ML20216B174
| ML20216B174 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 03/02/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20216B149 | List: |
| References | |
| 50-324-97-15, 50-325-97-15, NUDOCS 9803120431 | |
| Download: ML20216B174 (27) | |
See also: IR 05000324/1997015
Text
U.-S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos: 50-325. 50-324
Report No: 50-325/97-15. 50-324/97-15-
Licensee: Carolina Power & Light (CP&L)
Facility: Brunswick Steam Electric Plant. Units 1 & 2
Location: 8470 River Road SE
Southport. NC 28461
Dates: December 28. 1997 - January 31. 1998
Inspectors: C. Patterson, Senior Resident Inspector
E. Brown. Resident Inspector
E. Guthrie.. Inspector in Training
J. Coley, Reactor Inspector (Section M1.2 - M2.2)
Approved by: M. Shymlock. Chief. Projects Branch 4
Division of Reactor Projects
9903120431 980302
PDR ADOCK 05000324
0 PDR _
Enclosure 2
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EXECUTIVE SUMMARY ;
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Brunswick Steam Electric Plant. Units 1 & 2 1
NRC Inspection Report 50-325/97-15. 50-324/97-15
1
This integrated inspection included asrects of licensee operations. J
engineering, maintenance, and plant support. The report covers a 6-week 4
period of resident inspection: in addition it includes the results of a
maintenance inspection by a regional inspector.
Doerations
. A recirculation pump trip occi rred as a result of an electrical fault on
a transmission line. The transmission line was promptly restored and
the recirculation pump was satisfactorily ret"rned to service. Operator
response to the resultant transient was good (Section 01.1).
. The inspector concluded that the site alarms were being tested in
accordance with procedure requirements (Section 02.1). j
Maintenance l
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. The inspector concluded, from observation of routine maintenance l
activities, that the licensee was continuing to upgrade the material '
condition of plant equipment and equipment spaces (Section M1.1).
- Corrective and predictive maintenance activities observed were conducted
in a thorough and effective manner (Section M1.2).
- Technicians observed performing maintenance surveillance tests were ;
skillful, experienced, and knowledgeable of their assigned tasks I
(Section M2.1).
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. Discrepancies identified by maintenance technicians during a
< surveillance test indicated weaknesses in foreign material exclusion
'
controls test fixture traceability controls and the handling and l
storage of internally contaminated test equipment (Section M2.1).
- Numerous examples of inadequate control of special processes were
identified by the licensee of vendor examination activities for the
Unit 2. H6B reactor core shroud weld (Section M2.2).
- Extensive effort was subsequently expended by the licensee to identify
vendor examination problems and to implement corrective actions
necessary to compare ultrasonic data taken during refueling outages 12
and 13 for the Unit 2. H6B reactor core shroud weld (Section M2.2).
. The ECCS Response Time Testing was being conducted as a group of tests
at different times. This methodology requires further review
Section M3.1).
2
e Multiple failures of the Plant Process Computer (PPC) occurred during
the months of December 1997 and January 1998. A violation was issued
for failing to initiate Condition Reports for repetitive failures of the
PPC (Section M4.1).
Enaineerino.
- Instrument setpoint changes, deemed more conservative than existing TS
requirements, were being made in preparation for converting to Improved
Standard Technical Specifications. The inspector concluded that the
implementing instructions and changes needed additional clarification
and license review (Section E2.1).
- Inspector's review determined that the logic testing for the reactor
core isolation cooling condensate storage tank low water level automatic
transfer and the generation of the isolation signal on high turbine
exhaust diaphragm pressure were completed satisfactorily in accordance
with Technical Specifications (Section E3.1),
Plant Sucoort
. The inspector' concluded that Health Physics technician daily walkthrough
procedures lacked guidance to ensure continuity of walkthroughs
(Section R4.1).
- Twenty-eight doors in the Diesel Building were modified defeating the 3
hour fire rating of the doors. An unresolved item was issued to allow
additional review for the failure of the licensee to perform an adequate 1
- engineering review prior to modifying required fire protection quality
hardware (Section F4 1).
.
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Report Details
Sammary of Plant Status
Unit 1 operated continuously during this report period. At the end of -
this report period the unit had'been on-line continuously for 78 days. '
Unit 2 operated continuously during this report period. A recirculation
pump trip occurred on January 27. 1998, following the loss of an offsite
power feeder line. The transient, which occurred due to an electrical
fault, caused 6 loss of the 2B reactor recirculation pump motor
generator set. Reactor power decreased to around 55 percent due to the
loss of the recirculation pump. At the end of the report period, the
unit had been on-line continuously for 101 days.
Due to concerns about the control room dose. the licensee imposed an
administrative limit on Iodine until a Technical Specification (TS)
amendment submitted was approved. The licensee made a procedure change
to Administrative Procedure OAI-81. Water Chemistry Guidelines, setting
the limit at 0.1 microcurie per gram dose equivalent Iodine 131 comparod
to the TS value of 0.2 microcurie per gram. Also, the licensee has bmi
providing weekly water chemistry data to NRR and the Resident Inspector
for review. None of the data reviewed has exceeded the administrative l
limit. ]
Due to a reconstitution of the Environmental Qualification (E0) program
and items identified, there are 9 of 24 Justification for Continued
0)eration (JCO) that remain open for both units. The following provides
t1e status of the EQ JC0s and associated Engineering Service Requests ,
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(ESRs)-
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Closed i
1) ESR 97-00087. E0-Type JC0 for Improperly Configured Conduit Seal.
2) ESR 97-00574. Greyboot' Connectors. l
3) ESR 97-00329 (old ESR 96-00625). EQ Type JC0 for E0 Fuses Without
a Qualification Data Package (0DP).
4) ESR 97-00289. Post Accident Sampling System (PASS) Valve Limit l
Switch Panel Wiring.
5) ESR 97-00238. JC0 for Standby Gas Treatment Motor Operated Valve
(MOV) Position Indicator Rheostat.
6) ESR 97-00534. GE EB-5 Type Terminal Strips.
7) ESR 97-00513. In-Board Drywell Electrical Penetrations.
8) ESR 97-00535. Target Rock Solenoids Terminal Block Spray.
9) ESR 97-00449. Degraded Junction Boxes.
10) ESR 97-00250. Conduit Union in E0 Boundary.
11) ESR 96-00425. Evaluation of E0 sealants.
12) ESR 97-00523. High Pressure Coolant Injection (HPCI) Auxiliary Oil ,
Pump Motor Unit 1. '
13) ESR 97-00446. GE Radiation Detectors.
14) ESR 96-00587 PASS Valves. ,
15) ESR 97-00229. JC0 for GE Type 151 B Terminal Blocks.
2
DEG 4
16) ESR 96-00503. Associated Circuit E0. closure date To Be Determined. l
(TBD).
.17) ESR 97-00330 (old ESR 96-00501). Motor Control Center (MCC) E0 was
closed by the licensee, but was reopened - closure date TBD.
'
18) ESR 96-00426. . Evaluation Quality class and E0 classification of'
PASS valves was scheduled for completion June 6.1997, but closure
date is TBD.
19) ESR 97-00529. Failure of Unit 1 Drywell Motor. closure date TBD.
20) ESR 96-00627. ODP.for Marathon 300 Terminal Blocks was scheduled
for completion December 31. 1997 but revised to August 1. 1997,
but closure date is now TBD.
21) ESR 97-00206. Main Steam Isolation Valve (MSIV) Hiller Actuator 1
JCO. was scheduled for completion September 2.1997, but closure
date.is now TBD.
22) ESR 97-00343. Qualification of Kulka Model 500 Terminal Blocks was
scheduled for completion September 1. 1997, but closure date is
now TBD.
23) ESR 97-00435. MCC Fittinas, closure date TBC
'24 ) ESR 97-00602. Solenoid Vilve Field Wiring closure date TBD.
In summary Unit 1 and 2 operated continuously despite a trip of the
Unit 2 ~B" recirculation pump. However, there were 9 outstanding JC0s
in the E0 area for both units.
I. Operations
01 Conduct of Operations
01.1 Unit 2 ~B" Recirculation Pumo Trio
a. Insoection Scooe (71707)
The inspector reviewed the circumstances surrounding the January 27,
1998, trip of the 2B recirculation pump.
b. Observations and Findinas
-On January 27, 1998, both units were operating at 100 percent power. At
10:22 a.m. the 2B recirculation Jump tripped. The resultant decrease in
core flow caused entrance into t1e 5 percent thermal hydraulic
instability (THI) buffer region. The o)erators, in accordance with
Engineering Procedure OENP-24. Reactor Engineering Guidelines, inserted
rods to exit the 5 percent buffer region. Upon loss of the
recirculation pump. Unit 2 entered Abnormal Operating Procedure 2A0P-4.
Low Core Flow and Technical ' Specification (TS) Action 3.4.1.1.
Recirculation System, which required the power level reduced or core
flow increased until the limits established in TS Figure 3.4.1.1-1 were
met. The plant was stabilized at approximately 55 percent . cower with no
-indications of THI observed. The trip of the 2B recirculat. , pump was
attributed to an undervoltage trip as a result of an electrical fault on
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l a transmission line due to a damaged insulator which caused the loss of
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the Whiteville offsite feeder. The inspector verified that two
physically independent circuits were available throughout the transient.
This event was recorded in Conditior Reports (CR)98-181. 2B
Recirculation Pump Trip.98-185. Loss of 2B Recirculation Pump, and
98-184. Insulator Damage - Whiteville Line.
The licensee further reduced power to approximately 33 percent to
establish proper temperature and flow conditions for restart of the
tripped recirculation pump. At 1:50 p.m. the licensee attempteo to
restart the 2B recirculation pump: however, the 4160 volt drive motor
breaker had tripped when the internal drive motor temperature switch
stuck in the tripped position. The switch was removed and a new switch
installed. This event was recorded in CR 98-186. Failure of the 28 to
Start. The licensee successfully restarted the recirculation pump, thus
returning to two-loop operation at 9:05 p.m. The inspector observed
good operator response to the transient, procedure usage by the
operators and oversight by Operations supervision. The inspector
verified that the actions prescribed in 2A0P-4 were properly conducted
and TS properly applied.
The licensee questioned why the 2B recirculation pump received an
undervoltage trip and the 2A did not. Licensee review has not
definitively established the root cause for one pump tripping and not
the other. The inspector noted that this trip was similar to a
recirculation Jump trip on June 25. 1996, which resulted from a l
lightning stri ce as documented in NRC Inspection Report (IR) 50- j
325(324)/96-10. Licensee investigation into the cause of the !
recirculation pum) trip for the 2B pump and not the 2A pump, and the i
cause of the stucc temperature switch were underway.
c. Conclusion
A recirculation pump trip occurred as a result of an electrical fault on
a transmission line. The transmission line was promptly restored and
the recirculation pump was satisfactorily returned to service. Operator
response to the resultant transient was good.
02 Operational Status of Facilities and Equipment !
02.1 Weekly Test of Emeraency Alcrms
a. Insoection Scone (71707)
On January 9.1998, the inspector reviewed the weekly test of the plant
emergency alarms.
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b .- Observation and Findinas
l< During.a routine tour of the Unit 2 Reactor _ Building, the inspector
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noticed that.no other person was in the area while the site alarms were
- being tested. The site evacuation alarm, fire alarm. and building
l evacuation alarm are tested every Friday at 9:00 a.m. Each building
evacuation alarm is tested, such as Unit 2 Reactor Building Radwaste
. Building, etc.
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-The inspector questioned the control room operators that perform the
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test whether anyone was placed in the various buildings during the test.
No one was placed in the buildings during the test and it was not-
required by plant procedure. The alarms were tested by procedure 001-
01.04, Communications. The inspector reviewed this procedure. but it
only provided the public address system announcement used during
testing. The licensee stated that this test was done weekly to
familiarize personnel with the alarms.
The licensee stated that full volume testing was being performed by
procedure OPT-4.8.2.3. Public Address System Volume Level Bypass. The
inspector reviewed this procedure. This test requires placement of a
Jerson in the area being tested. The acceatance criteria was that the
Juilding/ area alarm was audible and that t1e warning lights were
visible. !
c. Conclusions
The inspector concluded that the site alarms were being tested in
accordance with procedure requirements.
02.2 Soecial UFSAR Review
A recent discovery of a licensee operating the facility in a manner
contrary to the' Updated Final Safety Analysis Report (UFSAR) description
highlighted the need for a special focused review that compares plant
practices, procedures, and/or parameters to the UFSAR descri)tions. l
dhile performing the inspections discussed in this report. tie-
inspectors reviewed the applicable portions of the UFSAR that related to
the areas inspected. The inspectors verified that the UFSAR wording was
consistent with the observed plant' practices, procedures, and/or
parameters.
The inspector reviewed the UFSAR Section 13.3, Emergency Planning, to
- review any alarm testing requirements. This section of the UFSAR
contains only a short paragraph that plans for coping with emergencies
are contained in the Radiological Emergency Res.?onse Plan. No
requirements are contained for alarm testing.
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II. Maintenance
M1 Conduct of Maintenance I
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M1.1 General Comments
a. Insoection Scooe (62707)
The inspector observed a portion of the following work activities:
. Diesel Generator (DG) 3 Scheduled Maintenance outage
. DG Building Ventilation Filter Upgrade
. Control Room Cable Sealing
d
b. Observations and Findinos
The inspector observed maintenance activities in the DG building on 1
January 12. 1998. Cylinder liner replacements were being conducted for j
four cylinders on DG 3. The inspector checked various clearance tags
for the work under clearance CL 2-97-00975. The work around the diesel
was controlled as a Foreign Material Exclusion (FME) area. i
The inspector observed the material upgrade of the building ventilation
filters. The old filters had been removed and support housing freshly
painted. One end of the building was completed with new filters
installed. This corrected the degraded material condition discussed in j
NRC IR 97-08. Section M1.1.
The licensee was conducting additional sealing of cable penetrations in
the floor of the control room cabinets. The cabinets were initially
sealed with a putty- type substance, but testing using a gas tracer
revealed leakage. The new sealing material was being' poured into the
cabinet floor area to provide a better seal. Another test was planned
once all cabinets were sealed.
c. Conclusions
The inspector concluded, from observation of routine maintenance
activities, that the licensee was continuing to upgrade the material
condition of plant equipment and equipment spaces.
M1.2 Observation of On Line Maintenance Activities
a. Insoection Scooe (62700)
The inspector examined the following on-line maintenance activities to
verify that mainteaance activities were being conducted in a manner that
resulted in reliable and safe operation of the plant.
- WR/JO 97-AIXP1 Unit 2 Repair Rad-Waste Floor Drain Sample Pump (2-
,
G16-C021A) Mechanical Seal (seal was leaking).
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. WR/JO 98-AABU1 Unit 2. 2B Motor Generator (MG) Set Outboard Motor
Bearing was Making an Abnormal Noise Indicative of a Problem.
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b. Observations and findinas
The aboie work was performed with the work package present and in active
use. Technicians were skillful, experienced, and knowledgeable of- their
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assigned tasks. The mechanical seal was successfully replaced on the
radwaste pump. Excessive vibration readings from the Unit 28 MG set
l resulted in the outboard motor bearing and the outboard generator
bearing being classified in the alert status. The licensee planned to
monitor the 2B MG set weekly until the bearings are changed out.
Tentative schedule will be to replace the bearings during the week of
February 16, 1998.
c. Conclusions
Maintenance activities observed were ccnducted in a thorough and )
effective manner.
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M2 Maintenance and Material Condition of Facilities and Equipment j
M2.1 Observation of Maintenance Surveillance Test (MST)
a. Insoection Scone (62700)
The inspectors observed the following surveillance calibration tests on
Unit 2:
. 2MST-RHR250, Residual Heat Removal (RHR) Pump Pressure Automatic
Depressurization' System. (ADS) Permissive Instrument Channel
Calibration.
- 2MST-RHR270. RHR Shutdown Cooling Reactor Pressure Instrument
Channel Calibration.
b. Observations and Findinas
Maintenance Eurveillance Test 2MST-RHR250 verified that all eight-
pressure switches were in calibration. The inspector also verified that
test equipment was properly calibrated. test procedures were followed
and testing was adequately performed. )
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-On January 7. 1998, the inspector observed a technician filling a test
hose to remove entrapped air in order to perform liaintenance ;
Surveillance Test 2MST-RHR27Q on the RHR Shutdown Cooling Reactor !
Pressure Instrument B32-PS-N018A-1. when an unexpected fluid slurry of !
resin came out of the hose and onto the floor. Further investigation by !
a health physics technician revealed that the resin we> contaminated. 2
The comparator pump and hose had been stored in a Unit 2 gang box marked
for contaminated storage. However, neither_the comparator pump nor the I
high pressure hose had been packaged to prevent the spread of !
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- contamination after 'ts previous use. The comparator pump and hose were
i subsequently packageJ and transported to a decontaminated area and {
replaced with other equipment from an equipment storage area within the 1
l reactor building. The inspector questioned the technician concerning
i the contaminated test equ pment and discovered that neither the ,
comparator pump nor the h gh pressure hose had serial numbers on them in
order to trace their previous use to determine if contaminated foreign
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material had entered other systems. In addition, the practice of
! storing internally contaminated test equipment in gang boxes was 4
L discussed. The technician subsequently notified his supervisor and CR
- 98-00029. Contaminated Test Equipment was issued to address the lack of j
! traceability of the test equipment, possible violation of foreign !
material exclusion requirements. and storage of internally contaminated
l equipment. Since previous we of the test equipment had not been i
! determined at the conclusion of the ins)ection, the inspector identified ,
l this item as Inspection Followup Item 1:1 50-325(324)/97-15-01. Test
l Fixture Discrepancies. Subsequent to the inspection, on January 12,
1998, the licensee not,fied the inspector that (1) all contaminated i
equ pment had been. removed from gang boxes and stored in a contaminated
l too room inside the plant. (2) an inspection had been conducted of the
, internals of dead weight testers and hoses, and the problem of cross J
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contamination was determined to be confined to hoses. (3) the previous
use of the hose which would have allowed the RHR system to be cross
centaminated was found to have occurred on January 2,1998, during work
activities implemented by Work Request / Job Order (WR/J0) 96-AG0K1 which
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directed maintenance technicians to unclog a rad-waste sample line, and
l that the hose had not been used since, and (4) programmatic controls
- were planned to be instituted to identify and control test equipment.
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l c. Conclusion
Technicians observed performing maintenance surveillance tests were
skillful, experienced, and knowledgeable of their assigned tasks.
However, discrepancies were identified by technicians which indicated
weaknesses in foreign material exclusion controls test fixture
traceability controls and the handling and stora;p of internally j
contaminated test equipment.
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M2.2 Unit 2 Shroud Weld H6B Ultrasonic Data Review
a. Insoection Scooe (737531
On January 9.1998, representatives from the licensee, the Electrical
Power Research Institute (EPRI), and the inspector reviewed automated '
ultrasonic data taken of reactor core shroud Weld No. H6B. during the
Brunswick Unit 2. 12th and 13th refueling outages. This review was
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conducted at the EPRI Nondestructive Examination (NDE) Center in
Charlotte. North Carolina. The review was necessary to confirm the
licensee's analyses of the differences in data, and the actions taken by
the licensee when the crack depths reported by an ultrasonic vendor were
consistently less in 1997 than those reported by the same vendor in
1996.
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b. ' Observations and Findinas
The licensee notified the inspector on October 9,1997. that there were
differences between the 1996 and the 1997 data and that crack depths on
core. shroud Weld No. H6B were consistently less in 1997. The licensee
stated that the raw data for 1996 and 1997 had been sent to'the EPRI NDE
center for their review. The licensee recuested that the EPRI NDE
center review the analysis process. procecures, tooling hysteresis,
tooling start positions, scan patterns, etc., to hel) the licensee
understand the effects these items may have had on tie differences in
the 1996 and 1997 crack depths. The licensee provided the inspector
with spreadsheets of the initial results of both inspections.
Arrangements were made at that time to review the results of the
CP&L/EPRI evaluations at the EPRI Center in order to verify the
subsequent conclusions using the raw ultrasonic data from both outages.
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The licensee issued CR 97-03902. Unit 2 Core Shroud Weld H6B. and with
assistance from EPRI conducted an extensive review of the problem.
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L On January 6 and 7.1998, the inspector reviewed documentation including
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the licensee's and EPRI's shroud examination findings delineated in CR
L 97-03902 in preparation for the inspection to be conducted at the EPRI
L NDE Center on January 9. Initial discrepancies reported by the licensee
l- in the CR consisted of the following: (1) the 1996 flaw depths were
reported as being taken in one inch increments when the ultrasonic data
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disks indicated the data was taken in 0.775 inch increments. (2) the
1997 data was not interpreted in areas where the data overlapped with
other ultrasonic scans resulting in some data being missed. (3) the
azimuthal locations of the data shifted causing flaws to be reported in
l areas that were reported as unflawed areas in 1996. (4) the tooling
i location error may be outside that used for analysis of the ultrasonic
results, and (5) the depths of the flaws in 1997 were significantly less
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than those determined in 1996 without any substantiated reason.
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l In the CR root cause analyses. the licensee captured the above reported
l problems in three central issues:
(1) The depths and lengths of the flaws were reported inaccurate:
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- The cause of the depth difference was attributed to the j
difference in rasper scan size between the 1996 and 1997
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examinations: the one inch ras)er scans were too large to ;
produce comparable crack growt1 results each outage: .and ;
impurities in the weld sometimes were included in the 1996 .
interpretation of crack depth. !
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. The cause of the lateral displacements was attributed to
failure of the analyst to sufficiently review overlap data.
Therefore, when start point errors in scanning were made
they were not compensated for in the analysis.
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(2) The data collection and analysis process discrepancies with
respect to tool location, data collection location validation, and
analyses of the results:
. Review of the inspection data revealed three known instances
where the 1997 data collected was not at the stated
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location.
. Additionally, the positioning tool was not precisely placed
against the lug.
- One instance was found where the licensee believes the
offset specified in the examination plan was not used for
the scan.
- Review of the 1996 data revealed that scans did not begin at
the location stated in the report, but were separated by
several degrees.
. Examples of discrepancies made by the analyst were that not
all of the data collected was evaluated. This was due to
the analyst's failure-to perform comparison of overlap data
for matching flaw profiles. In addition, independent review i
of the final report for accuracy and completeness was not I
satisfactorily performed.
Review of the inspection procedures by the licensee determined that
these procedures lacked controls to prevent the above instances from
occurring. Examples of inadequate controls for data collection
included: verification of correct scan location, verification that tool
start positions are correct, verification that the correct location and )
identifiers-are entered into the data collection computer, and
verification that any offsets used were applied.
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-(3) The vendors quality assurance process was ineffective in detecting
these errors.
- The vendor cuality assurance process lacked steps to detect
the items icentified in this event report.
The CR also noted under immediate corrective action that EPRI had
concluded, based on re-evaluation of the ultrasonic data, that the flaw
depth analysis for both years was accurate.
On January 9. 1998, representatives from CP&L and EPRI. and the
i inspector selected 17 crack depth reflectors reported in the 1996
examinations for re-inspection. These cracks represented crack defect
differences between inspections of at least twice the ultrasonic root
mean square error band established by the vendor when demonstrating
their procedure techniques at EPRI on Boiling Water Reactor Vessel
Internal Program Mockup Blcck 16.
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The examination of the 1996 data revealed the following: (1) of the 17
crack reflectors.10 were single indications ana the analyst made the
o correct call. (2) of the remaining seven crack reflectors five appeared
l to be two separate indications one crack and the other possibly
involving a metallurgical condition in or near the weld which the ;
analyst had conservatively included in the crack length. (3) the two J
remaining crack indications appeared as two' separate indications but
both EPRI and the inspector interpreted the total presentation as one
l crack. The review of the 1997 data revealed that although this data was
documented as being two decibels more sensitive than the 1996 data, the
- test sensitivity and noise level was actually much higher.in the 1996
l data. This resulted in single reflector type A-scan data presentations
- on the screen in 1997, where in 1996, due to the higher sensitivity, the
analyst had to deal with signals and facets of signals that were not
present in the 1997 data. The inspector concluded from this review
that both the 1996 analyst and the 1997 analyst had made the correct
crack depth calls based on the data they were presented. Differences
noted in the evaluation of defect signals between 1996 and 1997 were not
significant and did not account for the significant depth differences i
encountered in the 17 reflector chosen for review. Therefore the
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differences encountered in crack depth could only be attributed to the
difference in the rasper scans (0.775 inch in 1996 verses one inch in
1997) between inspections and the fact that the one inch rasper scan was
too large to verify crack growth differences between refuelings. This
was demonstrated by the overall negative difference value obtained of
(-) 0.071 inch for the 1997 ultrasonic data of Weld No. H6B from the
data taken in 1996, which is anomalous; defect growth should htue been
encountered with time.
10 CFR 50. Appendix B. Criteria IX. Control of Special Processes,
requires that measures shall be established to assure that special
processes, including nondestructive testing are controlled. CR 97-
03902, delineated inspection procedure weaknesses and numerous vendor
examination discrepancies, as described above, which resulted in
documentation of ultrasonic data that was incorrect and was not
comparable to previous data to determine defect growth. This
nonrepetitive. licensee-identified and corrected violation is identified
as a Non-Cited Violation, consistent with Section VII.B.1 of the NRC
Enforcement Policy and i.s designated NCV 50-324/97-15-02. Inadequate
Control of Special Processes,
c. Conclusions
Numerous examples of inadequate control of special processes were
identified by the licensee of vendor examination activities for the
Unit 2, H6B reactor core shroud weld. These discrepancies required the
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licensee to expend extensive time and effort to identify the cause and
( im)lement necessary corrective actions in order that ultrasonic data
tacen of the reactor core shroud H6B weld during the Unit 2.12th and
13th refueling outages could be compared.
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M3 -Maintenance Procedures and Documentation
M3.1 Emeraency Core Coolina System (ECCS) Response Time Testina
L a. Insoection Scoce (61726)
On January 9. 1998, the inspector reviewed the test data for a new
surveillance test performed on Unit 2.
I b. Observations and Findinas
The inspector reviewed Periodic Test OPf-08.2.7, Low-Pressure Coolant
Injection / Residual Heat Removal (LPCI/RHR) Pump Response Time Test. The
L test was performed to determine the operability of the LPCI/RHR pumps in
conformance with the requirements specified in TS 4.5.3.2.d. This
section of TS states that each LPCI subsystem shall be demonstrated
operable at least Once per 18 months by verifying the ECCS Response Time
for each LPCI subsystem is within its limit. The definition for ECCS
Response Time is in TS Section 1-0. Definitions.
The definition is as follows:
"The ECCS Response T'me shall be that time interval from
,~ when the monitored parameter exceeds its ECCS actuation
setpoint at the channel sensor until the ECCS equiament is
capable of Jerfcrming its safety function (i.e., t1e valves
- travel to t1eir required positions, pump discharge pressures
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reach their required values. etc.). Times shall include
diesel generator starting and sequence loading delays where
applicable."
The inspector reviewed the procedure and test data. ~he test data
,
indicated that the response time of each of the two RHR pumps in Loop A
l and Loop B was about 2 seconds. The acceptance criteria stated that
when each pump was started the RHR heat exchanger inlet pressure should
be greater than or equal to 215 pounds per square inch gauge (psig) in
less than.or equal to 4.0 seconds.
l Thus, each pump tested met the acceptance criteria. However, the
inspector questioned the definition that times shall include diese'
generator-(DG) ' starting and sequence loading delays where aiolicole.
l The new test was written to greatly simplify the old test tiat was
L performed with the unit off-line.
i
The inspector reviewed ESR 97-00508, ECCS Response Time Testing Methods,
p which 3rovided the basis for the testing change.. This ESR indicates
that L)CI response time was 53 seconds. A discussion of this time is
broken into several intervals. -The first time interval of 15 seconds
allows for DG start and energizing of the emergency bus. The next time
interval is 12.5 seconds for LPCI load sequence delay. This is followed
by 4 seconds for the pump response time.
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However, this new test only checks the pump response time of 4 seconds
and not the other times specified in the sequence above. The complete
l testing of all times could not be verified using this test. The
'
licensee stated that other times are tested using a different procedure
but at different times in the 18 month time requirement. This test
methodology and generic implications requires further review. This will
be identified as Inspection Followup Item IFI 325(324)/97-15-03. ECCS
Response Time Testing.
c. Conclusions
The ECCS Response Time Testing was being conducted as a group of tests
at different times. This methodology requires further review.
M4 Maintenance Staff Knowledge and Performance
M4.1 Process Comouter Failures
a. Insoection Scooe (62707. 37551)
The inspector reviewed recent failures of the )lant process computer and
the corrective actions taken in accordance wit 1 the maintenance rule and
the corrective action program.
b. Observ6tions and Findinos
On December 22. 1997, during routine review, the inspector noted that at
3:49 a.m. on December 20. 1997. the /lant Process Computer (PPC) ceased
producing the heat 'oalance for Unit 2. This malfunction was aromptly
corrected by 5:50 a.m. on December 20. On January 5. 1998, t1e
inspector noted that the PPC had gone down again at 8:48 p.m. on
January 4. 1998, and was restored at 7:42 a.m. on January 5. 1998.
During the January 4.1998. failure, the control room operators were
instructed not to increase recirculation flow or perform any evolutions
that could potentially increase core thermal power and engineering '
.
support was required to perform core thermal power calculations using
Periodic Test OPT-1.80. Core Tht mal Power Calculation. These actions
were consistent with a previous failure on November 18. 1997, as
recorded in CR 97-4004 Queue Manager Failure-U2 PPC. A Standing
Instruction (SI) 97-76 was initiated-for the November 18, 1997, to l
inform operations personnel to limit reactor power to less than 99.5
percent if the PPC fails. The SI also established frequencies for the
Nuclear Engineers to monitor thermal power indication and other
procedures to satisfy TS 4.2.1.a-c. 4.2.2.la-c. and Table 4.3.1-1
Note (e) surveillance requirements. The inspector verified that the
licensee took appropriate actions and no limits were exceeded.
The inspector questioned the licensee, after the December 20 and
January 4 failures, concerning the absence of CRs for the failures. The
licensee indicated that since the PPC performance criteria had not been
,
exceeded, no CR was required. After further licensee review. CR 98-012. l
j Unit 2 PPC Data Acquisition System failures was issued on January 6. 1
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1998. The CR recorded the increasing trend in PPC failures during
l
December 1997 and January 1998 for Unit 2. Plant Program Procedure
OPLP-04. Corrective Action Management, requires the initiatioc of a CR
for repetitive equipment failures. The inspector identified that no CRs
were generated until questioned by the NRC about the failures on
December 3 and 30, 1997 for Unit 1 and December 3. 10 and 20. 1997 and
January 4. 1998 for Unit 2. The failure to initiate CRs for repetitive
failures of the PPC is a violation. This violation is identified as VIO
50-325(324)/97-15-04, No CRs for Plant Process Computer Failures.
The inspector reviewed the Maintenance Rule PPC Scoping and Performance
Criteria. The performance criteria for the system was based upon an
expectation of 99 percent availability over a three year period minus
time for two scheduled refueling outages. This translated into an
unavailability goal of 274 hours0.00317 days <br />0.0761 hours <br />4.530423e-4 weeks <br />1.04257e-4 months <br /> per 36 months. The licensee scoping
report-indicated that this time was sufficient to permit development of
a trend toward unsatisfactory system performance. The inspector
questioned whether the established performance criteria was adecuate in
assessing degrading performance of the PPC. since the 36 month curation
of the allowable unavailability time masked observed degradation over
short periods of time. The inspector was also concerned that due to not
initiating a CR the long duration of the allowable unavailability time
would not prompt the performance of a cause determination for the
functional failures in accordance with the guidance 3rovided in Section
9.4.4 of Nuclear Management and Resources Council (NJMARC' 43-01.
Industry Guideline for Monitoring the Effectiveness of KJntenance at
Nuclear Power Plants. Review of the sco)ing report, indicated no
recorded unavailability for Unit 2 from rebruary 1995 through October
1997. However, from November 1997 to January 1998, the report stated
that the PPC had been unable to provide its intended function in excess
of 45 hours5.208333e-4 days <br />0.0125 hours <br />7.440476e-5 weeks <br />1.71225e-5 months <br />. The inspector determined that this sudden increase in
unavailability was evidence of system degradation. After further
licensee review, the PPC performance criteria was modified to require no
less than 21 hours2.430556e-4 days <br />0.00583 hours <br />3.472222e-5 weeks <br />7.9905e-6 months <br /> per quarter of unavailability for the PPC. Under the
new criteria, the Unit 2 PPC exceeded the established performance
requirements.
t Conclusion
Multiple failures of the Plant Process Computer occurred during the
months of December 1997 and January 1998. A violation was issued for-
failing to initiate Condition Reports for repetitive failures of the
PPC,
M8 Hiscellaneous Maintenance Issues (92902)
M8.1 (Closed) Violation VIO 50-324/96-18-02: Testing Using Uncalibrated
While observing the performance of Periodic Test OPT-8.2.2c LPCI/RHR
,
Sys'w Operability Test - Loop A for Unit 2. the inspector identified
! that the test was being performed using uncalibrated pressure gauges on
I
14
the RHR pumps A and C discharge side. The licensee was using temporary
gauges due to an existing drift problem affecting the calibration of the
permanently installed gauges (2-E11-R003A(C)). The. failure to
, incorporate test requirements into the testing procedure and to properly
l identi.fy the out-of-calibration gauges in the Automated Maintenance
l -Management System (AMMS) resulted in the use of those gauges during the
! operability test.
Violation VIO 50-324/96-18-02 was issued to address this failure. The
licensee reperformed OPT-8.2.2c with properly calibrated gauges.
Subsequently, the 2C RHR ) ump was.placed in the alert range which
, required an increase in t le testing frequency. The licensee revised-
!
Plant Program Procedure OPLP-24. Work Management Process, to require
identification of each deficient item either by a separate WR/JO or by
listing each component in the secondary equipment field on a single
WR/JO to ensure all nonconforming gauges are appro)riately captured.
Training was provided to the Operations staff on tie correct fields to
access to determine deficient components, based on a finding by the
licensee that many staff personnel were not aware of a secondary
function in AMMS needed to be accessed to perform an adequate search for
outstanding components. During this event, the requirement to use
temporary gauges for this periodic test were improperly located in a
Standing Instruction. The licensee performed a review to determine
,
I
whether.other procedural requirements were being controlled outside of I
an approved procedure. Several deficiencies were discovered and I
promptly corrected.
The licensee responded to the Violation issued in IR 50-325(324)/96-18
in a letter dated March 17, 1997. The inspector reviewed the root cause
analysis, revised procedures, and assigned corrective actions. The
corrective actions instituted were adequate to prevent recurrence.
Based on adequate completion of the corrective actions. this item is
closed.
M8.2 LClosed) Insoection Followuo Item IFT 50-325(324)/97-02-03: PM
Frequencies Based on Appropriate Plant Fuel Cycle
Review of the Transmission Substation Maintenance Procedures Manual
revealed that the frequency for performing preventive maintenance (PM)
procedures on components which require the unit to be in an outage in
order to perform the PM had not been updated to reflect the new 24-month 1
-fuel cycle for. Unit 1. The licensee had issued CR 97-01670. IFI 97-02. !
( PM Frequencies, on this issue. However, the offsite System Reliability
L 'and Power Quality (SRPQ) group which is responsible for revising these
procedures, had not done so to date. The primary reason SRP0 had not
revised the proceAres was due to Unit 1 not actually being in the 24-
month fueling cyca until the year 2000 and Unit 2 until 2001. However. !
the licensee had requested that SRPQ revise the appropriate procedures ;
by June 1. 1998. The inspector held discussions with the licensee's l
cognizant engineer, reviewed the schedule for Units 1 and 2 refueling l
cycles and determined that the licensee had control of this corrective
action and no additional inspection was necessary. This item is closed.
15
III. Enaineerina
-E2. Engineering Support of Facilities and Equipment
E2.1 Drywell Pressure Setooint Chanae
a. Insoection Scoce (37551)
The inspector reviewed the reason why the Unit 1 Reactor Protection
System (RPS) Hign Drywell Pressure Trip Setpoint was being changed on an
operating unit.
'b. Observations and Findinas
On January 8,1998, the inspector learned, by attending the morning
meeting. that a setpoint change was being made for Unit 1 RPS High
Drywell Pressure. This parameter is monitored because it provides
indication of a Loss of Coolant Accident. The setpoint was being
changed from 1.8 to 1.7 psig; the TS limit is 2.0 psig. The basis for
the change was due to Improved Standard Technical S
However. ITSs have not been approved for Brunswick.pecification (ITS).
-
The setpoints were being changed per ESR 97-0025. Implement Unit 1
Instrument Setpoint Changes. The ins)ector. reviewed the ESR that i
discussed implementation of some of tie ITS instrument setpoint changes.
The purpose of the ESR was to implement the instrument setpoint and TS
Allowable Value-(AV) changes-that result from ITS and'24 month refueling
project.
From the ESR there were 18 setpoint changes that were called "More
Restrictive Changes", which were determined to be more conservative than
the existing setpoint. The licensee determined that these could be
implemented prior to NRC approval. There were 11 setpoint changes that
were called "Less Restrictive Changes" which could only be made after
NRC ap3roval of ITS. The drywell pressure setpoint change was a change
that t1e licensee called "More Restrictive".
The inspector noted that on the cover sheet for the approval of the ESR
was a block checked._ "NRC Before Implement:ition." However, the ESR
itself allowed partial implementation. The inspector noted a statement
on page 3 that ITS had been-reviewed by Nuclear Assessment Section (NAS)
and Plant Nuclear Safety Committee (PNSC) and will be reviewed by the
NRC prior to implementation.
-The inspector questioned the licensee concerning implementation of these
changes prior to NRC approval and the lack of PNSC review prior to
implementation. A conference call with NRR was held on January 13.
L 1998, to discuss these issues. It was discussed that ITS had not been
approved yet, but maing more conservative changes prior to NRC ap3roval
had been an approach taken by other licensees. The review of whic1
items were conservative and non-conservative was discussed by the NRC as
something PNSC should review.
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The licensee was responsive to these issues and revised the ESR to
clarify the implementation process. The setpoint changes were discussed
l in a PNSC meeting February 3. 1998.
c. Conclusions
l
Instrument setpoint changes, deemed more conservative than existing TS
requirement, were being made in preparation for converting to Improved
Standard Technical Specifications. The inspector concluded that the
implementing instructions and changes needed additional clarification
and license review.
E3 Engineering Procedures and Documentation
E3.1 Testina of Safety-Related Loaic Circuits
a. Insoection Scoce (37551)
As a result of continuing industry problems to correct previously {
identified problems in logic circuit testing, the NRC issued Generic
Letter (GL) 96-01. Testing of Safety-Related Logic Circuits, in GL 96-
01, the NRC requested that the licensee review the plant surveillance
test procedures to verify adequate testing of all logic circuit
components. If testinc discrepancies were identified, the licensee was
instructed to modify the surveillance procedures to comply with the iS.
The inspector performed a review of selected TS required functioris for
the Reactor Core Isolation Cooling (RCIC) system.
b. Observations and Findinas
The inspector revi >wed the adequacy of the surveillance logic testing
for the RCIC suction automatic transfer on low-level in the condensate
storage tank (CST). Harmally, upon reaching the low-level setpoint, the .
CST suction valve receives a close signal unless one of the two I
suppression pool suction valves are not open. When in standay, the
opening of both suppression pool suction valves causes the automatic )
closure of the CST suction valve.
The ins)ector reviewed the adequacy of the surveillance logic testing
for tur)ine exhaust diaphragm's high pressure isolation function. This
function isolates RCIC u)on sensing a high pressure condition between
the turbine exhaust diapiragms.
The inspector reviewed Maintenance Surveillance Test (1)2MST-RCIC41R.
RCIC Auto-Actuation and Isolation Logic System Functional Test.
Maintenance Surveillance Test 2MST-RCIC230. RCIC Turbine Exhaust
Diaphragm High Pressure Instrument Channel Calibration, and the
associated elementary and control wiring diagrams. Based on inspector
review, the inspector determined that surveillance testing of relay
contacts. interlocks, and bypass was sufficient to provide adequate
logic testing for those functions reviewed.
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c. Conclusions
Inspector's review determined that surveillance procedures testing of
! generation of the isolation signal on high turbine exhaust diaphragm
pressure were being conducted in accordance with TS.
E8 Miscellaneous Engineering Issues (92903)
E8.1 (Closed) Violation VIO 50-325/96-16-01: Improper Work Planning Resulted
in a Loss of Shutdown Cooling
l
( (Closed) Licensee Event Reoort LER 50-325/96-14: Loss of Shutdown
l Cooling During Instrument Rack Repair
i
On October 11. 1996, with Unit 1 in Mode 5 for refueling. a grour 8
- isolation was received. The isolation signal closed the 1-E11-F008-
Shutdown Cooling (SDC) suction valve resulting in the loss of the
primary loop used for decay heat removal. Prompt identif.ication and
l restoration of the system by the control room operator resulted in
! minimalization of the coolant heatup to less than 1 degree Fahrenheit
l ( F). The licensee subsequently reported this event in LER 50-325/
l_ 96-14.
l The inspector reviewed the violation response. LER 50-325/96-14.
. associated CRs and root cause analysis 96-3166. The inspector verified
! that the corrective actions.were completed. Hov?ver, the inspector
l noted that an issue identified in the root cause was not addressed by
any of the corrective actions. .During this event it was determined that
multiple root cause barriers were broken. The ESR failed to adequately
address the scope of the modification: scheduling personnel by)assed the
administrative controls in place to make a schedule change witlout
- understanding the impact the change would have on the unit
- and the work
l instructions were not adhered to by the maintenance workers. However,
the' corrective actions addressed the specific inadequacy of the system
!
impact evaluation contained in the ESR. proper adherence to work ticket
instructions, and counseling for those involved. The corrective actions
l~ were not assigned to the root cause which identified that scheduling
[ personnel bypassed the administrative controls.
Several' modifications were made to the process of making an outage scope I
change after the outage risk assessment had been performed. These !
changes were incorporated into Administrative Procedure 0AP-22. BNP
Outage Risk Management. The inspector discussed the adequacy of the
procedure changes and other modifications made to the outage scheduling
process with the licensee. The inspector observed that the addition of
extra supervisory approval before permitting a scope change to the
outage schedule provides extra op)ortunities to catch errors. The !
inspector identified that the lacc of checks and balances for l
unauthorized schedule changes, before the schedule is issued / worked.
'
could allow the same event to reoccur. .This conclusion was based on the
scope change process allowing an individual who initiates a change
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request to be the same individual who makes the change. After further
review by the licensee, the licensee stated that the process changes
provided adequate checks and balances to prevent bypassing the required
administrative approval the corrective actions taken are adequate to
prevent recurrence. Based on completion of those items committed to in
the LER and the violation these items are closed.
E8.2 (Closed) Violation VIO 50-325(324)/96-181-1013: Inadequate Design
l Control for Material Selection in Service Water Pump
l
-(Closed) Licensee Event ReDort LER 50-325(324)/96-03-00. 01. 02: Dual
l Unit Shutdown Due to Service Water Pump Inoperability
1
l This violation was due to the wrong material selection for some bolts in
Service Water pumps. Because of a pump failure and inspecti_on of other
pumps which revealed a common mode failure mechanism, both units were
! shutdown. Each service water pump had the bolts replaced with a new
material. Hastelloy, which was less susceptible to galvanic corrosion.
I
The licensee responded to this violation on August 9.1996. The
i licensee completed a number of corrective actions to address the
l violation. A procedure was developed to provide guidance for material
l selection. Follow-up inspections were conducted on 2A Nuclear Service
!
Water Pump in December 1996 and 2B Conventional Service Water Pum) in
January 1997. The results of these inspections were reported in _ER 50-
325(324)/96-03-02. No corrosion of the Hastelloy bolts was found. The
pump inspections completed the corrective action for this violation.
These items are closed.
E8.3 (Closed) Licensee Event Reoort LER 50-325(324)/96-015-00. 01: Technical
Specification Required Suppression Chamber Water Volume Discrepancy
l The licensee identified that the suppression chamber water volumes, as
stated in TS and the Updated Final Safety Analysis Report (UFSAR) were
l incorrect. The licensee took prompt action to control torus water
l
level, within the correct band, using site administrative controls until
a change was made to the TS. The licensee evaluated the necessary
-
! corrective actions satisfactorily and implemented a T5 change and a
UFSAR update to incorporate the correct water volumes. The TS
l
amendments, number 186 to license number DPR-71, and number 217 to
I license number DPR-62, were approved on August 28, 1997. This LER is
closed.
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IV. Plant Support
R4 Staff Knowledge and Performance in Radiological Protection and Control
l R4.1 Health Physics Technician Work ~ Practices
a. Insoection Scoce (71750)
The inspector observed radiological controls and procedural compliance
during a tour of the radiologically controlled area with a Health
- Physics (HP) technician.
!
i b. Observations and Findinas-
- On January 2,1998, the inspector observed a-HP technician perform a
L- . daily Unit 2 Reactor Building walkthrough. The performance of this
. walkthrough was governed by Environmental and Radiological Control
! (E&RC) procedure OE&RC-0100. Routine /Special Dose Rate Survey.
e
[ The inspector observed the technician perform general area radiation ,
I surveys in various locations on each elevation of the Reactor Building.
l fhe technician observed the condition of eculpment on the tours, looking J
L for water and steam leaks. The inspector cetermined that the tour by, I
the technician was adequate. No deficiencies were noted by the .
J
l ' inspector. The inspector questioned the technician as to whether there
were specific locations at which they were expected to perform surveys, j
'
check general conditions in rooms and components, or check radiation and j
l high radiation boundaries, etc. The technician exalained that there
were no specific guidelines given to conduct walkt1 roughs. The
inspector verified that no guidance was given in the procedure.
!
'
The -inspector questioned licensee management whether minimum walkthrough
l guidance was deemed necessary to ensure that management expectations
l were met during the performance of the procedural requirement. E&RC
i management agreed with the necessity to have minimal guidance for HP
technician walkthroughs. Further discussion with E&RC management
,
confirmed that corrective actions were being addressed to formulate
l guidance.
c. Conclusions
l
'
The inspector determined that the tour by the technician was adequate.
The inspector concluded that HP technician daily walkthrough procedures
lacked guidance to ensure continuity of walkthroughs.
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F4 Fire Protection Staff Knowledge and Performance
l
F4.1 Diesel Generator Buildina Doors Imoaired
a. Insoection Scoce (71750. 37551) )
The inspector reviewed the circumstances surrounding a maintenance
activity which was subsequently determined to have degraded the 3-hour
fire rating of 28 fire doors in the DG building. This )roblem was
identified by the licensee in.CR 98-074. Fire Doors Loccset.
b.~ Observations and Findinas )
i
On January 13. 1998. the licensee determined that modifications to the j
latching mechanism on 28 doors in the DG building had defeated their !
3-hour fire rating. The modification performed, beginning in August
1996 and completed in December of 1997, removed an internal component
which 3revented the crash bar from opening the door in the event of a
fire w1ere the temperature exceeds 600 F. This function prevents the
door from opening if the crash bar is struck with debris. These doors i
are designed to restrict the s) read of flames when exposed to a d
predetermined fire exposure. Jpon recognition of the loss of the 3-hour
fire rating the licensee established a fire arotection impairment until
all the locksets could be replaced with the lardware needed to maintain
the 3-hour rating. The licensee initiated CR 98-074 to address this i
problem. The licensee's root cause review indicated that inadequate
documentation of the basis for the 3-hour fire rating existed. An
additional issue included the failure to perform a review for a
modification to fire. protection equipment.
l
The inspector reviewed UFSAR section 9.5.1.4.3, CR 98-074 and the
associated root cause, CR 96-3928. Configuration of Fire Doors. ESR 98-
00023 Evaluation of Yale Mortise Modifications associated WR/J0s, and
Nuclear Generation Group Standard Procedure EGR-NGGC-005 Engineering
Service Requests. Review of these CRs revealed a history-of incomplete
documentation for the fire doors and hardware problem. The lack of
documentation of the fire door basis was previously identified in
section F2.3 as a URI in IR 50-325(324)/97-13.
1
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The inspector reviewed WR/J0s'97-ADHR1 and 97-ADHS1 required for
implementation of the corrective action CR 96-3929, No Followup on UL
Report. The WR/J0s referenced ESR_"97-XXXX." The inspector questioned
if the designation of ESR "97-XXXX was an ESR referenced by CR 96-3929.
CR 96-3929 referenced ESR-97-571. Fire Door Problem. The inspector
determined that ESR 97-571 was still in review but the WR/J0s had been
completed. The inspector could not determine if an ESR had been ;
completed prior to the work performed by the WR/J0s. Due to the
'
licensee's review into this problem being incomplete at the close of
inspection report period, this item is unresolved. This unresolved item
is identified as URI 50-325(324)/97-15-05, Inoperable Fire Doors. '
-)
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c'. Conclusion
~
Twenty-eight doors in the DG Buildin were modified defeating the 3-hour
l fire rating of the doors. An unreso ved~ item was issued to allow
additional review for the failure of the licensee to perform an adequate
engineering review prior to modifying required fire protection quality
l hardware.
I
V- Manaoement Meetinos
L. XI Exit Meetina Summary
l
l~ The inspector presented the inspection results to members of licensee
- management at the conclusion'of the inspection on February 9.1998.
Post inspection briefings were conducted on January 8 and 12,1998. The-
licensee acknowledged the findings presented.
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PARTIAL LIST OF PERSONS CONTACTED
Licensee
A. Brittain, Manager Security
M. Christinziano, Manager Environmental and Radiation Control
W. Dorman. Supervisor Licensing and Regulatory Programs
N. Gannon, Manager Maintenance
J.'Gawron. Manager Nuclear Assessment Section
S. Hinnant. Vice President. Brunswick Steam Electric Plant
K. Jury. Manager Regulatory Affairs
J. Langdon., Supervisor NDE Services
B. Lindgren. Manager Site Support Services
J. Lyash Plant General Manager
G. Miller. Manager Brunswick Engineering Support Section
~
R. Mullis, Manager Operations
D. Ouidley. Superintendent, Electrical /I&C i
S. Tabor, Regulatory Affairs j
Other licensee employees or contractors included office, operation,
maintenance, chemistry, radiation, and corporate personnel. j
E. Brown
J. Coley j
E. Guthrie {
C. Patterson
]
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INSPECTION PROCEDURES USED
l IP 37551: Onsite Engineering
IP 61726: Surveillance Observations
IP 62700: Maintenance Implementation
IP 62707: Maintenance Observations
IP 71707: Plant Operations
IP 71750: Plant Support Activities
IP 73753: Inservice Inspection
IP 92902: Followup - Maintenance
IP 92903: Followup - Engineering
ITEMS OPENED, CLOSED AND DISCUSSED
'
Ooened
'
50-325(324)/97-15-01 IFI Test Fixture Discrepancies (paragraph M2.1)
i
50-324/97-15-02 NCV Inadequate Control of Special Processes
(paragraph M2.2) {
q
50-325(3?4)/97-15-03 IFI ECCS Response Time Testing (paragraph M3.1)
50-325(324)/97-15-04 VIO No CRs for Plant Process Computer Failures
(paragraph M4.1)
i
50-324/97-15-05 URI Inoperable Fire Doors (paragraph F4.1)
Closed
50-324/97-15-02 NCV Inadequate Control of Special Processes
(paragraph M2.2)
50-324/96-18-02 VIO Testing Using Uncalibrated Gauges (paragraph
M8.1)
50-325(324)/97-02-03 IFI PM Frequencies Based on Appropriate Plant Fuel
Cycle (paragraph M8.2)
50-325/96-16-01 VIO Improper Work Planning Resulted in a Loss of
Shutdown Cooling (paragraph E8.1)
50-325/96-14 LER Loss of Shutdown Cooling During Instrument Rack
Repair (paragraph E8.1)
, 50-325(324)/96-181-1013 VIO Inadequate Design Control for Material Selection ,
j in Service Water Pump (paragraph E8.2) I
50-325(324)/96-03-00 LER Dual Unit Shutdown Due to Service Water Pump
f Inoperability (paragraph E8.2)
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50-325(324)/96-03-01 LER Dual Unit Shutdown Due to Service Water Pump
Inoperability (paragraph E8.2)
50-325(324)/96-03-02 LER Dual Unit Shutdown Due to Service Water Pump
Inoperability (paragraph E8.2)
50-325(324)/96-015-00 LER Technical Specification Required Suppression
Chamber Water Volume Discrepancy (paragraph
E8.3)
i
50-325(324)/96-015-01 LER Technical Specification Required Suppression
Chamber Water Volume Discrepancy (paragraph
E8.3)
Discussed
50-325(324)/97-13-05 URI UFSAR Discrepancy Fire Doors (paragraph F4.1)
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