ML20247J245
| ML20247J245 | |
| Person / Time | |
|---|---|
| Site: | Limerick  |
| Issue date: | 05/11/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20247J230 | List: |
| References | |
| 50-352-98-02, 50-352-98-2, 50-353-98-02, 50-353-98-2, NUDOCS 9805210376 | |
| Download: ML20247J245 (49) | |
See also: IR 05000352/1998002
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket Nos. 50-352
50-353
License Nos. NPF-39
Report Nos. 98-02
98-02
Licensee: PECO Energy
Correspondence Control Desk
P.O. Box 195
Wayne, PA 19087-0195
Facilities: Limerick Generating Station, Units 1 and 2
Location: Wayne, PA 19087-0195
Dates: January 20,1998 through March 16,1998
Inspectors: A. L. Burritt, Senior Resident inspector
L. L. Eckert, Resident inspector j
F. P. Bonnett, Project Engineer, DRP j
A. Lohmeier, Senior Reactor Engineer, DRS !
L. A. Peluso, Radiation Specialist, DRS l
J. M. Trapp, Senior Reactor Analyst, DRS i
N. T. McNamara, Emergency Preparedness Specialist, DRS
Approved by: Clifford Anderson, Chief
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Projects Branch 4 :
Division of Reactor Projects
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9805210376 980511
PDR ADOCK 05000352
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EXECUTIVE SUMMARY
Limerick Generating Station, Units 1 & 2
NRC Inspection Report 50-352/98-02,50-353/98-02
This integrated inspection included aspects of PECO Energy operations, engineering,
maintenance, and plant support. The report covers an 8-week period of resident inspection
and region-based inspection in the Engineering and Radiological Environmental Monitoring
Program areas.
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Operations l
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e On three occasions, operators did not resolve why the 1B residual heat removal ;
(RHR) minimum flow valve was out of its normal position. Later, the licensee
identified that the valve failed closed as a result of a degradation of a transistor in 1
the analog trip unit. In each instance, operators re-aligned the system without
establishing an adequate bases for system operability. This failure to recognize
degraded performance also contributed to the delay in implementing appropriate
corrective action. (Section E1.1)
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e in general, operator response to the February 6, loss of shutdown cooling event,
l was appropriate and timely with the exception of a minor procedure compliance
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error. The operating procedures used to respond to this event were acceptable with
minor exceptions that were addressed by corrective actions following the event.
(Section 01.2) '
e The reactor water cleanup jumper installation, the initiating action for the loss of
shutdown cooling event, was properly controlled in accordance with plant
procedures. However, the individual installing the jumper failed to take adequate ,
precautions. The flow blockage in the RWCU bottom head drain line, which created 1
the need to install the jumper, should have been classified and tracked as an
operator work-around. (Section 01.2)
e The corrective actions planned and implemented for the loss of shutdown cooling
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event were generally adequate; however, the root cause of the initial inability to re-
open the shutdown cooling isolation valve was not identified. In addition,
weaknesses were noted with the licensees post-event review process. (Section
01.2)
I e Operators conducted the Unit 1 startup wellin a controlled fashion. Additional
control room operators helped to minimize disturbances on the operator withdrawing
the control rods. Good support by the reactor engineering staff was observed.
(Section 01.3)
e Equipment operators performed well during routine tours. The operators were
aware of plant parameters and alert to changing plant conditions. (Section 01.4)
e Operators responded well to degraded flow indications for the Unit 1 No. 2 jet
pump. Engineering and I&C technicians supported the operations staff in
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Executive Summary (cont'd)
determining the operational condition and status of the clogged jet pump.
Management implemented more restrictive limits for operation of the unit prior to
and after the GE aaalysis was performed. (Section 02.1)
- Deihiencies were identified with the control of locked valves, in that, a suppression
pool hatch valve was not properly locked after a local leak rate test. This was a
repetitive failure indicative of ineffective corrective actions for previous, NRC
identified, locked valve problems. (Section 08.2)
Maintenance
- Deficiencies wera identified with the configuration control process when returning
the secondary meteorological tower back to service after a calibration. This led to
the operations staff improperly declaring a monitor operable prior to correction of all
idar tified deficiencies. (Section M1.3)
.Enaineerina
e Engineering efforts to identify the root cause of the 1B RHR minimum flow valve
inadvertent closures demonstrated inadequate troublesboting. Initial efforts were
iarrowly focused and based on faulty assumptions. This failure to identify the root
cause led to ineffective corrective actions and resulted in multiple modes of the RHR
system being inoperable for extended periods of time. (Section E1.1)
- The licensee failed to fully implement a 1990 LER corrective action commitment
that involved replacement of potentially defective transistors in a select population
of safety-relatad analog trip units. In addition, the recent operability determination
addressing these transistors remaining in service, was not timely nor
comprehensive. (Section E1.1)
- The engineering staff did not aggressively pursue comprehensive troubleshooting,
testing, and component inspection of the HPCI turbine exhaust valve following
multiple failed valve surveillance. Prior to the fifth failure of this valve to stroke, a
conclusive root cause was not identified and consequently led to ineffective
corrective action, which in turn resulted in this valve, being inoperable for an
extended period of time. (Section E2.1)
- The operability determinations associated with the failure of the HPCI exhaust valve
to stroke closed were flawed. The determinations did not take into account the
closing time required by technical specifications. (Section E2.1)
Contrary to the recent and otherwise poor performance regarding the RHR minimum flow l
valve and the HPCI turbine exhaust valve, a number of positive longer term initiatives
were noted including:
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Executive Summary (cont'd)
e Engineering used a comprehensive approach to assess performance of plant
systems. Several systems not meeting plant performance criteria have been
identified and corrective action focused on these systems. (Section E1.3)
e LGS has implemented a program to identify chronic plant issues and provides for a
comprehensive program to monitor resolution of these issues. (Section E1.4)
l e LGS has developed a comprehensive " BOP 700 Strategy" to improve BOP system
performance and reliability. LGS implemented parts of the strategy in resolving
system problems and performing work to address equipment degradation. (Section
E1.5)
e PECO proactively prepared to identify the onset of vibration in the recirculation
system by placing vibratory sensors at critical locations on the recirculation system.
(Section E2.3)
Plant Sucoort
o Overall performance was good and the radiological environmental monitoring
program was effective, although an instance of poor attention to detail was noted
invciving the rough handling of a sample filter. (Section R1.1)
e The meteorological data acquisition was good. However, a weakness was noted
with the calibration and maintenance programs for the meteorological
instrumentation and related equipment. (Section R1.2)
e The QA audit requirements were met and the contractor's QA/OC program for the
REMP provided effective validation of analytical results. (Section R7)
e The licensee found a locked high radiation door in an unlocked and unguarded
condition. The c.orrective actions for this issue were appropriate. (Section R8.1)
e Regarding the loss of shutdown cooling event that occurred on February 6,1998,
while emergency resporise procedures did not explicitly require the event to be
classified as an emergency condition, we found that the crew on shift at the time of
the event did not consult the Nuclear Emergency Plan and Emergency Response
Procedures, which was a licensee expectation, to determine if plant conditions met
emergency action level criteria. The licensee's initial investigation into this matter
was poor; however, following discussions with the NRC, a more thorough
investigation was conducted. The licensee developed adequate corrective actions
from the event. (Section P8.1)
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TABLE OF CONTENTS
EX EC UTIV E S U M M A RY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ii
TA BLE O F C O NTE NTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . v
l Summary of Plant Status ............................................1
1 O pe r a tio n s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
01 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
l 01.1 General Comments .................................2
l 01.2 Loss of Shutdown Cooling Event - Unit 1 .................. 2
01.3 Startup Operation - Unit 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
01.4 Equipment Operator (EO) Performance . . . . . . . . . . . . . . . . . . . . 9
O2 Operational Status of Facilities and Equipment .................. 10
O2.1 Clogged Jet Pump - Unit 1 ...........................10
08 Miscellaneous Operations issues ...........................11
08.1 Revision to Technical Specifications Regarding Control Rod 50-27,
LGS, Unit 1 (TAC Nos. M99854 and M99855) .............11
08.2 (Closed) VIO 50-352,353/97-07-01 Control of Locked Valves
and Devices .....................................11
II . M aint e na n c e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
M1 Conduct of Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
M 1.1 General Comments on Maintenance Activities ............. 13
M1.2 General Comments on Surveillance Activities . . . . . . . . . . . . . . 14
M1.3 Configuration Control - Meteorological Tower Surveillance Test
implem entation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
M8 Miscellaneous Maintenance issues ..........................16
M8.1 (Closed) LER 50-352/1-97-012: Unplanned Closure of a Primary
Containment isolation Valve . . . . . . . . . . . . . . . . . . . . . . . . . . 16
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l 111. E ngin e e ri n g . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 7
E1 Conduct of Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
E1.1 Residual Heat Removal Minimum Flow Valve Operability and
Corrective Actions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
E1.2 Limerick Unit 1 and 2 Gross Power Generation . . . . . . . . . . . . . 22
E1.3 Limerick System Assessment .........................22
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E1.4 Equipment Performance and Material Condition . . . . . . . . . . . . . 23
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E1.5 Balance of Plant System improvement . . . . . . . . . . . . . . . . . . . 24
E2 Engineering Support of Facilities and Equipment .................24
E2.1 (Closed) URI 97-10-06, High Pressure Coolant Injection (HPCI)
Turbine Exhaust Valve Corrective Actions . . . . . . . . . . . . . . . . . 24
E2.2 Turbine Retrofit Project Oversight ......................28
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E2.3 Recirculation Pump Vibration . . . . . . . . . . . . . . . . . . . . . . . . . . 28
E2.4 Agastat Relays ...................................29
l E3 Engineering Procedures and Documentation . . . . . . . . . . . . . . . . . . . . 29
E3.1 LG S UFS AR Review . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 9
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Table of Contents (cont'd)
E8 Miscellaneous Engineering issues ...........................29
E8.1 (Closed) LER 50-352,353/1-97-009 Residual Heat Removal
Service Water (RHRSW) Radiation Monitor Incorrectly Configured . 29
E8.2 (Closed) LER 50-353/2-97-010: Failure to Perform a First Cycle
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Analysis of a Reactor Flux Wire Specimen.
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E8.3 (Update) IFl 50-352/97-07-02; Reactor Water Cleanup (RWCU)
Is ola tio n s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 0
E8.4 Spent Fuel Pool (SFP) Local Power Range Monitor (LPRM) Storage I
and Seismic Qualifications of the Cask Storage Pit ..........30
I V. Pla nt S u pport . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
R1 Radiological Protection and Chemistry (RP&C) Controls . . . . . . . . . . . . 31
R1.1 Implementation of the Radiological Environmental Monitoring
Prog ra m . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
R1.2 Implementation of the Meteorological Monitoring Program . . . . . 33
R1.3 RP Controls on Refueling Floor Skimmer Surge Tank Modification
..............................................34
R2 Status of RP&C Facilities and Equipment ......................34
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R2.1 Turbine Building Roof Special Study . . . . . . . . . . . . . . . . . . . . . 34
R2.2 Computer Upgrade and Chart Recorder Replacement . . . . . . . . . 35
R3 RP&C Procedures and Documentation . . . . . . . . . . . . . . . . . . . . . . . . 35
R7 Quality Assurance in RP&C Activities . . . . . . . . . . . . . . . . . . . . . . . . . 35
R8 Miscellaneous RP&C Activities .............................36
R8.1 Locked High Radiation Area (LHRA) Door #345 Found Open . . . . 36
R8.2 (Closed) IFl 50-352:353/97-07-06 Ventilation System Charcoal
Efficiency Testing Adequacy . . . . . . . . . . . . . . . . . . . . . . . . . . 36
P8 Miscellaneous EP issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37
P8.1 Emergency Preparedness Assessment of the Loss of Shutdown
Cooli ng . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 7
~ V. Management Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 9
X1 Exit Meeting Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 9
X2 Review of UFSAR Commitments . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39
ATTACHMENT
Attachment 1 -Inspection Procedures Used
- Partial List of Persons Contacted
-Items Opened, Closed, and Discussed
- List of Acronyms Used
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Report Details
Summary of Plant Status
Unit 1 began this inspection period operating at 100%. During the period the unit entered
into end-of-cycle (EOC) coastdown operations. Further, the following plant transients and
events occurred:
- January 30 Operators shutdown the unit to repair the high pressure coolant
injection (HPCI) turbine exhaust valve after the valve failed to stroke
during its increase frequency surveillance test. The unit was restarted
on February 4.
- February 5 During startup activities with the reactor at 4% power, PECO
personnel identified two valves with packing leaks and a steam leak
issuing from the HPCI discharge to feedwater isolation valve in the
outboard main steam isolation valve (MSIV) room. PECO
management decided to shutdown the unit to repair the leaks.
Operators made the reactor critical on February 7, and raised power {
to 100% on February 11.
- February 11 Shortly after reaching 100% power, an operator performing the daily
jet pump verification surveillance test (ST-6-043-320-1), identified
that the No. 2 jet pump was outside of its acceptable deviation with
respect to the 'B' recirculation pump flow. After reducing reactor ;
power to 75% for a rod pattern adjustment, PECO decided to remain 1
at this power, as a conservative measure to minimize vibration stress
to the jet pump riser should the No. 2 jet pump be clogged. Senior
management imposed a flow limitation until General Electric (GE) l
could evaluate the jet pump operational condition. l
- February 15 Operators reduced reactor power to 65% to perform a control rod
pattern adjustment, then raised reactor power to 85%. The No. 6
feedwater heaters (FWHs) were removed from service in accordance
l with the EOC coastdown strategy as stated in procedures GP-5,
Power Operations, and SO 2.2.B, " Removal of Steam Side of Fifth
and Sixth Stage FWH From Service During EOC Coastdown." Power
was then increased to 97% with recirculation flow.
- February 23 An employee of the Overhead Crane Company was injured while
i performing calibrations of a hoist limit switch on top of a turbine
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building crane. The individual was wearing a safety harness with an
attached lanyard, which was not tied-off since the individual was ;
l working on a platform with railings. The lanyard became entangled in
l a rotating drum of the crane pulling the individual into the machinery
l causing him to receive several serious injuries. The individual was
partially frisked prior to being transported to the hospital and later
confirmed not to be contaminated at the hospital. The inspectors
referred the incident to the Occupational Safeti, and Health
Administration (OSHA).
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e February 23 After reactor power had coastdown to 92%, operators removed the
No. 5 FWHs and raised power to 97% with recirculation flow. {
e March 6 Operators raised reactor power to 100% after GE determined that
safe operation could continue with recirculation flow as high as 110%
and a delta flow between jet pumps Nos.1 and 2 less than 45%.
The unit continued to coastdown ending the inspection period
operating at 96% power.
Unit 2 began this inspection period operating at 100%. The unit remained at full power
throughout the inspection period with exceptions for testing, rod pattern adjustments, and
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the following plant evolution.
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e ' January 27 Operators reduced reactor power to 93% to remove the 6A feedwater ,
heater (FWH) from service to repair a steam leak on the extraction
l steam line bleeder trip valve. Operators restored power to 100% on
l January 28.
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l. Operations
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l 01 Conduct of Operations'
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01.1 General Comments (71707)
Using Inspection Procedure 71707,the inspectors conducted frequent reviews of
ongoing plant operations. In general, PECO Energy's conduct of operations was ,
professional and focused on safety principles.
01.2 Loss of Shutdown Coolina Event - Unit 1
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a. Insoection Scope (71707,93702)
Resident and Region i based inspectors conducted a review of operator response to
the safety significance of, and the procedures quality for a temporary isolation of
shutdown cooling that occurred at Limerick Unit 1, on February 6,1998. Review of i
the emergency plan implementation, including event notification and follow-up !
assessments performed by the emergency preparedness organization, are discussed !
separately in Section P8.1 of this report. l
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1 Topical headings such as 01, M8, etc,, are used in accordance with the NRC standardized reactor inspection report outline. Individual
reports are not expected to address all outline topics.
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b. Observations and Findinas
Event
On February 5,1998, following the Unit 1 shutdown, operators placed the reactor
in a cold shutdown condition (mode 4), to conduct corrective maintenance on a
leaking HPCI valve. At the time of the event, the residual heat removal (RHR)
system was in service in the shutdown cooling (SDC) mode of operation. One
recirculation pump remained in service and operated throughout the duration of this
event. On February 6, at 12:17 a.m., a personnel error resulted in an inadvertent
emergency safeguards function isolation affecting the shutdown cooling system.
The error occurred while an operator was installing an electrical jumper used to
restore the reactor water cleanup (RWCU) system to service. The operator
installing the jumper inadvertently touched the jumper to ground resulting in a blown
fuse in the nuclear steam supply shutoff system (NSSSS). The loss of power
caused several containment isolation valves (CIV) to close including, the outside
containment shutdown cooling system suction isolation valve (HV-051-1FOO8). The
closure of this valve appropriately resulted in an automatic trip of the operating RHR
pump and the loss of SDC.
The SDC system was out-of-service for approximately 55 minutes. The reactor
coolant system (RCS) temperature was at 187'F at the time the SDC system was
lost. The RCS temperature reached a maximum of 206.5'F at 1:12 a.m., causing
an unplanned entry into a hot shutdown condition (mode 3) before operators
restored the SDC system to service. Following restoration of the SDC system, the
RCS temperature was reduced to below 2OO* F by 1:21 a.m.
Safety Significance
The inspectors determined that overall there were no safety significant
consequences associated with this event because RCS integrity was maintained
throughout the event. Plant configuration and available alternate decay heat
removal sources mitigated this event. All normal and emergency systems, including
several alternate means of decay heat removal (with the exception of the HPCI
system) were available. The plant had reached cold shutdown (mode 4) at 12:02
a.m., on February 6,1998, and had been in mode 4 for approximately 15 minutes
when SDC was lost. Therefore plant conditions necessary for entering hot
shutdown (mode 3) remained established. Further, forced reactor vessel circulation
was maintained throughout this event by the operating recirculation pump.
The inspectors determined that this event was potentially significant because the
reactor plant underwent an unplanned mode change from mode 4 to mode 3. The
SDC system remained out-of-service for approximately 55 minutes and several
operational difficulties challenged the operations staff during attempts to return SDC
to service. The RCS pressure boundary was intact with the exception that the
reactor vessel head vent valves were open. The operators interviewed indicated
that they intended to close the head vent valves if RCS temperature had exceeded
212 * F, which is consistent with GP-3, Plant Shutdown procedure. Primary
containment integrity was established with the exception being that the isolation
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signals were bypassed for the reactor enclosure cooling water (RECW) for the
recirculation pump seals (HV-013-108 & 11) and the SDC isolation valves (HV-051-
1FOO8 & 1F015A,B). The isolation valves automatic closure signals were
bypassed, in accordance with procedure, to allow the recirculation pump to
continue operation and to restore shutdown cooling to service.
Jumoer Installation
An operator was installing an electrical jumper in accordance with procedure
S44.1.A, RWCU Cold Startup, to restore the RWCU system to service. The RWCU
system had automatically tripped due to low suction pressure during the cooldown
of the RCS. The jumper bypassed the low suction pressure and the RWCU
differential flow trips to minimize the operator actions necessary to return the
RWCU system to service.
The RWCU system trip was a recurring event during plant shutdown. An apparent
flow reduction occurs in the lower reactor vessel head drain line causing reduced
net positive suction head for the RWCU pumps and the pumps trip on low suction
pressure. The operators, per plant procedures, throttle the RWCU suction flow from
the recirculation system loop, to maximize the bottom vessel flow, thus minimizing
thermal stratification in the vessel. PECO plans to remove the flow blockage, during
the next refueling outage (1RO7), however, this deficiency was not being tracked as
an operator work-around (an equipment problem that can impair an operator's ability
to control plant parameters).
PECO considered that installing the jumper was a satisfactory means for restoring
the RWCU system. The differential flow isolation of RWCU is not required by
Technical Specifications (TSs) when the plant is in cold shutdown (mode 4). The
low suction pressure trip is for pump protection and is not required by TSs. The i
jumpers are only temporarily installed (about 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />) and are installed and removed
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in accordance with plant procedures. The jumpers are administratively tracked
using a Troubleshooting Control Form (TCF) in accordance with Administrative
Procedure A-41.1, Troubleshooting Plant Equipment. The RWCU System Engineer
stated that the necessity and design of this jumper would be evaluated as part of ,
j the corrective action process following this event. )
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The inspectors concluded that although the event was initiated by the jumper j
installation, the jumpering process was adequately controlled in accordance with '
plant procedures. Field observations determined that the jumper installation process j
did not place inappropriate expectations on the operator and the event was due to i
human error. The inspectors concluded the flow blockage in the bottom vessel {
RWCU drain line should have been tracked as an operator work-around. '
l Operator Actions
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Control room operator's response to this event was appropriate and timely with the ,
exception of a minor procedural compliance error and the Shift Managers's failure to l
reference emergency preparedness procedures. The emergency preparedness ]
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aspects are discussed in Section P8.1 of this report. The operators were challenged
by several events, including several attempts to reopen the SDC suction valve (HV-
51-1 FOO8).
The inspectors conducted interviews with the operators on shift at the time of the
event, reviewed post event operator written assessments and reviewed the operator
logs to assess the quality and timeliness of the operators' response to this event.
The operators immediately suspected that a fuse blew during the installation of the
RWCU jumper and had caused the SDC isolation. The floor supervisor (SSV) was
dispatched to assist the equipment operator (EO) in identifying the blown fuse. The
control room operators entered off-normal Procedure (ON)-121, Loss of Shutdown
Cooling, which provided instructions for bypassing the closing logic for the SDC
l. isolation valve. An EO was dispatched to install this jumper in accordance with the
l procedure.
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The operators wanted to maintain the recirculation pump in service to maintain
forced circulation in the reactor vessel. The operators recognized that the RECW
had been isolated from the operating recirculation pump. The operators were aware
of the 10 minute requirement to either restore RECW or to secure the recirculation
pump. However, the isolation valve, which had closed as a result of the inadvertent
, NSSSS isolation, was reopened in accordance with ON-113, " Loss of RECW" 12
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minutes later. The valve was opened by using key lock bypass switches installed in
the main control room. The operators appropriately entered a 4-hour Technical
Specification action statement as a result of blocking the automatic containment
j isolation closure for these valves. The bearing temperature were being monitored
during the event and none of the monitored temperatures approached the alarm
setpoints. The recirculation pump was operating at minimum speed and therefore
required less timely restoration than that which was the basis for the 10 minute
RECW restoration requirement. The inspector found the operators actions not to be
consequential in this case. The failure to restore RECW in 10 minutes constitutes a
violation of minor significance and is being treated as a non-cited violation,
consistent with Section IV of the NRC Enforcement Policy. (NCV 50-352: 50-
353/98-02-01)
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The Floor SSV identified the location of the blown NSSSS fuse and the fuse was
replaced. The NSSSS logic was reset in the control room and operators attempted
to reopen the SDC suction valve (HV-51-1FOO8). The valve failed to open and a
control room alarm indicated that the valve had tripped on thermal overloads
(TOLs). An operator was dispatched to the breaker and the TOLs were reset. A
second attempt to open the valve also resulted in tripping the TOLs. Two operators
were dispatched to the valve to manually unseat the valve. After manually
- unseating the valve, the valve was remotely opened from the contrci room. The
SDC system was restored and the plant was returned to cold shutdown (mode 4).
Operatina Procedures i
The inspectors concluded that the operating procedures used to respond to this
event were acceptable, with a few exceptions. The licensee identified one
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i deficiency in procedure ON-121, Loss of Shutdown Cooling. The procedure 1
I
instruction for the recovery of the SDC suction valve required the installation of a
jumper to bypass the isolation logic contacts. For the case where control power is
lost, as was the case during this event, bypassing the logic contacts when control
power is not available will not be successful. The System Engineer stated that this i
procedure will be reviewed for enhancement as part of the corrective action process
reviewing this event. Tho inspector also noted some inappropriate restrictions in
the general and system operating procedures associated with the irnplementation of
an alternate cooling method. Specifically, the use of the procedures was
unnecessarily restricted to cold shutdown conditions. These deficiencies were
promptly corrected to expand the conditions for which the procedures can be used,
consistent with the UFSAR.
SDC Suction Valve Failure
The inspectors determined that the licensee failed to identify the root cause of the
SDC suction valve (HV-51-1F008) failure. Following the event, the licensee
conducted three valve strokes in an attempt to identify the cause for the failure of
this valve to reopen. During one valve stroke, an evaluation of the valve was
conducted using the motor-operator valve (MOV) diagnostic test equipment. The l
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test results indicated that the valve was functioning properly. The limit switches
were properly bypassing the torque switch during valve unseating. The TOLs were ;
also replaced and tested. The tests identified no abnormalities in the operation of
the TOLs.
The inspectors reviewed the components engineers evaluation of the SDC valve
failure. The evaluation stated that the TOLs were reported as tripped upon valve
isolation by a shift supervisor (this was not confirmed with the inspectors
discussion with the shift supervisor). The TOLs are bypass in the closed direction
and the torque switch stops valve closure. However, the TOLs alarms will still l
actuate in the closed direction. In the open direction, the TOLs can be bypassed by
holding the control switch in the open direction. The licensee evaluation stated
that the first attempted opening of the valve resulted in a TOLS trip of the valve
when the control switch was returned to the neutral position (the TOLs had already
tripped on the closed stroke). The TOLs were reset and the licensee's evaluation
states that the second attempt to open the valve failed because the mechanical
neutral zone which allows for the hammer blow to unseat the valve was removed
during the first open attempt. The absence of the hammer blow to unseat the valve
caused the TOLs to actuate. The valve was then opened successfully following
manually unseating the valve.
The valve is a horizontally mounted, flex wedged gate valve. This type valve could
be susceptible to thermally induced pressure locking. The licensee's component
engineers stated that thermalinduced pressure locking was not considered a
plausible root cause because of the small temperature change during this event.
Following additional discussions with the licensee concerning the elevation
differences and physical separation between the valve in question and the RCS, the
source of the temperature change, and the lack of a flow path between the valve
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7
and the RCS, the inspector also concluded that pressure locking was not probable.
Following these discussions the licensee plans to perform preventative maintenance
on the HV-051-1FOO8 motor operator during the upcoming outage. The initial
failure of the HV-051-1FOO8 to re-open electrically following the loss of shutdown
cooling event is an inspection follow-up item pending the inspections of the motor
operator, during the planned preventative maintenance. (IFl 50-352;353/98-02-02)
The inspectors concluded that the licensee failed to identify the root cause of the
valve failure. The inspectors also noted that the operator interviews verses the
written operator statements were not consistent as to the sequence of events
related to the thermal overloads tripping.
Post Event Review and Corrective Actions
Following the event the licensee initiated a performance enhancement program
(PEP) evaluation to address the cause of the event and implement corrective
actions. PECO determined the cause of the event to be inadequate precautions
taken by the operator installing the jumper, the excessive risk associated with
installing the jumper, and the operator work-around (installation of the jumper) that
was created as a result of the RWCU pump tripping on low suction flow as a result
of flow blockage.
I
The corrective actions included replacement of the jumpers typically used with a
shielded version that would minimize the potential of inadvertent grounding of
circuits; the operator involved was counseled; additional direct supervision, for an
interim period, will be provided during jumper installation; operations crews were
briefed on the event and the use of the new style shielded jumpers; and the licensee
plans to revise the associated procedure to include additional precautions when
installing jumpers in the RWCU systern. In addition, the operator intervention
required to restore the RWCU system to service has been added to the operator
work-around list for evaluation and resolution, and the shutdown procedure was
revised to remove RWCU from service during reactor depressurization pending
resolution of this issue. The licensee's corrective actions also included review of
other normal, off-normal, and transient procedures to ensure that there were not
additional similar issues that may create an operator challenge or operator work-
around. The licensee plans to focus on jumpers that are installed in panels that
have equipment important to safety.
During the follow-up to this event the inspector noted that personnel statements
and available objective evidence were limited, making it difficult to reconstruct the
sequence of events and associated timeline. The inspector found the written
statements prepared by personnel involved in the event were widely varied and
provided only limited factual information. Formal or standardized personnel
questionnaires were not used and are no longer available in procedure LR-C-10,
" Performance Enhancement Program." The inspector attended the post-event
critique and observed a brief discussion on the general sequence of events followed
by a discussion of what went well and areas for improvement. The debrief was not
adequately focused on a detailed reconstruction of what happened. The inspector
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found only limited objective evidence available through the plant monitoring system.
In addition, the ability to re-create the time or a detailed sequence in which
overhead annunciators and system status lights were initiated does not exist. The
inherent limitations associated with the ability to determine plant and operator
response to a transient or event places a heavier reliance on processes such as log
taking, questionnaires, and debriefs in the development detailed sequences of
events or timelines that are often necessary to confirm appropriate system and
operator responses. For example, the licensee's initial sequence of events had the
{
shutdown cooling isolation valve being manually cracked open approximately 13 l
rninutes after the isolation; however, the final review determined that the valve was !
actually opened off of the shut seat 41 minutes after the isolation. The inability to l
correctly determine a sequence of events promptly following operational events can
impair the ability to assess plant and personnel response and affect necessary
corrective actions. In this event the licensee was not able te conclusively confirm
when the shutdown cooling suction valve thermal overloads tripped. This, in part,
may have lead to an inconclusive root cause associated with the inability to
promptly re-open the valve. The licensee plans to evaluate possible improvements
to the post-event review process including a standardized personnel questionnaire,
taking into consideration the limitations on objective information following an event.
c. Conclusion
in general operator response to the February 6, loss of shutdown cooling event,
was appropriate and timely with the exception of a minor procedure compliance
error. The operating procedures used to respond to this event were acceptable with
minor exceptions that were addressed by corrective actions following the event.
The reactor water cleanup jumper installation, the initiating action for the loss of
shutdown cooling event, was properly controlled in accordance with plant
procedures. However, the individual installing the jumper failed to take adequate
precautions. The flow blockage in the RWCU bottom head drain line, which created l
the need to install the jumper, should have been classified and tracked as an
operator work-around.
The corrective actions planned and implemented for the loss of shutdown cooling
event were generally adequate; however, the root cause of the initial inability to re-
open the shutdown cooling isolation valve was not identified. In addition,
weaknesses were noted with the licensees post-event review process.
01.3 Startuo Operations - Unit 1
a. insoection Scope
Control room operators conducted a reactor startup at Unit 1 on February 5. The
inspector observed a portion of the startup from the main control room.
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b. Observations and Findinas
Shift management exercised positive control of control room traffic with the use of
signs and rope barriers in and out of the control room. Typically, only necessary
personnel were permitted to be in the control room during the startup. The
inspectors noted that this policy was enforced. Double verification of the rod
withdrawal sequence was accomplished with a reactor engineer overseeing the
activities,
c. Conclusions
Operators conducted the Unit 1 startup wellin a controlled fashion. Additional
control room operators helped to minimize disturbances on the operator withdrawing
the control rods. Good support by the reactor engineering staff was observed.
01.4 Eauioment Operator (EO) Performance
a. Inspection Scope
The inspector accompanied an EO during morning reactor building rounds.
b. Observations and Findinas
The EO was attentive and thorough throughout his rounds. The EO initiated actions
to address minor discrepancies he found during the conduct of his tour. The
inspector also noted that the EO had been provided with an electronic log keeping
device. This device appeared to be programmed in such a manner so as to assist
the EO in recording plant parameters.
The inspector noted several other examples of good performance by EOs during this
inspection period. In one case, an EO discovered a steam leak in the Unit 2 6A
- FWH room by noting a difference in sound emanating from the room during his
routine turbine building rounds. Also, during a Unit 1 reactor building routine tour,
an EO identified an unusual difference in flow between jet pumps No.1 and No. 2
and conveyed this information back to the control room (see Section O2.1),
c. Conclusions -
Equipment operators performed well during routine tours. The operators were
j aware of plant parameters and alert to changing plant conditions.
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O2 Operational Status of Facilities and Equipment
O2.1 Cloooed Jet Pumo - Unit 1
a. Inspection Scope
On February 11, PECO engineers determined that the No. 2 jet pump flow nozzle
was clogged. Unit 1 operators had completed a reactor startup and power
ascension to 100%, and an equipment operator, performing the daily jet pumps
surveillance test (ST-6-043-320-1), identified an unexpected differential pressure
(d/p) difference in the No. 2 jet pump. The inspector reviewed the event and
observed PECO's response to address the situation.
b. Observations and Findinos
!
Control room operators reduced reactor power to 95% by reducing recirculations
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flow. The control room supervisor (CRS) directed l&C technicians to vent and
calibrate the flow transmitter (FT-042-1NO34D)for the jet pump since the pump's
I flow was indicating 50% of normal flow. The calibration data was within
tolerances. The operations staff determined that the jet pump was operable based
on the surveillance test performance data meeting two of the three acceptance
criteria required by TS. As a precaution, Operations management directed that the
!
Jet pump surveillance test be performed every four hours. Further, after
subsequently reducing reactor power to 75% to perform a rod pattern adjustment,
Operations management decided to maintain power output at 75% until engineering
l
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evaluated the operation. ;
q
The system managers determined that the jet pump parameters did not indicate that
a displacement of the pumps rams head had occurred. From a detailed review of all
testing results and operational data, PECO concluded that the most likely cause of
the pumps degraded flow was that the flow nozzle became clogged by about 40%.
PECO engineering also contacted GE, the reactor vessel vendor, to perform an
analysis for the jet pumps continued operation.
,
The primary impact of the clogged jet pump nozzle was the reduction of flow to
'
subject jet pump that creates a flow imbalance between it and the companion jet .
pump (jet pump that shares the common nozzle assembly), resulting in increased I
vibration and fatigue. Preliminary investigation indicated a 40% mis-match in flow,
at rated conditions, between jet pumps No.1 and No. 2. Two eductor-like jet !
pumps are fed from a single . suction source (jet pump riser) which delivers drive
flow to each pump. GE recommended a 10% reduction in flow until an analysis of
l the limiting condition could be performed. PECO engineers placed an additional
i 10% constraint limiting drive flow to the jet pump to 80% of rated and a d/p of l
38% between jet pumps No.1 and No. 2 which was within the ASME Code stress
.
limitations.
I
An unsymetric flow condition between the two jet pumps can cause imbalanced
forces on the jet pump and the riser brace, leading to higher vibratory stress
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responses than that due to symmetric flow conditions. The GE analysis concluded
that the resultant vibration was acceptable, within the ASME Code for the reactor
vessel material provided that the flow mis-match was maintained less than 45%, at ,
110 Mlbs/hr rated flow. PECO management imposed a further restraint by !
restricting flow to 105 Mlbs/hr rated flow. PECO is continuing to operate Unit 1 l
under the constraints directed by the GE analysis.
c. Conclusion
l
Operators responded well to degraded flow indications for the Unit 1 No. 2 jet -
pump. Engineering and l&C technicians supported the operations staff in
'
determining the operational condition and status of the clogged jet pump.
Management implemented more restrictive limits for operation of the unit prior to
and after the GE analysis was performed.
08 Miscellaneous Operations issues (90712) !
l
08.1 Revision to Technical Specifications Reaardina Control Rod 50-27. LGS, Unit 1 !
(TAC Nos. M99854 and M99855)
The inspector reviewed licensee actions taken in response to an amendment, dated
1/16/98,that modified TS Sections 3.1.3.6 and 4.1.3.6 to allow operation of
control rod 50-27, uncoupled from its drive, for the remainder of Cycle 7. The
licensee's actions included a shift training notebook item (required reading) and
I
changes to procedures GP-2, " Normal Plant Startup," GP-3, " Normal Plant
Shutdown," and S73.1.A, " Normal Operation of the Reactor Manual Control
System".
Administrative controls implemented adequately addressed conditions contained
within the amendment. Those control room operators interviewed were familiar
with the required reading and procedural changes.
08.2 (Closed) VIO 50-352,353/97-07-01 Control of Locked Valves and Devices
a. Insoection Scope
NRC Inspection Report 50-352/97-07 described that a number of valves had been
l identified as inadequately locked and concluded that a programmatic problem
existed concerning how valves were locked and independently verified. The
licensee investigated this matter in PEP 10007306. During this inspection period, a
l security guard identified that the Unit 1 suppression pool hatch PP-60-106 was not
locked properly. The primary containment boundary valve was properly positioned.
The licensee initiated PEP 10007945 to investigate this matter. The inspector
conducted interviews with licensee staff, conducted tours, and reviewed licensee
procedures.
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b. Observations and Findinas
During an interview with licensee staff who had conducted the PEP evaluation and a
review of the PEP as it stood on February 20,1997, the following causes in the
licensee's PEP were discussed:
l e unfamiliarity with the intent of licensee procedure A-C-33, " Nuclear
l Generating Group Process for Verification of Quality;"
e. personnel performing task were unfamiliar with the LLRT procedure being
performed;
e pre job briefing did not sufficiently consider craft task skill level performing
the independent verification;
- expectations not set on technique of locking a yoke'd valve.
l
Human performance and human factors were also discussed during this interview.
The inspector was informed that the verifier was new to the maintenance
department and was still working to complete their on-job evaluations.' The
inspector questioned whether a specific job performance measure (JPM) had been
established pertaining to locked valves. The inspectors were informed that no
specific JPM had been established and the licensee stated that they felt there was
no need for a JPM.
The inspector noted that training had been performed and the individuals performing
the task had been trained recently. The licensee asserted that the training was
adequate.
The licensee concluded in a letter to the NRC, dated November 26,1997,
responding to Notice of Violation 97-07-01,that the cause of the failure to properly
apply locking devices were insufficient recurring training for personnel regarding
proper appli',ation of locking devices, an infrequently performed task with specific
expectations, lack of sufficient inspections and surveillance to verify the condition
of locking devices, and a specific valve design that was difficult to secure using a
standard cable and lock.
During a debrief with senior management, licensee representatives noted their
disagreement with the inspector's conclusion that this matter was a case of
ineffective corrective actions. In summary, the licensee representatives emphasized
that they felt that the primary cause of failure to locking PP-60-106 was poor :
human performance. The inspector agreed that poor human performance was a key i
contributing factor in the failure to lock PP-60-106.
During subsequent reviews of this matter, the inspector identified another
discrepancy pertaining to the licensee's locked valve control program which was
described in NRC Inspection Report 50-352,353/97-01,Section 01.2. In summary .
on February 3,1997, an EO identified two valves which had not been properly l
locked as required by procedure A-C-8, " Control of Locked Valves and Devices."
This matter was dispositioned as a non-cited violation. While PEP 1007945
identified that PEP 10007306 covered "other locked valve issues," neither PEP
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13
l highlighted the fact that other valves were found unlocked on February 3,1997 or
on December 16,1996.
The inspector considered this failure to lock valve PP-60-106 as repetitive to the
multiple locking issues described in NRC Inspection Report 50-352/97-07. The
inspector concluded that the corrective actions implemented to address NOV 97-07-
01 were inadequate and this is a violation of 10 CFR 50, Appendix B, Criterion XVI,
" Corrective Actions." (VIO 50-352,353/98-02-03) Violation 97-07-01 is
administratively closed. The adequacy of the licensee's locked valve control
program will be reviewed as part of VIO 50-352,353/98-02-03.
,
The inspector assessed that identification of this issue by a security guard was a
notable example of an individual who had demonstrated a good questioning attitude
in the conduct of their routine duties and may have been, in part, a result of
previous corrective actions on the control of locked valves.
c. Conclusions
Deficiencies were identified with the control of locked valves, in that, a suppression
pool hatch valve was not properly locked after a LLRT. This was a repetitive failure
indicative of ineffective corrective actions for previous, NRC identified, locked valve
problems.
II. Maintenance
M1 Conduct of Maintenance
M 1.1 General Comments on Maintenance Activities (62707)
The inspectors observed selected maintenance activities to determine whether
approved procedures were in use, details were adequate, technical specifications
were satisfied, maintenance was performed by knowledgeable personnel, and post-
maintenance testing was appropriately completed.
The inspectors observed portions of the following work activities:
- Unit 2 - RWCU Differential Flow Indicator Troubleshooting, March 3;
- Unit 2 - APRM Gain Adjustment, March 11;
- Common - 500 KV Switchyard Clearance on the 345 line, March 16;
- Unit 2 - High Pressure Feedwater Heater Steam Leak Repair, January 24;
e Unit 1 'B' Main Steam isolation Valve Repack, February 23;
Observed maintenance activities were conducted well using approved procedures,
and were completed with satisfactory results. Communications between the
various work and support groups were good, and supervisor oversight was good.
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! M1.2 General Comments on Surveillance Activities (61726)
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The inspectors observed selected surveillance tests to determine whether approved
procedures were in use, details were adequate, test instrumentation was properly
calibrated and used, technical specifications were satisfied, testing was performed
by knowledgeable personnel, and test results satisfied acceptance criteria or were
properly dispositioned.
The inspectors observed portions of the following surveillance activities:
e Unit 1 "A" Channel Manual Scram Functional Test, March 2;
e Unit 2-D22 Monthly Surveillance Test, March 4;
e Unit 2-D23 Monthly Surveillance Test, March 11;
e Unit 1-MSIV Cold Shutdown Valve Test, February 27
Observed surveillance tests were conducted well using approved procedures, and
were completed with satisfactory results. Communications between the various
work and support groups were good, and supervisor oversight was good.
M1.3 Configuration Control - Meteorological Tower Surveillance Test implementation
a. Inspection Scope
The licensee identified as a result of NRC inspection activities (see Section R1.2),
that the outage time of meteorological tower detectors was excessive. Subsequent
to identification of this issue, the licensee initiated another PEP (10007970)to
investigate opportunities for improved communication between l&C and operations -
staff regarding meteorological tower equipment problems. The inspector conducted
interviews at various times during the licensee PEP investigation and reviewed
licensee procedures,
b. Observations and Findinas
On November 3,1997, several potential limiting conditions of operstions (PLCOs)
were entered on the secondary meteorological tower as part of the licensee's semi-
annual meteorological tower calibration program. Several days thereafter, l&C
started the conduct of ST-2-036-418-0," Meteorological Monitoring - Air
Temperature Difference Tower 2; (300'26');(155'-26') Calibration." l&C personnel
noted a degraded cable to the secondary met tower differential temperature monitor
aspirator. The aspirator maintains air flow over the differential temperature monitor
to maintain readings representative of ambient conditions. The degraded cable
caused a short and fault indication in the main control room. Communication
regarding the degraded cable between l&C technicians and both the Operations
staff and l&C management was poor.
The Operations staff was not made explicitly aware of the fact that the secondary
meteorological tower 26' differential temperature detector was considered to be
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15
inoperable due to the short in the aspirator cable (with degraded flow indication).
l Operations subsequently declared the secondary met tower operable on
l November 18, based on a PIMS review for in-progress work orders and clearance
tagging and following a satisfactory channel check. In actuality, the ST remained
in-progress and the degraded cable was not replaced until December 17,1997.
The licensee and the inspector noted several barriers which were broken during the
course of improperly returning secondary meteorological tower 26' differential
temperature monitor to service,
o Licensee Procedure A-C-043, " Surveillance Testing Program," Steps 7.4.4
and 7.5.4, required that operability concerns be identified so that shift
management can make an operability determination. The licensee's review
identified that the l&C technicians did not clearly indicate the concerns
regarding secondary meteorological tower 26' differential temperature
detector operability to operations staff,
o Procedure ST-2-036-418-Orequires that "if any sign off step cannot be
satisfactorily completed, then immediately notify Shift Supervision and l&C
Supervision." The inspector noted that this requirement did not clearly !
delineate A-C-043 requirements regarding any operability concern found
during the conduct of an ST/RT. The licensee's review of this matter
concluded that the ST should have been failed rather than leave the ST open
for an extended period of time,
o The Action Request (AR) for the cable repair was generated to be worked
without SSV review. The AR initiator indicated that the AR was not TS
related, although in fact, it was. When the AR was processed during the
licensee's scope work management meeting it was not identified as
impacting an offsite dose calculation manual (ODCM) system. Finally, the
control room had fault indication, although there was no requirement to note
the status of flow indication during the daily met tower channel check.
o OM-L-9.1-1, " Expectations / Conduct," 7/3/95, step 2.4, requires that ST/RT
performers must "if unable to perform ST/RT satisfactorily or in its entirety.
Notify shift management immediately." This was not performed, as
evidenced by the ISC technicians holding the ST in-progress.
o OM-L-12.2, " Equipment Deficiencies / Potential Action Log," 2/1/96, step 2.7,
requires that "the equipment deficiency / potential action log entry should be
closed out in accordance with Exhibit OM-L-12.2:2 when all associated
deficiencies are corrected, and the equipment is properly tested and returned
to service." The potential action log entry was closed out without correcting
the aspirator cable deficiency.
On March 18,1998, the operations staff conducted a review of the Operations
Manual to determine if any events constituted a violation of any written
instructions / guidance contained in the Operations Manual as part of the PEP review.
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Operations initially determined that there were no violations to the Operations
Manual. The inspector did not agree with this assessment. The inspector
considered the failure to comply with procedures OM-L-9.1-1, OM-L-12.2 and A-C-
043 to be a violation. (VIO 30-352,353/98-02-04)
c. Conclusions 1
Deficiencies were identified with the configuration control process when returning
the secondary meteorological tower back to service after a calibration. This led to
the operations staff improperly declaring a monitor operable prior to correction of all
identified deficiencies.
i
M8 Miscellaneous Maintenance issues (92902)
M8.1 (Closed) LER 50-352/1-97-012:Unolanned Closure of a Primary Containment
Isolation Valve
l On November 20,1997, control room operators found the primary containment
L isolation valve HV-059-131, Instrument Gas Transversing incore Probe Purge valve,
- isolated. The valve closure was an engineered safety feature (ESF) actuation. The
! inspector performed an on-site review of the licensee's evaluation and corrective
actions. PECO determined that the valve isolated during performance of a post
maintenance surveillance test following Primary Containment and Reactor Vessel
isolation Control System (PCRVICS) relay replacement. The licensee found that an ,
isolation relay was not properly identified on the post-maintenance surveillance test
due to being mislabeled on an electrical print used as a reference for planning the
test. PECO also determined that the electrical print error resulted from an incorrect
revision following a 1995 plant modification.
The inspector reviewed the affected documents and the status of corrective actions
and found them to be adequate and timely. The corrective actions included a
sampling and engineering assessment of modification drawings to ensure a generic
concern did not exist and the designation of additional review by a subject matter
expert prior to issuing post maintenance tests. The inspector determined the
inaccurate drawing was a violation of Technical Specification 6.8.1. This non-
repetitive licensee-identified and corrected violation is being treated as a Non-Cited
Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy. (NCV 50-
352/98-02-05)
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til. Enaineerina
E1 Conduct of Engineering
E1.1 Residual Heat Removal Minimum Flow Valve Operability and Corrective Actions
a. Insoection Scope I
Control room operators found the 1B RHR minimum flow valve (HV-051-F0078),
closed four times over a five month period. The normal configuration of the RHR
system in a standby condition requires the valve to be open. The function of the
minimum flow valve is to open when an RHR pump is in operation with system flow
less than 1500 GPM. The valve is maintained open in a standby lineup to assure
minimum flow protection for the RHR pump under postulated fire scenarios. There
are four independent loops of RHR, two of which (1C and 1D) are dedicated low
pressure coolant injection loops. The inspector reviewed the bases for operability
following each valve closure event and the subsequent corrective actions
implemented. The inspector also reviewed the corrective actions from a previous
similar failure which involved the inadvertent actuation of the HPCI system.
b. Observations and Findinas
i
Seouence of Events September 1997 to January 1998
September 1 The 1B RHR minimum flow valve was found closed during shift
turnover walkdown. The valve was promptly re-opened and
the system considered operable; however, no bases was
documented in the control room log or other vehicle. An
equipment trouble tag (ETT) was generated to document and
investigate the problem. Control room operators considered
the venting of the RHR loop, to relieve built up pressure due to
leakage past system injection valves, on August 30 was a
l contributing cause to the unexpected minimum flow valve re-
positioning. The associated operating procedure was modified
'
to include a step to check minimum flow valve open following
system depressurization.
During subsequent troubleshooting to address the ETT
generated on September 1, output voltage of the flow
transmitter was checked and indicated a slight zero shift with
an indication of 125 to 250 gpm flow with no pump in
operation. The transmitter was removed from service and the
zero alignment found to be correct. The instrument was
returned to service, indicated no flow and maintained a
satisfactory zero current value. The licensee conjectured that
the transmitter was air bound and valving the transmitter in
and out of service resolved the problem.
.
- _ _ _ _ _ _ _ _ _
_ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ - _ _ - _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ - _ - _ - _ _ - _ _ _ - - _ _ _ _ _ - _ - _ _ _ _ _ - _ _
'
I
18
September 14 The 1B RHR minimum flow valve was again found closed
during shift turnover walkdown with no obvious explanation.
An ETT was initiated. Three hours later, following discussions 1
with the system manager, operators declared all technical !
specification required modes of the RHR system as inoperable l
I
for calibration of the minimum flow valve flow transmitter.
The instrument calibration and loop check was performed
satisfactory, no adjustments were required and no air found in
the system. Following operation of the RHR system to verify
proper minimum flow valve operation (twice), the RHR system
was declared operable based on satisfactory calibration check l
and the verification of proper valve operation. i
A performance enhancement program (PEP) evaluation was
initiated to address the valve failure. The PEP found the
corrective action implemented for the September 1, event,
inadequate, since air binding was assumed and a fill and vent
of the transmitter was not performed. The inspector identified j
ineffective corrective actions performed by the licensee during
the second failure. Specifically, no trapped air was found and
that the root cause determination was inconclusive. The
inspector also noted that the corrective actions documented on
the PEP evaluation were to monitor for spurious valve closures
due to suspected air in the system. The licensee's evaluation
of these corrective actions stated " excellent issue evaluation.
Good use of RCA techniques, system analysis, and
interviewing to determine causes. Corrective actions
appropriate for issues." The PEP was later annotated,
following a subsequent failure, to have ineffective corrective
action.
September 26 The system manager identified that trip units associated with
1 A and 1B RHR minimum flow protection (652A & 652B) were
reading about 500 gpm without the respective systems in
operation. The trip unit input voltages were checked and
confirmed to be correct, no further action was performed.
January 17 The 1B RHR minimum flow valve was found closed during a
load drop. An ETT was initiated and the system was
considered operable; however, no bases was documented in
the control room logs or other documents. Although additional
I
actions were being planned, no additional troubleshooting was
performed until after a subsequent valve closure event four
days later. A PEP was subsequently initiated to address the
failure of the shift to declare LPCI inoperable while the valve
was shut and lack of detail provided in the logs.
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ - _ _ _ _ _ .
.
19
January 21 The 1B RHR minimum flow valve was found closed during
shift turnover walkdown. An ETT was again written and all
required modes of the 1B RHR system were initially declared
inoperable. However, later all but the LPCI mode of RHR were
found to operable based on being manually initiated and
monitored functions.
January 24 The 1B RHR minimum flow protection analog trip unit was
determined to be degraded and replaced. Post-maintenance
testing was performed satisfactorily and the LPCI mode was
restored to an operable status. The licensee identified the root
cause of the failure to be a degradation of a transistor in the
analog trip unit.
Previous Analon Trio Failures
Similar failures had been experienced at both Limerick Units from 1987 to 1990 that
resulted in inadvertent safety system actuations. These safety system actuation
along with similar experiences at other plants resulted in issuance of a 10 CFR 50
Part 21 notification and service and information letter (SIL) discussing the problem.
The Part 21 noted that the failed transistors internal atmosphere had high levels of
moisture that leads to the formation of a conductive, hygroscopic residue. The
residue, in turn, lead to leakage paths across the trip units output transistor,
increases in output voltage to the point that the relay was activated thus causing
the associated trip function to occur with no change in the process being
monitored. The Part 21 report also noted that the trip status light emitting diode
(LED), on the front panel of the trip unit, would not activate, even though the
output of the trip unit caused a trip condition.
The related SIL 520 recommended either replacement of the suspect transistors or
replacement of the entire analog trip unit. The licensee initially planned to replace
all of the suspect transistors in response to the SIL: however, this corrective action
was delayed and ultimately not completely implemented. Only about 18 of the
more than 100 effected trip units were repaired or replaced. The licensees internal
response to the SIL stated, "the lack of success in completing more repairs is
primarily due to a backlog of higher priority work requiring more immediate attention
coupled with the budgeting and manpower restrictions." The scope of repairs was
subsequently reduced to approximately 18 analog trip units primarily for HPCI and
RCIC initiations at both units. However, the licensee was unable to provide a
formal bases for the acceptability of this scope reduction.
Dearaded Trio Unit Operability
The inspector noted that the licensee failed to implement the corrective action
commitment as specified in LER 1-90-003. This LER was initiated in response to an
inadvertent HPCI initiation caused by a an analog trip unit malfunction. As
discussed in the LER, the licensee planned to replace the defective transistors in all
analog trip units except those that provide alarms functions only or that alarm upon
l
. _ _ _ - _ _ - - _ ______-_ _ _-_ _-_ __- _-__
.
20
failure. The LER stated that "the units will be reworked on a prioritized basis
according to the potential impact on plant systems and are expected to be reworked
by December 1993." The licensee initiated a PEP to address the missed NRC
commitment.
The inspector questioned the operability of the potentially degraded transistors that
are still in-service in safety-related applications, at both units. The licensee initiated
a non-conformance report (NCR) to evaluate this issue. However, the licensee did
I_ not plan to immediately address operability, but instead stated it would be
l performed as soon as practical within 45 days. Following a discussion with the
l inspector on timeliness of operability determinations the licensee accelerated their
i
operability assessment. Within several days the licensee determined that the
systems impacted by the potentially degraded transistor were operable based on:
'
calibration and functional surveillance testing satisfactorily performed as required;
no increase in the trend of related transistor failures, only four failures since 1991;
and, that there is no single failure that would place the plant in an unanalyzed or
unsafe condition. The inspector noted that one failure, by itself, would not cause a
loss of a safety function. For example, if another minimum flow valve were to fail
closed on a low pressure emergency core cooling pump, the safety function would
be maintained by the redundant subsystems.
The inspector discussed the potential for a common mode failure of two or more trip
units with the licensee who believed that postulation of more than one failure was
beyond the design bases of the plant. The inspector had postulated a change in
ambient conditions from a ventilation failure could cause spurious actuation of
i multiple trip unit from a single cause. Following the discussion the licensee
contacted the manufacturer and performed additional evaluations to determine that
the transistors were not susceptible to common mode failures and were not
affected by changes in ambient conditions. Further, the degraded trip units do not
undergo accelerated aging as a result of the voltage leakage issues. However, the
- inspector later found that the manufacturers reply to PECO stated there is
'
insufficient data to identify common mode failures that would manifest the moisture
related failures in the potentially degraded transistor. At the end of the inspection
period, the licensee was still evaluating potential corrective actions. The inspector
did not identify any clear common mode failure mechanisms.
1B RHR Minimum Flow Operability and Corrective Actions
The inspector determined that licensee's troubleshooting for the 1B RHR minimum
flow valve closures was focused on the transmitter only following the first and
second failure in-spite of an inconclusive root cause determination. The technicians
did not equate the observed operation of the minimum flow valve with available
industry information (Part 21 and SIL). The technicians and engineers involved in
i trouble shooting the first two instances were not aware of the failure mechanism
'
identified in the SIL.
A General Electric letter concerning RHR pump operation at shutoff, for Limerick
Unit 2, stated that pump damage may occur under no flow conditions in as little as
. _ _ _ _ _ - _ _ _ _ _ _ _ _ - _ _ _ _ _ _ -
_ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ - _ _ _ - _ _ _ _ _ _ _ _ _ _
.
21
2 to 3 minutes. The function of the minimum flow valve is to open when an RHR
pump is in operation with system flow less than required to prevent pump damage.
The inspector postulated that if the system were to initiate on a valid accident
signal, and the minimum flow valve were to fail closed for several minutes prior to
achieving the conditions (reactor pressure less than the RHR pump shutoff head) for
automatic LPCI injection or prior to the operators being directed by EOPs to use the
other manual modes of RHR, the pump would be damaged and rendered inoperable ;
prior to performing the intended functions. At the end of the inspection period tha l
,
licensee still maintained that the RHR system was operable during the period in
j which the RHR minimum flow valve was malfunctioning; however, a detailed bases
was not provided.
Following each instance in which the valve was found shut the operators failed to
establish an adequate bases for operability. Further, following discussions with the ;
inspector concerning operability after the fourth failure, the inspector determined 4
l that the licensee again incorrectly concluded that the suppression pool cooling and
l suppression pool spray modes of RHR were operable.
10 CFR 50, Appendix B, Criterion 16, " Corrective Action," requires, in part, that
measures be established to assure that conditions adverse to quality, such as
failures, malfunctions, and deficiencies are promptly identified and corrected. In the
case of significant conditions adverse to quality, the measures shall assure that the
cause of the condition is determineri and corrective action taken to preclude
repetition. However, between Sep. ember 1,1997, and January 21,1998, the
corrective actions implemented we e ineffective at preventing recurrent valve
closures. The licensees failure to recognize the degraded operation of the 1B RHR
system as a condition that impacted operability caused the delay in implementing
prompt corrective action commensurate with the safety functions required by
technical specifications. The inspector determined the failure to implement
corrective actions or establish a bases for operability resulted in the LPCI system
(TS 3.5.5.1), suppression pool cooling (TS 3.6.2.3), suppression pool spray (TS 3.6.2.2), and hydrogen recombiner functions being inoperable and are apparent
violations of 10 CFR 50, Appendix B, Criterion XVI, " Corrective Action," (eel 50-
352,353/98-02-06)and of the associated technical specifications (eel 50-352,
353/98-02-07).
In addition, the failure to perform corrective actions recommended in SIL and
committed to in the LER, replacement of a defective transistor, resulted in the
degraded performance of the minimum flow valve and ultimately inoperability of
several modes of RHR is another example of ineffective corrective actions,
c. Conclusions
On three occasions, operators did not resolve why the 1B residual heat removal
(RHR) minimum flow valve was out of its normal position. Later, the licensee
identified that the valve failed closed as a result of a degradation of a transistor in
the analog trip unit. In each instance operators re-aligned the system without
[ establishing an adequate bases for system operability. This failure to recognize
l
_ _ _ _ _ _ _ _ _ _ _ _ - _ _ ____--
_ _ , _ _ _ _ _ - _ _ _ - _ _ - _ _ _ _ _ _ _ - - _ _ _ _ - _ _ _ _ _ _ _ - _ -_ - _ _ - _- --
.
22
degraded performance also contributed to the delay in implementing appropriate
corrective action.
Engineering efforts to identify the root cause of the 1B RHR minimum flow valve
inadvertent closures demonstrated inadequate troubleshooting. Initial efforts were
narrowly focused and based on faulty assumptions. This failure to identify the root
cause led to ineffective corrective actions and resulted in multiple modes of the RHR
system being inoperable for extended periods of time.
l The licensee failed to fully implement a 1990 LER corrective action commitment
that involved replacement of potentially defective transistors in a select population
f of safety-related analog trip units in addition, the recent operability determination
!' addressing these transistors remaining in service, was not timely nor
comprehensive.
l E1.2 Limerick Unit 1 and 2 Gross Power Generation
The inspector reviewed the 1996 and 1997 gross power generation charts for
Units 1 and 2 to compare the number of unplanned off-line and load drop power
<
interruptions. The inspector also reviewed findings of a Massachusetts Institute of
Technology (MIT) study of plant systems problems leading to power interruptions to
, identify those plant systems having an abundance of operating deficiernes. From
review of charts of gross power generation, the inspector found that unplanned
gross power generation off-line interruptions in 1997 were less than those in 1996.
For Unit 1, in 1996 there were 5 offline interruptions and 4 load drops; in 1997
there were 2 off-line interruptions and 4 load drops. For Unit 2, in 1996 there were
i 5 off-line interruptions and 2 load drops: in 1997 there were 2 off-line interruptions
and 7 load drops.
f. The inspector found that PECO provided LGS operating data to MIT for a study of
power generation interruption causal factors over a five year period. These were
l compared to similar US BWR IV utilities over the same period. While 74% of the
periods of lost power generation capability were due to BOP system failures, 54%
of LGS lost power generation capability resulted from BOP failures. This was
compared to 59% from industry wide data. From another perspective, 48% lost
power generation capability was the result of equipment factors, while 52% was
due to human factors. The study did not cover safety- related systems, but
underscored the fact that balance of plant (BOP) equipment failures frequently
challenge plant equipment and operators.
.
E1.3 Limerick System Assessment
l
! a. Insoection Scope (37550)
The inspector reviewed an LGS' initiative, using an Institute of Nuclear Operations *
(INPO) method, to identify unacceptably operating plant systems and alert
management to areas requiring corrective action.
I
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ .
.
.
.
23
b. Observations and Findinos l
The inspector found that PECO provides a Limerick System Assessment Report with
a color-coded performance rating for each plant system. The report discusses the
basis on which each system is rated, the cause of the deficiencies identified,
compliance issues encountered, configuration management issues developed, and
corrective actions and systems improvement action taken.
I The inspector found that the systems classified as having unacceptable
l performance (from the 1997 3rd Quarter System Assessment Report) included the
i main steam / automatic depressurization system, electric / hydraulic controls (EHC),
emergency diesel generators, reactor water cleanup, and control rod drive systems.
For each unacceptable performance identified, PECO engineering has prepared a
- corrective action program.
I c. Conclusions
l
'
Engineering used a comprehensive approach to assess performance of plant
systems. Several systems not meeting plant performance criteria have been
l identified and corrective action focused on these systems.
E1.4 Eauioment Performance and Material Condition
l
a. Insoection Scope (37550)
The inspector reviewed the LGS Equipment Performance and Material Condition
i Focus List to identify the method used by engineering to resolve chronic plant
issues,
i
l
b. Observations and Findinas
The inspector found a list of LGS equipmen. performance and material condition
that identifies operational concerns, plant problems, adverse performance trends,
key enhancements, and mid-life strategies. For each problem or concern identified,
the impact on safety and/or reliability is described, compensatory action taken, and
[ future plans to improve are described. ;
i
Examples of chronic issues identified were operator work-arounds (LPCl injection
'
valve failure to close under dynamic conditions), plant problems (main steam relief
valve performance, EHC/ main steam piping vibration), adverse trends (accelerated
general corrosion in service water system components due to elevated chlorine
levels), key enhancements (MOV output force margin improvement), and mid-life i
l strategies (reactor internals).
!
C. Conclusion _t
LGS has implemented a program to identify chronic plant issues and provides for a
comprehensive program to monitor resolution of these issues.
.
. . . . _
_ _ _ - - _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _
i.
D
24
E1.5 Balance of Plant System improvement
l a. Inspection Scope (37550)
l
l The inspector reviewed the LGS " BOP 700 Strategy" being developed to improve
l BOP system performance and reliability.
i
b. Observations and Findinas
The inspector reviewed a comprehensive PECO long term strategy to improve BOP
system performance and reliability using a team focus on issues requiring resolution.
PECO used MIT personnel to identify opportunities to eliminate challenges to plant
reliability through observation of industry and LGS operational failure history.
Systems reviewed included generator and auxiliaries, feedwater heating, air removal
and off-gas, EHC, condensate, drywell chilled water, instrument air,13 KV,
i- 220/500 KV, and fire protection. Results of these reviews included procedure
revisions, changes in preventative maintenance activities, and modifications to
upgrade or add redundancy to system designs.
Numerous examples were cited by PECO, where work was initiated in addition to
normal outage work, to address equipment degradation or "similar equipment"
failures. These examples included circulation water system expansion joints,
'
feedwater heater valve maintenance, heater tube testing, condenser neck seal
repair, and extensive EHC system work.
l
c. Conclusions
LGS has developed a comprehensive " BOP 700 Strategy" to improve BOP system
performance and reliability. LGS implemented parts of the strategy in resolving
system problems and performing work to address equipment degradation.
E2 Engineering Support of Facilities and Equipment
E2.1 (Closed) URI 97-10-06, Hioh Pressure Coolant Iniection (HPCI) Turbine Exhaust
Valve Corrective Actions
a. Inspection Scope
The HPCI turbine exhaust valve (HV-55-1F072), had failed to close on the initial
attempt six times in the last four years. Four of the six failures occurred within the
last five months. The first five failures were discussed in NRC Inspection Report
l 352,353/97-10. The inspector reviewed the recent failure to close event on
January 28,1998, the root cause for the repeated surveillance test failures, and
corrective actions for these issues.
l-
25
b. Observations and Findinos
On January 8,1998, following the fifth failure of the valve to stroke on the first
attempt, technicians identified a definitive failure, internal valve binding, by using
MOV diagnostic equipment. The most probable failure mechanism was believed to
be the disk rotating and wedging against the valve body and guides. The valve was
returned to an operable status since the failure mechanism was not repeatable and
there was rv evidence of degraded valve performance on subsequent strokes. In
addition tiu , Mst frequency was increased to weekly, in part, as a result of NRC
concerns documented in inspection Report 352,353/97-10.
On January 28,1998, during the second weekly valve stroke time test, the valve
failed to close on the initial attempt. The valve was reopened and then successfully
stroked closed similar to previous failures. Diagnostic testing, performed during the
failed stoke attempt, again indicated internal valve binding. However, in this case,
diagnostic testing on the subsequent stroke indicated a degrading condition
indicative of potentialinternal valve damage. The valve and consequently the HPCI
system was declared inoperable and Unit 1 was shutdown to establish the
conditions necessary for further valve interr.al investigation and repairs.
The licensee identified that the root cause for the HPCI exhaust valve failure to
stroke fully closed on the first attempt was mechanicalinteraction (galling) of the
valve disk and lower guide rail. The contributing causes for this interaction are as
follows: the horizontal orientation of the valve; the leading edge of the disk
assembly that rides on the valve guide rail was sharp (not chamfered); the
temperature conditions at the valve caused the guide rails to be ductile and
susceptible to galling.
The licensee's root cause stated that a decisive root cause was not previously
identified due to the unique valve behavior and intermittent nature of the failure.
Without an identified root cause the licensee stated that precautionary corrective
actions were implemented including stem lubrication, actuator output force
increases, and motor control center critical component inspections. However, the
inspector found that following the third failure in September of' 1997, no such
actions were taken. Further, following the fourth failure in October of 1997, the
output force was increased for the second time which did not appear to be a
conservative measure, but rather an action that may mask the problem. The
inspector also noted that in December of 1994, there was evidence of internal valve
binding which did not result in an internal valve inspection at the time or during the
subsequent outage, but rather was attributed to thermal effects. In addition, motor
operated valve diagnostic equipment was not used until the torque switch setting
was increased,6 months after the second failure close event in May 1995. ;
The licensee's root cause determined that the valve remained operable up to the
sixth failure on January 28,1998. The licensee evaluation stated that the
operability determination in the associated NCR is :.till considered appropriate based
upon all the best available knowledge and information at the time of the
3
determination because: the valve fulfilled its remote-manual safety closure function;
_ _ _ _
_ , _ - - _ _ - _ _ .. . - _ _ _ _ _ - - _ - _ _ _ _ _ - _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _
-
.
26
an unanalyzed failure mode was not discovered; the increased frequency exercises
testing with motor-operated valve diagnostic equipment to monitor valve condition
detected the degre.dation in valve material condition prior to loss of function.
Valve operability, documented in the associated NCR, was based on the following:
e The valve manufacturer did not encountered any specific events or
experience that identifies a horizontal orientated flexible wedge gate valve
that had an intermittent failure to stroke, then completely failed.
Additionally, there is no existing industry events or PECO plant specific
experience that identifies a horizontal oriented flexible wedge gate valve that
had an intermittent failure to stroke problem, then completely failed.
e In its present condition (prior to repair), the valve's integrity and material
conditien was considered acceptable and could rema'.n in service until the
valve internal repairs could be performed at a later date since the va!ve can
be manually closed successfully during subsequent stroke attempts. The
inability to completely close during the first attempt is of no consequence
and would not prevent the valve from fulfilling its remote-manualisolation
function.
- There was no evidence to sug0est that the valve's material condition was
being challenged or degrading due to the failed stroke attempts, such that,
the deferral of the valve internal inspection until the upcoming refueling
outage could create a future operability concern. The evidence to support
this conclusion was based on a comparative review of the diagnostic test
baseline data and the most recent failed stroke.
1
The inspector further ascertained, as stated in NRC report 97-10, that the
licensee continued to fail to consider the technical specification requirement
when assessing operability. Further, the licensee's assessment of historical
operability seems to be primarily premised on the lack of evidence that other
similar valves with similar conditions have completely failed and the belief :
that the unidentified failure mechanism was not getting worse. The
inspector determined that the condition was, in fact, getting worse as
evidenced by the degradation noted on subsequent valve strokes following
the sixth failure. In addition, raising the torque switch setting increasing the
motor operator output force twice, as a conservative measure, may have
resulted in acceptable performance for a period time, but masked potential
degradation and the identification of the root cause. Further, all of the test
failures (except December 1994) occurred at ambient conditions that are less
l susceptible to galling than the conditions that may be experienced when
l isolation of the HPCI system would be necessary. For example, if during a
I
loss of coolant accident a HPCI isolation was required, the valve ,
temperatures would be significantly elevated and thereby more susceptible to l
a complete failure of the valve to close. The inspector also noted that the j
HPCl turbine exhaust had been stroked successfully following HPCI operation
- _ _ _ - _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _
, . . . . . . . .
. _ . __ _ - - _ _ _
.
27
several times over the last four years with the most recent in September
1997.
Technical Specification 3.6.3, " Primary Containment isolation Valves,"
requires, in part, that the primary containment isolation valves shown in
Table 3.6.3-1 shall be operable with isolation times less than or equal to
those shown in Table 3.6.3-1. The HPCI turbine exhaust valve is listed as
an outboard isolation barrier, with a maximum isolation time of 120 seconds.
However, between March 1994 and January 1998, the HPCI turbine exhaust
valve, a primary containment isolation valve, was not maintained operable
with an isolation time less than or equal to 120 seconds. Specifically, the
l valve would not stroke consistently on the first attempt and thereby no
i assurance existed it could be isolated in 120 seconds.
a
10 CFR 50, /.ppendix B, Criterion XVI, " Corrective Action," requires, in
part, that measures be established to assure that conditions adverse to
quality, such as failures, malfunctions, and deficiencies are promptly
l identified and corrected. In the case of significant conditions adverse to
l quality, the measures shall assure that the cause of the condition is
!
determined and corrective action taken to preclude repetition. However,
following the March 1994 deficiency that prevented the HPCI exhaust valve
from being isolated on the first attempt, measures were not established to
j assure that this signincant condition adverse to quality, was promptly
!
corrected with measures to assure that the cause of the condition is
determined and corrective action taken to preclude repetition.
l
The failure to recognize the degraded operation of the HPCI exhaust valve as
condition that impacted operability, contributed to the delay in implementing ,
prompt corrective action commensurate with the functions required by '
! technical specifications. Further, the failure to implement corrective actions
l or establish an adequate bases for operability resulted in the primary
containment isolation function of the HPCI exhaust valve being inoperable
and are apparent violations of Appendix B, Criterion XVI, " Corrective i
Actions" (eel 50-352/98-02-08)and the associated technical specifications. l
(eel 50-352/98-02-09) l
l
The licensee's investigation assessed the generic implications from the root I
cause and identified that seven other safety-related valves associated with
HPCI and RCIC at both units, that may be susceptible to the same failure
mechanism as a result of similar configuration and operation. The licensee i
plans to inspect all of these valves in the upcoming refuel outages. In
addition, since the Unit 2 outage is more than a year away, the licensee
! plans to use MOV diagnostic equipment to monitor the performance of the
Unit 2 valves during the quarterly testing. The licensee also considered other j
horizontally mounted valves and confirmed these valves are not susceptible
to similar failures but plans some additional inspections.
l
. _ , __ _ _ _ _ . _ .__ _ _ _ _ _ _ ___-__ _ - _-_ _ - _ _ _ _ - _ _ _ _ - - - _ _ _ _ _ _
,
28
c. Conclusion
The engineering staff did not aggressively pursue comprehensive troubleshooting,
testing, and component inspection of the HPCI turbine exhaust valve following l
multiple failed valve surveillance. Prior to the fifth failure of this valve to stroke, a l
conclusive root cause was not identified and consequently led to ineffective
corrective action, which in turn resulted in this valve, being inoperable for an
extended period of time.
l
l
The operability determinations associated with the failure of the HPCI exhaust valve
to stroke closed were flawed. The determinations did not take into account the
closing time required by technical specifications.
E2.2 Turbine Retrofit Project Oversiaht
The inspector reviewed examples of PECO oversight of technicalissues related to
the replacement of turbine rotors in Units 1 and 2. The inspector found sufficient
site management and corporate oversight of technical issues in low temperature
turbine blade frequency testing, torsional vibration analysis to preclude externally
excited rotor vibration found in some General Electric (GE) " shrink-fitted disc" rotor
designs, and potential missile problems associated with catastrophic turbine failure.
The replacement turbine supplier's (Siemens) manufacturing and testing quality was i
observed by PECO engineers at facilities in Germany during the manuf acturing
phases of the replacement rotors.
E2.3 Recirculation Pumo Vibration
a. insoection Scoce (37550) l
!
The inspector reviewed a comprehensive licensee program to monitor system
vibration due to increased recirculation pump speed necessary for raising core flow
to 110 MB/hr.
I
b. Observations and Findinos l
The inspector found the station vibration monitoring procedure to be sensitive to, .
and consistent with, guidance provided in information notice IN 95-16 and GE SIL
No. 600. PECO was prepared to identify the onset of any such possibility by
placing vibratory sensors at critical locations on the recirculation system, j
c. Conclusions ;
PECO proactively prepared to identify the onset of vibration in the recirculation
system by placing vibratory sensors at critical locations on the recirculation system.
. . .
_--_------__--____---___u
-__ _ _ - _ _ - - _ _ _ - - _ - - _ - _ _ _ _ _-_ ..
.
29
E2.4 Aaastat Relavs
The inspector discussed with PECO the issue of failed Agastat relays and examined
samples of the relay and photographs of a deficient welding process used in
fabricating the relay. The inspector found that engineering was successful in
determining the root cause of Agastat relay failures through utilization of the
technical capability of the PECO Valley Forge Metallurgical Laboratory. Their
examinations and experiments revealed that the cause of Agastat failure was
improper welding of an electrical contact. Subsequent corrective action replaced
the defective Agastat relays with those having been constructed using proper >
contact welding techniques.
E3 Engineering Procedures and Documentation
The inspector reviewed results of the licensee's program to review the Updated
Final Safety Analysis report (UFSAR). PECO is implementing a complete review of
the Unit 1 and 2 UFSARs. PECO used an interdisciplinary team of 125 individuals
from within and outside LGS. To date, nearly half the UFSAR review has been
completed. Six (6) non-conformance conditions (NCRs) were found by LGS
through the end of January,1998. None of these conditions were deemed
reportable to NRC. Numerous instances of ambiguous, misleading, incorrect, or
incomplete information were found. As a result, twenty seven (27) document
(UFSAR) design change requests (DCRs) were generated, with three (3) completed,
and (7) more DCRs are expected in the near term to resolve the remainder of the i
items. '
)
E8 Miscellaneous Engineering issues (92902)
E8.1 (Closed) LER 50-352,353/1-97-009 Residual Heat Removal Service Water !
(RHRSW) Radiation Monitor incorrectiv Confiaured i
This event was reviewed and documented in NRC Inspection Report 50-352,
353/97-08, section E1.1. The inspector conducted an in-field review and
determined the licensee's corrective actions were appropriate. The inspector also
determined that although a majority of the corrective action commitments were
complete or in progress, one corrective action to review a representative sample of
l completed design change requests was delayed due to personnel reassignment.
l The inspector determined through discussions with the engineering system manager
l and responsible evaluator, that the licensee was aware of the delay and had
l preliminarily screened the design changes, identifying no immediate concerns. The
licensee stated they would pursue closure of the action in a timely manner.
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E8.2 (Closed) LER 50-353/2-97-010: Failure to Perform a First Cvele Analvsis of a
Reactor Flux Wire Specimen.
On November 7,1997, site engineering personnel determined that the Unit 2
reactor flux wire specimen analysis required by Technical Specification (TS)
surveillance 4.4.6.1.4 was not performed. The information obtained from the
specimen analysis is used to update the reactor vessel metal temperature vs.
pressure curve as shown in TS figure B 3/4.4.6-1. The inspector performed an in-
field review of the licensee's evaluation and corrective actions. PECO determined
that the flux specimen was removed from the reactor vessel and placed in the spent
fuel pool in April 1991, pending removal for analysis. The licensee also found that
no documentation existed proving the analysis was done and the specimen was j
apparently disposed of sometime after May,1992. PECO determined the root !
cause to be a proceduralinadequacy that failed to track documentation and
completion of the analysis.
The inspector determined through onsite inspection that PECO's corrective actions
for this incident were acceptable. The inspector reviewed the resutting j
10CFR50.59 and engineering evaluations and found them to be acceptab'.e. !
Additionally, the inspector determined through document review that generic
implications were addressed concerning control of spent fuel pool material and
industry experience was evaluated. This LER met the requirements of 10CFR50.73.
The inspector determined the procedural inadequacy was a violation of Technical
Specification 6.8.1. This non-repetitive licensee-ide.ntified and corrected violation is
being treated as a Non-Cited Vi ,lation, consistent with Section Vll.B.1 of the NRC
Enforcement Policy. (NCV 50-353/98-02-10)
E8.3 (Uodate) IFl 50-352/97-07-02: Reactor Water Cleanuo (RWCU) Isolations
NRC Inspection Report 50-352/97-02 described an LER where the Urtit 2 RWCU
system had isolated due to a high differential flow condition while revering a filter
demineralized to service. This IFl was opened to address maintenance rule
implications and common causes of isolations. The inspector discussed .RWCU
issues with the system manager and reviewed his associated focus list. Several
important actions are planned for the upcoming Unit 1 refueling outage, such as,
cleaning the reactor vessel bottom head drain to lessen the chance of a low suction
pressure RWCU pump trip during start-up. Also, several valves related to the
RWCU system will be removed or relocated. Other work, such as, RWCU pump
replacement will occur during a later outage. This matter will remain open pending
implementation of the corrective actions.
E8.4 Suent Fuel Pool (SFP) Local Power Ranoe Monitor (LPRM) Storace and Seismic
Qualifications of the Cask Storace Pit
During a tour of the refueling floor, the inspector noted that LPRM strirgs were
suspended from the top of the spent fuel pool curb. The inspectors also noted thet
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31
the spent fuel pool- cask storage pit gates were not installed. According to the
licensee this configuration had been maintained for various periods over the past
! several years. Because the spent fuel pool-cask storage pit gates had not been
installed, the inspectors questioned the seismic qualifications of the cask storage pit
connections such as drain lines and the associated valves.
The licensee found that the 10" cask storage pit drain line and valve were not
seismically qualified components according to plant records. Following discussions
with the inspector, the licensee lowered the LPRM strings such that no LPRM
detector was higher than the top of a fuel bundle. The licensee also found that the
condition was bounded by UFSAR Section 9.1.2.3 which states that "The bottom
of the fuel transfer canals between the spent fuel pool and the reactor well and
between the spent fuel pool and cask loading pit are above the top of the stored.
spent fuel, thus ensuring that failure of the gates in these canals cannot result in
the uncovering of the fuel." in support of UFSAR 9.1.2.3, the licensee conducted a
calculation demonstrating that 10 CFR 100 and GDC 19 requirements would be met
in the event of an SFP drain-down event.
This matter is unresolved (URI 50-352/98-02-11)pending further review of licensee
basis documentation regarding LPRM storage and SFP configuration.
IV. Plant Suonort
R1 Radiological Protection and Chemistry (RP&C) Controls
R1.1 Implementation of the Radiological Environmental Monitorina Proaram
1
'
a. Insoection Scoos (84750-02)
The inspection consisted of a review of (1) sampling equipment and technique;
(2) analytical results of environmental samples, and (3) the licensee's capability to
monitor plant releases and calculate projected doses.
b. Observations and Findinas
The inspector toured selected environmental sampling stations, including air
samplers for radioiodine and particulate; milk farms; surface water; and thermo- ;
luminescent dosimeters (TLDs). The inspector noted that air samplers were j
operational and TLDs were distributed according to the ODCM. The environmental !
sample media were collected from the locations at the frequencies designated in the l
ODCM. l
!
The air and water sampling equipment was operable and appropriately maintained. l
The orifices (flow restrictor) on the water sampling units were calibrated and j
maintained. The calibration results were within the tolerances specified in the l
procedure. l
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The inspector observed the environmental technician collect milk samples and
exchange air particulate filters and charcoal cartridges. The environmental
technician demonstrated a good milk sampling technique. The inspector noted that
the environmental technician removed the air filters by first grasping the center of I
the filters with a pair of tweezers then roughly lifting them from the holder. I
Handling the filters in this manner could remove particulate from the filter and
introduce an inaccurate measurement result. The inspector discussed with the
licensee the air particulate sampling technique. The licensee stated that the
sampling technique will be reviewed and willincorporate a better technique, as
appropriate.
The inspector reviewed the analytical data of environmental sample measurement
results from January - December 1997. The analytical data indicated that there l
were no elevated results due to plant operations, with the exception of tritium (H-3) l
releases. The licensee released tritiated water from the equipment drains. The H-3 l
is believed to be from ruptures in some of the control rod blade pins, which leak '
boron into the reactor water. Boron is one source of H-3 in reactor water. The
licensee released a total of 31.4 curies (Ci) of tritium in October 1997 as compared
to normal radioactive liquid releases which can range from (1 to 10 Ci). The
licensee routinely analyzed for H-3 insurface water quarterly, as required by the
ODCM. Surface water was composited from October, November, and December
1997. The analytical result of the quarterly composite sample at the Vincent Dam
location was 380 * 70 picocuries per liter (pCi/l). The Pennsylvania State
laboratory analyzed for H-3 monthly, and the analytical result of the October 1997
sample was 765 i 121 pCi/l. The licensee also analyzed the surface water sample
for October only (not a quarterly composite sample). The analytical result of the
October sample was 810 i 120 pCi/l. The licensee calculated a hypothetical H-3
concentration at the Vincent Dam using river water flow rate, dilution factor, and
total amount of tritium released during October 1997. The calculated concentration
at the Vincent Dam was 709 pCi/l. Although there is no regulatory limit for surface
water, one can compare the concentrations to the reporting levels for H-3 in
drinking water, which is 20,000 pCi/l, in Table 13.4-2 of the ODCM. The inspector
determined that the licensee effectively monitored the consequences of plant
releases using environmental sampling stations. The licensee had demonstrated
that the radiological environmental monitoring program was effective.
The inspector independently calculated the projected dose to the public due to
elevated H 3 at the Vincent Dam using the Regulatory Guide 1.109 methodology.
The projected dose to the public was 0.0035 mrem /qtr. The licensee had
calculated a projected dose to the public and it was 0.0046 mrem /qtr, which agreed
with the inspector's calculation. This dose was less than the regulatory limit of
3 mrem /qtr. The inspector determined that the licensee had calculated dose
projection in an acceptable manner.
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c. Conclusion
Overa!! performance was good and the radiological environmental monitoring ,
program was effective, although an instance regarding attention to detail was noted i
involving the rough handling of sample filters.
R1.2 Implementation of the Meteorological Monitorina Proaram
a. Insoection Scope (84750-02)
The inspection consisted of a review of: (1) calibration results of the ODCM-
required wind speed, wind direction, and temperature sensors, and related
instrumentation of the primary and secondary towers from November 1995 through
November 1997;(2) Equipment Deficiency / Potential Action Logs and Action Logs;
and (3) procedure IC-11-00449," Check Procedure for the Limerick Meteorological i
System" to pursue an issue discussed in a previous REMP inspection conducted in '
October 1995.
b. Observations and Findinas
The inspector verified system operability. The wind speed, wind direction, and l
temperature sensors of the primary tower were operable, as required by the ODCM, i
Table 13.1-1. However, the 304 foot wind speed,159 foot wind direction, and the l
30 foot dew point sensors of the secondary tower were not operable at the time of
the inspection. The 304 and 159 foot sensors from the secondary tower are
required by ODCM, Table 13.1-1 for redundancy. These secondary tower sensors
were not operable since December 12,1997 and January 26,1998, respectively.
The licensee was able return to service the 304 foot wind speed sensor by
February 13,1998. The other sensors remained out of service as of February 13,
1998.
The licensee's primary source of meteorological data acquisition is from the RM-21 A
computer. The incpector observed the system engineer access meteorological data
from the RM-21 A using a terminalin the Technical Support Center. The backup
method of data acquisition is from strip chart recorders in the control room and data
loggers. The chart recorders and data loggers were operable.
The inspector reviewed the calibration results. Calibrations of the wind speed, wind
direction, and temperature sensors were performed at the frequency required by
Table 13.1-2 of the ODCM. The reviewed calibration results were within the
licensee's acceptance criteria. The inspector also noted that licensee took two to
three weeks to calibrate the meteorological instrumentation for the primary and
l backup towers (each tower was declared out-of-service for 2 weeks). The
I
inspector noted that, most usually, calibration of such equipment is possible within
1 or 2 days. The licensee stated that efficient calibration methods will be
incorporated into the calibration program.
l
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34
! The inspector reviewed the licensee's Equipment Deficiency / Potential Action Logs
and Action Logs from 1996 through 1998. The inspector noted that the primary
meteorological tower had lost power for approximately 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> from June 12-13,
1996 due to an electrical storm while the backup tower was out-of-service for
calibration. The licensee appropriately entered the 7 day LCO. Based on the
information reviewed, no other LCO's had been entered during 1997 for a similar
reason.
During the previous REMP inspection conducted in October 1995, the inspector
noted that the procedure, IC-11-00449," Check Procedure for the Limerick 1
Meteorological System," did not provide cufficient instruction to adequately satisfy !
a UFSAR, Section 2.3 commitment. The licensee was to send the analog strip
l charts and data logger printouts to the environmental consultant weekly. (See
Section 5.1.6 of Combined inspection Report 50-352:353/95-18for details.)
Durint, this inspection period, the inspector reviewed the procedure and noted that it
had been revised appropriately. The licensee had sent strip charts and printouts to
the consultant weekly and documented these actions in a logbook.
l
l C. Conclusion
The meteorological data acquisition was good. However, a weakness was noted
l
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with the calibration and maintenance programs for the meteorological
instrumentation and related equipment.
R1.3 RP Controls on Refuelina Floor Skimmer Surae Tank Modification
,
'
RP controls on this modification were very good. The controls included direct RP
coverage, high-quality camera coverage, and remote electronic dosimeter coverage.
Work activities were scheduled in a manner such that highly contaminated
components were cut out early in the course of the modification thereby
significantly reducing general area dose rates.
R2 Status of RP&C Facilities and Equipment
R2.1 Turbine Buildino Roof Special Study
The inspector reviewed a special study conducted by the licensee to account for
potential releases from a modification of the Turbine Building roof. The licensee
performed a 50.59 safety evaluation. The licensee also calculated the projected
dose using the most restrictive assumptions to evaluate impact of potential releases
during non-accident and accident conditions. The licensee's assumptions were
appropriate. The report was well-detailed and no inadequacies were noted by the
inspector.
!
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l R2.2 Comouter Uoorade and Chart Recorder Replacement
L
l The inspector pursued the corrective actions related to the reliability of the RM-21 A
computer (see Section 5.1.6 of Combined Inspection Report 50-352:353/95-18 for
details). The RM-21 A is part of the licensee's Radiological and Meteorological
Monitoring System (RMMS). The RM-21 A, the primary source of meteorological
data retrieval, (1) stores radiation monitoring system and meteorological monitoring
l data, (2) performs projected dose calculations for routine operations, (3) sends
l information to the dose assessment computer model MESOREM (MESOREM is used
to perform the projected dose calculations for emergency purposes), and
(4) displays information for operations and emergency personnel. The RM-21 A
receives meteorologicalinformation from the sensors on the towers. The
information is sent to the RM 21 A, and the data loggers and strip chart recorders
simultaneously.
During the previous inspection, the inspector noted that the licensee had identified j
reliability problems with the RM-21 A. In some instances, portions of meteorological l
data sent to the RM-21 A were lost. Howevar, the data was recorded by the strip
chart recorders and data loggers. During this inspection, the inspector noted that l
the licensee plans to upgrade the computer by January 2000. Also, the licensee )
plans to replace the chart recorders by the end of 1998. The progress of these
upgrades will be further reviewed. (IFl 352:353/98-02-12)
R3 RP&C Procedures and Documentation
i
The inspector reviewed the Annual Radiological Environmental Monitoring Reports
for 1995 and 1996. The reports included results of the environmental monitoring ;
program, land use census, and interlaboratory comparison program, as required.
Overall, the reports provided a comprehensive summary of the results of the REMP
around the Limerick site and met the TS (Section 6.9.1.7) reporting requirements.
R7 Quality Assurance in RP&C Activities
a. Inspection Scope (84750-02)
The inspector reviewed (1) the Quality Assurance (QA) audit reports; and (2) the
analytical measurements laboratory QA/OC.
b. Observations and Findinas
The inspector revievved 1997 audit reports of the REMP (Audit #A1067413)and the
contract laborator; JPU Environmental Radioactivity Laboratory (Audit #
A1096921). The audits were performed by members of Nuclear Quality Assurance
(NOA). Several suggestions for improvement to the REMP were documented in the
report. The inspector noted that the suggestions appeared appropriate. No
deficiencies, findings of non-conformance, or significant performance issues were
j noted as a result of the audits. The inspector noted that the audits were thorough
and of sufficient depth to assess the quality of the REMP and MMP.
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36
i
The QA/QC program for analyses of REMP samples is conducted by the GPU
Environmental Radioactivity Laboratory (ERL). The ERL has interlaboratory and
intralaboratory quality control (OC) programs. The QC program consisted of
measurements of blind duplicate, spike, and split samples. The laboratory
continued to participate in the EPA Cross-Check Program and the Interlaboratory
Comparison Program provided by a vendor laboratory (Analytics, Inc.). The ERL
published a Quality Assurance report semi-annually. The inspector reviewed the
reports from 1996 and 1997. Comparisons of OC data listed in the semi-annual
Quality Assurance reports were within the ERL's acceptance criteria.
c. Conclusion .
The QA audit requirements were met and the contractor's QA/QC program for the
REMP provided effective validation of analytical results.
R8 Miscellaneous RP&C Activities
R8.1 Locked Hioh Radiation Area (LHRA) Door #345 Found Open
PEP 10007969 documented an issue that the turbine enclosure cooling water he~.t
exchanger LHRA door was found open and unguarded at 3:30 a.m. on February 23,
1998. This matter was discovered during the performance of Unit 1 turbine q
building operations rounds. Licensee review of this matter determined that the last '
authorized entry to this area occurred approximately at 4:35 p.m on February 22,
1998. The licensee reviewed electronic dosimeter records to determine if any
individuals had received any unexpected exposure due to the LHRA door being open
and unguarded for several hours. The licensee identified that no unexpected
exposures occurred. The inspector also reviewed the electronic dosimeter data and ;
concluded that this matter had no significant radiological safety consequences.
The inspector considered the licensee's investigation to be broad-based. Immediate
corrective actions included closing and verifying closure of the LHRA door, changing
lock cores, verifying the key inventory, and including a check of the door during
Security rounds. The most significant long-term corrective action was the
licensee's plan to implement a LHRA door preventative maintenance program.
This non-repetitive, licensee-identified and corrected violation of Technical ;
Specification 6.12 is being treated as a non-cited violation, consistent with
Section Vll.B.1 of the NRC Enforcement Policy. (NCV 50 352: 50-353/98-02-13)
R8.2 (Closed) IFl 50-352:353/97-07-06 Ventilation System Charcoal Efficiency Testina
l Adeauacy
As noted in NRC Inspection Report 50-352/97-07,the Office of Nuclear Reactor l
Regulation (NRR) has identified a potential testing discrepancy regarding charcoal
efficiency testing using the methodology described in RDT M-161T. The licensee
has followed their charcoal efficiency testing technical specifications. Pending the
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37
{
!
results of NRR's conclusions and any direction to take action regarding this matter,
this matter is considered closed,
q
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P8 Miscellaneous EP issues
P8.1 Emeroency Prenairedness Assessment of the Loss of Shutdown Coolina
a. Insoection Scoos (82201)
The inspector reviewed the Emergency Preparedness (EP) staffs' assessment of an
event on February 6,1998 which included a loss of shutdown cooling. Also, the
inspector conducted an independent review of the event, including interviews and
document reviews to determine the appropriateness of the licensee's response in
regards to emergency preparedness rf;quirements.
'b. Observations and Findinas
The licensee did not make an emergency classificauon for the loss of shutdown
cooling event. This was consistent with the Alert criterion contained in Emergency j
Response Procedures (ERP)-101, Emergency Action Levels (EALs). The Shift '
Manager (SM) did not refer to the ERP during this event and, as such, did not carry
out the expected Nuclear Emergency Plan (NEP) assessment actions of a SM for this ;
event.
Section 4.0 of the NEP discusses " emergency actions" in which criteria and action l
levels are provided for guidance to operators in determining which emergency plan
implementation is required. Emergency measures begin with shift management
detecting a potential or existing hazard comparable for one of the classes of
emergencies as described in ERP-101. ERP-101 is an implementing procedure that i
provides the EALs for declaring various classifications which " consider both existing l
consequences of accident conditions and the potential for consequences that may ,
occur due to an event in the plant." For example, "an EAL may be a set of in-plant I
conditions which if not corrected, represent a potential for consequences to occur."
'
Section 4.0 also defines and describes the responsibilities of shift management
L during a possible event. "The SM assumes the role of Emergency Director and
'
assesses the situation and classifies the emergency." Responsibilities include
assessment, classification of emergency conditions and activation. Section 4.1
l continues to state that shift management and personnel detect conditions
corresponding to an emergency through instrumentation, alarms, verbal reports or
observance of conditions in and around the plant. The SM will determine the event !
category and ERP-101 will be reviewed to determine the emergency classifications.
The inspector spoke with the SM regarding his assessment and emergency
preparedness actions and he stated that he did not review any procedures to
determine if plant conditions met the EAL emergency classification criteria set forth
in ERP-101. He stated reviewing ERP-101 was "not a priority at the time" and
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38
because he believed the alternate heat removal system would become available
when the valve isolating it was manually opened.
ERP-101, Appendix 11, " Loss of Hot or Cold Shutdown Capability," states the
following plant conditions are required before an Alert classification can be made:
" complete loss of ability to establish and maintain plant in a cold shutdown
condition symptomized by"....(b) loss of all means of primary and alternate decay
heat removal when shutdown, such that the reactor coolant temperature cannot be
maintained below 200 degrees Fahrenheit." At the beginning of the event, the
licensee had lost the primary means of decay heat removal while reactor coolant
temperature exceeded 200 degrees Fahrenheit for 17 minutes. The NRC's review
determined that the emergency core cooling system and safety relief valves
necessary for alternate heat removal, were available and could be used by the
operators to control temperature, as needed. Therefore, the criterion specified
under the Alert classification category was not satisfied.
The NEP clearly states that the shift manager is to assess the situation, determine
the event category and enter ERP-101. The shift manager had events in progress
that indicated a potential degradation of the level of the safety of the plant, reactor
coolant temperature was increasing and conditions were specifically comparable for
one of the classes of emergencies as described in ERP-101 (Loss of Hot or Cold
Shutdown). Based on the conditions described above, a consideration of a
declaration was warranted. However, the SM did not refer to the emergency action
criteria and EALs described in ERP-101 in determining if or when emergency plan
implementation was required.
]
The inspector discussed this issue with licensee representatives who stated that it i
is their expectation that during any potential event ERP-101 would be reviewed, and
'
a conscious decision made whether the conditions met an emergency classification.
The inspector also assessed the licensee's efforts to review and assess the event to
determine how they performed an investigation and formulated their conclusions. l
The EP staff's initial assessment of the event was poor. There was no independent
review, no interviews conducted with shift persoanel, and fact gathering was based
i on making assumptions and interpreting information contained in the Control Room
!
Log. Based on that information, the licensee determined that the SM acted
appropriately by reviewing ERP-101 and his decision not to declare an Alert was
appropriate. The NRC inspector informed the licensee that facts gathered by its
review were contradicting to the information gathered by the NRC during interviews
with the SM. The licensee's second attempt at gathering the facts was more
thorough, included interviews with shift and training personnel and a reenactment of
l the event using the Control Room Simulator.
l
The licensee's corrective actions resulting from the event included: (1) EP
management clarifying it's expectations regarding EP's internal review process for
event response; (2)immediate retraining of the SM regarding NEP and ERP review
during an event; and (3) a review of the operator's emergency response training
lesson plans to ensure the NEP and ERP are appropriately addressed.
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39
c. Conclusions
Regarding the loss of shutdown cooling event that occurred on February 6,1998,
while emergency response procedures did not explicitly require the event to be
classified as an emergency condition, we found that the crew on shift at the time of
the event did not consult the Nuclear Emergency Plan and Emergency Response
Procedures, which was a licensee expectation, to determine if plant conditions met
emergency action level criteria. The licensee's initial investigation into this matter
was poor; however, following discussions with the NRC, a more thorough
investigation was conducted. The licensee developed adequate corrective actions
from the event.
V. Manaoement Meetinas
X1 Exit Meeting Summary
The inspector presented the inspection results to members of plant management at
the conclusion of the inspection on March 25,1998. The plant manager
acknowledged the inspectors' findings. The inspectors asked whether any materials
examined during the inspection should be considered proprietary. No proprietary
information was identified.
The inspector discussed the inspection areas covered and the inspection findings
with the Director of Site Engineering. He acknowledged the findings presented.
X2 Review of UFSAR Commitments
t
l A recent discovery of a licensee operating their facility in a manner contrary to the
i UFSAR description highlighted the need for a special focused review that compares
plant practices, procedures and/or parameters to the UFSAR description. While
performing the inspections discussed in this report, the inspectors reviewed the
applicable portions of the UFSAR that related to the areas inspected. The
inspectors verified that the UFSAR wording was consistent with the observed plant
practices, procedures and/or parameters.
I
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. . .. .
i
ATTACHMENT 1
INSPECTION PROCEDURES USED
IP 37550 Engineering Inspection
IP 37551: Onsite Engineering
IP 61726: Surveillance Observation
IP 62707: Maintenance Observation
IP 71707: Plant Operations
IP 71750: Plant Support Activities
IP 84750-02: Radioactive Waste Treatment, and Effluent and Environmental
Monitoring
IP 82201 Emergency Detection and Classification
IP 90712: In-office Review of Written Reports
IP 90713: Review of Periodic and Special Reports
IP 92904: Followup - Plant Support
IP 93702: Prompt Onsite Response to Events at Operating Power
Reactors
PARTIAL LIST OF PERSONS CONTACTED
Licensee
V. T. Angus Engineer, Balance of Plant Systems
C. T. Bell Manager, Reactor Engineering :
J. A. Britain Engineer, Mechanical Design Engineering I
J. F. Buckley - Engineer, Reactor Engineering
F. A. Cook Senior Manager, Design Engineering l
D. R. Earl Engineer, Component Engineering '
J. P. Grimes Director, Site Engineering
R. Kinard, Manager, Nuclear Security /EP
M. Karney Security /EP Manager j
F. D. Lear Engineer, Balance of Plant Systems l
W. R. Lewis Manager, Balance of Plant Systems
'
C. S. Marke Engineer, Balance of Plant Systems
G. J. Reid Manager, Design Change
G. R. Sealy Engineer, Projects ,
R. D. Weingard Acting Manager, Equipment Focus l
1
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Attachment 1 2
ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
NCV 50-352/98-02-01 Failure to restore RECW to an operating recirculation
pump consistent with ON-113 (Section 01.2)
IFl 50-352/98-02-02 Inability to re-open the Unit 1 shutdown cooling ,
'
outboard isolation valve electrically (Section 01.2)
VIO 50-352;353/98-02-03 Control of Locked Valves - Inadequate Corrective
Actions (Section 08.2)
VIO 50-352;353/98-02-04 Configuration Control - Meteorological Tower
Surveillance Test Implementation (Section M1.3)
NCV 50-352/98-02-05 Unplanned Closure of a Primary Containment isolation
Valve (Section M8.1)
eel 50-352;353/98-02-06 Residual Heat Removal Minimum Flow Valve Corrective
Actions (Section E1.1)
eel 50-352;353/98-02-07 Residual Heat Removal Minimum Flow Valve Operability
l (Section E1.1)
eel 50-352/98-02-08 High Pressure Coolant Injection Turbine Exhaust Valve
Corrective Actions (Section E2.1)
l eel 50-352/98-02-09 High Pressure Coolant Injection Turbine Exhaust Valve j
l Operability (Section E2.1) '
NCV 50-353/98-02-10 Failure to Perform a First Cycle Analysis of a Reactor
Flux Wire Specimen (Section E8.2)
URI 50-352;353/98-02-11 Spent Fuel Pool Configuration
IFl 50-352:353/98-02-12 RM-21 A Computer Upgrade and Chart Recorder
Replacement (Section R2.2)
NCV 50-352;353/98-02-13 Locked High Radiation Area Door (Section R8.1)
Closed
VIO 50-352;353/97-07-01 Control of Locked Valves and Devices (Section 08.2)
LER 50-352/1-97-012 Unplanned Closure of a Primary Containment Isolation
Valve (Section M8.1)
URI 50-352;353/97-10-06 Unit 1 High Pressure Coolant injection Turbine Exhaust
Valve Failure (Section E2.1)
LER 50-352;353/1-97-09 Residual Heat Removal Service Water Radiation Monitor
f Incorrectly Configured (Section E8.1)
LER 50-353/2-97-010 Failure to Perform a First Cycle Analysis of a Reactor
Flux Wire Specimen (Section E8.2)
IFl 50-352;353/97-07-06 VentHation System Charcoal Efficiency Testing
Adequacy (Section R8.2)
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Attachment 1 3
Discussed
Update 50-352/97-07-02 Reactor Water Cleanup (Section E8.3)
LIST OF ACRONYMS USED
ADS Automatic Depressurization System
AR Action Request
BOP Balance of Plant
BWR Boiling Water Reactor
CFR Code of Federal Regulations
CRD Control Rod Drive
CREFAS Control Room Engineering Fresh Air System
EAL Emergency Action Level
ECCS Emergency Core Cooling System
EDG Emergency Diesel Generator
EHC Electric Hydraulic Control
ESF Engineered Safety Feature
ERP Emergency Response Procedure
GL Generic Letter
HPCI High Pressure Coolant injection
IFl Inspection Follow-up Item
IR inspection Report
LCO Limiting Condition For Operation
LER Licensee Event Report
LGS Limerick Generating Station
MIT Massachusetts Institute of Technology
MOV Motor Operated Valve
MS Main Steam
NCR Non Conformance Report
NCV Non-Cited Violation
NEP Nuclear Emergency Plan
NQA Nuclear Quality Assurance
NRB Nuclear Review Board
NRC Nuclear Regulatory Commission
NUPIC Nuclear Procurement issues Committee
ODCM Offsite Dose Calculation Manual
PECON PECO Nuclear Division
l PEP Performance Enhancement Process
PORC Plant Operations Review Committee
QA Quality Assurance
OC Quality Control
RCIC Reactor Core Isolation Cooling
RCO Request for Change Order
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w
Attachment 1 4
RHRSW Residual Heat Removal Service Water
RP&C Radiological Protection and Chemistry
l RP Radiation Protection
RT Routine Test
RWCU Reactor Water Clean-up
SCBA Self-Contained Breathing Apparatus
- SM Shift Manager
l
ST Surveillance Test
TLD Thermo-luminescent Dosimeter
l
TRM Technical Requirements Manual
TS Technical Specification
l UFSAR Updated Final Safety Analysis Report
URI Unresolved item
VIO Violation
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l
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