ML20197H188
| ML20197H188 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 12/08/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20197H167 | List: |
| References | |
| 50-324-97-12, 50-325-97-12, NUDOCS 9712310215 | |
| Download: ML20197H188 (54) | |
See also: IR 05000324/1997012
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' U, S.c NUCLEAR REGULATORY: COMMISSION: !
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REGIONLII- ;
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' Docket Nos': 50 325',-50 324: ;^
License Nos: .-0PR 71, DPR-62
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LReport'No:- -50s325/97-12, 50-324/97-12
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-Licensee: -Carolina-Power =& Light.(CP&L)-
facility: Brunswick! Steam Electric Plant, Units 1-& 2 '
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, 'Locationi 8470 R1'ver Road'SE
Southport, NC- 28461 t
Dates: September 28 November 8, 1997 -
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Inspectorsi C. Patterson. Senior Resident-Inspector
E.-. Brown, Resident: Inspector-
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. E. Guthrie. Inspector in Training
J. Coley. Reactor Inspector (Section-M2.2-2.3)
J. Lenahan, Reactor.-Inspector (Section El.1-El.2) .;
F. Jape Reactor Inspector (Section M1.1)
< . Approved by: M.~ Shymlock, Chief. Projects Branch 4
Division of-Reactor Projects
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EXECUTIVE SUMMARY .
Brunswick Steam Electric Plant, Units 1 & 2
NRC Inspection Report 50-325/97-12. 50-324/97-12
This integrated inspection included aspects of licensee ope ations.
engineering, maintenance, and plant support. The report cc- rs a 6-week
period of resident inspection: in addition, it includes the results of an
engineering and in-service inspection by regiona! inst actors.
Operations
e lhe torus was found very clean and absent of foreign material during an
inspection prior to final torus closeout. (3ection 02.1)
. During an inspection, the drywell was founc to be free of foreign
material and ready for closecut. (Section 02.2)
. One example of a violation of the plant clearance procedure occurred
because the torus master clearance was not adequate to protect plant
personnel and equipment. (Section 02.3)
. Operator response to a plant transient resulting from a mechanical
problem on a reactor feed pump was good. (Section 02.4)
. An inadvertent diesel generator start occurred due to an operator error
while performing the procedure to restore system lineup. This was
because of a lack of understanding of the procedure step required
actions and the procedure step did not provide clear guidance.
(Section 04.1)
. A weakness was identified in ti.e direction provided for reactivity
manipulation cortrol. A Non-Cited Violation occurred due to the failure
to follow procedure for control rod movement. (Section 04.2)
. During removal of Reactor Feed Pumps from service as aart of a planned
shutdown, two recirculation aump runbacks occurred. )ending further
licensee investigation and NRC review this item is unresolved.
(Section 04.3)
. During maintenance on an electrical bus a diesel generator automatic
start circuit was defeated as part of a clearance without Operations
recognition. This is an unresolved item pending further review.
(Section 04.4)
. The restart affirmation conducted by the Plant Nuclear Safety Committee
was determined to be thorough and effective in the evaluation of the
overall site organization's readiness to restart Unit 2. (Section 07.1)
. Outage planning and control continues to be a strength. (Section 07.2)
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Maintenangg
. Maintenance activities were 3erformed satisfactorily. The inspector
noted good controls of houseceeping and good supervisor oversight of
work activities. (Section M1.1)
3 The conduct of testing during the PT-1/ .:.1 Single Rod Scram Insertion
Time testing was satisfactory, no discrepancies were noted by the
inspector. (Section M1.2)
- The licensee took appropriate actions to ;ecure the surveillance test
when a discrepancy was identified, and they took the appropriate actions
to correct the procedures and drawings. (Section M1.3)
- The failure to pro)erly develop and implement a clearance for the
isolation of the 23 recirculation pump motor resulted in racking out the
incorrect breaker and the replacement of the pump seals due to damage
from excessive temperatures. These were identified as two examples of a
clearance violation. Prior licensee review of operating experience for
torquing motor oil coolers was erroneous. (Section M2.1)
. In-vessel visual inspections on the Core Spray annulus piping and the
jet pump riser welds were performed by skillful vendor technicians.
Clarity of examination surface resolution, detail, and contrast of
indica.tions when using the GE color camera was excellent. Crack like
indications on the outside diameter surface of the piping would be
properly identified by the enhanced visual examinations observed
(Section M2.2).
- Examination results from the 1996 and 1997 core shroud inspections
revealed very little crack growth for Weld H4. Weld H6B however, gave
conflicting information, crack depth was actually measured much less
during the 1997 examinations than during the 1996 examinations. The
licensee requested EPRI's help in determining the reason for these
examination differences (Section M2.3).
- Maintenance measuring and test equiament located within the plant was
found properly labeled and within t1e current calibration interval.
Revie*' of several surveillance tests determined that the acceptance
criteria and frequency were within Technical Specification allowances.
(Section M6.1)
Enoineerino
. Two violations were identified. The licensee's progress in addressing
the previously identified deficiencies in the environmental
qualification (E0) program has required extensive NRC review. The
violations identified are indicative of a lack of progress and failure
to address the previously identified issue regarding inadequate
corrective actions. The licensee has also failed to document
operability of rquipment for which F0 is indeterminate. (Section El.1)
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- The inspectors concluded that the modifications for USI A-46 were
adequately implemented in accordance with design requiremerits.
(Section El.2)
- Excellent planning and decision making led to the successful completion
of a major phnt modification. This was a significant strength in
project management. (Section E2.1)
. An apparent corrective action violation occurred because no action was
taken once the drywell temperatures exceeded their limit bounded by an
engineering analysis. This problem occurred due to a known deficiency
that was allowed to exist. The deficiency was routinely red circled in
operations daily logs as an out-of-specification condition and above the
UFSAR limit. (Section E2.2)
- Brunswick conducted activities, since original procedural approvals in
1974, which could have potentially exceeded the containment design
pressure in the event of a LOCA. The licensee had missed two
opportunities to recognize and take prompt action. A third opportunity
was initiated by the Resident Inspector, and only after questions from
the inspector did the licensee recognize the problem existed. Once the
licensee recognized the problem, corrective action was taken to correct
the problem via a procedural change. This issue was identified as the
second example of an apparent violation for failure to take corrective
action. (Section E2.3)
- Inadecuate design review during laitial comaosition allowed errors to be
introcuced into the database which establisled the Option B minimum
critical power ratio limits. A violation was issued for the failure to
assure that corrective actions taken upon discovery of an error in the
minimum critical power ratios database precluded repetition.
(Section E3.1)
a The NAS assessments were adequate in evaluating the licensee's onsite
engineering pro 0 ram. However the results of the assessments showed that
the licensee's corrective actions in response to previously identified
assessment findings have been ineffective. An additional violation was
identified regarding failure to implement the corrective action program.
(Section E7.1)
- During review of operating experience at another facility in response to
NRC Bulletin 96-02, the licensee determined that movement of the spent
fuel shipping cask with a non-single failure proof lift with the valve
box covers removed constituted an unreviewed safety question. The
failure to perform an adequate 10 CFR 50.59 screening to identify the
Unreviewed Safety Question was identified as an apparent violation.
(Section E8.1)
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Plant Suonort
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e Improved suaervisory oversight of radiation control practices was noted
during the Jnit 2 refueling outage. (Section RI.1)
- Corrective actions for a generic event identified at another facility
were found to be incomplete. Security personnel failed to secure
protected area access on two occasions which could have resulted in the
entrance of an unauthorized individual into the protected area. These
failures were identified as a violation. (Section S4.1)
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Bmprt Details
Summary of Plant Status
Unit 1 operated continuously durir.g this period until November 5. 1997,
completing 364 days of operation before starting a mid-cycle outage to
remove leaking fuel assemblies. A reactor feed pump tri) occurred on
October 24. 1997, when the feed pump oil pumas failed. ollowing
repairs. the unit returned to full power on October 27. 1997. On
October 29, 1997, the IB reactor feed pump mechanical linkage failed
resulting in a loss of the feed pump and subsequent downpower maneuvers.
The linkage was repaired and the unit returned to full power. During
the planned downpower on November 5.1997, te recirculation pump
runbacks occurred while removing reactor feed pumps.
Unit 2 completed a refueling outage and the reactor was taken critical
on October 13, 1997. The scheduled outage work was essentially
completed on October 15. 1997. but synchronizing to the grid was delayed
due to a problem with a recirculation pump motor oil cooler. The unit
was taken to hot shutdown on October 16. 1997, for repair of motor oil
cooler leaks. However, cooling water flow was erroneously secured to
the shaft seal resulting in exceeding the temperature limit of the seal.
The unit was then taken to cold shutdown for seal replacement.
Following repairs. the unit was taken critical on October 21, 1997. and
synchronized to the grid on October 22, 1997, ending the refueling
outage in 39 days. A five percent power uprate was implemented on the
unit. At the end of the report period the unit had been on-line
continuously for 17 days.
The licensee in a letter to the NRC dated February 13, 1997. committed
to upgrade the mechanical vacuum pumps trip function to include a vacuum
pump trip from the main steam line radiation monitor prior to the next
startup. This modification was completed for Unit 2 during this
refueling outage. During the Unit 1 mid-cycle outage in November 1997.
the modification was also completed. This completed the commitment that
was made because of a concern about control room dose in the event of a
Rod Drop Accident. The inspector inspected the installation of this
modification and no prc'lems
a were identified.
Due to concerns about the control room dose, the licenset. imposed an
administrative limit on Iodine until a Technical Specification (TS)
amendment submitted was approved. The licensee made a procedure change
to Administrative Procedure 0Al-81. Wcter Chemistry Guidelines, setting
the limit at 0.1 microcurie per gram dose equivalent Iodine 131 compared
to the TS value of 0.2 microcurie per gram. Also, the licensee has been
providing weekly water chemistry data to NRR and the Resident Insp ator
for review. None of the data reviewed has exceeded the administrative
limit.
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- Due to a reconstitution of- the Environmental'Oualification (E0) program
and items identified, there are-12 of 24 Justification's for Continued 3
0)eration (JCO) that~ remain open for both units. The following provides '
t1e status of the EQ JC0s and associated Engineering Service Requests
-(ESRs):
Closed
1) ESR 97-00087. E0 Type JC0 for Improperly Configured Conduit Seal.
2) ESR 97-00574. Greyboot Connectors.
3)' ESR 97-00329 (old ESR 96 00625). E0 Type JC0 for E0 Fuses Without
a Qualification Data Package (0DP).
4) f*:' 07-00289, Post Accident Sampling System (PASS) Valve Limit
bwitch Panel Wiring,
5) ESR 97-00238, JC0 for Standby Gas Treatment Motor Operated Valve
(MOV) Position Indicator Rheostat.
6) ESR 97-00534, GE EB-5 Type Terminal Strips.
7)- ESR 97-00513,- In-Board-Drywell Electrical-Penetrations.
8) ESR 97-00535. Target Rock-Solenoids TB Spray.
9) ESR 97-00449. Degraded Junction Boxes.
10) ESR 97-00250. Conduit Union in E0 Boundary.
11) ESR 97-00446, GE Radiation Detectors.
12) ESR 96-00503, Associated Circuit E0.
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13) ESR 96-00425. Evaluation of E0 sealants was initially closed by
the licensee but was reopened - closure date to be determined
(TBD).
14) ESR 97-00330 (old ESR 96-00501). Motor Control Center (MCC) E0 was
closed by the licensee, but was reopened - closure date TBD.
15) ESR 96-00426. Evaluation Quality class and E0 classification of
PASS valves was scheduled for completion June 6,1997. but closure
date is TBD.
16) ESR 97-00529. Failure of Unit 1 Drywell Motor, closure date TBD.
17) ESR 97-00523, High Pressure Coolant Injection (HPCI) Auxiliary 011
Pump Motor Unit 1, closure date TBD.
18) ESR 96-00587. PASS Valves, closure date TBD.
19) ESR 96-00627. ODP for Marathon 300 Terminal Blocks was scheduled
for completion December 31, 1997 but revised to August 1. 1997.
but closure date is ncw TBD.
20) ESR 97-00229. JC0 for GE Condition Report (CR) 151 B Terminal
Blocks was scheduled to be completed September 1. 1997 but
closure date is now TBD.
21) .ESR 97-00256. Main Steam Insulation Valve (MSIV) Hiller Actuator
JCO..was scheduled for completion September 2, 1997. but closure-
date is now TBD.
22). ESR 97-00343, Qualification of Kulka Model 600 Terminal Blocks was
scheduled for completion September 1. 1997, but closure date is
now TBD.
23) -ESR 97-00435. MCC Fittings, closure date TBD.
24) _ESR_97-00602, Soleno_id Valve Field Wiring, closure date TBD.
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In sumary, Unit 1 operated continuously during this report period until
a mid-cycle outage was started on November 5. 1997. Unit 2 completed- a
refueling outage and operated continuously once returned to service on
October 22, 1997 after a refueling outage. There are 12 outstanding
'JCOs in the E0 area for both units.
I. Operations
02 Operational Status of Facilities and Equipment
02.1 Torus Closecut Insoettion
a. Inspection Scoce (71707)
On September 29, 1997. the inspector inspected the Unit 2 torus in
preparation for torus closecut.
b. @servations and Findinas
The inspector toured the Unit 2 torus while it was dry and after
completion of work activities. The torus had been drained for
modification work to install new suction strainers for the core spray
(CS) system and residual heat removal (RHR) system. Each strainer
installation was inspected with emphasis on support clearances and
fastener attachments. No deficiencies were found.
The inspector also checked to see that all fcreign material had been
removed from the torus. The torus was completely dry and had been
recently vacuumed.- No foreign material was found. The torus was very
clean and no dust was present.
The inspector, with permission from the licensee, opened each torus to
drywell vacuum breaker and looked inside for any foreign material and
found none.
c. Conclusions
The torus was found very clean and absent of foreign material during an
inspection prior to final torus closecut.
02.2 Drywell Closecut Insoection
a. Inspection Scope (71707)
On October 12, 1997, the inspector inspected tne condition of Unit 2
drywell just prior to final closecut.
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b, Observations and Findinas
The inspector, along with the outage l manager, inspected all elevations
of the drywell. At the five foot ekvation the inspector looked inside
- each downcomer and found them free of any obstruction and foreign
material. The inspector observed that several pieces of grating were
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stored underneath the vessel and not tied down.
Each of the other elevations were generally clean with no foreign
material present. The inspector checked to see that junction boxes were
closed and sealed. Several safety relief valves were checked for proper
mechanical assembly and installation of-lock wires. No deficiencies
were noted.
Following the inspection the licensee determined that the loose grating
identified was properly secured. This was based on a review of the
acceleration valves and inertial forces. The storage requirements for
the grating were originally in Administrative' Instruction 0Al-105.
Under-vessel Ins)ection and Access Control, however, this procedure had
been deleted. T1e licensee issued a temporary revision to procedure
0Al-127. Primary Containment inspection and Closeout, to document this
inspection item.
c. Conclusions
During an inspection, the drywell was found to be free of foreign
material and ready for closeout.
02.3 Inadvertent Drainino of Water Into a Dry Torus
a. Insnection Scone (71707)
The inspector inspected the inadvertent draining of about 1000' gallons
of water into Unit 2 torus while in a dry condition. These occurred on
September 23 -1997, while work activities associated with the torus
suction strainer modification _we, a in progress.
b. Observations and Findinos
. While securing RHR from the shutdown cooling mode of operation in
accordance with plant procedures. water was introduced into the dry
torus:when the combined torus suction valve. 2-E11-F020A was opened.
This valve is normally opened providing the RHR pump suction path from
the torus except when closed for shutdown cooling operation. The
control room was notified that water was introduced into the torus and
the valve was closed. The licensee initiated CR 97-03292. Water in
Torus, to document this problem. The licensee conducted a Level 2 Root
Cause Review of the event.
The licensee's review determined that water trapped.between the combined
torus suction valve. 2-E11-F020A and the closed individual pump suction
valves. 2-E11-F004A and 2-E11-F004C. drained into the torus when the
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combined torus suction valve was opened. The torus master clearance.
2-97-555. used to isolate the torus used the indivi. dual pump suction
valves instead of-the combined torus suction valve because of planned
preventive maintenance on the valve. It was not recognized that the
time that the sequence of scheduling-activities would lead to'a
situation where water could be trapped between the valves.
No personnel safety problems or )ersonnel contamination events occurred
when water was introduced into tie torus. However, due to the fact that
-welding work was scheduled and being performed in the area. the
potential for a personnel safety risk was possible. Electrical power
cords welding supplies, and other tools were wetted. ,
Operating Instruction 001-01.09. Equipment Tagging, requires that
clearance activities be used to provide for the safety of personnel and
plant equipment during operation, maintenance, and modification
activities.
The licensee initiated clearance 2-97-01461 for valve 2-E11-F020A in the
closed position. Other corrective action included a review of other
potential areas where water could be introduced. The torus water was
drained. Any affected tools and equipment were replaced prior to work
re-start. This event was captured in the outage lessons-learned
database reviewed with clearance preparers and ) laced in operator
training. The licensee review of this event in t1e level 2 CR was
thorough,
TS 6.8.1 requires procedures for activities as equipment control covered
in Regulatory Guide (RG) 1.33. Plant Operating Instruction 00I-1.09.
Equipment Control, established requirement for equipment tagging to
protect personnel and plant equipment. This was the first example of a
violation against the plant clearance procedure. Clearance 2-97-00559,
was not adequate to protect )lant personnel and equipment. This
violation is identified as t1e first example of VIO 50-324/97-12-01.
Clearance Errors.
c. Conclusions
One example of a violaticn of the plant clearance procedure occurred
because the torus master clearance was not adequate to protect plant
- personnel and equipment.
-02.4 Unit l~ Reactor Feed Pumo (RFP) Linkaoe
a. Insoection Scone (71707)
The-ins)ector reviewed the Unit 1 transient that occurred on October 29,
1997, w1en_the IB RFP. control linkage failed.
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b. Observations and Findinos
While Unit I was operating at 92 3ercent power, a. reactor vessel low
water level alarm was received. )lant operators promptly observed low
flow on the 1B RFP. To avoid a unit trip, power was reduced to 55
percent power by manually reducing recirculation pump speed which
stabilized the transient. Later, the licensee determined that the IB
RFP speed control linkage became disconnected resulting in the speed of
the pump reducing to an idle condition. This was slower than a normal
feed pump trip and thus, no alarms were received to indicate a problem
with the pump.
A lock nut on the feed pum) linkage was found to have come loose. The
linkage was repaired and t1e feed pump returned to service.
c. Conclusions
Operator response to a plant transient resulting from a mechanical
problem on a RFP was good.
04 Operator Knowledge and Performance
04.1 Inadvertent Diesel Generator (DG) Start
a. Inspection Scone (71707)
The inspector reviewed the cause of the number 3 DG start on October 10.
1997
b. Observations and Findinas
Following maintenance on the E3 and E7 buses, power was being restored
to the E3 4160 volt bus when the number 3 DG automatically started.
Operators were performing Operating Procedure 00P-50.1. Energizing 4160v
Buses. Procedure step 5.3.5 required that the operator ensure the DG
was in the Auto mode on Panel XU-2. The operator thought the only way
to ensure completion of this step was to verify proper control
indication lights were illuminated. The operator closed the switch for
the DG control panel. This activated the control power circuitry and
.the DG automatically started as designed, because the circuitry sensed a
de-energized emergency bus. An error occurred in manipulation of the
control power switch, since the procedure sequenced the switch to be
closed last in step 5.3.13. The operators immediately secured the
running DG. The licensee initiated CR 97-03072 to document the problem.
The inspector went to the Control Room after the inadvertent start and
reviewed the procedure with the Shift Superintendent. The inspector
also reviewed clearance 2-97-01281 for de-energizing the E3 bus. The
inspector questioned how the error was made when performing the
procedure. The procedure ste)s to close the control power switch were
performed.out of sequence. T1e procedure step did not provide clear
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guidance as to how to verify the diesel was in automatic without control
power available for indications.
c. Conclusions
The inspector concluded that an inadvertent diesel generator start
occurred due to an operator error while performing the procedure to
restore the system lineup. This was because of a lack of understanding
of the procedure step required actions and the procedure step did not
provide clear guidance.
04.2 Reactor Feed Pumo Trio
a. Insoection Scope (71707).
The inspector reviewed the operator response to a RFP trip that occurred
on Unit 1.
b. Observations and Findinas
On October 24, 1997, the IB RFP tripped due to a loss of oil pressure.
Unit 1 power decreased from 100 percent to 50 percent power following
the pump trip. Several hours earlier the running feed pump oil pump
tripped due to an electrical short. The standby oil pump was designated
to emergency use due to a high vibration condition. The standby pump
ran for several hours but -subsequently failed. The loss of both oil
pumps resulted in the IB RFP trip.
The feed pump trip occurred at 6:33 a.m. The inspector entered the
control room around 6 45 a.m. as part of the normal daily routine and
observed stable plant conditions.
Reactor water level had decreased to a level of 173 inches. The scram
setpoint was at 166 inches. A recirculation pump runback occurred as
designed. The unit entered region 'B' of the thermal hydraulic
instability region. The operators inserted control rods to exit the
region.
Following the transition, the licensee determined that three control
rods were driven to position 'O' instead of the specification position
'12', The licensee initiated CR 97-03833. Control Rod Pattern, to
document'this problem. A reactor engineer verified no thermal limits
were exceeded. Due to the leaking fuel in Unit 1. the licensee provided
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direction to the operator for power changes in Standing Instruction (SI)97-053. This SI provided direction for a rapid power reduction use
procedure OENP-24.0 Reactor Engineering Guidelines. Form 2. This
procedure was not followed when three control rods were driven from
position '24' to position 'O' instead of the required position '12'.
As part of the licensee's corrective action, the reactor operator was
removed from duty pending a review of this event. SI 97-067 was issued
October 24, 1997, which provided direction to use procodure OGP-12.
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Power Changes, for immediate power reductions. This procedure requires
that a second licensed operator or other qualified member of the '
technical staff shall monitor control rod movement and shall document
correct selection and placement of control rods on the procedure
controlling rod movement.
The inspector reviewed SI 97-053. SI 07-067. OENP-24.0, and 0GP-12. The
inspector notad that 0ENP-24.0 was a " Reference Use" procedure intended
for the reactt,r engincer's use. 0GP-12 was a " Continuous Use" procedure
intended for the control room o)eratcr's use. The direction given by SI
97-053 to use OENP 24.0. gave t1e operator latitude for control rod
manipaletion outside the normal operations procedure. This was
considered a weakness in direction provided for reactivity manipulation
control.
1he operator's failure to follow arocedure for moving control rods was a
violation of plant procedures. T11s non-repetitive, licensee identified
and corrected violation is being treated as a Non-Cited Violation,
consistent with Section VII.B.1 of the NRC Enforcement Policy. This
Non-Cited Violation (NCV) was identified as NCV 50-325/97-12-02. Control
Rod-Movement Error,
c. Conclusinns
The inspector concluded that a weakness in direction provided for
reactivity manipulation control. An NCV occurred due to the failure to
follow procedure for control rod movement.
04.3 Unit 1 Recirculation Pumo Runbacks
a. Insoection Scone (71707)
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The inspector reviewed the circumstances surrounding the November 5-6,
1997, recirculation pump runbacks. These events were captured in CR 97-
3917.1B RFP induced transients,
b. Observations and Findinas
On November 5. 1997, the licensee began a controlled shutdown for the
Unit 1 forced outage in order to replace leaking fuel bundles. At
11:54 p.m.. while at 65 percent, the licensee started removing the IB
RFP from service. While securing the pump, unexpected level transients
were observed. As a result, the licensee ceased actions to secure the
IB RFP and restored the IB RFP. Attempts to secure the 1A RFP resulted
in larger than expected level changes, reactor water level dropped below
182 inches and due to feedwater flow on one pump being less than 20
percent, a recirculation pump runback on the IB recirculation pump to
the 45 percent limiter occurred. As efforts continued to secure the 1A
pump at 12:02 a.m. on November 6. 1997, level transients were
encountered for a third time and both the 1A and IB recirculation pumps
- received a runt'ack to the 45 percent limiter. During both runbacks
Abnormal Operating Procedure 1A0P-4.0. Low Core Flow was entered. The 5
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percent buffer region was entered and exited in accordance with
procedures. Subsequently, no other transients or runbacks were-
encountered while removing the RFPs from service.
The licensee has preliminarily attributed the first runback to a
malfunction of the IB discharge check valve causing diversion of the IA-
RFP flow through the IB discharge valve to the main condenser. Pending
licensee completion of. the event investigation and further NRC review
this item is unresolved. This unresolved item is identified as URI
50-325/97-12-03, Recirculation Pump Runbacks.
In addition, a previous weakness in training and 3rocedural guidance for
removal of an RFP from service was discussed in NRC IR 97-02.
c. Conclusion
During removal of RFPs from service as aart of a planned shutdown, two
recirculation pump runbacks occurred. Pending further licensee
investigation and NRC review this item is unresolved.
04.4 Diesel Generator low Voltaae Auto Start Defeat 0d
a. Insnection Scone (71707)
The inspector reviewed the low voltage auto start feature being defeated
on the number 4 DG.
b Observations and Findinos
The ins)ector reviewed the operator logs dated October 11. 1997, and
found tie following. At approximately 6:15 a.m., clearance 2-97-01038
was processed on the 4.16KV bus 2C. This war. a planned maintenance
activity on the 2C bus. TS 3.8.1,1 was entered at this time as part cf
the planned maintenance activity. The logs stated that the TS action
statement required the offsite power sources be restored in 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />
.At 6:47 a.m. the number 4 DG was aligned to provide power to the E4 bus
as part of the same planned maintenance activity on the 2C bus. Use of
the number 4 DG to supply power to the E4 bus was necessary because the
2C bus is the normal power supply to the E4 bus. Without the number 4
DG supplying power the E4 bus would have been inoper6ble.
The inspector determined, by reviewing CR 97-03683. that the operators,
subsequent to establishing the required plant lineup to perform the
maintenance on the 2C bus, questioned why the number 4 DG was operating
in a control room manual status instead of automatic on the isolated E4
bus. This question arose because a similar maintenance activity on the
20 bus had established a-lineup with the-number 3 DG in automatic.
- After investigation, by the operators, into why the diesels were in
different lineups for the same kind of maintenance activity, it was
determined that the clearance for the 2C bus had defeated the low
voltage auto start for the number 4 DG.
-
- . ._ _ _ _ _ _ _ _ _ . _ _
_. _ _ _ _ _ _ . _ _ . _ _ -
1
1
10
The. logs stated that at 8:35 a.m. the number 4 DG was declared .
i
xinoperable. The inspector determined; following discussion with the- i
licensee. that this was done because it is required by TS 3,0.3 action l
'
statement. The action statement requires that when the 4.16KV emergency
bus undervoltage relay is inoperable. then the diesel which supplies
that emergency bus.-must be declared inoperable. The operator logged at j
this time. 8:35 a.m., that TS 3.0.3 was entered because two offsite
power sources to E4 and the number 4 DG were' inoperable, which placed
the unit outside a condition addressed in TS 3.8.1.1. ;
The inspector identified that the operators, to resolve the problem.
determined that the low voltage relay was disabled in a manner that i
could be prevented. The clearance was changed and the low voltage relay
was' restored at 9:45 a.m. The clearance originally chose terminal
points dt junctions before and after two parallel path relays. The ;
wires were restored at those locations and then removed at the other i
relay in the parallel path circuit. thus restoring the low voltage relay
and providing a sufficient clearance condition to perform the
maintenance on the 2C bus. The operator logs stated that the number 4
DG was declared operable at 9:45 a.m. and that TS 3.0.3 was exited.
Following a review of the clearance 2-97-1038, the inspector noted that
in the special instruction.section, page three of the document, a
caution statement directed toward operations stated that three wire
lifts were necessary to perform the clearance. The caution statement
s)ecified that one of the wire lifts would prevent the DG from starting
w1en the emergency bus was de-energized. However, since the licensee
did not complete their root cause investigation at the conclusion of
this inspection report period, this is an unresolved item. URI 50-325 '
(324)/97-12-04 Diesel Generator Low Voltage Auto Start Defeated.
pending review of the completed investigation.
c. Conclusions
During maintenance on an electrical bus a diesel generator automatic
start circuit was defeated as part of a clearance without Operations
recognition. This is an unresolved item pending further review.
07 Quality Asst.rance in Operations
07.1 Startuo Plant Nuclear Safety Review Meetina
a. . Ins 9ection Scoce (71707)
The inspector observed startup assessment activities conducted in
accordance with Plant Programs OPLP-29. Self-Assessment for Readiness to
Startup Following an Outage.
b. Observations and Findinas
20n October 11. 1997. the ins)ector observed the Startup Plant Nuclear
Safety Committee (PNSC) for Jnit 2. The readiness of each organization
, . - - - --
11
to support restart activities was discussed by the PNSC and affirmed by
the appropriate supervisor. The affirmations observed by the inspector
were performed in accordance with Attachment 3 of OPLP-29. Areas
, addressed during the meeting included adequecy of stiffing and
housekeeping, completion of regulatory compliance items, and outstanding
engineering service requests. Any activities not ready for restart
where flagged as exceptions and a duration for resolution was discussed.
The meeting generated eight action items for completion. These items
-did not -include the OPLP-29 exception.
The inspector determined that the meeting was comprehensive and adequate
to assess restart readiness.
c. Conclusions
The restart affirmation conducted by the PNSC was determined to be
thorough and effective in the evaluation of the overall site
organization's readiness to restart Unit 2.
07.2 Outane Plannina
a. Insoection Scone (71707)
The inspector reviewed the control of Unit 2 outage activities.
b. Observations and Findinas
The planned work activities for the Unit 2 refueling outage were
completed without dif ficulty. This included completion of a major plant
modification as discussed in section E2.1. The planned 35 day outage
was completed in approximately 32-33 days. Com]letion of the outage was
delayed several days because of problems with t1e recirculation pump
motor oil cooler and shaft seals.
Contributing to this success was the 11censee's detailed and thorough
planning for the outage. Numerous milestones were reviewed prior to the
start of the outage. Lessons learned from previous outages were
formally incorporated into the outage planning. Once the outage
started, outages meetings were conducted twice a day with shift outages
managers. The licensee used a unified outage log to integrate all
important log entries into one document.
c. Conclusions
Outage planning and control continues to be a strength.
08 Hiscellaneous Operations Issues
08.1 (Onen) Violation VIO 50-325(324)/97-02-07: Failure to Initiate CR for
HPCI Valve Time Discrepancy
. __
12
This l item was inadvertently closed in 50 325(324)/97-09 and, remains
open pending completion of licensee corrective actions and further NRC
review.
11. Maintenance
M1 Conduct of Haintenance
Ml.1 Maintenance Proaram
a. Insoection Scone (62707)
The inspector reviewed / observed portions of the maintenance related work
and reviewed the associated documentation control rod drive (CRD)
rebuilding.
b. Observations and Findinos
The inspector observed that these activities were performed by personnel
who were experienced and knowledgeable of their assigned tasks.
Procedures were present at the work location and were being followed.
The procedure for rebuilding the control rod drives provided sufficient
detail and guidance for the intended activities. Activities were
properly authorized und coordinated with operations. Test and
maintenance equipment in use was calibrated, procedure prerequisites
were met, and replacement components were obtained through an acceptable
vendor.
The maintenance supervisor in ch_ of these safety related jobs was
observed frequently at the job lota , .. and aroviding good oversight of
work activities. Good control of area house (eeping was maintained
during the work. The inspector noted that when the old, replaced
components were removed from the CRD. they were immediately placed in a
shielded container to reduce the radiation level in the work area.
The rebuilt CRDs were stored in a container for installation in Unit 1
at a later date. Therefore the rebuilt CRDs were not leak tested at
this time. The licensee's plan is to leak test the drives shortly
before installation. The work activity was well controlled and
coordinated,
c. Conclusions
The inspector concluded that the maintenance activities were performed
satisfactorily. The inspector noted good controls of housekeeping and
good supervisor oversight of work activities.
. - .. - - -
1
13
M1.2 Control Rod Drive Scram Time Surveillance Testina (Unit 2)
al Insoection Scooe (61726)
The ins)ector observed the perforniance of Periodic Test PT-14.2.1. ,
Single Rod Scram Insertion Time 7esting,
b. Observations and Findinas
On October 23. 1997, the ins)ector observed the licensee perform
PT-14.2.1. The purpose of t11s test was to measure control rod scram
-insertion times on a single rod basis, following the Unit 2 Refueling
-Outage. Several TS requirements are verified by completion of the
surveillance.
The test evolution required personnel to perform portions of the testing
at three different locations. Auxiliary 0.perators were stationed at the
Hydraulic Control Units (HCU) in the Reactor Building, a Licensed
-Operator was stationed at the Reactor Protection System (RPS) scram test
panel, and the Reactor Operator was in the Control Room. The inspector
observed the conduct of the test from all three locations, observing
multiple control rods being tested at each location.
The inspector observed the Aux 111ary Operators in the Reactor Building
first. The Auxiliary Operators were dressed in full protective
clothing. in a contaminated area, while performing the surveillance.
-They were given direction by the Reactor Operator via hand held
communications. As the Auxiliary Operators received the next control
rod number to be tested they used good self checking practices to ensure
the correct HCU was located. The Auxiliary Operators were required to
operate the Charging Valve on each HCU and ensure proper nitrogen
accumulator pressures upon valve mani)ulction. Satisfactory
communications were used throughout t1e observed portion of the testing
evolution. Satisfactory independent verification was conducted for each
charging valve operation, also the verification check sheet was
initialed after each manipulation.
The inspector observed two operators at the RPS scram test panel. At
this panel the test switch is manipulated to cause individual scramming
of the control rods. The Reactor Operator directed the I.icensed-
Operator at the test panel, via the sound powered phone system, when to
, manipulate the test switch and when and where to move the test leads.
Satisfactory communications were used throughout the observed portion of
the evolution. Satisfactory continuous dual verification was performed
by both individuals at the RPS test Janel during the )ortion of the
testing' observed. -Adequate use of tle verification cleck sheet was
- observed as the inspector noted that. contrary to the Auxiliary Operator
and the Reactor Operator, they were using a check mark'on the check
sheet vice double verification initials. The inspector observed testing
in the Control Room and noted satisfactory procedural compliance and
communications between the Senior Control Operator, the Reactor
Operator, and the Reactor. Engineer and, as stated previously, between
. .
. . .- . - - . ._- .
14
'the remote stations. The inspector noted when the test was complete
that. individuals performing activities-in the remote locations initialed
the master verification check sheet in the Control Room.
-
,
c. -Conclusiong
The conduct of testing during the PT-14.2.1 Single Rod Scram insertion
Time testing was satisfactory, no discrepancies were noted oy the
inspector.
M1.3 Main Stack Radiation Monitor Surveillance Testina - Unit 1 ,
a. JnspectionScone(61726)
The ins]ector observed the performance of Maintenance Surveillance Test
IMST-RGE31R. Main Stack Radiation Monitor High Radiation Isolation
Response Time,
b. Observations and Findinas
On November 5, 1997, the inspector observed the licensee perform IMST-
RGE31R. The )urpose of this test was to determine the response times of
the Main Stact High Radiation Function of the Primary Containment
Isolaticn System (PCIS) for group six valves that are primary
containment purge and vent valves on Unit 1. Perforrance of this test
was in conformance with requirements specified in-TS 4.3.2.3 and UFSAR
Table-7,3.1-3A. item 1.g.
The inspector observed the pre-evolution brief which was conducted in
the Control Room. Al' the personnel necessary to conduct the test were
3 resent. The brief was conducted by a Control Operator. The use of a
]riefing check sheet resulted in a thorouqh brief by the Control
Operator who encouraged participation. The brief discussed actions for
expected and unexpected test results.
The test was performed with both Unit 1 and Unit 2 at 100 percent. The
Unit'2 Containment Atmospheric Control (CAC) Purge Vent Isolation System
was placed in override, per orocedure, to prevent isolation trips on
Unit 2. The test was performed by inserting a simulated Hi-H1 radiation
condition to the Main Stack Radiation Monitor system, which causes the
Reactor l Building Ventilation System to isolate, the Standby Gas
Treatnent System Trains' A and B to initiate, and PCIS group six valves
to-isolate.
The inspector noted that the proper TS Limiting Condition for Operations
(LCOs) were entered upon conmencement of the test. As the Hi-Hi
radiation signal was raised to the Hi-H1 setpoint, a graphic recorder
recorded five channel ctuations. The inspector observed that channel
five recorded no change of state. which would normally indicate that the
'
relay being. monitored did not actuate. However, upon investigation by
the technicians, it was determined that the test jacks, which were being
used.to monitor the signal, did not have wires hooked up to them. The
.
,e--e
. _ _ . _ _ . ___ ._ __
15
technicians notified operations of the problem. The test was secured
and the Unit 1 and Unit 2 systems were restored according to the
-procedure.-
The MST was considered by the licensee to be an invalid test. The PCIS
system was considered operable since the wires that were missing were
for test monitoring only and did not affect system operation.
Subsequent review by the licensee verified this evaluation to be
correct. CR 97-03919 was generated November 6, 1997.
Upon further investigation. the licensee found that the wires had been
removed in an effort to divide Division I and Division II logic
circuitry. The last time this response time testing had been performed
was August 25, 1995. The licensee identifjed a discrepancy in the
wiring diagram that was used to perform the test. The Main Stack
Radiation Monitor test procedure was a new procedure which became
effective October 17, 1997. This procedure was written referencing
drawing F-97083. The drawing showed that the test panel points 3B1-
11/12 were active. This drawing, entitled Unit No. 1 Division II
Terminal Cabinet XU-56 front Side - JXI Interconnection Wiring Diagram,
was revised October 5, 1994. The licensee identified another drawing.
LL-90046 entitled Unit 1 CAC System Outboard LOCA Signal Trip Control
Wiring and Cable Diagram, that showed terminals 3B1-11/12 as spares.
This drawing was revised October 20, 1994. The licensee generated CR-
97-3919 to document the problem, with a recommended action to determine
the cause of the wiring revision error and correct the drawing
discrepancy.
Procedure IMST-RGE31R has been revised to perfora the test using test
points on the relay via the test aanel. The inspector determined that
the change was performed via the 3runswick temporary revision procedure.
c. Conclusions
The inspector concluded that the licensee took appropriate actions to
secure the surveillance test when a discrepancy was identified, and they
took the appropriate actions to correct the procedures and drawings.
,
H2 Maintenance-and Material Condition of Facilities and Equipment
H2.1 2B Recirculation Pumn Errors
a. Insoection Scone (62707)
The inspector reviewed the circumstances surrounding the discovery of
water from the Reactor Building Closed Cooling Water (RBCCW) Sy; tem in
the 2B recirculation. pump motor lower oil reservoir and the clearance- ,
errors during the repair which resulted in damage to the recirculation
-pump seals. The repair of the motor cooler and recirculation sm) seals
resulted in a delay of startup activities for approximately a weet. The
recirculation pump seals serve as a pressure boundary between the
reactor coolant and the drywell atmosphere.
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,
-16
.
b. Observations and Findincs
t
On October 2.- 1997. Unit 2 was in Mode 5 when the licensee identified
that the 2B recirculation Jump motor had indications of an oil leak at
the coupling of the lower RBCCW cooling water piping to the-laver oil
reservoir. Work request / job order (WR/J0) 97-AGJS1 for the-repair of
the oil leak was planned and issued. On October 4. connections on the
. cooling water piping for the Jump motor were tightened. No additional
oil leakage was identified. iowever, during startup activities on
October:15. the licensee received the Recirculation Pump Motor B Lower
Bearing High Level annunciator. :
Motor 011 Cooler Problem Timeline
Octohar 2 4:24 p.m. Mode 5 - Refuel . WR/JO 97-
AGJS1 initiated for observed
recirculation notor reservoir ,
oil leakage
1
October 3 5:19 p.m. Clearance 2 97-1531 initiated
for repair of oil leak
-October 4 5:00 p.m. Maintenance completes work and
closes WR/JO 97-AGJS1
OctcLer 7- Clearance 2-97-1531 retracted
and ticket deleted
October 15 12:56 p.m. Mode Switch to Run
6:43 p.m. Mode 1 - 13.5 percent power
8:43 p.m. High oil level annunciator for
the B recirculation pump lower
bearing
October 16 12:59 p.m. Mode 3 - Hot Shutdown:
Inserted a manual scram to
repair the motor oil reservoir
cooler leak
,
The licensee determined that the 2B recirculation pump motor still was
- leaking fluid. The identification of excessive water in the lower oil
reservoir.was recorded in CR 97 3783. Recirc. 011/ Water Cooler Leak.
Another WR/JO was initiated and samples taken to identify the source of
the water. Chemistry sample results revealed RBCCW water in the oil.
.The licensee indicated in CR 97-3782. Improper Response to SIL 484. that
vendor guidance regarding damage to the oil cooler reservoir of a motor
due to torquing.had not been properly dispositioned. The operating
experience review had indicated that no motors for either unit contained
internal cooling coils mounted in the oil reservoir. However, both
units had this cooling configuration. As a result. the vendor
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17
recommendations were not integrateo into the cautions on the work
ticket. The cause of the RBCCW leak was not definitively identified.
hawever the licensee indicated that maintenance activities in or around
the damaged line could have contributed to the RBCCW leak.
-
Motor Oil Cooler RBCCW Leak
October 16 2:16 p.m. Clearance 2-97 1622 written to
drain oil-in the pump.
4i45 p.m. Clearance implementation error
for 2-97-1623 incorrect
breaker racked out- 2B bus
versus 2B recirculation motor
(CR 97-3765)
5:00 p.m. Increasing temperature seen on
recirculation pump seals (CR
97-3766)
11:32 p.m. Repair during hot shutdown
unsuccessful initiated
clearance 2-97-1623 to repair *
motor oil cooler leak and
replace damaged recirculation
seals
While isolating the 28 pump. two clearance errors were made. During
initial hanging of clearance 2-97-1623. the operator racked out the 4160
volt feed from the Unit Auxiliary Transformer (UAT) which isolated the
entire 2B bus instead of just racking out the 2B recirculation drive -
motor breaker. No injuries resulted and no required components were
damaged. The failure to implement the clearance in accordance with 001-
1.09 is a violation. This violation is identified as the second example
of VIO 50-324/97-12-01. Clearance Errors. After completing the correct
alignment to isolate the 2B recirculation pump, temperature was seen to
increase on the #1 seal. The licensee restored the system to the pre-
clearance alignment and reestablished seal injection. CR 97-3766.
Recirc. Seal Temp increase. Ws initiated to record the increased
temperature problem. = Tem)erature recorded for the seal exceeded the
graphical bounds of the clart recorder of 300 degrees Fahrenheit.
Inspector review of the vendor manual revealed that the seals were rated
for 200 degrees Fahrenheit. Subsequently, the licensee had to replace
both seals during'the motor cooler replacement.
The inspector reviewed the associated clearances, work tickets,
procedures, and CRs. Discussions with the licensee revealed substantial
damage to the #1 seal and a minor crack or the #2 seal as a result of
the temperature excursion. The licensee indicated that the #1 seal
would not have been capable of holding pressure had the pump been
returned to service. lhe inspector determined that the clearance
preparer did not consider the effects of attempting the repair for the
,
__ _ _ _ . _ _ . _ _ .
18
cooler while in hot shutdown. The failure to maintain the status and
integrity of important plant components and systems in accordance with
001-1.09 was a violation. This violation was identified as the third
example of V10 50-324/97-12 01. Clearance' Errors. The inspector
concluded that this errer constituted a lack of sensitivity by the '
clearance preparer and reviewer to activities affecting the pressure
boundary.
Preliminary review of the motor cooler RBCCW 1eak attributes the failure
to possibly maintenance activities on or around the cooler ai)ing.
During-inspector review of the failure mode determination ( M)) for CR ,
97-3766, errors in clearance development and review resulted in seal
degradation where classified in accordance with the corrective act:on
program as a level 3 or of minor significance, while the positioning of
the wrong breaker and the RBCCW motor cooler leak was assigned a
-level 2. important. Plant Program Procedure OPLP-4. Corrective Action
Management. describes the type of investigation to be 3erformed.
Level 1 and 2 CRs require a root cause determination w11ch is a
comprehensive review in accordance with Plant Program Procedure OPLP-
4.3' Foot Cause Investigations. Tha FMD reviewed identified the errors,
but not the root cause for the inadequate reviews. The inspector
discussed with the licensee the. lack of a comprehensive review of the
multiple human 3erformance errors associated with this event. The
licensee has su)sequently included the clearance errors in the root
cause review of CR 97-3765. Incorrect Breaker Racked Out. Discussion
with licensee management determined that a comprehensive review was
planned and the multiple CRs were rolled into one level two CR.
c. Conclusions
The failure to pro)erly develop and implement a clearance for the
isolation of the 23 recirculation pump motor which resulted in racking
out the incorrect breaker and the replacement of the pump seals due to
damage from excessive temperatures was identified as two examples of a
clearance violation. Prior licensee review of operating experience for
torquing motor oil cooler was' erroneous.
M2.2 Observation of Unit 2 In-Vessel Visual Insoections (TVVI)
a. InsnectionScoce(73751).
The inspector reviewed video taped visual examinations of the CS thermal
sleeve to shroud weld, the thermal sleeve to CS pipe weld and the CS
lower )iping downcomer elbow weld on loop "A" @ 10 degrees azimuth and
,
loop "3" @ 350 degrees azimuth. The weld Nos associated with these
examinations were Weld Nos. 1.-2 & 3 on loop "A" and Weld Nos. 21. 20
and 19 on loop "B". The welds were examined in accordance with NRC
Bulletin 80-13 and the industry's-BWRVIP standards. The inspector also -
reviewed video data for the visual examinations of the "F" Recirculation
System Jet Pump-Riser elbow welds and the pup piece to thermal sleeve
weld. The jet pump riser piping welds were examined as recommended by
the vendor in Service Information Letter (SIL) No. 605 Revision 1. To
_ _. , .
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1
l
19
~ determine the effectiveness of the enhanced visual examinations. the
' inspector evaluated camera resolution quality. examination surface i
detail; and contrast of visual indications.
b. Observations and Findinas
The enhanced visual examinations of the CS piping and thermal sleeves
were performed utilizing GE's underwater color comera. The ins)ection
sensivity was based on clear resolution of a 0.5 Mil wire. T1e
inspector determined that the camera work for these examinations was
excellent, cleaning of the examination surface was very good and
examination surface contrast, detail, and resolution was also excellent.
The inspector concluded that crack like indications on the outside
diameter (00) surface of the CS piping would be identified by the visual
examinations observed.
The inspector also selected the jet pump riser welds to examine. The
observed visual examinations of the jet pump elbow to riser, elbow to
pup piece, and pup piece to thermal sleeve (including draw beads) were
aerformed to the same examination sensitivity as the CS piaing above.
iowever, most of the jet pump welds were examined using a ) lack and
white camera because its smaller size allowed it access to the t@ter
clearances around the jet pumps. Surface contrast and resolution was
not as good as those provided by the color camera, but the same test
sensitivity was achieved and the welds were adequately examined,
c. Conclusions
In-vessel visual inspections were conducted by skillful technicians.
Examination surfaces were brush cleaned, examination sensitivity was a
0.5 Mil wire and surface contrast resolution was excellent es)ecially
with the vendor color camera. Crack like indications on the 0D surface
of the )iping would be identified by the visual examinations observed.
No cracts were identified during the examinations reviewed by the
inspector.
M2.3 Connarison of 1996 and 1997 Unit 2 Core Shroud Ultrasonic Data for
Select Welds
a. Insoection Scone (73753)
The inspector reviewed analysts' resolution sheets and spread sheet
presentations of ultrasonic (UT) data comparison for defect growth for
core shroud welds. This review was performed to determine the rate of
defect growth on selected welds.
b. Observations and Findinas
The inspector selected two core shroud welds to compare defect growth:
(1) Weld H-4 because it was in the high fluence area of the reactor core
shroud and would be expected to see the highest crack growth rate; and
(2) Weld H68 because it had the largest amount of crack recorded on any
,
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_ . . _ _ _ _ _ . _ . _ . - _ . - , _ . _ _ _ _ _
,
i
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- 20 ~ j
~
unrepaired: Unit 2 shroud weld. Review of the~H4 shroud weld data f
< revealed very little change in crack 1 length or death. The change
. . recorded was:found-within-the 0.108" UT-depth tec1nique error band. .-
.;
y
Subsecuent to the inspection. the inspector reviewed the comparison ;
--
spreac sheets-for_ H6B. which revealed that the crack depth ~was actually ;
measured much less.during the-1997 examinations than during the 1996 :
-
examinations. -The licensee stated that the Electric' Power Research:
Institute (EPRI) Nondestructive Examination (NDE) Center reviewed the- -!
analysis processes for the 1997 crack d4ths while onsite, as discussed- -l
in NRC IR 50-325(324)/97-11. and concurred with the analysis process. ;
The licensee was sending the-1996 raw UT data to the EPRI NDE Center-for-
their' review.. The' intent was for EPRI to review the actual analysis
process. procedures, tooling hysterisis, tooling start >ositions-. scan ;
'
patterns.. etc. to hel) the licensee better understand tie effects. if-
- any. these-items-may lave had on the differences in the 1996 and 1997 *
crack depths. 4
c. Conclusions ,
Examination results from the 1996 and 1997 cor. shroud inspections '
.
-revealed very little crack growth for Weld H4. .
conflicting-information. crack depth was actually?id aeasuredH6B muchhowever.
less gave
during the 1997-examinations than during the 1996 examinations.. The
' licensee requested EPRI's help in determining the reason for these
examination differences. ,
M6 Maintenance Organization and Administration
n
M6.1- knprino and Test Eauioment
,
a. Insoettion Scone (62707)
The inspector reviewed installed CS instrumentation data to verify
calibration activities were properly performed in accordance with TS '
requirements. Calibration of in-plant test ecuipment was reviewed as
well as standards located in the measuring anc test equipment- (M&TE)
facility.
b. Observations and Findinas
1The-inspector performed a verification of proper channel calibration
activities for CS trip functions -la - c as recorded in TS Table 3.3.3-2.
Emergency Core Cooling System Actuation Instrumentation Setpoints. The
, " inspector:reviewedi
,e' ~ Maintenance Surveillance Test OMST :RHR210. RHR-LPCI. CSS and HPCI -
6 -High Drywell Pressure Trip Unit Channel Calibration
~
e- Maintenance Surveillance Test.1(2)MST-RHR220. RHR-LPCI ADS CS LL3.
HPCI RCIC LL2 01 vision I Trip Unit Channel Calibration
_
L
6-
k _- _ -- l_ --
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21
. Maintenance Surveillance Test 1(2)MST RHR260. RHR CS Low Reactor
Pressure Permissive Trip Unit Channel Calibratica
All instruments were found to be within the prescribed calibration
frequency. Proceducal acceptance criteria and frequency were found to
be within TS allowances.
Throughout the inspection period the inspector reviewed labeling and
prescribed calibration frequency for test equipment located within the
M&TE facility end the plant. With one exception, the test equipment
reviewed was properly labeled in accordance with Maintenance Management
Manual 0MMM 006. Control of Measuring cnd Test Equipment and no
equipment was found beycnd the calioration due date. The inspector
during inspection activities within the M&TE facility identified a
temperature component of a shop standard which was beyond the
calibration due date. The inspector reviewed the last calibration for
all the test ecuipment calibrated by the standard. All equipment
calibration hac been performed prior to the calibration due date. No
discrepancies or concerns were identified.
c. Conclusions
Maintenance measuring and test equiament located within the plant was
found properly labeled and within t1e current calibration interval.
Review of several surveillance tests determined that the acceptance
criteria and frequency were within TS allowances.
M8 Hiscellaneous Maintenance Issues (92902)
M8.1 (Onen) Licensee Event Reoort 97-008-00: Main Stack Radiation Monitor
Surveillance Interval Exceeded.
Licensee Event Report (LER) 97-008-00. dated August 19. 1997, re)orted
that on August 19. 1997, the licensee identified that an UFSAR clange.
implemented on February 12,186. inappropriately eliminated the
requirement to perform Main Stack Radiation Monitor res)onse time
testing. Consequently, the Unit 1 and Unit 2 Main Stacc Radiatioc.
Monitor surveillance tests were not performed prior to the required
dates of July 12. 1997, and August 15. 1996. respectively. On
August 19, 1997, the licensee declared the Main Stack Radiation Monitor
inoperable and actions per TSs were implemented for both units. Test
procedures were developed by August 23, 1997, and performed to satisfy
the surveillance requirements of portions of the logic which had not
been performed within the required surveillance interval. Upon
satisfactory completion, the Main Stack Radiation Monitor was declared
operable. The licensee attributed the cause of this event to inadequate
review and basis verification related to the UFSAR change that
eliminated the response time testing requirement. This LER remains open
pending completion of a corrective action item to assess the UFSAR
change review process.
22
III. Enaineerina
El Conduct of Engineering
El.1 Environmental Qualification (37550. 929031
a. Insoection Scoce
The inspectors reviewed the licensee's corrective actions for the
Environmental Qualification (EO) program, in response to findings
identified during Self-Assessment numbers 95-0041 and 96-0271 and
the violations identified in NRC Inspection Report number 50-
325(324)/96-14.
b. Observations and Findinas
1) Review of Modifications to Drywell Terminal Boxes to Resolve
E0 Moisture Issues
The inspectors, accompanied by licensee E0 engineers,
performed walkdown inspections in the Unit 2 drywell and
examined modifications to electrical terminal boxes to
address moisture intrusion issues identified in CR number
97-02408. The modificationa, which were completed under ESR
97-00519, it.volved drilling of weepholes in the terminal
boxes to preclude the possibility of excessive moisture from
accumulating in the boxes during various accident scenarios.
The inspectors examined the electrical terminal boxes for
the following penetrations and verified the weep holes had
been drilled per the design requirements specifled in the
ESR: penetration numbers 102C 102H. 105D. 105G. and 105J.
The inspectors also examined the conduits located at
radiation monitors and verifier that they had been sealed as
s]ecified in the ESR to prevent intrusion of moisture from
t1e drywell spray headers. Conduits at the following
monitors were examined: 2-D22-RM-4195, 2-D22-RM-4196. 2-D22-
RM-4197 & 2-022-RM-4198.
Additional modifications are required to terminal boxes in
the Units 1 & 2 Reactor Buildings and the Uait I drywell to
resolve this issue. The scope of work for the modifications
required in the reactor buildings to close CR 97-02408 has
not yet been established. Additional comments on the
licensee's corrective actions program to resolve CR 97-02408
and other CRs is discussed in the paragraphs below. The
work in the Unit 1 drywell will be completed during the
Spring 1998 refueling outage.
_ - _ _ __- _ _. _ _ _ . _ . .
23 ,
2) Review of Environmental Qualification Condition Reports
The inspectors reviewed a random sample of CRs initiated by
the licensee to document and disposition nonconforming items
which were identified during the ongoing-E0 reconstitution
project. The nonconforming items were identified as a
result of E0 equipmcnt walkdowns. rev1ew and updating of EQ
ODPs, omissions from the original program, or changes to the
-
operating environment. The inspectors also reviewed the
status of corrective actions to resolve the nonconforming -
conditions. The CRs reviewed, the date the CR was
-identified, and the title / description are listed in the
-
Table below.
lAELE
E0 CONDITION REPORTS
CR Number Date CR Title /Descriotion
Initiated
96-03641 11/3/96 Exceeding qualified life of
ASCO pressure switches.
97-00189 1/9/97 Lack of documentation for
qualification of MSIV pilot
valve components.
97-01841 5/23/97 Affect of fire protection
system initiated by HELB on E0
equipment.
97-02015 6/6/97 Operator training concerns
relative to HELB.
97-02016 6/6/97 Painting of NAMCO limit
switches.
97-02017 6/6/97 Control wires for transmitter
below flood levels.
97-02025 6/6/97 Leakage through stranded wire
condtG ors / seals.
97-02074 6/11/97 Unknown qualified life of some
NAMCO limit switches.
97-02094' 6/12/97 Failure to document open items
in EQ references.
97-02103 6/13/97 Failure to identify E0
documents affected by ESRs.
. - . _
_ _ . . . _ _ _ _ . ~ . _- _ _ _ _ . _ _ .._ _ _ _ _ _ _ _ _
24
- CR Number Date CR -Title /Descriotion-
Ront'd)
97 02193 6/20/97 Use of incorrect wiring on
Valcor solenoid valves.
97 02257 6/27/97 Review of Level 2 CR action
items.
97-02333 7/2/97 Failure to perform safety
reviewsforchangestoEDdata
in the equipment data base.
'
97 02408 7/9/97 Effects of moisture intrusion
in electrical boxes.
- 97 02428 7/10/97 Qualification of radiai. ion
detectors.
97 02465 7/15/97 Questions regarding
operability determinations for
EQ related CRs.
CP&L Procedure PLP-04, Corrective Action Management.
implements the requirements of 10 CFR 50, Ap>endix 8.
Criterion XVI. Procedure PLP 04 specifies tie requirements
for identifying, evaluating, and correcting deficiencies,
,
'
defective equipment, programs, procedures, and other
nonconforming conditions. When a CR is identified, an
invest.igation is performed to determine the cause and
corrective actions are specified to resolve the problem.
The corrective actions are identified as Action items which-
are assigned to a work grou) with a due date. The Action
items (Als) are controlled )y CP&L Procedure PLP-4.1. Site
Action item Management. The CR is closed when all the
assigned Als for the CR are completed.
During review of the status of the corrective actions to
resolva the above listed CRs. the inspectors determined that
18 Als associated with 11 CRs had not been completed by the
assigned due dates. These included the following Al
,, numbers: Al 2 for CR 96 03941 which was due on 9/1/97: Al 6
for CR 97 00189 which was due on 9/2/97: Al 3 & 5 for CR 97-
01841-which were due on 9/8 & 9/24/97, respectively: Al 2.
3 & 4 for CR 97 02017 which were due on 9/30/97: Al 2 for
CR 97-02074 which was due on 9/1/97: Al-2 for CR 97-02103
which was due on 9/30/97: Al 1 & 2 for CR 97-02193 which
were due on 9/22 & 9/15/97, respectively: Al 2. 3. & 4 for
CR 97-02257 which were due on 9/22, 9/22, & 9/15,
respectively AI 4 for CR 97-02333 which was due on
9/12/97: Al 1 &-2 for CR 97 02408 which were due on 8/15 &
9/26/97, respectively; and Al 2 for CR 97-02428 which was
.
- . - -
7
25
due on 8/22/97. The due dates for many of these Als had
already been extended two or more times. -S)ecific examples
are Al 2 for CR 06 03641. Al 6 for CR 97 0139. Al 3 & 5 for
CR 97 01841. Al 2 for CR 97 02074. Al 1 & 2 for CR 97 02193,
and Al 2 for CR 97-02408.
On October 8. 1997 the licensee completed a detailed review
of the E0 related CRs and determined that approximately 100
Als related to 25 CRs were nyerdue from 8 to 53 days. The
licensee also determined that Als related to 18 E0 CRs (nine
from 1996 and nine from 1997) had been extended two or more
times. The Action items related to one 1996 CR had been
extended seven times.
Paragraph 4.2.7 of CP&L Procedure PLP-04. Corrective Action
Management, requires managers / superintendents to ensure that
assigned corrective actions required to resolve CRs are
implemented. Paragraph 5.4 of PLP-04 states that corrective
dctions for CRs shall be tracked per CP&L Procedure PLP-
04.1. Site Action item Management. Paragraph 4.2 of PLP-
04.1 requires supervisors and superintendents to ensure
assigned Al responses adequately addresses the item and are
completed by the due assigned date, if an extension of the
due date is recuired the extension is required to be
justifiable anc documented on the Action item Assignment
form in accordance with Procedure PLP-04.1. The failve of
licensee managers to ensure corrective actions were
implemented as required by Procedure PLP 04, and the failure
to complete the Als in accordance with the schedules
established by Procedure PLP-04.1 is identified as Violation
examples one and twe of V10 325(324)/97-12-05. Failure to
implement Corrective Actions in Accordance with Corrective
Action Program Requirements. Additional revi w will be
performed by NRC to followup on the corrective actions for
the above listed CRs.
3) Review of Justifintions for Continued Operation
The inspectors reviewed the licensee's procedures which
control determination of ecuipment operabit 'v when
deficiencies are identifiec in the environm6 mal
qualification program. Guidance issued by NRC in this area
and the licensee s program (procedures) which implements NRC
guidance are summarized below.
On April 7,1988, the NRC issued Generic Letter (GL) 88 07.
Subject: Modified Enforcement Policy Relating to 10 CFR
50.49. Environmental Qualification:of Electrical Equipment
Important to Safety. The GL provided guidance to licensees
regarding actions to be taken when potential deficiencies
are identified in the environmental qualification of-
. equipment. The guidance specifies that the licensee is
. . . . . - - . . .- . - - _ - - - - . - ~ . - . . - -. -..--.-
b
U
26
9
expected to make a prom)t determination of operability, take
immediate steps to esta)lish a plan with a reasonable
schedule to correct the deficiency. and have written a JCO.
On November 7, 1991, NRC issued GL 91 18. Subject: ,
Information to Licensees Regarding Two NRC Inspection Manual :
Sections on Resolution of Degraded and Nonconforming
Conditions and Operability. GL 91-18 provided licensees
with the written guidance used by the NRC staff regarding
resolution of degraded and nonconforming conditions and
performance of operability determinations, j
The licensee has-implemented the GL 88-07 guidance for
determination of operability (operability evaluations),
corrective actions, and preparation of JC0s in the following
CP&L Procedures: PLP-04. Corrective Action Management: EGR- i
NGGC 0005, Engineering Service Requests; and EGR NGGC-0156.
Environmental Qualification of Electrical Equipmen+ '
Important to Safety.
CP&L ]rocedure PLP 04, which implements the requirements of
10 CFl 50 Appendix B, Criterion XVI. specifies the
requirements for identifying, evaluating and correcting
deficiencies, defective equipment, or nonconformances.
Procedure EGR NGGC 0156 provides instructions for ,
establishing maintaining, and implementing the requirements
of 10 CFR 50.49 Environmental Qualification of Electric
Equipment Important to Safety for Nuclear Power Plants.
Section 9.3.2 of Procedure EGR-NGGC 0156, provides
instructions for performing E0 operability determinations
and ) reparation of JCOs. Paragraph 9.3.2.3 of procedure
EGR-4GGC 0156 requires preparation of an ESR to document
operability determinations and JCOs. Procedure EGR-NGGC-
0005 specifies recuirements for performance of engineering
work. This procecure implements the requirements of 10 CFR
50, Appendix B, and licensee commitments pertaining to
engineering activities. Paragraph 9.3.7 and Attachment 4 to
Procedure EGR-NGGC-0005, which provide instructions for
performance of engineering evaluations in support of system
operability, require preparation of ESRs to document
operability.
The inspectors reviewed the status of the 23 previously
identified JCOs which were initiated to address potential
. equipment operability issues. Nine of the JCOs were closed, ;
two were comoleted except for closecut of documentation, <
while the remaining 12 were still open pending completion of -
corrective actions. The inspectors noted that the ESR for
the o)erability determination of solenoid valves due to
possi)le incorrect ty]e of field wiring on the valves
(documented in CR 97-)2193 on June 20, 1997) had not been
approved (completed) until October 11, 1997 for Unit 2 and
October 21,.1997 for Unit 1.
,
, , . - m.,_ - _
_ , _ . . , . . _ . ._
.,,,..__.<,,.,,..n_ , --v..,--- .
.-.y,... .., ,
- - - - . . - - - . - - - . - - - -
4
27
The inspectors performed an additional review the CRs listed
above to determine if potential Equipment operability issues
were ,vidressed with a JC0 per the requirements of licensee
procedures. The following~ problems were identified:
- CR 96 03641 - This CR addressed a discrepancy in the
qualified service life of 88 tripoint pressure switches
manufacturer by the Automatic Switch Company (ASCO). The
manufacturer's original test reports, which were based on a
service temperature of 104 degrees Fahrenheit. indicated
that these switches had a ten year service life, lhis
service life was documented in ODP 77. ASCO Tri-point
Pressure Switches. The ODP was based upon data from DR
77.1. ASCO Test Re
ASCO Test Report # port #Revision
A0R-51785. A0R-10183. 0. TheRevision 1. and DR 77.2,
switches had
been installed in-1985 in Unit I and .986 in Unit 2. In
'
the early 1990's a licensee engineer rt 1culated to service
life to be 36.67 years by using an incoi ect value for the
activation energy in the Arrhenius equation. CR 96 03641
was initiated on November 3. 1996, when this error was
discovered. Per licensee records, based on the original
manufacturer's test report the service life for the Unit I
switches expired on October 2. 1995, while the service life
of the Unit 2 switches expired on April 24, 1996.
Discussions with licensee engineers disclosed that a preliminary
operability review had been performed in November,1996 when this
problem had been initially identified. The review consisted of a
prc'iminary calculation which was based on some actual historical
reactor building temperature data. The preliminary calculation
showed the service life of the ASCO switches was approximately 14
years. However the calculation had not been properly documented.
checked, reviewed, or approved. Also, the licensee failed to 1
prepare a JC0/ESR. During the current inspection the licensee was
in the process of preparing ESR 9700483, to document the revised
service life of the switches. The inspectors reviewed a draft of
the ESR and noted that the only environmental factor reviewed by
the ESR was the service temperature of the switches. Other
environmental factors such as switch wear. radiation, or frequency
of switch operation were not considered in the ESR. The liccnsee
informed the inspectors that they had determined that operating
temperature was the controlling design parameter. However this
had not been documented in the ESR. The inspectors noted that the
Al which addressed the completion of the ESR had been extended
twice and was overdue when the ins)ectors reviewed the draft co)y
of the ESR. 'The current due date lad been Se)tember 1. 1997. io
JC0 (ESR) had been prepared to document opera)1lity of the
pressure switches.
ESR 97 00483 was completed and approved on October 11. 1997.
The inspectors reviewed the completed ESR. The licensee,
based on a review of ODP-77 concluded that thermal aging was
l
,
_ . _ . _ __ _ ___ . . _ _ _ . _ _ _ _ . _ _ _
26
the limiting factor in the life of the switchet.. The
qualified life calculation in the ESR which was based on
actual operating temperature data showed the switches have a
qualified life of 14 years. The Unit I switches will
require replacement in 1999, and the Unit 2 switches will
require replacement in the year 2000
CR 97-02017 - This CR. initiated on June 6, 1997, addressed
t1e possible installation of an environmental seal for a
Rosemount transmitter below the flood (water) level during
some accident conditions OiELB) in the Unit i reactor
building north core spray room. Further review of the
problem disclosed that the seal would not be affected by
water but the wiring for the transmitters, which is covered
with a Kapton insulation, was not qualified for submergence,
The transmitter in question is installed in the core spray
system pump and is covered under RG 1.97. The supervisor's
comments on the CR stated that the transmitter is required
for LOCA but not HELB. when the conduit seal may be
submerged. Review of UFSAR Cha)ter 15 disclosed that the CS
system is required during a HEL 3. Therefore the comment on ;
the CR.-which apparently was a basis for not requiring an i
operability determination, was incorrect. No JC0/ESR had !
been prepared to document operability of the Rosemount
transmitter. The Action item for this issue had been
extended once. The new due date had been September 30.
1997.
The licensee determined that only one transmitter had been !
installed with the wiring and seal in an orientation to be l
affected by submergence. The inspectors performed walkdowns in
the north and south RHR room, north and south CS rooms..and HPCI
rooms in both Units 1 & 2 and verified that no other transmitter .
had been installed in locations where the lead wires or !
transmitters would be subjected to submergence. During the
inspection. the licensee was in the process of pre)aring an ESR to l
evaluate the existing installed configuration of tie '
transmitter / wiring. The licensee determined, based on data
'
provided by the manufacturer, that the lead wiring from the
transmitters were covered with a Raychem type protective jacket .
which was qualified for submergence. The inspector examined the l
installed transmitter and lead wires and verified that a Raychem l
Jacket had been 1.nstalled over the Kapton insulation to provide i
for resistance to moisture penetration.
CR 97-01841. 97-02025. & 97-02403 These CRs documented
various issues regarding possible effects of moisture on E0
equipment. The inspectors reviewed ESR 97-00391 which
documents an operability review of the problem (effect of
spray from the fire protection system on E0 equipment)
documented in CR 97 01841. This ESR was not issued until
July 22, 1997. 60 days after the CR was initiated. However. ;
,- ,. _ _ _ __ __ - . _ - . _ _ _ _ . _ . _ . _ _ _ - _ _
29
some other operability issues such as effect of deteriorated
junction box gaskets on E0 equipment were not evaluated in
the ESR, The inspectors concluded that no JC0/ESR had been
prepare to evaluate operability of this issue. The )roblem
documented in CR 97 02025 concerned a problem which 1ad been
a subject of IE Circular 79 05. Moisture Leakage in Stranded
Wire Conductors, which was issued by NRC on March 20, 1979.
The current concern at Brunswick involved primarily the effect .of
moisture intrusion through stranded wire conductors which could
result in leakage currents in instiument circuits. Patel seals
were used to seal some stranded wire conductors in instrument
circuits. A recommended action stated in the CR was to prepare a
JCO. However none was prepared. CR 97-02408 documents numerous
potential moisture intrusion issues. The i mediate corrective
action taken to resolve these issues, as documented in the CR was
to hire an outside consultant to address the issues. A
recommended action listed in the CR was to prepare a JCO. However
none was prepared. The consultant has reviewed many of the issues
documented ir '9 97-01841. 97-02025. and 97 02408 and made
recommendav% W of which have been implemented. The
consultant u TW,1y addressing the current leakage issues and
possible impact ou OOPS and E0 of equipment in ESR 9700440 for the
120 AC volt circuits and ESR 9700441 for DC volt circuits. The
current leakage issue is also anlicable to cuestions raised
regarding the NAMC0 limit switches, discussec below.
CR 97-07016 & 97 02074 - These CRS documented issucs
involving NAMCO limit switches for which the environmental
qualification was indeterminate due to inability to identify
the date of manufacture and a possible issue regarding
leakage currents due to moisture. Although the CRs were
identified as potential operability concerns, no JC0/ESR was
prepared. The licensee subsequently determined that the
switches were still within their qualified life. The
current leakage issue is presently being evaluated.
The above examples of failure to prepare JCOs and document
equipment operability on ESR when environmental
qualification was indeterminate is identified as violation
V10 50-325(324)/97-12 06. Failure to Prepare ESRs/JCOs to
Evaluate Equipment Operability Problems.
4) Qualification / Operability of Post Accident Sampling System
Valves
The inspectors reviewed the status of the operability of the-
R. G. Laurence valves in the post-accident sampling system
'(PASS). Two issues were identified which affected
environmental qualification of these valves and the
associated limit switches. The first issue, which was
. discussed in NRC Inspection Report number 50-325(324)/96-14
_ _ _ _
.
I
30
involved the EQ of the valves. The second issue involved EQ
-of PASS limit switch wiring. The JC0 for this issue was
documented in ESR 97 00289. This JC0 was closed when the
limit switch wires were replaced.
'
Operability of the PASS valves was originally addressed in
ESR 9600426. However this ESR (JCO) has been suaerseded by
ESR 9600587. The inspectors reviewed ESR 96 00537. Evaluate
Re)lacement Coils for R. G. Laurence Solenoid Valves. This
ES1 provided the evaluation that replaced non mtallic
components in the valves with components which were
environmentally qualified. The non metallic components
included the following: a body / bonnet 0 ring seal, a rotary
shaft 0-ring seal, ard the solenoid coil. The licensee
performed testing of the replacement components and verified
that the replacement materials met the requirements for the
service environment (temperature, radiation, humidity). The
18 PASS valves were then rebuilt under WR/J0s using new
materials / parts to replace all non metallic comaonents. The
inspectors randomly selected the WR/J0s listed selow and
reviewed the completed maintenance records (WR/J0s) which
documented the rebuilding of the valves. Records reviewed
were as follows: WR/JO 96 AHFZ1 for valve 1-Ell-F079A.
WR/JO 96 NIGA1 & 2 for valve 1 E11-F079B. WR/JO 96-AIFR1 for
valve 2 RXS-S64180.- and WR/JO 96-AIFS1 for valve 2 RXS SV-
4181. The inspectors concluded that the valves were
operable in their present configuration.
The licensee is in the process of updating ESR 96-00587 to
clarify documentation regarding environmental qualification
of the valves. A ODP is being prepared which will provide
the basis for documentation of the environmental
qualification of the PASS valves. This is part of the
licensee's corrective actions to resolve the violations
identified in NRC Inspection Report 50 325(324)/96-14.
c. Conclusions
Two violations were identified. The licensee's progress in
addressing the previously identified deficiencies in the EQ
program has required extensive NRC review. The violations
- 1dentified are indicative of a lack of progress and failure to
address the previously identified issue regarding inadequate
corrective actions. The licensee has also failed to document
operability of equipment for which environmental qualification is
indeterminate.
-
' '
n . . .. . . .. .. . . . , . . . . _ _ _ _ , . _ __ _ _ _ _ _ _ _ _ _ _ _ _ _ _
31
El.2 Ilown Inspectiot, for USI A-46 Unit 1 Modifications. Seismic
ification of {ouinment (92903)
a. Inspection Scope
The inspectors inspected modifications to various components in the
Unit 1 Control Building, Reactor Building, and drywell implemented to
resolve deficiencies identified during the US! A 46 walkdowns.
b. Observations and Findinns
The inspectors randomly selected the components listed below for
insSection and verified the modifications were implemented in accordance
wit 1 design requirements specified in ESR 96 00597. Seismic
Qualification - Unit 2 Outage Issues - SOUG. Revisions 0 through 14.
The following modifications were examined:
Location * ESR Pane Ogitr_ int _lon
CB-49 12,12A Connection of 2 EHC-XY-644 to 2-XU-
50.
CB 49 13, 14 Connection of 2-XU-62 to 2-XU 60.
CB 49 20. 21 Connection of 2-H12-P624 to 2 CAC.
TY-4426-1.
CB 49 22, 23 Connections of 2-XU 77 to 2 XU 65 &
-79: 2-XU-66 to 2 XV 65 & -67: and
2-XV 68 to 2-XU-67.
CB-23 32, 33 Connection of 2 2A UPS to concrete
column.
CB 23 34 38 Battery chargers.
CB 49 - 60. 61 HVAC interaction with XU 29.
RB 20 125 135 Seismic Interaction Resolution
2-2-H21 P003
RB-50 94 Add missing bolt to 2-Cl2-CV-
F010
RB 50 95, 96 Add new support. 2Cl2-CV-F010
RB-20 145, 146 Reroute ground cable. 2
IR RB+4
- Note: Location designated CB 23 refers to control building
elevation 23, CB-49 refers to Control Building elevation 49: RB 20
refers to Reactor Building elevation 20: and RB-50 refers to
Reactor Building elevation 50.
The inspectbrs also examined the two A 46 modifications
implemented in the Unit 2 drywell. These modifications included
relocation and-repair to an HVAC duct under WR/JO 97-ACBR2 and
correction of an interaction between a conduit and valve under
WR/JO 97-ACBR3.
32
The following attributes were examined by the ins)ectors during
the walkdowns: bolt s Res. thread engagement mem)er sizes.
installation tolerances, and location / orientation of
modifications. and where applicable, use of proper type hardware
to implement the modifications. No deficiencies were identified
by the inspectors,
c. Conclusions
The inspectors concluded that the modifications for USl A 46 were
adequately implemented in accordance with design requirements.
s
E2 Engineering Support of Facilities and Equipment
E2.1 Emeraency Core Coolina System Suction Strainer Pro.iect
a. Insnection Scone (37551)
The inspector reviewed the project activities associated with the
installation of new RHR and CS system strainers,
b. Observations and Findinas
The inspector noted excellent planning and decision makina associated
with the ECCS suction strainer project. The decision to drain the torus
early in the project decreased the complexity of the task. Underwater
installation and welding were avoided. The development of a rigging
plan using a full scale mock-up to perform a dry run of moving the
strainers along the heavy load path inside the reactor building led to
ease of installation.
The licensee used an engineering services company for design and
procurement of the strainers. A third party review of the engineering
work was performed. The review concluded that the strainers had been
correctly design in accordance with NRC requirements.
The inspector observed the installation of the strainers in the torus as
c discussed in Section 02.1. The task was accomplished according to the
outage schedule. The total job was performed only using 1? man rem.
The inspector reviewed the project implementation plan. This plan was
very detailed and thorough. It contained pre outage milestones,
schedules, project organization. ALARA plan, assessment of risks. and
many other topic discussions. This thorough implementation plan
resulted in a large modification being completed without difficulty,
c. Conclusions
The inspector concluded that excellent planning and decision making led
to the successful com)letion of a major plant modification. This was a
signification strengt1 in project management.
. . _- -. - - - .. - . - . _-.- - - -.-. -
I
f
33~
E2.2 peak Drywell Temneratures l
a. Insnection Scone (37551)
The inspectors reviewed the events surrounding the declaration of ;
several snubbers inoperable in Unit 1 drywell inoperable as a result of ;
high drywell temperatures. .
i
b. Observations ,
,
The inspector reviewed a time line of events leading up to declaring the.
snubbers inoperable. The time line was as follows:
IjE fJrD1 -
June 6, 1996 NRC IR 96-05 documented high drywell
temperatures above the UFSAR limit of 200
degrees Fahrenheit. This was part of URI 96 05- :
02. Discreaancies, to document NRC special
review of JFSAR problems. The licensee issued
CR 96-1388. ,
December 19, 1996 ESR 96 397 issued to address CR 96-1388
concerning exceeding UFSAR drywell temperatures
which determines new drywell temperature limits
for Unit 1 of 221.7 degrees Fahrenheit and Unit
2 of 240 degrees Fahrenheit.
'
June 4. 1997 Drywell Cooling Fan 10-1 tripped.
Note: Unit 1 drywell tem)eratures were running
above 200 degrees Fahrenleit as documented by
Operations routinely red circling an out-of-
specification reading on the daily logs but were
below 221.7 degrees Fahrenheit per ESR 96 397
until the cooler tripped. Temperatures then
took a step jump to around 230 degrees '
Fahrenheit.
September 19, 1997 Licensee entered 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> LC0 for TS 3.7.5 for i
snubbers due to temperatures as high as 249-
degrees Fahrenheit in the upper elevations of
the drywell.
September 21, 1997 Licensee declared that seven out of ten snubbers-
on the reactor head vent line were inoperable
due to exceeding their. seal life due to elevated
-temperatures in the drywell. Licensee prepared
ESR 97-532 to document that the pipe was-
qualified even with the inoperable snubbers left 1
in place.
.
4 --. we, s , , ,+ .. . . . . , , , . , , . , . , . _ _ _ r. , ,%, ,,_,....-,.g . . . - . , - , --,.M .m -,--,-.,mu .
- - .- . . - _ - _ - - - - - - . -. -
t
34
NRC 1R 50 325(324)/96 05 documented the observation that tem)eratures on i
the upper elevations of the Unit 2 drywell had exceeded the JFSAR peak !
drywell tem)erature of 200 degrees Fahrenheit. This observation was ;
identified )y the NRC as an URI 50 325(324)/96-05-02. FSAR
Discrepancies, and recorded by the licensee in CR 96-1388. Exceeding 200
degrees Fahrenheit temperature. Subsequently the licensee evaluated the
effect of the high temperatures on the qualified life of components
located in the u)per elevations in order to justify exceeding the limit
in the UFSAR. T11s evaluation was recorded in ESR 96-397. Evaluate
Change to the FSAR. ESR 96-397 redefined the maximum peak temperature '
and qualified life for snubbers located in both units. ESR 96 397
evaluated the ISI/ Snubber program using a predicted temperature profile
for the balance of the Unit 1 and 2 fuel cycles. The profiles predicted
a maximum temperature for Unit 1 of 221.7 degrees Fahrenheit and 240
degrees Fahrenheit for Unit 2. This action concluded that the increased
drywell temperature for Unit 2 had decreased the six year snubber seal
life by approximately two and a half years and determined that since the
Unit 1 calculated average temperature was below the previously evaluated
temperature, no seal 11fe adjustment was necessary.
Following the drywell cooler failure in June 1997. the inspector
discussed the drywell temperature problem with the Unit 1 operators and
pulled a plot of temperature from the plant computer to review the ;
temperature increase. Operations personnel indicated that engineering
was aware of the problem and that an existing analysis for Unit 2
allowed temperatures up to 240 degrees Fahrenheit. No further
information was received regarding this problem until the snubber
operability evaluation was referenced in the control logs on ,
September 19, 1997. The snubbers were declared inoperable on
September 21. 1997. An analysis determined the head vent line was still
operable without the snubbers.
c. f_inii.ngs
On September 19. 1997 CR 97-3214. Drywell Tem)erature Limitation, was
. written during an engineering evaluation of t1e qualified life for those
components on the upper elevations of Unit 1 for the next Unit 1 fuel
cycle. This evaluation revealed that the June 1997 failure of the 101
drywell cooler motor resulted in temperatures above those predicted in
ESR 96-397 and requested an operability assessment on those components
be conducted. The evaluation. ESR 97-532. Evaluate Snubber Removal for
Head Vent Piping, determined that the seal life for seven of 10 snubbers
located above tne 52 foot elevation could not be qualified until the
A)ril 1998 refueling outage. The evah.ation provided justification for
t1e removal of-these snubbers based on the completion of pipe support
and stress calculations SA-821-508-9700529,- revision 1A and PS-B21-508-
9700529. revision 3A.
- The inspector reviewed this issue and found that u)on the failure of the
101 drywell cooler in June 1997 no actions were tacen to evaluate the-
effect of the subsequent t?mperature rise on the seal life of those
snubbers in the upper elevations. It was determined that several
e
v+ - , .w + - . - - e- - , - , e w.<c-e.-,-syen.m,c, . . , ,e .>-m-riw ,w e , w v v ,*v -
m 1
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35
factors contributed to the licensee *s failure to promptly identify this
abnormal condition. The inspector reviewed temperature trending data
which indicated that the temperature in some areas for Unit I had
exceeded the UFSAR limit of 200 degrees Fahrenheit somewhere around
June 6. 1996. DuringJune1997,thetemperaturejum
-degrees Fahrenheit after the failure of the cooler. ped Thetoinspectors
around 230
noted that Operations had informed the system engineer of the condition,
but no follow up actions were identified to assure correction. There
was no action taken once the drywell temperatures were above the upper
limit bounded by ESR 96-397. Accordingly, this-is the first example of
an apparent violetion of 10 CFR 50 Appendix B. Criterion XVI. Corrective
Action. This will be tracked as eel 50-325(324)/97 12 07. Failure to
Take Corrective Action for High Drywell Temperatures and Torus Bypass,
d. Conclusions
The inspector-concluded that an a> parent corrective action violation
occurred because no action was tacen once the drywell temperatures
exceeded their limit bounded by an engineering analysis. This problem
occurred due to a known deficiency that was allowed to exist. The
deficiency was routinely red circled in operations daily logs 6s an
out-of-specification condition and above the UFSAR limit.
E2.3 Drywell to Torus Bvoass
a. Insnection Scone (37551)
The inspector reviewed the potential for the pressure suppression design
function of the primary containment to be bypassed in the event of a
Loss of Coolant Accident (LOCA) during the simultaneous
purging /inerting/deinerting of the torus and drywell. Operating
procedures for o)eration of the Containment Atmosqheric Control (CAC)
system and Stand)y Gas Treatment (SBGT) system. O. 24 and OP-10
respectively, as well as the piping drawings associated with the CAC and
SBGT systems were reviewed. The inspector reviewed LER 97-011-00 and
CR-97-02937 level 2 Root Cause Investigation.
b. .0bservations and Findinas
In April 1997 the licensee first responded to the )ressure suppression
containment bypass issue following an Operational Experience report
issued by Lasalle. The licensee concluded at that time that the valves
associated with purging /inerting/deinerting activities closed upon
receipt of a Group 6 isolation in the event of a LOCA, thus they
concluded that the bypass issue was not a concern. Again. in May 1997.
Operations provided Regulatory Affairs a similar response to a Dresden
.10 CFR 50.72 report. The licensee revisited this-issue in August 1997
after the NRC Resident Inspector questioned them about the issue and
-raised concerns about primary containment isolation valve timing
speci fications.
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' Based on industry related experience on this issue, the inspector
reviewed CAC and SBGT procedures and drawings to verify whether tre
necessary conditions existed during purging /inerting/deinerting
activities to establish a sup)ression pool bypass. Followino this
review it was determined by tle ins)ector that the procedures and plant
piping configuration allowed for a )ypass condition to exist. This
concern was discussed with Regulatory Affairs, including a concern ,
regarding primary containment isolation valve timing specifications. The '
concern with valve timing discussed that the UFSAR report describes the
pressure event. during a LOCA, as only taking a couple of seconds so
-that with a bypass condition established the containment isolation
valves would not close in time to allow for adequate pressure
suppression. However, primary containment isolation valves are allowed
by TS to close in 15 seconds. On September 4. 1997, the licensee issued ,
a Standing Instruction to prevent opening valves necessary to establish
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a by) ass path. CR 97 02937 recommended that administrative controls be
esta)11shed since an additional review had been conducted which
indicated that a suppression pool bypass path could be established. The '
CR described concerns with primary containment isolation valve timing
and that two of the CAC system valves had t6. same isolation division
logic signal (Division 1); so that a single failure of relay contacts
could result in.the bypass path remaining open since they would not
automatically close.
LER 50-325(324)/97 011 00. dated October 13.1997. with an event report .
date of September 12, 1997, determined that operating practices !
established a flow path where the primary containment pressure
suppression design function was being bypassed. The CAC system valve
lineup associated with purging /inerting/deinerting activities
established a direct path between the drywell and torus air spaces. The
procedures have allowed the simultaneous aerfcrmance of drywell and
torus purging /inerting/deinerting since t1e procedures were approved in
1974.
The LER additionally repnrted that the operation with the existence of a
bypass path was of concern for two reasons described previously: that
was the containment isolation valve timing issue and the single failure
of relay contacts in the isolation signal to the valves. Engineering !
reviewed both of these scenarios and concluded that during a small break
LOCA the bypass path was of sufficient size to result in exceeding the
drywell design pressure.
l
NRC 1R 50 325(324)/97-11 docume~ 'd that the PNSC held on Septembe u.
1997 recognized that they had m ied to properly evaluate indust:y
experience information and identify that the same issue existed at
Brunswick.
10 CFR 50 Criterie, XVI of Appendix' B. Corrective Actions, requires that l
measures shall be established to assure that conditions adverse to
cuality, such as failures, malfunctions, deficiencies, deviations,
cefective materials and equipment, and nonconformances are promptly
identified and corrected. !
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Measures were not taken promptly to identify and correct a condition
that was adverse to quality. The licensee missed two opportunities to
identify the condition. The third time this issue was considered by the
licensee was when the NRC Resident I; .ctor questioned them on the ,
matter. This issue was identified as the second example of an apparent
violation EEI 50 325(324)/97-12-07, failure to Take Corrective Action ,
for High Orywell Temperatures and Torus Bypass.
c. Conclusions I
Brunswick conducted activities, since original procedural ap3rovals in
1974, which could have potentially established a condition tlat could
have exceeded the containment design in the event of a LOCA. They had
two missed opportunities to recognize the problem and take prompt
action. The third opportunity was initiated by the Resident Inspector,
and only after questions from the inspector did the licensee recognize
that the problem existed. Once the licensee recognized the problem,
corrective action was taken to correct the problem via a procedural
,
change. This issue was identified as the second example of an apparent '
violation for failure to take corrective action.
E3 Engineering Procedures and Documentation
!
E3.1 B1C11 POWERPLEX Minimum Critical Power Ratios (MCPR) Limit Errors
a. Inspection Scone (37551)
The inspector reviewed the activities surrounding the discovery by the
licensee that errors existed in the Unit 1 Cycle 11 POWERPLEX HCPR
database. This event was described in CR 97 3331. BlC11 PPX MCPR Limits
Error.
b. Observations and Findin g
The minimum critical power ratios (MCPR) is a TS safety limit
'
established to avoid fuel damage due to severe overheating c' the
cladding. TS 3/4.2,2.2, Minimum Critical Power Ratio (Option B).
verifies that the control rod scram distribution assumed in the Option B
' analysis was consistent with actual control rod scram times. If
different. the TS allows adjustment of the limit. The erroneous data
section identified in CR 97-3331 was never used to determine the MCPR
due to the scram times never matching the erroneous data set. CR 97-
3331 indicated that this was the second time an error had been
identified in the POWERPLEX data. The licensee determined that the
database error was in the conservative direction, therefore no safety
limit would have been exceeded.
The inspector reviewed the root cause and failure mode determination for
CR 97-3331 and CR 97-1502. In the CRs. both events attributed the
errors to inattention to detail by both the data initiator and the
reviewer." CR 97-1502. BlC11 POWERPLEX Database Error, documented the
April 24, 1997 discovery of a typographical error in one of the 16 data
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sets used to determine the MCPR limit. After correction of the error.
the licensee performed a s)ot-check for consistency with the Core
0)erating Limits Report Every value was not specifically reviewed.
1le f ailure to assure that adecuate corrective actions taken to preclude
repetition of errors identifiec in the MCPR database is a violation.
This violation is identified as V10 50 325(324)/97 12 08. MCPR Database
Errors. The root cause also identified schedule pressure as a
contributing factor for the inadequate design review performed on the
data. The inspector determined, through review of associated procedures
and discussion with the licensee, that c minimum of four procedures
governed the review of the data. The licensee indicated that specific
guidance for the POWERPLEX data cycle creation update and verification
was contained in Nuclear fuels Management & Safety Analysis Section
Guideline NFG 14-23. POWERPLEX Data Bank Creation Standard Verification
Scope and NFG 14 29, POWERPLEX New Cycle update. Further discussion
revealed that these guidelines used, in addition to the rther design
verification procedures for verification of the data for deter 711ning TS
safety limits, were not controlled in accordance with the quality
assurance requirements as described in 10 CFR 50. Appendix B.
c. Conclusions
inadm uate design review during initial com)osition allowed errors to be
introcuced into the database which establisled the Option B minimum
critical power ratio limits. A violation was issued for the failure to
assure that corrective actions taken upon discovery of an error in the
MCPR database precluded repetition.
E3.2 Special UFSAR Revirm
A recent discovery of a licensee o)erating 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
parameters to the UFSAR descriptions. While performing the inspections
discussed in this re) ort, the inspectors reviewed the applicable
portions of the UFSAR that related to the areas inspected. The
inspectors verified that the UFSAR wording was consistent with the
observed plant practices, procedures, and/or parameters.
Review of UFSAR drywell temperature limits were reviewed. The licensee
was determined to be above the UFSAR limit and outside an existing
analysis as discussed in Section E2.2.
E7 Quality Assurance in Engineering Activities (37550)
E7.1 Licensee Assessments
a Insoection Stone
The inspectors reviewed assessments which were performed by the
Brunswick Nuclear Assessment Section of activities in the
Brunswick Env ineering Support Section (BESS).
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b. Observation and Findinas
lhe inspectors reviewed Assessment Report numbers B ES 97-01 and
B-ES 97-02 which document the results of assessments performed by
the Nuclear Assessment Section (NAS) to determine the
effectiveness of engineering activities performed at Brunswick,
Assessment number B-ES-97 01. which was performed between May 27
and June 6,1997. resulted in identification of two strengths,
four issues and three weaknesses, The strengths involved
improvements shown in the engineering continuing training program
and the fact that weekly program / system review meeting are
conducted. The four issues were as follows: 1) Failure to
document ESR reviews and design verifications: 2) Some engineering
supervisors were not knowledgeable or involved in the engineering
training program: 3) Engineering workload is not being etfectively
managed; and 4) Corrective actions for many NAS assessment
- m es/ weaknesses identified in BESS have not been fully
effective, The three weaknesses were as follows: 1) Engineering
management has not effectively established performance standards
and expectations with regard to processes and personnel: 2) Three
of the approved engineering training guides contain outdated
information: and 3) There was an inability to use ERFIS
downloaded information for performance monitoring.
One strength, three issues, and one weakness were identified
during Assessment number B-ES 97 02 which was performed on
September 8 through September 19, 1997. The strength recognized
that BESS initiatives related to inservice inspection testing have
resulted in significant dose and manpower savings. The issues
were as follows: 1) Some EQ ESRs were prepared by individuals who
'had not completed training: 2) An A/E firm providing engineering
services to BESS were unable to provide records which documented
training of their engineering personnel: and 3) A continuing
problem with lack of atter ion to detail in preparation of ESRs
which resulted in administrative errors / omissions in the ESRs,
The weakness identified that modification ESRs were not
consistently screened in accordance with CP&L procedures.
The licensee issued CRs to document the issues and weaknesses
identified in the assessments. The ins)ectors reviewed CR 97-
03305 which was initiated to document tle ESRs 97-00238 and 97-
00343 were prepared by individuals who had not completed the
required training, The inspectors noted that the licensee
previously identified the similar occurrences of unqualified
individuals-completing ERS or ESR reviews in CR 96 03693.
Initiated on November 12, 1996, and CR 97-01436 which was
initiated on April 20, 1997. CR 97 01905 identified a similar
issue where an unqualified engineer in the EQ group was signing
field verification data sheets, The inspectors concluded that the
licensee's corrective actions have been ineffective in resolving
the issue of engineering managers assigning work activities to
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individuals who were not qualified under the licensee's training
program. This was identified to the licensee as example four
violation VIO 50 325(324)/97-12 05, for failure to implement the
corrective action program.
c. Conclusions
The NAS assessments were adequate in evaluating the licensee's
onsite engineering program. However the results of the
assessments showed that the licensee's corrective actions in
response to previously identified assessment findings have been
ineffective. An additional violation was identified regarding
failure to implement the corrective action pr" ram.
E8 Hiscellaneous Engineering Issues (92903)
E8.1 (Closed) Unresolved item 50-325(324)/97 08 08: Control of
Moisture in Installation of E0 Components.
During the review of the E0 equipment deta sheets during the inspection
documented in NRC Inspection Report number 50-225(324)/97 38. the
inspectors determined that deficiencies in installation of E0 equipment
documented in the data sheets had not been addressed by licensee E0
engineers when the data sheets were reviewed. CP&L Procedure PLP 04
Corrective Action Management, requ. es managers and personnel to
initiate CRs when they become aware of adverse conditions or conditions
which do not meet expectations. The failure of managers and personnel
to initiate CRs to document the E0 equipment installation deficiencies
when they became aware of these conditions not meeting expectations was
identified to the licensee as another example of Violation item 50-325
(324)/97-12-05. Failure to implement Corrective Actions in Accordance
with Corrective Action Program.
The licensee had initiated three CRs to address the effects of moisture
and moisture intrusion issues on E0 components. These were CR rambers
97-01841. 97-02025. and 97 02408. The licensee had also identified
other CR to address specific moisture issues, for example 9/-02017. or
issued WR/JO to address repairs to specific equipment. However, these
were not issued for several weeks af ter the field walkdown inspections
were completed and the data sheets had been reviewed and signed by the
E0 engineers. As discussed above, the inspectors performed a detailed
review of the licensee's corrective ar' ions required to resolve these
issues. An additional violation example was identified for failure to
document operability reviews and is identified as example three of
VIO 50-325(324)/97-12 04, for failure to implement corrective actions.
E8.2 10nen) Licensee Event R oort (LER) 50-325(324)/97-04: Spent Fuel
Shipping Cask Handling Activities
On April 11. 1996, the NRC issued NRC Bulletin 96-02 Movement of Heavy
toads Over Spent Fuel. Over fuel in the Reactor Core, or Over Safety-
Related Equipment. This bulletin described another utility's inadequate
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evaluation of the movement of a spent fuel shipping cask over safety-
related equi) ment. The utility was )lanning to perform this activity
under a 10 CrR 50.59 evaluation. wit 1 the determination that no
unreviewed safety questions (US0) existed. However this bulletin
described a subsecuent NRC review which determined that a US0 was
involved because cropping of a spent fuel cask would have created an
accident of a different type than any evaluated previously and could
have also resulted in the increase in the potential consequences
evaluated in the UFSAR. The bulletin requested the submission of
information concerning the movement of heavy loads. The licensee
responded to the bulletin on May 10. 1996. This LER recorded that a
plant specific review of an identified deficiency at another facility
revealed that the Brunswick heavy load analysis as described in the
UFSAR did not completely bound movement of the shipping cask from the
primary non single failure proof lif t to the secondary lift with the
valve box covers removed. This condition was not previously analyzed
and therefore constituted a US0. In accordance with 10 CFR 50.59 a US0
requires prior NRC approval before implementation. The failure to
identify a condition outside of the design basis during the 10 CFR 50.59
screening for the cask transfer is a violation. This ap)arent violation
is identified as EEI 50 325(324)/97 12 09. US0 on Spent ruel Cask
Movement.
In a letter dated. August 6. 1997, the licensee submitted a license
amendment request for a US0. The letter contends that further
evaluation determined that a drop of the fuel cask during transfer from
the tilting cradle to the secondary yoke is not a credible event.
However, the licensee contended that the use of a single lifting device
during the transfer still re) resented an event not previously reviewed
by the NRC. Pending review )y the NRC of the licensee amendment request
this item will remain open.
E8.3 (Closed) Violation V10 50-325(324)/97-02-06: ESR Design Verification
Requirements
This item is closed based on the review documented in IR 50-325(324)/
97-09. Section E8.3.
IV. Plant Suo. pact
R1 Radiological Protection and Chemistry Controls
Rl.1 Radiation Control Practices Durina Unit 2 Outace
a. Insnection Scone (71750)
The inspector observed drywell, torus, and refuel activities during
routine plant tours,
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b. Observations and Findinos !
During the Unit 2 refueling outage. the inspector observed improved
supervisory oversight of radiation control practices. Supervisory !
oversight presence was visible and noticeable each time an inspector was I
ct one of the work locations.
!
Drywell and torus work activities were well planned and coordinated.
The licensee used briefing rooms with detailed ma)s to review dose rates 1
and contamination levels prior to entrance into t1ese areas. Remote ,
reading dosimetry was used for areas as the drywell dose rates were
high. This allowed remote tracking of exposure from someone not
involved in the work activities.
4
c. Conclusions
improved suaer visory oversight of radiation cc :rol practices was noted
during the Jnit 2 refueling outage.
R8 Hiscellaneous RP&C Issues
R8.1 (Closed) Violation VIO 50-325(324)/96-15 09: Improper Implementation of
-ARM Response Procedure
During inspection activities documented in IR 50-325(324)/96 15. a 1
violation was issued for the improper 1mplementation of the area
radiation monitor (ARM) radiation res)onse test. Inspector review of
Environmental & Radiation Control OE&RC-0358. Area Radiation Monitors
Radiation Response Monthly Test determined that the ARM setpoints were
inaccurate and abnormal readings were not being appropriately
dispositioned.
The inspector reviewed the August 13 and September 10,19'.J.
performances of the revised E&RC procedure. With the exception of an
abnormal reading in the Radiochemistry Lab during the August 13
performance, abnormal readings were dispositioned by notifying
Operations of the readings and initiation of work tickets or performance
of surveys to log the change in the ARM vicinity. Based on the
completion of the procedure revision and verification of proper
,
implementation, this item is closed.
S4 Security and Safeguards Staff Knowledge and Performance
S4.1 Protected Area Access Control
a. Insnection Scnne (71750) 1
The inspector observed protected area (PA) access measures including
equipment or pat-down searches for illegal contraband and reviewed
actions taken to address an operating experience report concerning an
observed weakness at another utility in granting authorized PA access.
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.b. Observations and Findinas
On October 3 and again on October 7. 1997, the inspector observed two-
individuals between the waist high turnstiles and the PA turnstiles. The
Access Control Person (ACP) as well as nearby Members of the Security
Force appeared to be monitoring other activities and did not lock down
the turnstile or remove the second individual from the area.
The inspector reviewed the Security Olan as well as various security
procedures including Security Instruction 051-09. Personnel A" cess
Authorization, Control, and identification. The procedure out' ted the
responsibilities of the ACP, The ACP was tasked with preventing entry
of unauthorized personnel into the PA by locking the turnstiles, As a
result of similar PA access issues at-another facility the NRC issued
information in a letter dated February 20, 1997, about potential
weaknesses in PA access control. As a result of this information the
licensee implemented long term corrective actions for potential software
problems and the licensee stated that another concern was corrected by
the conduct of training. The inspector reviewed training records
conducted in November 1996 and noted that the actions tak.en regarding
the ACP ensuring proper identification, assessment and response were not
covered in any training activities or a w .nistrative instruction
reviewed. The inspector noted that no additional training was conducted
to address security response to this issue, despite a different physical
layout, when the new access facility was placed in service in
July 1997. In addition no procedural guidance was identified that
outlinad the means to determine whether a threat existed; if present,
the extent of the threat: and those actions to be taken to neutralize
the threat. This lack of procedural guidance has allowed for diverse
methods of implerentation, in the events observed above the inspector
determined that the response for one instance, gesturing or using an
inaudible intercom, was ineffective in notifying those individuals
involved that their activities were in conflict with plant security
requirements, in addition, the inspector determined that the ACPs on
both occasions failed to lock down the PA access or remove the second
individual from the area to ensure the correct individual was being
granted access when faced with a situation that may have allowed an
unauthorized person access to the PA.
The failure to provide adequate procedural guidance for those actions
required for the ACP to control the final access function into the
protected area to prevent unauthorized access is a violation.
Specifically. no guidar ce existed for controlling a condition observed
by the inspector on October 3 and again on October 7, 1997 wherein the
ACP failed to lock down the Protected Area turnstiles or remove the-
second individual from the area during a condition which could have
allowed an unauthorized individual to gain access into the PA. This-
violation is identified as VIO 50-325(324)/97-12-10. Protected Area
Personnel Access Control Deficiency.
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c. Conclusions
Corrective actions for a generic event identified at another facility
were found to be incomplete. Due to an inadequate procedure, security
personnel failed to secure PA access on two occasions which could have
resulted in the entrance of an unauthorized individual into the
Protecte, trea. These failures were identified as a violation.
V. Manaaement Meetinoi
X1 Exit Meetino Summary
The inspector presented the inspection results to members of liceisee
management at the conclusion of the insDection on November 13, 1997.
Post inspection briefings were conducted on October 2 and 31, 1997. The j
. licensee acknowledged the findings presented. !
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PARTIAL LIST OF PERSONS CONTACTED
Licensee
A. Brittain. Manager Security
M. Christinziano, Manager Environmental and Radiation Control
W. Dorman. Supervisor Licensing and Raulatory Programs
N. Gannon. Manager Maintenance
J. Gawron. Manager Nuclear Assessment Section
S. Hinnant. Vice President. Brunswick Steam Electric Plant
K. Jury Manager Regulatory Affairs
B. Lindgren. Manager Site Support Services
J. Lyash. Plant General Manager
G. Hiller Manager Brunswick Engineering Support Section
R. Mullis. Manager Operations
Other licensee employees or contractors included office, operation,
maintenance, chemistry, radiation, and corporate personnel.
E
E. Brown
J. Coley
G. Guthrie
F. Jape
J. Lenahan
C. Patterson
M. Shymlock
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INSPECTION PROCEDURES USED
IP 37550: Engineering- l
IP 37551: Onsite Engineering
IP 61726: Surveillance Observations
IP 62707: Maintenance Observations
IP 71707: Plant Operations i
IP 71750: Plant Support Activities
IP 73753: Inservice Inspection !
IP 92901: Followup Plant Operations i
IP 92902: Followup - Maintenance
IP 92903: Followup Engineering
ITEMS OPENED, CLOSED, AND DISCUSSED ,
1
Doened l
50 324/97-12 01 VIO Clearcnce Errors (paragraphs 02.3 and M2.1 )
50 325/97 12-02 NCV Control Rod Movement Error (paragraph 04.2)
50 325/97-12-03 URI Recirculation Pump Runbacks (paragraph 04.3)
50 325(324)/97-12-04 URI Diesel Generator low Voltage Auto Start Defeated
(paragraph 04.4)
50-325(324)/97-12-05 V10 Failure to implement Corrective Actions in
Accordance with Corrective Action Program
(paragraph El.l.b.2) )
50 325(3241/97-12-06 V10 Failure to Prepare ESR/JC0 to Document Equipment
Operability Problems (paragraph El.l.b.3)
50-325(324)/97-12-07 eel Failure to Take Corrective Action (High Drywell
Temperature and Torus Bypass) (paragraphs E2.2
and E2.3)
50 325(324)/97-12 08 VIO MCPR Dat base Error (paragraph E3.1)
4
50-325(324)/97-12 09 eel US0 on Spent Fuel Cask Movement (paragraph E8.1)
50-325(324)/97-12-10 V10 Protected Area Personnel Access Control
Deficiency (paragraph S4,1)
C1053d
50-325(324)/97-02 06 VIO ESR Design Verification Requirements (paragraph
E8.3) ;
50-325/97-12 02 NCV Control Rod Movement Error (paragraph 04.2)
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50 325(324)/97 08 08 URI Control of Moisture in Installation of E0
Components (paragraph E8.1) ;
50-325(324)/96-15-09 VIO Imp,oper Implementation of ARM Response :
Procedure (paragraph R8.1) l
Discussed
[
50 325(324)/97-02-07 V10 Failure to initiate CR-for HPCI Valve Time i
Discrepancy (paragraph 08.1) l
50 325(324)/97 08 LER ' Main Stack Radiation Monitor-Tests not Performed
as Required. (paragraph M8.1) l
50-325(324)/97 04 LER Spent Fuel Shipping Cask Handling Activities l
(paragraph E8,1) i
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i
. - . - . . _ , , . - . . , , , - , - - - , , _ - _ . . , - . , _ , ; _ ;- . . . _ . . _ . . . . . , . _ _ . , _ _ . . _ . . _ - _ . - , - , _ . . . _ _ ,. s_,_ ,-. ..--