consideration of the upcoming activity.
Although not complicated, the manual override lever was freed
without processing a WR/J0.
Corrective maintenance is not
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permitted on a Preventive Maintenance authorization unless included in the preventive maintenance procedure.
The inspector concluded that the specific consequences of ouerating the valve with the circulating water system in operation (i.e., stirring up debris in the intake canal that subsequently clogged the travelling screens causing the CWIPs to trip) could not reasonably be foreseen by operators.
The effect was not as direct as would be the effect on condenser vacuum had the plant been at power. The licensee did not adequately consider this aspect when choosing to allow work to proceed on condenser cooling systems.
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During the week of February 1, an unexpected lowering of two inches of reactor vessel level in Unit 2 occurred when RHR shutdown cooling
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inboard isolation valve Ell-F009 was opened by maintenance personnel
while adjusting limit switches by procedure. Opening the valve filled the previously drained RHR piping downstream, thus lowering the level.
Additionally, two recent system draining evolutions involving RHR and
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the potable water system were insufficiently controlled resulting in j
minor flooding of plant spaces. The occurrence of.these events-
indicates that effective control of plant activities is sometimes i
insufficient or not well planned and thought out.
Containment Atmospheric Control Radiation Monitor and Drywell Sump Level t
Control System Seismic Oualification General Design Criterion (GDC) 30 establishes the requirements for the
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quality of the reactor coolant pressure boundary, as well as the
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detection and identification of the location and source of reactor coolant leakage.
Regulatory Guide (RG) 1.45, Reactor Coolant Pressure Boundary Leakage Detection System, provides acceptable methods of implementing GDC 30.
RG 1.45 requires at least three separate detection
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DW sump level / flow monitoring, airborne particulate radioactivity monitoring, and airborne gaseous radioactivity monitoring.
RG 1.45 further states that the leakage detection systems should be capable of performing their functions following a seismic event that does not require plant shutdown, and that the particulate monitoring system should remain functional when subjected to a Safe
Shutdown Earthquake (SSE).
On January 21, 1993, the licensee determined that the Containment
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Atmospheric Control (CAC) Airborne Particulate and Gaseous Radioactivity Monitors were not seismically qualified. The sump level / flow monitoring system is currently being evaluated to determine if it is in conformance
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with RG 1.45.
If repairs, modification or equipment changes are
required, the licensee has stated that they will be done prior to Unit 1 l
and Unit 2 restart. The licensee is continuing their investigation of
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the a M e item and has submitted LER l-93-01.
The licensee plans to j
submit a supplement to the LER as additional information becomes
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available.
The inspector will continue to follow this item as an
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Inspector Followup Item 325,324/92-10-02: Seismic Qualification Of CAC
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Systems. A detailed review and evaluation of the cause and corrective
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actions taken will be provided as information becomes available.
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Posting of Violations i
10 CFR 19.ll(a) requires that a licensee post current copies of any notice of violation involving radiological working conditions, and any response from the licensee.
In addition, 10 CFR 19.ll(e) requires that any Commission documents posted pursuant to paragraph (a)(4) be posted within 2 working days after receipt of the documents from the Commission; the licensee's response shall be posted within 2 working days after dispatch by the licensee.
Such documents shall remain posted for a minimum of 5 working days or until action correcting the violation has been completed, whichever is later.
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During tours of the licensee's facility on January 22, 1993, the inspector reviewed the licensee's boards for regulatory postings.
The i
inspector noted that the Notice of Violation (NOV) from a recent
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radiation protection inspection had not been posted as required by 10 CFR 19.11. The NOV was documented in Inspection Report 50-325,324/
92-32, and was dated November 24, 1992.
The inspector identified the failure to post the NOV involving radiological working conditions as a violation of 10 CFR 19.11 requirements.
Subsequent to identification of the issue by the inspector, licensee representatives stated that the
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posting deficiency was an oversight.
The inspector noted that on
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January 25, 1993, the subject NOV was posted in accordance with the
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regulations.
No further noncompliances with the licensee's postings were identified.
The inspector informed licensee representatives that the failure to post the November 24, 1992 NOV appeared to be an oversight. Considering the minimal safety significance of the issue and immediate actions taken to correct the noncompliance, this NRC identified violation is not being
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cited because criteria specified in Section VII.B. of the Enforcement Policy were satisfied. This violation is identified as NCV 325,324/93-10-01:
Failure To Post NOVs Involving Radiological Working Conditions.
Westinghouse Molded Case Circuit Breaker Deficiencies
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In December 1992, during preventive maintenance instantaneous trip testing of Westinghouse Type HMCP 150 breakers, the licensee identified
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four breaker failures. The failures were identified when the breakers were subjected to instantaneous currents in excess of NEMA AB4-1991,
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" Tolerance of Marked Adjustable Trip Circuit Breakers," plus 40% of l
expected trip value. The failed breakers were not used in safety-related applications.
However, there are 141 of these breakers i
installed at Brunswick, with 73 in safety-related applications on Unit 2
and 66 on Unit 1.
An evaluation determined that the above failures may
occur due to defects in fabrication, poor tolerance, and inadequate
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lubrication at critical hinges, i
On December 20, 1992, a Westinghouse Type HFD 3070 breaker used for the i
emergency diesel generator jacket water heater tripped and could not be
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reset.
It was found to be defective and was replaced. On December 26, the replacement breaker experienced an overcurrent condition due to cable insulation breakdown. The breaker failed to trip full open on all
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phases, but opened sufficiently to deenergize the control power feeding
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the breaker compartment contactor.
An investigation into these failures
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determined that a failure could also result from inadequate fabrication, poor tolerances, and inadequate lubrication. A total of 79 type HFD
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breakers are installed at Brunswick.
The majority of these breakers are used in nonsafety-related applications.
The licensee submitted a 10 CFR 21 report on the two above occurrences to the NRC on February 25, 1993. The submittal explained the defects
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and associated problems in detail.
The 1icensee has determined that the HMCP breakers used in safety-related applications will be replaced prior l
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to the restart of Units 1 and 2.
A decision on possible replacement of HFD breakers is being evaluated. The inspector will follow the above evaluation and replacement activities as an Inspector Followup Item 325,324/93-10-03: Molded Case Circuit Breaker Replacement.
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One NCV was identified.
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5.
Plant Specific Startup Issues (71707)(62703)(37828)
(Note: Confirmatory Action Letter (CAL) items are addressed in
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Enclosure 3 of CP&L's letter dated July 23,1992.)
CAL Item A-3, Seismic Instrument Rack Corrosion Repairs As part of the ongoing effort to evaluate the instrument rack upgrade, Plant Modification 92-071, completed WR/J0s were reviewed for the High Pressure Coolant Injection (HPCI) System Instrument Rack (2-H21-P014)
and the Residual Heat Removal / Service Water Instrument Rack (2-H21 - P018)..
Seventeen WR/J0s for the removal, reinstallation and
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testing of instruments on rack P014, as well as fifteen similar WR/J0s for rack P018, were reviewed. This review revealed a significant difference in the way work was performed and controlled on each rack.
The quality of work completed appeared to be adequate on both racks.
The inspector reviewed the following WR/J0s which were for pressure indicator removal and reinstallation on rack 2-H21-P014.
92-APIU1 HPCI Pump Discharge Pressure Indicator 2-E41-PI-R001 92-APIW1 Turbine Steam Supply Line Pressure Indicator 2-E41-PI-R003 92-APIX1 HPCI Pump Suction Pressure Indicator 2-E41-PI-R004 92-APIY1 HPCI Turbine Exhaust Pressure Indicator 2-E41-PI-R005 These instruments required only mechanical work and no deficiencies wero identified. The following WR/J0s involving the removal, reinstallation
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and testing of flow and pressure switches / transmitters were reviewed by the inspector:
92-APIP1 HPCI Discharge Line Flow Switch 2-E41-FSHL-N006 92-APIT1 HPCI Discharge Line Flow Transmitter 2-E41-FT-N008 92-APIZ1 HPCI Pump Suction Low Pressure Switch 2-E41-PS-N010 92-APJA1 HPCI Turbine Exhaust Drain Pot Line Pressure Switch-2-E41-PS-N017A 92-APJH1 HPCI Turbine Exhaust Pressure Switch 2-E41-PS-N0178 92-APJIl HF_I Turbine Exhaust Diaphragm High Pressure Switch.
2-E41-PSH-N012A 92-APJJ1 HPCI Turbine Exhaust Diaphragm High Pressure Switch 2-E41-PSH-N012C 92-APJL1 HPCI Pump Discharge Pressure Switch 2-E41-PSH-N027
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i 92-APJM1 HPCI Pump Suction High Pressure Switch 2-E41-PSH-N031 92-APJN1 HPCI Pump Discharge Pressure Transmitters-l
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2-E41-PT-N009
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92-APJP1 HPCI Turbine Supply Steam Drain Pot Inlet Pressure
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2-E41-PI-N013 92-APJR1 HPCI Pump Main Suction Line Transmitter 2-E41-PT-N019 92-APJQ1 HPCI Turbine Exhaust Steam Line Pressure Transmitter J
2-E41-PJ-N016 t
The inspector noted that instructions were added to the above WR/J0s to replace flexible connectors as necessary and to determinate and i
reterminate the specified instrument. Additional review revealed some instruments had been determinated and reterminated twice.
The original QC inspection for the first termination had been voided and each package contained another QC inspection sheet for the retermination.
The review found that the licensee had experienced an un nticipated isolation when
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it performed the required hydrostatic (hydro) test on the switch or transmitter with the device electrically connected.
Since all of the
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devices had been connected electrically, the WR/JO instructions were revised to reflect that electrical connections had to be determinated e
and reterminated after the hydro performance. The work was performed
and documented in the corrective action section of each WR/J0.
The review of WR/J0s for instrument rack 2-H21-P018 included WR/JO 92-AQFM1 for the removal of drain valves and 92-APMJ1 for the removal of i
RHR A shell and tube differential switch, PS-E11-PDS-No.03A.
No i
concerns were identified on these WR/J0s.
The following WR/J0s address the removal, reinstallation and testing of i
various switches and transmitters on rack 2-H21-P018:
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92-APMCl RHR Heat Exchanger 2A Discharge Conductivity Indicator
2-Ell-CIS-R001A 92-APNAl RHR Loop A Pressure Transmitter 2-Ell-PSL-2746 92-APMH1 RHR Loop A Flow Transmitter 2-Ell-FT-N015A
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92-APMX1 RHR Pump C Discharge Pressure Switch 2-E11-PS-N020C
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92-APMZ1 RHR Heat Exchanger 2A Inlet Pressure Transmitter i
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2-Ell-PT-N026A 92-APMTl RHR Pump 2A Discharge Pressure Switch 2-Ell-PS-N016A 92-APMY1 RHR Heat Exchanger 2A Discharge Pressure Switch
2-Ell-PSH-N022A
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92-APMF1 Service Water Flow from RHR Heat Exchanger 2A i
2-Ell-FT-N007A 92-APMU1 RHR Pump 2A Discharge Pressure Switch 2-Ell-PS-N020A
92-APMW1 RHR Pump 2C Discharge Pressure Switch 2-E11-PS-N016C
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The inspector's review revealed variations in the way work was planned I
and controlled between the two racks.
The WR/J0s for the P018 rack were
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not revised to reflect the work which was performed. However, all were
revised to replace the flex and connectors if required.
The hydrostatic-
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test specified in WR/JO 92-APMC1 was not performed as the conductivity indicator was not mechanically disconnected as specified in the work
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instructions. The instructions were not revised to reflect that the instrument was not disconnected and the hydro was not required to be performed. All but the first three WR/J0s contained comments in the corrective action section that the instruments were determinated and reterminated per the request of the OM&M Project Engineer.
None of these WR/J0s were replanned and revised to reflect the additional effort. Also these packages contained two electrical termination inspection reports, but the original inspection had not been voided as
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had been done during a similar effort on rack 2-H21-P014.
The following WR/J0s cover the removal, reinstallation and testing of i
mechanical pressure indicators on rack 2-H21-P018:
92-APMK1 RHR Pump A Suction Pressure 2-Ell-PI-R002A
92-APML1 RHR Pump C Suction Pressure 2-Ell-PI-R002C i
92-APMM1 RHR Pump A Discharge Pressure 2-Ell-PI-R003A
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92-APMP1 RHR Pump C Discharge Pressure 2-Ell-PI-R003C
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OM&M implemented a practice, which is not proceduralized, of voiding initial inspection reports if the activity is to be reinspected.
However, none of the original inspection reports were voided for rack P018. The inspector considered working under oral direction and not in accordance with procedures or instructions an example of poor work control practices. The inspector also noted that all work was not documented in the corrective action section of the WR/J0.
In several
packages the reviewer added comments regarding work which was
accomplished in the corrective action section, but not described in the
i instructions.
The failure to identify these items in the WR/JO closecut review is an example of inattention to detail.
Although no procedures were violated, the differences in content and quality of work packages for the same modification effort appears to be the result of a lack of work and documentation standards, as well as poor supervisory oversite and review.
CAL Item D-1, Reduction Of Short-Term Structural Intearity (STSI)
Backloa There were 48 STSI open items when the plant shut down on April 21, 1992.
Twenty-three of them were on Unit 2.
The licensee expanded the STSI list by identifying components rather than items. As an example, the original list had the service water pumps as one item, the revised method lists it as ten service water pumps. This was done to allow the.
licensee to better quantify the effort required to address each item.
The 23 original Unit 2 STSI items became 88 component discrepancies.
Sixty-five of these have been closed. Since the start of the current outage, 142 Unit 2 pipe supports have been identified by the design
. turnover project and approximately 688 additional components were identified during Unit 2 walkdowns. There are approximately 8E3 Unit 2 STSI components which have not been closed. The licensee has evaluated all open WR/J0s to determine if any potential STSI components exist in the described deficiencies. The inspector considers this to be
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appropriate.
The licensee has evaluated all of the STSI components that will remain open and determined that, taken individually, none of them will have an adverse effect on the safe operation of the plant.
The-licensee is currently conducting a review to determine if the cumulative
effects of the STSI components that will remain open can have an adverse effect on plant operation. The licensee has committed to close all of the Unit 2 STSI components, except fuel oil small bore piping, before the end of the 1994 refueling outage.
The fuel oil small bore piping is scheduled to be completed in 1995.
The licensee corrected a significant number of potential STSI components
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which were identified during the walkdowns that had not been included in any listing.
The inspector considers that the licensee has met their commitment to reduce the STSI backlog.
Provided the STSI cumulative effects review is found satisfactory, the licensee's progress in this
area is adequate to support the Unit 2 restart.
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CAL Item PM 92-73, Hardened Wet Well Vent - Unit 2 i
The Hardened Wet Well Vent system design'was previously discussed and i
evaluated in Inspection Report 325,324/92-37. The inspector has
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followed the installation and testing activities as they were completed.
The physical work was essentially completed during February 1993, and
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the system is in the process of being turned over to Operations.
The inspector performed a walkdown of all accessible portions of the system and questioned the appearance of light traces of rust at certain pipe weld joints. This was discussed with QC and it was verified that the correct weld filler material had been used during welding.
The staining appears to have come from carbon being drawn out by the welding heat or the use of improper wire brushes.
No other deficiencies or questions were identified during the above walkdown. The inspector reviewed the procedural changes that were required as a result of this modification-.
The licensee identified 26 procedural changes / updates, one new surveillance test and one new performance test that were required as a result of this modification.
Seven of the procedural changes / updates are required prior to declaring the system operable.
The inspector verified that these changes had been made. The licensee has stated that the remaining procedures will be revised or updated prior to their next use.
The inspector reviewed the modifications and plant change training scheduled for licensed operators prior to plant restart.
This training
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on the hardened wet well vent includes a student handout with a system description and a brief classroom discussion on the hardened wet well vent and how it will be used. The changes to the E0P for Primary Containment venting will also be covered. The inspector did note that the modification is not installed on the simulator, but is scheduled for installation in June 1993.
The preliminary review by NRC did not identify any deficiencies with the modification.
This item is satisfactory for Unit 2 restart.
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CAL Item E-2, Cold Side Walkdown The licensee has completed the Unit 2 Material Condition Walkdowns (Inspection Report 325,324/93-02).
The Unit 1 Material Condition Walkdowns are currently underway with an expected completion date in
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April 1993. The initial Hot /Coldside Walkdowns and subsequent Material
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Condition Walkdowns have identified over 6,000_ deficiencies to date.
The major portion of these items involve missing and loose bolts / nuts associated with electrical conduit, cable trays, HVAC and miscellaneous structural supports.
Some of the above items were corrected when-found.
i A significant number have been repaired under the minor maintenance program. The items that could not be corrected in that manner have been
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incorporated into the maintenance backlog to be worked under a WR/J0.
As a WR/JO they are prioritized under the PN-30 process and worked
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accordingly. To date, approximately 50% of the deficiencies identified during the walkdowns have been corrected.
The above walkdowns have not covered all plant areas.
Based on the -
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number of deficiencies identified to date, the licensee has stated that they intend to expand these inspections to cover the remaining plant
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areas. They informed the NRC that they will complete the walkdowns on Unit 1 prior to Refuel 9 which is currently scheduled to begin in March 1995, and prior to Refuel 10 which is scheduled to begin on March 1994,
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on Unit 2.
This will allow the licensee to schedule and work any deficiencies that may require a refueling outage.
The inspectors have reviewed these deficiencies and, since the majority of items identified to date had minimal impact on safe plant operation, this appears to be acceptable.
The completion of these walkdowns and correction of identified deficiencies will clearly demonstrate the licensee's
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commitment to standards.
The inspectors find that the licensee's plans l
and schedule for completion of these activities are acceptable for the
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Unit 2 restart.
CAL Item D-3, Reduction of Operator Work-Arounds
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The licensee committed to reduce the backlog of Unit 2 operator work-
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arounds in accordance with PN-30 requirements.
The work-arounds consist l
of several different components, including Reactor Turbine Generator Board (RTGB) WR/J0s, Temporary Caution Tags, Clearance Tags greater than 30 days and Electrical and Mechanical Jumpers.
The definition and scope
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of operator work-arounds has changed from April 21, 1992, to present.
l It has increased from two to seven categories.
On August 27, 1992, there were 290 operator work-arounds. As of March 1, 1993, this number had been reduced to 117.
Recently the definition and scope of operator
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work-arounds was revised to identify RTGB WR/J0s (Control Room
Annunciator and Instruments) as a separate category.
The licensee established goals for annunciators and instruments and operator work-i arounds to be achieved prior to startup.
There are currently 35 open
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RTGB WR/J0s, with a goal of ten or less by startup.
There are 82 operator work-arounds with a goal of 64 or less.
The inspector will follow the licensee's progress and review those items remaining open-at
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startup.
The licensee appears capable of meeting its commitment prior to startup. This item has been adequately addressed for Unit 2 restart.
6.
Plant Self-Assessment and Readiness for Restart (40500)
Manager / Peer Observation Program The inspector reviewed the Licensee's Administration Instruction,
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Manager / Peer Observer Program (AI-101), Revision 0.
This instruction established methods and requirements to implement a manager / peer review
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program at Brunswick.
This program is intended to: identify conditions
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and performance which affect the achievement of standards; ensure that field personnel receive needed management support; ensure that management expectations are communicated and met; and improve procedure understanding and compliance. The above was implemented by unit activity, peer observations and reports in the Operations, Maintenance and E&RC units, as well as site management's observations and reports of specific site activities and programs. This program was initially implemented by Site Vice-President Directive in January and incorporated
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into the Administrative Instruction on February 5.
The inspector
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reviewed the Vice President Directive, AI-101, and all completed manager / peer observer reports conducted between January 18, and February 22, 1993.
The instruction appears to provide adequate
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direction and guidance for the administration of this program.
The completed manager peer observer reports were frank and detailed and i
provide insights from the observer and those observed viewpoints.
It appears that the managers, supervisors and peers conducting these surveillances are all gaining from this program.
Many of the observers
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are gaining plant knowledge and an insight into what it takes for plant personnel to do their jobs, the obstacles they must overcome, and how
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well, or poor, plant personnel perform in their jobs and assigned tasks.
Many comments and suggestions for improvement are generated from these surveillances.
It appears that these surveillance observations are well received by line personnel and demonstrate that plant management and r
supervisors really care about the people "in the trenches". This item is identified as a strength.
NAD Assessments
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t The inspectors reviewed the status of the NAD's, Phase II Startup Readiness Assessment that was in progress during the January Resident
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Inspection Report period.
This assessment was completed on February 14, 1993. The inspector attended the assessment team meeting during the week of February 8, and the plant exit on February 14.
This assessment i
identified three issues that require action prior to Unit 2 Startup and
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two other issues that require near term post-startup action.
j The first issue involves "the lack of management and supervisory involvement in evolution preparation and event followup, and a tendency by operators to react and respond to changes in plant status without
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analyzing cause and effects have contributed to adverse conditions and
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plant events. " This item noted that eight recent events had occurred which cast doubt on operator readiness for plant restart.
These items involved operator and staff errors that related to poor decisions, inadequate control of plant systems and the lack of a questioning attitude by operations personnel.
The second item was that " work activities are not being scheduled and
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coordinated in a manner that will preclude unnecessary challenges to the l
plant and assure event-free, reliable plant operation.
Contributing to
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this problem is the lack of approved procedures which identify work flow and work group interface." This item is the result of a weak planning and scheduling plan and procedures coupled with an inefficient and less than effective work organization which operates without a realistic and coordinated schedule.
As a result, the line organizations are not able to follow the plan / schedule and gross inefficiencies are introduced into the work process.
It appears that insufficient progress had been made in correcting this situation.
The third item is " existing plans do not scope the total work nor fully describe the sequence of work necessary to complete the outage, accomplish testing and restore the plant to full power operation." This item noted that there appeared to be too much overlap between the integrated work schedule, the line managemet' M f-Assessment of Readiness for Restart of BNP Unit 2 (PN31) c 4 the Unit 2 Startup and Power Ascension Performance Objectives and Management Plan.
This assessment stated that the above plans and procedures were good, but were not detailed, planned and adequately staffed with required
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completion dates of key items identified. The inspector agreed that each of the above plans were a good starting point, but noted their lack of detail, qualified / trained staff, goals and oversite measures to ensure success.
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NAD noted that the PNSC had become overly involved in details involving the review of work additions and deferrals associated with the outage.
This had distracted them from their primary mission.
As a result of this item, changes are being made to the PN-30 review process that will reduce the overview of outage work activities to cover only high priority and safety significant work items and increase the PNSC review
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i of plant operations.
The second post startup issue involved the corrective action program. This item focused on weaknesses in the timely closure of corrective actions and the lack of effective tending programs.
The manager of NAD briefed the NRC during a management meeting in the i
Regional Office on February 18, 1993.
The inspector's evaluation of this effort was that the NAD assessment team was staffed with well qualified personnel. They objectively attempted to complete their assigned tasks of assessing the improvements made since plant shutdown and the readiness of Unit 2 for restart. They identified the areas
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where additional attention is needed prior.to Unit 2 restart.
They did-not provide an assessment or quantify progress made in these areas since plant shutdown in April of 1992.
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Although NAD has committed to follow the licensee's corrective actions for the above items, it is not clear how NAD will measure and determine when Unit 2 is ready for restart.
i The inspector reviewed the NAD assessment of welding and special
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processes conducted during the period of January 4 through
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January 15, 1993.
This inspection was -a result of a series of problems that had been recently identified with welding material control and the
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welding process. This assessment was a good effort with a summary of i
previously identified problems and some new findings. This report i
identified five issues and one weakness. ACRs were generated on the issues and the report required a response within 30 days after issuance.
The inspector reviewed the report and questioned if the identified issues were significant enough to require a stop work on welding until
they could be corrected. The inspector also questioned if interim measures had been put in place to address these issues until long-term corrective action could be implemented. The inspector discussed this action with plant management.
Interim measures are in place, but were l
not documented in the NAD report.
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I The site welding program and issues are unresolved item 50-325,324/
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92-47-01.
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7.
System Material Condition / Restart Readiness (71707 and 71710)
In September 1992, NRC inspected the licensee's pre / post-restart work i
screening process. As documented'in Inspection Report 50-325,324/92-29, the restart decisions being made at that tim n backlogged work items
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l were found to be appropriate; however, the piocess was considered slow l
and lacking adequate procedural guidance.
Subsequently, the screening process was proceduralized in Plant Notice PN-30, Integrated Recovery Methodology.
Providing a detailed mechanism to document system i
engineering review in support of system readiness, PN-30 (Revision 1)
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addresses the identification, compilation, categorization, integrated
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scheduling control, and completion of open work items. As such, PN-30 t
identifies the Integrated Backlog Item Report (IBIR) as being under the
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review scope of the system engineer.
Reflective of an open item's i
restart determination, the IBIR is derived from such things as open
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corrective WR/J0s, temporary conditions, hotside/coldside inspection
findings, EWRs, and EER action items.
Similarly, the System Reference
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Manual aids the system engineer in performing the PN-30 required review of non-IBIR based engineering / hardware issues (i.e., pending plant i
modifications, unanswered technical support memorandums, NED " blue
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memos", equipment decommissioning packages, etc...).
In order to assess the effectiveness of PN-30 (Revision 1) with respect to system material condition / restart readiness, six Unit 2 safety-i related systems were selected for evaluation. The six systems selected (none of which had undergone the final PN-30 readiness assessment but i
had undergone initial review) were:
core spray, high pressure coolant injection, reactor core isolation cooling, service water, residual heat
removal, and automatic depressurization/ safety relief valves. As a
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minimum for each of these systems, an inspector reviewed the associated IBIR and performed a system walkdown with the system engineer.
Overall, the selected system evaluations found the PN-30 process to be
effective.
Reviewed systems either exhibited good material condition /
restart readiness, or were expected to do so once identified restart items had been completed. There was, however, one issue identified that required resolution before Unit 2 restart.
This issue concerns the deferral of preventive maintenance on safety-related systems based on generic analysis.
Discovered during the core spray system evaluation, this issue, as well as all six system evaluations, are summarized below.
Unit 2 Core Spray System The inspector performed a detailed inspection of the Unit 2 Core Spray System, external to the primary containment.
The inspection included a walkdown of the system to assess the material condition of the system.
Components were examined for signs of leakage, proper assembly and fitup, as well as evidence of damage.
Supporting components, such as i
snubbers, pipe supports, and instruments were also included in this i
wal kdown.
Particular emphasis was provided to those IBIR entries which will not be worked prior to the end of the current outage.
The inspector observed that the general material condition of the system was
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good with most material deficiencies observed by the inspector having
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been previously identified by the licensee.
The inspector was satisfied that none of the deferred items identified in the IBIR represented a i
significant degradation in the system or could reasonably be expected to prevent the core spray system from performing its intended safety function.
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During the system walkdown, the inspector did note three previously
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undocumented minor material deficiencies.
These included a small leak on a vent plug for the 2A core spray flow measuring device (2-E21-FS-N006A); discolored wire sheathing for a 2A core spray motor heater; and
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the incorrect mounting of a heater on the 2A core spray pump motor.
The licensee issued work requests to address these inspector identified items. The inspector concluded that these items would not adversely impact system operation.
The inspector also compared the system drawing and the valve lineups _
provided by OP-18, Core Spray System. Two minor discrepancies were l
identified:
The Division II Line Inboard Test Valve (2-E21-F013B) and the 2-
t E21-F005B Inboard and Outboard Body Drain Valves (2-E21-V57 and 2-
E21-V58) had " Locked Closed" as the normal position on the valve lineup while the corresponding valves for Division I (2-E21-F013A, 2-E21-V55, and 2-E21-V56) all had " closed" specified as the normal position in the valve lineup.
This inconsistency was identified to the licensee.
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The inspector noted that the drawing indicated 2-E21-V75 and 2-
E21-V82, stem isolation valves for 2-E21-F007B and 2-E21-F006B respectively, were normally open. The corresponding valves on the other division were shown as normally closed. The correct position, and that specified in the valve lineup was closed.
This apparent drawing error was identified to the system engineer for resolution.
The inspector also reviewed ten WR/J0s, which accomplished the last calibration of most of the core' spray instruments.
Items noted by the r
inspector include:
The completed data sheet for calibration of the 2A core spray flow
indicator (2-E21-FI-R601A) was in error.
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LEFT" columns of the data sheet, though clearly annotated for recording data in mAdc, had in fact, been completed with flow in gpm. As a result, no evaluation of the instrument's calibration could be made since the acceptance criteria of the data sheet were
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provided in mAdc. The inspector concluded that the calibration procedure had been performed improperly.
Furthermore, the inspector noted that a supervisory review performed by an acting
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technician had failed to detect this error.
The licensee was
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requested to investigate this error.
Based on an interview of the technician, the licensee concluded that the calibration had been performed properly, but the technician had improperly documented the results. The licensee agreed that this error had not been detected during a supervisory review.
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The data sheets for the 2A and 2B core spray pump suction pressure
gauges (2-E21-PI-R001A and 2-E21-PI-R0018) calibrations were inconsistent.
Despite identical instrument ranges and instrument accuracies, the two functionally identical gauges had been calibrated using different generic data sheets and at different points.
The licensee was requested to explain this discrepancy.
Based on their review, the licensee identified that the 2A core
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spray pump suction pressure gauge (2-E21-PI-R001A) calibration was in error. The licensee noted that the technician had used the wrong data sheet for the instrument; that the technician had improperly calculated the calibration points; that the instrument was out of calibration at one of the five calibration points; and that the supervisor had failed to detect these errors in his review.
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When the above errors were identified, the licensee rescheduled the calibrations and generated M.ACs to evaluate and address the adverse'
i conditions.
Furthermore, the licensee modified the data sheets to provide additional information that should prevent similar errocs. The licensee committed to sampling similar calibration records to determine
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if other problems exist. The licensee also stated their intention to provide training on these errors to I&C personnel.
The safety significance of these errors was minimal. Neither instrument is required by TS, although the 2A core spray flow instrument is a RG i
1.97 instrument. Neither instrument provides a control function or an alarm feature.
However, both of these examples indicated a lack of
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attention to detail on the part of the technician performing the calibration, as well as a less than thorough review on the part of the supervisor. The net result was a failure to properly implement an
activity affecting quality as required by Criterion V to Appendix B of
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10 CFR 50. However, the corrective actions implemented by the licensee in response to these deficiencies, as well as upgrades in the licensee's calibration program (accomplished prior to the inspection period) should preclude recurrences.
This NRC identified violation is not being cited because the criteria specified in Section VII.B. of the NRC Enforcement Policy was satisfied.
This violation is identified as NCV 324/93-10-i 05:
Failure To Properly Calibrate Core Spray System Instrumentation, As Required By 10 CFR 50, Appendix B, Criterion V.
The inspector also reviewed the calibration data sheet for the core
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spray pump 2A discharge flow sensing instrument, 2-E21-FS-N006A.
In addition to measuring core spray to the reactor, this instrument also provides a signal to control minimum flow bypass valve 2-E21-F031 A.
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operation of this valve ensures that core spray pump minimum flow
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requirements are met.
The instrument and its associated flow switches l
were last calibrated on April 9,1991.
Based on the next scheduled calibration of the instrument on March 4,1994, the inspector questioned the planned 35-month calibration interval for an instrument with a calibration frequency of every refueling outage.
In response, the
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licensee furnished the inspector a PNSC approved memo dated November 18, 1992, entitled, Unit 2 Refuel Outage and Greater Frequency Preventive Maintenance Routes.
The memo stated,
"With the exception of PM routes identified by Technical Support... any Refuel Outage and greater frequency outage-required PMs that were completed satisfactorily on their last scheduled performance date may be rescheduled to reach the next refueling outage..."
The inspector reviewed the analysis provided in the above mentioned memo and discussed the issue with the licensee. In essence, the argument was made in the memo that only a 11 percent decrease in the survival i
probability of a component will occur by extending the preventive i
maintenance interval from 18 to 36 months.
This conclusion is based on
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the application of a generic analysis performed using the Age-
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Reliability Characteristic Curve.
The analysis requires that the preventive maintenance was successfully accomplished on the last performance before deferral and that a 10-year mean time between failure (MTBF) exists for the deferred components.
A 10-year MTBF for flow sensing instrument 2-E21-FS-N006A was arrived at by the licensee using generic data.
The memo clear 13 states that, "this approach was chosen in lieu of site-speci'ic or industry-generic data analysis because the efforts required for 1iose methods are extensive and extremely time i
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It was noted from tables provided in the memo, that the
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decrease in survival probability approximately doubled for the same deferral period if a 5-year MTBF was used. Accordingly, the inspector questioned using an assumed 10-year MTBF for installed instrumentation
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t instead of more specific plant or industry data. This issue, which also
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. involves other safety-related systems, is identified as URI 324/93-10-06:
Deferral Of Preventive Maintenance (Refueling Outage And Greater Frequency) Based On Generic Analysis.
Overall, the inspector concluded that the Unit 2 core spray system would
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be capable of performing its design function and that no undocumented
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deficiencies exist in the system.
Unit 2 Reacto Core Isolation Cooling And High Pressure Coolant Iniection Svstems
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The inspector's review of deferred backlog items did not reveal any
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unreasonable deferrals, with the possible exception of extended preventive maintenance items discussed above. Walkdowns of the HPCI and RCIC components with system engineers identified only minor l
deficiencies, none representing operability concerns. Housekeeping
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problems were apparent, although not excessive. The backside of the
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HPCI pump / turbine installation, which required entry into a contaminated
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area for access, did not meet indicated plant management standards for l
appearance.
l The inspector specifically inspected for visually observable conditions
.i similar to those recently causing turbine overspeed problems at another l
power reactor facility.
Similar conditions were not present, although
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the current shutdown status of HPCI and RCIC prevents a definitive conclusion. The licensee has not experienced unexplained overspeed
problems on either units' HPCI and RCIC turbines for many years.
Overall, the inspector considered the material condition of both Unit 2 systems to be good from a visual perspective.
No major corrective t
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maintenance has been identified on either system since the last Unit 2 refueling outage which was completed in December 1991.
This is due to
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the long duration forced outage, during which these systems have been
idle. Taking industry experience into consideration, the licensee took l
actions during the forced outage to establish lay-up conditions.
These included:
draining the water and steam sides back to the isolation valves; manually rolling the rotating assemblies on a monthly basis; r.nd
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frequently exercising the governor valve linkages and actuators to
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prevent sticking.
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During backlog review for HPCI, the inspector identified that
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WR/JO 90-AAGUI (documenting a problem with the HPCI turbine lube oil cooler temperature indication) represented a condition causing the high lube oil temperature annunciator in the control room to be disabled.
The system engineers stated that since the temperature recorder in the i
control room back panels was unaffected, an operational problem did not exist. The inspector questioned control room operators about the
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disabled annunciator.
The operators did not know the annunciator was disabled, nor could they produce any documentation of this condition.
This represents an unknown operator work-around which could potentially deny operators of critical information needed during HPCI operation.
The annunciator WR/JO was initiated on January 5, 1990. As such, the licensee is investigating the reason why this deficiency has existed for so long.
The inspector noted that all management reviews, including the PN-30 process, had been completed on this item, allowing deferral to post-restart.
Subsequent to the inspector identifying this concern, the licensee changed the status of this corrective maintenance to a startup prerequisite. The inspector noted that a similar condition exists on the same annunciator for Unit 1.
The inspector questioned the existence of other unknown operator work-arounds and what actions would be taken to determine the extent of this problem. The licensee was still evaluating this issue at the close of the inspection period.
Unit 2 Service Water System On February 18, 1993, the inspector walked down the Unit 2 Service Water (SW) system with the system engineer in preparation for the Unit 2
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restart.
The OM&M project manager accompanied the inspector and system engineer during the SW intake and building segment of the walkdown. The
basis of the walkdown was to inspect those items, as identified by the i
IBIR and the System Reference Manual, which would not be completed prior
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to startup. The inspector reviewed the above documents and verified that those items not being completed prior to restart met the requirements specified in PN-30.
Having initiated a major program in 1989 to upgrade the SW system, the licensee put in place an organization to oversee the engineering and implementation of modifications needed for the improvement program.
The system engineer and the project manager discussed the schedule for the completion of those items which would be completed post-restart. The two largest projects are the replacement of the SW piping with copper-nickel piping (scheduled to be completed by early 1996) and the replacement of the SW pumps.
The pump replacement is scheduled to. start in June 1993, and the last pump will be installed by October 1994.
It is the licensee's plan to upgrade the i
sssociated supports with the pump replacement.
The NED analyses and 4tifications for the supports which will be replaced were available
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The inspector did not identify any items during the
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walkdown which had not been previously identified, or which would prevent system operation. Accordingly, the PN-30 process appeared to be i
effective.
Unit 2 Residual Heat Removal System At the time of this inspection, the Unit 2 RHR system was still undergoing considerable maintenance / outage activities, and the
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associated IBIR contained approximately 300 potential work items.
The main focus of the inspection was on the numerous items in the IBIR which l
were designated to be accomplished after Unit 2 restart. Al though hindered by the significant amount of temporary shielding that was still in place, walkdowns of both trains were performed within the Unit 2
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reactor building in order to assess general material condition, as well
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as to better evaluate the licensee's process of work deferral under PN-30. During the walkdown of Train B, indications of minor leakage (i.e.,
brown water stains) from around the RHR 2B pump casing flange were observed by the inspector. As this condition was not reflected by the items listed in the IBIR, the inspector was surprised to see a trouble ticket on the pump relating to said condition.
Subsequent review by the system engineer revealed that the related WR/JO (initiated November 15, 1991) was deleted on October 27, 1992, after being inadequately tied to another WR/JO that was in the process of being deleted at the time of this inspection.
Having been previously determined to be an infrequent momentary condition while pump 2B was idle and pump 2D was operating, the system engineer indicated that it would be appropriately captured
under the RHR pump rebuild WR/J0s he was currently preparing for future outages. There were no other such material issues identified during the
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wal kdowns.
As indicated above, all items intended to be accomplished after Unit 2 restart (i.e., those designated as such in the IBIR, as well as those
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within the rescheduling process) were reviewed by the inspector.
Many items required discussions with the system engineer, as well.as
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evaluation of supporting documentation and test data.
The structural
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and MOV testing expertise of visiting Regional-based inspectors was l
utilized to review such items as the deferral of:
(1) revising the local leak rate test for inboard low pressure coolant injection valves
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2-Ell-F015A and B to reflect the hole recently drilled in their downstream disc (i.e., the valves were tested with the old procedure);
(2) reperforming V0TES testing on valves 2-E11-F007A and F011A; and (3) modifications to long-term qualify 21 RHR system hangers.
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addition to the IBIR, related LERs and the licensee's recently assembled
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RHR System Reference Manual were reviewed to determine if any further issues needed to be addressed before Unit 2 restart.
Like the walkdowns, the reviews discussed above did not reveal any RHR related Unit 2 startup items that were not already identified.
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The inspector's review of RHR related LERs did, however, identify a possible Unit I restart issue.
LER 324/89-09 addressed the June 1989 separation of disc and stem on valve 2-Ell-F017A (outboard low pressure i
coolant injection valve - Train A) due to inadequate engagement of the disc-to-stem locking pin.
As indicated in the LER, valve 2-Ell-F017A
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had been rebuilt in 1986.
The inadequate locking pin engagement was attributed to a procedural deficiency which was corrected following the
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separation event. The inspector confirmed that valve 2-Ell-F017B was subsequently inspected in late 1989 during an unrelated maintenance activity.
However, valve 1-Ell-F017B (last worked in 1988) is currently scheduled to be disassembled because of flow induced noises which are
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believed to be the result of disc and stem separation. As valve 1-Ell-
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F017A was last worked in early 1989, it too may be subject to disc and i
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stem separation.
Acknowledging the inspector's concern, the licensee is awaiting the 1-Ell-F017B inspection results before deciding to inspect
valve 1-Ell-F017A.
This is identified as Inspector Followup Item
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325/93-10-07:
Followup On Potential Disc and Stem Separation On Valves 1-Ell-F017A and B.
Unit 2 Automatic Depressurization System / Safety Relief Valves From March 1-5, 1993, an inspection was performed of the Unit 2 i
ADS /SRVs.
The inspection included a system walkdown with the system
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engineer and a QC inspector, an open items review, and review of past system performance. At the time of the inspection, plant modification
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PM 92-134, Main Steam SRV Solenoid Valve Upgrade, was in progress and the major remaining work activity was re-installation of the SRVs.
Based on the inspection results, the inspector determined that if the identified work scope is satisfactorily accomplished as planned, the
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system would be operational.
The system walkdown consisted of logic and actuation instrumentation panel (P617, 618, 626, 627, and 628) inspections and examination of selected sections of piping and associated supports inside the drywell.
No deficient conditions were observed in the instrumentation panels.
i However, the following deficiencies were identified during the piping walkdown: (1) six snubbers were found with excessive paddle to clamp gaps (Nos. 2B21-llSS344, -34SS298, -58SS281, -6SS25, -34SS338 and 2E51-4SS101); (2) the paddle on snubber 2B21-59SS330 was bound in the support clamp; and (3) variable spring support No. 2B21-27VS265 had no scale
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attached.
Excessive gaps have been previously discussed in Inspection
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Report 50-325,324/91-32 and associated correspondence. As a result, l
revision 8 to PT-19.0.52, VT-3/VT-4 Examination Of Component Supports,
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was implemented on July 24, 1992, to address gap as an inspection item.
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Thus, during future implementations of PT 19.0.52 excessive gap will be identified and corrected. The acceptability of incorporating the
identification and correction of excessive gaps in the normal inservice test program was based upon EER 91-0407. This EER justified, by use of plant data, that excessive gap had not caused snubber failures; therefore, immediate corrective actions were not deemed necessary.
Accordingly, work requests were initiated to add washers / spacers to the six snubbers in order to adjust the gap within the tolerances of PT-
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19.0.52 during the next refueling outage. An EWR was initiated to evaluate the operability of the snubber with the bound paddle. A i
subsequent inspection of snubber 2B21-59SS330 by engineering personnel determined that the snubber was tight with a small angle of movement (i.e., not bound).
Based upon previous experience, the engineer thought
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that the snubber was operable; however, at the end of the report period i
a calculation was being developed to confirm that the snubber would remain operable during a seismic event, as well as after piping thermal growth following a SRV lift.
If the calculation does not demonstrate operability, this item will be addressed prior to restart.
A work request was initiated to replace the scale on the variable spring support.
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The inspector reviewed items identified on the IBIR, as well as
outstanding NED " blue memos," direct replacements, FACTS action items, non-FACTS technical support action items, work requests, and
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surveillance schedules to verify that items required to be performed prior to restart had been identified and scheduled.
From this documentation, the inspector determined that all items required for system operability had been or would be addressed prior to startup. As part of the IBIR review, the inspector reviewed PM 92-134.
Successful performance of the PM acceptance test, coupled with the successful completion of scheduled instrumentation calibrations and logic functional testing, will be adequate to demonstrate ADS operability after the modification is completed and the SRVs are re-installed.
In addition, historical documents were reviewed for undesirable trends or conditions. This review involved completed work requests from January 1,1990 to the present, as well as previously performed surveillance tests and calibrations.
No adverse trends were detected.
8.
Onsite Review Committee (40500)
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 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 completed.
There were no concerns identified relative to the PNSC meetings attended.
The resolution of safety issues presented during these meetings was considered to be acceptable.
Violations or deviations were not identified.
9.
Emergency Preparedness Program (82701)
TSC/ EOF Building Emergency Diesel Generator The lack of a formal maintenance and testing program for the TSC/ EOF standby diesel was identified by the licensee and documented in ACR 92-827 on October 16, 1992.
During a routine emergency preparedness inspection in February 1993, it was found that no action had been taken to address this deficiency and that maintenance had requested two extensions on responding to the ACR. After questioning by a Regional Inspector, the licensee contracted the diesel vendor who performed an inspection, " major tuneup" and servicing on this unit. This work consisted of the following:
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e Replaced water seals
Replaced fuel and oil lines
Replaced day tank fuel filter
Replaced injectors
Set valves, injectors and fuel racks to factory specification
Replaced fuel injection jumper lines
Replaced thermostats and seals
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e Replaced water pump Installed isolation valves for engine block heaters e
e Replaced cooling water hoses e
Primed and pressure tested fuel system o
Chemically flushed cooling water system e
Pressure tested cooling water system o
Cooling water system drained and refilled with 50/50 water / antifreeze mixture after chemical flushing Lube oil system drained and refilled with new oil with sample of
old oil sent to laboratory for analysis Replaced crankcase drain line and installed shutoff valve e
Tested engine block heaters e
Pressure washed and cleaned exterior of radiator Changed primary and secondary fuel filters e
Replaced fan and alternator belts
e Reassembled removed parts with new gaskets l
Tested all engine shutdown drives
- low oil pressure
- high water temperature
- high oil temperature
- high crankcase pressure
- overspeed Load testing with TSC/ EOF building loads e
The inspector observed selected portions of the above work, discussed past maintenance, and after work completion conditions of the emergency diesel generator with the vendor and licensee maintenance personnel.
Based on the above work, it appears that the engine and auxiliaries are now in good mechanical condition.
The inspector observed selected portions of a scheduled four hour full load (300 KW) run on the DG, conducted March 1.
After startup and small injector adjustment, the engine performed well. Approximately 2 1/4 hours into the run the mechanics found that the engine mounted fuel oil l
tank was extremely low.
Rather than run out of fuel the engine was shutdown.
Investigation determined that the engine fuel oil transfer
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pump did not provide sufficient flow from the inground storage tank to the engine mounted tank. The test was aborted and a decision made to replace the pump with a larger capacity one. The licensee anticipated receipt and installation of this component during the week of March 8.
Vendor training of licensee maintenance personnel was also conducted during the week of March 1.
The inspector will verify that the larger capacity pump is installed and that a preventive maintenance program is established for this unit prior to Unit 2 restart. This item will be tracked as an Inspector Followup Item, TSC/E0F Diesel Generator Deficiencies, 325,324/93-10-04.
Violations or deviations were not identified.
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10.
Action on Previous Inspection Findings (92701) (92702)
Work Control Process The licensee's efforts to improve the work control process and implementation of the process are continuing.
Based on frequent recurrence of work control problems, corrective actions in this regard are not yet fully effective.
Due to similarities of topic or root cause, the following open items are closed with one item remaining open to track the overall work control process issue.
(Closed) Violation 324/91-01-01, Failure to meet procedure requirements with regard to performing shutdown calibration while at power.
(Closed) Violation 324/91-06-02, Failure to use approved procedure for performance of diesel repair resulting in damage to DG-1 camshaft.
(Closed) Violation 324/91-06-03, Failure to follow procedure and perform adequate double verification.
(Closed) Violation 325,324/91-26-01, f ailure to follow procedure and perform adequate independent verification with regard to DG-3 maintenance and RHR system operation, respectively.
(Closed) Violation 325,324/92-01-01, Inadequate procedure with regard to DG cleaning.
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(Closed) LER l-91-26, Unit I shutdown due to expiration of DG LCO.
(Same event as Violation 325,324/91-26-01 above.)
(Closed) Violation 325/91-16-01, Performing maintenance without written instructions /WR/JO resulting in inadvertent HPCI isolation.
(Closed) LER 1-91-14, HPCI isolation due to steam leak detection module maintenance.
(Same event as Violation 325/91-16-01 above.).
(0 pen) Violation 325,324/92-44-01, Damage to RHR valve operators by overtorquing handwheels due to an inadequate procedure and failure to stop work. This item will remain open to track the overall corrective actions on the work control process.
Other Violations (0 pen)
Violation 325,324/92-11-01, Requirements Of TS 3.7.2 Were Not Met In That One Control Room Emergency Filtration System Was Inoperable For More Than Seven Days. Specifically, on April 13, 1992, the resident inspectors identified that the 2A control building emergency air filter was found to be not fastened on one side; thereby rendering it
seismically inoperable.
Consequently, this initial installation
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condition resulted in train 2A of the control room emergency filtration
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system being inoperable since initial plant operation. This problem, which had gone undetected by the licensee during related seismic evaluations / inspections in October 1987 and April 1992, was subsequently corrected.
l Corrective actions encompassed by the licensee's June 24, 1992 violation response and associated LER 2-92-03 (Revision 1) included:
(1) emphasizing comprehensive field inspections / engineering evaluations j
through revisions to ENP-12 (Engineering Evaluation Procedure), DG-II.20 j
(Design Guide For Civil / Structural Operability Reviews) and DG-III.16 (Brunswick Nuclear Project Structural Scope Documents For Various Verification Programs); (2) training Technical Support and NED personnel on the aforementioned revisions; and (3) performance of inspections to resolve similar structural issues (including welds and other equipment mounting methods) during the Unresolved Safety Issue (USI) A-46 Inspection / Evaluation Program. The inspector confirmed that actions (1) and (2) above were performed as committed except that the training of NED personnel was still in progress. The results from third-party STSI equipment walkdowns and program reviews (including field validations of critical assumptions) will be inspected prior to Unit 2 startup under CAL 50-324/92-01, and Violation 325,324/92-11-01 will remain open pending completion of the aforementioned NED training.
LER 2-92-03 is considered closed.
(Closed) Violation 325,324/92-15-02, Failure To Maintain Adequate Procedural Controls Over Plant Systems (two examples).
In the first example, a surveillance test was accomplished on Drywell Cooling Unit IA l
without the test receiving the prerequisite reviews specified by paragraph 5.8.4 of POM Volume I, Book I.
In the second example, complete instructions were not provided for starting a RHR pump in OP-17 as required by Appendix A to Regulatory Guide 1.33.
The inspector reviewed the licensee's corrective actions provided in a letter dated August 3, 1992. The corrective action for the first example consisted of changes to plant procedures to more clearly define Special Procedures and the circumstances for their use; to limit the
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ability of a planner to specify steps for testing in a WR/J0; and to
provide guidance on failed MSTs.
The inspector verified that the
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corrective actions specified in the response were implemented.
Specifically, the inspector reviewed OMMM-001, OMMM-002, OMMM-003 and OMMM-013 and concluded that these revised procedures contain adequate steps to prevent recurrence.
For the second example, the licensee committed to evaluation and enhancements (as necessary) of procedural guidance provided to operators for swapping running equipment.
Based on this evaluation, the licensee revised 01-01, Operations Principles and Philosophy, and six ops.
The inspector concluded that the commitments of the response were met.
Furthermore, the inspector reviewed the revised procedures and concluded that adequate guidance now exists to prevent a recurrence of the second example.
This violation is considered closed.
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11.
Review of Licensee Event Reports (92700)
i losed) LER 2-92-008, Failure To Meet TS Required Number Of Operable C
NSW Pumps Due to a SW Piping Leak.
This October 19, 1992 event involved a corrosion induced through-wall leak which developed on the Unit 2 EDG jacket water cooler SW supply line. With both units in cold shutdown and all four EDGs already considered inoperable (due to seismic issues on interior EDG building walls) applicable TS actions had already been taken. As further addressed in the closure of related URI 325,324/92-34-02 (see Inspection Report 52-325,324/93-01), a permanent code repair to the subject pipe was made and UT inspections were performed on other susceptible locations on the 18-inch carbon steel, cement lined SW piping.
In addition, the SW supply and discharge lines to the EDGs are scheduled to be replaced with copper-nickel piping prior to the end of Refueling Outage #10 for Unit 1.
(Closed)
LEF,2-92-03, Control Building Emergency Air Filtration Base Bolting Found Outside Design Basis.
(See related violation 92-11-01 discussed in paragraph 9 above.)
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Corporate Improvement Initiatives 12.
l The licensee revised the structure of the Nuclear Generation Group at the three nuclear sites.
This new organization is shown on Attachment 1.
13.
Exit Interview (30703)
The inspection scope and findings were summarized on March 5 and 12, 1993 with those persons indicated in paragraph 1.
The inspectors described the areas inspected and discussed in detail the inspection findings listed below and in the summary.
Dissenting comments were not received from the licensee.
Proprietary information is not contained in this report.
Item Number Description / Reference Paragraph 325,324/93-10-01 NCV - Failure to post NOVs involving radiological working conditions, paragraph 4.
325,324/93-10-02 IFI - Seismic qualification of CAC systems, paragraph 4.
325,324/93-10-03 IFI - Molded case circuit breaker replacement, paragraph 4.
325,324/93-10-04 IFI - TSC/E0F diesel generator deficiencies, paragraph 9.
324/93-10-05 NCV - Failure to properly calibrate core spray system instrumentation, paragraph 7.
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i 324/93-10-06 URI - Deferral of preventive maintenance (refueling outage and greater frequency) based
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on generic analysis, paragraph 7.
325/93-10-07 IFI - Followup on potential disc and stem separation on valves 1-Ell-F017 A and B, paragraph 7.
14.
Acronyms and Initialisms ACR Adverse Condition Report
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AI Administrative Instruction A0 Auxiliary Operator
BNP Brunswick Nuclear Project l
CAC Containment Atmospheric Control i
CAL Confirmation of Action Letter CB Control Buildinc l
CP&L Carolina Power & Light Company CRD Control Rod Drive CWIP Circulating Water Intake Pump DG Diesel Generator DHL Decay Heat Level
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DHR DecLy Heat Removal DTOP Design Turnover Project EDG Emergency Diesel Generator EER Engineering Evaluation Report ENP Engineering Evaluation Procedure
EOF Emergency Operations facility E0P Emergency Operating Procedure E&RC Environr. ental and Radiation Control ESF Engineered Safety reature GDC General Design Cn terion HP Health Physics HPCI High Pressure Coolant Injection l
HVAC Heating Ventilation and Air Conditioning I&C Instrumentation and Control IFl Inspector Followup Item LC0 Limiting Conditions for Operation iER Licensee Event Report SCI Low Pressure Coolant Injection MAC Minor Adverse Condition MCC Motor Control Center MMM Maintenance Management Manual MST Maintenance Surveillance Test
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NAD Nuclear Assessment Department NCV Non-Cited Violation NDE Non Destructive Examination NED Nuclear Engineering Department NEMA National Electrical Manufacturers' Association NOV Notice of Violation NRC Nuclear Regulatory Commission NRR Nuclear Reactor Regulation
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NSD Nuclear Services Department NSW Nuclear Service Water
Operating Instruction OM&M Outage Management & Modification OP Operating Procedure PA Protected Area PNSC Plant Nuclear Safety Ccmmittee QC Quality Control RCIC Reactor Core Isolation Cooling RG Regulatory Guide
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RTGB Reactor Turbine Generator Board SCO Senior Control Operator
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SRA Shutdown Risk Assessment
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SRV Safety Relief Valve SSE Safe Shutdown Earthquake STA Shift Technical Advisor STSI Short Term Structural Integri j SW Service Water
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TI Temporary Instruction TS Technical Specification TSC Technical Support Center
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URI Unresolved Item USI Unresolved Safety Issue UT Ultrasonic Testing
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WR/JO Work Request / Job Order
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