ML20137T571
| ML20137T571 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 03/31/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20137T500 | List: |
| References | |
| 50-324-97-02, 50-324-97-2, 50-325-97-02, 50-325-97-2, NUDOCS 9704160125 | |
| Download: ML20137T571 (46) | |
See also: IR 05000324/1997002
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U. S. NUCLEAR REGULATORY COMMISSION -
l REGION II
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Docket Nos: 50 325, 50-324
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Report No: 50 325/97 02, 50 324/97 02
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Licensee: Carolina Power & Light (CP&L) '
Facility: Brunswick Steam Electric Plant, Units 1 & 2
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Location: 8470 River Road SE
Southport, NC 28461
Dates: January 19 March 1, 1997
Inspectors: C. Patterson, Senior Resident Inspector
M. Janus, Resident Inspector
E. Brown, Inspector In Training
J. Lenahan, Reactor Inspector (Section E1.1 E1.3,E8.1)
J. Coley, Reactor Inspector (Section M1.1)
J. Kreh, Reactor Inspector (Section P2 P7)
Approved by: M. Shymlock, Chief, Projects Branch 4
Division of Reactor Projects
Enclosure 2
9704160125 970331
PDR ADOCK 05000324
G PDR
EXECUTIVE SUMMARY
Brunswick Steam Electric Plant, Units 1 & 2
NRC Inspection Report 50 325/97-02, 50 324/97-02
This integrated inspection included aspects of licensee operations,
engineering, maintenance, and plant support. The report covers a 6 week
period of resident inspection; in addition, it includes the results of an
engineering inspection, maintenance inspection , and emergency preparedness
inspection by regional inspectors.
Operations
A violation was identified for failure to follow procedure for restoring
an open radwaste system valve to a locked closed position.
(Section 01.1) This error was significant in that independent
verification failed to detect this error.
An unresolved item was identified concerning a recirculation pump trip
and three separate recirculation pump runback conditions that occurred
in one day. (Section 01.2) The pump trip occurred because a grounding
strap was inadvertently left in place when a 230 kilovolt transmission
yard breaker was closed resulting in a plant transient.
The material condition of the battery room was good. (Section 01.3)
Maintenance
A vertical slice examination of the licensee electrical maintenance
program at Brunswick revealed strengths including good offsite support,
good maintenance procedures, dedicated and knowledgeable project
engineers, supervisors, and technicians who demonstrated a "think and
verify attitude". Plant equipment was maintained in an exemplary
manner. (Section H.1.1)
Failure to perform an adequate historical review to classify the reactor
protection system (electrical protection assembly breaker logic cards)
as (a)(1) was identified as a violation of the Maintenance Rule.
(Section M1.1)
An inspector followup item was identified for followup on preventative
maintenance frequencies based on refueling outage scheduling.
(Section M1.1).
A Non Cited Violation was identified for failure to establish
communication as required by procedure during performance of a
surveillance test. (Section M3.1)
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- Enaineerina
1 A violation was identified for failure to have adequate design control
measures for design verification of configuration changes.
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(Section E.1.1)
4 The licensee's progress to correct the EQ program deficiencies was
- progressing satisfactorily. Equipment operability issues were
appropriately evaluated through Justification for Continued Operation.
(Section E1.2)
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The licensee's actions to evaluate and repair the corroded anchor bolts
on the service water system headers were conservative and completed
promptly. Engineering response to this issue was rated as a Strength.
(Section E1.3)
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i A violation was identified for failure to take corrective action when a
discrepancy was identified with the High Pressure Coolant Injection
- System valve stroke time. (Section E1.4)
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A weakness was identified in the development of work packages necessary
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to maintain and support continued operation of the plant.
A sitewide assessment conducted by the Plant Evaluation Section was
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thorough and self critical. (Section E7.1) Problems in engineering were
recognized. Site management was receptive to the issues presented.
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Plant Suocort
Emergency response facilities were well equipped and were maintained at
a suitable level of operational readiness. (Section P2.1).
The operational status and maintenance of the siren system exceeded
regulatory requirements. (Section P2.2)
Changes made to the Emergency Response Plan (ERP) since the May 1994
, inspection and implementation of selected Plan commitments met
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regulatory requirements. (Section P3.1)
A non cited violation was identified for failure to have a procedure to
adequately implement the section of the ERP addressing recovery.
(Section P3.2)
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The licensee's Emergency Response Organization training program was in
accordance with the ERP training commitments and with the intent of NRC
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regulatory requirements and guidance. (Section PS.1)
The licensee's program of emergency response training drills appeared to
be a strength. (Section P5.2)
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No degradation had occurred in the orgtnization or management of the
emergency preparedness program. Emergency preparedness appeared to be
receiving strong management support at Brunswick (Section P6.1).
The Nuclear Assessment Section audits fully satisfied the 10 CFR 50.54(t) requirement for an annual independent audit of the EP program.
(Section P7.1)
The inspector observed portions of the baron acid ' addition to the
Standby Liquid Control storage tank. A violation was identified for
failing to provide adequate control to prevent the introduction of
incorrect or defe'.tive materials. The failure to effectively correct
previously identified deficiencies in the receiving and storage of
materials was identified as a weakness. (Section R7.1 and R7.2)
The ins)ector concluded that the Personnel Containmination Event were
thoroug11y reviewed by the licensee and corrective actions initiated.
(Section R7.3) The licensee reviewed these problems with the level of
detail necessary to address the cause and issue adequate corrective
action.
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Report Details
Summary of Plant Status
Unit 1 operated continuously during this period with a downpower on
January 29, 1997, to 60% power to check for condenser vacuum leaks.
Also a leak on the 4B feedwater heater drain was identified. The 4B and
58 heaters were isolated and the unit returned to full aower. On
February 15, 1997, power was reduced to 28% to re) air t1e leak on 4B
feedwater heater. The leak was repaired and the 1 eaters returncd to
service. At the end of the inspection period the unit had been on-line
114 days. Although a 5% power uprate was approved for the unit, the
licensee committed to hold the unit at the new 95% power level pending
resolution of questions.
Unit 2 operated continuously during this period with a downpower on
March 1,1997, to 30% power for recirculation motor generator brush
replacement. At the end of the inspection period, the unit had been on-
line 169 days.
The mechanical vacuum pumps remained tagged out on both units due to
concern about control room dose in the event of a Rod Drop Accident.
The licensee, in a letter to the NRC dated Februar 13, 1997, committed
to upgrade the mechanical vacuum pump trip functic.i to implement a
vacuum pump trip from the main steam line radiation monitor prior to the
next startup.
Six out of seven Justification for Continued Operation (JCO) in the
Environment Qualification (EQ) of equipment area remain open for both
units. The following provides the status of the EQ JCOs and associated
Engineering Service Requests (ESRs):
1) ESR 96-00425, Evaluation of EQ sealants was considered closed by
the licensee.
2) ESR 96-00503, Associated Circuit EQ was scheduled for completion
May 31, 1997.
3) ESR 96 00426, Evaluation Quality class and EQ classification of
PASS valves was scheduled for completion June 6,1997.
4) ESR 96-00501, Motor Control Center (MCC) EQ was scheduled for
completion June 6,1997.
5) ESR 96-00625, EQ Type JC0 for EQ Fuses Without a Qualification
Data Package (QDP) was scheduled for completion June 6,1997.
6) ESR 96 00627, QDP for Marthon 300 Terminal Blocks was scheduled
for completion December 31, 1997.
7) ESR 9700087. EQ Ty)e JC0 for Improperly Configured Conduit Seal
was scheduled to De completed June 30, 1997.
In addition, a JC0 and an Operations Standing Instruction SI 97-016,
remains in effect 3roviding guidance and allowed out of service time for
the three control Juilding air conditioning units. During a Safety
System Functional Inspection conducted in May June 1996, it was
identifled that the units were incorrectly downgraded from safety
related or Q-list to non safety related. ESR 96 00366, Evaluation of
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Using Existing Control Room Air Conditioners, provided a JC0 evaluation
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until the issue was resolved. The issue remains open and the licensee
committed in their February 15, 1997, letter to resolve all open issues
- by the completion of the Unit 1 refueling outage 12, scheduled to begin
- in the second quarter of 1998.
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In summary, both units operated continuously during this report period.
. However, there are six outstanding JCOs in the EQ area and one JC0 for
j the non-Q control building air conditioning units. Compensatory
measures remain in effect for the mechanical vacuum pump due to concerns
i related to Rod Drop Accident analysis.
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, I. Doerations
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l 01 Conduct of Operations
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01.1 Radwaste Valve Found Out of Position.
j a. Insoection Scoce (71707)
i The inspector reviewed the work activities associated with this valve
mispositioning event.
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b. Observation and Findinas
$ On January 26, 1997, the licensee identified that valve 2 G16 V1116, the
] Radiation Monitor Inlet Header Crosstie Valve in the radwaste liquid
release stream was unlocked and o)en. The required position per
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0)erating Procedure 00P 6.4, Disc 1arging Radioactive Licuid Effluents to
- t1e Discharge Canal, was locked closed. The licensee cocumented this
- finding in Condition Report (CR) 97 385. Following identification of
- the mispositioned valve, the licensee placed the valve in the correct
- position, and reperformed a system valve lineup to verify that no other
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problems existed. It was determined that the valve had been manipulated
- the previous evening during a discharge of the Detergent Drain Tank. ;
} The inspector reviewed the procedural ste)s in OP 6.4 Section 7.3, ,
i Securing Discharge of Detergent Drain Tan ( A(B) via the General Electric !
j Radiation Monitor. Step 12 requires the operator to OPEN Radiation
i Monitor Inlet Header Cross Tie 2 G16-V1116, and ste) 22 requires the
1 operator to CLOSE and LOCK Radiation Monitor Inlet leader Cross Tie
- Valve 2 G16 V1116. The final procedural step in Section 7.3, requires
the operator to COMPLETE Attachment 8 of the procedure. This requires
independent verification by another operator. Both the procedural ste)s
and the Attachment 8 lineup documentation recuire the valve to be LOCKED
CLOSED. The inspector reviewed the completec documentation and noted
that both the performer and independent verifier blocks were initialed
complete, indicating the valve was verified locked closed.
The failure of the operators to properly position the valve in
accordance with the procedure is identified as a violation of TS
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6.8.1.a. identified as VIO 50 325(324)/97-02 01, Locked Valve Out of
Position.
The licensee's root cause investigation determined that the valve in
question was located inside of a contaminated area. Interviews of the
involved operators indicated that they left the valve alignment
procedure outside of the contaminated area while performing the
manipulations and verifications and referenced to it between each step.
However, as it was outside of the contaminated area, they could not
initial or put place indicators on the alignment procedure following the
completion of each step. These actions were not in accordance with the
requirements of Administrative Procedure 0AP-10, Procedure Use and
Adherence. 0AP-10, Section 4.4.3.1 Continuous Use, requires that for
" Continuous Use Procedures, " that the operator read each step of the
procedure prior to performing the step, perform each step in the
sequence specified, and where required, sign off each step as complete
before proceeding to the next step.
It was noted that the locked closed valve in cuestion required the
operator to physically unlock and remove a paclock and chain in order to
manually operate the valve. The valve in question was a rising stem
valve. Valve position on this type of valve body is clearly
identifiable. The licensee did not identify any other manipulations or
work which would have changed the position of that valve during the
intervening time between completion of work and identification the
following shift. l
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Additionally, the inspector noted that on January 30, 1997, a site wide l
work stand down was conducted to discuss the recent number of human i
performance problems. The stand down focused on a review of recent !
events, and the discussion of management expectations regarding the
basic fundamental performance standards of procedure / policy adherence,
application of self checking techniques, and maintaining a questioning
attitude. Despite this effort, the inspector noted that on February 4,
1997, the licensee identified another example of an operator failing to
follow a valve alignment procedure in a contaminated area. This was
documented in CR 97-0548.
c. Conclusions
The inspector concluded that a violation for failure to follow the
operating procedure had occurred. Inde3endent verification failed to
ensure the proper position of a valve t1at was suppose to be locked i
closed. 1
01.2 Recirculation Pumo Transients
Inspection Scope (71707)
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a. On March 1,1997, Unit 2 conducted a downpower involving single loop
operations for recirculation motor-generator (MG) brush replacement, rod
pattern exchange, as well as other maintenance items. During this
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evolution a recirculation pump tripped and three recirculation pump
, runbacks occurred.
b. Observations and Findinas
The recirculation pum) trip occurred when transmission yard breaker 31A
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was closed. The brea(er immediately reopened. A ground strap was left
installed following breaker maintenance. The 2B recirculation MG set
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tripped. The 2A recirculation MG set remained in operation and no other
- plant equipment problems were identified. The licensee formed an event
l assessment team to review the event.
The first recirculation runback occurred near the start of the downpower
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when removing the 2A reactor feed pump (RFP) from service. This caused
j the recirculation pump s]eeds to reduce from a value of 45% to 40% for A
- and 42% for B. This pro]lem should not have occurred as removing a RFP
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from service was a routine plant evolution.
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j The second recirculation runback occurred when the 2B pump was lowered
! to 28% speed in preparation for starting the 2A pump. This occurred due
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to operation of the pump speed lear the 28% limiter. This could have
been avoided by a more accurate way of monitoring or setting up plant
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conditions ahead of time.
1 The third recirculation runback occurred while removing the 2B
! condensate pump from service to work on a leaking discharge check valve.
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A transient which occurred may have been due to condensate system
reverse flow pass the leaking discharge check valve or an air line
failure on the 2B RFP recirculation valve.
Since these events all occurred on the last day of the inspection report
period, an unresolved item, URI 50 325(324)/97 02 02. Recirculation Pump
Transients, will be opened pending complete review of these items.
- c. Conclusions
The inspector concluded that a recirculation pump trip and three
, recirculation pump runbacks occurred during a downpower maneuver causing
operational challenges to the plant. These items will be reviewed
during resolution of the URI.
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02 Operational Status of Facilities and Equipment
02.1 Enaineered Safety Features Review of DC Systems and Plant Liahtina
- a. Insoection Scoce (71707)
The inspector performed a walkdown and review of the 125VDC, 24V DC and
- lighting systems.
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b. Observations and Findinas
The inspector performed walkdowns of the 125VDC and 24VDC battery rooms.
Good housekeeping was observed in these areas. The physical condition of
the batteries showed no evidence of leakage or corrosion, and the
i seismic supports observed were acceptable. Labeling on system motor
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control centers and components was acceptable. Verification of proper
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breaker position was performed in the accessible areas. The inspector
observed parts of the performance of Preventive Maintenance OPM BAT 003
! Equalizing 24VDC Batteries and OPM BAT 004, Equalizing 125VDC Batteries.
These activities were completed satisfactorily with one work request / job
i - order initiated for the repair of one of the 24VDC battery charger
equalizer pot. The inspector discussed the FSAR and system operational
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and maintenance rule status with the system engineers. No concerns were
identified.
The inspector performed a walkdown of the associated DC lighting in the
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reactor and turbine buildings and reviewed the results of OPT 34.15.9.2,
Plant Battery Powered Emergency Lighting. Two conditions reports CR 97-
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223 and 97 290 were initiated as a result. CR 97 223 noted results from
0PT-34.15.9.2, Plant Battery Powered Emergency Lighting, which
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identified protected area administrative building discrepancies with the
installation of lights above a drop ceiling and the inability to
functional test lighting due to a spared circuit breaker. CR 97-290
documented that the alternate DC power supply breaker to the Unit 2
Lighting and Communications Inverter was found open. The licensee
verified other DC switchboard breaker positions and no additional items
were identified. For the DC lighting system powered by station
batteries no regulatory concerns were identified.
c. Conclusions
The inspector reviewed the DC and station battery powered lighting
systems. Good housekeeping was identified and battery material
condition was observed to be acceptable.
II. Maintenance
M1 Conduct of Maintenance
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M1.1 Maintenance Imolementation !
a. Insoection ScoDe. Electrical Maintenance (62700)
The inspector reviewed documentation and observed work activities
consisting of the inspection and addition of pneumatic gas and oil as
a3plicable for the 230KV switchyard circuit breakers; the replacement of )
t1e reactor protection system (RPS) electrical protection assembly (EPA) l
3 breaker logic card; and the "as found" and post maintenance
surveillance test of the EPA 3 breaker logic cards. These activities
were examined to verify that maintenance activities were being conducted I
in a manner which would result in the reliable and safe operation of the ;
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plant. Walkdown inspections were also performed of all high voltage
switchyard equipment: high voltage transformers: generator isolated
phase bus: and EPA breakers to determine the material condition of the
equipment.
The inspector reviewed the Brunswick Units 1 & 2 UFSAR Chapter 7,
Section 7.2, " Reactor Protection System", and Chapter 8 Section 8.2,
"Offsite Power Systems" and Section 8.3, "Onsite Power Systems" to
determine design requirements. The TS Section 3/4.3.1, " Reactor
Protection System Instrumentation", and 3/4.8 " Electrical Power
System", were reviewed to determine the surveillance requirements.
b. Observations and Findinas
The inspector verified that required preventive maintenance (PM) was
performed by reviewing completed PM documentation for the high voltage
transformers, switchyard circuit breakers, protective relays, and 230KV
Power Circuit Breaker (PCB) bus disconnects. These maintenance
activities were performed by the off site transmission department and
monitored by the on site project engineer. Other documentation reviewed
included preventive maintenance procedures, condition reports, root 1
cause evaluation reports, predictive maintenance documentation such as
oil sample test, and the interorganizational agreement between l
management at the Brunswick Nuclear Plant and the off-site transmission
department. Off site electrical technicians were observed performing
pneumatic gas and oil inspections on Unit 1 switchyard circuit breakers
Nos. PCB 21A, PCB 22A, PCB 23A and PCB-24A in-accordance with (IAW)
Maintenance Procedure OPM LTM003. The addition of a small volume of !
pneumatic gas or oil as applicable was required for the circuit breakers i
observed. Each maintenance function performed was verified by a second
off-site individual.
During the review of documentation and observation of work for the off-
site power system activities programmatic strengths were observed.
These strengths included preventive maintenance procedures / instructions
which covered each off-site component: the well maintained condition of
off site equipment; the on site project engineer's knowledge and
technical cognizance of maintenance for the high voltage transformers
and switchyard: and the new interorganizational agreement between the
plant and the transmission department. This detailed document defined '
responsibilities which among other things required the plant
transmission activities coordinator (project engineer) to perform a self
assessment of the processes described in the agreement at least
annually. However, the inspector's review of the Transmission
Substation Maintenance Procedures Manual revealed that the frequency,
for performing preventive maintenance procedures on components which,
require the Unit to be in an outage in order to perform the PM, had not
been updated to reflect the new 24 month fuel cycle for Unit 1.
Discussions with the project engineer indicated that this issue had been
addressed in the last "No Loss Of Offsite Power Team Meeting". But when
the project engineer inquired, an engineer from the transmission
department stated that, no official word had been received which would
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require the time interval between refueling outages at any plant to be
extended. Inspector Followup Item IFI 50 325(324)/97 02 03, "PM
Frequencies Based on Appropriate Plant Fuel Cycle", was identified to
followup on the transmission department's development of specific plant
maintenance prcredures which address PM frequencies based on the length
of each Unit's fuel cycle.
The inspector also observed electrical maintenance work practice
involving the replacement of the Unit 1 RPS EPA 3 breaker logic card
which was conducted in accordance with Work Request / Job Order (WR/J0)
96-AHSN1 and Special Process Procedure OSPP CBL001 " Termination of
Electrical Cables". The "as found" test of the old logic card and the
post maintenance surveillance test of the new logic card were also
observed. These tests were conducted in accordance with Maintenance i
Surveillance Procedure OMST RPS21SA, "RPS Electrical Protection Assembly l
Channel Calibration." The licensee was currently replacing four EPA
logic cards on Unit 1 and one on Unit 2 with an improved version because
of excessive calibration drift observed during surveillance testing of l
all 12 breaker logic cards. The work observed was performed by j
professional and very knowledgeable electrical technicians using double '
verification and STAR (Stop, Think, Act, and Review) techniques in an
excellent manner. The prejob briefing was also every detailed covering )
job requirements, safety precautions, and emphasized maintaining ,
component and job area cleanliness.
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During the inspector's historical review of documentation related to I
several previous EPA logic card failures the inspector questioned why a l
condition report had not been issued on February 10, 1995, when the
frequency setpoint of EPA 4 and EPA 1 were found to have drifted below
the Technical S)ecification limit of 57 HZ. Of immediate concern to the
inspector was way this systrm was not in the Maintenance Rule (MRule)
(a)(1) category, and how these events were being documented for the
MRule 3 year historical review if no condition report was written to
decument these TS violations. The licensee's immediate response was
that the RPS was not in the MRule (a)(1) category, and that these events
would have been documented for the 3 year historical review using the
Maintenance Work Request / Job Order (WR/J0) trouble tickets in lieu of ,
condition reports. However, the inspector was notified prior to the l
exit meeting that a subsequent historical review of the RPS revealed I
that the RPS should be in the MRule (a)(1) category. The licensee also j
informed the inspector that their recent review found that the EPA 4 and
EPA 1 logic card failures experienced on February 10, 1995, had not been
documented against the RPS because the previous historical review was
limited to corrective WR/J0's. Therefore, calibration failures found in ,
surveillance testing procedures or failures located in other potential i
historical sources of data were not accounted for in these reviews. I
Carolina Power and Light Administrative Procedure ADM-NGGC 0101,
Revision 4, implements the requirements of the Maintenance Rule.
Section 9.11.1 of this procedure establishes baseline SSC performance
using historical data, and provides an exclusive list (surveillance !
tests and condition reports were not listed) of historical sources that j
may be used. The licensee issued Condition Report 97-00683 to document j
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their limited review of the RPS and to evaluate other Maintenance Rule
systems to determine if the historical searches performed were adequate
to identify all functional failures. This finding was identified as
VIO 50 325(324)/97 02-04, " Failure to Implement the Requirements of
(a)(1) and (a)(2) of 10 CFR 50.65, The Maintenance Rule."
c. Conclusion
The inspector's vertical slice examination of the licensee electrical
maintenance program at Brunswick revealed strengths including good
offsite su) port, good maintenance procedures, dedicated and
knowledgeaale project engineers, supervisors, and technicians who
demonstrated a "think and verify attitude". Plant equipment was
maintained in an exemplary manner. However, a historical review of
specific RPS equipment failures revealed there has been an apparent
reluctance to issue condition reports even when TS requirements are not
met. This assumption was further substantiated by a CP&L Memo dated
July 5, 1996, from C. G. Pardee to Operation Personnel which illustrated
the problem using findings on this subject from NRC IR 96 05 and NAS
Assessment B 0M 96 01. This finding along with the exclusive list
(surveillance tests and condition reports were not listed) of historical
sources given in CP&L Maintenance Rule Program Procedure ADM NGGC 0101,
Revision 4, were contributors which led to the use of corrective WR/J0s i
only, for performing RPS historical reviews. Therefore, functional '
failures were not documented and the RPS was improperly monitored under ;
the Maintenance Rule.
CR 97 00683 was issued by the licensee to document this finding and to
evaluate other Maintenance Rule systems to determine if historical
searches performed on these systems were adequate to identify all
functional failures. This finding was identified by the inspector as a
violation of the Maintenance Rule.
The inspector's review of the Transmission Substation Maintenance
Procedures Manual also revealed that the frequency, for performing
preventive maintenance procedures on com)onents which require the Unit
to be in an outage in order to perform t1e PM had not been updated to
reflect the new 24 month fuel cycle for Unit 1. An inspector followup
item was identified to followup on the transmission deaartment's
development of specific plant maintenance procedures w11ch address PM l
frequencies based on the length of each Unit's fuel cycle. l
M1.2 2B Conventional Service Water Pump Inspection !
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a. Inspection Scope (62707)
The inspector observed licensee personnel perform the removal,
inspection and reinstallation of the 2B Conventional Service Water (CSW)
Pump.
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b. Observation and Findinas
On January 20, 1997, the licensee removed the 2B CSW pump from service
- to perform a scheduled inspection of the pump internals. The licensee
specifically examined the condition of the Hastalloy bolts which were
replaced in March of 1996. The bolts were replaced following the
failure of the thrust ring retainer bolts which allowed the 2A Nuclear
- Service Water pump impeller to slip and bind on the pump shaft. The
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bolting failure was due to galvanic corrosion of the Monel bolts holding
the im)eller and thrust bearings. These problems resulted in a dual
3 unit slutdown to repair and rep'. ace the failed bolts. This was
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documented in NRC Inspection Reports (IR) 50-325(324)/96 04 and 96 09.
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As a result of these problcms, the licensee committed to performing a
- follow-up inspection to assess the performance of the new bolting
i material. This pump removal was part of that material performance
i assessment.
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The inspector examined the pump internals and fasteners in the clean
maintenance shop on January 22, 1997, following its removal from the
Service Water (SW) intake structure. The inspector examined the thrust
rings, thrust ring covers, and fasteners, in particular, those which had
exhibited the most corrosion with the previous material. On
examination, the inspector did not observe any noticeable evidence of
corrosion or degradation from the 10 months in service. The new
material appeared to be performing up to the licensee's expectations.
Following the disassembly and ins)ection of the pump internals, the pump
was reassembled and installed bac( at the SW intake structure. The '
inspector observed the mechanics reassemble and install the pump on l
January 23 and 24, 1997. During these observations, the inspector
focused on the use of aro)erly calibrated tools; the correct use of the j
torque procedure for t1e )olt up and assembly of the pump shaft columns;
verified the correct revisions and coaies of all necessary procedures
were at the jobsite and being used: t1e establishment and adherence to
good foreign material practices in accordance with the procedure; and
the Quality Control (QC) verification of work, and proper sign offs of
all QC hold points. The inspector did not observe any problems with the
reassembly and installation of the 28 CSW pump. The pump was returned
to service on January 28, 1997 following successful performance of the
Post Maintenance Test Requirements. The results of this inspection were
documented in Supplement 2 to Licensee Event Report 1 96 03, Dual Unit
Shutdown Due to Service Water Pump Inoperability, issued February 18,
1997.
c. Conclusions
The inspector concluded, based on the condition of the new bolts that
the new bolting material installed in the service water pumps appears to
be performing as expected, after over 10 months in service. The
Hastalloy bolts did not exhibit any signs of corrosion or degradation as
previously identified with the Monel bolts in March of 1996.
Additionally, the inspector did not note any problems or deficiencies
. _- . . . _ _ _ __ _ _ _ _ _ _ _ _ _ . _ _ _ _
e l
,
>
10
,
'
with the removal or reinstallation of the pump assembly. All work
observed proceeded in accordance with the procedure and good work
,
practices.
f M3 Maintenance Procedures and Documentation
l M3.1 Failure to Establish Communications Durina Surveillance Test
4
a. Insoection ScoDe (61726)
The inspector observed the performance of the following Maintenance
Surveillance Test OMST-RHR280, Residual Heat Removal System (RHR) Remote
Shutdown Panel (RSDP) System Flow Channel Calibration.
b. Observations and Findinos
On February 6, 1997, the inspector observed licensee Instrumentation and
Controls (I&C) technicians perform OMST-RHR280. The purpose of this
test was to determine the operability of the RHR system remote shutdown j
panel flow monitoring instrumentation in accordance with TSs.
The inspector observed the I&C technicians setup the necessary equipment
and perform the calibration check. A portion of the test evolution. 1
required one technician to Se stationed at the remote shutdown panel on '
the 20 foot elevation of the reactor building, while the other remained
at the instrument rack in the South RHR room on the minus 17 foot
elevation. Procedural Step 7.1.1.1, required the technicians to have
established communications between these two test locations.
During the initial portion of the calibration, the inspector was present
at the RHR room instrument rack, where the test signals were being i
generated. Per the procedure, a five point calibration was to be
performed, with the second technician verifying proper response of the
flow instrumentation at each point. The inspector observed the
technician input the first calibration point, wait approximately 30
seconds, and proceeded to input the second calibration point. The
inspector questioned how he was communicating with the technician at the
remote shutdown panel. The technician informed the inspector that he
was adjusting the calibration points, holding for a short period and
moving on to the next calibration 3ressure. He stated that he would
compare results with the other tec1nician after all the calibration
points were completed.
The inspector asked the technician how he was complying with the
procedural requirement to have established communications between the
two test areas. The technician appeared unsure of how to answer the
question, stopped the test and proceeded to consult with the other
technician upstairs at the remote shutdown panel. When the technician
returned, he informed the inspector that they wculd use the plant page
system to communicate between the two test locations after each
calibration point. This failure to have established communications
between the two testing locations in accordance with the requirements of
. .- - - - - . - - - --. -- - - - -- . - _ _ - _.
,
11
procedure step 7.1.1.1, is identified as a violation of TS 6.8.1.a.
This violation is identified as NCV 50 325(324)/97-02 05, Failure to
. Follow Procedures for Establishing Communications. This failure
$
constitutes a violation of minor significance, and is being treated as a
Non Cited Violation, consistent with Section IV of the NRC Enforcement
Policy.
4
The technicians completed the remainder of the procedure without
, incident. The inspector observed that the use of the plant page
system required the technicians to step away from their respective
'
panels following each calibration point. Following the completion
i of the test, the inspector discussed his observations with the I&C
- crew supervisor, in particular, the inspector questioned the
i practice of using the plant page system to communicate when it
involves moving away from the instrumentation being tested.
- CR 97 617 was initiated to document this incident.
Subsequent license investigation revealed that a small number of the I&C
'
crews had either performed similarly or did not understand the intent of
the communications requirement. Because of this result, a work stand-
down was held with the I&C crews to discuss this event and management
expectations.
c. Conclusions
Following this event, the inspector observed other MSTs in progress, and
noted that all had clear lines of communications established, and that
all crews and supervisors were fully aware and informed about the event
noted above and the importance of establishing communications and
procedural compliance. This event was identified as a Non Cited
Violation for the failure to follow the procedure requirement for
establishing communications.
e
M3.2 Reactor Protection System Scram Discharae Volume Hiah Water Level
Surveillance Test
a. Inspection Scooe (61726)
On February 5, 1997, the inspector observed the performance of
Maintenance Surveillance Test 1MST RPS270, Reactor Protection System
Scram Discharge Volume High Water Level Channel Functional Test and
Channel Calibration conducted in accordance with the requirements of
Technical Specifications (TS).
b. Observation and Findinas
The aurpose of this test was to determine the operability of the scram
disc 1arge volume (SDV) high water level function of the reactor
protection system (RPS). Additionally, the test determines the
o)erability of the control rod withdrawal block on high water level in
t1e SDV. This test was performed to fulfill the testing requirements
specified in TS 4.3.1.1 and 4.3.4.1 which require that the RPS nstrument
,
12
channels and the control rod withdrawal block instrument channels be
demonstrated operable by the performance of a channel check, channel
calibration and channel functional test during the operational
conditions and frequencies specified in TS table 4.3.1-1 and 4.3.41
respectively. The inspector verified that the required frequency for
these instrument channel checks was quarterly, which was consistent with
the testing being performed.
The inspector observed the technicians perform the testing noted above i
which involved the connection of a test rig to the SDV allowing the
technicians to raise the water level in the SDV until the water level
switch trip setpoints were reached. On reaching the appropriate water
levels, alarm and relay actuations were confirmed to have taken place,
verifying 3 roper response of the instrument being tested. The inspector
observed t1e various instrument responses and verified that they were
consistent with the required responses, thus demonstrating the
operability of the instrument.
The inspector verified that the work was performed in accordance with
the applicable procedures, and that validated copies of the correct
revisions were present and used at the worksite. The inspector observed
that the licensee personnel were knowledgeable of their assigned tasks:
used good communications between crew members and the control room: used
good self checking techniques; that required tools and equipment
necessary to complete the work were prestaged and available at the
jobsite; and appropriate safety equi) ment was used as required. The :
test was successfully completed, wit 1 no problems or deficiencies !
identified by the inspector.
M3.3 ResiduJ Heat Removal System Pumo Discharae Pressure Automatic
Depresourization System Permissive Surveillance Test
a. Insoection Scoce (61726)
On February 5, 1997, the inspector observed the performance of
Maintenance Surveillance Test, 2MST RHR250, Residual Heat Removal System
Pump Discharge Pressure Automatic Depressurization System Permissive
Instrument Channel Calibration conducted in accordance with the
requirements of TS.
b. Observation and Findinas
The purpose of this test was to demonstrate the operability of the RHR
System pump discharge pressure permissive function of the Automatic j
Depressurization System (ADS) in conformance with the testing l
requirements of TS 4.3.3.1, 4.3.3.2, and TS tables 3.3.31(4.f) and
3.3.3 2(4.f). These specifications require that each Emergency Core ;
Cooling System (ECCS) actuation instrument channel be demonstrated l
oaerable by the performance of a channel check, channel calibration, and {
clannel function test during the operational conditions and frequencies i
specified. The test verifies that a signal from a running RHR pump is I
I
received by the ADS actuation logic.
13
This test involves the application of a test pressure to the isolated
instrument channel to verify proper relay response of the ADS logic to
the increase in pressure. The ADS logic requires the receipt of at
least one running RHR pump signal to com)lete the actuation logic. The
HST tests all eight of the RHR pump disc 1arge )ressure instrument
channels, and verifies that on reaching a disc 1arge pressure greater
than 100 psig that a signal is transmitted and received by the ADS
actuation logic. The test required technicians at the instrument rack
in the reactor building input the test pressure, and technicians in the
control room back panels verifying ADS signal receipt and correct relay
response. The inspector observed the ap)1ication of the test pressure
and noted that at 100 psig or greater, t1e appropriate responses
occurred.
.
The inspector verified that the work was performed in accordance with
the applicable procedures, and that validated copies of the correct
revisions were present and used at the worksite. The inspector observed
that the licensee personnel were knowledgeable of their assigned tasks:
used good communications between crew members and the control room; used
good self checking techniques; that requirad tools and equipment
necessary to complete the work were prestaged and available at the
jobsite: and appropriate safety equi) ment was used as required. The
test was successfully completed, wit 1 no problems or deficiencies
,
identified by the inspector.
M3.4 Remote Shutdown Panel and Reactor Turbine Gauge Board Panel Reactor
Water Level Indicator Surveillance Test
a. Inspection Scope (617261
On February 20, 1997, the inspector observed the performance of
Maintenance Surveillance Test, 2MST-RSDP210 Remote Shutdown Panel and
Reactor Turbine Gauge Board Panel Reactor Water Level Indicator Channel
Calibration conducted in accordance with the requirements of TS.
b. Observation and Findinas
The purpose of this test was to determine the operability of the Remote
Shutdown Panel (RSDP) reactor water level monitoring instrumentation
B21 LT N0268, B21 LI R604BX, B21-LT 3331, and 821 LI 3331 in accordance
with TS 4.3.5.2 which requires that remote shutdown monitoring
instrumentation for reactor water level be demonstrated operable by the
performance of quarterly channel calibration as required in TS Table
4.3.5.2-1. Additionally, the test determines the operability of the
RSDP Reactor Water Level Monitoring Instrumentation B21-LT-N0268 and
B21 LI R604B in accordance with TS 4.3.5.3, which requires accident
monitoring instrumentation channels for reactor vessel water level to be
demonstrated operable by the performance of a channel calibration every
refueling cycle per TS Table 4.3.5.3-1. Because the B21 LT-N026B and
B21-LI-604B are included as both a required RSDP instrument channel and
a required accident monitoring instrument channel, this one quarterly
channel calibration satisfies both the quarterly requirement and exceeds
. - - - - . . .. -. .-- - . . -. - -- -.-. .-. - ~-
1
J
14
'
the once per refueling cycle frequency for the accident monitoring
instrument channel.
! The test involves isolating the various level transmitters and applying
1
a differential pressure across the instruments, simulating a change in
!
level. A five point calibration was performed using this process to
e generate a signal corresponding to the five different levels. The
1
inspector observed the technicians perform the calibration checks and
-
verified that the instruments responded within calibration limits.
I Additionally, the calibration of the level indicators in the control
- room and the RSDP was verified to be correct during the performance of
j this test. The ins metor observed the response of the indicators in
- both locations to tie simulated level changes, and noted that the
. instruments were properly calibrated.
i The inspector verified that the work was performed in accordance with
. the applicable procedures, and that validated copies of the correct
! revisions were present and used at the worksite. The inspector noted
that the technicians were very cautious in performing the necessary
valving operations associated with this procedure so as to cause no
j perturbations within the system. The inspector observed that the
licensee personnel were knowledgeable of their assigned tasks: used good
- communications between crew members and the control room
- used good self
! checking techniques: that required tools and equipment necessary to
i complete the work were prestaged and available at the jobsite: and
- appropriate safety equipment was used as required. The test was
successfully completed, with no problems or deficiencies identified by
the inspector.
l M3.5 Control Room Emeraency Filtration System Monthly Ooerability Check
i a. Insoection Scooe (61726)
E
1
'
The inspector observed the performance of Periodic Test (PT) OPT 23.1.3,
Control Room Emergency Filtration System (CREFS) Monthly Operability
Test,
l
b. Observations and Findinas
l On January 23, 1997, the inspector observed the performance of OPT-
'
23.1.3, Control Room Emergency Filtration System Monthly Operability
- Test. This PT satisfies the operability assessment required by
TS 4.7.2.a which requires that once every 31 days the CREFS shall be
i demonstrated operable by successfully demonstrating flow can be
i initiated from the control room through both the HEPA filter and
2
charcoal absorbers in each unit for at least 15 minutes. No concerns
were identified with the applicable procedure. TS, or FSAR section
- reviewed.
( The inspector observed the pre job brief and determined that the
4
briefing adequately covered previous problems, procedural prerequisites
and instructions. The inspector observed good discussion and
.
. -. - . .
15
preparation for possible communication interference from noise or from
the affects of hand held radios on equi > ment in the Control Building.
The inspector observed performance of t1e testing from both the control
room and various plant locations. Observed communication was acceptable
and the PT was performed satisfactorily with no identified concerns.
c. Conclusio_ns
No problems or deficiencies were noted during the observation of the
surveillance tests in paragraph M3.2 M3.5.
M8 Miscellaneous Maintenance Issues (92902)
M8.1 (Closed) LER 50-325/95-07: Safety Relief Valves Tested At Wyle
Laboratories Exceeded Technical Specification Setpoint Limits
(Closed) LER 50-324/96 02: Safety Relief Valves Tested At Wyle
Laboratories Excecded Technical Specification Setpoint Limits
(Closed) LER 50 325/96-13: Safety Relief Valves Tested At Wyle
Laboratories Exceeded Technical Specification Setpoint Limits
These three Licensee Event Reports (LERs) documented the results of
as found safety relief vslve (SRV) testing on both units. LERs 1 95 07
& 2 96-02 described the failure of all SRVs on Unit 1 and 9 SRVs on
Unit 2 during refueling outages B110R1 and 8212R1 to meet the TS lift
setting limit of ilt. Subsequently, the valves were replaced with i
certified spares. Investigation, of previous failures going back to
'
1984, has attributed the failure mechanism to oxygen induced bonding of
the ailot disc-to seat surface. To test a proposed method to resolve
the Jonding issue, the licensee installed 3 modified SRVs in both units.
The modified valves contained platinum coated discs which showed
setpoint drift of less than or equal to it. In addition, vendor
testing has verified that a lift setting of i 3% would not exceed the
ASME code pressure limitation of 1375 psig. Based on the success of the
modified discs and the verificatior. of the acceptability of the i 3%
lift setting, the licensee committed to pursue a TS change revising the
SRV lift setpoint from i 1% to i 3% and to replace the SRVs with the
modified discs. Based on the installation of the modified discs and
NRC's approval of Amendment 183 for Unit 1 and Amendment 214 for Unit 2,
these items are closed.
M8.2 (Closed) LER 50 325/95-13: During High Pressure Coolant Injection System
Surveillance a Ground was Noted Affecting System Instrumentation
.(Closed) VIO 50 325/95 19 05 or 50 325/95 166 1013: Design Review Did
Not Adequately Isolate DC Power Supply
(Closed) VIO 50-325/95 19 06 or 50 325/95 166 1023: Post Hodification
Testing of HPCI/RCIC Inverter and Flow Controller Replacement
- .u..
'
a
I
l
16
i A modification was performed, during the Unit 1 spring 1995 outage, to l
4
replace the flow controller in the High Pressure Coolant Injection l
(HPCI) and Reactor Core Isolation Cooling systems and obsolete inverters l
'
with DC/DC power supplies. Inadequacies with the modification designs '
resulted in RCIC flow controller problems and formation of battery bus j
, grounds on RCIC and HPCI, which rendered HPCI inoperable. These issue l
were discussed previously in Inspection Reports 50-325(324)/95-13 and :
95 14. The associated violation was issued in a letter from the NRC to
<
l
.
CP&L dated September 8, 1995. Licensee Event Report (LER) 50 325/95-13 i
described the HPCI inoperability and associated corrective actions and a l
'
letter from CP&L to the NRC dated October 6, 1995 contained the I
violation response and the associated corrective actions. '
i
The inspector reviewed the committed corrective actions and verified l
! their completion. The committed actions reviewed included verification i
! of the installation of an output signal isolation device for the control ,
<
'
circuit wiring, engineering procedures were developed or revised to l
established and clarify existing responsibilities and requirements for
- design modifications, and revisions to relevant design documentation to l
1 incorporate lessons learned. Based on completion of the committed i
- actions for LER 50 325/95 13 and the associated violation response dated
- October 6, 1995, these items are closed.
I
'
III. Enaineerina
El Conduct of Engineering
E1.1 Desian Change Processes
a. InsDection Scope (37551)
The inspector reviewed the licensee's procedures which control the
design change program.
b. Observations and Findinas
The inspector reviewed the procedures listed below which control design
and design changes to determine if the procedure implement the
requirements of 10 CFR 50, Appendix B, Criterion III and 10 CFR 50.59.
The following procedures were reviewed:
EGR NGGC 0001, Conduct of Engineering Operations, Rev. 2, dated
February 3, 1997 ;
EGR NGGC-0003, Design Review Requirements, Rev. 0, dated
June 3, 1996
EGR NGGC 0005, Engineering Service Requests, Rev. 3, dated
December 17, 1996
OENP 1000, Brunswick Engineering Support Section Conduct of
Operations, Rev. 0, dated February 5, 1997
1
- _ __ _ ._ __ ._ _ _ _ _ _ . _ - _
!
17
OIA 109, Performance of Nuclear Safety Reviews. Rev. 8 dated
January 14, 1997
'
The inspector concluded that the )rocedures adequately addressed:
design input, training, drawing c1anges, post modification
testing, control of field changes,10 CFR 50.59 safety
l evaluations, and ALARA reviews. However, review of EGR NGGC 0003
and 0005 disclosed the following problem: The engineering service
' requests (ESRs) was the process used for performing engineering
work. EGR NGGC 0005 defined three type of ESRs. These were
design change (DC), configuration change (CC), and engineering
disposition (ED) ESRs. Design change ESRs were defined as a
change which affects the design input of a system, structure, or
component (SSC), while a configuration change was a change to a
SSC which does not change the design inputs. Both of these ESRs
produce design output documents which could result in
modifications to an SSC. Engineering disposition ESR were used to
supply information and do not produce design output documents or l
change any SSC. ESRs designated as design change ESRs required l
design verification to meet the requirements of 10 CFR 50 Appendix i
B, Criterion III, ANSI N45.2.11, and Regulatory Guide 1.64. The {
qualifications for design verifiers were addressed in paragraph '
4.5 of OENP 1000 and paragraph 4.9 of EGR NGGC 0001. ESRs i
designated as configuration changes require an engineering review, ;
instead of a design verification. There were no specific
requirements listed for individuals who perform the engineering
review. The engineering review, as defined by CP&L procedure EGR- i
NGGC 0003 did not meet the in depth review and independent review l
requirements of Appendix B, Criterion III, ANSI N45.2.11, and !
Regulatory Guide 1.64. These requirements specify that the design j
control measures, including design verification activities, be l
established to assure the design basis is correctly translated I
into design outputs (e.g., drawings, specifications, procedures, l
and/or instructions). The requirements also s)ecify that design I
changes be subjected to the same controls as t1ose applied to the
original design. The inspector reviewed safety related
configuration change ESRs completed, and approved since
August 1, 1996. In addition to ESR number 9700057, discussed in
paragraph E1.3 below, more than half of the safety related configuration
change ESRs initiated were completed and ap3 roved without the benefit of
an independent design verification. These ESRs were subject to an
engineering review only. The failure to include design verification
requirements for configuration change ESRs was identified as Violation
item 50-325(324)/97 02-06, ESR Design Verification Requirements.
Section 9.1.2 of EGR NGGC 0003 specify the instructions for the
design verifier. Review of these instructions disclosed that the
requirement to confirm that design interfaces are controlled was
not addressed in this section of the procedure. However, they
were addressed on Attachment 1, Design Review Considerations.
i
_ - _ _ _ _ _ _ _ ___ _ _. __ . _ _ _ _ _ _ _ . _ _ _ _ . _ .
.
,
4
'
18
i
j c. Conclusions
i
i With the exception of the issue identified in VIO 325(324)/97 02 06, the
- inspector concluded that the licensee's design change control procedures
- complied with the requirements of 10 CFR 50.59, and 10 CFR 50,
- Aopendix B, Criterion III.
! E1.2 Environmental Qualification
!
a. Inspection Scope (37551)
- The inspector reviewed the licensee's Environmental Qualification (EQ)
,
program, specifically their corrective actions to respond to findings
i identified during Self Assessment numbers 95 0041 and 96 0271 and the
] violations identified in NRC Inspection Report number 50 325(324)/96 14.
j b. Observations and Findinas
j
'
The inspector reviewed the status of the licensee's corrective
actions to resolve problems identified in the EQ program. The
- following issues were discussed with the licensee's EQ Task Force
>
Manager:
-
e Corrections to the Equipment Data Base System (EDBS) and
corrections to the EQ equipment list.
i
e Updating of Qualification Data Packages (QDPs).
! e Revision of the Reactor Building Environmental Report
- (RBER).
4
e Status of the walkdown inspections being performed to
- determine if equiment required to be EQ was installed in
- accordance with t1e QDPs.
! e Status of the four previously identified Justification for
- Continued Operations (JCOs) and resolution of the technical
l issues required for closecut. These JCOs address
i operability of Post Accident Sampling System (PASS), thread
- sealants, associated circuits, and the Motor Control Center
(MCC)s.
The discussions disclosed that the licensee's actions were on
schedule to correct the program deficiencies. The EDBS system and
- ~
EQ lists were updated and Revision 5 of the RBER, which addresses
updated temperature and pressure data, including the effect of the
power uprate project and extended core life, has been completed.
- The licensee was in the process of updating the QDPs. Some of
- this work may be outsourced to an Architect-Engineer firm in order
- to meet the scheduled date of December 1997 for completion of the
i QDP updates. During the EQ equipment walkdowns, three Rosemount
i
i
. - - - .--
-. .- . - - .. . . .
19
,
transmitters with improperly installed seals were identified on
the Unit 2 reactor water cleanup system. The seals had been
installed at the terminal box end of the flexible conduit instead
] of adjacent to the instrument itself as the QDP required. The
flexible conduit is not considered qualified to provide a moisture
'
tight barrier and prevent moisture from intruding into the
Rosemount transmitters. This problem was documented in CR
97 00436. The remaining Rosemount transmitters were determined to
- be properly installed. The licensee removed the Unit 2 Reactor
Water Cleanup Unit from service and issued three work requests to
correct the problem and returned the system to service. The
inspector reviewed the work requests, numbers WR/JO 96 AJMG3, -
l AJMJ4, and AJMJ5, which were initiated to install the seals at the
proper location.
After the 3roblem discussed above was identified, the licensee
adjusted t1eir EQ equipment walkdown schedule to inspect
instrumentation and otier components which required seals to
protect the equipment from moisture intrusion. Approximately 80
ASCO Tripoint pressure switches with improperly installed conduit
seals (i.e. seals were installed at terminal box end of the
flexible conduit) were identified during the licensee's
inspections. This problem was documented in CR 97-00508. A JC0
was issued in ESR 97 00087 on February 3, 1997, to address the as-
found conduit seal configuration for the ASCO Tripoint pressure
switches and other similar components, such as excess flow check
valves, which also recuired conduit seals. The inspector reviewed
the JC0 and questionec licensee engineers regarding a temperature
discrepancy in the JC0 regarding the qualification of the NAMC0
limit switches, and whether a short circuit in the excess flow
check valves could be an associated circuits issue. After
aerforming a walkdown inspection in the Units 1 and 2 reactor
)uildings, the inspector also questioned licensee engineers
regarding the type and identification of the flexible conduit
installed. The inspector noted during the ins)ection that at
least two different types of flexible conduit 1ad been installed
and some flexible conduit had been Sainted so that identification
of the type / materials was not possi)le.
In response to the inspector's questions, and questions from other
NRC staff, the licensee revised the JC0 and issued ESR 97 00087,
Revision 1 on February 12, 1997. The revised JC0 only addresses
the ASC0 Tripoint pressure switches and provides additional
specific test data that shows they could be qualified with the
existing seal configuration. The licensee will install new seals
adjacent to the instrument, as required by the QDP, as a long term
corrective action. This work is scheduled to be completed by
July 1997. Other types of components were not included in the
revised JC0s since additional inspections by licensee EQ personnel
have not identified any new seal installation problems.
Approximately 50 percent of the excess flow check valves have been
inspected. The seals were properly installed at the junction of
-- .-- - - .- .-. -. . _ . _ -~. . . - - . - . - . - - . - - - - -
s
i
20
! the flexible conduit and valve. Based on the configuration of the
i excess flow check valves, the licensee has a high level of
confidence that all seals for these components were properly
- installed.
c. Conclusions
The inspector concluded that the licensee *s progress to correct
- the EQ program deficiencies was progressing satisfactorily.
j Equipment operability issues were appropriately evaluated through
JCOs. Additional followup inspections will be performed to review
and inspect EQ issues and previously identified violations and
open inspection items.
'
E1.3 Followuo on Service Water System ReDairs
j a. Insoection Scope (37551)
'
The inspector reviewed the licensee *s actions to evaluate and
l repair corroded bolts in supports for the conventional and nuclear
j
.
service water header supports.
b. Findinas and Observations
On January 24, 1997, an anchor bolt on a support, PS 2112 1, on
.
the Unit 1 nuclear service water header was found broken off. The
j broken anchor had been installed during original plant
- construction. The anchor bolts installed during original
- construction were carbon steel studs installed in drilled in
sleeve anchors. Several of the original anchor bolts had been
i
replaced with new stainless steel anchors in 1992 93. The
, stainless steel bolts (wedge anchors) were in good condition. The
! licensee initiated Condition Report (CR) 97 00377 to document and
! disposition this problem. Corrective actions included '
nondestructive (NDE) testing of all anchor bolts on the Unit 1 and
,
2 nuclear and conventional service water headers, operability
'
evaluations of the as found conditions, and replacement of damaged
bolts. CR 97 00381 was issued to document and disposition
degraded Unit 2 anchor bolts discovered by NDE.
'
I The inspector reviewed the following records which documented the
licensee *s actions to evaluate and correct the damaged anchor
i bolts:
,
CR 97 00377 Unit 1 SW Header Anchorage
CR 97 00381 Unit 2 SW Header Anchorage
.
ESR 97 00056 Unit 1 SW Nuc/ Cony Structural Operability
)
Evaluation for Corroded Bolts
!
4
_ . . - . - .
__ _ _ ___ . _
. -_ . _ -_ __
i
a
4 21
ESR 97 00058 Unit 2 SW Nuc/ Cony Structural Operability
Evaluation for Corroded Bolts
- ESR 97-00057 - Service Water Header Anchorage Repair
Review of the results of the NDE showed that a majority of the
remaining anchors installed during original construction were not
adequate to perform their intended function either due to
4
corrosion or insufficient anchor length. The licensee performed
a
an operability review of the degraded bolts in accordance with
CP&L procedure EGR-NGGC 0320, Civil / Structural Operability
Reviews, Revision 0, dated May 8, 1996. The review was performed
by assuming the bolts installed during original plant construction '
were degraded to the point where they would not carry any load.
- Review of the operability evaluations showed that the headers were j
- short term qualified.
^ 1
The inspector examined ESR 97 00057, Revisions 0 through 3, which I
provided instructions to restore the service water headers to long l
term qualified conditions. The repair involved welding of
. extensions on the existing sup) ort baseplates and replacement of
i all remaining carbon steel anc1 ors with new one inch diameter
- stainless steel wedge anchors. Stainless steel anchors were
selected since they are more corrosion resistant. The inspector
'
4
walked down the service water headers and examined the repairs
completed as of the inspection date. This work included
installation of new concrete anchors to replace those installed
-
during original construction (the corroded bolts), welding of base i
plate extensions for the new bolts, removal of the corroded l
anchors, and partial grouting of some of the new anchors. The new
work was compared to the design drawings and checked for
configuration, member size, welding, and anchor diameter. The
inspector also examined quality control (OC) inspection records
for installation of the new anchors for the Unit 1 header supports l
and visual inspection of welds for the Unit 1 base plate l
extensions. No discrepancies were identified.
The licensee was also planning to conduct an inspection of anchors
installed in other areas which may have been damaged by corrosion.
The inspections will include visual and NDE. The number of
anchors to be inspected will be based on the sample (population)
size.
c. Conclusions
The licensee's actions to evaluate and repair the corroded anchor
bolts on the service water system headers were conservative and
completed'promptly. Engineering response to this issue was rated
as a strength.
22
E1.4 Hiah Pressure Coolant Injection (HPCI) System Inoperability
a. Inspection Scone (37551)
The ins)ector reviewed the 4-hour emergency notification concerning
Unit 1 iPCI being declared inoperable on February 13, 1997.
b. Observations and Findinas
HPCI system was declared inoperable because the minimum flow bypass to
suppression 2001 valve,1 E41-F012, exceeded its opening stroke time of
10 seconds w1en performing 0PT-09.2 HPCI System Operability Test. The
actual valve stroke time was 10.04 seconds. The licensee reviewed the
stroke time history of the valve and noted a gradual increase in stroke
time for this direct current motor. The licensee replaced the motor and
obtained a stroke time of less than 10 seconds.
However, during the review of the operating history, the licensee
i noticed that the acceptance criteria was 10 seconds for Unit 1 and 19.4
seconds for Unit 2. The two different times were next to each other in
a table in Attachment 2 of procedure OPT-09.2, HPCI System Operability
Test. The licensee reviewed the last performance of the test for Unit 2
and found that the Unit 2 time was less than 10 seconds and no immediate
operability concern existed for Unit 2 HPCI. The licensee further
reviewed this difference and initiated Condition Report (CR) 97 00669,
UFSAR-HPCI Valve Stroke Time. This CR identified as one of the reasons
this problem occurred was due to failure to implement timely resolution
. to an identified UFSAR discrepancy. The UFSAR change raised the
acceptance criteria to 20 seconds for the minimum flow valve.The
discrepancy was identified in April 1996. Timely processing of the
UFSAR revision and change management to the In Service Test (IST)
program and operating procedures would have prevented HPCI from being
declared inoperable.
. The inspector independently verified Unit 2 test data for January 18,
March 9. Hay 18, and July 3,1996, and concluded that the test data was
'
all less than 10 seconds. The basis for the difference in acceptance
times was discussed with the responsible engineers. The Unit 1 was
coening time was based on UFSAR section 7.3.3.1. The Unit 2 opening
time of 19.4 seconds was based on IST Program data. The value of 19.4
seconds was twice the normal opening time of 9.7 seconds.
The ins)ector reviewed with the UFSAR review program supervisor how
design Jasis errors found in the UFSAR are promptly corrected in plant
procedures. The process established by the licensee was to write a CR
once a UFSAR discrepancy was identified. The CR should state what
corrective actions such as procedure changes are required. A UFSAR
discrepancy may not involve a procedure revision. However, a CR gets a
reportability and operability review initially and the corrective
actions are to be specified in seven days. The procedure requirements
for CRs are in OPLP-04, Corrective Action Management. This procedure
specifies times for completion of corrective action assignment. A level
- . . - .. -- - . . - . - _ _ _ - _ _ _ _ _ _ _ _ _ _ _ __
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III CR is allowed seven days. A level II CR for adverse trends and .
. equipment problems is allowed up to 28 days. '
.
In this case, the licensee identified the problem in April 1996 as I
- stated in CR 97 00669. A CR was not processed at.that time. The
- inspector reviewed the UFSAR change form and the initiator had signed
"
the form on April 29, 1996, but the supervisor signed the form on :
February 13, 1997. The UFSAR change was nunsered 97 FSAR-018 and titled
i
ECCS Injection Valve Stroke Times. The basis for the UFSAR change was
that in some places the valve stroke times specified were nominal and in
other places times specified were maximum valves. The change would
provide a table providing both nominal and maximum valves. In the case
of Unit 1 HPCI, the valve time in question, was 10 seconds at the
nominal valve. The change would specify a 10 second nominal and 20 ;
!
second maximum. J
t
In reviewing this issue the inspector determined that although the
acceptance criteria in the test procedure was more restrictive than
required, it was not the correct valve. It was fortuitous that the i
number was more conservative. A CR was not written in a timely manner <
- to resolve the UFSAR discrepancy and initiate the required corrective
4 action necessary to put the correct design basis numbers into the
procedure acceptance criteria. The licensee took Unit 1 HPCI system out
of service to replace the minimum flow valve motor based on an
acceptance of 10 seconds instead of twice the base IST valve or 20 l
l seconds.
,
'
Accordingly, this failure to process a CR as required by plant arocedure
OPLP 04 was identified as a corrective action violation. 10 CF150
. A>pendix B, Criterion XVI, Corrective Action, recuires that measures
- s1all be established to assure that conditions acverse to quality such
!
as deficiencies, deviations, and nonconformances are promptly identified
i and corrected. This violation will be identified as VIO 50-325(324)/
l 97 02 07. Failure to initiate CR for HPCI Valve Time Discrepancy.
I c. Conclusions
.
The inspector concluded a violation of the corrective action program has
occurred due to the failure to initiate a CR.
E1.5 Soecial UFSAR Review
.
- A recent discovery of a licensee o)erating the facility in a manner
4 contrary to the UFSAR description lighlighted the need for a special
i focused review that compares plant practices, procedures, and/or
parameters to the UFSAR descriptions. While performing the inspections
discussed in this report, 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.
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i
.The UFSAR discrepancy discussed in paragraph E1.4. Noted in this review ;
was the fact that the UFSAR discrepancy was initiated in April 1996, but i
not completed until February 1997. The timeliness of this change was
discussed with licensee management. Review of this issue will be part
of URI 50 325(324)/96 05 02, UFSAR Discrepancies.
E2 Engineering Support of l'acilities and Equipment
E2.1 Leak Repair on Unit 1. Number 4 Bypass Valve
a. Inspection Scope (37551)
The inspector reviewed the Engineering Service Request (ESR) associated
with the temporary leak repair attempted on the Electro-Hydraulic
Control (EHC) fluid leak on the Unit 1 number 4 bypass valve.
b. Observations and Findinas
The licensee had previously identified an EHC fluid leak on the
hydraulic controller for the Unit 1. number 4 bypass valve on
November 23, 1996, during a hotside walkdown of the EHC system. The
leak did not impact the operability of the bypass valve, and thus was
contained until a suitable time and reaair plan could be developed. ESR
97 01, Fluid Actuator Supply (EHC) Lea ( Repair for 1 MS BPV 4 (the
number 4 main steam bypass valve) was initiated to develop a temporary
modification and install a leak repair clamp on the leaking fluid
actuator supply fitting.
The leak repair effort was conducted on February 15, 1997, involving the
use of a leak repair vendor. A leak repair clamp was installed on the
leaking fitting, and pumped with sealant in accordance with the guidance
provided by the ESR and the vendor. Following the leak repair effort,
the licensee identified that the as left leak rate was essentially the
same as the rate prior to installing the repair clam). The licensee
initiated Condition Report (CR) 97 694 to document t11s problem.
Investigations into the causes of the failed leak repair focused on the
compatibility of the sealant material with EHC fluid; the time and
conditions required for the sealant material to properly cure: and
possible deficiencies with the clamp design and or installation,
c. Conclusion
This was identified as a weakness in the development of work packages
necessary to maintain and support continued operations of the plant.
This leak repair effort required the entry of a number of individuals
into a high radiation area, and resulted in the expenditure of 525 mrem
of dose. The initial work accumulated 408 mrem of dose and an
additional 117 mrem was accumulated during the two subsequent entries to
pump more sealant into the clamp in an effort to get it to seal.
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E7 Quality Assurance in Engineering Activities
E7.1 Plant Evaluation Section (PES) Sitewide Assessment
i a. Insoection Scope (37551)
1 I
, On January 31. 1997, the inspector attended an exit conducted by PES.
] This was an audit required by UFSAR Section 17.3 for a 24 month review.
3
b. Observations and Findinos
There were 11 issues. 7 weaknesses 4 items for management
consideration, and 5 strengths. The assessment group consisted of 12
people, with people from other utilities and other CP&L sites. The
audit was self critical and thorough. Many of tne issues and problems
in the engineering area were raised. Site management was receptive to
the findings.
l
1
Issues as identified on the handout provided during the meeting are I
listed below: l
.
1. "Some persistent equipment problems are not being corrected in a
timely manner.
2. A few station expectations need definition, additional
clarification, or reinforcement by management in order to l
sufficiently challenge station personnel to achieve top quartile i
performance. :
3. Some corrective actions taken by engineering have been ineffective !
in correcting the underlying equipment 3roblems and the backlog of '
o)en corrective actions in the BESS bac(log is increasing.
4. T1e present implementation of the check valve program at BNP does
not meet industry requirements nor the recuirements of ENP 640
" Check Valve Analysis. Tracking, and Trencing Program."
5. Although the site is in the process of implementing an extensive
foreign material exclusion effort. FME-related incidences at the
plant are occurring indicating that further improvements are
necessary, i
6. There is insufficient independent oversight of engineering tasks
to adequately assist in identifying the diagnosing problems with
engineering product and program quality.
7. The outsourcing of engineering products to vendors often result in
poor quality engineering products.
8. Engineering resources have not been effectively focused to improve
engineering performance due to emergent equipment issues and
changing site priorities. 1
9. Deficiencies associated with engineering modifications have
adversely affected the operation of plant equipment and caused
rework and installation delays.
10. Some shortcomings exist in contamination control.
11. Chemistry control in some closed loop cooling systems is not
adequate to ensure stable system conditions and prevent the
ingress of microbiological activity."
-)
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- The weaknesses were as follows:
i
1. "Some areas of the plant have large numbers of minor oil and water
- leaks, degraded protective coatings, and dirt.
!
2. Inconsistent coding is leading to difficulties in trending in the
1 Corrective Action Program.
3. BNP has recognized an administrative procedure adherence problem
,
but has not yet developed a formal integrated plan to resolve the :
<
1ssue.
! 4. Some plant programs are not clearly defined by program documents, I
i
lack a formal designation of ownership, and usually do not require ;
i
'
periodic assessment of program effectiveness.
5. Operators are not following up on all plant deficiencies.
6. The pace at which the reactor operators manipulate controls and
.
. 1
'
monitor plant parameters during simulator exercises causes a
.
'
degradation of the self checking process, crew briefings.
diagnosis of equipment problems, and annunciator response.
7. Unit 2's thermal performance has degraded from 99.9% of target l
heat rate in July 1996 to 98.1% in December 1996 which is below l
the established goals without significant progress being made to
resolve this issue."
The strengths were as follows:
1. "The FIN Team concept is effective in utilizing maintenance
manpower and controlling the maintenance backlog.
2. Cross disciplinary training within the maintenance organization is
cor.r.idered very effective use of manpower and work control
mcuagement.
3. Shift turnovers in O mrations and E&RC groups are very effective. I
4. Pre job briefs are t1orough and all involved personnel take an !
active part. )
5. Excellent performance in Reactor Water Chemistry was achieved i
during 1996." !
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c. Conclusions
.
The inspector concluded that the audit was thorough and self critical. )
Problems in engineering were recognized. Site management was receptive ;
to the issues presented.
E7.2 Nuclear Safety Review Committee
i
a. Insoection Scope (37551)
The inspectors observed several presentations during the BNP Nuclear
Safety Review Committee (NSRC) meeting. This committee was intended to
provide independent insi pts into plant status and operational issues.
b. Observations
On February 16, 1997, the inspector observed several presentations and
discussions during the NSRC meeting. This meeting was not required by
plant TS. The meeting presented plant operational status, causal ;
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27
analysis of post violations, a review of Engineering Improvement
Initiatives, and NAS strengths and issues.
The inspector determined that the licensee presented a good description
of the plant performance and operational status. The meeting did not
take advantage of the opportunity to incorporate industry experience.
c. Conclusions
The inspector concluded that the meeting was a good discussion of plant
performance and problems.
E8 Miscellaneous Engineering Issues (92903)
E.8.1 (Closed) Unresolved Item 50 325(324)/96 15 08: QC Inspection
Requirements for Miscellaneous Structural Steel.
Discussions with licensee engineers and review of CP&L Specification l
248-107, Installation of Seismic Pipe and HVAC Supports and :
Miscellaneous Structural Steel, disclosed that there were no
requirements in Specification No. 248-107 Revision 18. dated August 12, i
1996, for QC inspection of miscellaneous structural steel installation.
The licensee initiated CR 96 04142 to document and disposition the fact
that inspection of safety related miscellaneous structural steel was not
being performed per the requirements of UFSAR Section 1.8. UFSAR
Section 1.8 states that structural steel work performed under the BNP QA
program meet original installation specification requirements,
applicable guidance contained in ANSI N45.2.5 1974, or acceptable
alternatives based upon an engineering evaluation. The licensee's
investigation of this issue disclosed that the inspection requirements
were deleted from the specification in 1986. l
l
The inspector determined that the lack of an program for I
inspection of miscellaneous structural steel did not comply with I
the requirements of 10 CFR 50, Appendix B. Criterion X and the
licensee's Quality Assurance plan which require an inspection
program to verify conformance of activities affecting quality with
requirements specified for those activities. This issue was !
identified to the licensee as (VIO) 50 325(324)/97 02 08, Failure I
to Implement an Inspection Program for Safety Related 1
Miscellaneous Structural Steel. Unresolved item URI 50-
325(324)/96 15-08 is closed.
1
E8.2 (Closed) LER 1 96 02: Unit 1 Manual Reactor Scram Due to Main Turbine l
Vibration. l
This manual trip occurred on January 23, 1996, with Unit 1 operating at ;
28% power. Power was being reduced for a planned shutdown to replace ;
the Scram Pilot Solenoid Vaives (SPSV) when the turbine vibration l
reached plant procedural limits and the operator initiated a manual i
reactor scram. Also, included in this LER was the slow control rod i
insertion times. The licensee supplemented the original LER on May 30, ;
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28
1996. The cause of the increased turbine vibration was determined to be
dia)hragm packing rubs on the recently installed monoblock low pressure
,
'
tur)ine rotors that caused hot spots on the rotor shaft which created
bowing of the rotor shaft. The licensee incorporated recommendations
, for coping with main turbine vibration into the plant shutdown
procedure. The inspector reviewed procedure OGP 05, Unit Shutdown, that
incorporated the changes.
Also, the licensee determined that the cause of the slow control rod
insertion times was the adherence of the SPSVs exhaust diaphragm to the
valve. The diaphragms were changed from the original Buna N to a Viton
dia]hragm. This problem was a generic Boiling Water Reactor (BWR)
-
Owners Group effort and recommendation. The slow scram times were
further reviewed in NRC Inspection Report 96 01 and NRC Information
- notice 96 07. These issues are closed.
IV. Plant Support
- P2 Status of EP Facilities Equipment, and Resources
- P2.1 Facility Inspection
,
4
a. Inspection Scooe (82701)
1
The inspectors examined the licensee's emergency response facilities
(ERFs) and equipment to assess their adequacy and to determine whether i
they were maintained in a state of operational readiness.
b. Observations and Find 1n.gs
The inspectors toured the Main Control Room, Technical Support Center
(TSC), Operational Support Center (OSC), and Emergency Operations l
Facility (EOF). Selected equipinent and supplies within these facilities !
were ins)ected, including the Emergency Response Facility Information
System (ERFIS), miscellaneous telephones, and Selective Signaling ,
System, which was a dedicated telephone system for communicating l
emergency information to State and local officials. All tested :
equipment was found to be in operabit condition. Miscellaneous !
instruments and supplies stored in cabinets in the various facilities I
were selectively examined. The organization of these cabinets was !
excellent, and no discrepancies were identified. ;
In September 1994, the licensee completed major renovations of the TSC
and EOF. The TSC modifications included a new ergonomic facility layout -
and three large, front projection video monitors arrayed across one wall l
of the Command Room. Any of the ERFIS data screens could be displayed
on the video monitors, which were readily visible from all seating
positions in the Command Room. The modifications to the E0F were
similar in nature to those in the TSC. These changes represented a
significant upgrading of the ERFs, and the inspector commended the
licensee's efforts in this regard.
1
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1
The inspectors observed the satisfactory conduct of the routine monthly j
! test of the emergency diesel generator for the TSC/E0F building, as
1 performed in accordance with procedure OPM GEN 008. Covington Diesel
i Generator Electrical Inspections. Operational problems with the
i generator that arose during Hurricane Fran in September 1996 had been
identified and repaired.
'
The following records of surveillances and aeriodic tests of emergency
i supplies and equipment were inspected for t1e period 1995 1996: i
'
e OPT 93.0, E0F/TSC Building Emergency System Test
j e OPEP 04.2, Emergency Facilities and Equipment
,
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e OPEP 04.6, Radiological Emer u ency Kit Inventories
i
i Surveillances and tests as specified by the above procedures were
i
performed at the required frequencies. No discrepancies were noted by
'
the inspectors. The documentation indicated that deficiencies
identified during the surveillances were expeditiously corrected.
,
c. Conclusions
'
Emergency response facilities were well equipped and were maintained at
a suitable level of operational readiness.
j P2.2 Public Alert And Notification System
a. Insoection Scope (82701)
1
The inspectors reviewed the licensee's methodology for notifying the
public in the event of an emergency, and the results of system testing
<
during 1995 and 1996.
! b. Observations and Findinas
The licensee maintained a public alert and notification system
consisting of 34 sirens within the 10 mile Emergency Planning Zone (EPZ)
around the Brunswick Nuclear Plant. The inspectors reviewed the summary
data (as transmitted to the Federal Emergency Management Agency) for
i 1995 and 1996 testing of the siren warning system. For the 34 sirens.
.
the aggregate success rates of the biweekly silent tests, quarterly
1
growl tests, and annual full cycle test were 98.3% for 1995 and 98.0%
for 1996. The success rates of the full cycle test alone were 91.2% for
1995 and 94.1% for 1996. These rates implied a strong surveillance /
maintenance progrsa by the licensee.
j c. Conclusions
The operational status and maintenance of the siren system exceeded
regulatory requirements.
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30
P3 EP Procedures and Documentation
P3.1 Emeroency Resoonse Plan
a. Insoection Scope (82701)
The inspectors reviewed the licensee's maintenance of the Emergency
Response Plan (ERP) and selected commitments therein, and reviewed
recent revisions to the ERP.
b. Observations and Findinas
Since the previously referenced May 1994 inspection, the NRC has
received Revisions 38 through 45 of the ERP. The version of the ERP in
effect at the time of the current inspection was Revision 45, effective
November 3, 1996. The inspectors reviewed Revisions 44 and 45 and
determined that the changes were primarily administrative in nature,
with some minor organizational modifications.
Between the May 1994 inspection and the ending date of the current
inspection, seven emergency declarations were made by the licensee, all
at the Notification of Unusual Event (NOUE) level. Three of these
declarations were the result of a hurricane warning being posted for the
area (Hurricanes Felix in August 1995 . Bertha in July 1996, and Fran in
September 1996). Two others were caused by the loss of audible alarms
in the Control, Room for more than 15 minutes. The inspectors examined
licensee documentation for the seven NOVE declarations, and concluded
that each was correctly classified based on the licensee's emergency
action levels (EALs), and that notifications to cognizant offsite
authorities were made in accordance with requirements regarding
timeliness and content.
,
Documental review confirmed the licensee's conduct of the required
annual review of EALs with State and local governmental authorities for
1995 and 1996. This review was accomplished annually by means of a j
formal presentation to cognizant officials during meetings of the '
Brunswick Task Force. No dissenting observations or comments were i
received from those agencies, according to the licensee. '
c. Conclusions
Changes made to the ERP since the May 1994 inspection and implementation
of selected Plan commitments met regulatory requirements.
P3.2 Plant Emeroency Procedures
a. Insoection Scope (82701)
The inspectors reviewed the licensee's adminia ration of selected ERP
requirements through evaluation of the adequacy of the implementing
details contained in the Plant Emergency Procedures (PEPS).
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! b. Observations and Findinas
)
In accordance with regulatory requirements and guidance, the licensee
developed criteria to be used to determine when and how, following an
'
accident,-reentry and recovery activities would be initiated.
Section 7.0 of the ERP was a 13 page aresentation of the licensee's
!
concept of operations for recovery. iowever, the PEPS did not include a
procedure for implementation of this section of the ERP. Section 1.3.1
of the Plan stated that " Specific plant implementing procedures have
been developed ... to describe in detail how involved plant and
corporate personnel carry out their specific responsibilities as
identified in the Plan" [ emphasis added]. The only substantive
reference to recovery identified in the PEPS was in Section 5.1 of
,
OPEP 02.6.27, Activation and Operation of the Emergency Operations
l Facility, in which six basic steps for recovery were listed for the
! Emergency Response Manager's consideration, with reference to the Plan
i as the primary source of information in the area of recovery. Use of
the Plan to implement a PEP is not in accordance with the Plan
recuirements for implementing procedures as quoted above. The licensee
, hac identified the need for an implementing procedure for recovery as
'
long ago as 1995, but had not yet completed the development of same. A
{ draft version was scheduled for completion and issuance by May 31, 1997.
- No other examples of ERP commitments without appropriate PEP
P
implementing details were identified by the inspectors.
l
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Selected copies of the Pian and PEPS which were available for use at the
! Control Room, TSC, OSC, and EOF were checked and found to be current I
j revisions. I
i c. Conclusions
The licensee *s failure to have a procedure to adequately implement the I'
section of the ERP addressing recovery was identified as a violation, in
, that 10 CFR 50.54(q) requires that nuclear power plant licensees follow
L and maintain in effect their approved emergency plans. Licensee
3 management committed to the completion of corrective action for this {
- violation by May 30, 1997. This licensee-identified violation is being 1
treated as a Non Cited Violation (NCV), consistent with Section VII.B.1
of the NRC Enforcement Policy NCV 50-325(324)/97 02 09. Inadequate :'
procedure for implementing the section of the ERP addressing recovery.
P5 Staff Training and Qualification in EP
P5.1 Trainina of Emeraency Response Personnel l
a. Inspection Scoce (82701)
The inspectors conducted a broad perspective review of the training
program for the emergency response organization (ERO) to determine
whether ERP requirements and the intent of regulatory requirements were
being met.
_ _ _ _ _ _ _ _ _ _ _ _ _
32
b. Observations and Findings
The inspectors reviewed the two procedures which primarily implemented
the ERO training program:
e Training Instruction TI 306 Emergency Preparedness Training
Program, Revision 9
e Training Administrative Procedure TAP-6.16, Administration of the
Emergency Preparedness Training Program and ER0 Qualification
Checklists, Revision 2
These procedures reflected the implementation of major changes in the
ERO training program which occurred in 1995. These included the
requirement for specialized training for all ERO personnel (clearly
delineated by position in a detailed matrix), and a requirement for
persons filling 23 designated ERO positions to participate in an
exercise or drill as part of the qualification process, and annually
thereafter.
c. Conclusions
The licensee's ER0 training 3rogram was in accordance with the ERP
training commitments and wit 1 the intent of NRC regulatory requirements
and guidance.
P5.2 Emeroency Response Drills
a. Inspection Scope (82701)
The inspectors compared the licensee's drill commitments to the actual
drills performed, and evaluated the quality of those drills,
b. Observations and Findinas
The inspectors reviewed the documentation packages for ten training
drills that were conducted in 1995 1996. The scenarios were
challenging, and the licensee's critiques of the drills were objective.
The drill comments were appropriately documented. tracked, and resolved.
Each of the five TSC/OSC/ EOF teams (serving in weekly rotation)
participated in at least one drill per year. Beginning in March 1997,
the licensee planned to conduct these team drills in coordination with
licensed operator requalification activities so that these drills would
be Control Room simulator-driven. This approach had the potential to
provide a major enhancement to the ERO training program.
The licensee used a computer driven notification system for off hour
augmentation of the ERO with two distinct manual backup systems which
were tested regularly. Off hour ERO augmentation drills involving
actual travel to the plant were conducted four times in 1995 to develop
and ensure adecuate performance (although the licensee was committed to
only one such crill every 24 months). The first of those was
. - - .. . - - . . . - - . . -.-
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33
unsuccessful and resulted in remedial day shift drills to practice the
mechanics of the process. The last of these 1995 drills yielded ERF
staffing times well within the licensee's commitments. Pager drills for
ERO personnel were conducted' monthly beginning in 1996.
c. Conclusions
! The licensee's program of emergency response training drills appeared to
be a strength.
P6 EP Organization and Administration
l
a. Inspection Scope (827011
The inspectors reviewed this area to determine if any changes in
management or personnel had occurred which could negatively affect the
management and implementation of the emergency preparedness program.
b. Observations and Findinas
The organization and management of the emergency preparedness program
were reviewed and discussed with licensee representatives. Several
personnel changes since the May 1994 inspection affected the emergency
planning function, including reassignment in March 1995 of the position
of Supervisor Emergency Preparedness. At the time of the inspection,
this position was temporarily reporting to the Manager - Site Su] port
Services who reported to the Vice President Brunswick Nuclear )lant.
Based upon discussions with various management and staff personnel, the
inspector concluded that organizational and management personnel changes
did not decrease the effectiveness of the emergency preparedness.
program,
c. Conclusions
No degradation had occurred in the organization or management of the
emergency preparedness program. Emergency preparedness appeared to be
receiving strong management support at Brunswick.
P7 Quality Assurance in EP Activities
P7.1 10 CFR 50.54(t) Audit of Emercency Preparedness Proaram
a. Inspection Scoge (82701)
The inspectors reviewed this area to assess the quality of the required
audit, the qualifications of the auditors, and to verify that the audit
met the requirements of 10 CFR 50.54(t).
b. Observations and Findinas
The licensee's Nuclear Assessment Section (NAS) conducted extensive,
two week audits in 1995 and 1996. The March 1995 audit, documented in
_.
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34
NAS Report File No. B-EP-95 01, identified no strengths or weaknesses,
one issue, and two items for management consideration. The March 1996
audit, documented in NAS Report File No. B EP 96 01, identified two
strengths, no weaknesses, two issues, and two items for management
consideration. These audits were judged to be thorough, detailed, and
aggressively independent. Furthermore, the audits represented a clear
demonstration of the licensee's ability to self-identify and correct
emergency preparedness program deficiencies.
The EP staff began a arogram of quarterly self assessments in 1995. The
inspectors reviewed t1e reports of this program from 1996, and
determined that the self-assessments were producing useful results,
including trending information on ERO performance.
c. Conclusions
The NAS audits fully satisfied the 10 CFR 50.54(t) requirement for an
annual independent audit of the EP program.
R7 Quality Assurance in Radiological Protection and Chemistry Activities q
R7.1 Unlabeled Boron Containers
a. Inspection Scooe (71750)
i
'
During a routine tour of the Unit 2 reactor building the inspector
identified an issue concerning the control of waste materials.
l
b. _Fjn@os and Conclusions
On January 29 30, 1997, during a routine tour of the Unit 2 reactor
building the inspector observed 10 unattended 55 gallon drums on the 50
foot elevation. These drums contained the boric acid solution that was
drained from the Standby Liquid Control (SLC) storage tank to allow for
the chemical addition later on January 30. Administrative Instructions
0AI 132, 011. Liquid Waste from Planned Maintenance Activities and Hop
Water Management Program and 0AI 121, Chemical / Consumable Use Program,
required that material transferred to secondary or temporary containers
have an identification label attached describing the status, contents,
rad all appropriate chemical control and hazard information. The
inspector observed no markings on the containers. Additional unlabeled
containers of boric acid solution were observed on the 20 foot elevation
in Unit 1. The inspector discussed this finding with the licensee and
Condition. Report (CR) 97 547, Unlabeled Barrels, was initiated.
10 CFR 50 Appendix B, Criterion VIII, Identification and Control of
Materials, Parts, and Components, requires that measures shall be
established for the identification and control of materials, aarts, and
components. These identification and control measures shall 3e designed
to prevent the use of incorrect or defective material, parts, and
com>onents. Regulatory Guide 1.38, Quality Assurance Requirements for
Paccaging, Shipping, Receiving, Storage, and Handling of Items for ;
i
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35
Water-Cooled Nuclear Power Plants, accepts the requirements as outlined
in American National Standards Institute (ANSI) N45.2.2 - 1972,
Packaging, Shipping, Receiving, Storage and Handling of Items for
Nuclear Power Plants During the Construction Phase, for meeting 10 CFR
Appendix B quality assurance requirements.
Additionally, the licensee commented to this regulatory guide and ANSI
standard in section 1.8 of the UFSAR and is implemented through the CP&L
Corporate Quality Assurance Program Section 5.2 and Nuclear Generation
Group Standard Procedures MCP NGGC 0401, Material Acquisition, and MCP-
NGGC-0402, Material Management. The failure to adequately control
materials to prevent the use of incorrect or defective material was
identified as the first example of violation VIO 50-325(324)/97 02 10,
SLC Chemical Addition.
Further observations regarding control of boric acid are contained in
Section R7.2.
a. Inspection Scope (71750)
The inspector observed the implementation of these requirements during
the addition of sodium pentaborate to the (SLC) storage tank by
Chemistry personnel.
b. Observations and Findinas
On January 29 30, 1997, the inspector observed activities associated !
with the addition of sodium pentaborate (boron) to the SLC storage tanks !
for both units. The performance of these activities was controlled by '
two procedures Operations Procedure 20P 05 Standby Liquid Control )
System, and Environmental and Radiation Control Procedure OE&RC-1130,
Chemical Addition and Determination of Sodium Pentaborate Solution in '
Standby Liquid Control Tank. The inspector observed the pre-job )
briefing between the Operations personnel and the Environmental and !
Radiation Control (E&RC) responsible supervisors.
The inspector reviewed the assessments conducted in 1995 and 1996 of the
licensee's material handling and storage practices. The assessments
showed long term problems with the licensee's material handling and
storage. The licensee developed corporate procedures to correct these
problems. Other problems identified included poor quality of recei)t
inspections and item traceability. The inspector determined that t1e
failure to adequately address deficiencies affecting the receipt,
storage, and handling of materials contributed to the chemical control
issues discussed in this section. The failure to effectively correct
previously identified deficiencies in the receiving and storage of
materials was seen as a weakness.
The inspector reviewed the precautions and limitations contained in
OE&RC 1130 at the jobsite. Among the precautions was an item requiring
- - - - .- . ___ _. -
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the chemicals to have a QA Accept label attached. The inspector
examined all six of the containers in the work area and identified two
containers marked with a number on the side but without QA Accept labels
to indicate the quality status upon receipt onsite. The licensee had
verified the 3recautions and limitations complete and had completed air
sparging of tie SLC tank in preparation for chemical addition. The
inspector discussed the labeling issue with the personnel present. The-
SR0 present and the field E&RC supervisor halted work until verification
that the chemical had been properly received was obtained. The absence
of the labels indicating the quality status of the chemical could have
allowed the introduction of incorrect or defective materials into the i
SLC System.
The indications on the side of the containers were later identified as
numbers used during material procurement, these numbers did not indicate l
the material quality status. The status information for the unlabeled j
containers was later identified on a separate container. After I
discussions with the licensee, this issue was described in CR 97 466, l
Chemical Addition to U/2 SLC. The inspector concluded that the numbers !
and multiple container listings were inconsistent with the MCP NGGC 402
requirements and would be insufficient to provide adequate status due to
the difficulty identifying the containers current quality status should I
containers of this size become separated in the work area. The failure i
to adequately control materials in accordance with OE&RC 1130, Chemical !
Addition and Determination of Sodium Pentaborate Solution in Standby
Liquid Control Tank, to prevent the use of incorrect or defective l
i
material was identified as the second example of VIO 50 325(324)/97 02- !
10, SLC Chemical Addition Labeling Problems. 1
The ir,spector reviewed applicable purchase orders, toured the receiving I
and storage warehouses and various storage areas, and on February 10,
1997, the inspector identified, in the turbine laydown area, over 40
drums of electro hydraulic control fluid with inconsistent or
nonexistent labeling. This issue was described in CR 97 632, Chemical
Control Program. Subsequent licensee actions have included assessments
of worker knowledge of the chemical control requirements and walkdowns
to determine the adequacy of the chemical control program throughout the
protected area and Materials & Contract Services areas. The results
identified deficiencies in worker knowledge, labeling, and storage and
were recorded in the licensee's root cause assessment and CRs 97 846,
97 848, 97 851, 97 856, and 97 859. CR 97 893, Chemical Handling
Errors, indicated that the conditions identified in the material
handling assessment as recorded in the CRs mentioned above, suggested a
wide spread adverse trend in the handling of site chemicals. Among the
items identified were deficiencies in the labeling and storage of
chemicals in the turbine, radwaste, and various other buildings within
the protected area.
The inspector discussed the labeling issues with the licensee. The
licensee indicated that communication of site expectations for chemical
control requirements would be performed, labeling inconsistencies would
. - _ _ -
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be corrected, and all affected procedures would be revised to eliminate
j procedural inconsistencies with existing regulatory requirements.
c. Conclusions
The inspector observed portions of the boron addition to the SLC storage
tank. A violation with two examples was identified for failing to
provide adequate controls to prevent the introduction of incorrect or
defective materials. The failure to effectively correct previously
identified deficiencies in the receiving and storage of materials was
seen as a weakness. -
R7.3 Personnel Contaminations ,
i
a. Insoection Scope (71750)
l
The inspector reviewed the completed CRs for two problems dealing the l
contamination control. The first CR was 97 00163. Personnel '
Contamination: HST Particle Inside Shoe. The second CR was 97 00261. 1
Increase in Personnel _ Contamination Events resulting from Discrete
Particles. These events were initially reviewed in NRC IR 96-18 under
paragraph R2.3. J
b. Observations and Findinos I
l
The first event involved an auxiliary operator that had a hot particle ;
inside his shoe and took the shoe home. Personnel monitor alarms had '
been received at different times by the operator during the course of I
the work day, but he was released to go home because his shoe passed a '
RM 14 monitor. The licensee's review of this event determined that the
shoe had failed to pass a Small Article Monitor. The technician that
released the operator made a nonconservative decision concerning the
release of the shoe. The technician received disciplinary action
concerning this decisions.
The licensee also initiated action to revise procedures providing clear
guidance for steps to be take regarding monitor alarms and conflicts.
The licensee determined the individual probably got the particle on his
shoe after he removed his shoes to put on protective clothing. The
licensee assigned a calculated extremity exposure of 220 mrem to the
operator.
The second event was determined to be an increase of discrete particles l
from under vessel Control Rod Drive (CRD) activities during the full l
Unit 1 refueling outages. During the outage several CRD mechanisms were
replaced. The licensee's review determined that there were several
transport mechanisms for disbursal of these particles. One issue was
the decreased effort in housekeeping during the holiday season. There
had been instances where contaminated area mop heads were mixed in with
clean area mop heads. Other issues were identified with laundering of
protective clothing. Several corrective actions were initiated to
address these issues.
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c. Conclusions
The inspector concluded that these events were thoroughly reviewed by
the licensee and corrective actions initiated. The licensee reviewed
these problems with the level of detail necessary to address the cause
and issue adequate corrective action.
R8 Miscellaneous Radiological Protection and Chemistry Issues (92904)
R8.1 (Closed) Violation 50 325/96-01 02: Missed Surveillance.
1 Closed) LER 1-96 01: Technical Specification Required Surveillance Not
Performed Within Allotted Time.
These two items documented the licensee's failure to perform a
Technical Specifications (TS) required surveillance within the
required time period. On December 6, 1995, the Unit 1 Reactor
Building Vent was sampled and analyzed for tritium in accordance
with the requirements of TS 4.11.2.1.2. Based on the results of
this sample, licensee then established a due date for the next
sample performance of January 5,1996, with an overdue date of
Januey 12, 1996. On January 15, 1996, it was identified that the
sample had not.been performed in accordance with the TS
requirement.
Investigation into the missed surveillance identified that the
Environmental and Radiation Control (E&RC) personnel had relied
solely on the Surveillance Test Scheduling System (STSS) to
schedule and track the performance of required surveillance. The
licensee event investigation determined that the STSS
Completion / Exception form had been misplaced by E&RC personnel and
not returned to scheduling for incorporation. This resulted in
the E&RC 3ersonnel failing to recognize the need to schedule or
perform t1e surveillance. Poor communication between scheduling
and E&RC personnel prior to the approaching due date failed to
identify that the Completion / Exception form had not been returned
to scheduling.
The licensee documented this missed TS Surveillance in Licensee
Event Report (LER) 1 96 01 Technical Specification Required
Surveillance Not Performed Within Allotted Time, issued
February 14, 1996. The inspector reviewed this event at the time
of occurrence, and documented it in NRC Inspection Report
50 325(324)/96 01, as violation 50 325/96-01 02, Missed
Surveillance.
In response to the event and subsequent violation, the licensee
initiated and committed to the following corrective actions in LER
1 96 01: satisfactorily performed tritium sample and analysis on
January 15, 1996 scheduling reviewed and identified those
surveillances which were within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> of an overdue date: E&RC
incorporated all TS required surveillance into the Automated
_
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39
[ Maintenance Management System (AMMS), to ensure incorporation into
daily schedule: E&RC management provided clear responsibilities
and accountabilities for E&RC personnel to ensure required
surveillance are performed as scheduled; and other work groups TS
- required surveillance were reviewed and incorporated into the work
management system by March 29, 1996.
The ins >ector has reviewed these completed corrective actions, and
. finds t1em acceptable for the closure of both Violation 50 325/96-
j 01 02, and LER 1-96-01.
V. Manaoement Meetinas
XI Exit Meetina Summary
The inspector presented the inspection results to members of licensee
, management at the conclusion of the inspection on March 10, 1997. Post
! inspection briefings were conducted on January 31, February 7, and
- February 14, 1997. The licensee acknowledged the findings presented.
4
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PARTIAL LIST OF PERSONS CONTACTED
Licensee
G. Barnes, Manager Training
A. Brittain, Manager Security
W. Campbell, Vice President, Brunswick Steam Electric Plant
J. Cannon, Project Engineer, Electrical
C. Cashwell, Supervisor - Emergency Preparedness
R. Delong, Supervisor. Electrical / Instrumentation and Control ,
N. Gannon,-Manager Maintenance
J. Gawron, Manager Nuclear Assessment
T. Groblewski, Suxrintendent Quality Control. NAS
K. Jury, Manager Regulatory Affairs
W. Levis, Director Site Operations
B. Lindgren, Manager - Site Support Services
R. Lopriore, General Plant Manager
J. Lyr.sh, Brunswick Engineering Support Section
R. Miller, Superintendent, Design Control. Nuclear Engineering
C. Pardee, Manager Operations
R. Schlichter, Manager Environmental and Radiation Control
S. Tabor, Senior Specialist, Regulatory Compliance
L. Troutman, Project Engineer, Electrical
M. Turkal, Manager, Licensing and Regulatory Programs
H. Wall, Training Supervisor
R. Williams, Manager EQ Task Force, BESS
H. Willetts, Supervisor, Instrumentation Control
Other licensee employees or contractors included office, operation,
maintenance, chemistry, radiation, and corporate personnel.
E. Brown ;
J. Coley l
M. Janus '
J. Kreh i
J. Lenahan l
C. Patterson l
M. Shymlock l
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,
INSPECTION PROCEDURES USED ,
=/ 37550: Engineering
IP 37551: Onsite Engineering
IP 40500: Effectiveness of Licensee Controls in Identifying, Resolving, and
Preventing Problems
IP 61726: Surveillance Observations
4
IP 62700: Maintenance Program Implementation
IP 62707: Maintenance Rule
IP 71707: Plant Operations
IP 71714: Cold Weather Preparations
- IP 71750: Plant Support Activities
,- IP 82701: Operational Status of the Emergency Preparedness Program
l IP 92902: Followup - Maintenance
- IP 92903
- Followup Engineering
IP 92904: Followup Plant Support
- ITEMS OPENED CLOSED, AND DISCUSSED
1 .
2
Opened
50 325(324)/97-02 01 VIO Locked Valve Out of Position (paragraph 01.1)
- 50-325(324)/97 02-02 URI Recirculation Pump Transients (paragraph 01.2)
4
50 325(324)/97-02 03 IFI PH Frequencies Based on Appropriate Plant Fuel
]; Cycle (paragraph M1.1)
'
50-325(324)/97 02 04 VIO Failure to Implement Maintenance Rule
Requirements (paragraph Hl.1)
4
-
50-325(324)/97 02 06 VIO ESR Design Verification Requirements (paragraph I
E1.1)
50-325(324)/97 02-07 VIO Failure to Initiate CR for HPCI Valve Time 1
'
Discrepancy (paragraph E1.4)
1 50 325(324)/97-02-08 VIO Failure to Implement an Inspection Program for
4
'
Safety Related Miscellanm us Structural Steel ,
(paragraph E8.1) l
.
50-325(324)/97-02 10 VIO SLC Chemical Addition Labeling Problems
(paragraph R7.1 & R7.2)
Closed
50 325(324)/97 02 05 NCV Failure to Follow Procedure for Establishing
Communications (paragraph M3.1)
. . - - . . . _ . - - - = . . - - . -- -- - -. _ - . - - _ _ .
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50 325/95 07 LER Safety Relief Valves Tested at Wyle Laboratories
Exceeded Technical Specification Setpoint Limits
- (paragraph M8.1)
50 324/96 02 LER Safety Relief Valves Tested at Wyle Laboratories
Exceeded Technical Specification Setpoint Limits
(paragraph M8.1)_ ,
{ 50 325/96 13 LER Safety Relief Valves Tested at Wyle Laboratories
l Exceeded Technical Specification Setpoint Limits
(paragraph M8.1)
-
50 325/95 13 LER During High Pressure Coolant Injection System
i~ Surveillance a Ground was Noted Affecting System
Instrumentation (paragraph M8.2)
j -
50 325/95 19 05 and VIO Design Review Did Not Adequately Isolate DC
- 50 325/95 166-1013 Power Supply (paragraph M8.2)
50 325/95 19 06 VIO Post Modification Testing of HPCI-RCIC Inverter
- 50-325/95 166 1023 and Flow Controller Replacement (paragraph M8.2)
l 50 325(324)/96 15 08 UR1 OC Inspection Requirements for Miscellaneous
Structural Steel (paragraph E8.1)
50 325/96 02 LER Unit 1 Manual Reactor Scram Due to Main Turbine l
j Vibration (paragraph E8.2) l
.
50 325/96 01-02 VIO Missed Surveillance (paragraph R8.1) ;
50 325/96 01- LER Technical Specification Required Surveillance
, Not Performed Within Allotted Time (paragraph ,
1 R8.1)
.
Discussed
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