IR 05000324/1991006
| ML20138G138 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 04/11/1996 |
| From: | Christensen H, Prevatte R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20138G128 | List: |
| References | |
| 50-324-91-06, 50-324-91-6, 50-325-91-06, 50-325-91-6, NUDOCS 9610180254 | |
| Download: ML20138G138 (18) | |
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/p2 Retoq'o UNITED STATES NUCLEAR REGULATORY COMMISSION
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y" REGION 11
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g-g 101 MARIETTA STREET, N.W.
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ATLANTA, GEORGI A 30323 (*...
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Report No.:
50-325/91-06 and 50-324/91-06
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Licensee: Carolina Power and Light Company P. 0. Box 1551 i
Raleigh, NC 27602-Docket Nos.:
50-325, 50-324 License Nos.:
Brunswick 1 and 2 Inspection Conducted:= March 1 - 31, 1991-Lead Inspector:
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'R. C. Prevatte
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Date' Signed j
Other Inspectors:
W. Levis D. J. Nelson E
R.j., Carroll i
Approved By:
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H. Christensen, Section Chief Date Signed Reactor Projects Branch 1 i
Division of Reactor Projects i
SUMMARY Scope:
This routine safety inspection by the resident inspectors involved the areas of maintenance observation, surveillance' observation, operational safety verification, onsite review committee, onsite followup of events, and action on previous inspection findings.
Results:
In the areas inspected, two apparent violations for the failure to follow
. procedures-and one apparent violation for performing maintenance activities without adequate procedural guidance were identified.
The first violation involved inadequate documentation and out of sequence performance of calibra-tions on safety-related equipment that is used only for' local indication and inservice testing, paragraph 3.
The second violation involved an improper double verification during removal of diesel generator No. 4 from service, paragraph 2.c.
The third violation involved the performance of maintenance V
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investigation / troubleshooting and repair activities on an emergency diesel generator without adequate procedures.
An error during the removal of a camshaft bearing resulted in damage to the diesel's camshaft.
Since the repair activities on the diesel generator exceeded the time allowed in the applicable Technical Specification Limiting Condition for Operation (LCO), both units were subsequently shut down o' Harch 29, 1991, paragraph 2.b.
The above events continue to demonstrate weaknesses in the licensee's work control process.
These events are similar to those cited in violations 324/90-29-01, 325,324/
90-29-05 and 324/91-01-01.
The licensee also experienced load fluctuation problems with diesel generator (DG) No. 2 during its monthly load test on March 11, 1991. These problems were initially thought to be governor problems, but were later attributed to its kilowatt meter not being correctly calibrated, paragraph 2.a.
Additionally, arcing due to carbon buildup in the brush rigging resulted in DG No. 3 being inoperable for two days while repairs were accomplished, paragraph 2.b.
Unit 1 tripped from 100 percent power on March 5 due to an incorrectly calibrated generator overcurrent relay.
After completion of all required items the unit was restarted on March 8, paragraph 4.b.
As discussed above, both units continued to operate at essentially full power until they were forced off
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line on March 29 due to the expiration of an LC0 for DG No. 1.
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l REPORT DETAILS 1.
Persons Contacted
Licensee Employees
- K. Altman, Manager - Regulatory Compliance F. Blackmon, Manager - Radwaste/ Fire Protection M. Bradley, Manager - Brunswick Assessment Project S. Callis, On-Site Licensing Engineer
- G. Cheatham, Manager - Environmental & Radiation Ccatrol W. Hatcher, Supervisor - Security
- R. Helme, Manager - Technical Support J. Holder, Manager - Outage Management & Modifications (OM&M)
M. Jones, Brunswick Assessment Project
- T. Jones, Senior Specialist Investigations - Regulatory Compliance
- B. Leonard, Manager - Training
- J. Moyer, Manager - Operations
- R. Poulk, Manager - License Training J. Simon, Manager - Operatione Unit 1
- W. Simpson, Manager - Site Planning and Control
- J. Spencer, General Plant Manager - Brunswick Steam Electric Plant
- R. Starkey, Vice President - Brunswick Nuclear Project
- R. Tart, Manager - Operations Unit 2
- R. Warden, Manager - Maintenance
- K. Williamson, Manager - Nuclear Engineering Department (0nsite)
Other licensee employees contacted included construction craftsmen, engineers, technicians, operators, office personnel, and security force members.
- Attended the exit interview Acronyms and initialisms used in the report are listed in the last paragraph, 2.
MaintenanceObservation(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 components were operable; administrative controls were followed; tagouts were adequate; personnel were qualified; correct replacement parts were
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used; radiological controls were proper; fire protection was adequate; l
I quality control hold points were adequate and observed; adequate post-
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maintenance testing was performed; and independent verification require-t ments were implemented.
The inspectors independently verified that selected equipment was properly returned to service.
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g 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:
91-AFPK1 CG 1 Brush Rigging Inspection 91-AFXP1 Investigate Source of Metal Particles in Lube Oil i
Strainers l
91-AGGH1-4 Replace DG 1 Right Bank Camshaft l
MST-DG500 Emergency Diesel Generator Inspection PM-LUB500 Plant Equipment Lubrication Schedule a.
On March 11, 1991, during its monthly load test, DG No. 2 experienced load fluctuations after running for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> loaded at 3500 KW. The load fluctuations ranged from 200-300 KW and required the operators stationed locally at the diesel to make periodic adjustments.
At the time of these fluctuations, small air bubbles were observed in the governor hydraulic sight glass and the oil level was fluctuating.
Because of these fluctuations, the diesel was declared inoperable and the licensee entered the appropriate LC0 action statement.
As part of the corrective actions, maintenance personnel drained the oil from the governor, flushed these components with No. 2 diesel fuel, and then refilled the governor with new oil.
It was noted that the oil removed from the governor was discolored with a reddish brown appearance versus a normal yellow color. After the oil was changed, the diesel was run with no load fluctuations noted.
At that time,
the licensee theorized that the most likely causes of the noted
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problems were possible contamination of the governor oil and j
entrainment of air in the governor and/or its oil system.
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The licensee sent samples of the old oil along with samples from the j
other three DG governors to their E&E Center for evaluation.
They reasoned that the other diesels were operable based on the fact that previous pts had been performed for these diesels with no noted problems.
The inspector reviewed the technical manual for the Woohard Governor and noted the following:
Oil contamination was noted as the major cause of governor troubles.
- If oil is noted to be dirty or breaking down, the governor is to be drained while hot, flushed with the lightest grade of the same oil, and then refille...
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The mechanical governor needle valve is to be opened in order to bleed air from the oil passages each time the oil is changed in the governor.
The oil from the governor for DG No. 2 was last changed in December
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1990.
It is changed every 18 months during the diesel generator inspection in accordance with Step 7.2.4.3 of OMST-DG500, Emergency Diesel Generator Inspection, Revision 0.
This procedure has no provisions for draining the oil while hot, flushing out the governor oil with the lighter weight oil, or opening the needle valve to bleed air from the oil passages.
The procedure also specifies to use approximately one gallon of oil to fill, while the technical manual states that the governor requires about 2-1/2 quarts when completely empty.
OPM-LUB500, Revision 8,
Plant Equipment Lubrication Schedule, requires that the governor oil be checked weekly.
These checks verify proper level along with the proper color of the lubricant as stated in Section 6.1.1 and attachment 6 of the procedure. Although the governor oil for No. 2 DG was discolored, no problems were noted during the weekly inspection.
The licensee claims that the discoloration of the oil was not so severe that it could be readily seen through a small sight glass.
The inspector also noted that this diesel had experienced load fluctuation problems in 1988.
At that time, ven',e assistance was requested.
The vendor representative directed that some adjustments to the governor be made and that the governor oil be drained and flushed to remove the varnish.
It is not clear that this flushing evolution was performed, although a procedure (0PM-ENG510, Revision 0),
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Instructions for Flushing the Governor on the Emergency Diesel Generator was developed to perform this evolution.
The licensee has since determined that the most likely cause of the generator oscillations was not due to the governor malfunctioning, but rather the kilowatt meter being out of calibration.
This conclusion was based on review of fuel oil consumption rates, stable governor output signals, and no movement in the fuel rack.
Calibration of the meter also showed that it was out of calibration.
Although the governor did perform correctly, this event did display several weaknesses in the licensee's PM program.
These were discussed with plant management who acknowledged the inspector's comments.
b.
On March 18, 1991, DG No. 3 was declared inoperable due to excessive l
sparking in the generator which was observed during the diesel's l
monthly load test.
Inspection of the brush assembly showed carbon j
buildup on the brush holder yoke.
The licensee theorized that the
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collection of the carbon dust created a ground path and, therefore, was the cause of the sparking noted by the auxiliary operator.
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brushes, brush holders, and a yoke bushing were installed _ and the
diesel was returned to operable status on March 20, 1991.
The remaining 3 diesels were also inspected.
Carbon dust was also found on each of their brush holder yokes.
As the buildup was not as severe as that found in DG Nn. 3, the licensee concluded that these diesels were operable.
On March 22, 1991, DG No. I was removed from service to clean and inspect the generator brush rigging assembly.
Compared to DG Nos. 2 and 4, this diesel was judged by the licensee to have the most carbon
dust buildup.
The licensee also planned to investigate the high D/P in the suction lube oil strainer noted during the February run of the diesel.
Several contaminants were found on the lube oil strainers
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when they were removed.
These contaminants included fibrous materials, aluminium metallic particles, lead / tin particles, and some aluminum flakes.
The metallic materials were determined to be bearing material.
Consequently, clearance measurements were taken on j.
all lower crankshaft and connecting rod bearings. Two connecting rod bearings were found out of tolerance. They were removed, inspected,
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and replaced.
No other abnormal wear was noted.
Camshaft bearings were then inspected.
Fourteen of the eighteen bearings exhibited wear.
Several of these had grooves, scuffs, and excessive wear.
The licensee's investigation determined that the fibrous material had originated from cloths used to clean the diesel sump during past outages.
During the removal of the camshaft bearings every other bearing was removed to allow adequate support of the camshaft.
Due to problems removing No. 9 south' bearing, the adjacent bearing was also removed.
This action was concurred in by the vendor's technical representa-tive, the maintenance supervisor, and the technical support engineer.
During the time that the No. 8 and No. 9 right cam shaft bearings were removed, the engine was barred over.
During this evolution, the camshaft rolled up on an exposed No. 9 bearing journal housing, causing gouging of the camshaft.
Several longitudinal gouges up to approximately two inches in length and 3/8 inch deep were noted in the shaft.
The licensee evaluated various repair techniques and opted for two methods.
One repair involved the replacement of the camshaft with another that had been procured from a nearby utility.
The second involved repairing the old camshaft by machining out the damage and performing a weld buildup. Since both repairs were estimated to take 4 to 5 days, the licensee requested a Waiver of Compliance from Region II to extend the LC0 Action Statement time of Technical Specification 3.8.1.1 an additional 7 days for both units.
The l
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waiver was based primarily on the small incremental increase in risk based on the licensee's PRA.
The waiver was submitted on the afternoon of March 28, 1991.
After consultation with NRR and review of the request with the licensee, the Region did not grant the waiver request.
The licensee then entered the Action Statement of TS 3.8.1.1 and commenced a shutdown of Unit I at 7:09 p.m., on March 28,
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1991.
The unit achieved hot shutdown at 1:45 a.m.,
on March 29, 1991, and cold shutdown at 3:30 p.m., on March 29, 1991.
Unit 2 commenced its shutdown at 2:20 a.m., on March 29, 1991.
It reached hot shutdown at 10:37 a.m., on March 29, 1991, and cold shutdown at 3:35 a.m., on March 29, 1991.
The removal of the camshaft bearings on DG No. 1 and the subsequent barring of the engine was accomplished without a written and approved procedure. WR/JO AFXP1 provided the work instructions for investiga-ting the cause of the metallic particles in the lube oil strainer.
This WR/JO did not specify the removal of adjacent bearings nor the provisions to bar over the engine. While it is recognized that there is some " skill of the craft" involved with these type repairs, a procedure or detailed work instructions is required by the Technical Specifications and the licensee's administrative procedures.
Since this evolution, removal of camshaft bearings, had not previously been performed by the licensee's staff, detailed instructions were even more important in this case.
The failure to have a procedure for this work is a Violation:
Failure To Perform Diesel Repairs With Approved Procedures, (325,324/91-06-02).
The performance of the diesel repair without a procedure is an indication that personnel are not yet sensitive to the need of performing work in accordance with approved procedures.
There are several maintenance issues involving the diesel generators noted in this report.
These include draining and flushing of governor oil; inspection, cleaning, and repair of generator brush rigging; and bearing inspection / replacement. These problems indicate an inadequate preventive maintenance program on the diesel generators.
This situation is compounded by the fact that the allowed out of service time for a diesel generator with either unit operating is 7 days. This time period does not allow sufficient time for detailed inspections even during unit outages.
The other problem faced by the licensee is that the manufacturer of the diesel, Nordt,arg, is no longer in business. Although the service rights for these diesels still exist, the rights are often sold and little baseline expertise is available.
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The EDSFI team is conducting inspections in this area.
The details of those inspections will be documented in Inspection Report No.
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91-09.
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c.
On March 30, 1991 local clearance 2-91-0261 was approved to allow the removal from service of No. 4 DG.
Since the diesel generator is one of the systems listed in the licensee's Administrative Procedure as requiring doubie verification when removed from service, two A0s were sent'to hang the clearance.
Tag No. 1 of the clearance required that the 125 volt DC control power normal feed breaker, located in DG No. 4 exciter panel, be placed in the off position.
Instead of opening this breaker, the A0 hanging the clearance tag mistakenly opened the control power breaker for switchgear E-4.
The A0 performing the double verification was present when the tag was hung, but did not recognize the error.
Consequently, he initialed the clearance sheet as the double verifier, indicating tha+ the tag was attached to the correct component which was in the required position.
The loss of control power to E-4 was noted by the control room personnel who took immediate measures to have the power restored.
The loss of power resulted in a loss of protective relaying for components fed from this switchgear. The safety significance of this condition is minimal due to its short duration and the fact that both units were in cold shutdown at the time.
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Section 5.3.8 of AI-58, Equipment Clearance Procedure, Revision 34, dated March 12, 1991 specifies the actions for performing double verification of components.
Specifically, c::h 0,nerator will perform the following:
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Each operator will independently identify the component (separation of time and distance is not required).
- Each operator will identify to himself the position to which the component is to be manipulated.
- The operator performing the manipulation will announce to the other operator the position to which he is manipulating the component.
The operator will manipulate the component only after securing confirmation from the other operator that the announced position is correct.
The second operator will check the component to be in the proper position, in accordance with 01-13.
This method of double verification is required for removal from service of systems / components important to safety as designated in Administrative Procedure Table 11.7.1.
In this case the double verification was not properly performed.
The individual performing the double verification did not independently identify the component being removed from service.
The diesel
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generator exciter panel is located in the diesel cell at the 20 foot elevation.
Compartment AK2, located on switchgear E-4, is on the 50 foot elevation.
These locations, with the exception of the elevation
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were clearly noted on the clearance sheet. A situation which can be t
confusing, is that compartment AK2, where the E-4 control power breaker is located, also contains DG No. 4 output breaker.
This output breaker was also being tagged as part of this clearance.
The inspector.noted, however, that a red sign is attached to compartment AK2 which warns that this compartment contains the normal control power breaker for E-4.
The failure to properly implement the double.
verification requirements -is a violation:
Failure to Follow Procedures and Perform Adequate Double Verification, 325,324/91-06-03.
Two violations 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 l
requirements; administrative controls were followed; personnel - were qualified; instrumentation was calibrated; and data was accurate and 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:
OPIC-DPT007 Calibration of Rosemount Model 1151 Square Root
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Differential Pressure Transmitter l
OPIC-UI004
' Calibration of Action Model V560 Indicators On March 15, 1991, while conducting a routine plant tour,~ the insp. Otor observed an I&C technician performing process instrument calibration activities on a Rosemount Model 1151 square root differential pressure transmitter for the Standby Liquid Control system flow on Unit 1.
The activities were being performed under WR/JO 90RWW451 using calibration i
procedure OPIC-0PT007, Revision 1.
The - technician, when questioned, stated that he was performing the independent verification, steps 7.4.6 through 7.4.11, required by the above procedure to return the unit to service.- The inspector reviewed the working copy of the procedure and noted that it had been completed up to step 7.4.6, but that no initials
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The technician, performing the independent verification was questioned on how he could accomplish the task when the first technician had not yet signed off for completing the j
steps and restoring the system to service.
He stated that the first
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i technician had completed the ' steps, but had left to go to the restroom
without signing off those steps. The second technician returned while the
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inspector was present and reiterated the above.
After discussing.the apparent - out of sequence independent verification with the two
technicians, the inspector reviewed the completed test records for a I
process instrument calibration, on the Calibration of Action Model V560
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Indicator, OPIC-VI004, Revision 2, that the technician had completed in
the morning on the SLC system flow indicator C41-FI-5512.
It was noted, i
on this completed. test procedure, that the technician had not signed the prerequisite step 3.1 for receiving permission from the shift foreman to
j perform this test, and had not initialed step 7.1.1 for lifting a lead l
prior to connecting the calibration test equipment.- The inspector noted that these were the only signatures required on page 7 of this procedure.
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i The technicians stated that they had obtained the required permission from the shift foreman and-had signed on page 8, step 7.2.2, for reconnecting j-the lifted wire.
The inspector reviewed the control room log and did not find documented evidence that permission had been granted by Operations to
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t commence the test.
However, two shift foremen had signed the route sheet i
granting permission to perform the test on the previous shift.
Control i
personnel also stated that not all minor tests and calibrations are j
cntered in the control room log.
The inspector next met with the acting I&C test foreman, the Manager for
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Unit 1 I&C and electrical crews, and the Maintenance Manager to discuss l
personnel not sequentially following and completing the steps as required i
in the two above procedures.
These licensee personnel stated that there was no maliciousness intended by the technicians to incorrectly document
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all procedure steps or to do the independent verification out of sequence.
j They and the technicians acknowledged that they were in error in these
instances.
Maintenance also informed the inspector that they had L
additionally identified tha. independent verification had not been j
accomplished, as required, for. steps 7.1.12 and 7.1.13 on procedure OPIC-DPT007 and step 7.4.2 of procedure OPIC-UI004 The Maintenance
Manager also stated that a meeting had been conducted with maintenance personnel to discuss this issue and reinfurce the requirement for accomplishing tests in sequence and correctly documenting each step as it
is completed.
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The inspector, in the above discussion with maintenance management, noted j
that some similarity existed with two previous events involving I&C technicians where the failure to read an: observe each procedural step had i --
i resulted in two plant trips from 100 percent power.
The events were described in detail in Inspection Reports 90-29 and 91-01.
Each of the i
abcve events resulted in escalated enforcement. The licensee, in response
to the earlier violations, conducted meetings with personnel to stress the need for following procedural guidance.
Sensitivity training to increase
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plant personnel awareness of responsibility and accountability for doing
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each job correctly was also conducted for maintenance personnel. Based on
the above event, it appears that the licensee's efforts in this area have
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j not been fully sucussful.
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The failure to follow the correct sequence in performing the independent verification steps in procedures OPIC-DPT007 and OPIC-U1004, and the failure to document completion of two steps in procedure OPIC-VIOO4 is contrary to the requirements and guidance provided in plant maintenance procedure, Conduct of Operations OMM-001, Revision 14, and is a Violation:
Failure to Follow Procedures, Inadequate Work Control, (325/91-06-01).
One violation was identified.
4.
Operational Safety Verification (71707)
a.
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, j
discussions with personnel, reviewing of records and independent
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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 operating trends and out of service safety systems to ensure that there were no conflicts with Technical Specification Limiting Conditions for Operations.
Direct observations of control room panels and instrumentation and recorder traces important to safety were conducted to verify 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 verified t.he status of selected control room annunciators.
Operability of a selected Engineered Safety Feature division was verified weekly by ensuring that each accessible valve in the flow path was in its correct position; each power supply and breaker was closed for components that must activate upon initiation signal; the RHR subsystem cross-tie valve for each unit was closed with the power removed from the valve operator; there was no leakage of major components; there was proper lubrication and cooling water available; and conditions did not exist which coul'1 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.
l The inspectors verified that the licensee's health physics policies /
l procedures were followed.
This included observation of HP practices
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and a review of area surveys, radiation work permits, postings, and l
instrument calibration.
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The inspectors verified by general observations 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 PA; 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 measures were employed when required; and security's response to threats or alarms was adequate.
The inspectors also observed plant housekeeping controls, verified position of certain containment isolation valves, checked clearances, and verified the / operability of onsite and offsite emergency power sources.
b.
On March 5,1991, Unit 1 experienced an automatic turbine trip /
reactor scram from 100 percent power.
All safety systems functioned as required.
There was no.HPCI or RCIC automatic actuation.
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Group 2, 6 and 8 isolation signals were received as anticipated. The electro-hydraulic control system controlled reactor pressure with the bypass valves and no SRVs were activated.
Reactor water level was maintained with the feedwater pumps.
The plant was rapidly-stabilized with no initial major equipment malfunctions.
The inspectors were onsite and immediately responded to the control
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room to observe plant and personnel response to the event.
Plant i
operations personnel handled the event exceptionally well.
It was-immediately discovered that the "B" phase main generator overcurrent (Type 51) relay had tripped causing the scram.
The CP&L Executive Vice President, who was. touring the plant at that time, identified that this relay did not have the correct setpoint.
l As a part of the scram recovery, an attempt was made to restart 1A
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reactor recirculation pump MG set, but it. tripped when the field excitation breaker failed to close.
At that time, an attempt was made to open recirculation pump A discharge valve 1-B32-F031A.
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valve failed to open, so recirculation pump B was restarted to
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equalize loop temperatures.
At this time, a decision was made to retain the unit in Hot Shutdown, investigate the event, and perform all required repairs.
l An investigation of the event determined that the generator "B" phase overcurrent relay had been calibrated during the recently completed refueling outage and had not been returned to the correct setpoint after completion of the calibration.
These relays were rem:ved from the site. and calibrated at the Transmission Department's facility during the outage.
The documentation used for this evolution is a i
simple card that identifies the component, shows the required
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i setpoints, and records all calibrations.
For. this evolution, no
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specific procedure is provided since this task is considered within J
the skill of the technician.
The manufacturer's instruction book
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In this event, the equipment was left with the tap and dials in the setting used for calibration and was
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not returned to the "as found" settings required for correct operation. The licensee's HPES coordinator is currently working with the Transmission Department to do an HPES " root cause" evaluation of this event and determine what remedial actions are required to
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correct the problem and prevent recurrence.
l This is the third plant occurrence in the past 2 years where the Transmission Department's work efforts have either caused a plant
scram or degradation Jf the offsite power system through either a lack of quality procedures or poor communication with plant personnel.
As a result of the above events, some steps have been taken to correct these problems.
However, it does not appear that adequate management attention and resources have been directed to fully resolving these problems.
It is noted that the calibration of these relays was performed late in 1990 and the improvements which
have been initiated may not have had sufficient time to improve the
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interface between the plant and Transmission Department and become fully effective.
The inspector held discussions with the Manager of the Wilmington
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area transmission maintenance unit.
He stated that he had recently been assigned to this unit with a mandate to correct these
deficiencies.
He appeared to be motivated for this task and has j
developed communication and work interfaces with appropriate plant personnel.
Investigation into the 1-B32-F031A valve failure revealed that the
M0V motor was burned up.
Further investigation revealed that the actual differential pressure across the valve at the time it was required to open far exceeded the capability of the motor.
Consequently, since the motor overloads are sized at greater than 200
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percent, the motor burned up.
This problem is a generic problem that was identified in GE SIL-368 for these double disc valves.
The SIL recommended drilling a hole in the discharge side of the discharge valve disc to allow pressure equalization to the bonnet and area between the double disc.
This modification has been implemented in Unit 1 and is scheduled for implementation in Unit 2 during the next
scheduled refueling outage.
In the interim, specific instructions have been provided to Operations on how to overcome this problem
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until the modification can be installed in Unit 1.
The unit was restarted on March 8,1991, after completing repairs to the above valve, the 1A MG set, and other items identified while the unit was shutdown.
The licensee is currently preparing a LER on this event.
The inspectors will review the LER and verify that identified concerns are corrected.
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Violations and deviations were not identifie. -
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5.
OnsiteReviewCommittee(40500)
The inspectors attended selected Plant Nuclear Safety Committee meetings i
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 qualific tions.
Meeting minutes were reviewed to confirm that decisions /
recommendations were reflected in the minutes and followup of corrective
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actions was completed.
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Violations and deviations were not identified.
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Onsite Followup of Events (92700)
F
The below listed events were reviewed to verify that the information
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provided met NRC reporting requirements.
The verification included adequacy of event description and corrartive action taken or planned,
existence of potential generic probleus, and the relative safety
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significance of the event.
Onsite inspections were performed and
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i concluded that necessary corrective actions have been taken in accordance
with existing requirements, license conditions, and commitments, unless
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j otherwise stated.
(CLOSED)
LER 2-90-01, Outside Technical Specification Due to Missed
Surveillance: CS Subsystems Inoperable.
The lack of formal guidance for
determining which LCOs were required when a Technical Specification
surveillance test could not be performed (i.e., when the system was'out of service) caused both core spray loops to be declared operable when a
j portion of its logic, which is tested in a RHR test, had not been tested.
Subsequent to this' event, the licensee has formalized guidance to provide I
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the SR0 with sufficient information to determine what systems are affected
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when a test can not be performed. The inspector reviewed these procedural I
changes and had no further questions.
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Violations and deviations were not identified.
i 7.
Action on Previous Inspection Findings (92701) (92702)
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(CLOSED)
IFI 325,324/89-34-35, Followup on Implementation and i
Effectiveness of Actions Taken to Ensure Overall IAP Improvements Are l
Implemented / Adjusted and Performance Monitored as in IAP Items El and E2.
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IAP Item El - Define / Track Operational and Management Perfonnance;
Document Goals to be Used to Manage Performance.
As previously discussed in Inspection Reports 90-11 and 90-37, specific
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operational and management related goals have been established at the i
site, department, and section levels.
These goals and their status of
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achievement have, and continue to be, appropriately communicated throughout the ranks.
A wide variety of performance indicators, ranging
anywhere from " obsolete equipment replacements performed" to " radiological j-related concerns" have been employed to monitor progress towards achieving
the desired goals.
These performance indicators are updated monthly and j
are being effectively utilized by licensee management (i.e., during monthly project review meetings, etc...) to determine success of specific
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i accountabilities, as well as. the overall success of Brunswick.
Accordingly, the -inspector had no further questions concerning this
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ongoing process of performance management.
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IAP Item E2 - Ensure Improvement Programs Are Implemented / Monitored.
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By memorandum (Starkey to Core) dated January 17, 1990, eight improvement
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programs (along with their respective project managers) were identified for implementation completion monitoring under IAP Item E2.
As progressively addressed in Inspection Reports 90-11 and 90-37, these eight
improvement programs are:
Impel FSAR Study; HPCI SSFI; Systems
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Engineering Training; EDSS Completion; Technical Staff / Manager Training;
Service Water SSFI; Clearance Project; and Commercial Grade Procurement.
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The inspector verified that a completion plan and an appropriate tracking
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mchanism were established for each program as specified in IAP Item E2 l
and detailed in the above referenced CP&L memorandum.
Since the last review of E2 in Inspection Report 90-37, the remaining two items in the Clearance Project (i.e., implementation of ACMS and Task j
Analysis Training) have been completed.
Further review of Systems
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Engineering Training and Technical Staff / Manager Training, although l
previously completed with respect to the intent of E2 (i.e., training i
programs in place for both and INPO accreditation for the latter),
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indicates that the desired training continues to be appropriately
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performed, scheduled, and tracked.
A brief status of the three remaining
open programs under E2 is provided below:
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j EDBS Completion i
The current plan to complete remaining EDBS activities (scope) is as
follows:
i Re-initiationofEDBScompletionwork(1/1/90)
Completion of adding supports to Q-List (8/31/91)
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Completion of remaining Q-List scope (12/31/91)
Completion of remaining Parts List scope (12/31/92)
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Based on a review of the January 1991 EDBS Monthly Status Report and discussions'with the~ assigned ' Project Manager, the inspector confirmed that EDBS completion work was re-initiated as scheduled.
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Six action items remain open; four (DW-06, DW-16, D0-20, and DW-21) are presently scheduled for completion in 1991, one (RW-7B for Unit 1) in July 1992, and the last (RW-7B for Unit 2) in July 1993.
j Service Water SSFI Ten items remain to be resolved; five (items 55, 99, 100, 134, and 140)
are presently scheduled for completion in 1991, four (items 95, 96, 101, and 118) in 1992, and the last (item 97) in December 1993.
Regarding the above three programs remaining open under E2, a review of their individual completion plans and associated Monthly Status Reports to upper management indicates that established licensee monitoring is as
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intended / appropriate. Accordingly, the inspector had no further concerns.
Violations and deviations were not identified.
8.
Exit Interview (30703)
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j The inspection scope and findings were summarized on April 1,1991, with
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those persons indicated in paragraph 1.
Subsequently, via telephone conversation with Mr. R. Starkey on April 5,1991, an additional finding (Violation 325,324/91-06-08) was identified. The inspectors described the areas inspected and discussed in detail the inspection findings listed
below.
Dissenting comments were not received from the licensee.
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Proprietary information is not contained in this report.
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Item Number Description / Reference Paragraph 325/91-06-01 VIOLATION - Failure to follow procedure, paragraph 3.
325,324/91-06-02 VIOLATION - Failure to Perform Diesel Repairs with Approved Procedure, paragraph 2.b.
325/324/91-06-073 VIOLATION - Failure to follow procedure and perform
adequate double verification, paragraph 2.c.
9.
Acronyms and Initialisms ACMS Automated Clearance Management System A0 Auxiliary Operator BSEP Brunswick Steam Electric Plant CS Core Spray DG Diesel Generator
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i D/P Differential Pressure E8E Energy & Environment EDBS Engineering Data Base System EDSFI Electrical Distribution System Functional Inspection
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l ESF Engineered Safety Feature F
Degrees Fahrenheit FSAR Final Safety Analysis Report i
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HP Health Physics HPCI High Pressure Coolant Injection HPES Human Performance Evaluation System IAP Integrated Action Plan I&C Instrumentation and Control IE NRC Office of Inspection and Enforcement IFI Inspector Followup Item IPBS Integrated Planning, Budgeting and Scheduling KW Kilowatt LC0 Limiting Condition for Operation LER Licensee Event Report MG Motor Generator M0V Motor Operated Valve MST Maintenance Surveillance Test NRC Nuclear Regulatory Commission NRR Nuclear Reactor Regulation PA Protected Area PIC Process Instrument Calibration l
PM Plant Modification PNSC Plant Nuclear Safety Committee PRA Probabilistic Risk Assessment
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PT Periodic Test QA Quality Assurance QC Quality Control RCIC Reactor Core Isolation Cooling RHR Residual Heat Removal SIL Service Information Letter SLC Standby Liquid Control SR0 Senior Reactor Operator
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SRV Safety Relief Valve SSFI Safety System Functional Inspection STA Shift Technical Advisor TS Technical Specification URI Unresolved Item WR/JO Work Request / Job Order
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