ML20198F410
| ML20198F410 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 08/01/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20198F382 | List: |
| References | |
| 50-324-97-08, 50-324-97-8, 50-325-97-08, 50-325-97-8, NUDOCS 9708130035 | |
| Download: ML20198F410 (43) | |
See also: IR 05000324/1997008
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U. S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos:
50 325, 50 324
License Nos:
Report No:
50 325/97 08, 50 324/97 08
Licensee:
Carolina Power & Light (CP&L)
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-Facility:
Brunswick Steam Electric Plant, Units 1 & 2
Location:
8470 River Road SE
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Southport, NC 28461
Dates:
May 25
July 5,1997
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Inspectors:
C. Patterson, Senior Resident Inspector
E. Brown, Resident Inspector
J. Lenahan, Reactor Inspector (Sections E1.2, E1.3,
E3.1, E3.2, E5.1)
J. Coley, Reactor Inspector-(Section M1.3)
J. Canady, Resident Inspector-(Plant Hatch)
Approved by:
M. Shymlock, Chief. Projects Branch 4
Division of Reactor Projects
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Enclosure 2
9708130035 970901
ADOCK 050
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EXECUTIVE SUMMARY
Brunswick Steam Electric P1 ant, Units 1 &-2-
NRC Inspection Report 50 325/97 08, 50 324/97 08
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This integrated inspection included aspects of licensee operations
maintenance, engineering, and plant support. The report covers a 6 week
period of resident inspection; in addition, it includes the results of an
engineering inspection and maintenance inspection by regional inspectors.
Ooerations
The inspector concluded that operator performance was excellent during
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an unplanned dual unit downpower maneuver.
(Section 01.1)
The inspector concluded that the licensee's response to an issue
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potentially affecting operability of the Standby Gas Treatment (SBGT)
and Environmental Qualification (EQ) components was poor. This problem
occurred due to the licensee living with a known deficiency with a
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alugged drain. The inspector identified water leakage a second time
3ecause of inadequate controls to prevent the problem from recurring.
(Section 02.1)
The inspector concluded that the licensee activities of dredging the
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intake canal and maintenance activities on the diversion structure were
maintaining the intake structure free of debris.
(Section 02.2)
The inspector concluded that the operator's res>onse to an unexpected
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recirculation pump speed transient was good. T1e aroblem was quickly
recognized and action taken to prevent further pro)1 ems. (Section 02.3)
One example of a violation for failure to enter a Limiting Condition for
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Operation (LCO) was identified.
(Section 08.2)
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Maintenance
The inspector observed good electrical safety precaution while
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performing preventive maintenance on circuit breakers.
The inspector
noted that the diesel generator (DG) building ventilation intake filter
structure was degraded. A missed opportunity to verify EQ components in
the motor control center (MCC) occurred when the MCC was tagged out and
opened.
(Section M1.1)
The inspectors concluded that two violations were identified.
Following
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' work on the emergency bus.-no post maintenance. testing (PMT) was
conducted to insure operability. An intent change to a procedure was
made changing the undervoltage relay operating range as a pen and ink
change.
(Section M1.2)
Verification of the licensee's corrective maintenance activities
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revealed three noticeable in process-maintenance' strengths. These-
strengths consisted of: 1) knowledgeable and technically confident
maintenance technicians performing the work: 2) formation of a site
investigation team which used formal fault tree analysis techniques to
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identify equipment and human performance problems, determine their
direct cause, and implement appropriate corrective action, and (3)
aggressive engineering and supervision oversight to assure work
activities proceeded effectively.
However, one NCV for Failure to
-Follow Work Instructions During the Previous Installation of Solenoid
Valves 2 CAC SV 4410 26 & 27. and one unresolved item for Failure to
Obtain an EQ Disposition on Extension of Vendor Recommended EQ Life for
Thermo Electric Cooler were also identified. (Section Hl.3)
Enaineerina
The inspector concluded that a questioning attitude and conservative
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decision making led to the discovery of a problem in the number two DG.
The preplanned systematic approach to problem solving was beneficial to
an orderly timely resolution of the issue.
(Section E1.1)
Upon exceeding the tracking LC0 covering the hydrogen / oxygen thermo-
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electric qualified life operability review, an extension was not
obtained until questioned by the inspector. This was a violation-of the
plant operating instruction.
(Section E4.1)
A noncited violation (NCV) was identified for failure to perform an
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adecuate 50.59 review for downgrading the control building air-
concitioning qualify classification.
(Section E8.2)
A violation was identified for failure to initiate condition reports
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when nonconforming . EQ hardware installations were identified. An
unresolved item was identified for concerns related to moisture
-intrusion into EQ equipment. A weakness was identified for failure to
train contract engineering personnel in the requirements of the
corrective action program.
(Section E1.2, E5.1)
The licensee's arogress to correct the EQ program deficiencies was
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satisfactory. -
Equipment operability issues were aapropriately evaluated
through JCOs although closure of the JC0s has not aeen timely. (Section
E1.2)
Engineering response to address equipment operability issues were
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conservative and prompt. Engineering support to plant operations is
rated as a strength.
(Section E1.3)
The inspectors concluded that the licensee's Phase I UFSAR was performed
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in accordance with their procedure and was an effective program for
identification of errors. The licensee is considering various o)tions
for performance of additional UFSAR reviews to assure that the U:SAR
accurately reflects the design. operation, and licensing basis of the
plant. (Section E3.1)
The licensee's corrective actions for the EQ program will address the-
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insufficient detail in DBD 100.
Further review will be performed by NRC
to determine the adequacy of other DBDs. (Section E3.2)
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Plant Support
A lack of ccwprehensive procedural guidance or standard site practice
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contributed to the inconsistent posting of radioactive material within
the radioactive controlled area.
(Section R2.1)
The inspector concluded that plant management made a conservative
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decision to perform a dual unit shutdown based on the untimely and
erroneous test results provided by the LPU. An ongoing NAS audit
identified several issues in this area.
Two non cited violations were
identified for failure to promptly take corrective action when flow test
performance did not meet acceptance criteria and for an inadequate fire
protection flow test procedure. A weakness was identified-in trending
and monitoring of the fire protection water suppression system
performance. (Section F1.1)
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The inspector concluded that there was a violation of the fire
protection procedure for having transient combustibles in a fire
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separation zone.
Designation of fire separation zones was unresolved
recuiring further review.
Implementing procedures for the establishment
anc maintenance of fire protection separation zones were weak. This was
evident by the discovery of transient combustibles in separation zones.
(Section F1.2)
An NCV was identified for the mispositioning of a hydrant isolation
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valve.
(Section F3.1)
Poor attention to detail resulted in the inadvertent water spraying on
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an energized high voltage Unit Auxiliary Transformer.
No personnel were
injured and no equipment damage or malfunction was observed.
(Section
F4.1)
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Report Details
Summary of Plant Status
Unit 1 operated continuously during this period. On June 21, 1997,
>ower was decreased to 22 percent until concerns about the fire main
leader were resolved as discussed in this report. Two control rods
remain inserted around an identified fuel pin leaker. At the end of the
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period the unit had been on line 240 days.
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Unit 2 operated continuously during this period. On June 21, 1997,
)ower was decreased to 22 percent until concerns about the fire main
leader were resolved as discussed in the re
At the end of the
period the unit hr.d been on line 295 days. port.
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The mechanical facuum pumps remained tagged out on both units due to
concerns about centrol room dose in the event of a Rod Drop Accident.
The licensee, in a letter to the NRC dateo February 13, 1997, committed
to upgrade the mechanical vacuum pump trip function to implement a
vacuum pump trip from the main steam line radiation monitor prior to the
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next startup.
Due to an identified discrepancy between TS required suppression chanber
water level and water volume, the licensee has issued Standing
Instruction (SI), SI 97 031. to maintain a more conservative water level
band until a TS amendment is approved. The SI directs o ' rations to
maintain level between 27.5 inches and 29.5 inches compared to TS
values of 27 inches to 31 inches. The inspectors have observed
compliance with this SI during routine tours of the control room.
Due to concerns about the control room dose the licensee imposed an
administrative limit on Iodine until a TS amendment is 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 com)ared to a TS value of 0.2 microcurie per
gram. Also, the licensee has
3een providing weekly data to NRR and the
resident inspector for review.
None of the data reviewed has exceeded
the administrative limit.
Nine of thirteen Justification for Continued Operation (JCO) in the
Environmental Qualification (EQ) of equipment area remain open for both
units. The following provides the status of the EQ JCOs and associated
Engineering Service Requests (ESRs):
1)
ESR 96 00425, Evaluation of EQ sealants was closed by the
licensee.
2)
ESR 97 00331 (old ESR 96 00503), Associated Circuit EQ was
scheduled for completion May 31, 1997, but revised to July 18,
1997.
3)
ESR 96 00426. Evaluation Quality class and EQ classification of
PASS valves was scheduled for completion June 6,1997, but revised
to October 31, 1997,
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4)
ESR 97 00330 (old ESR 96 00501), MCC EQ was scheduled for -
completion June 6, 1997, but was revised to July 18, 1997.
5)
ESR 97 00329 (old ESR 96 00625), EQ Type -JC0 for EQ Fuses Without
a Qualification Data Package (QDP) was closed by the licensee.
6)
ESR 97 00340 (old ESR 96 00627), QDP for Marathon 300 Terminal
Blocks was scheduled for completion December 31, 1997 but revised
to August 1, 1997.
7)
ESR 97 00087, EQ Type JC0 for Improperly Configured Conduit Seal
was closed by the licensee.
8)
ESR 97 00229, JC0 for GE CR 151 B Terminal Blocks was scheduled to
be completed July 15, 1997.
9)
ESR 97 00238, JC0 for SBGT Motor Operated Valve (MOV) Position
Indicator Rheostat, was closed by the licensee.
10)
ESR 97 00250, Conduit Union in EQ Boundary, was scheduled for
completion December 31, 1997
11)
ESR 97 00256, Main Steam Isolation Valve (MSIV) Hiller Actuator
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JCO, was scheduled for completion July 17, 1997.
12)
ESR 97 00289, Pass Valve Limit Switch Panel Wiring, scheduled for
completion September 15, 1997,
13)
ESR 97 00343, Qualification of Kulka Model 600 Terminal Blocks was
scheduled for completion September 1,1997.
In summar
However, y, both units operated continuously during this report period.
there were nine outstanding JCOs in the EQ area.
The
mechanical vacuum pump remained tagged out due to concerns related to
Rod Drop Accident analysis.
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I. Operations
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Conduct of Operations
01.1 Dual Unit Downoower
a.
l!1soection Scone (71707)
The inspector periodically observed operator performance during the dual
unit downpower and return to full power during June 20 21, 1997.
b.
Observations and Findinas
The inspector observed that operator performance during the downpower
was controlled and deliberate. Good pre job briefings were conducted at
major evolutions. The downpower was staggered between the units to
- provide more control in the Control Room.
c.
Conclusions
The inspector concluded that operator performance was excellent during
an unplanned dual unit downpower maneuver.
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02
Operational Status of Facilities and Equipment
02.1 Water Leak onto Standby Gas Treatment (SBGT) System
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a.
Insoection Scone (71707)
The inspector reviewed the activities associated with a unit 1 weekend
downpower and associated water leak on the SBGT system,
b.
Observations and Findinas
On June 1,1997, the inspector reviewed the operator logs concerning
activities associated with the Unit I weekend down>ower.
Noted in the
logs on May 31, 1997, was an event where water lea (ed onto the Unit 1
SBGT. This occurred due to a plugged floor drain on the upper elevation
resulting in water running down onto the SBGT. This caused a ground on
the 1B 250 volt battery bus and anntmciator "RX BLDG SBGT UNITS TEMP
HIGH" alarm.
Later, the alarm and ground cleared.
The inspector toured the Unit 1 reactor building on June 1, 1997, to
inspect the condition of the 1B SBGT.
Noted above the control panel and
other instrumentation was a tem)orary protective cover to divert water
from going onto the IB SBGT. T1e inspector noted that the control panel
was labeled as EQ. The inspector questioned the control room operators
as to whether the adequacy of EQ component sealing had been considered
since the water intrusion caused the grounds and annunciator alarms and
if the operability of the SBGT train had been affected. A Condition
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Report (CR) 97 01940. Water Leaking on 1B SBGT, had been written but it
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only addressed the drain problem. The CR addressed that the drain had
been plugged for scme time but was not corrected.
The licensee reviewed the EQ question and determined that SBGT was EQ
for radiation only for a loss of coolant accident (LOCA) in the drywell.
It was not sealed for a high energy line break (HELB) in the reactor
building. Also, the licensee did an additional walkdown of the SBGT on
June 1,1997, to identify water leakage paths. No evidence of water
intrusion into the control
)anel was found. The top of the panel was
dry with dust on it. Opera)ility tests were conducted on both SBGT
trains in accordance with OPT 15.6. Standby Gas Treatment System and
were completed satisfactorily. On June 2, 1997, the licensee opened the
panel and found half an inch of water in the bottom of the panel.
On June 13, 1997, during a routine tour of the Unit I reactor building,
the inspector observed water running out from underneath the door (door
402) to the Southwest Swamp Ventilation Room on the 80 foot elevation.
The inspector immediately contacted the control room and stayed in the
area until plant aersonnel arrived. A health physics technician
responded and too( swipes of the water. The water was not contaminated.
It was determined that the water was from condensation due to running
the air conditioning.
In addition, the inspector told a plant operator
that water was running down onto the 50 foot elevation and was wetting
electrical junction box 45A/DA.
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The inspector also notified plant management because this was the second
time that water had run out of this area. The licensee inspected the
junction box and found no water inside the box. The licensee initiated
CR 97 02121 to document the problem. Also, management directed that the
Unit I reactor building temporary cooling system operation be stopped
until a way was developed to handle the condensation drainage due to the
floor drain being plugged.
c.
Conclusions
The inspector concluded that the licensee's response to an issue
potentially affecting operability of the SBGT and EQ components was
poor. This problem occurred due to the licensee living with a known
31ugged drain. The inspector identified water leakage a second time
3ecause of inadequate controls to prevent the problem from recurring.
02,2 Intake Canal
a,
inspection Scope (71707)
On June 25, 1997, an inspection of the intake canal was performed.
b.
Qbservations and Findinas
The inspector observed the main circulating water and service water
intake structures at the traveling screens from the intake canal.
Both
structures were found to be free of debris.
During several months in
the Spring of 1997.-the licensee conducted dredging of the entire intake
canal to ensure reliable operation prior to the vegetation growth
season,
Also, the diversion structure at the beginning of the intake canal at
the mouth 01' the Cape Fear River was inspected. The licensee was in the
process of installing coarse mesh screens, called turtle blockers, on
the-river side of the structure outside of fine mesh diversion screens.
These blocker screens would prevent any sea turtles from entering the
canal if a blowout occurred at the fine mesh screen. A maintenance crew
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was assigned to the diversion structure-seven days a week during this
time of year for cleaning vegetation, etc. from the fine mesh screens,
c.
Conclusions
The inspector concluded that the licensee activities of dredging the
intake canal and maintenance activities on the diversion structure were
maintaining the intake structure free of debris.
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02.3 Recirculation PumD SDeed Increan
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a.
InsDeCtion SCoDe (71707)
The ins)ector reviewed the transient that occurred on Unit 1 on July 1,
1997, w1en the 1A recirculation pump speed increased unexpectedly,
b.
OhservationsandFindinas
During routine operations, without any indication of an annunciator
alarm or other warning, the control room operator observed a step
increase in power on a monitor display.
Power was at 97 percent due to
a limiting control rod pattern and then unexpectedly increased to an
indicated power of 101.6 percent. The operator went to the
recirculation pump speed controller and noticed that the 1A speed
indication was pegged high.
The operator took manual control of the 1A
recirculation pump and reduced the speed.
The licensee, after reducing speed, locked the scoop tube preventing any
further inadvertent transient. The controller was replaced and the old
controller checked for defects. The licensee determined, by
calculation, that the step increase in power had occurred about five
minutes early until observed by the operator. The calculated power was
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100.3 percent.
The inspector observed the response to the pump speed increase. Good
communication and supervisory oversight was present.
Due to the
transient, operations promptly restored the out of service Diesel
Generator as a precautionary measure. The inspector noted that
engineering res;>onse was prompt and provided good support in determining
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the effect of the transient on core safety parameters.
c.
Conclusions
The inspector concluded that the operator's res)onse to the unexpected
recirculation pump speed transient was good. T1e aroblem was quickly
recognized and action taken to prevent further proalems.
08
Miscellaneous Operations issues (92901)
08.1
(Closed) VIO 50 325(324)/96 04 02:
Croldown Menitoring Not Followed
This violation, with two examples, was issued as a result of exceeding
the cooldown rate on February 3, 1996 following the Unit 2 shutdown for
refueling and a failure to record Unit 1 bottom head temperature during
a )lant cooldown on March 18, 1996. The event that occurred on
Fe>ruary 3.1996 was identified as URI 50 324/96 01 01. This URI was
closed in Inspection Report (IR) 50 325(324)/96 04 and opened as another
example of Violation 50 324/96 04 02 for not following plant shutdown
procedure OGP 05.
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The licensee responded to this violation in a letter dated May 29, 1996.
The immediate corrective actions included counseling of the involved
operating crew regarding management's expectations, training of licensed
operators during requalification training on the circumstances
surrounding the events, and training of licensed operators on a new
periodic test procedure that was developed for the monitoring of heatup
and cooldown limits.
The corrective actions to be taken, as stated in the licensee's res>onse
of May 29,1996, included the development of a unit shutdown plan tlat
would be integrated into the outage plan: the revision of appropriate
operations procedures to interface with the newly developed periodic
test procedure for monitoring heatup and cooldown limits; and an
evaluation of the scram discharge volume surveillance test to identify
siternatives to the testing method.
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The inspectors reviewed Brunswick Site Procedure BSP 35, Outage
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Planning, Revision 5, to verify that a Unit Shutdown Plan was integrated
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into the Outage Planning procedure. Additionally, the inspectors
reviewed the Unit Shutdown Plan for refueling outage B111R1 that began
October 4,1996, and the planned B213R1 refueling outage scheduled for
September 12, 1997.
The ins
Operating Procedures OGP 02,pectors verified that General Plant
Approach to Criticality and Pressurization
of the Reactor, Revision 56 and 0GP 05, Unit Shutdown, Revision 73 were
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revised to interface with the new Periodic Testing Procedures 1(2)PT-
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01.7, Heatup/Cooldown Monitoring, Revision 0.
The inspectors reviewed
Periodic Testing (surveillance) procedures OPT 14 1.1b, ASME Section XI
Functional /N498 Hydrostatic Pressure Test of the Class 2 Control Rod
Drive (CRD) System and Scram Discharte Volume Piping, Revision 3: and
OPT 14,1,2, Scram Discharge Voluma Visual Inspection Revision 5.
It
was noted from this review that procedure OPT 14 1 lb was revised to
include inspection of the scram discharge volume (SDV) piping whic1 was
removed froni procedure OPT 14.1.2. This revision resulted from on
evaluation of the SDV surveillance to identify alternatives to the
existing test method. The inspectors noted that heatup and cooldown
cautions and response ex>ectations were listed in the procedural
revisions. Based upon tiese reviews, this violation is closed.
08.2 (Closed) URI 50 325(324)/97 07 01:
Failure to Enter TS ACTION Statement
During the April performance of Haintenance Surveillance Test OMST-
CLDETIIH, Chlorine Detection System Channel Functional Test the response
of the Control Building Heating, Ventiletion and Air Conditioning
(CBHVAC) System, to a chlorine isolation signal was tested.
This
isolation rendered the control room radiation and smoke protection
functions inoperable due to these signals being blocked when the
chlorine isolation mode was actuated,
The inspector determined that the
licensee failed to enter the ACTION statement for TS 3.7.2 Control Room
Emergency Ventilation System (CREVS) since the smoke and control room
radiation protection modes were inoperable. TS 6,8,1.a. requires that
written procedures shall= be established, im)1emented, and maintained
covering the activities in Appendix "A" of Regulatory Guide (RG) 1.33,
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November 1972.
Section I, requires administrative procedures for log
entries and equipment control.
Operating Instruction 001 01.08, Control of Equipment and System Status,
requires that for limiting condition for oxrations (LCOs) an entry
describing the condition be entered into tie LCO tracking system. The
failure to log entrance into the 15 3.7.2 ACTION statement upon loss of
the smoke and radiation modes is a violation. This is the first example
of VIO 50 325(324)/97 08 01, TS/LC0 Administration.
The licensee addressed not only this missed LC0 entry, but four
additional-instances as captured in the following CRs:
CR 97 815, Log Entry Clarity
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CR 97 1017, Missed Technical Specification Applicability
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CR 97 1028, CAC Honitor Filter Changeout
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CR 97 1242, LC0 Not Written for Both Units
The inspector reviewed the licensee common cause evaluation. The
inspector was concerned with the number and the repetitive nature of
these failures. Four out of the five reports stated the Control Room
supervisor failed to correctly recognize and log TS LC0 conditions.
The inspector noted that many of these events were for LCOs of short
duration and that 12 events in 18 months were identified.
Four out of
12 events reported were related to inaccuracies, errors, or oversights
with the LCOs concerning the Control Building Emergency Filtration
System. Two others dealt with errors regarding the containment
radiation monitors. The licensee root cause attributed the failures to
not having formal second verification. Operations management conducted
a standdown to address this adverse trend, among the causes identified
were inadequate validation and verification, wrong assum)tions, and
inadequate supervision. The inspector determined that tle licensee root
cause evaluation was deficient since the root cause did not acknowledge
or address those specific additional items identified.
In addition, the
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inspector noted a deficiency in the procedural guidance.
Procedure 001
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1.0.8 does not require nor suggest referencing the specific Technical
Specification requirements.
This URI was closed with issuance of the violation.
08.3 Corrective Action Program
The conclusion statement in paragraph 07.1.c of NRC Inspection Renort
50 325.324/97 07 was re reviewed by the inspectors. The statement which
inferred that senior management training on the Corrective Action
Program (CAP) and Condition Reports (CRs) was behind the scheduled NRC
commitment should be revised to indicate that management training on CAP
and CRs was behind the NRC. commitment.-
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II. Maintenante
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Conduct of Maintenance
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M1.1 General Comments
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a.
Inspection Scope (62707. 61726)
The inspectors observed all or portions of the following work
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activities:
e
WR/JO 97 ACFH1
Rebuild standby liquid control-(SLC) pump 2B
discharge check valve C41 F033B
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WR/JO 97 ADCX1
Investigate cause for point 7 indicating error
for the containment atmosphere control system
torus /drywell temperature recorder
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WR/JO 97 ABTW 01 4160 volt breaker PMS
b.
Observations and Findinas
All work observed was performed with the work Jackage present and in
active use. Technicians were experienced and (nowledgeable of their
assigned tasks.
The inspectors also observed the use of foreign
material exclusion practices where appropriate.
The insactors noted, during a subsequent review of the operation daily
logs, t1at the SLC pump discharge check valve rebuilt under WR/JO 97
ACFM1 had failed its post maintenance functional test (0PT 06.1).
Based
upon O wrations. discussions with Engineering, the check valve did not
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meet tie full stroke closed criteria of OPT 061.
It would be tracked
as increased frequency testing under Inservice Testing deviation report
number 97 016.
On May 28, 1997, the inspector observed work activities associated with
the Unit 2 Residual Heat Removal (RHR) Loop A outage. The inspector
observed preventive maintenance on 4160 volt breakers for RHR pump A and
RHR pump 2A wrformed under WR/JO ABTW 01. The work was performed per
procedure OPi BKR001, ITE 4KV Breaker and Compartment Checkout. The
inspector verified that revision 17 dated July 29, 1996, was the correct
revision of the procedure. The insactor observed good use of safety
_ equipment.
The technicians used ru)ber gloves, a face shield, and a
safety man with a hot stick. The inspector also verified that the
-megger and other test equipment were in calibration.
Each breaker compartment was dusted off using a paint brush. A handful
of dust was taken out of each com)artment. Although the general area
was very clean, the inspector looted for possible sources of-dust or
dirt. The 4160 volt class 1E breaker com)artments are located on the
upper elevation of the Diesel Generator (JG) building. The DG building
ventilation intake filters were in poor material condition. The filters
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were dirty and the structures holding the filters in place were degraded
which allowed unfiltered air entry into the DG buildirg.
Also, the inspector observed breaker work in the Unit 2 reactor building
on MCC 2XA, The inspector observed that the MCC was t6
circuit breaker preventive maintenance was in arogress.99ed out and
The inspector
questioned if any EQ walkdowns as part of the
EQ 3rogram reconstitution
were being performed to verify components in the 4C0 but none were being
conducted. The EQ walkdown was not planned,
c.
Conclusions
The inspector observed good electrical safety precaution while
performing preventive maintenance on circuit breakers,- The inspector
noted that the DG building ventilation intake filter structure was
degraded. A missed opportunity to verify EQ com
occurred when the MCC was tagged out and opened.ponents in the MCC
M1.2 Loss of E 2 bus and Diesel Generator
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a.
Insoection Scoce (62707)
The inspector reviewed the circumstances concerning a loss of the E 2
emergency bus due to the off site power supply breakers tripping and
subsequent loss of DG 2 due to a fuel oil leak that occurred on June 8,
1997,
b,
Observations and Findinas
- On June 8,1997, the licensee was_ preparing for a scheduled outage of
DG 4.
Preparation involved quick start testing of the other three DGs
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to ensure operability prior to taking the DG 4 out of service, When
preparing to start DG 2, the operator placed the DG 2 selector switch in
the " Local Manual" position to allow personnel in the DG building to
start the DG. The master and slave breakers supplying the normal off-
site power to the emergency 4160 VAC bus E P. tripped de energizing
emergency bus E 2.
DG 2 auto started and W ed onto the emergency bus
per design. The loss of the E 2 bus resulted in a half scram and
several half isolations of containment group-isolations. The half scram
and group isolations were reset without complications.
Since no
apparent cause for the breaker trip could be determined, the licensee
declared off site power inoperable. A four hour notification was made
to the NRC at.6:05 p.m,
Later, at 7:13 p.m.. DG 2 was manually tripped due to a fuel oil leak
caused by a 1/4 inch fuel oil line to a pressure gauge breaking.- The-
-licensee entered TS 3.0.3 due to a loss of off site power and DG 2 being
After identifying the most- probable cause of the breaker tripping to E 2
was a relay failure, and with DG 2 in AUTO but mechanically locked out,
the E 2 bus was_re energized from off site power at 7:26 p.m. and TS
_
%.m
-
--
_ . . .
.
.
10
3.0.3 exited. A four hour notification was made to the NRC at 10:30
p.m. concerning the second loss of E 2.
At 11:30 p.m. it was determined
'
that the 27 PK relay contacts were in the tri> ped condition with no trip
signal present.
The relay was replaced and t1e trip condition was no
longer present. The mechanical lockout for DG 2 was roset.
l
The licensee formed an event review team once the E 2 tius was lost to
investigate the problem. The licensee determined that the loss of E 2
due to tripping of the master and slave breakers was because one of the
trip contacts of 27 PK relays three colls failed to opon when the relay
was energized. This was due to an incorrect operating arm / armature
assembly adjustment.
There are three protective relaym in parallel
connected to the E 2 bus between the master and slave breaker. Any one
of the three relays or nine contacts could cause this same trip
condition.
The 27 PK relay is an under voltage relay designed to sense
an under voltage condition on off site power allowing the DG to be the
sole electrical source. The 27 PK relay is normally energized when
installed but only in the trip circuit when the select switch is not in
the "AUT0" mode of operation and the master and slave breakers are
closed.
The failed relay had been successfully calibrated and tested on a relay
tester on May 27, 1997.
Upon examination of the failed rniay, one of
the three contact assemblies had limited contact travel. The licensee's
'
root cause evaluation stated that it was believed that the as found
condition existed since initial installation. Adjustment of these
contacts was addressed in the vendor manual which indicated that the
contact gap to checked to be .005 inches prior to installation.
Further, the inspector questioned if post maintenance testing (PMT) had
been performed to ensure operability of the emergency (E) bus components
following maintenance and after separating electrical connections or
contacts. The PM was performed under WR/JO AELB 001 that specified no
aost maintenance test requirement. The relay test procedure was OPIC-
lLY026. Relay Calibration using Pulsemaster Software and Pulsar Relay
Tester. This procedure was a bench test of the relay atter removal from
service and did not cover any PMT.
The inspector also reviewed procedure 0PLP 20. Post Maintenance Testing
Program.
Stated in the procedure, under section 6.1. Scope of the
Program, was that post maintenance testing verifies the tatisfactory
completion of maintenance activities and the technical specification
operability of the equipment, if applicable.
No post maintenance test to verify the E 2 bus operability or continuity
of relays after replacement was performed.
Vendor recommendations to
verify relay contact point ga) prior to installation was not
)erformed.
This was a violation of TS 6.3.1.a. written procedures shall
)e
established, implemented, and maintained covering the activities in
A)pendix "A" of RG 1.33. November 1972.
RG 1.33. Section 1. requires
tlat maintenance which can affect performance of safety related
equipment should be properly preplanned and performed in accordance with
o
.
.
11
written procedures, documented instructions, or drawings a
opriate to
the circumstances. This violation will be treated as VIO
325(324)/97 08 02, Failure to Verify / Check E Bus Relay Operability.
Additionally, the inspector reviewed the completed procedura (0PIC-
RLY026) for PK 27 relay calibration.
The data sheets used in the
procedure were completed on May 27, 1997. The "as left" pickup voltage
range was specified as 52.25 to 57.75. The picku
was denoted as not being in the correction range.p voltage was_50.60 end
The technicians
performing the work made a pen and ink change to the procedure to change
the range from 50.0 to 55.0 which would agree with the technical manual.
The inspector reviewed how a wn and ink change could be made on a
protective relay in a safety
aus.
Procedure OAP 004, Temporary Changes
to Procedures, gives the guidance for making a temporary change within
14 days as discussed in TS. -Temporary changes generally are classified
as changes that do not alter the intent of a procedure. One of the
examples given in Section 3.2, Intent of a Procedure, was one that
alters or deletes setroints or required operating parameter ranges.
This type change was an intent change.
This was a violation of PS 6.8.1 for maintaining procedures. TS 6.8.2
provides that a temporary change can be made in 14 days if the intent of
the procedure was not chan]ad. This violation was identified as
50 325(324)/97 08 03, Safety Relay Setting Change Made as Pen and Ink
Changes to Procedure.
Additionally, the inspector reviewed how the information in the
Equipment Data Base System (EDBS) was initially reviewed in relay test
3rocedure OPIC RLY026 and the relay setpoint change made in EDBS.
-
3rocedure step 7.2.11.6 requires entry of EDBS settings.
From
discussion with the licensee it was learned that the fields in EDBS in
this case were color coded as "information only". They were not to be
used until verified as the correct design data.
Also, the inspector reviewed how the EDBS data was changed and this also
was done with a computer generated form and not the form in the
3rocedure. The licensee initiated CR 97 02400 concerning non validated
EDBS information. The CR stated that non validated EDBS data had been
routinely used to determine settings for the following components:
balance of plant instruments with non specific data sheets in
o
' applicable procedures -
e
4160 volt protective relays
molded case circuit breakers magnetic trip settings
e
Limitorque motor operated valve torque and limit switch settings
e
Control of EDBS information will be unresolved pending further review.
This will be tracked as URI 50 325(324)/97 08 04. Control of EDBS
Information.
_ _ _ _ _ _ _ _ _ _ _
_
a
.
.
12
c.
Conclusigns
The inspectors concluded that two violations were identified.
Following
work on the E bus, no PHT was conducted to insure operability. An
intent change to a procedure was made changing the undervoltage relay
operating range as a pen and ink change.
M1.3 Maintenance Imolementation
a.
Inspection Scope. Corrective Maintenance (62700)
l
The inspector reviewed documentation and observed work activities
consisting of troubleshooting and corrective maintenance of components
in the Unit 2, 4410 containment atmosphere control (CAC) analyzer
cabinet. These activities were examined to verify that maintenance
activities were being conducted in a manner which would result in the
reliable and safe operation of the plant,
b.
Observations and Findinal
The installed system for measuring the oxygen and hydrogen gas
concentration in the primary containment was the Teledyne CAC 4410
monitor. This system was qualified as a Class 1E nuclear safety related
system. The system was designed to measure hydrogen and oxygen
concentration in the primary containment under normal or accident
conditions. Even under containment conditions of 50 pounds per square
j
inch gauge and 445 degrees Fahrenheit the system would continue to
lL
provide accurate measurements of hydrogen and oxygen concentrations.
The Brunswick Unit 2 -CAC 4410 monitor failed after five hours of
operation following preventive maintenance performed on May 28 29. 1997.
A trouble alarm was received, caused by actuation of the sample flow
switch, and water was observed in the rotameter and found in the sample
lines. An investigation revealed that the solenoid valves previously
installed in April 1996, for 2 CAC SV 4410 26 and 2 CAC SV 4410 27 were
improperly installed. A normally closed valve was installed where the
drawing required a normally open valve and a normally open valve was
installed where a normally closed valve was indicated. The installation
and maintenance instruction that accompanied each valve stated that the
valves were not interchangeable.
The inspector observed the licensee's troubleshooting and corrective
maintenance activities from the point where the-licensee thought the
improperly installed valves were identified as the cause of the failure
to the resolution of the problem. This work was performed in accordance
with WR/JO ADLP 1.
Maintenance-performed
replaced the flow switch and the CAC pump. prior to this point had
On June 2, 1997, the pro >er
valves were installed, correct valve installation was verified for tie
other train-and Unit 1, and the monitor was run. On June 2 3, after
five hours of o>eration the same failure symptoms were observed, On
June 2. 1997, tie licensee also assigned an investigation team to
develop an equipment problem action plan and identify the cause of the
_
__.
.
.
13
monitor failure using formal failure analysis methods, and to establish
appropriate corrective :ction.
During the investigation team's development of a fault tree the vendor
was contacted. The vendor immediately attributed the current problem to
a problem identified in an August 13, 1993. 10 CFR Part 21 notice on the
monitor's-thermo electric cooler.
However, the licensee was not
convinced that this was their )roblem.
Both of the failures re>orted in
the Part 21, resulted in a hig1 temperature alarm to indicate tie
failure (current drop).
This had not been encountered during the
Brunswick Unit 2 monitor failure.
But, the licensee proceeded at this
point to obtain a new thermo electric cooler from another utility since
the vendor could not support the Unit 2 schedule in a timaly manner.
Troubleshooting continued on other fault tree issues and two other
problems were identified.
The first was that terminal block 28 in the
lower solenoid valve trough-had a broken thermal shield barrier between
points 11 & 12. This problem apparently occurred during the replacament
of the solenoid valves. The licensee Q d not have a spare terminal
block or thermal shield barriers. Therefore, an ESR 97 00321 was issued
to evaluate the problem and restore the cabin.t wiring to an analyzed E0
configuration. This was accomplished by relocating the wire on terminal
TB 11 to terminal TB28 3.
During the engineering review a second
problem was also identified in that, the 2 CAC AT 4410 logic print was
in error. The vendor was again notified and the licensee was informed
that the vendor drawing had been changed. This change was not
incorporated into the vendor drawing issued to CP&L as a foreign print
drawing. The ESR made the appropriate drawing changes but, the vendor
was requested to provide the correct revised drawing.
On June 5,1997, the new thermo electric cooler arrived on site, and
work immediately proceeded to replace the cooler.
Prior to its removal
maintenance technicians found particles of copper and insulation on a
ledge in the cooler, During further disassembly, the connector on the
thermal plate in the back of the cooler fell off.
The licensee sent
these parts to be analyzed to determine the direct cause of the failure.
On June 5 and 6 the CAC 4410 monitor was successfully tested.
Documentation was O so initiated to trouble shoot' the cooler on the
other Unit 2 monitor (CAC 4409) and the coolers on both monitors for
Unit 1.
- With the exception of the improperly installed valves, the problems
experienced on the CAC 4410 monitor were the result of the cooler
failure.
The licensee also determined during their investigation that
the improperly installed solenoid valves did not affect the monitor's
o>eration.
The valves tested and operated satisfactory because flow was
t1 rough the same valve ports, whether the valve was open or closed and
the differential 3ressure on the valve seat was insufficient to open the
seat even under tie most extreme conditions.
=-_
,
___ ___
1
.
.
1
I
'
14
i
The licensee issued two condition reports on findings identified during
investigation of the CAC 4410 Honitor failure. The first (CR 97 01946)
!
dealt with the previous improper installation of the two CAC AT 4410
The inspector reviewed documentation of the April 16,
'
1996 installation, and found that although visual inspection or testing
of the valves would not determine which valve was open or closed. valve
parts numbers were correct for proper valve installation. Therefore,
the cause was due to personnel error during the valve replacement
'
process. The inspector considered the improper valve installation to be
,-
caused by a technician's failure to follow work instructions. This
!
failure constitutes a violation of minor si
i
treated as an NCV, consistent with Section gnificance and is being
IV of the NRC Enforcement
'
4
]
Policy.
It was reported as NCV 50 324/97 08 05, Failure to Follow Work
'
Instructions During Previous Installation of Solenoid Valves 2 CAC SV.
l
,
4410 26 & 27.
'
'
The second CR (CR 97 02005) issued by the licensee involved the Part 21
!
issued by Teledyne.
Based on this reported failure Teledyne shortened
'
'
the EQ life of this compoaent from 40 years to two years. The
,
- licensee's system engineer believed the vendor's recommendation was
!
overly conservative based on licensee's operating history and performing
!
>
i
the vendor recommended testing to verify operability.
Hcwever, an EQ
j
review of the disposition was not obtained. The immediate corrective
i
actions for this CR notified EQ and 001 1.0.8 LC0 was written to obtain
an operability assessment by engineering for both units.
The inspector
4
i-
was informed of CR 96 02005 late in the inspection and insufficient time
was available to
Therefore, follow up
will be required, properly review this problem.
and this item will be identified as Unresolved Item
~L
50 325(324)/97 08 06. Failure to Obtain Engineering Disposition on
Extension of Vendor Recommended EQ Component Life.
l
c.
Conclusions
<
During verification of the licensee's corrective maintenance activities
three noticeable in process maintenance strengths were observed. Th9se
strengths consisted of: 1) knowledgeable and technically confident
-
maintenance technicians performing the work: 2) formation of a site
4
investigation team which used formal _ fault tree analysis techniques to
.
- identify equipment and human performance problems, determine their
direct cause, and implement appropriate corrective action, and 3)
'
,.
i
aggressive engineering and supervision oversight to assure work
!
activities proceeded effectively. However, one NCV Failure to follow
i
Work Instructions During the Previous Installation of Solenoid Volves 2-
'
CAC SV 4410 26 & 27, and one unresolved item Failure to Obtain an EQ
Disposition on Extension of Vendor Recommended EQ Life for Thermo-
.
Electric Cooler were also identified,
a
.
M1.4 Special UFSAR Review
A recent discovery of a licensee o wrating the facility in a manner
- contrary to the UFSAR description lighlighted the need for a special
focused review that compares plant practices, procedures, and/or
,
,
4
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. _ - - _ _ _ _ _
.
.
l
i
15
!
arameters to the UFSAR descriptions. While performing the inspections
discussed in this re) ort, the inspectors reviewed the applicable
,
portions of the UFSAl that related to the areas inspected.
The
'
inspectors verified that the UFSAR wording was consistent with the
observed plant practices, procedures, and/or parameters.
,
W
'
The inspector reviewed the UFSAR Section 8.3, Onsite Power Systems, to
review the 27 PK relay setting. There are specific relay settings
listed in Table 8.3.1 17 but not the 27 PK relay.
This was due to this
',
relay only being in the circuit when the DG was run in manual.
MB
Miscellaneous Maintenance Issues (92902)
i
M8,1
(Closed) LER 50 324/96 01: Control Rod Average 5 percent Insertion Time
Exceeds Technical Specification Requirements
.'
(Closed) LER 50 324/96 01 01: Control Rod Average 5 percent Insertion
l
Time Exceeds Technical Specification Requirements
Based on the closure of this item for Unit 2 in IR 50 325(324)/97 02
.
Section E8.2 and no degradation of scram times as discussed in IR 50-
325(324)/97 07 Section M3.1, these LERs are closed,
'
i
III. Enaineerina
!
El
Conduct of Engineering
i
E1.1 Diesel Generator Slow Start
a.
Inspection SCoDe (37551)
4
The inspector reviewed the circumstances concerning a slow start of DG 2
'
that occurred on June 20, 1997,
.
i
b.
Observations and Findinas
On July 1,1997, the DG 3 scheduled outage was delayed because DG 2
.
l
start time was longer than expected.
In
outage, each of the other DGs were quick _ preparation for the DG 3
started to ensure they were
operable prior to removing the DG scheduled for maintenance. DG 2
experienced a start time of about 9.5 seconds compared to a normal start
of 8.5 seconds.
The TS allowed start tiine is 10 seconds or less. The
licensee implemented a preplanned slow DG start time trouble shooting
plan,
This plan was developed as part of a site wide systematic
approach to problem solving.
By implementing the trouble shooting plan
4
it was found that a pressure regulator in the air start system was not
functioning correctly. The DG was still operable due to the capability
.
to start from the redundant side of the air start system. After
replacement of the regulator, DG 2 start time was about 8.5 seconds, the
normal starting time.
.a.
_
,
. . -
- _ -
-
--.-
. - - -
~ . - . . - . - .-
.....;...
- - - .
. - - . - , - - .
___ . _ _ _
___._
_____
__
<
<
e
,
4
h
16
4
i
j
c.
Conclusions
The inspector concluded that a questioning attitude and conservative
i
decision making led to the discovery of a problem with DG 2.
The
,
-preplanned systematic approach to problem solving was beneficial to an
i
orderly timely resolution of the issue.
El.2 Environmental Oualification
!
.,
a.
Inspection Scope (37550)
,
J
The inspectors reviewed the licensee's corrective actions for the EQ
program, in res3onse to findings identified during Self Assessment
1
95 0041 and 96 0271 and the violations identified in NRC IR 50 325(324)/
j
96 14,
i
j_
b.
Observations and Findinas
a
.
1)
Status of EQ Justifications for Continued Operation
!
The licensee has issued 13 JCOs in response to deficiencies
!
identified in their EQ program.
Four of the JCOs have been closed
and nine remain open. The requirements for JCOs are specified in
i
Section 6 of Attachment 2 to CP&L procedure EGR NGGC 0156,
i
Environmental Qualification of Electric Equipment Important to
Safety. The procedure requires that a CR be initiated and that a
4
JC0 be prepared to address the problem. The-instructions for
,
!
preparation of the JC0 references NRC Generic Letter 9118.
Subject: Information to Licensees Regarding Two NRC Inspection
Manual Sections on Resolution of Degraded and Nonconforming
l
Conditions and on Operability, dated November 7, 1991. The JC0s
were reviewed by the inspectors during previous inspections and
!
were found to be technically adequate.
However, closure of the
JCO's has not been timely.
,
i
The JC0s and controlling procedures have been reviewed by the NAS
j
in November,1996, and during a self assessment conducted in June,
1997. CR 96 3799 was issued on November 15, 1997, as a result of
the NAS review,' which determined that the site procedures used to
prepare JCOs did not reference the appropriate regulatory
'
requirements. -These requirements were incorporated into EGR NGGC-
'
0156.- A finding from the self assessment concerned the lack of
consistency in the JC0s and the fact that the ESRs written for the
!
JCOs were not processed as design change ESRs.~ CR 97 2008 was
initiated on June 5, 1997 to document and disposition this
-
finding.
2)
EQ Equipment Inspection
The licensee's corrective action program to address the EQ program
deficiencies identified in NRC IR 50 325(324)/96 14 included a
<
_
commitment to perform a walkdown inspection of all EQ equipment to
4
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i
.
.
17
verify the equipment was installed in accordance with the
requirements specified in QDPs. The inspectors reviewed CP&L
Special Procedure OSP 96 014 EQ Equipment Field Verification,
Revision 1 dated April 18, 1997. This procedure specifies the
requirements for performance of walkdown inspections which are
being performed to determine if EQ equipment was installed in
accordance with the configurations required by the ODPs.
The
procedure contains a three page data sheet for recording and
review of the field inspection data.
Pages one and two of the
o ta sheets are used fo, recording the results of the field
inspections.
Page 3 of the data sheet is completed by a _ qualified
EQ engineer to document disposition of the field inspection
results, including deficiencies in the installed equipment.
The inspectors accompanied members of the EQ Task Force ad
witnessed these individuals in performance of walkdown
i
inspections.
Equipment examined during the walkdowns included the
l
following:
Unit 2 Post Accident Sampling System (PASS) valve numbers 2-
-
4183, 4186, 4188,
4189, and 4192.
Unit 2 Containment Atmospheric Control valve numbers 2 CAC-
-
SV 4540 and 213A.
Unit 1 motor control center (MCC) 1XDA
-
The purpose for examining the MCCs was to identify the type of
equipment (e.g., breakers, resistors, overload relays, etc.)
installed in the MCCs and the location installed in the MCCs. The
MCC walkdown data will be compared to the EDBS. The EDBS will be
corrected to reflect the information from the field walkdowns.
When equipment is identified which is not listed in EDBS, and for
which has not been qualified by a ODP, a CR will be issued, and if
appropriate, a JC0 will be written. The inspectors noted that
during inspection of the MCCs, the gasket materials around the MCC
doors were examined to determine if the gaskets were intact and
were performing their function to seal the HCCs. These gasket
materials had been replaced in 1996 as part of the corrective
actions for CR 96 02545. The replacement gasket materials were
qualified under ESR 96 00659.
A JC0 was issued under ESR 96 00501
to resolve concerns regarding qualification of equipment in the
MCCs. Discussions with licensee engineers and review of the
ESR/JC0 disclosed that two additional ESRs had been issued to
"
address replacement of gasket materials which were inaccessible
and could not be replaced in 1996. These gaskets were the ones
originally supplied with the MCCs by the vendor, Ger,eral Electric,
and had been qualified for the life of the plant. However tests
which were performed on the original gasket materials disclosed
that the gaskets had been fabricated from different materials
which had a life of only approximately 30 years and will require
replacement in the years 2003
2005. This problem had not been
._
.
..
.
-
- -.
..
.
.
18
documented in a CR as required by the licensee's corrective action
program specified in CP&L procedure OPLP 04.
Failure to initiate
a CR to document and disposition this issue was identified to the
licensee as violation item 50 325(324)/97 08 07. Failure to
Initiate Condition Reports to Document EQ Equipment Installation
Deficiencies. The licensee initiated CR 97 02262 on June 26, 1997
to document this problem after this violation was identified.
During the walkdowns licensee engineers identified unmarked wires
on PASS valves 4188 and 4189. Review of original construction
documentation identified the type of wire which had been installed
during plant construction, a description of the wires, and the
reason for installation. CR 97 02143 was initiated to document
the fact that unidentified and/or potentially unqualified wiring
was found on the PASS valves.
'
The inspectors also observed portions of the installation of new
EQ seals for ASCO Tripoint pressure switches N010 and N027.
The
seals were installed adjacent to the instruments. The seals had
been originally installed at the junction box, with a piece of
flexible conduit between the junction box and instrument.
Since
the flexible conduit was not EQ qualified it was necessary to
-install new seals adjacent to the instrument to comply with the
QDP. This problem was documented on CR 9700508 which was
!
initiated on February 3, 1997, and a JC0 issued under ESR
97 00087.
3)
Review of EQ Equipment Inspection Data Sheets
The inspectors reviewed the EQ Component Field Verification Data
Sheets for walkdown inspections completed between February 1
through 15, 1997, and other randomly selected components which had
been field inspected through March 15, 1997. The data sheets were
completed in accordance with OSP 96 014.
Information on the data
sheet pages 1 and 2 included field walkdown data, identified
deficiencies and included comments on potential EQ concerns.
Sheet 3 of the data sheets contains a summary of a review of the
walkdown data by a qualified EQ engineer and lists deficiencies
which require repair.
Review of the data sheets disclosed that
the field inspectors identified numerous potential deficiencies in
installation of EQ equipment where the installed equipment did not
comp /or manufacturer's requirements.ly with the requirements of the qualificatio
and
As discussed below, some
potential deficiencies had not been addressed on page 3 of the
data sheet by the EQ engineers when they reviewed the data sheets.
The inspectors noted comments in the data sheets regarding lack of
weep holes in junction boxes, potentially damaged gaskets on
junction boxes, and other comments regarding possible effect of
moisture intrusion on EQ equipment.
However, these comments /
concerns had not been addressed in the review of the EQ field
,
.
19
inspection notes as documented on page 3 of 3 of the field
inspection data sheets. The inspectors noted that CRs 97 1841,
97 2017, and 97 2025 had been initiated between May 23 and June 6,
1997, to document and disposition some of these problem.
In .ome
cases the data sheets (page 3 of 3) were signed off several wr.eks
prior to initiation of the condition reports.
Pending further
review by NRC of the various issues concerning the effect oi
moisture on EQ equipment, and identification of corrective actions
and the affected equipment, this problem was identified to the
licensee as URI 50 325(324)/97 08 08. Control of Moisture in
Installation of EQ Components.
Review of the data sheets also disclosed comments on the possible
incorrect installation of Raychem splices. These comments
indicated that some Raychem splice installations may not comaly
with the manufacturer's recommendations or the licensee's QD) for
Raychem splices.
Discussions with EQ task force personnel and
review of licensee documentation disclosed that licensee
engineers, in review of Operating Experience report OE 8238, noted
that non conforming configurations had been identified for some
Raychem splices installed at BNP. However, this )roblem was not
documented on a condition report as required by tie licensee's
corrective action program.
The failure to initiate a CR to
document and disposition the potentially defective Raychem splices
was identified as another example of violation item VIO 50-
325(324)/97 08 07, Failure to Initiate Condition Reports to
Document EQ Equipment Installation Deficiencies,
c.
Conclusions
The licensee is making progress in addressing the previously
identified deficiencies in the EQ program. However, the failure
to initiate CRs to document nonconforming items when they are
identified continues to be a 3roblem which resulted in a violation
which was identified during tie inspection. An unresolved item
was identified for concerns related to moisture intrusion into EQ
equipment.
E1.3 Followuo on Service Water System Reoairs
a.
Inspection Scooe (37550)
The inspectors reviewed the licensee's actions to evaluate
corroded bolts in a support on a service water booster pump motor
cooler pipe su) port and two through wall leaks in the vital
service water leader.
b.
Findinas and Observations
On June 23. 1997, two of four anchor bolts on pipe support number
1 SW 148PG248 on the Unit 1 IB RHR service water booster pump
motor cooler inlet line 1 SW 1481417A were found to be severely
J
.
.
20
corroded. The bolts, when measured using ultrasonic testing (UT),
were found to have no measurable embedment length in the concrete.
This aroblem was documented on CR 97 02213. The UT inspections
were :eing performed in response to corroded anchor bolts
identified on the Unit I nuclear service water header in
January, 1997. This issue was discussed in NRC IR 50 325(324)/
97 02.
Review of the results of the NDE showed that while two bolts were
corroded and had no embedment length in the concrete, the
remaining two anchor bolts were in acceptable condition to carry
their design loads. The licensee performed an operability review
,
of the degraded bolts in accordance with CP&L procedure EGR.NGGC.
0320. Civil / Structural Operability Reviews, Revision 0, dated
i
'
May 8, 1996. The inspectors reviewed ESR 97 0351. Revision 1.
l
which documents the operability review.
The operability review
was performed by assuming only two bolts were remaining to carry
the piping loads.
The analysis showed that the supports were
operable until the next refueling outage.
The licensee identified two leaks in a section of piping on the
Division 1 vital service water header.
These-
documented on CR numbers 97 02013 and 02108. problems were
Each leak was
estimated to be approximately one drop per minute.
Based on the
results of NDE ultrasonic testing, licensee engineers determined
that the leaks were of the " pinhole" type.
The inspectors
reviewed ESR 97 00326, Revisions 0 and I which evaluated the
)iping wall thickness using the guidance provided in Generic
.etter 90 05. The conclusion of the ESR was that the piping was
operable until the next refueling outage.
.c.
Conclusions
The 11censee's actions to evaluate the corroded-anchor bolts on
the service water system booster pump pipe support and the pinhole
leaks in the vital header were conservative and completed
promptly. Engineering response to these issues is rated as a
strength and a continuing example of good engineering support to
plant operations. The inspectors concurred with the results of.the
licensee's operability evaluations.
E3
Engineering Procedures and Documentation
E3.1 UFSAR Review
a.
Inspection Scooe (37550)
The inspector examined the licensee's-program for review of the UFSAR.
_
.
.
i
21
b.
Observations and Findings
l
Theinspectorsreviewedthelicensee'sUFSARreviewproject, The
l
purpose of the review is to provide reasonable assurance that the UFSAR
properly reflects the current plant configuration, plant processes and
procedures, and operating oarameters.
The inspectors reviewed CP&L
S>ecial Procedure OSP 96 0)3, Revision 0, dated June 28, 1996. UFSAR
P1ase I Review, This procedure provides instructions for aerformance of
the review, As a result of the review, approximately 250 CRs have been
initiated to document discrepancies identified in the UFSAR during the
review. The discrepancies include the following: Administrative errors
such as typos and incorrect references; errors in the original FSAR
which were carried over into the current UFSAR: and errors resulting
from implementation of modifications which were not considered when
updating the UFSAR. The inspectors reviewed the CRs and concluded that
I
none of the UFSAR errors affected operability of any safety related
systems,
c.
Conclusions
l
The inspectors concluded that the licensee's Phase 1 UFSAR was
!
performed in accordance with their procedure and was an effective
i
program for identification of errors, The licensee is considering
various options for aerformance of additional UFSAR reviews to
assure that the UFSAR accurately reflects the design, operation,
and licensing basis of the plant,
E3.2 Review of Design Basis Documents (DBD)
a,
Insoection Scope (375501
The inspectors reviewed two DBDs to determine their content and
accuracy pertaining to documentation of the design basis for the
Brunswick Plant.
b,
Observations and Findinas
The inspectors performed a review of DBD 09, Neutron Monitoring,
Revision 1, dated May 29, 1997, and DBD 100 Equipment Qualification,
Revision 0, dated December 6, 1993.
DBD 09 was recently revised to
include design information on the power u) rate project.
However the
inspectors noted that the references in tie DBD were incomplete
regarding the response to Generic Letter 82 33, Sup lement No. I to
Requirements for Emergency Response Ca ability Regarding
Post Accident Neutron Monitoring Instrumentation,
eferences not
included in the DBD included the licensee's letter dated August 30,
1993, Serial: BSEP 93 0142, and a letter from NRC to CP&L dated
February 15, 1993. These letters concerned the licensee's
implementation of the BWR owners group position on Regulatory Guide 1.97, documented in NED0 31588 regarding qualification of the neutron
monitoring system. The NED0 31588 report
neutron monitoring system instrumentation, proposed criteria for the
in lieu of the Category 1
.
.
22
criteria fn:1uded in RG 1.97. The proposed criteria, which was accepted
by NRC in o Safety Evaluation Report attached to an NRC letter to CP&L
dated April 7. 1993, does not require the neutron monitoring
instrumentation to be included in the EQ program.
Review of DBD 100 showed that this DBD was incomplete and contained
references to procedures which had been recently deleted / superseded by
new procedures.
Also, numerous NRC documents, such as Information
Notices relating to EQ issues were not referenced in the DBD.
However,
as part of the corrective actions to the EQ violations discussed above,
the licensee is in the process of reviewing and updating the DBD. The
inspectors reviewed ESR 97 00055. EQ NRC Docum ntation Identification.
This ESR. which has been partially completed, will include a review of
NRC documents such as circulars, generic letters, bulletins, and
information notices, and verify they have been included in the BNP EQ
program,
c.
Conclusions
The licensee's corrective actions for the EQ program will address the
insufficient detail in DBD 100.
Further review will be performed by NRC
to determine the adequacy of other DBDs.
E4
Engineering Staff Knowledge and Performance
E4.1 Thermo electric Cooler Oper3bility Timeliness
(
a.
Inspection Scope 137551)
The inspector reviewed the timeliness of the operability assessment for
the Hydrogen /0xygen Analyzer Thermo electric coolers,
b.
Qblenations and Findinas
In 1993 a 10 CFR Part 21 evaluation was issued concerning a reduction of
the qualified life of the hydrogen / oxygen analyzer thermo electric
cooling units from 40 to two years due to galvanic corrosion. The
licensee reviewed the Part 21 notification and decided not to decrease
the qualified life of the component.
Upon discovery, the licensee
initiated tracking LC0 for both units in accordance with Operating
Instruction 001 1.08 Control of Equipment and System Status. Tracking
LCOs TI 97 542 and TI 97 543 were initiated ai. 1:00 p.m. on June 5,
1997, with a 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> duration causing the LCOs to expire June 7, 1997,
at 1:00 p.m.
On June 7. 1997, around 2:15 p.m., the inspector questioned the shift
superintendent (SS) on the status of the operability assessment.
The SS
stated verbal acceptance had been given at 12:17 p.m. but an approved
ESR would not be completed in accordance with the established duration.
The inspector questioned why an extension was not requested in
accordance with 001 1.0.8.
The SS subsequently requested and received
-
.
.
23
>ermission for an extension at 3:00 p.m.
CR 97 2028, Untimely
)ocumentation for LCO, was initiated documenting this occurrence.
TS 6.8.1 requires that written procedures be implemented for eg2.pment
ul
control as recommended in Appendix "A" of RG 1.33, November 19
001-
1.0.8 required that the Manager 0perations and the manager of the
assisting organization approve any extension of the initially
established time frame.
The inspector noted that the acting manager of
the assisting organization was a member of the team performing the
The failure to properly obtain an extension in
accordance with 001 1.08 until questioned by the inspector was
identified as a violation.
This violation is the second example of VIO
50 325(324)/97 08 01, TS/LCO Administration,
c.
Conclusions
Upon exceeding the tracking LC0 covering the hydrogen / oxygen thermo-
i
electric qualified life operability review, on extension was not
obtained until questioned by the inspector.
This was a violation of the
i
plant operating instruction.
E5
Engineering Staff Knowledge and Qualification
E5.1 Trainina and Qualification of Svjtem Enaineers
a.
IDSpection Scope (37550)
The inspactor reviewed the licensee's program for training and
qualification of personnel in the EQ task force including both
I
CP&L and contract engineers,
b.
Observations and Findinas
The inspe';ars reviewed Training Administrative Procedure (TAP)
6.04, Revision 1. dated January 14, 1997 Engineering Support
Personnel Job Specific Training Guide for Plant Engineers. This
procedure specifies the licensee's arogram for training and
qualification of engineers within tie Brunswick Engineering
Support Section (BESS). The ins)ectors also reviewed the
qualifications of engineers in tie EQ task force. These included
CP&L direct employees and contract engineers employed temporarily
in the EQ task force. The records indicated that the 3ersonnel
involved in the EQ program were well
With the exce) tion of one individual, qualified in the
EQ area.
all CP&L direct employees
involved in tie EQ program have completed training and are fully
qualified as modification engineers as specified in TAP 6.04. The
contract engineers, with the exception of a recently hired
individual, were all fully qualified as EQ engineers in accordance
with Attachment 9 of TAP 6.04.
However the inspectors noted that
contract engineers did not require training in the licensee's
corrective action program, CP&L procedure OPLP 04
The TAP 6.04
training program requires self study (reading for understanding)
,
.
.
24
of procedure OPLP.04.
Failure to include this recuirement as part
of the contract engineers' training was identificc to the licensee
as a weakness. CR 97 01927 was recently initiated to document an
issue that engineers in the EQ group were concerned that
nonconformances were not being addressed appropriately.
A finding
was also identified during the recently completed self assessment
in the EQ group that the threshold for when a CR should be written
was inconsistent among personnel in the EQ task force,
c.
CODelusions
The inspector concluded that the licensee's program for training
and qualification of EQ engineers meets NRC requirements. A
weakness was identified for failure to require that the contract
engineers receive training on the licensee's corrective action
program.
E8
Hiscellaneous Engineering Issues (92903)
E8.1 (Closed) VIO 50 324/96 04 03:
Inadequate Work Instructions for Main
Steam Line Radiation Trip Modification
This violation was issued as a result of inadequate work instructions
for deleting the Main Steam Line High Radiation Trip function for
Unit 2.
A similar violation occurred during installation of the same
modification on Unit 1 dlaing the Spring 1995 Refueling Outage.
The licensee responded to this violation in a letter dated May 29, 1996.
The licensee's corrective actions included a work stoppage, a design
package review, disciplinary action for the persons involved and
establishing procedural direction to require independent verification of
modification implementation packages by appropriate technical personnel.
The inspectors reviewed CR 96 00594: Action Item Assignment Project 10
96 00594.1: and Engineering Request EGR NGGC 005, " Engineering Service
Requests, Revision 4. The inspectors verified through these reviews that
the ap3ropriate corrective actions were taken by the licensee. Based
upon t1ese reviews, this violation is closed.
E8.2 (Closed) URI 50 325(324)/95 22 01: Control Building Ventilation Problems
(Closed) llR 50 325/95 020: Control Building Emergency Air Filtration
System (CBEAF), Unable to Maintain Positive Pressure
(Closed) LER 50 325/95 020 01: Control Building Emergency Air Filtration
System (CBEAF), Unable to Maintain Positive Pressure
The problem was identified during testing of the control room pressure
envelo)e on October 25, 1995. The control room pressure is required by
TS to >e positive to minimize radioactive material intrusion into the
control room during accident conditions. The licensee immediately
established compensatory measures once the problem was identified.
The
!
_
.
.
25
most probable cause of the negative pressure condition was the
cumulative degradation of control room cable seals and ductwork.
Following completion of trouble shooting activities, system repairs, and
a satisfactory surveillance test, the control building ventilation
system was declared operable with no compensatory measures on
December 4, 1995.
The licensee Supplement 1 to LER 195 20, committed to 1) a development
and implementation plan which establishes periodic functional testing of
control building HVAC system and components: 2) develop and implement a
preventive maintenance inspection procedure to evaluate the condition of
and repair as required the control building access door seals: and
3) complete a safety system functional inspection (SSFI) for the control
building HVAC system.
The inspector reviewed the plan for periodic testing.
This plan listed
all current periodic tests and surveillance tests required by TS.
Several preventive maintenance items were added to the required tests to
formalize the plan. The inspector reviewed the preventive maintenance
check list developed for doors and seals. The licensee conducted an
SSFI during April 29
May 31, 1996. A significant issue was found in
the SSFI concerning the Q list downgrade to non-Q of the control
building air conditioning units. This downgrade was done without a 10 CFR 50.59 safety evaluation being perf e ed. This item will be reviewed
to determine why a 10 CFR 50.59 review was not aerformed. This is
identified as URI 50 325(324)/ 97 08 09, 50.59 leview for Control
Building Air Conditioning Quality Classification Downgrade.
Additionally, after submittal of the power uprate license amendment
request, several cuestions concerning control building ventilation
system were raisec. The licensee committed in a letter to the NRC dated
February 15, 1997, to two commitments to be completed by the end of the
Unit 1 twelf th refueling outage scheduled to start in April 1998. The
first commitment was to evaluate the sealing and pressurization
capabilities of the existing CREVS and to implement imarovements to
increase pressurization of the control room while in tie smoke / radiation
protection mode. The second commitment was a part of a comprehensive
plan to resolve all remaining open items associated with the SSFI.
The inspector reviewed the licensee's project plan for the issues
committed to by the licensee to resolve all control room ventilation
issues.
It is a comprehensive plan with a dedicated project manager.
The programmatic review of the licensee committed corrective actions
will be tracked as IFI 50 325(324)/97 08 10 Review of Control Room
Ventilation Issues. The URI and LERs associated with these issues are
closed and completion of the corrective actions will be tracked as part
of the IFI review.
E8.3 10pftn) VIO 50 32E(324)/96 15 06:
Repeat Failure to Take Adequate
Corrective Action; for Chlorine Detector Failures
j
.
.
26
1 Closed) VIO 50 325(324)/96 05 01:
Failure to Take Corrective Actions
for Chlorine Sensors
(Closed) LER 50325(324)/9612:
Five of 8 Chlorine Detectors Inoperable
(Closed) LER 50 325(324)/96 05.1 Six of 8 Chlorine Sensors Used for
Control Building Isolation Logic Were Found Inoperable
(Closed) LER 50 325(324)/95 021 Multi)1e Chlorine Sensors used for
Control Buildin Logic Were Found to )e Outside Technical Specification
Tolerance Durin Routine Calibration
Based on the corrective actions for the repeated failures of the
chlorine detectors as described in IR 50 325(324)/96 15 being the same,
the closure of these issues will be tracked under the associated
violation 50 325(324)/96 15 06, Repeat Failure to Take Adequate
Corrective Action for Chlorine Detector Failures.
E8.4 1 Closed) LER 50 325/96 02 01: Unit 1 Hanual Reactor Scram Due to Main
Turbine Vibration
Based on NRC review as documented in IR 50 325(324)/96 01 and 50-
325(324)/97 02 this item is closed.
IV. Plant Sunoort
R2
Status of RP&C Facilities and Equipment
R2.1 Radioactive Material Postina
,
a.
Inspection Scope (71750)
The inspector reviewed the posting of radioactive material area (RMA),
b.
Dh gr_gtions and Findinas
On June 20, 1997, the licensee extended the radiation control area (RCA)
to include the transformer switchyard, Auxiliary Off Gas, Diesel and
Water Treatment Building, the Condensate Storage, Deniineralized Water
Tanks for both units, as well as the Diesel Fuel Oil Storage Tanks.
During routine inspections of the RCA on June 24 25, 1997, the inspector
noted inconsistencies in the posting of radioactive material areas. At
-the north end of the RCA, between the Unit 1 Turbine Building and the
Radioactive Haterial Control Storage Building, the inspector observed
several metal containers and other equipment. All equi) ment observed
was labeled, however only the metal containers were wit 11n the posted
roped off RHA. Additional review of the RCA revealed numerous
inconsistencies in RMA posting.
Some radioactive material is located
within roped off areas
other material was not, the outside areas of
the RCA encompassing half the plant site are considered one continuous
RMA. -Therefore, areas used to store RMA are not always posted. One
area the inspector noted was behind the Radwaste loading dock. This
.
.
27
area contains several high integrity containers which served as a
temporary storage arec until the waste can be moved to its designated
storage location. The area was posted as a radiation area, but not a
RMA despite the presence and storage of radioactive material.
The inspector discussed these inconsistencies with the licensee and
reviewed Nuclear Generation Group Standard Procedure HPS NGGC 0003,
Radiological Posting, Labeling and Surveys.
Discussions with the
licensee revealed a dichotomy concerning how radioactive material should
be posted. The inspector could not locate a comprehensive standard site
practice or expectation for the posting of RM within the RCA.
Section
9.1.8 Radioactive Materials Area of HPS NGGC 003, provided adequate
instruction for the establishment cf RMA outside of the RCA.
However,
no comprehensive instructions for the establishment of RMA's within the
RCA could be located.
The lack of comprehensive instructions for the
l
establishment of posted RMAs within the RCA was seen as a weakness.
l
'
c.
fanclusions
A lack of comprehensive procedural guidance or standard site practice
contributed to the inconsistent posting of radioactive material within
the radioactive controlled area.
R8
Miscellaneous RP&C Issues
R8.1
(Closed) Violaijpn 50 325(324)/96 04 04:
Failure to Conduct CAT
This violation was issued as a result of individuals being allowed
unescorted access to contaminated areas of the plant without the
required contamination area training.
The licensee responded to this violation in a letter dated May 29, 1996.
The licensee's cor rective actions included a review of Contaminated Area
Training (CAT) records to identify those individuals required to work in
restricted areas who had not received CAT instruction, the conduct of
special training classes for those individuals identified as not having
.
CAT, and implementation of an electrcnic flagging feature to ensure that
'
only >ersons who have completed CAT ate allowed to sign on a Radiation
Work Jermit and an assessment of the programs implement to ensure
adequate barriers exist to prevent the performance of work without the
required CAT.
The inspectors reviewed Action Item Assignment Project ID 96 00823.9 and
96.00823.11 through 96 00823.17. Each of these Action Item Assignment
packages contained a Self Assessment Report that described the
effectiveness of the barrier designed to provent the performance of work
without the required training. The inspectors identified no
deficiencies during the review of the Self Assessment Reports.
Based
upon these reviews, this violation is closed.
.
.
1
,
.
28
F1
Control of Fire Protection Activities
F1,1 Qual Unit Downoower Due to Fire Suppression System Declared Inonerable
a.
Inspection Scope (71750)
The inspector reviewed the dual unit downpower that occurred on June 20,
1997, following declaration that the fire suppression water system was
b,
Observations and Findinas
On June 20, 1997, at 6:00 p.m., the fire suppression water system was
declared inoperable. The system was declared inoperable because during
a flow test performed by 0PT 34,7,10, Fire Suppression Water System Flow
Test, the test results did not meet the acceptance criteria. The test
results were logged into the Loss Prevention Unit (LPU) Shift Supervisor
log on June 19, 1997, at 6:00 p.m.
but were not adequately communicated
to Hanagement.
Plant Procedure OPLP 01.2 Fire Protection System Operability. Action,
and Surveillance Requirements, required that, with the fire suppression
water system inoperable, a backup fire suppression water system must be
established within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or be in at least HOT SHUTDOWN within the
next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
Plant Management concluded that 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> had elapsed prior to
establir,hing a backup fire suppression water system and proceeded to
initiate a dual unit shutdown. This was a conservative decision. The
sequence of events was as follows:
llE
EYff
Jslie_12
6:00 p.m.
Fire Suppression System Test Does Not Meet
Acceptance Criteria Logged into LPU Shift
Supervisor Log.
June 20
6:00 p.m.
Licensee starts 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> to hot shutdown LCO.
10:10 p.m.
Unit 2 started power reduction.
11:00 p.m.
Unit I started power reduction.
11:02 p.m.
Licensee made 10 CFR 50.72 one hour report to
NRC,
June 21-
2:45 a.m.
_ Licensee re performs test which again did not
meet acceptance criteria.
_ _
_ _ _ _ - - . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
_ _ _ _ _ ___ _ __ _ _ _ _ __.
.
.
29
4:15 a.m.
Fire watches established as compensatory
measures for portion of fire main loop that
was believed to be partially blocked or had
reduced flow.
5:38 a.m.
Units stop shutdown both units around 22
percent power based on compensatory actions
for portion of fire main loop that had reduced
flow.
6:00 a.m.
Power increase started.
4:20 p.m.
ESR 97 000348 determined that an error was
made in the calculation of test date.
June 22
Test date for last performance of test in 1995
found to be questionable.
The inspector reviewed the test procedure, OPT 34.7.10. The purpose of
the test was to determine the water flow capability of the Fire
Suppression Water System underground loop piping. This surveillance
test was required by OPLP 01.2, step 6.1.3.1.f.
At least once per three
years a flow test was required to be performed in accordance with
Chapter 5, Section 11. of the Fire Protection Handbook,14th edition,
published by the National Fire Protection Association.
This procedure
performs three flow tests and calculates a "C", friction loss co-
efficient for each flow test. The acceptance criteria was a C factor
greater than or equal to 100. The test takes pressure readings at
various locations under static conditions and then takes pressure.and
nozzle flow readings under dynamic conditions.
This data is then used
to perform a fluid flow calculation to determine the C factor.
1
The reason the test was performed on June 19, 1997, was because of CR
97 02142. Suspect Flow in the Fire Header.
During fire drills in recent
weeks LPU personnel noticed an apparent drop in pressure at the hose
nozzles. The test data taken on June 19, 1997, indicated a C factor
greater then 100 for test one and test two but test three was 83. The
test was re performed on June 21, 1997, and determined to give similar
results with a value of 84 for test three. They concluded that there
was a partial system blockage or reduced flow in a portion of the fire
main loop.
The licensee performed a technical review of the test data and
determined there was an error in the calculation. This analysis was
' documented in ESR 97 00348, Evaluation of OPT 34.7.1.0. Fire Protection
Flow Test Data.
The licensee concluded that there was an error in the
calculation and the static differential pressure should be applied as a
correction factor when measuring differential pressure under dynamic
conditions. This data was. collected as cart of the test but was not
specified as to how the C factor was to oe applied in the calculation.
Once this correction was made, the test data for test three indicated
valves greater than 100. The licensee concluded that there was no
system blockage and the test data was acceptable.
.
.
30
The inspector reviewed the test procedure OPT 34.7.1.0 and ESR 97 00348.
The inspector concluded that using the )rocedure as written would not
provide accurate results. TS 6.8.1,f,
rire Protection Implementation,
requires that written procedures shall be established, implemented, and
maintained covering the Fire Protection Program.
The test procedure was
not adequately maintained and was identified as a violation of TS 6.8.1.f.
The licensee identified and corrected violation is being
treated as a Non Cited Violation (NCV), consistent with Section VII.B.1
of the NRC Enforcement Policy. This will be tracked as NCV 50 325(324)/
-97 08 11,- Inadequate Fire Protection Flow Test Procedure.
Additionally, the inspector questioned how the system flow data compared
to the last >erformance of the three year test in 1995.
The licensee
determined t1at the C factor was not calculated in 1995. As a result of
an audit finding, the procedure was changed to put the C factor
determination back into the procedure, liowever, taking the pressure and
flow date from 1995 and calculating a C factor determined that the data
was not reasonably close to the expected values. The C factor values
ranged from 576 to 303.
Data taken from a Fire Protection Handbook
indicated the following C. factor valves:
._ip.e
G.fAC10C
P
Jnlined Cast Iron, new
120
Unlined Cast Iron,10 years mildly corrosive water
110
Unlined Cast Iron, 20 years mildly corrosive water
90
Unlined Cast Iron, 30 years mildly corrosive water
80
Cast Iron, cement lined
140
Steel Pipe, new
140
Therefore, the data in 1995 was erroneous and was not questioned until
the inspector requested a comparison. The purpose of these flow tests
being performed every three years was to monitor system performance and
possible problems.
The inspector determined that the failure to identify a trend in the
1995 test results and establish a baseline data for OPT 34.7.1.0 was a
weakness in trending and monitoring of the fire protection water
suppression system performance.
The inspector reviewed the licensee's Corporate Quality Assurance
Program (CQAP) Hanual
Section 15. QAS Program for Fire Protection
Systems.
Section 15.8, Conditions Adverse to Quality (CATO), states
that CATQ for fire protection related items shall be identified,
reported, dispositioned, and corrected in accordance with Section 12.
Conditions Adverse to Quality and Correction Action. Section 12 of the
CQAP manual implements 10 CFR Appendix B. Criterion XVI, Corrective
' Action.
Accordingly, a violation of 10 CFR Appendix B. Criterion XVI, Corrective
Action, as committed to by the licensee's CQAP for fire protection
related items was identified.
_ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ -
_ _ _ _ _ _ _ _ _ _ _
_ _ _ _ - _ _ _ _
__
_ - _ _ _ _ _-__________ _ _______ -__-__-- ___
.
.
31
,
A violation was identified for failure to promptly take corrective
1
action for a flow test >erformed on June 19, 1997, that did not meet the
1
acceptance criteria. T1e results for the test were not adequately
communicated to Hanagement until the next day. This licensee identified
and corrected violation is being treated as a NCV consistent with
Section VII.B.1 of the NRC Enforcement Policy. This will be tracked as
NCV 50 325(324)/97 08 12. Failure to Take Corrective Action for Abnormal
Fire System Flow Data.
Additionally, there was a comunir.ations interface problem with
Operations. The licensee had taken the approach to fire protection as
not being part of TS and placed control of the systems out of
Operations.
For example, in IR 50 325(324)/97 07 the inspector
discussed a compensatory fire protection problem with Operations but was
told that LPU had control over this issue and all discussion should be
with LPU.
In fact, in LPU shift supervisor's log, there is an LC0
statement to indicate when a fire protection LC0 was initiated or
canceled. The LCOs are not logged or tracked by Operations.
In the
past few months, the fire )rotection engineer was taken out of
engineering and placed in
_PU.
The inspector discussed with licensee management that licensed operators
must maintain control of the LCOs for fire protection equipment. The
facility operating license requires that the fire protection program be
maintained. The TSs require that the fire protection program procedures
be established, implemented, and maintained.
The inspector attended a debrief on July 2.1997, of an NAS audit of the
Several issues were identified by NAS. The
NAS team assessment concluded that the program was ineffective based on
a number of program elements being below acceptable standards,
c.
Conclusions
The inspector concluded that plant management made a conservative
decision to perform a dual unit shutdown based on the untimely and
erroneous test results provided by the LPU. An ongoing NAS audit
identified several issues in this area.
Two non cited violations were
identified for failure to promptly take corrective action when flow test
performance did not meet acceptance criteria and for an inadequate fire
protection flow test procedure. A weakness was identified in trending
and monitoring of the fire protection water suppression system
performance.
F1.2 Transient Combustible in Seoaration Zone
a.
Inspection scope (71750)
The inspector, during routine inspection activities, observed the
improper storage of combustibles in the Unit I reactor building.
.
.
32
b.
Observations and Findinas
The Safe Shutdown Analysis defines separation zones as areas " intended
to provide separation between redundant trains in lieu of three hour
barriers," Keeping these zones free of combustibles is required to
prevent a fire from damaging redundant safe shutdown equipment on either
side of the zone.
The requirement was established as part of the fire
protection requirements in a Safety Evaluation Report dated December 30,
1984.
During routine inspection activities on June 23, 1997, the inspector
observed transient combustible material stored within a separation zone
located on the 50 foot elevation in Unit 1.
The inspector questioned a
nearby worker regarding the material. The material was immediately
removed and the LPU supervisor was notified.
The separation area was
posted indicating that no transient combustibles were allowed.
The failure to maintain the Unit 150 foot elevation separation zone
free of transient combustibles is a violation of TS 6.8.1.f.
This
violation is identified as examples one of VIO 50 325(324)/97 08 13.
Failure to follow Fire Protection Program procedures.
The inspector reviewed the UFSAR section and discussed this event with
the licensee. The inspector reviewed 0FPP 13. Transient Fire Load
Evaluation and 0FPP 14, Control of Combustible. Transient Fire Loads,
and Ignition Sources. These procedures were weak in providing guidance
concerning the maintenance and inspection of fire separation zones.
On June 24, 1997, during routine inspection activities the inspector
observed combustible material in a separation area. This area was
located in the Unit 1 ECCS Mini Steam Tunnel.
The control room was
notified and the items removed.
The entrance to the ECCS Mini Steam Tunnel has a sign on the door
stating that no transient combustibles were allowed to be stored-in the
separation area in accordance with 0FPP 13.
However, from discussion
with the licensee, the actual separation zone was thought to be above
the tunnel and the posting was mislead 61
This item will be-identified
as an unresolved item pending further review and tracked as URI 50-
325(324)/97 08 14 Designation of Fire Separation Zones.
In addition, on July 2.1997, the licensee initiated CR 97 02331,
Combustibles in Separation Zone.
This CR identified that a computer and
desk had been placed in the Separation Zone in the DG building south
end. This area was designated by the Alternate Shutdown Capabilities
Assessment Report as an Alternate Safe Shutdown Separation Zone.
c.
Conclusions
The inspector concluded that there was a violation of the fire
protection procedure for having transient combustibles in a fire
separation zone.
Designation of fire separation zones was unresolved
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requiring further review.
Implementing-procedures for the establishment
and maintenance of fire protection separation zones were weak. This was
evident by the discovery of transient combustibles in separation zones.
F3
Fire Protection Procedures and Documentation
i
F3,1 Hydrant Isolation Valve Misoositioned
a.
Insoection SCoDe (71750)
The inspector reviewed the circumstances surrounding an out of position
hydrant isolation valve.
g
b.
Observations and Findinas
On June 19, 1997, during the performance of OPT 34.7.1.0, Fire
Sup)ression Water System Flow Test, the isolation valve for hydrant
num)er 5 was found closed. This clocad valve prevented flow from this
section of the fire suppression loop. However, flow was still available
to the other hydrants in the loop via another flow path.
The inspector reviewed the appropriate procedures, associated prints,
and discussed the issue with the licensee.
00P 41 Fire Protection and
Well Water System, required the valve to be open. A review of the last
,'
performance of tir; valve line up in 1995 indicated that the valve was
verified open. Subsequent licensee review has not determined the reason
for the mispositioning. TS 6.8.1.a requires that procedures shall be
implemented and maintained for the Fire Protection System as required by
Appendir iof Regulatory Guide 1.33 November 1972. The failure to
maintain the. valve in accordance with 00P 41, is a violation of TS 6.8.1.a. This licensee identified anti corrected violation is being
treated as an NCV consistent with Section VII.B.1 of the NRC Enforcement
,
Policy. This violation is identified as NCV 50 325(324)/97 08 15.
Hydrant IV Mispositioned,
c.
Conclusions
An NCV was. identified for the mispositioning of a hydrant isolation
valve.
F4
Fire Protection Staff Knowledge and Performance
F4.1 Inadvertent Actuation of Deluae Vah q
'
a.
Insoection Scope (71750)
The inspector reviewed the circumstances surrounding the actuation of
the transformer fire protection deluge system on June 22, 1997.
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34
b.
Observations and Findings
On June 11, 1997, the LPU 3erformed Periodic Test 1PT 34.13.3.3,
Transformer Deluge System runctional Test.
This surveillance
demonstrated the operability of the deluge system for the Unit 1
transformers. The 3rocedure isolated the water source to prevent
spraying water on t1e 230 kV transformer.
System alarm and Control Room
annunciation are verified from the manual pull station and by simulation
of a heat source by use of a heat gun.
The alarms and annunciators are
reset and cleared and then the water source is restored.
During the performance of 1PT 34.13.3.3 on the Unit 1 Startup
Transformer (SAT), the technician halted performance of the test and
left tne work site. U
the wrong transformer,pon the technician's return, work was resumed on
the unit auxiliary transformer (UAT). Upon use
of the heat gun on the UAT heat detector, the UAT fire protection deluge
system actuated spraying water on the energized 24/4.16 kV UAT. The
ins)ector reviewed the procedure, work site, and discussed the event
wit 1 licensee personnel. The procedure indicated under precaution 4.2
that high voltage exists in the transformer area, EXERCISE caution.
Also, precaution 4.4 requires communications must be ESTABLISHED and
MAINTAINED between personnel at the deluge valve, transformer spray
,
l
headers, and the Control Room while performing the test. The inspector
determined that similar labeling on the heat detectors for both
transformers, poor procedural equipment identification, and the
technician's lack of attention to detail were contributing factors to
this event. No personnel were injured nor was any equipment damage or
malfunction noted. The licensee wrote CR 97 02196, Inadvertent Deluge
Actuation, to document this problem.
TS 6.8.1.f requires that written procedures shall be implemented for the
The failure to implement the test in
accordance with IPT 34.13.3.3 is a violation. This violation is
identified as example two of VIO 50 325/97 08 13, Failure to follow Fire
Protection Program procedures.
c.
Conclusions
Poor attention to detail resulted in the inadvertent spraying of water
on an energized high voltage Unit Auxiliary Transformer.
No personnel
were injured and no equipment damage or malfunction was observed.
'
F8
Miscellaneous Fire Protection Issues (92904)
F8.1
(Closed) VIO 50 325(324)/96 04 06:
Failure to Follow Fire Protection
Procedure
This violation, with two examples, was issued as a result of contractor
painters not implementing the procedural requirements for transient
combustibles and the lack of a valid transient loading evaluation for
combustibles found in both units. Also, the material found on both
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units was not properly tracked in accordance with procedural
- requirements.
The licensee responded to this violation in a letter dated May 29, 1996.
The immediate corrective actions included the conduct of a stand.down by
the involved painting contractor and a field verification of the
- transient load evaluation log book by the licensee,
The corrective actions to be taken, as stated in the licensee's response
of May 29, 1996. included a procedural revision to ensure combustible
,
load evaluation requirements are clearly defined and easily understood.
The inspectors reviewed Fire Protection Procedure 0FPP 014. Control of
Combustible Transient Fire Loads, and Ignition Sources, Revision 15.
The inspectors observed during the procedural review that a detailed
l
definition section was 'in the revised procedure and the organization of
the procedure was clear and straightforward. The inspectors also
l
,
observed that training on the procedural revision was presented to
facility personnel to include contractors.
Based upon this review, this violation is closed.
V.
Manaaement Meetinos
,
XI
Exit Meetina Summary
- The inspector presented the inspection results to mcmbers of licensee
management at the conclusion of the inspection on Jaly 10. 1997. Post
inspection triefings were conducted on' June 6 and Juie 27, 1997. The
licensee acknowledged the findings pressated.
PARTIAL-LIST OF PERSONS CONTACTED-
Licensee-
'
G. Barnes. Manager Training
A. Brittain, Manager Strurity
4
M. Christinziano, Manager Environmental and Radiation Control
'
N. Gannon, Manager Maintenance
J. Gawron, Manager Nuclear Assessment
S. Hinnant, Vice President, Brunswick Steam Electric Plant-
K.- Jury, Manager Regulatory Affairs
W. Levis, Director Site Operations
B. Lindgren, Manager Site Support Services
R. Lopriore, General Plant Manager
J. Lyash, Brunswick Engineering Support Section
R. Mullis, Manager Operations
H. Turkal, Supervisor Licensing and Regulatory Programs
,
4
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36
Other licensee employees or contractors included office, operation,
maintenance, chemistry, radiation, and corporate personnel.
E. Brown
J. Canady
J. Coley
J. Lenahan
C. Patterson
H. Shymlock
,
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INSPECTION PROCEDURES USED
IP 37550:
Engineering
IP 37551:
Onsite Engineering
4
IP 61726:
Surveillance Observations
IP 62700:
Maintenance Implementatien
IP 62707:
Maintenance Observations
IP 71707:
Plant Operations
IP 71750:
Plant Support Activities
IP 92901:
Followup
Operations
IP 92902:
Followup
Maintenance
IP 92903:
Followup
Engineering
IP 92904:
Followup
Plant Support
ITEMS OPENED, CLOSED, AND DISCUSSED
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Ooened
50 325(324)/97 08 01
TS/LC0 Administration (paragraphs 08.2. E4.1)
50 325(324)/97 08 02
Failure to Verify / Check E Bus Relay Operability
(paragraph M1.2)
50 325(324)/97 08 03
Safety Relay Setting Change Made as Pen and Ink
Changes to Procedure (paragraph M1.2)
50 325(324)/97 08 04
Control of EDBS Information (paragraph Hl.2)
50 324/97 08 05
Failure to Follow Work Instructions uuring
Previous Installation of Solenoid Valves 2 CAC-
SV 4410 26 & 27 (paragraph Hl.3)
-50 325(324)/97 08 06
Failure to Obtain an EQ Disposition on Extension
of Vendor Recommended EQ Life for Thermo-
Electric Cooler (paragraph Hl.3)
50 325(324)/97 08 07
Failure to Initiate Condition Reports to
Document Nonconforming EQ Items (Paragraph E1.2)
50 325(324)/97 08 08
Control of Moisture in Installation of EQ
Components (Paragraph E1.2)
50-325(324)/97 08 09
10 CFR 50.59 Review for Control Building. Air-
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Conditioning Quality Classification Downgrade
(paragraph E8.2)
50 325(324)/97-08 10
IFI
Review of Control Room Ventilation Issues
(paragraph E8.2)
50 325(324)/97-08-11
Inadequate Fire Protection Flow Test Procedure
(paragraph F1.1)
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50 325(324)/97 08 12
Failure to Take Corrective Action for Abnormal
Fire System Flow Data-(paragraph F1.1)
50 325(324)/97 08 13
Failure to follow Fire Protection Program
procedures (paragraphs F1.2 and F4.1)
50 325(324)/97 08 14
Designation of Fire Separation Zones (paragraph
F1.2)
50 325(324)/97 08 15
Hydrant IV Mispositioned (paragraph F3.L)
l
Closed
50 325(324)/96 04 02
VIO.
Cooldown Monitoring Not Followed (paragraph
08.1)
i
50 325(324)/97 07 01
Failure to Enter TS ACTION Statement (paragraph
08.2)
50 324/97 08 05
Failure to Follow Work Instructions During
Previous Installation of Solenoid Valves. ? CAC.
SV 4410 26 & 27 (paragraph M1.3)
50 324/96 01
LER
Control Rod Average 5 percent Insertion Time
Exceeds Technical Specification Requirements
(paragraph M8.1)
50 324/96 01 01
LER
Control Rod Average 5 percent Insertion Time
exceeds Technical Specification Requirements
(paragraph M8.1)
50 324/96 04 03
Inadequate Work Instructions for Main Steam Line
Radiation Trip Modification (paragraph E8.1)
50 325(324)/97 08 09
Failure to Perform 50.59 for Control Building.
Air Conditioning Quality Classification
Downgrade (paragraph E8.2)
50 325(324)/95 22 01
Control Building Ventilation Problems (paragraph
E8.2)
50 325/95 020
LER
Control Building Emergency Air Filtration System
(CBEAF). Unable to Maintain Positive Pressure
(paragraph E8.?)
50 325/95 020 01-
LER
Control Building Emergency Air Filtration System
(CBEAF). Unable to Maintain Positive Pressure
(paragraph E8.2)
,
50 325(324)/96 05-01
Failure to Take Corrective Actions for Chlorine
Sensors (paragraph E8.3)
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50 325(324)/96 12
LER
Five of 8 Chlorine Detectors Inoperable
(paragraph E8,3)
50 325(324)/96 05
LER
Six of 8 Chlorine Sensors Used for Control
Building Isolation Logic Were Found Inoperable
(paragraph E8.3)
50 325(324)/95 02
LER
Multiple Chlorine Sensors used for Control
Building Logic Were Found to be Outside
Technical Specification Tolerance During Routine
Calibration (paragraph E8.3)
50 325/96 02 01
LER
Unit 1 Manual Reactor Scram Due to Main Turbine
Vibration (paragraph E8.4)
50 325(324)/96 04 04
Failure to Conduct CAT (paragraph R8.1)
50 325(324)/97 08 11
Inadequate Fire Protection Flow Test Procedure
(paragraph F1,1)
50 325(324)/97 08 12
Failure to Take Corrective Action for Abnormal
Fire System Flow Data (paragraph F1.1)
50 325(324)/97 08-15
Hydrant IV Mispositioned (paragraph F3.1)
50 325(324)/96 04 06
Failure to Follow Fire Protection Procedure
(paragraph F8.1)
Discussed
50 325(324)/96 15 06
VIO-
Repeat Failure to Take Adequate Corrective
Action for Chlorine Detector Failures (paragraph
E8.3)
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