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| ML18152A078 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 10/30/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18152A079 | List: |
| References | |
| 50-280-97-09, 50-280-97-9, 50-281-97-09, 50-281-97-9, NUDOCS 9711190189 | |
| Download: ML18152A078 (32) | |
See also: IR 05000280/1997009
Text
Docket Nos:
License Nos:
Report Nos:
Licensee:
Facility:
Location:
Dates:
Inspectors:
Approved by:
.9711190189 971030
ADOCK 05000280
G
U.S. NUCLEAR REGULATORY COMMISSION
REGION II
50-280, 50-281
50-280/97-09 and 50-281/97-09
Virginia Electric and Power Company (VEPCO)
Surry Power Station. Units 1 & 2
5850 Hog Island Road
Surry, VA 23883
August 24 - October 4. 1997
R. Musser. Senior Resident Inspector
K. Poertner. Resident Inspector
P. Byron. Resid~nt Inspector
L. Garner. Project Engineer (Section M8.2)
R. Gibbs. Reactor Inspector (Section M8.1)
W. Miller. Reactor Inspector (Sections F2.1. F2.2. and
F8.1)
D. Payne. Reactor Inspector (Section 05.1)
R. Haag, Chief. Reactor Projects Branch 5
Division of Reactor Projects
Enclosure 1
EXECUTIVE SUMMARY
Surry Power Station. Units 1 & 2
NRC Inspection Report Nos. 50-280/97-09.50-281/97-09
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
announced inspections by four regional inspectors.
Operations
Licensee actions to repair a minor through wall leak on service water
piping were conducted in a conservative manner.
Operations personnel
exhibited a good questioning attitude during identification of the
leaking service water line (Section 01.2).
The inspectors verified that Technical Specification requirements were
satisfied during Unit 1 operation with both Pressurizer Powered Operated
Relief Valves (PORVs) isolated (Section 01.3).
A Non-cited Violation was identified for an inadequate procedure that
resulted in an inadvertent makeup to the spent fuel pool from the Unit 2
refueling water storage tank.
The inspectors concluded that the
corrective actions implemented should prevent recurrence (Section 01.4).
Hydrogen concentration has continued to decrease within the Unit 1
containment following installation of a portable autocatalytic
recombiner.
The portable recombiner appears to be functioning
appropriately to reduce hydrogen concentration (Section 01.5).
For the specific areas inspected. the Surry Operator Requalification
program fully meets the requirements. and intent of 10 CFR 55.59(c).
The inspectors noted much improvement in the operator requalification
program since the last inspection of the program (Section 05.1).
Maintenance
Maintenance performed on the Emergency Service Water Pumps was completed
in a satisfactory manner.
Problems with marine growth on the pumps have
not been adequately resolved.
An inspection followup item is being
opened to track the licensee's resolution of this matter (Section Ml.1).
The licensee has made an effort to determine the cause of No. 1
emergency diesel generator louver controller failures but has not been
successful. Additional effort is required to repair and return the east
bank of louvers to a fully functional condition.
Maintenance personnel
were deliberate and acted in a professional manner during
troubleshooting activities (Section Ml.2).
Reactor Protection System Logic Testing was performed in an excellent
manner (Section Ml.3).
Enclosure 1
2
The licensee's deferral of the A Reactor Coolant Pump seal inspection
during the upcoming Unit 2 outage could result in a mid-cycle
maintenance outage, but does not preclude safe operation of the unit.
Licensee commitments for the Unit 2 outage were reviewed and found to be
within the scope of the outage (Section Ml.4).
The licensee's actions with regard to surveillance. testing and
maintenance of the auxiliary shutdown panels and the remote monitoring
panels were excellent (Section MB.1).
Foreign material exclusion worker qualification training was considered
a strength in that it personalized the negative affects that foreign
material can have on employee safety and dose. as well as. the economic
impact on the company (Section MB.2).
Engineering
- The Safety Evaluation addressing service water expansion joint
operability was thorough and adequately justified system operability.
The decision to defer modification of the Unit 2 expansion joints inside
the containment for approximately two weeks until a scheduled refueling
outage appeared appropriate (Section El.1).
Plant Support
Health physics practices were observed to be proper (Section Rl).
An Emergency Preparedness exercise was conducted August 26.
Regional
personnel and the resident inspectors participated in the exercise
(Section Pl).
Security and material condition of the protected area perimeter barrier
were acceptable (Section Sl).
Two apparent violations were identified for inadequate fire protection
features which failed to meet the requirements of 10 CFR 50 Appendix R.
The control room complex and safety related vital electrical panels were
not fully protected. such that one train of systems necessary to achieve
and maintain hot shutdown condition from either the control room or
emergency control stations would be free of fire damage (Section F2.1).
Two apparent violations were also identified for the failure of the
licensee to report these discrepancies to the NRC and for the failure to
correct these discrepancies in a timely manner (Section F2.1).
Excellent housekeeping was provided for the Radwaste Facility with good
implementation of the station's fire prevention procedures and
maintenance of the fire protection equipment (Section F2.2).
A justification for changes to the Radwaste Facility building structure.
equipment and facility process was not being maintained. This was
identified as an Inspection Followup Item (Section F2.2).
3
The licensee took positive action to enhance the preventive maintenance
being performed on the storage of spare safety related electric motors
and rotating mechanical components (Section FB.1).
A Non-cited Violation was identified concerning the failure to perform
fire watch tours within the specified one hour time frame (Section
FB.2).
Report Details
Summary of Plant Status
Unit 1 operated at power the entire reporting period.
On September 15 a power
reduction was commenced in anticipation of a Technical Specification (TS)
required shutdown due to an inoperable service water flowpath.
The power
reduction was terminated at 99.25 percent power when the TS action statement
was exited and the unit was returned to 100 percent power.
The unit operated
at power for the remainder of the inspection period.
Unit 2 operated at power the entire reporting period.
On September 10 power
was reduced to approximately 81 percent to repair a leak on the A condenser
waterbox outlet piping. The leak was repaired and the unit returned to 100
percent power that same day.
The unit operated at power for the remainder of
the inspection period.
I. Operations
01
Conduct of Operations
01.1 General Comments (71707. 40500)
The inspectors conducted frequent control room tours to verify proper
staffing. operator attentiveness. and adherence to approved procedures.
The inspectors attended daily plant status meetings to maintain
awareness of overall facility operations and reviewed operator logs to
verify operational safety and compliance with TSs.
Instrumentation and
safety system lineups were periodically reviewed from control room
indications to assess operability. Frequent plant tours were conducted
to observe equipment status and housekeeping. Deviation Reports CDRs)
were reviewed to assure that potential safety concerns were properly
reported and resolved.
The inspectors found that daily operations were
generally conducted in accordance with regulatory requirements and plant
procedures.
01.2 Service Water Piping Leak
a.
Inspection Scope (71707)
The inspectors reviewed licensee actions associated with a through wall
piping leak in the service water system.
b.
Observations and Findings
On September 14. at 11:10 a.m .. operations personnel identified a minor
through wall leak on a service water line located in mechanical
equipment room number 3.
The leak developed in a 6 inch to 4 inch
reducer immediately upstream of valve 2-SW-309.
Initial discussions
with engineering personnel indicated that an operability concern did not
exist. however. subsequent review by engineering determined that the
r
C .
2
through wall leak rendered the line inoperable. This determination was
communicated to the operating crew at approximately 6:42 p.m. and a 24
hour TS action statement on both units was entered.
The TS action was
entered at 11:10 a.m .. the time the leak was identified.
TS 3.14 requires two operable service water flow paths to the charging
pump service water subsystem.
With only one operable flow path TS 3.14.d requires that two flowpaths be restored within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or the
unit be placed in hot shutdown.
The location of the leak resulted in
only one operable service water flowpath on both units.
The service
water line was isolated and tagged out at 10:50 p.m. for maintenance.
The line was repaired and returned to service at 10:04 a.m. on September
15.
Prior to the return to service of the second service water flowpath
a power reduction was commenced on Unit 1 at 9:36 a.m. in anticipation
of a required dual unit shutdown if maintenance activities were not
successful in returning the flowpath to an operable condition. The Unit
1 power reduction was terminated with the unit at 99.25 percent power
when the service water line was returned to service. The initiation of
a power reduction was determined not to be reportable to the NRC since
the service water flowpath was returned to service prior to the
expiration of the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> action statement.
Conclusions
Licensee actions to repair a minor through wall leak on a service water
flowpath were conducted in a conservative manner.
Operations personnel
exhibited a good questioning attitude during identification of the
leaking service water line.
01.3 Unit 1 Operation With both Pressurizer Power Operated Relief Valves
CPORVs) Isolated
a.
Inspection Scope (71707)
b.
The inspectors reviewed the TS requirements for unit operation with both
pressurizer PORVs isolated.
Observations and Findings
On September 16. at 7:09 p.m .. the block valve associated with PORV 1-
RC-PCV-1455C was closed to isolate the PORV.
The other PORV block valve
had been closed earlier in the cycle due to PORV seat leakage.
Isolating 1455C resulted in both PORVs being isolated. The block valve
was shut to determine the effect on Reactor Coolant System (RCS) leakage
and Primary Relief Tank (PRT) parameters.
TS 3.1.A.6 allows operation
with both PORVs isolated as long as the PORVs can be manually cycled and
power is maintained on the associated block valve.
The 1455C block
valve was reopened at 9:20 p.m. on September 18.
PORV tailpipe
temperatures decreased when the block valve was shut and PRT parameters
stabilized but RCS leakage was *not affected.
The block valve remained
open for the remainder of the reporting period.
3
c. Conclusions
The inspectors verified that TS requirements were satisfied during Unit
1 operation with both pressurizer PORVs isolated.
01.4 Inadvertent Spent Fuel Pool CSFP) Makeup from Unit 2 Refueling Water
Storage Tank (RWST).
C.
a.
Inspection Scope (71707)
The inspectors reviewed the circumstances surrounding an inadvertent
addition to the SFP from the Unit 2 RWST.
b. Observations and Findings
On August 30. while Unit 1 operators were performing procedure 1-0P-FC-
001. "Spent Fuel Pool Makeup," Revision 3. to makeup to the SFP from the
Unit 1 blender. the operating crew determined that Unit 2 RWST level was
slightly decreasing.
Procedure 1-0P-FC-001 was secured and the makeup
to the SFP was terminated after approximately 1000 gallons of water had
been added.
Investigation determined that procedure 2-0P-CS-005.
"Purifying Unit 2 RWST." Revision 3. was in progress on Unit 2 and this
procedure aligned the Unit 2 RWST through the SFP ion exchanger.
When
procedure 1-0P-FC-001 was initiated the operator opened manual valve
1-FC-69 and this resulted in a flowpath from the Unit 2 RWST to the SFP .
The misalignment was recognized and corrected within 10 minutes.
level and SFP level remained in the normal operating band. Operations
issued a deviation report documenting that the procedures were
inadequate in that they did nqt properly verify system alignment prior
to commencing a makeup from the Unit 1 blender. The Unit 2 RWST
recirculation procedure was revised to require that valve 1-FC-69 be
tagged closed to prevent an inadvertent addition to the SFP from the
Unit 2 RWST.
The inspectors discussed this event with the operating
crew and operations supervision and reviewed the deviation report and
the procedure change initiated to prevent recurrence.
The inspectors
concluded that procedure 1-0P-FC-001 was inadequate in that it did not
verify proper system alignment prior to initiating a makeup to the SFP
and that the corrective actions implemented should prevent another
inadvertent addition to the SFP from the Unit 2 RWST.
This non-
repetitive. licensee-identified and corrected violation is being treated*
as a Non-cited Violation (NCV) consistent with Section VII.B.1 of the
NRC Enforcement Policy. This matter is identified as NCV 280.
281/97009-01.
Conclusions
A NCV was identified for an inadequate procedure that resulted in an
inadvertent makeup to the SFP from the Unit 2 RWST.
The inspectors
concluded that the corrective actions implemented should prevent
recurrence.
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01.5 Unit 1 Containment Hydrogen Concentration
- 05
a.
Inspection Scope (71707)
The inspectors continued to review the licensee's actions related to
detectable hydrogen concentration within the Unit 1 containment.
b.
Observations and Findings
C.
As reported in NRC Inspection Report 280, 281/97-07. the licensee
installed a Portable Autocatalytic Recombiner (PAR) in the Unit 1
containment on August 22. 1997. to remove hydrogen from the containment
atmosphere.
At that time. containment hydrogen concentration was
approximately 0.5 percent. Subsequent to the installation of the PAR.
the inspectors have been monitoring containment hydrogen concentration
and have noted a downward trend.
At the end of the reporting period.
Unit 1 hydrogen concentration was approximately 0.3 percent indicating
that the PAR is performing as expected.
The licensee is continuing to
perform bi-weekly samples of the containment to monitor hydrogen
concentration changes.
Conclusion
Hydrogen concentration has continued to decrease within the Unit 1
containment.
The PAR appears to be functioning appropriately to reduce
hydrogen concentration.
Operator Training and Qualification
05.1 Licensed Operator Requalification Program (71001)
a.
Inspection Scope
During the period September 22-25. 1997. the inspectors reviewed the
licensee's licensed operator requalification program. Specific areas of
review included observation of simulator and plant walkthrough tests.
program implementation procedures. and management involvement in the
program.
b.
Observations and Findings
The inspectors observed three teams of operators from Crew B shift.
This crew was comprised of five Senior Reactor Operators (SROs). six
Reactor Operators (ROs). and two Shift Technical Advisors (STAs).
Each
operator was administered two simulator scenarios and five Job
Performance Measures (JPMs).
The inspectors noted that operator performance was' generally good.
Several operators had performance weaknesses which were identified and
documented by the training department evaluators. Additionally, the
scenarios appeared to be quite good.
They were challenging and
operationally oriented.
Each explored various aspects of the abnormal
5
and emergency procedures as well as TS actions. The JPMs were good as
well.
The inspectors observed that many enhancements had been made in
response to findings of the previous requalification inspection.
The inspectors noted that the licensee's evaluators did an excellent
job, particularly during the simulator evaluations. They were objective
and thorough in identifying and documenting operator strengths and
weaknesses.
These were discussed among all team members immediately
following each scenario to ensure no problems were overlooked and to
ensure they were properly characterized., The evaluation team included
an Operations Department representative. Usually this representative
was the Operations Superintendent.
The inspectors reviewed the licensee's documentation of operator
performance for this crew and that for Crew E.
The inspectors found
that remedial training was identified and conducted when needed.
Operators with minor deficiencies were trained and re-tested before
returning to shift. While remediation appears to be primarily self-
study, some instructor interface was required.
Documentation and follow
through in this area was very good. but the actual retraining identified
in the remedial packages lacked depth.
The inspectors found evidence of strong and continual management
involvement in the requalification training program (as well as other
non-licensed training programs). A file of management observations.
forms for the last two years was reviewed.
The inspectors. found that
the management observer often provided meaningful feedback and
beneficial ideas. The inspectors found several completed observation
forms by the Plant Manager.
Each form had been properly dispositioned.
with corrective action identified where necessary.
c. Conclusions
The inspectors noted much improvement from the last inspection.
It was
evident that the nuclear training department had worked on those areas
where improvement could be made and the positive change in performance
was observable.
The inspectors concluded that the Surry Operator
Requalification training program was in very good condition.
For the
specific areas inspected. the Surry Operator Requalification program
fully meets the requirements and intent of 10 CFR 55.59(c).
08
Miscellaneous Operations Issues (92901)
08.1
(Closed) Violation CVIO) 50~280/96005-01. 50-281/96005-01: inadequate
system isolation.
On May 18. 1996. the control room operator received
ventilation system Vent-Vent ALERT alarms on both the Victoreen (RI-VG-
110) and Kaman (RI-VG-131-1) radiation monitors.
The operator observed
that the overhead gas pressure had decreased by approximately two psi.
The operator isolated the Primary Drains Transfer Tank (POTT) from the
overhead gas header and terminated the release to the Unit 2
containment.
The operators determined that the release path had been
through POTT Cooler Inlet Header Relief Valve. 2-DG-RV-202. which had
I'
6
been removed to perform set point testing. A Root Cause Evaluation
(RCE) team was formed and their findings are contained in RCE S-96-1089.
The RCE Team reviewed Safety Valve/Relief Valve (SV/RV) work practices
and determined that an operator knowledge deficiency existed in the area
of tailpipe system interactions. The operators had not considered that
when removing a single relief valve in the tailpipe system that the
potential for lifting a second active RV in the chain must be considered
before the SV/RV is removed.
The team determined that three other RVs
had been worked with the Residual Heat Removal (RHR) Heat Exchanger
outlet header RV in service.
The tagout of the POTT vent line was not
discussed or considered prior to releasing work on 2-DG-RV-202.
Two
SROs reviewed and concurred with the proposed boundaries and another SRO
approved the hanging of tags.
Work was released for maintenance without
carefully considering that the system downstream of the RV tail pipe was
slightly pressurized by the gaseous waste system (approximately two
psig).
OPAP-0010 requires that a system be depressurized prior to
breaking its pressure boundary for maintenance.
The team determined
that job scoping did not address special circumstances. Unit 1 had
known fuel failures and the outage unit (Unit 2) POTT vent remained
connected to the Unit 1 common waste gas header.
Isolating the Unit 2
POTT vent from the common gaseous waste header was never considered or
discussed.
The RCE Team made three recommendations to site management:
Develop a training synopsis on SV/RV tagging requirements to
include tail pipe system interactions and OPAP-0010 requirements.
Modify Operations Checklist (OC)-9, Outage Readiness Checklist. to
ensure SV/RV tagging/maintenance is addressed.
Evaluate revising existing procedures to establish an alternate
vent path for the POTT during refueling outages.
Management accepted all the recommendations and committed to the NRC
that the first two items would be completed as the corrective actions in
their August 14, 1996. response to the violation.
The inspectors reviewed the training synopses and training attendance
records for the SV/RV training. The inspectors verified that OC-9 was
modified to address the issues. The licensee evaluated Operating
Procedures 1 and 2-MOP-DG-001. "Removal and Return to Service of the
POTT for Maintenance," Revision 0. and as a result issued a PAR to add
alternate vent paths in Step 5.1.3. The inspectors reviewed 1 and 2-
MOP-DG-001. Revision 0. P-1 and verified that the licensee completed all
three recommended corrective actions.
08.2
(Open) Inspection Followup Item CIFI) 280. 281/97002-01: long term
corrective actions to resolve potential Turbine Driven Auxiliary
Feedwater (TDAFW) pump overspeed trips. The inspectors reviewed the
status of licensee corrective actions with regard to this IFI.
The
7
licensee is presently in the early stages of developing a design change
package to enhance the design of the TDAFW pump control circuitry. The
design change. as presently conceived. will add a seal in signal to the
pump start circuitry. _Discussions with the system engineer indicated
that the modification would most likely be implemented during the next*
scheduled refueling outage on the respective units.
The design change
package and schedule for implementation had not been finalized. This
item will remain open until a final resolution is determined and
implemented.
II. Maintenance
Ml
Conduct of Maintenance
Ml.1
Emergency Service Water Pump (ESWP) 1-SW-P-lB Cleaning
a.
Inspection Scope (62707)
On September 11. 1997. ESWP 1-SW-P-lB failed its monthly Operations
Periodic Test (OPT). (O-OPT-SW-002) and was declared inoperable.
The
inspectors observed portions of the licensee's efforts to restore the
pump to operable status.
b. Observations and Findings
On September 11. the licensee performed procedure O-OPT-SW~002.
"Emergency Service Water Pump 1-SW-P-lB." Revision 10-Pl. The licensee
entered a seven day Limiting Condition for Operation (LCD) when Tagout
l-97-SW-0075 was implemented for pump testing. At 4:18 a.m .. the
operator at the low level reported that the pump had failed the OPT in
that it was only able to achieve a flow of 14.750 gpm.
The test
required that the pump achieve a minimum flow of 15.100 gpm.
Divers
were brought in to clean the pump.
The pump was run a number of times.
but CODtinued to exhibit low flow.
Deficiency Report (DR) 97-2528 was
written to track this event.
The inspectors attended a meeting chaired
by Engineering which focussed on causes of the pump to achieve required
flow and corrective actions.
The decision was made to remove and
disassemble the pump. inspect the pump internals. re-baseline. and have
vendor support on site.
Work Order (WO) 374295-01 was issued to
troubleshoot and perform the required maintenance.
On September 12. the pump was removed from the pump bay, disassembled.
and inspected.
The licensee's inspection revealed barnacles
approximately one half inch deep on the pump diffuser and impeller.
The
vendor representative stated that marine growth in excess of one forth
of an inch would significantly affect pump performance.
The licensee
took photographs of the affected areas of the pump.
The inspectors
viewed the photographs and toured the low level to observe the
disassembled pump.
The inspectors observed the craft removing marine
growth from the pump column.
The disassembled pump and the pump bowl .
diffuser and impeller were viewed.
The bowl. impeller. and diffuser
were sent to the shop to remove the barnacles and re-activate the anti-
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fouling coating.
The licensee had previously coated these components to
inhibit hydroid growth.
The inspectors observed craft performance and also observed that the WO
and the following procedures and documents were at the job site and were
being used.
O-MCM-1910-01. "Diving Procedure.* Revision 2
O-MCM-0114-01. "Emergency Service Water Pump Maintenance."
Revision 5
GMP-C-107. "Rigging and Lifting,* Revision 5
Tagout l-97-SW-0075
The inspectors reviewed WO 374295-01. the tagout. and five of the last
completed O-OPT-SW-002 procedures.
On September 13. the licensee had
reassembled the pump. replaced it in the pump pit. and realigned the
pump assembly.
The pump was placed back in service following Post
Maintenance Testing (PMT) with the pump producing 16.700 gpm.
The
licensee exited the LCO at 10:45 p.m. on September 13.
The licensee
performed the same maintenance on the A and C ESWPs.
Upon removal from
the water. both pumps exhibited barnacle growth similar to the B pump.
Following cleaning. both pumps demonstrated a significant improvement in
performance.
The licensee is evaluating various methods to prevent barnacles from
attaching to the impeller as well as methods to effectively remove the
barnacles without pump disassembly.
Review of the licensee's corrective
actions is identified as IFI 50-280. 281/97009-02.
c.
Conclusions
Maintenance performed on the ESWPs was completed in a satisfactory
manner.
Problems with marine growth on the pumps have not been
adequately resolved.
An IFI is being opened to track the licensee's
resolution of this matter.
Ml.2
No. 1 Emergency Diesel Generator (EOG) Radiator Louvers
a.
Inspection Scope (62707)
The inspectors observed the licensee's troubleshooting efforts to
determine the cause of the failure of the East Radiator Louvers of No. 1
EOG to modulate.
b.
Observations and Findings
On August 12. 1997. an operator observed that the East Radiator Louvers
of No. 1 EOG did not operate properly.
The controller was replaced and
the louvers functioned satisfactorily. This matter was documented in
..
9
NRC Inspection Report 50-280. 281/97-07.
On September 1. during the
troubleshooting effort. the "Hot Engine* alarm came in and cleared
several times during the two hour EOG run.
The east louvers did not
open until 185 degrees F but should have started to open at 165 degrees
F.
The controller was set at 165 degrees Fas a corrective action for
the August event.
DR 97-2463-was issued to track the event.
The
inspectors attended several meetings in which the licensee discussed
potential causes of the failure of the East Louvers to modulate.
No
conclusions were reached on the causes of the failure and Engineering
requested that the EOG be run for data gathering. Operations was
reluctant to unnecessarily operate the EOG for data gathering.
On September 23. the inspectors observed the data gathering run for the
No. 1 EOG.
The licensee instrumented the controls for the East Radiator
The inspectors observed that the instrument cables were routed
between the control cabinet and the door and rested on the upper door
hinge.
The door was free to move and the inspectors believed the cables
could be damaged if the door was accidentally closed. The inspectors
discussed their observation with the licensee who concurred with the
conclusion.
The licensee secured the door in the open position to
prevent it from closing.
The inspectors observed that WO 370314-01. "Repair Louver Control." and
Operating Procedure (OP)-EG-001. "Number 1 Emergency Diesel Generator.*
Revision 7. were at the jobsite and were used by both the craft and the
operators. Craft personnel were methodical and professional in carrying
out their duties.
The inspectors observed that the operators were
performing independent verification of the prestartup procedure steps.
The inspectors reviewed the WO and OP-EG-001.
The No. 1 EOG was started at 10:45 a.m. and was at full load 27 minutes
later. The inspectors observed the run and noted that the west louvers
modulated but the east louvers only opened slightly. The EOG coolant
temperature stabilized and the east louvers had not modulated nor did
the "Hot Engine* alarm initiate. At 11:54 a.m. the EOG load was reduced
when the system engineer determined that no additional data was
required. A review of the data revealed that the controller did not
function properly and DR 97-2655 was issued to track the failure of the
. contra 11 er.
The licensee contacted the controller vendor. Barber-Coleman. and was
informed that the vendor no longer recommends the use of the external
capacitor that is located between the controller and the actuator. A
Request for Engineering Assistance (REA) was submitted to remove the
capacitor from all three EDGs.
The licensee was attempting to obtain
another actuator and planned to replace both the actuator and
controller. The licensee plans to bench test the replacement controller
prior to installation.
The controller is designed to cause the louvers to fully open when the
"Hot Engine* alarm is initiated. The licensee determined that No. 1 EOG
was not inoperable based on their determination that the EOG coolant
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10
temperature limits would not be exceeded even if the east lovers failed
to open.
Conclusions
The licensee attempted to determine the cause of No. 1 EOG louver
controller failures. but has not been successful. Additional effort is
required to repair and return the east bank of louvers to a fully
functional condition. The inspectors considered that the craft were
deliberate and acted in a professional manner during troubleshooting
activities.
Ml.3 Surveillance Observations (61726)
On October 4. the inspectors observed portions of procedure 1-PT-8.1.
"Reactor Protection System Logic (For Normal Operations)." Revision 14.
being performed.
The inspectors observed the briefings held in the
Instrumentation & Calibration (I&C) shop. the Control Room. and with the
work planning SRO and the STA.
The briefings were thorough and
detailed. The inspectors observed the train A portion of the
surveillance. The performance of the surveillance was observed in the
relay and switchgear rooms and in the Control Room.
The I&C technicians
were methodical and cautious. Repeat backs and verification were
consistently performed.
The inspectors considered that the technicians
did an excellent job performing the surveillance .
Ml.4 Miscellaneous Unit 2 Outage Issues
a.
Inspection Scope (62707)
The inspectors reviewed the licensee's plans and commitments for the
upcoming Unit 2 refueling outage. This effort included licensee
maintenance deferrals and commitments.
b.
Observations and Findings
Unit 2 Reactor Coolant Pump (RCP) Seal Inspection
The licensee had originally scheduled a RCP seal inspection during the
upcoming Refueling Outage (RFD 15); however. management determined that
the seal inspection of RCPs A and B would be deferred until RFD 16.
The -
RCPs at Surry are Westinghouse Model 93A with a standard eight inch
Aluminum Oxide seal package.
The vendor recommends inspection of the
seals on a frequency of every other cycle.
The licensee asked
Westinghouse in 1994 for recommendations concerning the extension of the
inspection frequency to every third cycle.
In an August 24. 1994.
memorandum. Westinghouse provided recommendations for extending the
operation life of the seals. The recommendations were to be implemented
at the beginning of the three cycle period and included:
1.
Rebuild the Number 1 seal with new internal 0-rings.
2.
3.
4.
5.
6.
7.
11
Replace the Number 1 and 2 inserts regardless of condition.
Install new Number 2 and 3 runners.
Calibrate and repair all RCP seal related instrumentation.
If the
instrumentation is chronically unreliable. replace it.
Install high temperature 0-rings.
Do not use obsolete Aluminum Oxide seal components:
The Silica
Nitride seals of RCP B have better wear characteristics.
Reduce the rating of the seal injection filters.
Westinghouse stated that even with the recommendations fully implemented
the licensee should anticipate some erratic Number 2 seal operation
during the third cycle.
For RCP A. only recommendations Number 1. 2. and 7 were implemented.
All but recommendations Number 4 and 5 had been implemented for RCP B
during 1995.
Engineering recommended that the inspection frequency not
be extended to three cycles for RCP A and that the seal be overhauled
during RFD 15.
Engineering stated that the operation of RCP B for an
additional cycle had its risks. but the condition of the seal was more
conducive to operation for an- additional cycle .
The inspectors were concerned about the deferral of the RCP A seal
inspection and discussed their concerns with licensee management.
The
inspectors were informed that the licensee was aware of the risks
involved and that the deferral of the RCP A seal inspection was an "at-
risk" decision. A factor in this decision was that if the Number 1 seal
failed. it would not be catastrophic failure and the Unit could be
safely shut down.
NRC Commitments To Be Completed During The Unit 2 RFD 15
The licensee has committed to the NRC to perform or complete various
tasks. The following is a list of those significant items which will be
completed during RFD 15:
Install Appendix R isolation breakers between vital buses and
uninterruptable power supplies. (DCP-94-018)
Modify valves 2-SI-MOV-1890A/B to install bonnet cavity pressure
equalization line. CDCP 96-034. WO 350835-01)
Complete the physical verification of differences associated with
documented valve alignments for valves not accessible during
normal plant operation. CIR 50-280. 281/96011)
The inspectors reviewed these commitments and determined that they were
in the scope of the outage.
C.
12
Conclusions
The licensee's deferral of the A RCP seal inspection during the upcoming
Unit 2 outage could result in a forced RCP seal replacement outage, but
does not preclude safe operation of the unit.
Licensee commitments for
the Unit 2 outage were reviewed and found to be within the scope of the
outage.
MB
Miscellaneous Maintenance Issues (92902)
MB.1 Auxiliary Shutdown Facilities Maintenance/Surveillance
a.
Inspection Scope (62700)
b.
This portion of the inspection was conducted to review the licensee's
practices concerning surveillance. testing and maintenance of the
plants* auxiliary shutdown facilities. The purpose of the inspection
was to determine what actions were being taken by the licensee to assure
that the facilities would perform their safety function if called upon
during a plant event.
In order to complete the inspection. the licensee
was requested to provide the following information: a list of all
surveillances. preventive maintenance. and calibrations performed; a
list of all deficiency reports and work orders written on the facility
in the last year. and a list of any design changes implemented on the
facility in the last three years. This information was provided and
reviewed during the course of the inspection. Additionally, the
inspectors reviewed the Updated Final Safety Analysis Report (UFSAR).
TSs and the licensee's Abnormal Procedure AP 20. "Main Control Room
Inaccessibility," Revision 3.
Walkdowns of the auxiliary shutdown panel
(for each unit) and the two remote monitoring panels (located in the
cable spreading room) were conducted. These walkdowns compared
installed equipment to the applicable drawing. verified system lineup to
the applicable site procedure. and included an inspection of the inside
of the auxiliary shutdown panels for material condition.
In addition. a
sample of surveillances. calibrations and periodic tests were reviewed
for technical adequacy.
Observations and Findings
Review of the station deviations and WOs written on the equipment
determined that adequate and appropriate corrective action was being
taken for identified equipment deficiencies.
Review of the UFSAR
determined that there were no differences between the UFSAR and the site
procedures concerning the auxiliary shutdown facility.
Walkdown of the
panels identified one minor problem concerning eight switches. which had
been inadvertently omitted from the switch position verification
checklist in OC-15 (Unit 1) and OC-16 (Unit 2). "Aux Shutdown Panel
Switches." effective date June 23. 1997. This condition was immediately
addressed by the licensee in Deviation Report S97-2653.
The walkdown
determined that the equipment was in good condition. although the inside
of the auxiliary shutdown panel had some dust accumulation.
The
licensee was in the process of establishing a five year preventive
13
maintenance to clean that area.
The inspection determined that the
following surveillance. calibration. and periodic testing was being
routinely conducted by the licensee:
Functional testing of all switches on the auxiliary shutdown
panels was performed in accordance with procedure 1-0SP-ZZ-001.
"Auxiliary Shutdown Panel Functional Surveillance." Revision 2.
Calibration of all meters on the auxiliary shutdown panels and the
remote monitoring panels was performed in accordance with various
site calibration procedures.
An operational check was periodically performed. using Procedure
PT-36.1. "Remote Instrumentation Channel Check." Revision 4. which
compared the readings on the remote meters to those same readings
in the control room.
An operational check was periodically performed which verified the
correct positioning of the auxiliary shutdown panel(s) switches in
accordance with Procedures OC-15 and OC-16.
c. Conclusions
The licensee's actions with regard to surveillance. testing and.
maintenance of the auxiliary shutdown panels and the remote monitoring
panels were excellent. All switches controlling equipment on the
auxiliary shutdown panels were subjected to testing to verify
operability. All meters on all of the panels were in the licensee's
calibration program. There were operational checks that compared the
meter readings on all of the panels to the comparable control room
meters. and checks that periodically verified proper switch positioning
on the auxiliary shutdown panels.
M8.2 (Closed) VIO 50-280. 281/94017-02:
failure to implement corrective
actions to preclude repetition of Foreign Material Exclusion (FME)
deficiencies.
The inspectors reviewed the following documents:
Reply To A Notice Of Violation. dated August 17. 1994
VPAP-1302. "Foreign Material Exclusion Program.* Revision 9
&
VPAP-2002. "Work Request and Work Order Tasks.* Revision 7
Station Nuclear Safety Station Deviation Trend Reports for fourth
quarter 1996 and first and second quarter 1997
Surry Self Assessment 1997 Unit 1 RFD FME Report.
Maintenance Self Assessment First Quarter 1997 Status Report
Lesson plan EMI-6-LP-4. Foreign Material Exclusion Program
14
Various Deviation Reports (DRs) issued for FME problems.
In addition. the inspectors looked at the computer based training
provided for the Nuclear Business Unit employees. attended the FME
worker qualification training presented on September 25. 1997. and
discussed FME issues with Maintenance personnel. Actions to avoid FME
problems included the requirements in VPAP-1302 that personnel entering
a FME area were to have been qualified or be escorted by a qualified
person and specially trained FME coordinators were to be assigned
responsibility for the FME area.
The FME worker qualification training
was considered a strength in that it personalized the negative affects
that foreign material can have on employee safety and dose. as well as.
the economic impact on the company.
The licensee has expended
considerable resources to sensitize workers. both contract and plant
employees. concerning FME issues.
III. Engineering
El
Conduct of Engineering
El.1 Service Water System Safety Evaluation 97-123
a.
Inspection Scope (37551)
The inspectors reviewed safety evaluation 97-123 that justified
continued operation with improperly installed service water Metal
Expansion Joints (MEJs).
b. Observations and Findings
On September 17. a concern was raised by engineering personnel dealing
with the adequacy of the service water MEJs in the recirculation spray
heat exchanger service water lines located inside containment on both
units.
The concern specifically addressed the configuration of the tie
rods and the gap between the nuts on the tie rod and the expansion
joint. The installed configuration allowed unrestrained compression of
the MEJs but did not allow unrestrained extension of the MEJs.
Based on
the as installed configuration of the expansion joint tie rods. an
engineering analysis was performed to determine the effect of this
additional loading on the system.
The analysis determined that the most,
limiting component was the recirculation spray heat exchanger upper
support structure support plate and shear bolts. The associated design
allowable stress values would be exceeded during a design basis seismic
event.
The analysis also determined that the stresses would not exceed
the American Society of Mechanical Engineers.Section III Appendix F
allowables.
Based on the analysis performed. the licensee determined
that the system was degraded but operable.
The Unit 1 MEJ tie rods were configured to the proper configuration
prior to completion of the safety evaluation.
Based on the operability
evaluation. the licensee elected to wait until the scheduled Unit 2
C.
15
refueling outage to modify the expansion joint tie rods inside the Unit
2 containment.
The unit was scheduled to shutdown October 6 for the
refueling outage.
Conclusions
The Safety Evaluation addressing service water expansion joint
operability was thorough and adequately justified system operability.
The decision to defer modification of the Unit 2 expansion joints inside
containment approximately two weeks until a scheduled refueling outage
appeared appropriate.
IV. Plant Support
Rl * Radiological Protection and Chemistry Controls (71750)
On numerous occasions during the inspection period. the inspectors
reviewed Radiation Protection (RP) practices including radiation control
area entry and exit. survey results. and radiological area material
conditions.
No discrepancies were noted. and the inspectors determined
that RP practices were proper.
Pl
Conduct of Emergency Preparedness (EP) Activities
On August 26. an Emergency Preparedness Exercise was conducted.
Regional personnel and the resident inspectors participated in the
exercise. The exercise is discussed in detail in NRC Inspection Report
280. 281/97008.
Sl
Conduct of Security and Safeguards Activities
On numerous occasions during the inspection period. the inspectors
performed walkdowns of the protected area perimeter to assess security
and general barrier conditions.
No deficiencies were noted and the
inspectors concluded that security posts were properly manned and that
the perimeter barrier's material condition was properly ~aintained.
F2
Status of Fire Protection Facilities and Equipment
F2.1
10 CFR 50 Appendix R Isolation and Breaker Coordination
a.
Inspection Scope (64704)
The inspector reviewed an issue identified by the licensee regarding the
electrical isolation and protection provided for the vital electrical
bus panels in the event of a control room fire. Also reviewed was
circuit breaker coordination provided for the vital electrical bus
panels for compliance with the requirements of 10 CFR 50 Appendix R.
b. Observations and Findings
r
16
VITAL BUS ISOLATION
The Surry facility has a common control room for both Units 1 and 2.
The control room complex includes the Unit 1 computer room. the Unit 2
computer room and the control room administrative annex.
These rooms
are in the same fire area.
Each unit has four Uninterruptable Power
Supplies (UPS). UPS A-1. A-2. B-1 and B-2. which supply power to vital
emergency panels. These panels provide power to safety related
equipment and equipment required to achieve safe shutdown in the event
of a control room fire.
UPS lA-1 and lA-2 supply power to panels VB 1-I
and VB 1-III which are located in the Unit 1 computer room.
and 2A-2 supply power to VB 2-I and VB 2-III which are located in the
Unit 2 computer room.
UPS lA-2 supplies the Unit 2 Appendix R safe
shutdown panels and UPS 2A-2 supplies the Unit 1 Appendix R safe
shutdown panels. These Appendix R remote shutdown panels are located in
each unit's emergency switchgear room and in the cable spreading room.
They contain instrumentation required for performing plant shutdowns
from outside the main control room. such as steam generator level. RCS
pressure and temperature. and pressurizer level.
There were no means available to isolate the vital 120 VAC bus panels in
the Unit 1 and 2 computer rooms from the UPS panels. A control room
fire could cause an electrical fault ("short") in vital buses VBs 1-I.
1-III. 2-I and 2-III which could trip the breaker or fuse to the
affected UPS panel. This could result in the loss of power to the
Appendix R shutdown panels. Should this occur. there would be no
instrumentation operable on the Appendix R panels to support the plant
shutdown activities. In addition. power would also be lost to the
emergency communication equipment located adjacent to the remote
Appendix R panels. This communication equipment is required for remote
, shutdown activities. Power to the vital buses could not be restored
until the fault conditions were corrected and any blown fuses replaced.
The failure to provide vital bus isolation does not meet the
requirements of Appendix R Section I II. G and is i denti fi ed as Apparent
Violation EEI 50-280. 281/97009-03
BREAKER COORDINATION
The vital bus panels are supplied power by the UPS.
Each vital bus
panel contains a number of branch circuit breakers and a 100-amp main
circuit breaker.
Each circuit breaker has a thermal unit and a magnetic
unit.
Based on the licensee's engineering evaluations. the thermal
units had inverse time versus current characteristics. so that as
current increased. the trip time decreased.
The magnetic units would
operate instantaneously. * At current less than 1.000 amps. the thermal
units would provide selective tripping to ensure that the branch
breakers would open prior to the main circuit breaker. i.e .. correct
circuit breaker coordination.* However. at currents above 1. 000 amps.
proper selective tripping could not be ensured. This could result in
the opening of either the branch or main circuit breaker.
Most of the
vital bus panels supply power to some Appendix R related functions.
If
17
the main circuit breaker opened. all functions provided by the panel
would be lost. The licensee's analysis found that at least one panel
could be lost due to a coordination issue in the following fire areas:
control room. Unit 1 emergency switchgear room. Unit 2 emergency
switchgear room and the turbine building. These branch circuits supply
electrical power to a number of Appendix Rand safe shutdown components.
This inadequate breaker coordination does not meet the requirements of
10 CFR 50. Appendix R.Section III.Gas implemented by the Surry
Appendix R report. Section 3.9.2 which states "The problem of associated
circuits of concern by common power supply is resolved by ensuring
adequate electrical coordination between the safe shutdown power source
supply breaker and the component feeder breakers or fuses ... " The
failure to meet the requirements of Appendix R for circuit breaker
coordination is identified as Apparent Violation EEI 50-280. 281/97009-
04.
CORRECTIVE ACTIONS
The licensee's Electrical Distribution System Functional Inspection
(EDSFI) assessment performed in 1992 identified the possible loss of
uninterruptable power supplies to equipment required in both units to
achieve and maintain the plant in a safe shutdown condition in the event
of an Appendix R control room fire. The licensee issued Deviation
Report (DR) S-92-1806 which documented that the facility was outside the
plant's design basis and in violation of the requirements of 10 CFR 50
Appendix R.
However. this condition was not reported to the NRC.
A
plant modification request was initiated by Design Change Package (DCP)
93-002-03 to install fuses on the feeders to the vital bus panels. This
DCP was subsequently superseded by DCP 94-018 which was scheduled to be
completed for Unit 1 during the Fall 1998 refueling outage and for Unit
2 during the Fall 1997 refueling outage.
In early 1993. the licensee identified inadequate breaker coordination
between the branch circuits and the main circuit on a number of vital
bus distribution panels. This issue involved the possibility that a
fault condition affecting one of the branch circuits would trip the main
panel circuit breaker in lieu of the branch circuit breaker and result
in the loss of the entire bus panel. This issue was identified as
outside of the plant's design basis and was documented by DR S-93-0109.
This condition was also not reported to the NRC.
DCP 94-018 was revised'
to replace the main input breakers to each of the vital bus distribution
panels with non-automatic switches. i.e .. no fuses or circuit breakers.
On March 24. 1997. following completion of engineering evaluation ET
CCE-96-068 to support DCP 94-018. the licensee concluded that the plant
was not in compliance with the requirements of Appendix R.
This
conclusion was documented by DR S-97-0981 and this issue was discussed
with the NRC resident inspectors; however. this condition was not
formally reported to the NRC.
18
On July 31 and August 5. 1997. the NRC staff had conference calls with
the licensee to discuss these issues. Effective August 14. 1997. the
licensee revised the Fire Contingency Action Procedure O-FCA-1.00.
"Limiting Main Control Room Fire (With 19 Attachments)." Revision 12. to
provide sufficient guidance to ensure that the units would be maintained
in a safe shutdown condition in the event of an Appendix R fire. This
procedure could be accomplished with the normal minimum plant staffing
plus one designated electrician assigned to the operating shift. In
general. the compensatory actions required cutting the supply cables to
vital bus panels VBs 1-I. 1-III. 2-I. and 2-III. This would disconnect
or open the circuit to the fire damaged cables or panels to eliminate an
electrical fault condition.
The vital power supply panels would then be
- restored to service.
Any blown fuses within the uninterruptable power
supply panels would be replaced.
The electrical tools. fuses and other
equipment required to perform these tasks were stored within the
emergency switchgear room.
Performance of these repair actions would be
required within 30 minutes to meet the time lines for safe shutdown
established in the Surry Appendix R Report. Chapter 5. Attachment 2.
The licensee had performed walkdowns and verified that these actions
could be accomplished within the-required time frame.
Adequate
compensatory measures were implemented in August 1997 to control and
monitor a plant shutdown following an Appendix R type fire until the
permanent modifications were completed.
The compensatory measures for the breaker coordination issue consisted
of restoring the vital buses supplying Appendix R equipment to service
on an as needed basis. Operations personnel had been directed and
Procedure O-FCA-1.00 had been revised to first attempt to reclose an
open circuit breaker on the affected vital bus panel.
If this was not
successful. circuit breakers supplying non-Appendix R equipment would be
opened to allow the main circuit breaker to be successfully closed.
The
compensatory actions implemented in August 1997 were considered adequate
to address this issue until permanent modifications are completed.
The inspectors reviewed Procedure O-FCA-1.00. inspected the repair
supplies and equipment stored in the emergency switchgear room. and
concluded that the proposed compensatory actions were appropriate.
These compensatory actions were first identified in 1993; however. prior
to August 1997. a designated electrician was not always on the site to
perform the required actions and the required ~lectrical tools and
replacement fuses were not stored within the emergency switchgear rooms.
In addition. Procedure O-FCA-1.00 did not adequately address all of the
required compensatory actions. The inspectors concluded that prior to
August 1997. the plant operators may not have been able to activate the
remote shutdown panels and establish remote monitoring of plant
conditions within the required 30 minute time frame.
The Surry Operating License Section 2.I for Units 1 and 2 states that
the licensee is required to implement and maintain the administrative
controls identified in Section 6 of the Fire Protection Safety
Evaluation.
The Surry Appendix R Report. Chapter 12. Section C
19
identified that the Quality Assurance program applies to the fire
protection program. Section C.8 states that measures established to
ensure that conditions adverse to fire protection. such as failures.
malfunctions. deficiencies. deviations. defective components.
uncontrolled combustible materials. and nonconformances are promptly
identified. reported and corrected and are described in Section 17.2.16
of VEP 1-5A. "Operational Quality Assurance Program Topical Report." A
noncompliance to the Appendix R requirements in the event of a control
room fire was identified in 1992 and inadequate breaker coordination
issues were identified in 1993: however. actions were not taken to
promptly correct these issues. The failure to promptly correct these
identified Appendix R fire protection discrepancies is identified as
Apparent Violation EEI 50-280. 281/97009-05.
REPORTABILITY
10 CFR 50.72(b)(l)(ii)(B) and 50.73(a)(2)(ii)(B) require licensees to
notify the NRC of identified plant conditions that are outside the
design basis of the plant. The notification is to be as soon as
practical, but within one hour. of the occurrence followed by a written
Licensee Event Report CLER) within 30 days after the discovery of the
event.
The licensee did not report these issues to the NRC.
The
failure to properly report to the NRC Appendix R fire protection
discrepancies which were outside the design basis of the plant is
identified as Apparent Violation EEI 50-280. 281/97-09-06.
c.
Conclusions
Two apparent violations were identified for inadequate fire protection
features involving the control room complex and for safety related vital
electrical panels.
Because of these deficiencies. at least one train of
systems necessary to achieve and to maintain the plant in a hot shutdown
condition from either th.e control room or emergency control station may
not be protected from fire damage.
Two additional apparent violations
were identified involving the failure to report conditions outside the
design basis of the plant and the failure to correct Appendix R fire
protection discrepancies promptly.
F2.2 Fire Protection Features for Radwaste Facility (64704)
a.
b.
Inspection Scope
The inspectors reviewed the fire protection features provided for the
Radwaste Facility to determine if these features met the NRC guidelines
of NUREG 0800, Section 9.5.1.
Observations and Findings
Document C-20-122K-001. "Safety Analysis for New Radwaste Facility."
Revision 1. dated April 1991. contained a description of the fire
protection features for the Radwaste Facility. The inspectors reviewed
Document C-20-122K-001 and performed a walkdown inspection of the
20
Radwaste Facility. The facility is a six-story non-combustible building
provided with an automatic fire alarm system. fire hose standpipe
system. portable fire extinguishers. and automatic sprinkler systems.
The sprinkler systems only provide partial protection and were installed
in areas containing combustible materials or high radiation.
The design
concept for the facility's fire protection features included provisions
to detect and alert the facility operators of the existence of a fire.
suppress the fire. and prevent the spread of fire to adjacent building
areas.
The fire alarm signals are received in the Radwaste Facility control
room which is continuously manned.
Upon receipt of a fire alarm signal.
the alarm response procedure refers the operator to Radwaste Abnormal
Procedure RAP-26-02,"Fire." Revision 1. T~is procedure directed the
operators to extinguish the fire and to contact the Surry control room
and request Surry Fire Brigade assistance if the fire cannot be
extinguished with one portable fire extinguisher.
The inspectors
verified that the Radwaste Facility operators had received training in
the use of fire extinguishers.
Most of the maintenance and surveillance testing activities for various
equipment in the Radwaste Facility were performed by radwaste personnel.
Previously, the testing of the fire protection equipment had been
performed by Surry station personnel; however. testing of the fire
protection equipment was in the process of being transferred to the
Radwaste Facility personnel.
The Surry fire prevention procedures were used to control transient
combustible materials. combustible and flammable liquids. hot work
activities. and the surveillance and testing of the fire protection
equipment. These were adequate. except operability of the Radwaste
Facility fire protection equipment was not addressed.
To address this
issue. the licensee had implemented a policy in which the Radwaste
Facility personnel were to inform the Surry control room and fire
brigade of any fire protection impairments.
In addition. the area of
the effected impairment was to be monitored approximately every four
hours while the fire protection systems were out of service. The
inspectors concluded that these compensatory actions were appropriate.
During the facility inspection. the inspectors noted that the general
housekeeping in the facility was excellent with appropriate emphasis
being provided for the control of combustible and flammable materials.
Material condition of the fire protection equipment was very good and
the equipment appeared to be well maintained.
However. the inspectors
noted that several changes had been made to the fire protection features
provided for the facility, such as replacing the Halon fire
extinguishers with dry chemical type extinguishers and installation of a
suspended ceiling below the installed fire detection instruments in
several areas.
The licensee stated that no written evaluation was
available to justify these changes.
The safety analysis document for
the Radwaste Facility was prepared as a 10 CFR 50.59 evaluation to
determine if the facility could be constructed. tested and placed in
21
service without NRC approval. This document was apparently not intended
to be maintained as a design basis document.
Currently the licensee
does not have a process to maintain an updated description of the
facility and operational process or a requirement that a justification
be provide for any changes made to the facility. The licensee stated
that this issue would be evaluated. Until the inspectors can review and
assess the licensee's evaluation. this is identified as IFI 50-280.
281/97009-07 ..
The inspectors reviewed the preventive maintenance program records and
verified that periodic inspections and tests of the fire protection
equipment was being performed at the frequency recommended by the
licensee's insurance carrier. This inspection frequency was considered
satisfactory.
c.
Conclusions
Excellent housekeeping was provided for the Radwaste Facility with good
implementation of the station's fire prevention procedures and
maintenance of the fire protection equipment.
An IFI was identified
involving the lack of a design basis type document and no requirement to
provide justifications for changes made to the building structure.
equipment and facility processes.
F8
Miscellaneous Fire Protection Issues (92904)
F8.l (Closed) VIO 50-280. 281/96010-03: inadequate preventive maintenance
performed on spare electric motors.
(Closed) IFI 50-280. 281/96010-04: preventive maintenance requirements
for spare RHR and component cooling water pumps.
The licensee responded to the VIO by letter dated November 26. 1996.
The corrective actions taken on the VIO and IFI were closely related.
The VIO was related to the lack of adequate preventive maintenance being
performed for two large spare safety related component cooling water
pump motors.
The IFI was related to the preventive maintenance
requirements for mechanical equipment in storage. such as safety related
pumps.
As corrective action. the licensee sent the two electric motors to a
vendor for a detailed inspection.
The vendor performed an inspection
and repaired all identified discrepancies.
An assessment was performed
by the licensee of the preventive maintenance requirements for all
electric motors and mechanical components. such as pumps. blowers. air*
compressors. etc .. which were being stored in the site warehouses.
Procedure O-EPM-2302-01. Inspection of Stored Motors. Revision 3. was
revised to enhance the maintenance being provided for the stored motors.
The revision included detailed inspection requirements for all stored
motors and required the shafts be rotated annually for all electric
motors in storage.
In addition. all Appendix R designated motors and
motors more than 50 HP were required to be rotated quarterly. The
..
22
licensee's assessment also identified several motors. such as the two
large motors for the component cooling water pumps, which were required
to be provided with heaters during storage.
The licensee's assessment identified approximately 20 mechanical
components which were required to be included in a preventive
maintenance program.
These mechanical components were inspected and the
component's shafts were rotated at least every 6-months using a routine
maintenance work order.
The inspectors reviewed the work request for the maintenance components
which was completed August 5, 1997. and Procedure O-EPM-2302-01. which
was completed on August 25. 1997. and verified that the required
preventive maintenance for the electric motors and mechanical components
in storage were bei~g performed.
The licensee took positive action to enhance the preventive maintenance
being performed on the storage of spare safety related electric motors
and rotating mechanical components.
F8.2 (Closed) LER 50-280/96007-00: fire watch patrol inspection frequency
exceeds one hour. This event was reported to the NRC when the licensee
failed to complete fire watch inspections within the frequency required
by TS 3.21.B.1 of "at least once per hour."
More specifically, three
fire detection zones were inspected 7 minutes late. two fire detection
zones were inspected 11 minutes late. and three fire detection zones
were inspected 13 minutes late. The cause of this event was attributed
to the fire watch patrol being delayed by station security personnel
following an inadvertent activation of a security alarm.
The licensee* s corrective actions for this event entailed the fo 11 owing;
Cl) Fire watch personnel were instructed that fire detection zone
inspections must be performed in accordance with TSs and security
requirements. (2) Fire watch personnel were further instructed to inform
security officers that they are performing fire watch duties if a
security alarm is activated during the tour so that the tour could be
completed in accordance with TS requirements. and (3) Fire watch
computer based training was revised to emphasize the importance of
compliance with the one hour TS requirement for completing fire watch
tours.
The inspectors reviewed these actions and found them to be
satisfactory.
The failure to perform fire watch tours within the specified one hour
time frame is a VIO of TS 3.21.B.1. This non-repetitive. licensee-
identified and corrected VIO is being treated as a Non-cited Violation
consistent with Section VII.B.1 of the NRC Enforcement Policy. This
matter in identified as NCV 280. 281/97009-08 .
V. Management Meetings
23
Xl
Exit Meeting Summary
The inspectors presented the inspection results to members of licensee
management at the conclusion of the inspection on.October 10. 1997.
The
licensee acknowledged the findings presented.
The inspectors asked the licensee whether any materials examined during the
inspection should be considered proprietary.
No proprietary information was
identified.
PARTIAL LIST OF PERSONS CONTACTED
Licensee
M. Adams. Superintendent. Engineering
R. Allen. Superintendent. Maintenance
R. Blount. Assistant Station Manager. Nuclear Safety & Licensing
D. Christian. Station Manager
M. Crist. Superintendent. Operations
B. Shriver. Assistant Station Manager. Operations & Maintenance
T. Sowers. Superintendent. Training
B. Stanley, Director. Nuclear Oversight
W. Thorton. Superintendent. Radiological Protection
IP 37551:
IP 40500:
IP 61726:
IP 62700:
IP 62707:
IP 64704:
IP 71001:
IP 71707:
IP 71750:
IP 92700:
IP 92901:
IP 92902:
Opened
INSPECTION PROCEDURES USED
Onsite Engineering
Effectiveness of Licensee Controls in Identifying, Resolving, and
Preventing Problems
Surveillance Observation
Maintenance Program Implementation
Maintenance Observation
Licensed Operator Requalification Program Evaluation
Plant Operations
Plant Support Activities
Onsite Followup of Written Reports of Nonroutine Events at Power
Reactor Facilities
Followup - Plant Operations
Followup - Maintenance
ITEMS OPENED, CLOSED, AND DISCUSSED
50-280, 281/97009-01
inadequate SFP makeup procedure
(Section 01.4).
24
50-280. 281/97009-02
IFI
ESWP corrective action followup
(Section Ml .1).
50-280, 281/97009-03
failure to meet the requirements of
Appendix R for vital bus isolation
( Sect i on F2. 1) .
50-280. 281/97009-04
failure to meet the requirements of
Appendix R for circuit breaker
coordination (Section F2.1).
50-280. 281/97009-0~
failure to promptly correct licensee
identified Appendix R fire
protection discrepancies (Section
F2.1).
50-280. 281/97009-06
failure to report Appendix R fire
protection discrepancies which were
outside the design basis of the
plant (Section F2.l).
50-280. 281/97009-07
IFI
no documentation or evaluations
available for changes made to the
Radwaste Facility (Section F2.2).
50-280. 281/97009-08
failure to perform fire watch tours
within the specified one hour time
frame (Section F8.2).
Closed
50-280.281/97009-01
inadequate SFP makeup procedure
(Section 01. 4).
50-280. 281/96005-01
inadequate system isolation (Section
08.1).
50-280. 281/94017-02
failure to implement corrective
actions to preclude repetition of
deficiencies (Section M8.2).
50-280. 281/96010-03
inadequate preventive maintenance
performed on spare electric motors
(Section F8 .1).
50-280. 281/96010-04
IFI
preventive maintenance requirements
for spare RHR and component cooling
water pumps (Section F8.1).
50-280. 281/97009-08
failure to perform fire watch tours
within the specified one hour time
frame (Section F8.2).
_
_..J
50-280/96007-00
LER
Discussed
280. 281/97002-01
IFI
25
fire watch patrol inspection
frequency exceeds one hour (Section
F8. 2).
long term corrective actions to
resolve potential TDAFW overspeed
trips (Section 08.2)
I'
tlie failure to make a required report to the NRC will be based upon the significance of and the
circumstances surrounding the matter that should have been reported. However, the severity level of an
untimely report, in contrast to no report, may be reduced depending on the circumstances surrounding
the matter. A licensee will not normally be cited for a failure to report a condition or event unless the
licensee was actually aware of the condition or event that it failed to report. A licensee will, on the other
hand, normally be cited for a failure to report a condition or event if the licensee knew of the information
to be reported, but did not recognize that it was required to make a report.
V. PREDECISIONAL ENFORCEMENT CONFERENCES
Whenever the NRC has learned of the existence of a potential violation for which escalated enforcement
action appears to be warranted, or recurring nonconformance on the part of a vendor, the NRC may
provide an opportunity for a predecisional enforcement conference with the licensee, vendor, or other
person before taking enforcement action. The purpose of the conference is to obtain information that will
assist the NRC in determining the appropriate enforcement action, such as: (1) a common understanding
of facts, root causes and missed opportunities associated with the apparent violations, (2) a common
understanding of corrective actions taken or planned, and (3) a common understanding of the
significance of issues and the need for lasting comprehensive corrective action.
If the NRC concludes that it has sufficient information to make an informed enforcement decision, a
conference will not normally be held unless the licensee requests it. However, an opportunity for a
conference will normally be provided before issuing an order based on a violation of the rule on
Deliberate Misconduct or a civil penalty to an unlicensed person. If a conference is not held, the licensee
will normally be requested to provide a written response to an inspection report, if issued, as to the
licensee's views on the apparent violations and their root causes and a description of planned or
implemented corrective actions.
During the predecisional enforcement conference, the licensee, vendor, or other persons will be given an
opportunity to provide information consistent with the purpose of the conference, including an
. explanation to the~RC of the immediate corrective actions (if any) that were taken following
identification of the potential violation or nonconforrnance and the long-term comprehensive actions that
were taken or will be taken to prevent recurrence. Licensees, vendors, or other persons will be told when
a meeting is a predecisional enforcement conference.
A predecisional enforcement conference is a meeting between the NRC and the licensee. Conferences
are normally held in the regional offices and are normally open to public observation. Conferences will
not normally be open to the public if the enforcement action being contemplated:
(1) Would be taken against an individual, or if the action, though not taken against an individual, turns
on whether an individual has committed 1,,vrongdoing;
(2) Involves significant personnel failures where the NRC has requested that the individual(s) involved
be present at the conference;
(3) Is based on the findings of an NRC Office ofinvestigations report that has not been publicly
disclosed; or
(4) Involves safeguards information, Privacy Act information, or information which could be considered
proprietary;
In addition, conferences will not normally be open to the public if:
(5) The conference involves medical misadministrations or overexposures and the conference cannot be
conducted without disclosing the exposed individual's name; or
(6) The conference will be conducted by telephone or the conference will be conducted at a relatively r
small licensee's facility.
Enclosure 2
Notwithstanding meeting any of these criteria, a conference may still be open if the conference involves
issues related to an ongoing adjudicatory proceeding with one or more intervenors or where the
evidentiary basis for the conference is a matter of public record, such as an adjudicatory decision by the
Department of Labor. In addition, notwithstanding the above normal criteria for opening or closing
conferences, with the approval of the Executive Director for Operations, conferences may either be open
or closed to the public after balancing the benefit of the public's observation against the potential impact
on the agency'.s decision-m~ng process in a particular case.
The NRC will notify the licensee that the conference will be open to public observation. Consistent with
the agency's policy on open meetings, "Staff Meetings Open to Public," published September 20, 1994
(59 FR 48340), the NRC intends to announce open conferences normally at least 10 working days in
advance of conferences through (1) notices posted in the Public Document Room, (2) a toll-free
telephone recording at 800-952-9674, (3) a toll-free electronic bulletin board at 800-952-9676, and on
the World Wide Web at the NRC Office of Enforcement homepage (www.nrc.gov/OE). In addition, the
NRC will also issue a press release and notify appropriate State liaison officers that a predecisional
enforcement conference has been scheduled and that it is open to public observation.
The public attending open conferences may observe but may not participate in the conference. It is noted
that the purpose of conducting open conferences is not to maximize public attendance, but rather to
provide the public with opportunities to be informed of NRC activities consistent with the NRC's ability
to exercise its regulatory and safety responsibilities. Therefore, members of the public will be allowed
access to the NRC regional offices to attend open enforcement conferences in accordance with the
"Standard Operating Procedures for Providing Se~urity Support For NRC Hearings and Meetings,"
published November 1, 1991 (56 FR 56251). These procedures provide that visitors may be subject to
personnel screening, that signs, banners, posters, etc., not larger than 18" be permitted, and that
disruptive persoris may be removed. The open conference will be terminated if disruption interferes with
a successful conference. NRC's Predecisional Enforcement Conferences (whether open or closed)
normally will be held at the NRC's regional offices or in NRC Headquarters Offices and not in the
vicinity of the licepsee's facility ..
For a case in which an NRC Office of Investigations (OI) report finds that discrimination as defined
under 10 CFR 50.7 (or similar provisions in Parts 30, 40, 60, 70, or 72) has occurred, the OI report may
be made public, subject to withholding certain information (i.e., after appropriate redaction), in which
case the associated predecisional enforcement conference will normally be open to public observation.
In a conference where a particular individual is being considered potentially responsible for the
discrimination, the conference will remain closed. In either case (i.e., whether the conference is open or
closed), the employee or former employee who was the subject of the alleged discrimination (hereafter
referred to as "complainant") will normally be provided an opportunity to participate in the predecisional
enforcement conference with the licensee/employer. This participation will normally be in the form of a
complainant statement and comment on the licensee's presentation, followed in turn by an opportunity
for the licensee to respond to the complainant's presentation. In cases where the complainant is unable to
attend in person, arrangements will be made for the complainant's participation by telephone or an
opportunity given for the complainant to submit a written response to the licensee's presentation. If the
licensee chooses to forego an enforcement conference and, instead, responds to the NRC's findings in
writing, the complainant will be provided the opportunity to submit written comments on the licensee's
response. For cases involving potential discrimination by a contractor or vendor to the licensee, any
associated predecisional enforcement conference with the contractor or vendor would be handled
similarly. These arrangements for complainant participation in the predecisional enforcement conference
are not to be conducted or viewed in any respect as an adjudicatory hearing. The purpose of the
complainant's participation is to provide information to the NRC to assist it in its enforcement
deliberations.
A predecisional enforcement conference may not need to be held in cases where there is a full
adjudicatory record before the Department of Labor. If a conference is held in such cases, generally the
conference will focus on the licensee's corrective action. As with discrimination cases based on OI
investigations, the complainant may be allowed to participate.
,
Members of the public attending open conferences will be reminded that (1) the apparent violations
discussed at predecisional enforcement conferences are subject to further review and may be subject to
change prior to any resulting enforcement action and (2) the statements of views or expressions of
opinion made by NRC employees at predecisional enforcement conferences, or the lack thereof, are not
intended to repres~nt final determinations or beliefs.
When needed to protect the public health and safety or common defense and security, escalated
enforcement action, such as the issuance of an immediately effective order, will be taken before the
conference. In these cases, a conference may be held after the escalated enforcement action is taken.
VI. ENFORCEMENT ACTIONS
This section describes the enforcement sanctions available to the NRC and specifies the conditions under
which each may be used. The basic enforcement sanctions are Notices of Violation, civil penalties, and
orders of various types. As discussed further in Section VI.D, related administrative actions such as
Notices ofNonconformance, Notices of Deviation, Confirmatory Action Letters, Letters of Reprimand,
and Demands for Information are used to supplement the enforcement program. In selecting the
enforcement sanctions or administrative actions, the NRC will consider enforcement actions taken by
other Federal or State regulatory bodies having concurrent jurisdiction, such as jn transportation matters.
Usually, whenever a violation ofNRC requirements of more than a minor concern is identified,
enforcement action is taken. The nature and extent of the enforcement action is intended to reflect the
seriousness of the violation involved. For the vast majority of violations, a Notice of Violation or a
Notice ofNonconformance is the normal action.
A Notice of Violation is a written notice setting forth one or more violations of a legally binding
requirement. The Notice of Violation normally requires the recipient to provide a written statement
describing (1) the reasons for the violation or, if contested, the basis for disputing the violation;
(2) corrective steps that have been taken and the results achieved; (3) corrective steps that will be taken
to prevent recurrence; and (4) the date when full compliance will be achieved. The NRC may waive all
or portions of a written response to the extent relevant information has already been provided to the
NRC in writing or documented in an NRC inspection report. The NRC may require responses to Notices
of Violation to be under oath. Normally, responses under oath will be required only in connection with
Severity Level I, II, or III violations or orders.
The NRC uses the Notice of Violation as the usual method for formalizing the existence of a violation.
Issuance of a Notice of Violation is normally the only enforcement action taken, except in cases where
the criteria for issuance of civil penalties and orders, as set forth in Sections VI.B and VI.C, respectively,
are met. However, special circumstances regarding the violation findings may warrant discretion being
exercised such that the NRC refrains from issuing a Notice of Violation. (See Section VII.B, "Mitigation
of Enforcement Sanctions.") In addition, licensees are not ordinarily cited for violations resulting from
matters not within their control, such as equipment failures that were not avoidable by reasonable
licensee quality assurance measures or management controls. Generally, however, licensees are held
responsible for the acts of their employees. Accordingly, this policy should not be construed to excuse
personnel errors.
B. Civil Penalty
A civil penalty is a monetary penalty that may be imposed for violation of (1) certain specified licensing
provisions of the Atomic Energy Act or supplementary NRC rules or orders; (2) any requirement for
which a license may be revoked; or (3) reporting requirements under section 206 of the Energy
Reorganization Act. Civil penalties are designed to deter future violations both by the involved licensee
as well as by other licensees conducting similar activities and to emphasize the need for licensees to
identify violations and take prompt comprehensive corrective action.