IR 05000324/1990007
| ML20012E465 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 03/23/1990 |
| From: | Dance H, Ruland W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20012E464 | List: |
| References | |
| TASK-2.F.2, TASK-TM 50-324-90-07, 50-324-90-7, 50-325-90-07, 50-325-90-7, NUDOCS 9004050210 | |
| Download: ML20012E465 (22) | |
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NUCLEAR CECULATCRY COMMC^1:N
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101 MAHIETTA STREET.N.W.
ATLANTA. OEoRGI A 30323 I
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Report No. 50-325/90-07 and 50-324/90-07 L
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Licensee:
Carolina Power and Light Company F
'P. O. Box 1551-Raleigh, NC 27602 L
Docket No. 50-325 and 50-324 License No. DPR-71 and DPR-62
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Facility Name:
Brunswick 1 and 2 t
. Inspection Conducted:
February 1 - March 2,1990 3 h
Inspector:
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'W. H. Ruland
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.Other Inspectors:
R. E. Carroll (February 26 - March 2)
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W. Levis
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D. J. 141 son
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' Approved By:
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H. C.. Dance, Section Chief Date Sidned s
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Division of Reactor Projects
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SUMMARY
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This routine safety inspection by the resident inspectors involved the areas of
maintenance observation, surveillance observation, operational safety
iverification, Engineered Safety Feature System walkdown, TMI Action Item
l II.F.2.3.B onsite Licensee Event Reports (LER) review, in office Licensee e
Event Reports review - Unit 1, action on previous inspection findings, and startup from refueling - Unit 2.
Results:
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- In the areas inspected, one non-cited violation was identified - failure to
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follow. procedure WP-18 covering rigging from plant piping.
The licensee found
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evidence'that a 1-1/2 inch reactor vessel instrument variable leg pipe was used
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While the drywell closecut I
' properly found this problem and other deficiencies, it pointed to a weakness in
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certain work controls.
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l The HPCI systems were found operable during a system walkdown.. Minor L.
deficiencies were noted that were not safety significant.
Licensee actions to l
resolve operability concerns of the RWCU leak detection system were prudent.
Some deficiencies were noted in the initial compensatory measures taken.
9004050210 900323
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The. inspectors! reviewed status < of startup preparations for Unit 2.
The
- inspectors found that proper training and procedure revision had occurred for
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. modifications performed this outage.
Weaknesses-were noted in the areas of
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t work control and inaccessible space closeout, r
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The licensee's closeout of issues, based on a review of LERs and inspector n
followup' items,-was proper.
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REPORT DETAI'LS
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1.
Persons Contacted s
Licensee Employees K. Altman, Manager - Engineering Projects
"F. Blackmon, Manager - Operations
- S. Callis, On-Site Licensing Engineer T. Cantebury, Manager - Unit 1 Mechanical Maintenance
- G. Cheatham, Manager - Environmental & Radiation Control M. Ciemnicki, Security R. Creech, Manager - Unit 2 1&C Maintenance J. Cribb, Manager - Quality Control (QC)
- C. Gray, Supervisor - Materials and Control Service
' V. Grouse, Employee Relations
- J. Harness, General Manager - Brunswick Nuclear Project
- J. Harrell, Manager - Projects
- W. Hatcher, Supervisor - Security A. Hegler, Supervisor - Radwaste/ Fire Protection
- R. Sielme, Manager - Technical Support
'J. Holder, Manager - Outage Management & Modifications (OM&M)
L. Jones, Manager - Procurement
- M. Jones ~, Manager - On-Site Nuclear Safety - BSEP R. Kitchen, Manager - Unit 2 Mechanical Maintenance J. McKee, Manager - QA
- J. Moyer, Technical Assistant to Plant General Manager
- P. Musser, Manager - Maintenance Staff
- R. Oates, Principal Engineer - Licensing
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- J. O'Sullivan, Manager - Training l
- R. Poulk, Supervisor - Regulatory Compliance W. Simpson, Manager - Site Planning and Control
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S. Smith, Manager - Unit 1 I&C Maintenance i
- R. Starkey, Vice President - Brunswick Nuclear Project I
- R. Warden, Manager - Maintenance B. Wilson, Manager - Nuclear Systems Engineering i
L Other licensee employees contacted included construction craf tsmen, engineers, technicians, operators, office personnel, and security force members.
- Attended the exit interview Note:
Acronyms and abbreviations used in the report are listed in the last paragraph.
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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
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codes and standards. The inspectors also verified that:
redundant components were operable; administrative controls were followed; tagouts were adequate; personnel were qualified; correct replacement 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 require-ments were implemented.
The inspectors independently verified that selected equipment was properly returned to service.
Outstanding work requests were reviewed to ensure that the licensee gave priority to safety-related maintenance.
The inspectors observed / reviewed portions of the following maintenance activities:
89-QDF472 OPM-M0-504 on 1, 2 SW-V211 - Mechanical Inspection and Lubrication of Limitorque Operators 90-AEFU1 2-E41-F001 Disassemble, Inspect / Repair, Reassemble 90-AEHX3 1A Nuclear Service Water Pump - Repair of Lube Water Line a.
Inadequate Work Controls The inspector witnessed maintenance activities on the IB RHR pump on February 12, 1990.
The maintenance items scheduled were a lubrica-tion check, visual inspection of external components, and surge ring bracket inspection.
The pump motor was not placed under clearance r
for these. work items.
The work order for the surge ring bracket inspection, WR/JO 90-UKE 055, specified that the work be performed in accordance with OPM-M502.
The inspector noted that, in Sections 3 and 4 of OPM-M502, Revision 0, the motor being inspected was required to be placed under clearance.
The inspection is performed by removing the ventilation screens from the motor and inspecting the surge ring brackets using an inspection mirror.
Based on this inspection method, the inspector felt that a clearance was appropriate.
The inspector asked the workers why the motor was not placed under clearance as required by their procedure.
Based on the inspector's question, maintenance did not perform the surge ring bracket inspection.
They performed the other scheduled maintenance items that did not require a cleara ue.
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The licensee has issued an NCR to address this work control discrepancy.
Since the procedure which required the equipment clearance was not performed, no violation occurred.
The inspector will monitor the closeout of the NCR in future routine inspections.
b.
Improper Use of Instrument Line for Rigging Attachment On February 10, 1990, during Unit 2 drywell closecut inspections, the licensee discovered evidence that a variable leg sensing line for reactor water level instrumentation had been used as a rigging point during the outage.
The evidence consisted of a one-half inch wire rope still attached to the line and numerous nicks and surface defects in the line, apparently caused by the wire rope. The sensing line is a one and one-half inch horizontal line and penetrates the reactor vessel at nozzle N16B.
The rigging point was less than 18 inches from the vessel nozzle.
The affected portion of the line is approximately one foot long located between two socket welds. At the end opposite the reactor vessel, the lino runs several feet prior to the next support.
Brunswick Construction Work Procedure WP-18 Temporary Rigging and Scaffolding, Revision 1, provides guidelines for rigging from permanent plant components.
This apparent rigging configuration violates numerous restrictions in WP-18.
Rigging from pipe less than three inches in diameter is
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prohibited.
Rigging from instrument lines is prohibited.
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Only non-metallic or synthetic web chokers should be used in
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cases where it is necessary to wrap around the component being loaded.
Pipe spans being rigged from must not be adjacent to equipment
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nozzles.
Additionally, a Temporary Rigging / Scaffolding Release form was not completed. Therefore, the actual loading condition, i.e., weight and direction, is unknown.
Technical Specification 6.8.1.a. requires that written procedures shall be established, implemented, and maintained covering the activities recommended in Appendix
"A" of Regulatory Guide 1.33, November 1972, including procedures for performing maintenance.
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stated above, numerous requirements of WP-18 were not implemented.
Therefore, this is a violation of TS 6.8.1.a: Work Procedure WP-18, s
Temporary Rigging and Scaffolding, Was Not Properly Implemented (324/90-07-02).
This licensee identified violation is not being cited because criteria specified in Section V.G.1 of the NRC Enforcement Policy were satisfied.
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The licensee initiated NCR 90-014 to document the condition.
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90-ACYW1 was initiated, identifying the nicks and surface defects which were subsequently removed with no pipe minimum wall thickness violations.
A reactor hydrostatic test was conducted on Februsry 13, 1990.
- During the test, the reactor vessel and recirculation system, i
including the affected instrument sensing line, were held at test pressure of 1100 psig for approximately eighteen hours.
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following day the inspector discovered water droplets hanging from
the line in the area between the socket welds where the rigging had
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been attached.
This was also seen by a Technical Support person. A small puddle was located just below the line on a support. No other water was in the vicinity.
The line was covered from above by another support.
Therefore, the water could not have dripped from overhead.
The inspector estimates that there was less than ten milli 11ters of water.
The water was wiped off and none additional was observed several hours later. During this time, reactor pressure was 900 to 950 psig.
The licensee conducted two independent liquid penetrant inspections of the area between and including the socket welds.
No through wall indications were evident, but no source of water other than through wall leakage could be determined. Technical Support Memorandum 90-0093 evaluated the condition as acceptable based on the original indications being less than.005 inch and not indicative of a heavy load.
To remove the indications. 010 to.013
inches of metal removal was required.
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The licensee considered performing further inspections of the line at normal operating pressure (1000 psig) after unit startup, but determined that expected dose levels were prohibitive during operation.
The licensee confirmed at the exit that they plan to inspect the line for evidence of leakage during the first unit
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shutdown that includes a drywell entry.
One non-cited violation and no deviations were identified.
3.
SurveillanceObservation(61726)
The inspectors observed surveillance testing required by technical specifications.
Through observation, interviews, and record review, the inspectors verified that:
tests conformed to technical specification Wquirements; administrative controls were followed; personnel were qualified; instrumentation was calibrated; and data was accurate and
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complete. The inspectors independently verified selected test results and proper return to service of equipment.
The inspectors witnessed / reviewed portions of the following test activities:
MST-HPCl24Q Unit 1 HPCI Steam Leak Detection Channel Calibration.
E41-TS-N602 A and B
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MST-HPCI25Q Unit 1 HPCI Steam Leak Dctection Channel Calibration, l
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E41-TS-3314, 3315, 3354, 3316, 3317, 3318, 3488 and i
3489 MST-RCIC14M Unit 1 RCIC Steam Leak Detection Channel Functional Test PT-14.2-1 Unit 2 Scram Response Time Test i
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SP-89-051 DG-3 E Bus Energization Response Time Test Violations and deviations were not identified.
4.
Operational Safety Verification (71707)
r The inspectors verified that Unit 1 and Unit 2 were operated in compliance with technical specifications and other regulatory requirements by direct observations of activities, facility tours, discussions with personnel, reviewing of records and independent verification of safety system status.
The inspectors verified that control room manning requirements of 10 CFR 50.54 and the technical specifications were met.
Control operator, shift supervisor, clearance, STA, daily and standing instructions, and jumper / bypass logs were reviewed to obtain information concerning
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operating trends and out of service safety systems to ensure that there were no conflicts with Technical Specifications Limiting Conditions for Operations.
Direct observations were conducted of control room panels, instrumentation and recorder traces important to safety to verify operability and that operating parameters were within technical specification limits.
The inspectors observed shift turnovers to verify that continuity of system status was maintained.
The inspectors verified the status of selected control room annunciators.
Operability of a selected Engineered Safety Feature division was verified weekly by insuring that:
each accessible valve in the flow path was in its correct position; each power supply and breaker was closed for components that must activate upon initiation signal; the RHR subsystem cross-tie valve for each unit was closed with the power removed from the valve operator; there was no leakage of major components; there was proper lubrication and cooling water available; and a condition did not exist which might prevent fulfillment of the system's functional requirements.
Instrumentation essential to system actuation or performance was verified operable by observing on-scale indication and proper instrument valve lineup, if accessible.
The inspectors verified that the licensee's health physics policies /
procedures were followed.
This included observation of HP practices and a review of area surveys, radiation work permits, posting, and instrument calibratio w f
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The inspectors verified that:
the security organization was properly manned and security personnel were capable of performing their assigned functions; persons and packages were checked prior to entry into the i
protected area; vehicles were properly authorized, searched and escorted within the PA; persons within the PA displayed photo identification badges; personnel in vital areas were authorized; effective compensatory i
measures were employed when required; and security's response to alarms was adequate.
The inspectors also observed plant housekeepir,g controls, verified
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position of certain containment isolation valves, checked a clearance, and verified the operability of onsite and offsite emergency power sources.
The licensee's RWCU system engineer identified a potential concern on February 9,1990 regarding the operation of the RWCU leak detection system.
Specifically, the leak detection system was not able to detect or isolate a leak or break in RWCU piping from downstream of flow element FE-N040 to the MSIV pit penetration.
This piping is 4" in diameter and is approximately 100. feet in length.
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The licensee believes that this break is bounded by existing HELB analyses.
Until the evaluation can be formally completed and documented by NED, the following compensatory measures were put in place:
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o Information was provided to operations personnel regarding how such a leak could be detected with existing alarms and indications.
o At least one filter domineralizer flow controller must be left in manual.
o Periodic visual inspection of the piping by a fire watch who is posted in the area.
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The inspectors questioned the adequacy of some of the above measures.
The inputs for the alarm, which the operators were instructed to monitor, had not been calibrated recently.
Of the four imputs to the alarm, three had not been calibrated since 1983 and the other was last calibrated in 1988.
In addition, it was not clear to the inspectors what size leak would be required to cause the annunciators to alarm.
Subsequent to these initial actions, the licensee also installed a chart recorder on the 50 foot elevation in the Reactor Building which measures the temperature at 8 points along the RWCU pipe, 6 downstream of the flow orifice and 2 upstream of the F004, the outboard isolation valve.
If the temperature exceeds the alarm setpoint, the recorder will alarm locally and also cause an alarm in the control room.
The inspectors were satisfied with the licensee's actions to resolve this issue including the compensatory measures currently in place.
The only I-
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i deficiency noted was that the initial compensatory measures should have been examined more thoroughly.
Overall, however, the licensee took all
the steps that the NRC would expect a prudent licensee to take to resolve an emergent issue.
Violations and deviations were not identified.
5.
Engineered Safety Features System Walkdown (71710)
The inspector completed an engineered safety features system inspection that was begun during the last reporting period and addressed in Inspection Report No. 90-02.
The selected system was HPCI.
Physical verification of accessible Unit 2 HPCI local and remote valve and breaker positions revealed no discrepancies with actual position versus
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the required standby lineup pcsition in the HPCI Operating Procedure OP-19, Revision 65, except for known abnormal lineups due to clearances associated with outage work.
However, during the walkdown, the inspector
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discovered two minor lineup discrepancies:
The local control switch for valve 2-E41-F002 is not included in the
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OP-19 electrical lineup.
Similar switches for other components are included.
The switch is spring-return to the correct position.
Therefore, the inspector does not consider this discrepancy to be st'ety significant.
Two valves appeared to have their identification labels switched.
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Either E41-V1 and E41-V2 (root valves to instruments E41-PI-R004, E41-PT-N019 and E41-PS-N010, E41-PSH-N031, respectively) or E41-IV-773 and E41-IV-774 (drain valves to the above instruments)
were interchangeo, i.e., the instrument root valves and drain valves did not match.
Due to complex piping runs, the inspector did not follow the lines to the instruments to determine which valves were labeled incorrectly.
The root valves and drain valves have the same required position.
Therefore, the mislabeling is not safety significant.
The inspector identified a minor drawing discrepancy on the Unit 1 and 2 HPCI system piping diagrams, drawings D-25023 sheet 2, Revision 33, and D-02523 sheet 2, Revision 30, respectively.
Suppression pool level switches E41-LSH-N015A and B are shown as differential pressure instruments but are actually float switches with significantly different instrument piping configurations.
No safety significance is associated with this discrepancy.
The inspector informed the system engineer of this problem.
During a walkdown in the Unit 2 HPCI roof area, the inspector noted significant air leakage on the valve actuators of both E41-F028 and E41-F029, inboard and outboat d drain valves to the steam supply drain po L
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t The air leakage necessitated actuator overhauls.
Had the air leakage continued unnoticed and worsened such that one or both of the valves r
failed clot.ed, the drain pot level would increase and alarm on high level.
Manual valve operation would then be required to prevent HPCI from
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becoming inoperable.
Required maintenance items such as this should be
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identified by the licensee instead of by the inspector at the end of an outage, t
Other ger.eral discrepancies:
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The Unit 1 HPCI skid area contained numerous fasteners without full
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thread engagement, although none appeared to be on high pressure lines.
The system engineer was informed of this item.
Miscellaneous loose hangers on small bore pipe.
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Unit 2 condensate storage tank level instrumentation - numerous valve
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labels missing.
Some valve descriptions on labels were significantly different than
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the description in the OP-19 valve lineup.
For example, 1-E41-F047 and 1-E41-V59 are listed on OP-19 as " Exhaust Drain Pot Drain Line Inboard and Outboard Test Valve", respectively, but both are labeled as " Test Line Valve Upstream of F022."
A Unit 1 HPCI toom carbon dioxide fire suppression pipe support was
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broken out of the concrete wall.
The NRC does not consider these minor problems to be safety significant, but are typical of the problems reported whenever the inspector conducts a
detailed ESF system walkdown.
Problems of a similar nature were found during the last two walkdowns on RHR and core spray systems.
The inspector notes that the licensee is continuing its label plate improvement program and since December 1989, has hung over 4600 new
stainless steel valve tags with approximately 1500 ready to be hung.
None of the above-mentioned labeling deficiencies involved new labels.
In addition to valve tags, approximately 1500 miscellaneous equipment labels have been made/ hung.
Violations and deviations were not identified.
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TMI Action Item (25565)
(CLOSED)
ltem II.F.2.3.B Install Level Instruments for Detection of Inadequate Core Cooling.
This item was previously inspected in inspection reports 85-38, 85-25 and 85-24.
This requirement is also addressed in GL-84-23.
This generic letter outlined the importance of reactor vessel water level instrumentation in BWRs.
Two improvement categories were
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proposed that would result in increased assurance that the level instrumentation will provide the instrumentation for the inadequate core cooling required by NUREG-0737, Item II.F.2.
The Brunswick units had already implemented one improvement, replacement of mechanical level indication equipment with analog level transmitters.
The second improvement suggested modifications to reduce level indication errors caused by high drywell temperature.
This has been implemented for the Brunswick units by installation of plant modifications 1-86-007 and 2-86"008, which installed two uncompensated condensing chambers in the drywell and routing the reference legs outside containment, minimizing the vertical drop in the drywell.
The vertical drop in the drywell was reduced from approximately 222 inches to 24 inches.
This reduced vertical drop will reduce reactor water level indication error resulting from high drywell temperatures and thus ensure indication of an approach to inadequate core cooling.
The inspector reviewed the completed plant modification packages, walked down the portion of the reference legs external to the drywell, walked down the Unit 2 reference legs inside containment, and reviewed emergency operating procedures that direct the use of level instrumentation on the new reference legs during elevated drywell temperature conditions.
No discrepancies were noted.
Violations and deviations were not identified.
7.
Onsite Review of Licensee Event Reports (92700)
The below listed LERs were reviewed to verify that the information provided met NRC reporting requirements.
The verification included adequacy of event description and corrective action taken or planned, existence of potential generic problems and the relative safety significance of the event.
Onsite inspections were performed and concluded that necessary corrective actions have been taken in accordance with existing requirements, license conditions and commitments, unless otherwise stated.
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(CLOSED)
LER 1-87-01 (Revision 1), Failure of Unit 1 HPCI System Turbine Steam Supply Valve E43-F002 to Open.
As discussed in inspection report 87-03, the failure of valve E41-F002 to open on demand was attributed to a generic failure of the auxiliary contact adder block (CR 205 series device).
A review of records related to Revision 1 of the LER and an October 30, 1987 Part 21 report, which was supplemented on December 15, 1989, confirmed that, with the
excepti on of 1-E11-F073, all Unit I and Unit 2 CR 205 series
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auxiliary contact adder blocks used in safety-related applications have been replaced with CR 305 series auxiliary contact adder blocks or new Westinghouse components.
The appropriate modification to 1-E11-F073 is scheduled for completion during the upcoming Unit I refueling outage.
Replacement of the CR 205 series auxiliary contact
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i adder blocks for those non-safety-related applications
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(per OSPP-BKR003 and OPM-BKR003) is being performed during normal
r corrective and preventive maintenance activities when necessary.
Licensee actions regarding limited failures of older CR 305 series
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auxiliary contact adder blocks, encountered during CR 205 replacement-l activities for non-safety-related applications (IFI 325,324/8815-04),
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were reviewed and documented as being appropriate in inspection
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report 89-02, t
b.
(CLOSED)'
LER 1-87-11. Safety Relief Valves' Setpoints Exceeded During Testing at Wyle Laboratories. A review of the March 1987 Wyle Laboratories notices of anomaly to CP&L confirmed that eight of i
eleven SRVs had failed the + 1 percent set pressure test, with one of
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the eight failing to actuat'e at maximum test pressure.
The primary
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cause of the failures was attributed to corrosion induced pilot t
disc-to-seat bonding.
Since the licensee continues to pursue this
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SRV failure mode with the BWR Owners Group, the ADS and manual initiation functions of the SRVs were apparently not affected, and the average SRV setpoint drift was within a sufficient margin for
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reactor over-pressure protect 10n, the inspector has no further questions.
c.
(CLOSED)
LER 1-87-15 Unplanned Primary Containment. Group 1
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Isolation and RPS Trip Signal During Testing of MSIV Closure /RPS Trip
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Function.
This event resulted from a technically deficient revision i
to MST-RPS22R.
The inspector verified performance of the specified corrective actions (i.e., revision of both units' MSTs and event review by maintenance procedures group) and had no additional questions.
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d.
(CLOSED) LER 1-87-16, Late Performance of Reactor Power IRM Detector I
Position Control Rod Block Functional Test.
The inspector reviewed the circumstances surrounding the missed performance of Periodic Test
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PT-01.10. Selected training and related procedural change documenta-
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tion was reviewed to verify completion of corrective actions.
e.
(CLOSED)
LER 1-88-26 Unplanned Unit 1 Groups 3, 6 and 8 Isolations Due to Momentary Loss of Power to Units 1 and 2 Common Emergency Bus E-2.
The lack of an adequate jumper connection combined with other
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plant modification work in progress resulted in a momentary loss of power to emergency bus E-2 and the subsequent grou) isolations. The licensee has experienced other events due to tie inadequate
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installation of jumpers as described in LERs 2-83-52, 2-87-12 2-88-04 and 2-88-17.
Training for the appropriate maintenance I
l personnel has been conducted to stress the importance of proper test l
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' equipment attachment.
In addition, the flat headed or oval headed i
screws used for the alligator clip attachments are being replaced
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with banana jack to ring lug connectors.
These connectors are
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presently being installed in mild environment locations for Unit 2
and are scheduled for installation in Unit I during its next refueling outage.
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(CLOSED)
LER 2-87-11, Division I Primary Containment Group 5 Isolation of RCIC System Due to Spurious Actuation of Steam Leak
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Detection Instrumentation.
Based on a review of associated licensee actions and results, the inspector considers the licensee's
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conclusion of a spurious actuation to be appropriate, g.
(CLOSED)
LER 2-87-12, Unplanned Division I Primary Containment
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Group 5 Isolation of Reactor Core Isolation Cooling (RCIC) System While Installing Electrical Jumper During RCIC Surveillance Testing.
On December 7, 1987, the RCIC System turbine steam supply inboard primary containment valve auto-closed on an A logic, Division 1
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primary containment Group 5 isolation signal.
At the time,
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performance of the channel calibration and functional test of the RCID isolation instrumentation was in progress.
The inadvertent isolation occurred when an alligator clip attached to an electrical jumper slipaed off a terminal making niomentary contact with the nearby terminal of an RCIC isolation instrument.
The jumper was then reinstalled and the RCIC was returned to standby the same day. The licensee, in response to this event, conducted real time training
during January,1988.
The lesson objectives cautioned personnel to
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ensure alligator clips are insulated, the proper size, and not worn.
The licensee also plans to install banana jacks in non-environmentally
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qualified cabinets, so alligator clips do not have to be used in tight spots.
The licensee controls the installation of the jacks under EER 89-0186, and WR/J0s.
The inspector verified that the licensee had completed the EER and had planned several WR/J0s to install the jacks.
Based on the inspector's judgement and the documents reviewed, the licensee most likely will complete the corrective actions.
The in::pector did not complete inspecting
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whether using an EER and WR/JO vice a plant modification for installing the jacks met all licensee procedures and other regulatory requirements.
This item will be reviewed during future inspections.
h.
(CLOSED)
LER 2-88-13, Loss of RPS Bus A Due to Tripping of Alternate
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Power Supply Breakers EPA-5 and 6.
Voltage fluctuations brought on by the manual or automatic starting and stopping of auxiliary distribution loads, coupled with low switchyard voltage, was determined by the licensee to cause the repeated undervoltage trips of EPA-5 and 6.
From a review of subsequent LERs, the inspector determined that the voltage regulating transformer installed upstream of each unit's EPA-5 breaker (PM-87-003) has been effective in
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reducing the breakers' susceptibility to normal voltage fluctuation L
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(CLOSED)
LER 2-89-21, Reactor Protection System A Trip Resulting in Automatic Starting of the SBGTs and a Group 6 Primary Containment l
Isolation Due to Electrical Protection Assembly Breaker Trip.
The
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licensee could not determine the cause of the EPA-1 and 2 breaker
P trip.
A modification for a seal-in feature for the cause of the trip was not pursued by the licensee.
The inspector, through discussions with the cognizant engineers, determined that, if the problem becomes
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L repetitive (more trips without known causes), and WR/J0s are written to investigate, an EER must be written per PLP-05, Repetitive Failure Detection Program, Revision 0, section 6.2.4.
Thus, the issue would
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be re-evaluated.
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Violations and deviations were not identified.
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0.
In Office Licensee Event Report Review - Unit 1 (90712)
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The below listed LERs were reviewed to verify that the information provided met NRC reporting requirements.
The verification included adequacy of event description and corrective action taken or planned, existance of potential generic problems and the relative safety significance of the event.
(CLOSED)
LER 1-90-01, Coincident Inoperability of HPCI and RCIC Placing Unit 1 in Technical Specification 3.0.3 for Two Minutes Caused by Personnel Error While Researching a Clearance.
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Violations and deviations were not identified.
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Action on Previous Inspection Findings (92701) (92702)
a.
(CLOSED)
Violation 324/87-11-01, HPCI Flow Controller Failure Not
Reported Within Four Hours.
The inspector reviewed the licensee's
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corrective action for appropriateness and verified the completion of training / implementation of a computerized LC0 tracking system, an
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instructional workshop addressing 10 CFR 50.72 notifications, and related procedural upgrades to RCI-06.5 and OI-51, b.
(CLOSED) Violation 325/89-20-01 and 324/89-20-01, Corroded Service Water Pump Lubricating Water Piping Supports.
The inspector reviewed the licensee's rupplemental response to the Notice of Violation dated November 20, 1989.
The licensee has repaired the corroded supports
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and provided a protective coating over the susceptible portions of
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the support structure to prevent further corrosion.
In addition, the horne-flex on the supports was not reinstalled following the repair so that corrosion of the support in the future will be visible.
To correct the communication problem between engineering personnel and plant management, the licensee revised their site Corrective Action Procedure PLP-04, in Revision 2, to provide specific guidance to the engineering staff for reporting potential operability concerns of Technical Specification related equipment.
The inspector reviewed this change and had no further question q
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(CLOSED)
Violation 325/89-20-05 and 324/89-20-05, Inadequate Secondary Containment Integrity Test.
The inspector reviewed the licensee's supplemental response to the Notice of Violation dated
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November 20, 1989.
The licensee rau SP-89-050 on September 9,1989
to verify that secondary containment integrity could be maintained
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with the inner railroad door open.
PT-15.4, Secondary Containment
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Integrity Test, was also revised to include a requirement for individual inspection of the personnel airlock and inner railroad
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door seals for leaks and for testing with the inner railroad doors
open.
Based on the results of the special procedure and the inspector's review of the revised PT, the inspector had no further questions, d.
(CLOSED)
Violation 325/89-20-09, Thermal Power Levels Exceeded
,
License Limit.
The inspector reviewed the licensee's supplemental response to the Notice of Violation dated November 20, 1989.
The licensee has counseled the responsible individuals and provided training for all operators.
The inspector reviewed the lesson plan and attendance sheets to verify that the event was adequately covered and that the appropriate people attended.
Reactor power is also now
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logged hourly to ensure that the 2436 MW limit is not exceeded.
The
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inspector has verified, through direct observations, that the above measures have been effective in maintaining core thermal power less than or equal to the licensed limit, e.
(CLOSED)
IFI 325/84-07-02 and 324/84-07-03, PT-46.4 Being Reviewed
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and Procedure Revision to Incorporate Required Acceptance Criteria.
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This item was last inspected in report No. 88-34.
This item was opened to track the incorporation of a 1/8-inch control room positive pressure acceptance criterion for the Control Room Emergency Filtration System (CREFS).
The NRC accepted, in the SER issued for TMI Action Item III.D.3.4 on February 16, 1989, an acceptance criterion for the CREFS to " maintain the control room at a positive pressure relative to the outside atmosphere during system operation" (TS 4.7.2.d.4).
See report No. 90-02 for inspection of TMI Action Item III.D.3.4.
f.
(CLOSED)
IFI 325/84-13-04 and 324/84-13-04, Completion of Plant i
Modification 82-030 and TAR B84-025 to Help Prevent Spurious l
Actuations of Emergency Core Cooling Systems.
See report No. 89-14.
The fundamental issue covered by this item concerned inadvertent
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activation of ECCS equipment upon loss of power to the analog trip units.
In 1981 and 1982 (see reports 81-20, 81-24, 81-31 and 82-09),
several events caused loss of power to the analog trip units, causing core spray, RHR, HPCI and the diesel generators to start.
Those
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l power losses were caused by blown fuses, inappropriate ground l-hunting, battery charger failures, and voltage spikes on the DC bus.
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Plant Modificttion PM-82-031 was implemented in 1983 on Unit I to l
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provide overvoltage protection for the battery chargers, preventing
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I spiking on thu DC buses and subsequent spurious ECCS activations.
This PM trips the charger supply breaker at 140.5 V.
The Unit 2 version of thin PM,82-030, was completed in 1985 but the maintenance must still cloneout the procedure review.
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L To further increase system reliability, PM-85-020 (Unit 2) and
PM-85-021 (Unit 1) are scheduled for installation in 1991.
These
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modifications separate the power supply to each division's ECCS and
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RPS actuation instrumentation to different battery buses.
Current system design has redundant inverters and power supplies for each division.
Those redundant inverters are supplied by different 125
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Vdc distribution panels (4A and 12A for Unit 2 Division I ECCS
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cabinet, for example), but from the same battery bus and r,harger
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(charger and battery 2A-1).
The modification will add a new distribution panel (12C) that will supply power from a different
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battery and charger (2A-2) from the same division.
A loss of a i
single 125 Vdc bus would then not cause a spurious actuation.
Since
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one set of modifications is essentially complete, this item is
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closed.
The inspector will track the licensee's completion of the
upgrade of the DC power to the analog trip units under an Inspector Followup Item:
ECCS Analog Trip Units Power Source Upgrade,
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(325/90-07-01 and 324/90-07-01).
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(CLOSED)
IFI 325/84-31-01 and 324/84-31-01, Licensee to Develop and Submit a Technical Specification Change Request for Rod Sequence
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Control System (RSCS) Testing.
This item was last inspected in report No. 89-12.
The licensee has installed the new Rod Worth Minimizers (RWM) in both units.
This new RWM is more reliable in
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enforcing the rod patterns and rod blocks.
The licensee also has an outstanding Technical Specification Interpretation (TSI) against the RSCS.
By letter dated February 2, 1990, the licensee committed to delete RSCS from the TS by submitting an amendment request by March 15, 1990.
Since the original issue was the lack of a TS testing requirement for RSCS during shutdown, and
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the licensee maintains that requirement in a procedure, and they are
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committed to submit a TS change, the inspector has no further
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questions on this issue.
h.
(CLOSED)
IFI 325/86-05-02 and 324/86-06-02, Service Water System technical specification Discrepancy.
The licensee's current
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Technical Specification for the service water system does not match the current design basis or mode of operation.
The licensee was
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issued a proposed violation and imposition of civil penalty on
January 23, 1990, based on findings primarily by the Diagnostic l
Evaluation Team.
The licensee has submitted TS amendment request l
dated February 28, 1990, to reflect the current design and operation.
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(CLOSED)
IFI 325/86-33-01 and 3N/86-34-01, IRM Fuse Testing and Subsequent Required Modifications Per GE SIL 445.
As discussed in inspection report No. 88 15, PCNs 05400A (Unit 1) and 054006 (Unit 2)
were issued to develop plant modifications (PMs 89-58 and 89-4%) to install power monitor relays to monitor the -24 Vdc input to the IRM
drawers.
The inspector determined, through related documentation review and interviews, that the power monitor relays will not be installed and the associated PCNs and PMs have been cancelled /
replaced by PCN 054000.
This new PCN reflects the modification of existing printed circuit boards by GE to include the power monitor function.
The licensee is currently under contract with GE to include this modification during an overall IRM drawer upgrade /
refurbishment which is scheduled for completion in late 1991.
As the licensee's cetions are appropriate to address the issues of GE SIL 445, this item is closed, j.
(CLOSED)
IFI 325/87-02-03 and 324/87-02-03, Diesel Generator Jacket l
Water Gasket Deterioration.
This item concerned the failure of a jacket water gasket in a cylinder head of EDG 3 in early 1987.
The gasket is intended to seal the internal jacket water passage from the engine block to the cylinder head.
The gasket deteriorated and allowed jacket water to leak out onto the top exterior of the engine.
The licensee's analysis concluded that the deterioration was due to normal aging of the gasket material, neoprene, in the sodium nitrite treated jacket water system.
The licensee began to change out these.
gaskets in each cylinder head during preventative maintenance.
By late 1988, none of the changed gaskets exhibited abnormal deteriora-
)
tion.
The licensee then changed the replacement scheme to replace the gaskets only when the heads were removed for other reasons.
The I
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licensee has determined that any gasket leakage will be visible from the top of the block and will not cause the diesel to be inoperable.
The licensee stated that the separate cylinder head gasket keeps the cylinder area sealed from jacket water intrusion.
No further jacket water gasket leaks have been discovered.
k.
(CLOSED)
IFI 324/87-02-04, Add Caution Note to GP-05 and Review Instructions Regarding MSIV Closure.
This item concerned an event during a unit shutdown en January 17, 1987, in which reactor pressure exceeded 500 psig with the low condenser vacuum channels bypassed.
This violated TS 3.3.2, although the inboard MSIVs were shut.
The l
MSIVs are automatically closed if condenser vacuum decreases to less
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than 23 inches and is required to be operable whenever reactor pressure is greater than 500 psig.
The licensee took action to
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reduce pressure to less than 500 psig and met the TS LCO time
constra"nts.
The licensee attributed the cause to be an inadequate
procedure and added a caution note to GP-05, Unit Shutdown, to prohibit reactor pressure from exceeding 500 psig with the low
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condenser vacuum switches in bypass.
Additionally, the licensee i
conducted real time training on this event.
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(CLOSED)' IFI 325/87-31-04 and 324/87-35-04 Develo functional Test
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Procedures to Periodically Verify Operabillty of kemote Shutdown
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Equipment.
The licensee has written and implemented functional test
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procedures for remote shutdown equipment.
PLP-1.5, Alternate Shutdown Capability Controls, Revision 1, Table 1, lists ASSD conponents, its associated functional test and periodicity require-
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ments.
The inspector verified that all components listed had an associated f unctional test.
Scheduling and tracking of the tests is accomplished by the licensee's STSS.
The inspector reviewed
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selected tests to ensure that they were scheduled as required.
The
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inspector also verified that other remote shutdown equipment, CRD pumps and B and 0 RHR service water pumps which are not ASSD
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equi) ment,alsohavefunctionalteststoverIfytheirremoteshutdown capa)ility feature.
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(CLOSED)
IFI 325/87-36-04 and 324/87-37-04, TS Amendment to Clarify
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Containment Oxygen Concentration Specification.
The licensee submitted a request to change the bases for this specification by
letter dated November 2,1988.
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(CLOSED) IFI 3t5/87-39-02 and 324/87-40-02, Revise 01-1 and AI-58 to y
Address Concerns Found During A0 Tour.
The inspector had found several problems:
a clearance tag was taped to the inside of a 120 V distribution panel for a breaker that was not labeled; the A0 had
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written the numbers of the valves to be cleared on his yellow glove; and no clear prohibition or requirement existed in the above i
procedures that addressed.these issues.
The licensee has agreed to strengthen Al-58 (Equipment Clearance Procedure) and 01-1 (Operating
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Principles and Philosophy), by adding "shall" vice "should" where requirements are intended.
The inspector also found that the added steps on hanging clearances inside enclosed panels, added in Revision 23 of Al-58, had been inadvertently deleted by Revision 29.
The
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licensee re-inserted the recuirements to either fasten the tag or a l
I small portion of it to the "areaker in Revision 31 to AI-58, issued February 29, 1990.
Operations action item 90-117 has been opened by the licensee to track the revision.to 01-1.
Based on the licensee's agreement to track and fix the above problems, the inspector has no further questions.
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(CLOSED)
IFI 325/89-26-04 and 324/89-26-04, Small Sump Lubricating l
Oil Change / Sample.
The licensee has chosen to sample lubricating oil I
on some small sump safety-related equipment at every oil change and i
on other equipment only when indicated by abnormal oil color, l
clarity, smell, or presence of metal flakes or water.
The inspector notes that the licensee's reliance on mainly visual indication of oil condition will not reveal the presence of contaminants detectable only through sample analysis.
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(CLOSED)
URI 324/87-43-03, Reactor Coolant System Leakage in M51V
pit.
The licensee had discovered a 5 to 10 GPM leak in the MSIV pit that was filling the Unit 2 south core spray sump.
The licensee t
electrically backseated the feedwater system outboard stop-check
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isolation valves, stopping the leak.
The evaluation and compensatory
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action taken at that time was acceptable.
The inspectors did
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i question whether TS 3.4.3.2, Reactor Coolant System (RCS) Operational I
Leakage, applied for RCS boundary leakage outside the drywell, since i
surveillance requirements only measured drywell leakage.
Region !!
requested NRR to review the issue.
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NRR determined that the intent of TS 3.4.3.2 and its respective l
surveillance requirement in TS 4.4.3.2.a is for monitoring RCS leakage inside the drywell.
Therefore, no change to the current TS
is waaranted.
The staff also stated that the licensee should develop a surveillance method to monitor and limit leakage to a minimum i
value.
The BSEP FSAR provides for measuring systems for those areas in which RCS boundary leaks can occur.
Leak detection methods, alarms and isolations are listed in FSAR Table 5.2.5-1 and referenced in sections 5.2.5.2.4.
The inspector reviewed annunciator panel and procedures, reactor building sump pumps equipment and alarms.
t The inspector found that Unit I and 2 South RHR sump pump out timer settings did not match the current annunciator panel procedure APP A-04 setting.
Both units were listed with a setting of greater than 11 minutes while Unit I setting was 9 minutes and Unit 2 setting was 5 minutes.
The setting in the APP may also have been wrong since a longer time a shorter time appears more conservative - the pump has to run a shorter time before the alarm is actuated.
The licensee agreed to resolve this issue by answering a technical support memo from operations (TSM 90-144) by April 1,1990.
The Unit 1 APP for A-04, window 1-3, was incorrectly identified as the HPCI sump instead of the North RHR sump.
The licensee submitted a request to change the procedure.
Violations and deviations were not identified.
I 10.
Startep fror. Refueling - Unit 2 (71711)
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The inspector reviewed the licensee's administrative controls concerning plant modifications to ensure that the proper controls were in place to t
train personnel and revise procedures to reflect modifications installed in the plant during the outage.
The inspector noted that ENP-3.0, Plant Modification Procedure, Revision 41, and 01-26, Operations Review of Plant Modification Direct Replacement Packages, Technical Specification Changes
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and Procedure Changes as a Result of Technical Specification Changes,
Revision.10, contain the necessary provisions to train operators and
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update their procedures prior to unit startup.
The inspector reviewed L
several training packages and the revised operating procedures resulting l
from selected modifications installed this outage.
Proper training had j
been conducted and appropriate procedure revisions were made, i
i The inspector also performed a walkdown of 28 core spray system to verify
that it had been returned to service in accordance with approved i
procedures.
No deficiencies were found.
The HPCI system was also I
inspected.
Further information regarding this inspection is contained in
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paragraph 5.
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Areas that are inaccessible during normal plant operation were also
inspected.
The dr
penetration room, ywell, MSIV pit, RCIC steam tunnel HPCI roof, 66-foot and torus were inspected to assess the effectiveness of i
the licensee's closeout process for these spaces, j
The drywell inspection revealed more deficiencies relative to past
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inspections that have been performed.
Missing and loose instrument line
"U" clamps, unsupported conduits, loose electrical junction box cover
screws and some general housekeeping iterus were found.
The inspector did
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note that the majority of the items had been previously identified by the
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licensee's QC and technical support personnel and that these items were
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scheduled for repair prior to closeout of the drywell.
In fact, licensee
personnel had identified a large number of deficiencies during their own i
inspections the previous weeks.
This large number indicates a weakness in the work control area in that systems and components are not being
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returned to their proper condition following work activities.
This l
restoration is also hampered by a lack of documentation that accurately
reflects the installed configuration of fie.1d run components.
NCR 87 037
was previously issued by the licensee to a W ess past workmanship concerns i
and assess the effectiveness of licensee's corrective actions.
This NCR
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is still open and the inspector will monitor its closeout during future
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inspections, i
r The MSIV pit was inspected following the scheduled completion of work j
activities in this area.
The inspector found a number of housekeeping
items including unistruts, pieces of scaffolding 2 light strings and
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other items that had been lef t in the area.
In addition, some equipment i
items such as a missing condulet cover, an open ventilation duct
inspection cover and a missing MSIV junction box cover screw were also
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found.
These items do not pose an operability con:ern but do indicate
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that the licensee's controls to ensure that a space is ready for closeout
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were not effective.
Since this inspection, the licensee has corrected the
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discrepant conditions and designated an individual who is responsible for
ensuring tht.t all work activities are properly completed in that area.
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l A number of housekeeping items were also identified in the RCIC steam
tunnel and on the HPCI roof.
A few housekeeping items were found in the 66-foot penetration room and no discrepancies were noted in the torus.
)
Violations and deviations were not identified.
l 11.
ExitInterview(30703)
The inspection scope and findings were summarized on March 2.1990, with
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those persons indicated in paragraph 1.
The inspectors described the areas inspected and discussed in detail the inspection findings listed
below and in the su mary.
Dissenting comments were not received from the
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licensee.
Proprietary information is not contained in this report.
Item Number Description / Reference Paragraph 325, 324/90 07-01 IFl - ECCS Analog Trip Units Power Source Upgrade,(paragraph 9.f).
324/90-07-02 Non Cited Violation - Work Procedure WP 18 Temporar Rigging and Scaffolding. Was Not Properl Implemented.(paragraph 2.b).
12.
List of Abbreviations for Unit I and 2 ADS Automatic Depressurization System Al Administrative Instruction A0 Auxiliary Operator APP Annunciator Panel Procedure ASSD Alternative Safe Shutdown Drill BSEP Brunswick Steam Electric Plant
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BWR Boiling Water Reactor CRD Control Rod Drive CREFS Control Room Emergency Filtration System DC Direct Current i
DG Diesel Generator ECCS Emergency Core Cooling System EDG Emergency Diesel Generator EER Engineering Evaluation Report ENP Engineering Procedure
EPA Electrical Protection Assembly ESF Engineered Safety feature i
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Degrees Fahrenheit FSAR Final Safety Analysis Report o
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GL Generic Letter GP General Procedure GPM Gallons Per Minute HELB High Energy Line Break HP Health Physics HPCI High Pressure Coolant Injection 18C Instrumentation and Control
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IFI Inspector Followup Item i
IPBS Integrated Planning, Budgeting and Scheduling IRM Intermediate Range Monitor
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LCO Limiting Condition for Operation I.
LER Licensee Event Report
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MSIV Main Steam Isolation Valve
MST Maintenance Surveillance Test
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IWT Megawatts Thermal
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NCR Non Conformance Report
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NRC Nuclear Regulatory Commission
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NRR Nuclear Reactor Regulation i
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Operating Instruction t
OP Operating Procedure t
OPM Operating Procedure Manual
PA Protected Area
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PCN Plant Change Notice
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PM Plant Modification
PNSC Plant Nuclear Safety Committee
PSIG Pounds per Square Inch Gauge
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PT Periodic Test
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QA Quality Assurance
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i QC Quality Control
RCI Regulatory Compliance Instruction i
RCIC Reactor Core Isolation Cooling
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RSCS Rod Sequence Control System
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RWCU Reactor Water Cleanup RWM Rod Worth Minimizer
SER Safety Evaluation Report
SIL Service Information Letter l
SP Special Procedure i
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Surveillance Test Scheduling System
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TAR Task Assistance Request
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TMI Three Mile Island
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TS Technical Specification l
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TSI Technical Specification Interpretation i
TSM Technical Support Memo
URI Unresolved Item
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WR/JO Work Request / Job Order l
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