ML20198L047
| ML20198L047 | |
| Person / Time | |
|---|---|
| Site: | Cooper  |
| Issue date: | 01/12/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20198L034 | List: |
| References | |
| 50-298-97-10, NUDOCS 9801150152 | |
| Download: ML20198L047 (28) | |
See also: IR 05000298/1997010
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ENCLOSURE 2_ !
U.S. NUCLEAR REGULATORY COMMISSION ,
REGION IV
. Docket No.: 50 298 '
License No.: DPR-46
Report No.: 50 298/97 10
Licensee: Nebraska Public Power District
Facility: Cooper Nu: lear Station
Location: P.O. Box 08
Brownville, Nebraska
Dates: November 2 through December 13,1997
Inspectors: Mary Miller, Senior Resident inspector
Chris Skinner, Resident inspector
Tom Meadows, Reactor Inspector
Approved By: Elmo Collins, Chief, Branch C
Division of Reactor Projects
ATTACHMENT: Partial List of Persons Contacted
List of Inspection Procedures Used
List of items Opened, Closed, and Discussed
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EXECUTIVE SUMMARY
Cooper Nuclear Station
NRC Inspection Report 50 298/07 10
Dactations
- The inspectors concluded that operations maintained proper control room conduct in
which good self checking techniques, communication, and briefb,g techniques were
used. The inspectors also observed that operations management exercised a strong
pre,sence and involvement in control room and plant activities (Section 01.1).
- The inspectors identified three examples where operability assessments did not
address all the relevant aspects of untimely 4100V electrical breaker preventive
maintenance. No operability assessment conclusion was determined to be incorrect
(Section 02.1).
- The inspectors identified procedure weaknesses and ambiguities when the plant was
placed in an alternate configuration. The procedures did not account for the
alternate configuration and the licensee f ailed to identify contingency actions to
compensate for these procedure weaknesses and ambiguities (Section 3.1).
- The licensee promptly implemented appropriate guidance to address four NRC
inspection findings that affected operations' procedures and knowledge. However,
the information transmittal to operators was weak and required inspector
involvement on four other inspection findings (Section O3.2).
Maintenance
- Some examples of equipment condition deficiencies were observed, in some cases,
these items resulted in M 5 voidable entry into action statements to repair equipment
(Section M2.1).
- The licensee addressed a steam leak and seat leakage promptly, although examples
of poor planning, workmanship, and troubleshooting were identified. The licensee
declared the reactor core injection cooling system operable without reinstalling the
metal jacket on piping and f ailed to recognize that it had been assumed to reduce
the heat loading on the room in a calculation. The contribution to the heat loading
was minimal but nonconservative (Section 2.2).
- Maintenance missed an opportunity to repair a steam leak during the scheduled
outage. As a consequence, a repair at power ivas performed that resulted in
additional radiation exposure and a longer out of service time for a safety system
(Section 2.3h
- A maintenance work order submitted to the control room which would have required
a plant shutdown to perform testing was ques.ioned and rejected after clearances
were hung but before the work order was implemented. This was the first
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s;gnificantly flawed work order submitted to the control room in over 4 months and ;
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represented a reduction in the frequency of challenges to the control room
(Section M4.1). ,
Engineering
- An error in testing resulted in an unnecessary removal of Reactor Equipment C' oling '
Heat Exchanger A from service for 5 days (Section E2.2).
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- A surveillance test of secondary containment door leakage used nonconservative
leakage values in calculating the operability margin for the standby gas treatment
and secondary containment systems. The minimum leakage through airlock doors
was used. This would result in a nonconservative operability margin if one of the - ,
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doors was opened or f ailed (Section E2.3).
- In March 1997, inspectors identified that three manual valves were used as
containment boundaries during installation of amodification without an evaluation of
their ability to perform this function under design basis conditions. Evaluation and
planning of the implementation of this modification during plant operation was '
inadequate. Af ter inspector questions, the licensee evaluated the primary
containment function and concluded that primary containment remained operable
during the modification (Section E4.1).
- The licensee appropriately identified, bounded, and addressed the seismic
considerations of valve operators of higher weight then specified. This error had
been introduced in a 1979 modification. The equipment had remained operable
(Section E7.1).
Plant Support
- Maintenance plannina and troubleshooting activities for repair of equipment in high
radiation areas were not wellimplemented. The equipment configuration was not
precisely known. Problems encountered during the activity resulted in additional
radiation exposure (Section R1.1).
- A memorandum to security shif t supervisors stated nonconservative battery power
duration for station blackout. This was promptly corrected (Section S3.1).
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Flaport Details
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Summarv of Plant Statua ,
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During this report period, the plant operated at 100 percent power, with the exception of a l'
' downpower for scheduled turbine valve testing on December 6,1997.
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l. Omarations
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01 Conduct of Operations
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01.1 General Comments .
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a. Inanaction Scone (71707)
The insper, tors observed day to day activities, control room shift changes, and shift !
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crew functions.
b. Observations and Findings
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Inspectors observed that turnovers included appropriate informatien and crews
focuwed on maintaining alert and questioning observation of plant conditions and
activities. Alarm response procedures were referenced and followed. Alarms were l
acknowledged quickly and cleared appropriately. Logkeeping was thorough and
addressed relevant plant conditions and indications. Operators exhibited good
self checking before control manipulations and practiced good communications
skills. Briefings by the shift technical engineers and operations management were
concise and address appropriate safety issues. >
Inspectors observed several examples where stalf and operations management
successfully demanded and f acilitated troubleshooting and equipment repairs.
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Operations also prioritized some engineering efforts to address operability issues,
such as diesel start anomalies, an instrument power supply failure, and regulator
valves design vulnerabilities, inspectors observed control room management
providing standards to perform work in a steady and conscientious manner. For
example, due to emergent work, the shift supervisor requested that work control
remove work from the schedule.
The inspectors observed that the professionalism of the control room had improved
in that the control room environment had become quieter when compared to recent
years. The inspectors determined thht this was apparently due to the licensee's
efforts to free control room operators from daily administrative tasks and move
these tasks to other organizations outside the control room,
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. c. Conclusions ,
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The inspectors concluded that operations maintained proper control room conduct in
which good self checking techniques, communication, and briefing techniques were
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used. The inspectors also observed that operations management exercised c strong
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presence and involvement in control room and plant activities.
i 02 Operational Status of Facilities and Equipment
02.1 Weak Ooerability_ Assessments
a. IDsoection Scoce (71707)
The inspectors reviewed operability assessments performed to address issues raised
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by an NRC SpecialInspection Team. Discussions were held with licensing,
maintenance, and engineering to resolve the operability concerns.
b. Observations and Findinos
The inspectors identified three operability assessments that -fid not address the
concern or contain all of the information in developing the conclusion.
0) The operability assessment for not performing 4160V breaker overhauls on a
5-year frequency in accordance with manuf acture's recommendations
addressed only six safety-related breakers that have never been overhauled.
The operability assessment did not address 14 safety-related breakers that
where beyond the manuf acturer's reccmmended overhaul frequency. The
inspectors determined that the licer.aee did not address these breakers based
on a recently developed standard for preventive maintenance for breakers,
which had not been implemented. This standard for preventive maintenance
for breakers and control circuits stated a 9-year overhaul frequency was
appropriate. All of the safety-related breakers were still within the proposed
9 year interval. The licensee issued Problem identification Report 2-20160
and wrote an operability assessment.
2) The operability assessment for Problem Identification Report 2 20160 did not
include or address Service Advice Letter 354.1, which recommended a
5-year overhaul cycle to ensure maximum reliability. The inspectors
concluded that the breakers were operable based on the original operability
assessment for the six safety related breskers, documented undet Problem
identification Reports 2-17801 and 217816.
6) The inspectors reviewed the operability assessment associated with
lubrication of the 4160V breakers (Problem Identification Report 2-20169)
and identified that it did not address the concern. The manuf acturer
recommended using oil to replenish the old grease lubrication properties and
the licensee used new grease without removing the old grease. The concern
was that the addition et new grease over old grease may not replenish the
old grease lubrication p operties. Problem Identification Report 2-03174 was
issued to doct. ment the weak operability assessment. Based on the
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compensatory actions in place and the breaker inspections, the inspectors
concluded that there was no immediate operability issue.
c .' Conclusions
The inspectors identified three examples where operability assessme N did not
address all the relevant aspects of untimely 4160V electrical brea' r ventive
maintenance. No operability assessment conclusion was determinaj u es int errect.
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03 Operations Proceoures and Documentation
03.1 Systems Placed in Alternate Confiaurations
a. Insocction Scone (71707)
Inspectors observed activities to address two cases of equipment out of normal
alignment,
b. Observations and Findingji
On November 16,1997, in response to a relay qualification concem, the licensee
aligned the plant monitoring information system to its alternate source, a nonvital
electrical source. This monitoring system provides the safety parameter display
system for event monitoring.
On November 18, the no-break power pand transferred from its normal power
source to Motor Control Center MCC-R, its backup power source. The licensee
initiated troubleshooting and lef t the no-break power panel aligned to its alternate
source. The no-break power panel primary power source is the "A" 250Vdc battery,
and the alternate source can be fed from either vital bus. Equipment controlled by
the no-break power panelincluded minimum flow valves for condensate, condensate
booster, and feedwater pumps, as well as various instrumentation and controllers.
On November 19,1997, the inspector noted that operations had not identified
specific procedural steps in abnormal and emergency procedures relying on
equipment fed from the no-break power panel and plant monitoring and information
systems. The associated station blackout and safety parameter display system
commitments had not been evaluated. 'spectors questioned if emergency or /
abnormal procedures relied on instruments powered by the no break power panel
normal source. The instruments would be uriavailaole in a station blackout. Based
on the inspectors' question, the licenne reviewed procedures and identified that
alternato instruments were available.
Inspectors identified that Emergency Proceoa..) G.2.5, " Loss of Normal AC Power-
Use of Emergency AC Power," indicated on Attachment 1 that, for Mctor Control
Center MCC-R, only motor-operated valves would affect dieselloading. The
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inspector noted that the no-break power panel, a 9.5kw load, was also fed from
MCC-R in this alternate alignment, and this had not been indicated by the procedure.
The inspecter noted that tne operators would not have clear information to account
for Motor Control Center MCC-R loads in this alternate alignment. The inspectors
also questioned how the licensee addressed peak loading. The normal configuration
would maintain a constant load through the 250 Vdc power source, and with the
no break power panel on the alternate power supply the load would not be constant.
Therefore, peak / final loading may be higher than assumed.
After discussion of this issue with the control room staff, the shift technical
engineer identified that Procedure 5.2.5.1, " Loss of All AC Power Station Blackout,"
Step 4.24.7, identified that the no-break power supply to security would have been
in use during a statidn blackout. The control room informea security that this power
source alternative was no longer available based on the current no-break power
panel configuration. Security response is documented in Section S3.1 of this report.
On December 1,1997, the licensee acknowledged that they could have identified
procedure steps which would be affected by the no break power panel and plant
monitoring and information system being out of service. An operations policy
(Attachment V) identified that, for off-normal plant conditions, expected
contingencies should be identified and documented in night orders. Operatic 7s
management identified the need to clarify requirements which identify contingency
actions and expected procedural challenges as a result of off-normallineups or
equipment f ailures,
c. Conclusions
The inspectors identified procedure weaknesses and ambiguities when the plant was
placed in an alternate configuration. The procedures did not account for the
alternate configuration and the licensee f ailed to identify contingency actions to
compensate for theste procedere weaknesses and ambiguities.
03.2 Lack of Clear Guidance RecardiDo Recent Desian insoection Findinos
a. lasoection Scoce (71707)
Inspectors observed licensee response to findings by the NRC Architect Engineering
Inspection (results to be documented in NRC Inspection Report 50 298/97 201),
inspectors observed Scensee actions to address findings regarding expected operator
actions and implementation of design requirements by operating procedures,
b. Observations and Findirigs
The licensee promptly implemented appropriate night orders and procedure changes
to address four NRC inspection findings that affected operations procedures and
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knowledge. However, for four other concerns, the information transmittal to
operators was weak and required inspector involvement.
1. Residual Heat Removal Pumo Minimum Flow limits: On November 20,1997,
inspectors identified that findings by the NRC team regarding required
minimum flow through residual heat removal pumps did not appear to have
been properly conveyed to the control room crew. Specifically, the pump
vendor stated that, for up to 15 minutes, residual heat removal pumps could
run two pumps simultaneously with minimum flow at 1450 gpm each. The
vendor also stated that each pump could run at 1800 gpm for up to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />,
and a minimum of 2800 gpm per pump was requirc,d for sustained pump
operation.
Operations had been trained that, !! two residual heat removal pumps
operated on minimum flow, one pump should be promptly secured. This
practice had been demonstrated in the simulator. However, the procedure
guidance and operator knowledge did not clearly state that, with two residual
heat removal pumps operating, one pump must be secured within 15 minutes
before vender specified limits were exceeded. After the licensee reviewed
the issue, the inspector identified that the license had not provided these
limits to operators. A night order was written in the context of emergency
core cooling system initiation.
Af ter reviewing the night order and pump vendor information, the inspector
pointed out that, under an inadvertent or unexpected residual heat removal
injection valve closure, the residual heat removal minimum flow valve would
open when flow dropped below 2500 gpm. This flow rate is
nonconservative with respect to the 2900 gpm required flow rate minimum
for two pumps (2800 gpm per pump for sustained pump operation).
On November 25, after discussions with inspectors, the licensee issued a
second night order which stated that time on minimum flow should be
minimized on each residual l. eat removal pump to a maximum of 10 minutes.
Residual heat removal pumps were not to be operated less than 1450 gpm
per pump. The pumps were not to be operated between 1450 and 1800
gpm per pump greater than 15 minutes; they were not to be operated
between 1800 and 2800 gpm per pump greater than or equa; to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> in
any 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period; greater than 2800 gpm were to be maintained for
continuous operation. This appeared to clarify the pump vendor's
requirements.
2. Procedure to Address Hiah Control Buildina Temoerature: The NRC team
identified inadequate clarity of the procedure addressing high control building
basement temperatures. On a loss of offsite power and accident conditions,
service water booster pump and air compressor operation would cause the
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control building basement temperature to rise to the point of equipment
damage. Procedures had insufficient detail and some procedures were in
conflict.
Based on design calculations, engineering concluded that, under all design
basis conditions, only one service water booster pump would be required to
provide conting. Use of a second pomp was desirable but not required.
Operators had not been informed that the instructions to shut off all but one
pump to maintain temperature were more limiting than the instructions to run
two pumps.
A procedure change was made to shut off service water booster pumps as
necessary, air compressors, and air dryers and clarified the reason for the
temperature limit (to protect service water booster pump bearings). The
licensee also initiated Night Order 97 36 to require operators to review the
changes made to the procedure.
3. Procedure inadecuacies for Hiah Temoerature Conditions: Inspectors
questioned if the crane referenced by Procedure 2.4.8.4.9, "Centrol Building
Temperature Ab > ie or Below Temperature Limit," for lif ting the three metal
floor panels was powered by vital power. Engineering walkdown confirmed
that the crane was powered by nonvital power. Operations identified chain
f alls which could be used to perform the step. However, operations
identified that they had not received adequate training to assure
accomplishment of the rigging in accordanco with site procedures.
4 Emeraency Core Coolino Pumo Room Temperature Limita Not Proceriv
Controlled: Inspectors identified that the instructions and control room
indications for emergency core cooling system pump room temperatures did
not specify operability lim;ts. The indicators included a green band which, for
some pump rooms, extended to a higher temperature than the maximum
assumed at the start of an accident. At the time this issue was raised,
temperatures wers within analysis assumptions.
Operations initiated a night order which clarified maximum temperature limits
and instructed operators to maintain temperature below analysis limits by
operating room coolers. Problem identification reports were initieted and
further permanent corrective actions for each of the above issues were
planned at the close of this inspection period,
c. Conclunons
The licensee promptly implemented appro riate guidance to address four NRC
inspection findings that affected operations * procedures and knowledge. However,
the iniormation transmittai 1 operators was weak and required inspector
involvement on four othe inspection findings.
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38 Miscellaneous Operations issues
08.1 (Closed) Licensee Event Reoort 50-298/97010-00 and 01: Standby gas treatment
inoperable due to a design deficiency. This licensee event report is closed since it
was discussed in NRC Inspection Report 50 298/97-012. Corrective actions will be
addressed in closure of Violation 97012-01 (EA 97 424).
08.2 (Closed) Unresolved item 50-298/97006-02: Failure to provide operations checklist
for component verification for shif t turnovers. On January 2,1980, the NRC issued
an order which required the licensee to provide control room turnover checklists as
described in NUREG 0578, " TIM-2 Lessons Learned Task Force Status Report and
Short Term Recommendations." The inspectors identified that the turnover
checklists did not list all of the critical parameters or specific plant components to
check in the control room, which was inconsistent with the requirements described
in NUREG-0578. On November 20,1997, the licensee implemented shift turnover
checklists which were more consistent with NUREG-0578.
The f ailure to have shift checklists as required by order dated January 2,1980, is a
violation. This f ailure constitutes a violation of minor significance and is being
treated as a noncited violation, consistent with Section IV of the NRC Enforcement
Policy (50 298/97010-03).
11. Maintenance
M1 Conduct of Maintenance
M1.1 General Comments
a. Insoection Scone (62707 and 61726)
The inspectors observed the following maintenance activities:
Special Procedure SP 97-014. Preparation of GE-2OOO shipping cask to
transport GE vessel samples
Mcintenance Work Request 97-0859, Replace Pressure Switch RHR-PS-105C
Surveillance Procedure 6.1CSCS.305, Core Standby Cooling Systems
Discharge Piping Full Low Pressure Af arm
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Troubleshooting and Repair of Reactor Core injection Coolant Drip Leg Line
Leak and Valve Seat Leakage
Repair of High Pressure Coolant injection Drip Leg Valve Packing Leak
Maintenance Work Request 971502, Troubleshooting of Diesel Generator 1
after f ailure to start
c. Conclusion
in general, appropriate practices were implemented to set clearances, follow
procedures, comply with radiation protection requirements, and perform
postrnaintenance testing and surveillance testing. Specific examples of exceptions
are described in this section.
M2 Maintenance and Material Condition of Facilities and Equipment
M 2.1 Summarv of Material Condition
a. Insoection Scone (62707)
During routine tours and document reviews, inspectors identified and assessed
various cases of material condition concem,
b. Qbittyhns and Findinas
1. Oil Leaks: Oil leaks and oil soaked pads were observed under equipment
items, including both diesel generators, condensate pumps, and feedwater
pumps. The rate of oilleakage was not considered highly significant since oil
addition had not been frequently required. Oil pooling under the diesel
generators appeared to be the most significant buildup and was only partially
alleviated by operations crew efforts. .
2. Identification of Numerous Steam Leaks: Steam leaks were identified in the
reactor core isolation cooling system and the high pressure core injection
system. The reactor core isolation system consisted of a throughwallleak
and a valve seat leaking by (Section M2.2), The high pressure core injection
system contained a valve packing leak that became worse over time
(Section M2.3).
3. Diesel Generator Failures to Start: Diesel Generator 1 failed to slow start
(nonemergency start) on three occasions (Section M2.4).
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4. Eculoment Failure Resulted in Alternate Plant Confiouration: The no break
power supply and the plant monitoring and information systems experienced
equipment failure that caused the systems to operate on alternate power
supplies (Section O3.1).
5. Residual Hent Removal Hea ; chancer Service Water Outlet Valves Leakace:
These valves were worked in the outage in April 1997 to stop leakage.
About a month after the end of the outage, leakage was noted through these
valves. This requires the licensee to sample service water outlet flow for
radioactive releases,
c. Conclusions
Some examples of poor material condition of specific equipment were observed, in
some cases- these items resulted in entry inte action statements to repair
equipment. These nction statement entrles could have been avoided in some cases
if repair activities had been effacted during the refueling.
M2.2 Reactor Core isolation Coolina Steam Sucolv Drio Leo Valve Leakaoe and
Throuchwall Leak
a. Insoection Scone (61707)
Inspectors observed activities to identify and conect a throughwall steam leak and
upstream valve seat leakage,
b. Observations and Findinas
On November 21,1997, the licensee identified water collecting in the torus area
under a steam tunnel piping penetration. A steam tunnel entrv identified a pin hole
steam leak on the reactor core isolation cooling drip leg return line to the main
condenser. The licensee further concluded that Valves RCIC-AOV 34 and -35,
upstream from the leak, allowed seat leakage.
1. Poor Plannino. Workmanshio. and Troubleshootino: planning by
maintenance and engineering resulted in a longer out-of service time for the
resctor core isolation cooling system during the repairs of Valve RCIC-AOV-
34. A larger valve was installed which resulted in a longer distance for
electrical cables, which required an electrician to be called back to the site.
Poor workmanship by maintenance failed to identify that the handwheel for
Valve RCIC-AOV-34 was in contact with the operator for Valve RCIC-AOV-
35 after installation of a new actuator for Valve RCIC-AOV 34. The
inspectors identified the problem and the licensee had to modify the
handwheel to preclude interference. This modification resulted in a longer
out of-service time for the system.
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Poor troubleshooting resulted in a longer out-of service time and greater
radiation exposure. The licensee troubleshooting determined the steam trap
was allowing steam to pass through. The licensee disassembled the steam
trap and found it in good working condition. Further diagnosis identified that
the seat for the steam trap bypass valve was leaking. The licensee
concluded they did not have enough time to repair the valve during the
Technica! Specification action statement. The licensee closed the valve as
tightly as possible and turned the system over to operations for testing.
2. Failure to Reaoanize Effect of Insulation Flashina on Heat Loadina
Assumotions: Insoectors noted that the reactor core isolation cooling system :
had been returnou to operable status before the metal Jacket was installed on
the insulation. Inspectors questioned if the heat loading calculations
assumed reduced heat loading as a result of the radiant heating precluded
due to the presence of metal Jacket. Engineers responded that the metal
Jacket did not provide significant insulation since the conductivity of matal
was relatively high. The inspector reviewed Heat Loading Calculation 89-
1927, " Review of Enercon Calculation NPP1 SBO 006 "RCIC Room
Temperature," dated October 24,1989, and identified that the contribution
of the linearized radiative heat transfer coefficient was included in the
calculation. The calculation used an emissivity of 0.1.
The limiting temperature in the room was approximately 160'F and the heat
loading calculation determined that the enaximum expected temperature in
the room was approximately 120*F without the metal flashing installed. The
licensee issued Problem identification Report 2-09007. The metal jacket was
reinstalled on December 1, in accordance with the existing maintenance work
request.
The licensee's corrective action at the end of this report period had consisted
of briefing engineers and operations oersonnel on this issue. The licensee
documented the need to evaluate the apparent causes r'f the f ailure to assess
calculation assumptions as well as failure to restore a ;ystem to its normal
configuration without an evaluation.
Radistion dose consideiations are discussed in Section R1.1 of this report.
c. Conclusions '
The licensee addressed a steam leak and seat leakage promptly, although examples
of poor planning, workmanship, and troubleshooting were identified. The licensee
declared the reactor core injection cooling system operable without reinstalling the
metal Jacket on piping and failed to recognize it had been assumed to reduce the
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heat loading on the room in a calculation. The contribution to the heat loading was
minimal but nonconservative.
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M2.3 Failure to Recalt Packino Leak Durina Outace Resulted in an inoot te High
Pressure Core Iniectio.D
a. [nsag.c11on Scooe (62707) 3
Inspectors reviewed licensee identification and repair of a valve packing leak in the
high pressure core injection steam line drip leg.
b. Qbservations and Findinos
On November 23, operators identified that a steam leak on Valve MS-AOV-790, a
high pressure core injection drip leg return line had changed from a small steam leak
to a significantly larger leak. The licensee isolated the high pressure core injection
system and repaired the leak.
The licensee personnel stated that this valve had leaked prior to the outage of soring
1997, but had not been repaired at that time. The licensee's documentation of the
problem had indicated a packing adjustment was needed rather than repair of a
steam leak. Based on the documentation, the licensee failed to address the safety
system operability consequences and the higher radiation exposure to repair the leak
at power.
c. Conclusions
Maintenance missed an opportunity to repair a steam leak during the scheduled
outage. As a consequence, a repair at power was performed that resulted in higher
dose and a longer out-of service penod for a safety system.
M2.4 Failure of the Diesel Generator to Slow Start
a. Insoection Scoce (62707)
The inspectors observed the licensee performing troubleshooting on Diesel
Generator 1. The inspectors held discussions with operations, maintenance, and
engineering personnel,
b. Observations and Findinos
On November 6,1997, Diesel Generator 1 f ailed to slow start during a
postmaintenance test for the replacement of the generator output breaker
(Maintenance Work Request 97-1502). The diesel generator reached 300 rpm for
1.5 minutes before shutting down. A second slow start,2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> later, was
performed af ter the %el oil and lube oil system line-ups were performed. The diesel
generator reached iull power (600 rpm) and successfully loaded to the bus.
l
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.
.
-12-
The licensee determined that the most likely cause of the failure was a diesel fuel oil
booster pump failure to start. The licensee replaced a relay in thu diesel generator
ncnemergency start logic. Eight hours after the second start, a third start was
attempted. This resulted in a similar f ailure as the first start (350 rpm for
1.5 minutes). From the monitored parameters, engineering concluded that low lube
oil pressure mused the diesel generator to shut down. The licensee identified
burned paint at various locations on the engine-driven lube oil pump. Maintenance
technicians replaced the engine-driven lube oil pump and performed a satisf actory
slow start which demonstrated operability.
On December 9, Diosel Generator 1 again f ailed to achieve rated conditions during a
slow start. On December 10, a succe:.sful fast start was performed. The licensee
concluded that this demonstrated that the diesel generator was operable.
The licensee is continuing efforts to determine the root causes of both (November
and December) diesel generator f ailures. The licensee issued Licensee Event Report
50-298/97-015. Inspectors will follow up on the licensee's root cause evaluation
and corrective actions during the licensee event report evaluation,
c. Conclusions
The licensee has not conclusively determined the cause of multiple failures to the
start of Diesel Generator 1.
M4 Maintenance Staff Knowledge and Performance
M 4.1 Inadeouate Soecification of Work Activity
a. Insocction Scone (62707)
The inspector followed licensee activities regarding preparations of maintenance
work packages.
b. Qhservations and Findinas
On October 6,1997, the control room staff prepared for Work Item 96-2198, " Time
Delay Relay Testing for Technical Support Center Emergency Feeders." After the
clearance was established, the licensee identified that this work item would require
entry into Technical Specification 1.0.J in order to perform postmaintenance testing
of the system. Technical Specification 1.0.J requires a 6-hour controlled shutdown
from power. The system was restored without performing the work. Af ter
discussion with the control room staff regarding the inadequate work package, the
scheduling organization issued Problem identification Report 2-18214 to document
incorrectly specified postmaintenance testing. However, the problem identification
_ _ _ - - - . _ _ _ . . . _ _ .__,m _ .. _. . _ _ m.- _ _ _ _ _
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report did not note the safety significance of the concern, i.e., that a Technical
Specification 1.0.J entry would have been required to perform the postmaintenance
testing.
,
c.. Conclusions
A maintenance work order submitted to the control room which would have required .
'
a plant shutdown to perform testing was rejected after clearancea were hung but
- before the work' order was implemented. This was the first significantly flawed
work order submitted to the control room in over 4 months and represented a -
reduction in the frequency of challenges to the control room.
M8 Miscellaneous Maintenance issues (92902)
M8.1 (Ocan) Licensea Event Raoort 50-298/97-015: Diesel Generator 1 failure to slow
l start. Section M2.4 discussed this topic. The licensee event report will remain
open to evaluate the licensee's root cause analysis and corrective actions.
'
111. Engineering
E2 Engicxig Support of Facilities and Equipment
E2.1 Dual Una Containment isolation Valves
,
l a. Innoaction Scone (Tl 2515/136.1
i
inspectors reviewed primary containment valves and provided emergency core
>
cooling system active communication and containtnent isolation, as described in the
temporary instruction. This was an information gathering temporary instruction.
The inspectors walked down plant configurations, reviewed procedures and the
i Updated Safety Analysis Report, and held discussions with operations and
4
engineering staff.
a
b. Observations and Findinas
,
a
This temporary instruction was implemented to determine if the containment
isolation function of a valve would be possible under all emergency conditions. The -
inspector requested liccnsee evaluation of three valves with dual functions. The
configurations for these three valves are described below.
1. Core Spray injection Valves CS-MO 12A and -128 received open signals on
an emergency core cooling system injection signal, if the valve must be ,
closed; operation of a key lock switch in the control room can close the
valves,
e
a
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2. Residual Heat Removal Minimum Flow Valves RHR-MO 16A and 16B do not
receive an emergency core cooling system signal. They are normally open.
The valves return minimum flow from residual heat removal pumps below the
water line of the torus. Therefore, the line is water sealed. These valves
shut after pump flow reaches 2500 gpm and open as flow decreases below
2500 gpm. If residual heat removal flow stops, these valves remain cian.
The licensee found that the valves could be closed if the associated pump
breakers were opened, but this information was not readily available in
procedures. .
3. Residual Heat Removal Injection Valves RHR-MO-25A and -258 do not close
if an emergency core cooling system signsiis present. Therefore, control
room personnel would not be able to close the residual heat removalinjection
valves under emergency core cooling system conditions. Under some
simulator scenarios, operators have closed a different valve in the injection
line, but these valves are not leak rate tested.
The information requested by Ti 2515/136 has been forwarded to NRR.
E2.2 incorrect Diaonosis of Reactor Eauioment Coolina Heat Exchanaer Outlet Valve Leak
a. I_nsoection Scone (37551)
Inspectors reviewed heat exchanger performance test activities which concluded
that the heat exchanger outlet valve leaked. Inspectors observed troubleshooting
activities and discussed this issue with maintenance and engineering staff.
,
b. Observations and Findinas
On November 26, the licensee performed reactor equipment cooling heat exchanger
performance testing. The test results showed a differential of 900 gallons per
minute and the licensee concluded that this flow was passing through Reactor
Equipment Cooling Heat Exchancer A Outlet Valve REC-MO-712. The safety
function of the valve is to shut on loss of raactor equipment cooling pressure to limit
loss during a line break. The Reactor Equipment Cooling Heat Exchanger A inlet
valve was shut and the heat exchanger was declared inoperable on November 26.
The licensee chose not to perform troubleshooting over the holiday weekend, since
proper assessment and repair of the as-found condition could require significant
licensee manpower.
On December 1, during subsequent probiem assessment, the licensee identified that
the valve was not leaking. The engineering staff had not accounted for a parallel
flow path for approximately 900 gallons per minute. The licensee had placed the
to assess the condition.
I heat exchanger in . _ _ - _ _ _ . _ ._ _
1
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.
-15
c .- Conclusions
An error in testing resulted in an necessary removal of Reactor Equipmeat Cooling
Heat Exchanger A from service for 5 days.
E2.3 insoection of Secondarv Containment Controls
a. {uspution Scooe (37551)
The inspectors evaluated issues found during the accomplishment of the
containment inspection Temporary Instruction 2525/136, inspectors held
discussions with engineering and operations staff,
b. Obsetyatiens and Findinas
During inspection of secondary containment valves and surveillances, the inspector
recognized the lack of a comprehensive valve checklist walkdown or lineup
procedure to establish secondary containment. The licensee issued Problem
Identification Report 2-02528 to document the lack of a process or program that
verifies that valves are in the correct position to establish secondary containment.
The standby gas operating procedure addressed only ventilation system dampers.
For primary containment, the license did not walk down normally shut, unsealed
primary containment valves, except upon restoration at the end of a refueling
outage. This is in accordance with their interpretation of NRC Safety Guide 11.
The licensee stated that this interpretation for both primary and secondary
containment valves will be reviewed.
On December 2, the inspector identified that the Procedure 6.SC.502, " Secondary
Containment Penetration Examination". Revision 2, calculation of operability margin,
was nonconservative. Step 2.4 defined the minimum path leakage as the leakage of
the door in a given airlock penetration which is the lowest. The lowest leakages are
sammed and subtracted from the standby gas treatment system service margin te
determine tha operability margin. The inspector identified that this process was
nonconservative since it would overestimate the operablility margin which would be
present when the airlock door with the lowest leakage was opened or f ailed.
The licensee identified that the last surveillance had indicated an opera 61ity margin
of less than 170 scfm flow. After assumption of the worst case f ailure on one set
of doors as well as personnel use of air-lock doors, the margin decreased to about
115 cfm. The licensee was evaluating a more appropriate methodology for
identifying the operability margin of the standby gas treatment system. As of
December 15, no information had been providad to operators that the margin to
standby gas treatment operability was potentially less than documented in the most
recent surveillance test. The failure to provide an appropriate methodology to
determine if the standby gas treatment system and secondary containment are
I
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operable is a violation of 10 CFR Part 50, Appendix B, Criterion V. Criterion V
requires that activities affecting quality be prescribed by procedures appropriate to
the circumstances (50 298/07010-01).
For piping systems which penetrate secondary containment, liquid loop seais are
used to maintain the secondary containment boundary. Examples are the
emergency core cooling system room sumps and some ventilation drain lines. The
seals are filled from inside the reactor building, in a poataccident environment, entry
into the containment would not be allowed. The inspector identified that no review
had been done to determine that these loop seats would remain full during an
accident. Also, no procedures were in place to refill the loop seals during an
accident, if necessary. The licensee stated that the loop seals remain operable for
60 days after filling and are filled every 30 days by surveillance procedures. Further,
evaluations are in place concluding that secondary containment is needed for only
30 days after an accident.
Valves RCIC AOV 34 and -35 are secondary containment isolation valves.
Valve RCIC-AOV 35 is not classified as essential, and the two valves are not
electrically independent, They are controlled from the same switch in the control
room. Similar arrangements are in place for other secondary containment valves.
Groups 4 and 5 isolations close the steam admission valves to reactor core isolation
cooling and high pressure core injection. These isolations occur in a high
temperature environment in the reactor core isolation cooling, high pressure core
injection pump rooms, or near the steam lines. These isolations do not close the
secondary containment isolation valves for those systems. The valves on the
reactor steam supply drip legs get closed signals once the pump / turbine starts to
run, and they re-open after the pump is secured. Instructions are not available to
operators to shut these valves in an isolution, nor to quantify leakage through these
valves to the condenser.
The piping downstream of Valve RCIC AOV 34 is classified as nonessential piping.
At one time,it had been seismically qualified. The licensee changed the Updated
Safety Analysis Report to remove the seismic qualification from some piping
between secondary containment isolation valves and the secondary containment.
The affected piping includes all piping which does not perform an active accident
mitigation function.
The sizing of accumulators to maintain valves in the closed position has been
inspected. Surveillance procedures provide assurance that the secondary
containment valves will remain closed for a minimum of one hour after a loss of
instrument air, inspectors questioned if all the valves f ailed closed.
The licenaea was evaluating the above questions at the end of the inspection period.
. Cont ol of secondary containment valves by procedures, the 30-day postaccident
operability requirement for secondary containment, the lack of independence of pairs
- _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ -_ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ __ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _
__ _ _ .- . . - _ . _ _ _ _ . __
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-17
of secondary containment valves, the lack of guidance to operators concerning drip
leg centainment valve isolation, removal of seismic qualifications from secondary
containment boundary piping, valve failure positions, and sealing and controlling of
secondary valve positions and will be further reviewed and will be an inspector
folionup item (50-298/97010-02),
c. Conclusions
A surveillance test of secondary containment door leakage used nonconservative
leakage values in calculating the operab".ty margin for the standby gas treatment
and secondary containment systems. The minimum leakage through airlock doors
was used. This would result in a nonconservative operability margin if one of the
' doors was opened or f ailed. This is a violation.
E4 Engineering Staff Knowledge and Performance
E4.1 Maintenance _Affectina Primary Containment
a. Insoection Scone (375511
The inspectors reviewed implementation of a design modification during power
operation and monitored the licensee's actions, inspectors observed the
- - implementation of the modification and discussed activities with operations,
engineering, and maintenance staff and management.
b. Observations and Findinas
in March 1997, opcrations personnel drained piping in accordance with work
instructions and Clearance Order 97000229. These instructions required closure of
Primary Containment Isolation Valves RHR-MO 57 and -67; Manual Valve RHR-V-
426, and opening a vent between the primary containment isolation valve ar.d the
manual valvo. No documentation had been provided with work instructions which
would indicate this valve would function as a primary containment isolation valve.
Local leak rate testing had been performed on the primary containment isolation
valves and as a consequence Valve RHR-V-426 had been tested during localleak
rate testing. Ve!ve RHR V-426 was found to be leak-tight in the nonaccident
direction.
J
The licensee closed Valve RHR V 426, directly upstream of Primary Containment
isolation Valves RHR MO-57 and -67, to install a piping tee between the primary
containment isolation valves and Valve RHR V 426. During the time while the
piping was vented, the vent path was established between Valve RHR-V 426 and
the isolation valves, defeating the containment be andary function of Valves RHR-
MO 57 and -67. Therefore, Valve RHR-V-426 became the containment boundary
valve. Technical Specifications referred to RHR-M(' 57 and 67 as primary
containment isolation system valves. Valve RHR-V-426 appeared to be fulfilling the
,
4
.
18-
primary containment isolation system function of RHR MO-57 and 67 with respect
to maintaining an emergency core cooling system source term within the primary
containment boundary. Valves RHR-MO 57 and 67 had a second isolation function
which was to isolate the direct pathway outside the secondary containment to
radwaste. Valve RHR-V 426 did not fulfill this function since a pipe cut directly
downstream of the valve, plus the positioning of Valves RHR-MO 57 and -67 in the
closed position during this modification, isolated the secondary containment
boundsry path,
inspectors noted that this configuration of Valves RHR-MO-57 and RHR-MO 67
existed for most of the design modification, except for the case where both valves
were open for draining the piping. In this case both valves remained energized and
would have respositioned on a primary containment isolation signal.
Valves RHR V 101 and 102 were also used as containment isolation valves. The
valves are located in the bypass line around Valve RHR-MO-20, a 20-inch valve
located at the crosstie between redundant trains of the residual heat removal
system. These valves, in the closed position, also provide isolation of the redundant
trains of residual heat removal. To install the modification, a pipe cut was made
between these two isolation valves, making them emergency core cooling system
containment isolation valves.
The inspector noted that, for these three valves used for a primary containment
boundary service, no leakage testing or evaluation had been performed. The
licensee later verified by direct observation that no leaking occurred through the
seats of Valves RHR-V-101 and -102. Valve RHR V 426 evidenced a small amount
of leakage. The licensee torqued the valve to eliminate the leakage.
The inspector noted that the ambient pressure of approximately 30 to 40 pounds
behind these three valves was provided by the residuai heat removal " keep-fill"
system. This was nonconservative with respect to the approximate 60 pounds
pressure expected under emergency core cooling system conditions. Also, the
licensee stated that localleak rate testing of Valves RHR-MO 57 and -67 required
approximately 60 psig pressure, which provided a leakage test of Valve RHR-V-426
in the nonaccident direction.
The licensee's operability evaluation, performed on March 13,1997, concluded the
primary containment was operable based on use of Valves RHR-V-101, -102, and
-426 as boundary valves.
During this modification, Valves RHR-V-101, -102, and -426 were used in a
potential primary containment boundary function. Source term would be expected
to be present in this system during emergency core cooling system conditions. No
analysis had been performed to substantiate use of these valves as primary
containment boundary valves. These valves are all located in secondary
ccntainment. The licensee acknowledged that an evaluation would be desirable,
<
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T
issued Problem identification Report 2-09074, and provided an operability evaluation
of the use of these three valves as primary containment boundaries.
This issue will be followed up to evaluate applicability of regulatory r_equirements for - l
primary containment isolation valves in Technical Specifications and to follow
licensee corrective actions and will be tracked as an inspector followup item
(298/97010-02),
c, Conclusion
inspectors identified that three manual valves were used as containment boundaries
during installation of a modification without an evaluation of their ability to perform
this function under design basis conditions. Evaluation and planning of the
implementation of this modification during plant operation was inadequate. After
inspector questions, the licensee evaluated the primary containment function and
concluded that primary containment remained operable during the modification.
E7 Quality Assurance in Engineering Activities
E7.1 Licensee identification of Incorrect Valve Ooerator Weiahts
a. Insnection Scone (37551)
'aspectors followed the licensee's efforts to identify, bound, and correct a problem
.
regarding weight of valve operators,
b. Observations and Findinas
During repair of Valve RCIC AOV 32, the licensee identified that the weight of the
replacement valve was higher than documented and required evaluation with respect
to seismic effects. The licensee also considered the weight of the actuator which
was not replaced. Upon weighing the actuator it was found to be 20 pounds
heavier than originally documented. The licensee reanalyzed this piping and
evaluated eleven other air operated valves with potentially nonconservative weights
documented in seismic analysis. Engineering found that these actuators were
installed by MDC 79-017 (12 total valves). All are steam trap bypass or isolation
valves. The engineering organization performed field walkdowns of pipin0 and
evaluations. The licensee concluded that piping and supports remained within code
allowables and Updated Safety Analysis Report limits and thus had remained
The f ailure to properly evaluate and control weight of equipment is a violation of
3
10 CFR Part A, Appendix B, Criteria Ill, which requires, in part, that measures be
established to correctly translate applicable regulatory requirements into drawings
and procedures and that measures be established for the selection and service for
suitability of application of parts and equipment that are essential to the safety.
O
_
.
20-
related functions of the structure, systems, and components. This nonrepetitive,
licensee identified and corrected violation is being treated as a noncited violation,
consistent with Section Vll.B.1 of 1ihe NRC Enforcement Policy (50 298/97010-04),
c. Conclusion
The licenae appropriately identified, bounded, and addressed the seismic
considerations of valve operators of higher weight than specified. This error had
been introduced in a 1979 modification. The licensee determined that the
equipment had remained operable.
E8 Miscellaneous Engineering issues
E8.1 (Closed) Violation 50-298/96009-03: Safety evaluation for in-core fuel sipping.
The inspector reviewed the licensee's closure of the condition-adverse to-quality
documentation and foJnd that it addressed the relevant issues. Training had been
performed. inspectors noted that in both NRC and licensee performance based
assessments,10 CFR 50.59 reviews had been, in general, more thorough and
addressed design basis requirements in a more comprehensive f ashion.
E8.2 (Closedl Unresolved item 50-298/95014-01: Operation of the spent fuel pool
cooling system. These concerns were addressed in Violations 50 298/96030-02
and 50 298/96030 03 associated with EA 96 0487 and 96-488. The concerns
described in this unresolved item will be addressed in the closure of the violation.
E8.3 (Closed) Violation 50-298/96024-04: Failure to update the Updated Safety Analysis
Report. These concerns were addressed in Violation 50-298/96024-14 associated
with EA 97-017. The issues of this open item will be addressed during closure of
the violation.
E8.4 (Closed) Violation 50-298/96031-03: Failure to perform 10 CFR 50.59 evaluation.
These concerns were addressed in Violation 50-298/9602414 associated with
EA 97-017. The issues of this open item will be addressed during closure of the
violation.
E8.5 (Closed) Violation 50-298/96031-04: Examples of failures to update the Updated
Safety Analysis Report. These concerns were addressed in Violation 50-
298/96024 14 associated with EA 97-017. The issues of this open item will be
addressed during closure of the violation.
. _ _ _ - _ _ _ _ _ _ _ _ _ - _ -
e
A
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IV. Plant Support
R4 Staff Knowledge and Performance in RP&C
R1.1 Ineffective Work Plannina and Execution Resulted in Additional Radiation Exoosure
a. inspection Scone f 7175Q1
Inspectors reviewed the work planning and execution of the repair of valves with
steam leaks,
b. Observations and Findinos
The steam leak in Valve MS AOV-790, the high pressure core injection drip leg drain
line, had been noted before the spring 1997 outage. The licensee had not
documented this problem as a steam leak and therefore did not accomplish the
repair during the outage. The steam leak securred upon plant startup and
subsequently worsened. Repair activities 'or this valve resulted in higher
accumulated dose at power than if the valve were repaired during a plant shutdown.
During implementation of the work, inspectcrs noted that work activities
demonstrated examples of f ailure to plan and troubleshoot effectively. Examples
included lack of recognition that the electrical cables would require replacement.
Af ter the valve operator was in place, the cables were recognized as too short.
Also, it was not recognized that the steam trap bypass valve was leaking until after
the steam trap was disassembled and found to be in good working order. Lastly, it
was not recognized that the handwheel of the valve was too close to the operator
of a nearby valve untilinstallation, requiring work in a radiation area to alter the
handwheel. The resolution of these problems resulted in additional radiation
exposure,
c. Conclusions
Maintenance planning and troubleshooting activities for repair of equipment in high
'
radiation areas were not wellimpiemented. The equipment configuration was not
precisely known. Problems encountered during the activity resulted in additional
radiation exposure.
4
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"
S3 Security and Safeguards Procedures and Documentation
S3.1 Nonconservative Guidance Regardina Station Blackout Effects on Security Svstem
a. insoection Scooe (71750)
Inspectors reviewed security actions in response to transfer of the no break power
panel to its alternate source. Discussions were held with operations and security
personnel.
b. Observations and Findinas
As discussed in Section O3.1, station blackout coping procedures require that,
4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> af ter initiation of a station blackout, the no-break power panel for the
security system inverter feeder be opened. The security staff issued a memorandum
to security shif t supervisors which stated that the existing security batteries would
be adequate for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The inspector noted this was nonconservative with
respect to the information provided by the shift technical engineer who had found
that the security batteries would be expected to last 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. Prior testing of similar
security batteries had indicated that the batteries lasted about 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and
20 minutes. Security immediately changed the meraorandum to document the need
to have all compensatory measures for station blackout in place 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> after Part
of a station blackout,
c. Conclusions
A memorandum to security shift supervisors stated nonconservative battery power
duration for station blackout. This was promptly corrected.
F8 Miscellaneous Fire Protection issues
F8.1 Minor Combustible Control Concerns
a. insoection Scoce (717501
The inspectors observed general plant housekeeping during plant tours and during
other inspection activities.
b. Observations and Findinas
The inspectors observed that, with minor exceptions, the f acility was reasonably
clean and well-lighted and the floors were clear and free from debris. The
inspectors, however, found small amounts of combustible debris in two combustible
free zones on the 903-foot level of the reactor building. These items were
immediately removed when the inspectors informed the control room staff. In
l
1
_____ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __
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response to these findings, operators performed a walkdown of the combustible
control areas and found a third instance of a small amount of combustible debris in a
combustible free zone.
c. Conclusion
Plant housekeeping was generally good, with the exception of small amounts of ;
debris in combustible free zones.
VI. Manaaement Meetinas
X1 Exit Meeting Summary
The inspectors presented the inspection results to members of licensee management at the
exit meeting on December 18,1997. 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 ider;tified.
l
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- ATTACHMENT- i
'
= :
PARTIAL LIST OF PERSONS CONTACTED -
'
a
-;
Licanama
-l
->
D. Buman,f AE inspection Response Team Leader '
P. Caudilli Senior Manager Site Support - ,
T. Chard,- Assistant Radiation Protection Manager - '
C. Gains, Maintenance Manager ;
M. Gillan,' Acting Performance Analysis Department Manager _'
P. Graham, Vice President
.
8. Houston, Licensing Manager ,
S. Minahan, Work Control Manager [
D. Madsen, Licensing Engineer.- '
{ L. Newman, Operations Manager -
< RJ Sessoms, Senior Manager of Quality Assurance
INSPECTION PROCEDURES USED--
= IP 37551::- Onsite Engineering . ,
IP 61726:' ~ Surveillance Observations :;
IP. 62707:'- Maintenance Observations
IP 71707:- Plant Operations -
IP -71750: - Plant Support Activities
IP 92901: - Follow up - Operations -
~
IP 92902: - Follow up - Maintenance
' IP 92903: . Follow up Engineering
Tl 2515/136 Operation of Dual Function Containm,nt Isolation Valves
E
.
ITEMS OPENED, OPENED AND CLOSED, CLOSED, AND DISCUSSED
Opened
'298/97010-01 VIO ' A procedure used an inappropriate methodology '
(Section E2.3).
~ 298/97010 02 lFI Various containment issues (Section E2.3 and E4.1).-
Onaned and Clgsad
298/97010-03:. :NCV. Inadequate' operations checklist for shift turnoverJ .;
-4
_ (Section 08.2).
-
298/97010 04. : NCV- - Valve operator weights more thal listed on design specification
(Section E7.11.~
_. ..
s
- T
s- +e 3 -_a -g--w- +b- me, e y- e p . wy
b3
. ge:.
.
8
2
, Closed
298/97010-00
298/97010-01 LER Standby gas treatment inoperable due to a design deficiency
(Section 08.1).
298/97006-02 URI Failure to provide operations checklist for component
verification for shift turnovers (Section 08.2).
298/96009 03 VIO Safety evaluation for incore fuel sipping (Section E8.1).
298/95014-01 URI Operation of the spent fuel pool cooling system (Section E8.2).
,
298/96024-04 VIO Failure to update the Updated Safety Analysis Report
(Section E8.3),
298/96031-03 VIO- (EEI) Failure to perform 10 CFR 50.59 evaluation
(Section E8.4).
298/96031-04 VIO (EEI) Examples of failures to update the USAR (Section E8.5).
Discussed
298/97015-00 LER Diesel Generator 1 failure to slow start (Section M2.4 and 8.1).
1
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